10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended September 30, 2018

Commission file number 000-26591

RGC RESOURCES, INC.

(Exact name of registrant as specified in its charter)

Virginia	54-1909697
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

519 Kimball Avenue, N.E., Roanoke, VA	24016
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code (540) 777-4427

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class	Name of Each Exchange on Which Registered
Common Stock, $5 Par Value	NASDAQ Global Market

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act.        Yes  ¨  No  x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨  No  x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See definition of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer	¨	Accelerated filer	x
Non-accelerated filer	¨ (Do not check if smaller reporting company)	Smaller reporting company	x
		Emerging growth company	¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨   No  x

State the aggregate market value of the voting and non voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity as of the last business day of the registrant’s most recently completed second fiscal quarter: March 31, 2018. $188,207,371

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the last practicable date.

Class	Outstanding at November 23, 2018
COMMON STOCK, $5 PAR VALUE	8,003,606 SHARES

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the RGC Resources, Inc. Proxy Statement for the 2019 Annual Meeting of Shareholders are incorporated by reference into Part III hereof.

TABLE OF CONTENTS
			Page Number
		Cautionary Note Regarding Forward Looking Statements		2
PART I
	Item 1.	Business		3
	Item 1A.	Risk Factors		6
	Item 1B.	Unresolved Staff Comments		10
	Item 2.	Properties		10
	Item 3.	Legal Proceedings		11
	Item 4.	Mine Safety Disclosures		11
PART II
	Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		12
	Item 6.	Selected Financial Data		14
	Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations		14
	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		30
	Item 8.	Financial Statements and Supplementary Data		31
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosures		68
	Item 9A.	Controls and Procedures		68
	Item 9B.	Other Information		70
PART III
	Item 10.	Directors, Executive Officers and Corporate Governance		71
	Item 11.	Executive Compensation		71
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		71
	Item 13.	Certain Relationships and Related Transactions, and Director Independence		71
	Item 14.	Principal Accounting Fees and Services		71
PART IV
	Item 15.	Exhibits and Financial Statement Schedules		72
	Item 16.	Form 10-K Summary		72
	Signatures			73

Cautionary Note Regarding Forward Looking Statements

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.

2

PART I

Item 1. Business.

General and Historical Development

RGC Resources, Inc. ("Resources" or the "Company") was incorporated in the state of Virginia on July 31, 1998, for the primary purpose of becoming the holding company for Roanoke Gas Company (“Roanoke Gas”) and its subsidiaries. Effective July 1, 1999, Roanoke Gas and its subsidiaries were reorganized into the holding company structure. Resources is currently composed of the following subsidiaries: Roanoke Gas, Diversified Energy Company and RGC Midstream, LLC.

Roanoke Gas was organized as a public service corporation under the laws of the Commonwealth of Virginia in 1912. The principal service of Roanoke Gas is the distribution and sale of natural gas to residential, commercial and industrial customers within its service territory in Roanoke, Virginia and the surrounding localities. Roanoke Gas also provides certain non-regulated services which account for less than 2% of consolidated revenues.

In July 2015, the Company formed RGC Midstream, LLC, a limited liability company established for the purpose of becoming a 1% investor in Mountain Valley Pipeline, LLC (the "LLC"). Mountain Valley Pipeline, LLC was created for the purpose of constructing and operating interstate natural gas pipelines. Additional information regarding this investment is provided under Note 4 of the Company's annual consolidated financial statements and under the Equity Investment in Mountain Valley Pipeline section of Item 7.

Diversified Energy Company 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), revenues and margin as a percentage of the total for each category. For the purposes of this schedule, margin for the utility operations is defined as revenues less cost of gas.

	2018
	Customers		Volume		Revenue			Margin
Residential	91.2	%	39	%	58		%	61		%
Commercial	8.7	%	32	%	33		%	25		%
Industrial	0.1	%	29	%	6		%	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	60,228		9,925,974		$	65,534,736		$	32,776,289

	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

3

	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

Roanoke Gas’ regulated natural gas distribution business accounted for approximately 98% of Resources total revenues for fiscal years ending September 30, 2018, 2017 and 2016. The tables above indicate that residential customers represent over 91% of the Company’s customer total; however, they represent less than 40% of the total gas volumes delivered and more than half of the Company’s consolidated revenues and margin. Industrial customers include primarily transportation customers that purchase their natural gas requirements directly from a supplier other than the Company and utilize Roanoke Gas’ natural gas distribution system for delivery to their operations. Most of the revenue billed for these customers relates only to transportation service, and not to the purchase of natural gas, causing total revenues generated by these deliveries to be approximately 6% of total revenues, even though they represent 29% of total natural gas deliveries for the year ended September 30, 2018 and approximately 10% to 11% of 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-gas portion of customer billing rates. Increases or decreases in the cost of natural gas are passed on to customers through the purchased gas adjustment mechanism as explained in Note 1 of the Company’s annual consolidated financial statements.

The Company’s residential and commercial sales are seasonal and temperature-sensitive as the majority of the gas sold by Roanoke Gas to these customers is used for heating. For the fiscal year ended September 30, 2018, approximately 66% of the Company’s total DTH of natural gas deliveries and 74% of the residential and commercial deliveries were made in the five-month period of November through March. These percentages are higher than in the prior two years as colder weather led to increased consumption by weather sensitive customers. Total natural gas deliveries were 9.9 million DTH, 8.6 million DTH and 8.8 million DTH in fiscal 2018, 2017 and 2016, respectively.

Suppliers

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 to transport natural gas from the production and storage fields to Roanoke Gas’ distribution system. Roanoke Gas is directly served by two pipelines, Columbia and East Tennessee. Columbia historically has delivered more than 60% of the Company’s gas supply, while East Tennessee delivers the balance of the Company’s requirements. The rates paid for 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. The current pipeline contracts expire at various times from 2019 to 2027. The Company anticipates being able to renew these contracts or enter into other contracts to meet customers’ continued demand for natural gas.

The Company manages its pipeline contracts and liquefied natural gas storage (“LNG”) facility in order to provide for sufficient capacity to meet the natural gas demands of its customers. The maximum daily winter capacity available for delivery into Roanoke Gas’ distribution system under the interstate pipelines is 78,606 DTH per day. The LNG facility is capable of storing up to 200,000 DTH of natural gas in a liquid state for use during peak demand. Combined, the pipelines and LNG facility may provide up to 105,000 DTH on a single winter day.

The Company uses multi-year contracts to meet its natural gas supply needs. 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

4

management agreement is priced at indexed-based market prices as reported in major industry pricing publications. The Company renewed its contract with the asset manager in March 2018. The new agreement expires March 31, 2021.

The Company uses summer storage programs to supplement gas supply requirements during the winter months. During the summer months, the Company injects gas into its LNG facility. In addition, the Company has contracted for 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. 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 necessity ("CPCN") 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 term of 20 years and will expire December 31, 2035. The Company has filed an application with the Virginia State Corporation Commission ("SCC") to obtain a CPCN for portions of Franklin County that are not currently certificated. A final decision is pending on this request. Roanoke Gas plans to tap into the Mountain Valley Pipeline and provide natural gas service to portions of Franklin County.

Management anticipates that the Company will be able to renew all of its franchises when they expire. 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. CPCN, issued by the SCC, are generally of perpetual duration and subject to compliance with regulatory standards. If the SCC issues a CPCN for the currently uncertified sections of Franklin County, the CPCN would have a 5-year term if natural gas service was not extended into those areas.

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 and solar. Competition can be intense among the other energy sources with the primary driver being price in most instances. 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 supply of natural gas, mostly due to improved drilling and extraction processes in shale formations, has served to maintain prices at lower levels. The Company continues to see a demand for its product. Construction activity for new business has improved over this past year and growth in residential service has remained steady over the last few years as the Company continues to grow its customer base through a combination of extending service by new construction and converting existing alternative 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 the 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.

Employees

At September 30, 2018, Resources had 110 full-time employees and 112 total employees. As of that date, 32 employees, or 29%, belonged to the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied-Industrial International Union, Local No. 515 and were represented under a collective bargaining agreement. The union has been

5

in place at the Company since 1952. The current collective bargaining agreement will expire on July 31, 2020. Management maintains an amicable relationship with the union.

Website Access to Reports

The Company’s website address is www.rgcresources.com. Information appearing on this website is not incorporated by reference in and is not a part of this annual report. The Company files reports with the Securities and Exchange Commission ("SEC"). A copy of this annual report, as well as other recent annual and quarterly reports are available on the Company's website. You may read and copy these filings with the SEC at the SEC public reference room at 100 F Street, NE, Washington, D.C. 20549. Information on the operation of the Public Reference Room can be obtained by calling the SEC at 1-800-SEC-0330. The SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding the Company’s filings at www.sec.gov, which is hyper-linked on the Company's website where you may obtain other Company filings with the SEC.                    

Item 1A. Risk Factors

Please carefully consider the risks described below regarding the Company. These risks are not the only ones faced by the Company. Additional risks not presently known to the Company or that the Company currently believes are immaterial may also impair business operations and financial results. If any of the following risks actually occur, the Company’s business, financial condition or results of operations could be adversely affected. In such case, the trading price of the Company’s common stock could decline and investors could lose all or part of their investment. The risk factors below are categorized by operational, regulatory and financial:

OPERATIONAL RISKS

Availability of sufficient and reliable pipeline capacity.

The Company is currently served directly by two interstate pipelines. These two pipelines carry 100% of the natural gas transported to the Company’s distribution system. Depending on weather conditions and the level of customer demand, failure of one or both of these interstate transmission pipelines could have a major impact on the Company’s ability to meet customer demand for natural gas and adversely affect the Company’s earnings as a result of lost revenue and the cost of service restoration. If the failure is frequent or prolonged, it could lead customers to switch to alternative energy sources. Capacity limitations on existing pipeline and storage infrastructure could impact the Company’s ability to obtain additional natural gas supplies, thereby limiting the ability to meet customer demand and thus decreasing future earnings potential.

Risks associated with the operation of a natural gas distribution pipeline and LNG storage facility.

Numerous potential risks are inherent in the operation of a natural gas distribution system and LNG storage facility, including unanticipated or unforeseen events that are beyond the control of the Company. Examples of such events include adverse weather conditions, acts of terrorism or sabotage, accidents and damage caused by third parties, equipment failure, failure of upstream pipelines and storage facilities, as well as catastrophic events such as explosions, fires, earthquakes, floods, or other similar events.  These risks could result in injury or loss of life, property damage, pollution and customer service disruption resulting in potentially significant financial losses. The Company maintains insurance coverage to protect against many of these risks. However, if losses result from an event that is not fully covered by insurance, the Company’s financial condition could be significantly impacted if it were unable to recover such losses from customers through the regulatory rate making process. Even if the Company did not incur a direct financial loss as a result of any of the events noted above, it could encounter significant reputational damage from a reliability, safety, integrity or similar viewpoint, potentially resulting in a longer-term negative earnings impact.

Supply disruptions due to weather or other forces.

Hurricanes, floods 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 or lead to higher prices and/or service disruptions. Disasters could also lead to additional governmental regulations that may limit production activity and/or increase production and transportation costs.

6

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; 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. which could materially increase the Company's costs to protect against such 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.

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 will be facing retirements of key personnel over the next several years, the failure to replace those departing employees with skilled and qualified employees could increase operating costs and expose the Company to other operational and financial risks.

Geographic concentration of business activities.

The Company's business activities are concentrated in the Roanoke Valley. Changes in the local economy, politics, regulations and weather patterns could negatively impact the Company's existing customer base, leading to declining usage patterns and financial condition of customers, both of which could adversely affect earnings.

Volatility in the price and availability of natural gas.

Natural gas purchases represent the single largest expense of the Company. Even with increasing demand from other areas, including electricity generation, natural gas prices are currently expected to remain stable in the near term, although there can be no guarantee to that effect. If demand for natural gas increases at a rate in excess of current expectations, natural gas prices could face upward pressure. Increasing natural gas prices could result in declining sales as well as increases in bad debt expense.

Impact of weather conditions and related regulatory mechanisms.

The Company’s revenues and earnings are dependent upon weather conditions, specifically winter weather. The Company’s rate structure currently has a weather normalization adjustment factor that results in either a recovery or refund of revenues due to any variation from the 30-year average for heating degree-days. If the provision for the weather normalization adjustment were removed from its rate structure, the Company would be exposed to a much greater risk related to weather variability resulting in earnings volatility. A colder than normal winter could cause the Company to incur higher than normal operating and maintenance costs.

Inability to complete necessary or desirable pipeline expansion or infrastructure development projects.

In order to serve new customers or expand service to existing customers, the Company needs to install new pipeline 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

7

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 Mountain Valley Pipeline ("MVP"). Any of these factors could negatively impact 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 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 convert their natural gas-fueled equipment to systems that use alternative energy sources, thus lowering natural gas deliveries and earnings. Price considerations could also inhibit customer and revenue growth if builders and developers do not perceive natural gas to be a better value than other energy options and elect to install heating systems that use an energy source other than natural gas.

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

Roanoke Gas Company holds either franchises or certificates of public convenience (“CPC”) to provide natural gas to customers in its service territory. The franchises are granted by the local municipalities and the CPCs are granted by the State Corporation Commission of Virginia. The ability to renew such agreements is important to the long-term operations of the Company and the ability to obtain new franchises or CPCs 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 CPCs for new service areas could negatively impact future earnings growth.

REGULATORY RISKS

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.

Environmental laws or regulations associated with global warming and climate change.

Several federal and state legislative and regulatory initiatives have been proposed in recent years in an attempt to limit the effects of global warming and climate change, including greenhouse gas emissions such as those created by the combustion of fossil fuels such as 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, resulting in reduced deliveries and earnings. The current Presidential administration is de-emphasizing climate change initiatives; however, future administrations might prioritize climate change and greenhouse gas emissions, which could lead to new and stricter environmental laws.

Regulatory actions or failure to obtain timely rate relief.

The Company’s natural gas distribution operations are regulated by the SCC. The SCC approves the rates that the Company charges its customers. If the SCC did not allow rates that provided for the timely recovery of costs or a

8

reasonable rate of return on investment in natural gas distribution facilities, earnings could be negatively impacted. Issuance of debt and equity by our subsidiaries are 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.

FINANCIAL RISKS

Access to capital to maintain liquidity.

The Company relies on a variety of capital sources to operate its business and fund capital expenditures, including internally generated cash from operations, 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.

Investment in Mountain Valley Pipeline.

The success of the Company's investment in the LLC is predicated on several key factors including but not limited to the ability of all investors to meet their capital calls when due, timely state and federal approvals and completing the construction of the pipeline within the targeted time frame and budget. 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 begin construction on the pipeline, progress on the MVP has been hindered by several legal and regulatory obstacles as both the U.S, Fourth Circuit Court of Appeals (“Fourth Circuit”) and FERC have issued stays or stop orders affecting portions or all of the project pending resolution of issues or concerns raised as the project has progressed. For example, in July 2018, the Fourth Circuit challenged the adequacy of alternative route evaluations for the permits issued by the US Forest Service and the Bureau of Land Management for the right-of-way granted for the 3.5 mile section of the 303 mile pipeline through the Jefferson National Forest. In August 2018, FERC issued a project wide stop work order related to the Fourth Circuit’s stay issued for the right-of-way in the National Forest. At the end of August, FERC issued a Modified Stop Work Order that allowed construction activities to restart in all locations except for the Jefferson National Forest and a section in West Virginia. The Fourth Circuit also lifted a stay order which had stopped construction through streams and wetland crossings in West Virginia thereby allowing construction to proceed in these areas. In October, the Fourth Circuit issued an order to vacate the stream and wetland crossing permit issued by the US. Army Corps of Engineers, which impacts approximately 160 miles of the project in West Virginia.

The LLC continues to respond to the issues and concerns raised. However, these ongoing starts and stops have caused delays in construction and resulted in significantly higher projected costs and an extended targeted in-service date for the pipeline. Cost overruns may not be approved for recovery or be recovered through regulatory mechanisms that may otherwise be available, and the LLC could be obligated to make delay or termination payments or responsible for other contractual damages. They could also experience the loss of tax credits or tax incentives, or delayed or diminished returns, and could be required to write-off all or a portion of its investment in the project. New or extended regulatory, legislative or judicial actions could lead to further delays and even higher costs all of which could significantly impact future returns for the LLC and ultimately impact Resources consolidated financial position and results of operation.

In addition, there are numerous risks facing the LLC, which can adversely affect the Company's earnings and financial performance through its 1% investment. The LLC's ability to obtain and keep contract crews to complete construction of the pipeline, the inability to obtain or renew ancillary licenses, rights-of-way, permits or other approvals and opposition from pipeline opponents and environmental groups could all influence the successful completion of the pipeline. Should the LLC be unable to adequately address these issues, the LLC’s business, financial condition, results of operations and prospects could be materially adversely affected, which could materially impact the financial condition and results of operations of the Company. Any failure to negotiate successful project development agreements for new facilities with third parties could have similar results.

9

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 resulting from terrorism, cyber-attacks, or individuals and/or groups attempting to disrupt the LLC’s business, or the businesses of third parties, may materially adversely affect the LLC’s business, financial condition, results of operations and prospects.

Insurance coverage may not be sufficient.

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

Post-retirement benefits and related funding of obligations.

The costs of providing defined benefit pension and retiree medical plans are dependent on a number of factors such as the rates of return on plan assets, discount rates used in determining plan liabilities, the level of interest rates used to measure the required minimum funding levels of the plan, future government regulation, changes in life expectancy, and required or voluntary contributions made to the plan. Changes in actuarial assumptions and differences between the assumptions and actual results, as well as a significant decline in the value of investments that fund these plans, if not offset or mitigated by a decline in plan liabilities, could increase the expense of these plans and require significant additional funding. Both funding obligations and increased expense could have a material impact on the Company's financial position, results of operation and cash flows.

Failure to comply with debt covenant requirements.

The Company's long-term debt obligations and bank line of credit contain financial covenants. Noncompliance with any of these covenants could result in an event of default which, if not cured or waived, could accelerate payment on outstanding debt obligations or cause prepayment penalties. In such an event, the Company may not be able to refinance or repay all of its indebtedness, pay dividends or have sufficient liquidity to meet operating and capital expenditure requirements. Any such acceleration would cause a material adverse change in our financial condition.

Item 1B. Unresolved Staff Comments.

Not applicable.

Item 2. Properties.

Included in “Utility Property” on the Company’s consolidated balance sheet are storage plant, transmission plant, distribution plant and general plant of Roanoke Gas as categorized by natural gas utilities. The Company has approximately 1,141 miles of transmission and distribution pipeline with transmission and distribution plant representing more than 87% of the total utility plant investment. The transmission and distribution pipelines are located on or under public roads and highways or private property for which the Company has obtained the legal authorization and rights to operate.

10

Roanoke Gas currently owns and operates eight metering stations through which it measures and regulates the gas being delivered by its suppliers. These stations are located at various points throughout the Company’s distribution system.

Roanoke Gas also owns a liquefied natural gas storage facility located in its service territory that has the capacity to store up to 200,000 DTH of natural gas.

The Company’s executive, accounting and business offices, along with its maintenance and service departments, are located on Kimball Avenue in Roanoke, Virginia.

Although the Company considers its present properties to be adequate, management continues to evaluate the adequacy of its current facilities as additional needs arise.

Item 3. Legal Proceedings.

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

Item 4. Mine Safety Disclosures.

Not applicable.

11

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Market Information

Resources' common stock is listed on the NASDAQ Global Market under the trading symbol RGCO. Payment of dividends is within the discretion of the Board of Directors and depends on, among other factors, earnings, capital requirements, and the operating and financial condition of the Company.

	Range of Bid Prices				Cash Dividends
Year Ending September 30, 2018	High		Low		Declared
First Quarter	$	31.57	$	25.01	$	0.1550
Second Quarter	27.49		22.16		0.1550
Third Quarter	29.46		23.61		0.1550
Fourth Quarter	31.33		25.85		0.1550
Year Ending September 30, 2017
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

As of November 24, 2018, there were 1,140 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.”

Comparisons of Cumulative Total Shareholder Returns

The following performance graph compares the Company’s total shareholder return from September 30, 2013 through September 30, 2018 with the Dow Jones US Utility Index, a utility based index, and the Standard & Poor’s 500 Stock Index (S&P 500 Index), a broad market index.

The graph below reflects the value of a hypothetical investment of $100 made September 30, 2013 in the Company’s common stock and in each index as of September 30, 2018, assuming the reinvestment of all dividends. Historical stock price performance as reflected on the graph is not indicative of future price performance. The total value at the end of the five years was $245 for the Company’s common stock, $172 for the Dow Jones US Utilities Index and $192 for the S&P 500 Index.

12

A summary of the Company’s equity compensation plans follows as of September 30, 2018:

	(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	100,000	$14.34	555,568
Equity compensation plans not approved by security holders	—	—	—
Total	100,000	$14.34	555,568

13

Item 6. Selected Financial Data.

	Year Ending September 30,
	2018		2017		2016		2015		2014
Operating Revenues	$	65,534,736	$	62,296,870	$	59,063,291	$	68,189,607	$	75,016,134
Operating Income	11,593,045		11,666,309		11,212,092		10,006,192		9,681,868
Net Income	7,297,205		6,232,865		5,806,866		5,094,415		4,708,440
Basic Earnings Per Share (1)	$	0.95	$	0.86	$	0.81	$	0.72	$	0.67
Cash Dividends Declared Per Share (1)	$	0.62	$	0.58	$	0.54	$	0.51	$	0.49
Book Value Per Share (1)	$	9.95	$	8.29	$	7.75	$	7.43	$	7.35
Average Shares Outstanding (1)	7,649,025		7,218,686		7,149,906		7,092,315		7,073,218
Total Assets	$	219,560,106	$	183,135,071	$	165,552,849	$	145,847,194	$	137,423,321
Long-Term Debt (Less Unamortized Debt Expense)	$	70,321,936	$	61,312,011	$	33,636,051	$	30,316,573	$	30,306,919
Stockholders' Equity	79,583,112		60,040,472		55,667,072		52,840,991		52,020,847
Shares Outstanding at Sept. 30(1)	7,994,615		7,240,846		7,182,434		7,112,247		7,080,567

⁽¹⁾Total shares and per share amounts for the prior years were revised to reflect the three-for-two stock split in 2017.

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

Forward-Looking Statements

This report contains forward-looking statements that relate to future transactions, events or expectations. RGC Resources, Inc. (“Resources” or the “Company”) may 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.

Overview

Resources is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately 60,200 residential, commercial and industrial customers in Roanoke, Virginia, and the surrounding

14

localities, through its Roanoke Gas Company (“Roanoke Gas”) subsidiary. Roanoke Gas also provides certain unregulated services. Resources formed a wholly-owned subsidiary, RGC Midstream, LLC ("Midstream"), to invest in the Mountain Valley Pipeline, LLC (the "LLC"). Midstream is a 1% member in the LLC. More information is provided under the Equity Investment in Mountain Valley Pipeline section below. The unregulated operations represent less than 2% of revenues and margins of Resources.

The utility operations of Roanoke Gas are regulated by the Virginia State Corporation Commission (“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. 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.

On December 22, 2017, the President signed into law the Tax Cuts and Job Act, or TCJA, which provided sweeping changes to the federal income tax code. The most significant change for the Company was the reduction in the corporate maximum federal income tax rate from 35% to 21%. The maximum federal income tax rate for Resources was 34%. Under the provisions of the law, the Company began applying the lower corporate income tax rate to earnings beginning with the current fiscal year, in addition to revaluing its deferred tax assets and liabilities derived from the Company's 34% tax rate down to a 21% rate. For the unregulated operations of the Company, the effect of the change in tax rate and revaluation of the deferred taxes are reflected in income tax expense. However, for the regulated operations of Roanoke Gas, the net estimated deferred tax liability adjustment was transferred to a regulatory liability for refund to customers and a rate refund liability has been recorded for the estimated excess billings to customers during the current year as billing rates were designed to recover operating expenses and provide a rate of return based on a federal income tax rate of 34%. Additional information regarding the TCJA and its impact on the Company is provided under the Regulatory and Tax Reform section below.

The Company is committed to the safe and reliable delivery of natural gas to its customers. Since 1991, the Company has placed an emphasis on the modernization of its distribution system through the renewal and replacement of its cast iron and bare steel natural gas distribution pipelines and other system improvements. The Company completed the replacement of all cast iron and bare steel pipe in the first quarter of fiscal 2017 and is continuing its renewal program with the replacement of first generation, pre-1973 plastic pipe to be completed over the next few years.

The Company is also dedicated to the safeguarding of its information technology systems.  These systems contain confidential customer, vendor and employee information as well as important financial data.  There is risk associated with the unauthorized access of this information with a malicious intent to corrupt data, cause operational disruptions, or compromise information.  Management believes it has taken reasonable security measures to protect these systems from cyber attacks and other types of 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 to assist with responding to the incident.  The Company maintains cyber-insurance coverage to mitigate financial expense that may result from a cyber incident.

More than 98% of the Company’s revenues are derived from the sale and delivery of natural gas to Roanoke Gas customers. The SCC authorizes the rates and fees the Company charges its customers for these services. These rates are designed to provide the Company with the opportunity to recover its gas and non-gas expenses and to earn a reasonable rate of return for shareholders based on normal weather. Normal weather refers to the average number of heating degree days (an 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, the Company 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 a purchased gas adjustment factor ("PGA"), weather normalization adjustment factor ("WNA"), inventory carrying cost revenue ("ICC") and a Steps to Advance Virginia Energy ("SAVE") adjustment rider.

The Company's approved billing rates include a component designed to allow for the recovery of the cost of natural gas used by its customers. The cost of natural gas is considered a pass-through cost and is independent of the non-gas rates

15

of the Company. This rate component, referred to as the PGA clause, allows the Company to pass along to its customers increases and decreases in natural gas costs incurred by its regulated operations. On a quarterly basis, or more frequently if necessary, the Company files a PGA rate adjustment request with the SCC to adjust the gas cost component of its rates up or down depending on projected price and activity. Once administrative approval is received, the Company adjusts the gas cost component of its rates to reflect the approved amount. As actual costs will differ from the projections used in establishing the PGA rate, the Company will either over-recover or under-recover its actual gas costs during the period. The difference between actual costs incurred and costs recovered through the application of the PGA is recorded as a regulatory asset or liability. At the end of the annual deferral period, the balance is amortized over an ensuing 12-month period as amounts are reflected in customer billings.

The WNA reduces the volatility in earnings due to the variability in temperatures during the heating season. The WNA is based on the most recent 30-year temperature average and provides the Company with a level of earnings protection when weather is warmer than normal and provides its customers with price protection when the weather is colder than normal. The WNA allows the Company to recover from its customers the lost margin (excluding gas costs) from the impact of weather that is warmer than normal and correspondingly requires the Company to refund the excess margin earned for weather that is colder than normal. The WNA year runs from April through March. Any billings or refunds related to the WNA are completed following the end of the WNA year. For the fiscal year ended September 30, 2018, the Company recorded approximately $45,000 in additional revenue from the WNA for weather that was less than 1% warmer than normal. For the fiscal years ended September 30, 2017 and 2016, the Company recorded $1,839,000 and $1,318,000 in additional revenue from the WNA for weather that was approximately 18% and 13% warmer than normal for the respective years. As normal weather is based on the most recent 30-year temperature average, the 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 winters and dropping off colder than normal years from the beginning of the 30-year period, the number of heating degree days that defines normal has declined from 3,998 in fiscal 2013 to 3,944 in fiscal 2018. 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 3,944 heating degree days, or about 1% less than for what the rates were designed to recover. The 30-year normal will be reset in base rates when the Company implements new non-gas rates associated with its recently filed rate application with the SCC.

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 for the financing costs, or “carrying costs”, of its investment in natural gas inventory. The ICC factor applied to average inventory is 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.

During times of rising gas costs and rising inventory levels, the Company recognizes ICC revenues to offset higher financing costs associated with higher inventory balances. Conversely, during times of decreasing gas costs and declining inventory balances, the Company recognizes less carrying cost revenue as financing costs are lower. In addition, ICC revenues are impacted by changes in the weighted-average cost of capital. Although, the average balance of storage gas at September 30, 2018 was higher than last year due to higher injection prices earlier in the year, ICC revenues declined by $35,000 due to an overall 8% reduction in the ICC factor related to the lower federal income tax rate more than offsetting a higher equity allocation. The combination of lower average storage balances and a reduction in the ICC factor resulted in a nearly $63,000 decline in ICC revenues for fiscal 2017 from fiscal 2016. Based on current storage balances and natural gas futures, the average dollar balance of gas in storage should remain stable and, with a more consistent ICC factor, should result in less volatility in ICC revenues.

Generally, as investment in natural gas inventory increases so does the level of borrowing under the Company’s line-of-credit. However, as the carrying cost factor used in determining ICC revenues is based on the Company’s weighted-average cost of capital, ICC revenues do not directly correspond with incremental financing costs generally provided by the line-of-credit. Therefore, when inventory cost balances decline due to a reduction in commodity prices, net income will decline as carrying cost revenues decrease by a greater amount than the line-of-credit costs decrease. The inverse occurs when inventory costs increase.

The Company’s non-gas rates are designed to allow for the recovery of non-gas related expenses and provide a reasonable return to shareholders. These rates are determined based on the filing of a formal rate application with the SCC. Generally, investments related to extending service to new customers are recovered through the additional revenues generated by the non-gas rates currently in place. The investment in replacing and upgrading existing infrastructure is generally not recoverable until a formal rate application is filed to include the additional investment, and new non-gas rates are approved. The SAVE Plan and Rider provides the Company with the ability to recover costs

16

related to these SAVE qualified investments on a prospective basis rather than on a historical basis. The SAVE Plan provides a mechanism to recover the related depreciation and expenses and provide a return on rate base of the additional capital investments related to improving the Company's infrastructure until such time a formal rate application is filed to incorporate this investment in the Company's non-gas rates. SAVE Plan revenues have grown each year corresponding to the level of SAVE qualifying capital investment. The Company recognized approximately $4,469,000, $3,813,000, $2,538,000 in SAVE Plan revenues for years ended September 30, 2018, 2017 and 2016, respectively. The current SAVE revenues have been incorporarted as part of the non-gas base rates in the Company's current general rate case application, which go into effect in January 2019. Additional information regarding the SAVE Rider is provided under the Regulatory Affairs section.

The economic environment has a direct correlation with business and industrial production, customer growth and natural gas utilization. Currently, the local economy appears to show growth and should continue to improve absent a major economic setback on a local, regional or national level.

Results of Operations

Fiscal Year 2018 Compared with Fiscal Year 2017

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

Operating Revenues
Year Ended September 30,	2018		2017		Increase		Percentage
Gas Utilities	$	64,341,783	$	61,252,015	$	3,089,768	5	%
Other	1,192,953		1,044,855		148,098		14	%
Total Operating Revenues	$	65,534,736	$	62,296,870	$	3,237,866	5	%

Delivered Volumes
Year Ended September 30,	2018	2017	Increase	Percentage
Regulated Natural Gas (DTH)
Residential and Commercial	7,103,825	5,840,883	1,262,942	22	%
Transportation and Interruptible	2,822,149	2,721,699	100,450	4	%
Total Delivered Volumes	9,925,974	8,562,582	1,363,392	16	%
Heating Degree Days (Unofficial)	3,954	3,250	704	22	%

Total gas utility operating revenues for the year ended September 30, 2018increased by 5% from the year ended September 30, 2017 primarily due to higher gas sales and increased SAVE Plan revenues more than offsetting refunds related to the reduction in the corporate federal income tax rate and lower gas costs. Total natural gas deliveries increased by 16% over last year primarily due to weather and increased commercial and industrial consumption. Industrial consumption, as reflected in the transportation and interruptible volumes, increased as net production activities increased due to a stronger local economy. Residential and commercial customers natural gas usage tend to be more weather sensitive as reflected by a 22%increase in volumes on 22%more heating degree days. Usage by larger commercial customers, which generally are less weather sensitive than residential and smaller commercial customers, increased by 20% due to a combination of colder weather, new business development in the region and increased usage by existing customers. SAVE Plan revenues grew by 17% due to the Company's ongoing investment in its SAVE related infrastructure replacement program. The Company also recorded a reserve in the amount of $1,320,167 associated with the accumulated excess revenues billed to customers as a result of the reduction in the corporate federal income tax rate. Other revenues increased by 14% due to increased customer requirements.

17

Gross Utility Margin
Year Ended September 30,	2018		2017		Increase / (Decrease)			Percentage
Utility revenues	$	64,341,783	$	61,252,015	$	3,089,768		5	%
Cost of gas	32,091,923		28,919,625		3,172,298			11	%
Gas Utility Margin	$	32,249,860	$	32,332,390	$	(82,530	)	—	%

Regulated natural gas margins from utility operations (total utility revenues less utility cost of gas) were nearly unchanged from fiscal 2017, as higher SAVE Plan revenues and increased volume deliveries were offset by the excess revenue reserve adjustment to refund customers for the effects of the lower federal income tax rate. Total SAVE Plan revenues increased by $656,000 as the Company continues to invest in qualified infrastructure projects. Since January 2014, the Company has invested nearly $40,000,000 in such projects. Volumetric margin increased by nearly $2,316,000 due to greater natural gas deliveries resulting from much colder weather and growth in both customers and non-weather related customer usage. Much of the margin related to increased sales was offset by a much lower WNA adjustment. Weather during fiscal 2018 was nearly normal while the weather last year was 18% warmer than normal resulting in a reduction in the WNA adjustment of $1,795,000. The remaining net increase in WNA adjusted margin is related to increased economic activity in the region combined with customer growth. ICC revenues declined by $35,000 due to a lower ICC factor.

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

	Twelve Months Ended September 30,
	2018			2017		Increase / (Decrease)
Customer Base Charge	$	12,476,755		$	12,412,753	$	64,002
SAVE Plan	4,468,556			3,813,043		655,513
Volumetric	15,889,359			13,573,704		2,315,655
WNA	44,569			1,839,454		(1,794,885		)
Carrying Cost	554,090			588,624		(34,534		)
Rate Refund	(1,320,167		)	—		(1,320,167		)
Other	136,698			104,812		31,886
Total	$	32,249,860		$	32,332,390	$	(82,530	)

Operations and Maintenance Expense - Operations and maintenance expenses decreased by $751,151, or 6%, from last year due to reductions in compensation, contracted services and benefit costs, partially offset by higher bad debt expense. Total operation and maintenance compensation declined by $127,000 in large part due to the reduction in employees related to the outsourcing of the customer service function, net of additions in other areas. Contracted services also declined as the higher costs related to outsourcing the customer service function were offset by declines in meter reading costs, due to the implementation of an automated meter reading system in fiscal 2017, and the insourcing of the utility line locating function. Employee benefit costs declined by $705,000 primarily as a result of decreases in the actuarially determined expenses of both the pension and other post-retirement benefit plans as reflected in Note 8. Strong asset performance and funding combined with an increase in the discount rate served to reduce the actuarially determined expenses of the plans and improve the overall funded status. Bad debt expense increased by $85,000 on higher gross customer billings due to a much colder heating season compared to the prior year. Total capitalized overheads were nearly unchanged from the prior year as increases in capital expenditures were offset by lower capitalization rates, due to benefit plan reductions and other factors. The remaining variance relates to a variety of offsetting factors.

General Taxes - General taxes increased$91,940, or 5%, primarily due to higher property taxes associated with increases in utility property offset by lower payroll taxes.

Depreciation - Depreciation expense increased by $699,607, or 11%, corresponding to 10% increase in utility plant investment.

18

Equity in Earnings of Unconsolidated Affiliate - The equity in earnings of the MVP investment increased by $516,885 due to the allowance for funds used during construction ("AFUDC") related to the increasing investment in the project. The investment in Mountain Valley Pipeline and the related AFUDC earnings are discussed further under the Equity Investment in Mountain Valley Pipeline section below.

Other (Income) Expense - Other (income) expense moved from $132,446 in net expense to $122,330 in net income primarily due to the implementation of a revenue sharing incentive mechanism related to the gas supply asset management agreement, lower pipeline assessments and charitable commitments and higher interest earnings. See the Regulatory and Tax Reform section below for more information on revenue sharing.

Interest Expense - Total interest expense increased by $544,311, or 28%, due to a 20% increase in the average total debt outstanding during the year. Most of the net increase in borrowing is attributable to the investment in Mountain Valley Pipeline. Roanoke Gas funded its capital expenditures for 2018 through the $15 million equity infusion from Resources. The average interest rate increased during the current year from 3.56% to 3.80%. The increase in the average interest rate is due to the issuance of the $8,000,000 unsecured notes on October 2, 2017 at a rate of 3.58% which replaced a portion of the lower-ate balance under the line-of-credit combined with the rising interest rate on the Company's variable-rate debt.

Income Taxes - Income tax expense decreased by $910,254, or 24%, even though pre-tax earnings increased. The effective tax rate was 28.4% for fiscal 2018 compared to 37.9% for fiscal 2017. This decrease in the effective tax rate and income tax expense corresponds to the reduction in the corporate federal income tax rate from 34% for fiscal 2017 to 24.3% for fiscal 2018, and ultimately to 21% in fiscal 2019. More information regarding the impact of tax reform can be found in Note 7 and under the Regulatory and Tax Reform section below.

Net Income and Dividends - Net income for fiscal 2018 was $7,297,205 compared to $6,232,865 for fiscal 2017. Basic and diluted earnings per share were $0.95 in fiscal 2018 compared to $0.86 in fiscal 2017. Dividends declared per share of common stock were $0.62 in fiscal 2018 compared to $0.58 in fiscal 2017.

Fiscal Year 2017 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	)%

Total gas utility operating revenues for the year ended September 30, 2017 increased by 5% from the year ended September 30, 2016 primarily due to higher gas costs and increased SAVE Plan revenues more than offsetting a reduction in natural gas deliveries. The average commodity price of natural gas increased by 11% per decatherm sold due to higher commodity prices. Delivered volumes declined primarily due to weather, as reflected in the lower

19

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. Transportation and interruptible volumes, which are primarily driven by production activities rather than weather, decreased by 1%. Other revenues experienced a 6% increase.

Gross Utility Margin
Year Ended September 30,	2017		2016		Increase		Percentage
Utility revenues	$	61,252,015	$	58,079,990	$	3,172,025	5	%
Cost of gas	28,919,625		27,009,330		1,910,295		7	%
Total Gross Margin	$	32,332,390	$	31,070,660	$	1,261,730	4	%

Regulated natural gas margins from utility operations increased by 4% from fiscal 2016, primarily as a result of increasing SAVE Plan revenues. Total SAVE Plan revenues increased by $1,275,000 on the increasing investment in qualified infrastructure projects. Volumetric margin declined by nearly $526,000 due to a reduction in total volumes delivered. Residential and commercial volumes declined due to warmer weather. Interruptible and transportation volumes were nearly unchanged reflecting only a small decline. The impact of the warmer weather on volumetric margin was offset by the WNA, which provided approximately $522,000 in revenues. As discussed in more detail above, the WNA allowed the Company to recognize margin related to those natural gas volumes not delivered due to the warmer weather. ICC revenues declined by $63,000 due to lower average gas storage balance and a lower ICC factor.

The changes in the components of the gas 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

Operations and Maintenance Expense - Operations and maintenance expenses, in total, were nearly unchanged reflecting a net increase of $1,955 for the year. Expense declines in certain areas were offset by higher expenses in other categories. The most significant offsets pertain to labor, contracted services, employee benefit costs, corporate insurance, capitalized overheads and bad debt expense. Total operation and maintenance labor declined by $158,000 primarily as a result of the outsourcing of the Company's customer service, billing and credit and collection functions. Management made a strategic decision to transfer these operations to a provider that has significant experience in serving utility clients. In July 2017, the Company transitioned to the service provider, resulting in a reduction of 18 employees. The personnel savings from this work force reduction was partially 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 a reduction in the general and administrative overhead rate and less LNG overheads due 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.

20

General Taxes - General taxes increased $122,944, or 7%, primarily due to higher property taxes associated with increases in utility property.

Depreciation - Depreciation expense increased by $665,127, or 12%, corresponding to 10% increase in utility plant investment.

Equity in Earnings of Unconsolidated Affiliate - The equity in earnings of the Mountain Valley Pipeline investment increased by $268,782 primarily consisting of the allowance for funds used during construction.

Other (Income) Expense - Other expense, net, decreased by $123,139, or 48%, primarily due to lower pipeline assessments and charitable commitments.

Interest Expense - Total interest expense increased by $280,933, or 17%, due to a 24% increase in the average total debt outstanding. The combination of Mountain Valley Pipeline investments and the level of capital expenditures during fiscal 2017 generated the higher debt balances. The average interest rate declined 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 expense increased by $139,206, or 4%, on higher pre-tax earnings. The effective tax rate was 37.9% for fiscal 2017 compared to 38.7% for fiscal 2016. The lower effective tax rate was attributable to the exercise of stock options during the year, which resulted in additional tax deductions above the amount recorded at grant date due to the significant appreciation in stock price over the grant price.

Net Income and Dividends - Net income for fiscal 2017 was $6,232,865 compared to $5,806,866 for fiscal 2016. Basic and diluted earnings per share were $0.86 in fiscal 2017 compared to $0.81 in fiscal 2016. Dividends declared per share of common stock were $0.58 in fiscal 2017 compared to $0.54 in fiscal 2016. All per share amounts were restated for the three-for-two stock split effective March 1, 2017.

Capital Resources and Liquidity

Due to the capital intensive nature of the utility business, as well as the related weather sensitivity, the Company’s primary capital needs are for the funding of its continuing construction program, the seasonal funding of its natural gas inventories and accounts receivables and payment of dividends. To meet these needs, the Company relies on its operating cash flows, line-of-credit agreement, long-term debt and capital raised through the issuance of common stock.

Cash and cash equivalents increased by $177,771 in fiscal 2018 compared to decreases of $573,612 and $341,982 in fiscal 2017 and 2016, respectively. The following table summarizes the categories of sources and uses of cash:

Cash Flow Summary	Year Ended September 30,
	2018			2017			2,016
Net cash provided by operating activities	$	13,503,795		$	12,980,978		$	14,921,640
Net cash used in investing activities	(34,166,578		)	(23,492,555		)	(20,996,501		)
Net cash provided by financing activities	20,840,554			9,937,965			5,732,879
Increase (decrease) in cash and cash equivalents	$	177,771		$	(573,612	)	$	(341,982	)

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 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 quarters, operating cash flows generally decrease due to the combination of increasing natural gas storage levels and rising customer receivable balances.

21

Cash provided by operating activities was $13,504,000 in fiscal 2018, $12,981,000 in fiscal 2017 and $14,922,000 in fiscal 2016. Cash provided by operating activities increased by more than $500,000 over last year primarily as the net result of several items including net income, depreciation, rate refund, and prepaid income taxes, offset by change in over-collections and deferred income taxes. Strong earnings in fiscal 2018 combined with higher depreciation, related to the increasing investment in natural gas infrastructure, provided nearly $1,800,000 in additional operating cash over last year. Tax reform impacted liquidity in several ways. An additional $2.5 million was provided from a reduction in prepaid income taxes, associated with the lower federal income tax rate, and the establishment of a rate refund for excess billings to customers, as discussed under the Regulatory and Tax Reform section below. In addition, cash provided by increases in deferred taxes, both the combined deferred taxes and the regulatory liability related to deferred taxes, declined significantly as the TCJA eliminated bonus depreciation for utilities. Furthermore, the Company will be refunding the net regulatory liability for excess deferred taxes over the next several years. Stable natural gas prices and near normal weather in fiscal 2018 combined with the refunding of the prior year over-collection of gas costs resulted in a $2.4 million use of cash as the over-collection of gas costs moved to an under-collected position by the end of the year.

	Twelve Months Ended September 30,
Cash Flows From Operating Activities:	2018			2017			Increase (Decrease)
Net Income	$	7,297,205		$	6,232,865		$	1,064,340
Depreciation	7,090,169			6,378,368			711,801
Gas in storage	74,698			(265,109		)	339,807
Prepaid income taxes	959,142			(245,989		)	1,205,131
Change in over-collection of gas costs	(2,360,972		)	528,387			(2,889,359		)
Deferred taxes	755,994			3,325,379			(2,569,385		)
Accounts payable and accrued expenses	191,054			(989,683		)	1,180,737
Rate refund	1,320,167			—			1,320,167
Other	(1,823,662		)	(1,983,240		)	159,578
Net cash provided by operating activities	$	13,503,795		$	12,980,978		$	522,817

Cash Flows Used in Investing Activities:

Investing activities primarily consist of expenditures under the Company’s construction program, which involves a combination of replacing aging natural gas pipe with new plastic or coated steel pipe, making improvements to the LNG plant and distribution facilities and expanding its natural gas system to meet the demands of customer growth, as well as the continued investment in the LLC. The Company’s expenditures related to its pipeline renewal program and other system and infrastructure improvements increased to nearly $23,300,000 in fiscal 2018 from $20,700,000 in fiscal 2017 and $18,000,000 in fiscal 2016. The Company renewed 8.3 miles of natural gas distribution main and replaced 496 service lines to customers in fiscal 2018. This compares to 9 miles of main and 459 service lines in fiscal 2017 and 14.9 miles of main and 684 service lines in fiscal 2016. The current renewal program is focused on replacement of pre-1973 first generation plastic pipe as the Company completed the replacement of its cast iron and bare steel pipe in late 2016. In addition, the Company’s capital expenditures included costs to extend natural gas distribution mains and services to 451 new customers in fiscal 2018 compared to 499 new customers in fiscal 2017 and 495 new customers in fiscal 2016. Total capital expenditures increased by more than $2.5 million even though the prior year included the implementation of the automated meter reading ("AMR") project. The AMR project involved the retrofitting of all customer meters with transponders to allow consumption data to be collected remotely. Fiscal 2018 projects included a major system reinforcement to increase capacity within certain areas of the Company's natural gas distribution system, the extension of gas service to a new industrial park, which included system reinforcement to the surrounding service area, and progress toward extending the Roanoke Gas' distribution pipeline to interconnect with the MVP. Depreciation covered approximately 30% of the current year's capital expenditures compared to 31% for 2017 and 32% for 2016, with the balance provided from other operating cash flows and borrowings.

Capital expenditures are expected to remain at elevated levels over the next few years. The Company is continuing its focus on replacing the remaining pre-1973 first generation plastic pipe with polyethylene pipe. This renewal project is expected to be completed in a few years. The current capital budget for fiscal 2019 is projected at more than $21,000,000, consistent with fiscal 2018 and 2017 levels. In addition to the replacement of pre-1973 plastic pipe, the Company plans to complete its interconnect with the Mountain Valley Pipeline at two locations, extend service to

22

another industrial park and conduct two additional system reinforcements to meet increasing demand and ensure the continued reliability of gas service. The Company expects to increase its borrowing activity to meet the funding requirements of these planned expenditures.

Investing cash flows also reflect the Company's $11,036,247 funding of its participation in the LLC. The Company's total expected funding increased to $46 million as discussed below, with anticipated cash investment for fiscal 2019 to be more than $22 million. Funding for the investment in the LLC is currently provided through the $38 million credit facility, which matures in 2020. The source for the balance of the financing is currently being evaluated. More information regarding the credit facility is provided in Note 6 and under the Equity Investment in Mountain Valley Pipeline section below.

Cash Flows Provided by (Used in) Financing Activities:

Financing activities generally consist of borrowings and repayments under debt agreements, issuance of stock and the payment of dividends. Cash flows provided by financing activities were $20,841,000, $9,938,000 and $5,733,000 in fiscal 2018, 2017 and 2016 respectively. 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. The combination of Resources' equity issuance, Roanoke Gas' $8,000,000 unsecured notes and Midstream's $11,431,000 borrowing accounted for the increased cash flows. Roanoke Gas used the proceeds from the $8,000,000 unsecured notes to refinance a portion of the line-of-credit balance and used the equity infusion from Resources to reduce the line-of-credit balance further. Total proceeds from the issuance of stock were $16,520,000 with $15,110,000 from the issuance of 700,000 shares in an equity offering and the balance issued under the Company's stock plans. Dividends increased to $4,647,000 as the annualized dividend rate per share went from $0.58 in fiscal 2017 to $0.62 in fiscal 2018.The Company’s consolidated capitalization was 53.0% equity and 47.0% long-term debt at September 30, 2018, exclusive of unamortized debt expense. This compares to 49.4% equity and 50.6% long-term debt at September 30, 2017. The long-term debt as a percent of long-term capitalization decreased from last year due to the equity issue offering.

On April 11, 2018, Midstream entered into the First Amendment to Credit Agreement ("Amendment") and amendments to the related Promissory Notes ("Notes") originally issued in December 2015. Under the provisions of the Amendment, the total borrowing limits under the Notes increased to $38,000,000, with a reduction in the interest rate to 30-day LIBOR plus 135 basis points. No changes were made to the due dates on the Notes, which mature on December 29, 2020.

On March 26, 2018, Roanoke Gas entered into a new unsecured revolving line-of-credit note agreement. The new line-of-credit agreement is for a two-year term expiring March 31, 2020, replacing the two-year agreement that expired on March 31, 2019. 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 multi-tiered borrowing limits to accommodate seasonal borrowing demands and minimize borrowing costs. The total available borrowing limits during the term of the new agreement range from $2,000,000 to $25,000,000. As the agreement is for a two-year term, amounts drawn against the new agreement are generally considered to be non-current. The Company intends to request an extension of the agreement by one year prior to next March when the outstanding 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.

On October 2, 2017, the Company issued two 10-year unsecured notes in 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 each year until the notes mature. The proceeds from these notes were used to refinance a portion of the line-of-credit balance 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).

Contractual Obligations and Commitments

The Company has incurred various contractual obligations and commitments in the normal course of business. As of September 30, 2018, the estimated recorded and unrecorded obligations are as follows:

23

Recorded contractual obligations:	Less than 1 year		1-3 Years		4-5 Years		After 5 Years		Total
Long-Term Debt - Notes Payable (1)	$	—	$	17,743,200	$	7,000,000	$	38,500,000	$	63,243,200
Long-Term Debt - Line of Credit (2)	—		7,361,017		—		—		7,361,017
Total	$	—	$	25,104,217	$	7,000,000	$	38,500,000	$	70,604,217
(1) See Note 6 to the consolidated financial statements.
(2) See Notes 5 and 6 to the consolidated financial statements. New line-of-credit agreement executed for a 2-year term, expiring March 31, 2020. 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)	$	11,184,000	$	15,360,868	$	8,217,849	$	1,950,134	$	36,712,851
Gas Supply (4)	—		—		—		—		—
Interest on Line-of-Credit (5)	41,447		18,571		—		—		60,018
Interest on Notes Payable (6)	1,928,013		3,721,105		3,185,711		15,396,752		24,231,581
Pension Plan Funding (7)	—		—		—		—		—
Investment in MVP (8)	22,231,073		6,295,212		—		—		28,526,285
Franchise Agreements (9)	107,302		224,357		238,021		1,942,731		2,512,411
Other Obligations (10)	215,833		424,281		11,503		138,379		789,996
Total	$	35,707,668	$	26,044,394	$	11,653,084	$	19,427,996	$	92,833,142
(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, 2018, 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, 10-year $8 million Roanoke Gas Co. Prudential note payable due October 02, 2027, and on the September 30, 2018 balance on Midstream notes due December 29, 2020. See Note 6 to the consolidated financial statements.
(7) Estimated minimum funding requirement 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 2019.
(8) Projected remaining funding of the Company's 1% interest in the LLC as entered into on October 1, 2015.
(9) Franchise tax obligations due Roanoke City, Salem City and Town of Vinton per 20-year term agreements. See Note 11 to the consolidated financial statements.
(10) Various lease, maintenance, equipment and service contracts.

Equity Investment in Mountain Valley Pipeline

On October 1, 2015, the Company, through its wholly-owned subsidiary Midstream, entered into an agreement to become a 1% member in the LLC. The purpose of the LLC is to construct and operate the Mountain Valley Pipeline ("MVP"), a natural gas pipeline connecting the Equitrans gathering and transmission system in northern West Virginia to the Transco interstate pipeline in south central Virginia.

Management believes the investment in the LLC will be beneficial for the Company, its shareholders and southwest Virginia. In addition to the potential returns from the investment in the LLC, Roanoke Gas will benefit from access to another source of natural gas to its distribution system. Currently, Roanoke Gas is served by two pipelines and a liquefied natural gas storage facility. Damage to or interruption in supply from any of these sources, especially during the winter heating season, could have a significant impact on the Company's ability to serve its customers. A third

24

pipeline would reduce the impact from such an event. In addition, the proposed pipeline path would provide the Company with a more economically feasible opportunity to provide natural gas service to previously unserved areas in southwest Virginia.

On October 13, 2017, FERC issued the Certificate of Public Convenience and Necessity to the MVP, and since January 2018, FERC has issued several Notices to Proceed, which granted the LLC permission to begin construction activities. The LLC also had received the necessary federal permits and the required Virginia and West Virginia environmental agency permits. Since construction began on the pipeline, the LLC has encountered various challenges to the project, including pipeline protesters, legal challenges to various federal and state permits resulting in stop orders and FERC intervention. Currently, the LLC is continuing its pipeline installation activities with the exception of sections along the route that cross waterways and through the Jefferson National Forest and associated watershed. The LLC plans to continue its construction activities and will work with court and corresponding permitting agencies to resolve the issues that have limited construction activities in these areas.

Intially, the total project cost was estimated at $3.5 billion, and as a 1% member in the LLC, Midstream's cash contribution was expected to be approximately $35 million. As a result of the delays in construction, the LLC revised the project cost to an estimated $4.6 billion with Midstream's estimated investment increasing to $46 million. Furthermore, the anticipated completion date for the pipeline has been extended to the fourth quarter of calendar 2019. In April 2018, Midstream, in conjunction with its lenders, amended the two 5-year unsecured Promissory Notes, which increased the available borrowing limits to $38 million and reduced the variable interest rate. With the recently revised project cost, Midstream will need an additional $8 million in funding to fulfill its obligation. Management is currently evaluating various financing options for the remaining balance.

A majority of the current earnings from the investment in MVP relates to the AFUDC income generated by the deployment of capital in the design, engineering, materials procurement, project management and ultimately construction phases of the pipeline. AFUDC is an accounting method whereby the costs of debt and equity funds used to finance facility infrastructure are credited to income and charged to the cost of the project. The level of investment in MVP, as well as the AFUDC, will continue to grow as construction activities continue. Once the pipeline is completed and placed into service, AFUDC will cease. Earnings after the pipeline is operational will be derived from the fees charged for transporting natural gas through the pipeline.

On April 11, 2018, the LLC announced the MVP Southgate project, which is a planned 70 mile pipeline extending from the MVP mainline in Virginia to delivery points in North Carolina. Midstream will be a less than 1% investor in the Southgate project and, based on current project cost estimates, will invest between $1.8 million and $2.5 million toward the project. On November 6, 2018, the LLC filed with FERC the formal application request to construct the Southgate pipeline. Unlike with its investment in the Mountain Valley Pipeline, where the Company was an important member of the project and where the pipeline would benefit Roanoke Gas by providing additional natural gas access to its distribution system, Midstream's participation in the Southgate project is for investment purposes only.

Regulatory and Tax Reform

Based on its evaluation of the effects of tax reform as discussed in Note 3 and below and the changes in plant investment, operating expenses, regulatory assets and capital structure, Roanoke Gas filed a general rate application request incorporating all of these changes into new non-gas base rates. As part of the rate application, revenues currently collected under the SAVE Plan mechanism through December 31, 2018 will be incorporated into the non-gas rates through revised customer base charge and volumetric rates rather than through a separate rider. The new non-gas rates will be placed in effect for service rendered on or after January 1, 2019, subject to refund pending a final order from the SCC. The new rates are designed to collect an additional $10.5 million per year in non-gas rates, including approximately $4.7 million currently being recovered through the SAVE Plan rider.

The Company continues to recover the costs of its infrastructure replacement program through its SAVE Plan. The original SAVE Plan was designed to facilitate the accelerated replacement of aging natural gas pipe by providing 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. Since the implementation and approval of the original SAVE Plan in 2012, the Company has modified, amended and updated it each year to incorporate various qualifying projects. On September 28, 2018, the SCC issued their order approving the 2019 SAVE Plan and SAVE rider effective January 1, 2019 with a continued focus on the ongoing replacement of the pre-1973 plastic pipe. As all previous SAVE investment has been incorporated into the general rate application, the new SAVE Plan Rider will reflect only the recovery of qualifying SAVE Plan investments beginning in January 2019.

25

The 2019 SAVE Plan Rider is expected to provide approximately $362,000 in revenue. In addition, the SCC also approved the true-up factor for the 2017 SAVE Plan, which will refund approximately $163,000 in excess SAVE Plan revenues to customers.

As disclosed in Notes 3 and 7, the TCJA was signed into law on December 22, 2017 and provided sweeping changes to the federal income tax code. The most significant change included the reduction of the maximum corporate federal income tax rate from 35% to 21%. Another significant change included the elimination of bonus depreciation for utilities in exchange for retaining the full deductibility of utility related interest expense. There were several other changes to the tax code that will have lesser impact on the Company.

The reduction in the federal corporate tax rate impacted the Company's financial statements in three areas: income tax expense, deferred income taxes and utility revenues. As the tax rate change became effective January 1, 2018, the Company used a blended tax rate for fiscal 2018 calculated on the average number of days each tax rate was in effect for the fiscal year. The Company's calculated federal tax rate during 2018 was 24.3% with an overall tax rate, including state income tax, of 28.84%. This compares to an overall rate of 37.96% in prior years. In fiscal 2019, the overall tax rate will decline to 25.74% as the federal tax rate will fully transition to 21%.

ASC 740, Income Taxes, requires entities to revalue their deferred tax assets and liabilities based on changes in tax rates and record the change in income tax expense. As a result of TCJA, deferred tax assets and liabilities have been revalued from a 34% federal income tax rate to the new rate of 21%. For rate regulated entities, such as Roanoke Gas, the excess deferred income taxes were originally derived from its customers based on billing rates utilizing the 34% federal income tax rate. Instead of recording the adjustment to deferred income taxes as a component of income tax expense in the current period, the excess net deferred taxes were recorded as a regulatory liability to be refunded to, or collected from, to the extent such net deferred tax assets and liabilities were attributable to rate base or cost of service of its customers. As of September 30, 2018, Roanoke Gas had a net regulatory liability for excess deferred income taxes consisting of $12.7 million related to excess tax depreciation which will be refunded to customers over the remaining average life of assets using the Reverse South Georgia method and $1.3 million in net deferred tax assets that will be collected from customers over a period yet to be determined. The revaluation of deferred income taxes of the non-rate regulated operations of Resources and Midstream resulted in $256,000 charge to income tax expense. On direction from the SCC, Roanoke Gas has begun refunding the excess deferred taxes to customers resulting in a corresponding net reduction in revenue and income tax expense of $264,000.

As noted above, Roanoke Gas filed a general rate application request, in part, to incorporate the impact of the TCJA in the non-gas rates billed to customers. The non-gas base rates used during fiscal 2018 were derived from a federal income tax rate of 34%. As a result, Roanoke Gas has over-recovered from its customers the difference between federal income tax expense of 34% and 24.3% (blended rate) for fiscal 2018. The SCC issued a directive in early 2018 requiring all utilities to accrue a liability to refund customers for the excess revenue collected from customers due to the reduction in the federal income tax rate. As of September 30, 2018, the Company has accrued an estimated $1.3 million reduction in revenues and established a corresponding liability to be refunded to customers. Roanoke Gas will continue to bill customers at rates that are based on the higher federal income tax rate until the new non-gas base rates are placed into effect in January 2019. The amount to be refunded to customers is the Company's best estimate based on the available information and is subject to review and approval by the SCC.

The Company currently holds the only franchises and certificates of public convenience and necessity to distribute natural gas in its service area. Certificates of public convenience and necessity are issued by the SCC to provide service in the cities and counties in the Company's service territory. These certificates are intended for perpetual duration subject to compliance and regulatory standards. Franchises are granted by the local cities and towns served by the Company and are generally granted for a defined period of time. The current franchise agreements with the City of Roanoke, the City of Salem and the Town of Vinton will expire December 31, 2035.

On May 7, 2018, the SCC granted the Company's motion to resume its proceeding for the application of a Certificate of Public Convenience and Necessity to include the remaining portions of Franklin County, Virginia into its authorized natural gas service territory. A decision from the SCC is pending and should be received in the near future.

Roanoke Gas contracts with a third party asset manager to manage its pipeline transportation, storage rights and gas supply inventories and deliveries. In return for the right to utilize the excess capacities of the transportation and storage rights, the asset manager credits Roanoke Gas monthly for an amount referred to as a utilization fee. In June 2018, the SCC issued an order approving implementation of an incentive mechanism, whereby the Company would share the utilization fee with its customers. Under the incentive mechanism, customers would receive the initial $700,000 of the

26

utilization fee collected through reduced gas costs and thereafter every additional dollar received during the annual period would be shared 25% to the Company and 75% to its customers. The SCC order provided retroactive application of the incentive mechanism to April 1, 2018. The Company recognized approximately $138,000 from the incentive mechanism for the year.

Critical Accounting Policies and Estimates

The consolidated financial statements of Resources are prepared in accordance with accounting principles generally accepted in the United States of America. The amounts of assets, liabilities, revenues and expenses reported in the Company’s financial statements are affected by accounting policies, estimates and assumptions that are necessary to comply with generally accepted accounting principles. Estimates used in the financial statements are derived from prior experience, statistical analysis and professional judgments. Actual results may differ significantly from these estimates and assumptions.

The Company considers an estimate to be critical if it is material to the financial statements and requires assumptions to be made that were uncertain at the time the estimate was made and changes in the estimate are reasonably likely to occur from period to period. The Company considers the following accounting policies and estimates to be critical.

Regulatory accounting - The Company’s regulated operations follow the accounting and reporting requirements of FASB ASC No. 980, Regulated Operations. The economic effects of regulation can result in a regulated company deferring costs that have been or are expected to be recovered from customers in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as assets in the consolidated balance sheet (regulatory assets) and recorded as expenses when such amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for current collection in rates of costs that are expected to be incurred in the future (regulatory liabilities).

If, for any reason, the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the Company would remove the applicable regulatory assets or liabilities from the balance sheet and include them in the consolidated statements of income and comprehensive income for the period in which the discontinuance occurred.

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 be adjusted quarterly 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 refund excess revenue collected for weather that was colder than the 30-year average or bill the customer for revenue short-fall for 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 natural gas delivered to customers but not yet billed during the accounting period based on weather during the period and current and historical data. The financial statements include unbilled revenue of $911,657 and $965,683 as of September 30, 2018 and 2017, respectively.

The Company will adopt ASU 2014-09, Revenue from Contracts with Customers, and subsequent guidance, beginning in October 2018. Management has determined that the new standard will not have a material impact on the Company's

27

financial position, results of operations or cash flows. The Company will adopt the new guidance using the modified retrospective approach.

Allowance for Doubtful Accounts - The Company evaluates the collectability of its accounts receivable balances based upon a variety of factors including loss history, level of delinquent account balances, collections on previously written off accounts and general economic conditions. The Company recently outsourced its credit and collections function as part of its strategic decision to move the call center, billing and other customer service functions to a third party provider with significant utility experience. These changes will impact the current valuation model for accounts receivable, which used historical information based on collection functions previously handled by Company personnel.

Pension and Postretirement Benefits - The Company offers a defined benefit pension plan (“pension plan”) and a postretirement medical and life insurance plan (“postretirement plan”) to eligible employees. The expenses and liabilities associated with these plans, as disclosed in Note 8 to the consolidated financial statements, are based on numerous assumptions and factors, including provisions of the plans, employee demographics, contributions made to the plan, return on plan assets and various actuarial calculations, assumptions and accounting requirements. In regard to the pension plan, specific factors include assumptions regarding the discount rate used in determining future benefit obligations, expected long-term rate of return on plan assets, compensation increases and life expectancies. Similarly, the postretirement medical plan also requires the estimation of many of the same factors as the pension plan in addition to assumptions regarding the rate of medical inflation and Medicare availability. Actual results may differ materially from the results expected from the actuarial assumptions due to changing economic conditions, differences in actual returns on plan assets, different rates of medical inflation, volatility in interest rates and changes in life expectancy. Such differences may result in a material impact on the amount of expense recorded in future periods or the value of the obligations on the balance sheet.

In selecting the discount rate to be used in determining the benefit liability, the Company utilized the Citigroup yield curves which incorporate 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 4.11% and 4.09%, respectively, for valuing its pension plan liability and postretirement plan liability at September 30, 2018. These rates increased over the prior year by 0.39% and 0.40%, respectively. The rise in the discount rate is evidenced by the 30-year Treasury rate, which increased from 2.86% to 3.19%. Corporate bond rates increased as well and credit spreads widened among high quality investments supporting a larger discount rate increase. This increase in the discount rates was the primary driver in the reduction of the accumulated benefit obligation on the postretirement plan. The rise in the discount rate for the pension plan nearly offset the increase in liabilities associated with additional credited service and salary increases resulting in small increases in both the accumulated benefit obligation and the projected benefit obligation. The Company used the RP-2014 Mortality Table, adjusted to 2006, with generational mortality improvements using Projection Scale MP-2017 for the current year valuation.

Over the last few years, management has focused 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 employees who were not receiving payments under the plan. Approximately 63%, or 40 former employees, elected to receive their pension benefit in a lump sum, which resulted in a payout of $1,242,000 from plan assets while reducing plan liabilities by nearly $1,500,000 at the time and also reduced the number of participants on which the Pension Benefit Guaranty Corporation ("PBGC") premiums are determined. In 2017, the Company implemented its next de-risking strategy by implementing a "soft freeze" to the pension plan whereby new employees hired on or after January 1, 2017 would not be eligible to participate in the pension plan. 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 medical plan. These strategies have reduced liability growth by not allowing new participants into the plans and reducing the number of participants entitled to future benefits.

The Company also has focused on the asset investment strategy. An aggressive funding strategy combined with strong investment returns have allowed plan assets to increase by $6.8 million over the last three years, while the liabilities under the pension plan increased only $1.7 million during the same period for the reasons noted above. As of September 30, 2018, the pension plan is at a 98% funded status. With future pension liability growth associated with increasing benefits limited to employees hired prior to the freeze, the Company evaluated measures that would mitigate the effect of changing interest rates on the pension liability. As the pension liability represents the present value of future pension payments, an increase in the discount rate used to value the pension obligation would reduce the liability while a reduction in the discount rate would lead to an increase in the pension liability. To limit the potential volatility related to fluctuations in the discount rate, the Company moved to a more conservative asset allocation model by

28

transitioning from a 60% equity and 40% fixed income allocation to a 40% equity and 60% fixed income allocation for pension assets. Furthermore, the Company implemented a Liability Driven Investment approach ("LDI") that matches the duration of the fixed income investments with the duration of the corresponding pension liabilities. As a result, the valuation of the fixed income investments will move inversely to the corresponding pension liabilities as a result of changes in interest rates, which in turn will reduce the volatility in the plan's funded status and expense. The Company continued to retain a 40% investment in equities to provide asset growth potential to offset the growth in pension liability related to those employees continuing to accrue benefits. The Company has not made a change in investment allocation for the postretirement assets as increasing medical and insurance costs warrant the need for a continued higher allocation to equities for future plan asset growth potential. Though not to the same magnitude, the postretirement plan assets increased by $2.5 million and liabilities increased by $0.9 million over the last three-year period.

A summary of the funded status of both the pension and postretirement plans is provided below:

Funded status - September 30, 2018	Pension			Postretirement			Total
Benefit Obligation	$	28,850,299		$	16,207,322		$	45,057,621
Fair value of assets	28,184,697			12,924,957			41,109,654
Funded status	$	(665,602	)	$	(3,282,365	)	$	(3,947,967	)

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	)

The Company annually evaluates the returns on its targeted investment allocation model as well as the overall asset allocation of its benefit plans. Understanding the volatility in the markets, the Company reviews both plans potential long-term rate of return with its investment advisors to determine the rates used in each plan's actuarial assumptions. With the revision to the asset allocation for the pension plan, management reduced the long-term rate of return assumption down to 5.50% from 7%. Likewise, although the asset allocation remained unchanged for the postretirement plan, management's and the advisors' evaluations determined that a 4.30% expected long-term rate of return is reasonable. Management will continue to re-evaluate the return assumptions and asset allocation and adjust both as market conditions warrant.

Management estimates that, under the current provisions regarding defined benefit pension plans, the Company will have no minimum funding requirements next year. However, management plans 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 $800,000 to its pension plan and $300,000 to its postretirement plan in fiscal 2019 with a continuing goal to improve both plans' funded status. The Company will continue to evaluate its benefit plan funding levels in light of funding requirements and ongoing investment returns and make adjustments, as necessary, to avoid benefit restrictions and minimize PBGC premiums.

The following schedule reflects the sensitivity of pension costs to changes in certain actuarial assumptions, assuming that the other components of the calculation remain constant.

Actuarial Assumptions - Pension Plan	Change in Assumption		Increase in Pension Cost		Increase in Projected Benefit Obligation
Discount rate	-0.25	%	$	112,000	$	1,125,000
Rate of return on plan assets	-0.25	%	70,000		N/A
Rate of increase in compensation	0.25	%	43,000		221,000

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.

29

Actuarial Assumptions - Postretirement Plan	Change in Assumption		Increase in Postretirement Benefit Cost		Increase in Accumulated Postretirement Benefit Obligation
Discount rate	-0.25	%	$	52,000	$	625,000
Rate of return on plan assets	-0.25	%	32,000		N/A
Medical claim cost increase	0.25	%	95,000		607,000

Derivatives - The Company may hedge certain risks incurred in its operation through the use of derivative instruments. The Company applies the requirements of FASB ASC No. 815, Derivatives and Hedging, which requires the recognition of derivative instruments as assets or liabilities in the Company’s balance sheet at fair value. In most instances, fair value is based upon quoted futures prices for natural gas commodities and interest rate futures for interest rate swaps. Changes in the commodity and futures markets will impact the estimates of fair value in the future. Furthermore, the actual market value at the point of realization of the derivative may be significantly different from the values used in determining fair value in prior financial statements. The Company had one interest-rate swap outstanding at September 30, 2018 related to the 5-year $7,000,000 variable-rate note. This swap agreement became effective November 1, 2017.

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

The Company is exposed to market risks associated with interest rates and commodity prices. Interest rate risk is related to the Company’s outstanding variable rate debt. Commodity price risk is experienced by the Company’s regulated natural gas operations. The Company’s risk management policy, as authorized by the Company’s Board of Directors, allows management to enter into derivatives for the purpose of managing commodity and financial market risks of its business operations.

Interest Rate Risk

The Company is exposed to market risk related to changes in interest rates associated with its borrowing activities. As of September 30, 2018, the Company has $7,361,017 outstanding under its variable-rate line-of-credit with an average balance outstanding during the year of $6,730,334. The Company also had $17,743,200 outstanding under two 5-year variable rate unsecured term loans and $7,000,000 outstanding on another 5-year variable-rate, which has a fixed rate swap effective November 1, 2017. A hypothetical 100 basis point increase in market interest rates applicable to the Company’s variable-rate debt outstanding during the year would have resulted in an increase in interest expense for the current year of approximately $179,000. The Company’s remaining debt is at a fixed rate.

Commodity Price Risk

The Company is also exposed to market risks through its natural gas operations associated with commodity prices. The Company’s hedging and derivatives policy, as authorized by the Company’s Board of Directors, allows management to enter into both physical and financial transactions for the purpose of managing the commodity risk of its business operations. The policy also specifies that the combination of all commodity hedging contracts for any 12-month period shall not exceed a total hedged volume of 90% of projected volumes. The policy specifically prohibits the use of derivatives for the purposes of speculation.

The Company manages the price risk associated with purchases of natural gas by using a combination of liquefied natural gas (LNG) storage, underground storage gas, fixed price contracts, spot market purchases and derivative commodity instruments including futures, price caps, swaps and collars.

At September 30, 2018, the Company had no outstanding derivative instruments to hedge the price of natural gas. The Company had approximately 2,441,000 decatherms of gas in storage, including LNG, at an average price of $3.13 per decatherm compared to 2,388,000 decatherms at an average price of $3.23 per decatherm last year. The SCC currently allows for full recovery of prudent costs associated with natural gas purchases, and any additional costs or benefits associated with the settlement of derivative contracts and other price hedging techniques are passed through to customers when realized through the regulated natural gas PGA mechanism.

30

Item 8. Financial Statements and Supplementary Data.

31

RGC Resources, Inc.

and Subsidiaries

Consolidated Financial Statements

for the Years Ended September 30, 2018, 2017

and 2016, and Report of Independent

Registered Public Accounting Firm

32

RGC RESOURCES, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

	Page
Report of Independent Registered Public Accounting Firm	34
Consolidated Financial Statements for the Years Ended September 30, 2018, 2017 and 2016:
Consolidated Balance Sheets	35
Consolidated Statements of Income	37
Consolidated Statements of Comprehensive Income	38
Consolidated Statements of Stockholders’ Equity	39
Consolidated Statements of Cash Flows	40
Notes to Consolidated Financial Statements	41

33

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

RGC Resources, Inc.

Roanoke, Virginia

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of RGC Resources, Inc. and Subsidiaries (“the Company”) as of September 30, 2018 and 2017, and the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows for each of the years in the three-year period ended September 30, 2018, 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, 2018 and 2017, and the results of its operations and its cash flows for each of the years in the three-year period ended September 30, 2018, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of September 30, 2018, based on criteria established in Internal Control-Integrated Framework - 2013 issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated December 3, 2018, expressed an unqualified opinion.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

              CERTIFIED PUBLIC ACCOUNTANTS

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

Blacksburg, Virginia

December 3, 2018

34

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

AS OF SEPTEMBER 30, 2018 AND 2017

	2018			2017
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	247,411		$	69,640
Accounts receivable, net	3,913,830			3,492,703
Materials and supplies	913,889			1,021,191
Gas in storage	7,627,196			7,701,894
Prepaid income taxes	837,683			1,796,825
Under-recovery of gas costs	922,898			—
Interest rate swap	100,723			26,777
Other	980,972			1,576,574
Total current assets	15,544,602			15,685,604
UTILITY PROPERTY:
In service	224,854,320			204,223,714
Accumulated depreciation and amortization	(63,099,306		)	(59,765,987		)
In service, net	161,755,014			144,457,727
Construction work in progress	4,208,614			3,470,244
Utility plant, net	165,963,628			147,927,971
OTHER ASSETS:
Regulatory assets	8,862,147			11,796,260
Investment in unconsolidated affiliate	28,507,146			7,445,106
Interest rate swap	209,840			90,066
Other	472,743			190,064
Total other assets	38,051,876			19,521,496
TOTAL ASSETS	$	219,560,106		$	183,135,071

(Continued)

35

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

AS OF SEPTEMBER 30, 2018 AND 2017

	2018			2017
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Dividends payable	$	1,242,753		$	1,050,281
Accounts payable	5,211,032			5,122,899
Capital contributions payable	10,142,766			1,055,504
Customer credit balances	1,003,622			1,220,578
Customer deposits	1,421,043			1,471,960
Accrued expenses	3,750,466			3,006,936
Over-recovery of gas costs	—			1,438,074
Rate refund	1,320,167			—
Total current liabilities	24,091,849			14,366,232
LONG-TERM DEBT:
Notes payable	63,243,200			43,812,200
Line-of-credit	7,361,017			17,791,760
Less unamortized debt issuance costs	(282,281		)	(291,949		)
Long-term debt net of unamortized debt issuance costs	70,321,936			61,312,011
DEFERRED CREDITS AND OTHER LIABILITIES:
Asset retirement obligations	6,417,948			6,069,993
Regulatory cost of retirement obligations	11,163,981			10,055,189
Benefit plan liabilities	3,947,967			8,214,326
Deferred income taxes	12,585,577			23,076,848
Regulatory liability - deferred income taxes	11,447,736			—
Total deferred credits and other liabilities	45,563,209			47,416,356
COMMITMENTS AND CONTINGENCIES (Note 11)
CAPITALIZATION:
Stockholders’ Equity:
Common Stock, $5 par value; authorized 10,000,000 shares; issued and outstanding 7,994,615 and 7,240,846 shares in 2018 and 2017, respectively	39,973,075			36,204,230
Preferred stock, no par; authorized 5,000,000 shares; no shares issued and outstanding in 2018 and 2017	—			—
Capital in excess of par value	13,043,656			292,485
Retained earnings	27,438,049			24,746,021
Accumulated other comprehensive loss	(871,668		)	(1,202,264		)
Total stockholders’ equity	79,583,112			60,040,472
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	219,560,106		$	183,135,071

(Concluded)

See notes to consolidated financial statements.

36

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

YEARS ENDED SEPTEMBER 30, 2018, 2017 AND 2016

	2018			2017		2016
OPERATING REVENUES:
Gas utilities	$	64,341,783		$	61,252,015	$	58,079,990
Other	1,192,953			1,044,855		983,301
Total operating revenues	65,534,736			62,296,870		59,063,291
OPERATING EXPENSES:
Cost of gas - utility	32,091,923			28,919,625		27,009,330
Cost of sales - non utility	666,524			568,088		489,047
Operations and maintenance	12,348,890			13,100,041		13,098,086
General taxes	1,878,010			1,786,070		1,663,126
Depreciation and amortization	6,956,344			6,256,737		5,591,610
Total operating expenses	53,941,691			50,630,561		47,851,199
OPERATING INCOME	11,593,045			11,666,309		11,212,092
Equity in earnings of unconsolidated affiliate	938,531			421,646		152,864
Other (income) expense, net	(122,330		)	132,446		255,585
Interest expense	2,461,565			1,917,254		1,636,321
INCOME BEFORE INCOME TAXES	10,192,341			10,038,255		9,473,050
INCOME TAX EXPENSE	2,895,136			3,805,390		3,666,184
NET INCOME	$	7,297,205		$	6,232,865	$	5,806,866
EARNINGS PER COMMON SHARE:
Basic	$	0.95		$	0.86	$	0.81
Diluted	$	0.95		$	0.86	$	0.81
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic	7,649,025			7,218,686		7,149,906
Diluted	7,695,712			7,256,046		7,159,763

See notes to consolidated financial statements.

37

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

YEARS ENDED SEPTEMBER 30, 2018, 2017 AND 2016

	2018		2017		2016
NET INCOME	$	7,297,205	$	6,232,865	$	5,806,866
Other comprehensive income, net of tax:
Interest rate swaps	137,850		72,489		—
Defined benefit plans	406,798		1,222,478		(210,686		)
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX	544,648		1,294,967		(210,686		)
COMPREHENSIVE INCOME	$	7,841,853	$	7,527,832	$	5,596,180

See notes to consolidated financial statements.

38

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

YEARS ENDED SEPTEMBER 30, 2018, 2017 AND 2016

	Common Stock		Capital in Excess of Par Value			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Stockholders’ Equity
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
Net income	—		—			7,297,205			—			7,297,205
Other comprehensive income	—		—			—			544,648			544,648
Exercise of stock options (1,575 shares)	7,875		12,070			—			—			19,945
Cash dividends declared ($0.62 per share)	—		—			(4,839,514		)	—			(4,839,514		)
Issuance costs	—		(990,459		)	—			—			(990,459		)
Issuance of common stock (752,194 shares)	3,760,970		13,729,560			—			—			17,490,530
Reclassification adjustment for effect of change in tax law	—		—			234,337			(214,052		)	20,285
Balance - September 30, 2018	$	39,973,075	$	13,043,656		$	27,438,049		$	(871,668	)	$	79,583,112

See notes to consolidated financial statements.

39

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

YEARS ENDED SEPTEMBER 30, 2018, 2017 AND 2016

	2018			2017			2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	7,297,205		$	6,232,865		$	5,806,866
Adjustments to reconcile net income to net cash provided by operations:
Depreciation and amortization	7,090,169			6,378,368			5,709,525
Cost of retirement of utility plant, net	(288,222		)	(354,744		)	(449,201		)
Stock option grants	—			73,780			64,640
Equity in earnings of unconsolidated affiliate	(938,531		)	(421,646		)	(152,864		)
Deferred income taxes	755,994			3,325,379			4,466,954
Other noncash items, net	163,482			203,743			197,298
Changes in assets and liabilities which provided (used) cash:
Accounts receivable and customer deposits, net	(476,161		)	(191,386		)	(258,960		)
Inventories and gas in storage	182,000			(462,161		)	867,682
Over/under recovery of gas costs	(2,360,972		)	528,387			(991,739		)
Other assets	784,566			(956,894		)	(398,864		)
Accounts payable, customer credit balances and accrued expenses, net	(25,902		)	(1,374,713		)	60,303
Rate refund	1,320,167			—			—
Total adjustments	6,206,590			6,748,113			9,114,774
Net cash provided by operating activities	13,503,795			12,980,978			14,921,640
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for utility property	(23,290,994		)	(20,750,181		)	(17,945,719		)
Investment in unconsolidated affiliate	(11,036,247		)	(2,759,346		)	(3,055,746		)
Proceeds from disposal of utility property	160,663			16,972			4,964
Net cash used in investing activities	(34,166,578		)	(23,492,555		)	(20,996,501		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under line-of-credit	29,814,468			42,569,303			38,310,326
Repayments under line-of-credit	(40,245,210		)	(39,334,328		)	(33,094,539		)
Proceeds from issuance of unsecured notes	19,431,000			9,916,000			3,396,200
Debt issuance expenses	(32,678		)	(64,835		)	(101,619		)
Proceeds from issuance of stock	16,520,016			967,698			1,031,194
Cash dividends paid	(4,647,042		)	(4,115,873		)	(3,808,683		)
Net cash provided by financing activities	20,840,554			9,937,965			5,732,879
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	177,771			(573,612		)	(341,982		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	69,640			643,252			985,234
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	247,411		$	69,640		$	643,252
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid (refunded) during the year for:
Interest	$	2,137,782		$	1,734,178		$	1,480,665
Income taxes	1,180,000			726,000			(907,000		)

See notes to consolidated financial statements.

40

RGC RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2018, 2017 AND 2016

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation—RGC Resources, Inc. is an energy services company primarily engaged in the sale and distribution of natural gas. The consolidated financial statements include the accounts of RGC Resources, Inc. and its wholly owned subsidiaries (“Resources” or the “Company”): Roanoke Gas Company (“Roanoke Gas”), Diversified Energy Company and RGC Midstream, LLC. Roanoke Gas is a natural gas utility, which distributes and sells natural gas to approximately 60,200 residential, commercial and industrial customers within its service areas in Roanoke, Virginia and the surrounding localities. The Company’s business is seasonal in nature as a majority of natural gas sales are for space heating during the winter season. Roanoke Gas is regulated by the Virginia State Corporation Commission (“SCC” or “Virginia Commission”). RGC Midstream, LLC is a wholly-owned subsidiary created primarily to invest in the Mountain Valley Pipeline project. Diversified Energy Company is inactive.

The Company follows accounting and reporting standards established by the Financial Accounting Standards Board (“FASB”) and the Securities and Exchange Commission (“SEC”).

Resources has only one reportable segment as defined under FASB ASC No. 280 – Segment Reporting. All intercompany transactions have been eliminated in consolidation.

Certain reclassifications have been made to the prior year income statements to be consistent with the current year presentation by moving cost of gas - utility and cost of sales - non utility under the operating expenses caption. This presentation makes the Company's income statement presentation consistent with industry peers.

On June 28, 2018, the SEC adopted amendments to the definition of a "smaller reporting company' that became effective on September 10, 2018. Under the rules for smaller reporting companies, certain disclosures required of larger public business entities are reduced or eliminated. As it has met the qualifications under the definition of smaller reporting company, the Company has used the smaller reporting company exception on a limited basis, but in most instances, disclosures have been consistent with the prior year.

Rate Regulated Basis of Accounting—The Company’s regulated operations follow the accounting and reporting requirements of FASB ASC No. 980, Regulated Operations. The economic effects of regulation can result in a regulated company deferring costs that have been or are expected to be recovered from customers in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this situation occurs, costs are deferred as assets in the consolidated balance sheet (regulatory assets) and recorded as expenses when such amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for current collection in rates of costs that are expected to be incurred in the future (regulatory liabilities). In the event the provisions of FASB ASC No. 980 no longer apply to any or all regulatory assets or liabilities, the Company would write off such amounts and include them in the consolidated statements of income and comprehensive income in the period for which FASB ASC No. 980 no longer applied.

41

Regulatory assets and liabilities included in the Company’s consolidated balance sheets as of September 30, 2018 and 2017 are as follows:

	September 30
	2018		2017
Regulatory Assets:
Current Assets:
Accounts receivable:
Accrued WNA revenues	$	169,602	$	248,840
Under-recovery of gas costs	922,898		—
Other:
Accrued pension and postretirement medical	293,000		658,786
Utility Property:
In service:
Other	11,945		11,945
Other Assets:
Regulatory assets:
Premium on early retirement of debt	1,826,995		1,941,182
Accrued pension and postretirement medical	5,704,718		8,643,524
Other	1,330,434		1,211,554
Total regulatory assets	$	10,259,592	$	12,715,831
Regulatory Liabilities:
Current Liabilities:
Over-recovery of gas costs	$	—	$	1,438,074
Accrued expenses:
Over-recovery of SAVE Plan revenues	670,034		215,514
Rate refund	1,320,167		—
Deferred Credits and Other Liabilities:
Asset retirement obligations	6,417,948		6,069,993
Regulatory cost of retirement obligations	11,163,981		10,055,189
Regulatory liability - deferred income taxes	11,447,736		—
Total regulatory liabilities	$	31,019,866	$	17,778,770

As of September 30, 2018, the Company had regulatory assets in the amount of $10,247,647 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 Plant and Depreciation—Utility plant is stated at original cost and includes direct labor and materials, contractor costs, and all allocable overhead charges. The Company applies the group method of accounting, where the costs of like assets are aggregated and depreciated by applying a rate based on the average expected useful life of the assets. In accordance with Company policy, expenditures for depreciable assets with a life greater than one year are capitalized, along with any upgrades or improvements to existing assets, when they significantly improve or extend the original expected useful life of an asset. Expenditures for maintenance, repairs, and minor renewals and betterments are expensed as incurred. The original cost of depreciable property retired is removed from utility plant and charged to accumulated depreciation. The cost of asset removals, less salvage, is charged to “regulatory cost of retirement obligations” or “asset retirement obligations” as explained under Asset Retirement Obligations below.

Utility plant is composed of the following major classes of assets:

42

	Years Ended September 30
	2018		2017
Distribution and transmission	$	196,778,546	$	177,845,619
LNG storage	13,413,175		13,299,288
General and miscellaneous	14,662,599		13,078,807
Total utility plant in service	$	224,854,320	$	204,223,714

Provisions for depreciation are computed principally at composite straight-line rates over periods ranging from 5 to 76 years. 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 in June 2014 and will be required to complete a new depreciation study in fiscal 2019. The composite weighted-average depreciation rate realized using the most recently completed depreciation study was 3.32%, 3.29% and 3.25% for fiscal years ended September 30, 2018, 2017 and 2016.

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. 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.

Asset Retirement Obligations—FASB ASC No. 410, Asset Retirement and Environmental Obligations, requires entities to record the fair value of a liability for an asset retirement obligation when there exists a legal obligation for the retirement of the asset. When the liability is initially recorded, the entity capitalizes the cost, thereby increasing the carrying amount of the underlying asset. In subsequent periods, the liability is accreted, and the capitalized cost is depreciated over the useful life of the underlying asset. The Company has recorded asset retirement obligations for its future legal obligations related to purging and capping its distribution mains and services upon retirement, although the timing of such retirements is uncertain.

The Company’s composite depreciation rates include a component to provide for the cost of retirement of assets. As a result, the Company accrues the estimated cost of retirement of its utility plant through depreciation expense and creates a corresponding regulatory liability. The costs of retirement considered in the development of the depreciation component include those costs associated with the legal liability. Therefore, the asset retirement obligation 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, the Company increased its asset retirement obligation to reflect revisions to the estimated cash flows for asset retirements.

The following is a summary of the asset retirement obligation:

	Years Ended September 30
	2018			2017
Beginning balance	$	6,069,993		$	5,682,556
Liabilities incurred	79,608			65,556
Liabilities settled	(126,907		)	(137,304		)
Accretion	332,537			312,503
Revisions to estimated cash flows	62,717			146,682
Ending balance	$	6,417,948		$	6,069,993

Cash, Cash Equivalents and Short-Term Investments—From time to time, the Company will have balances on deposit at banks in excess of the amount insured by the Federal Deposit Insurance Corporation (“FDIC”). The Company has not experienced any losses on these accounts and does not consider these amounts to be at credit risk. As of September 30, 2018, the Company did not have any bank deposits in excess of the FDIC insurance limits. For purposes of the consolidated statements of cash flows, the Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents.

43

Customer Receivables and Allowance for Doubtful Accounts—Accounts receivable include amounts billed to customers for natural gas sales and related services and gas sales occurring subsequent to normal billing cycles but before the end of the period. The Company provides an estimate for losses on these receivables by utilizing historical information, current account balances, account aging and current economic conditions. Customer accounts are charged off annually when deemed uncollectible or when turned over to a collection agency for action.

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

	Years Ended September 30
	2018			2017			2016
Beginning balance	$	99,456		$	76,934		$	52,721
Provision for doubtful accounts	169,096			84,587			14,074
Recoveries of accounts written off	78,919			110,725			137,055
Accounts written off	(243,898		)	(172,790		)	(126,916		)
Ending balance	$	103,573		$	99,456		$	76,934

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

Inventories—Natural gas in storage and materials and supplies inventories are recorded at average cost. Natural gas storage injections are priced at the purchase cost at the time of injection and storage withdrawals are priced at the weighted average cost of gas in storage. Materials and supplies are removed from inventory at average cost.

Unbilled Revenues—The Company bills its natural gas customers on a monthly cycle; however, the billing cycle period for most customers does not coincide with the accounting periods used for financial reporting. As the Company recognizes revenue when gas is delivered, an accrual is made to estimate revenues for natural gas delivered to customers but not billed during the accounting period. The amounts of unbilled revenue receivable included in accounts receivable on the consolidated balance sheets at September 30, 2018 and 2017 were $911,657 and $965,683, respectively.

Income Taxes—Income taxes are accounted for using the asset and liability method. Under the asset and liability method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the years in which those temporary differences are expected to be recovered or settled. A valuation allowance against deferred tax assets is provided if it is more likely than not the deferred tax asset will not be realized. The Company and its subsidiaries file 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’s Purchased Gas Adjustment (“PGA”) clause, the SCC provides the Company with a method of passing along to its customers increases or decreases in natural gas costs incurred by its regulated operations, including gains and losses on natural gas derivative hedging instruments. On a quarterly basis, the Company files a PGA rate adjustment request with the SCC to increase or decrease the gas cost component of its rates, based on projected price and activity. Once administrative approval is received, the Company adjusts the gas cost component of its rates to reflect the approved amount. As actual costs will differ from the projections used in establishing the PGA rate, the Company may either over-recover or under-recover its actual gas costs during the period. Any difference between actual costs incurred and costs recovered through the application of the PGA is recorded as a regulatory asset or liability. At the end of the deferral period, the balance of the net deferred charge or credit is amortized over an ensuing 12-month period as amounts are reflected in customer billings.

Fair Value—Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between 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:

44

• Level 1 – Unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date.

• Level 2 – Inputs other than quoted prices in Level 1 that are either for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability, or inputs that are derived principally from or corroborated by observable market data by correlation or other means.

• Level 3 – Unobservable inputs for the asset or liability where there is little, if any, market activity which require the Company to develop its own assumptions.

The fair value hierarchy gives the highest priority to unadjusted quoted prices in active markets (Level 1) and the lowest priority to unobservable inputs (Level 3). All fair value disclosures are categorized within one of the three categories in the hierarchy. See fair value disclosures below and in Notes 8 and 12.

Use of Estimates—The preparation of financial statements in conformity with Generally Accepted Accounting Principles in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Excise and Sales Taxes—Certain excise and sales taxes imposed by the state and local governments in the Company’s service territory are collected by the Company from its customers. These taxes are accounted for on a net basis and therefore are not included as revenues in the Company’s Consolidated Statements of Income.

Earnings Per Share—Basic earnings per share and diluted earnings per share 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 share is presented below:

	Years Ended September 30
	2018		2017		2016
Net Income	$	7,297,205	$	6,232,865	$	5,806,866
Weighted-average common shares	7,649,025		7,218,686		7,149,906
Effect of dilutive securities:
Options to purchase common stock	46,687		37,360		9,857
Diluted average common shares	7,695,712		7,256,046		7,159,763
Earnings Per Share of Common Stock:
Basic	$	0.95	$	0.86	$	0.81
Diluted	$	0.95	$	0.86	$	0.81

Business and Credit Concentrations—The primary business of the Company is the distribution of natural gas to residential, commercial and industrial customers in its service territories.

No sales to individual customers accounted for more than 5% of total revenue in any period or amounted to more than 5% of total accounts receivable.

Roanoke Gas currently holds the only franchises and certificates of public convenience and necessity to distribute natural gas in its service area. These franchises are effective through January 1, 2036. The Company's current certificates of public convenience and necessity 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.

45

Derivative and Hedging Activities—FASB ASC No. 815, Derivatives and Hedging, requires the recognition of all derivative instruments as assets or liabilities in the Company’s balance sheet and measurement of those instruments at fair value.

The Company’s hedging and derivatives policy allows management to enter into derivatives for the purpose of managing the commodity and financial market risks of its business operations. The Company’s hedging and derivatives policy specifically prohibits the use of derivatives for speculative purposes. The key market risks that RGC Resources, Inc. 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 balance sheet with the offsetting entry to either under-recovery of gas costs 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, 2018 and 2017, the Company had no outstanding derivative instruments for the purchase of natural gas.

The Company has one interest rate swap associated with its $7,000,000 term note as discussed in Note 6. Effective November 1, 2017, the swap agreement converted the floating rate note based on LIBOR into a fixed rate debt with a 2.30% effective interest rate. The swap qualifies as a cash flow hedge with changes in fair value reported in other comprehensive income. No portion of the swap was deemed ineffective during the period.

The table below reflects the fair value of the derivative instrument and its corresponding classification in the consolidated balance sheets.

	September 30
	2018		2017
Derivatives designated as hedging instruments:
Current assets:
Interest rate swap	$	100,723	$	26,777
Other assets:
Interest rate swap	$	209,840	$	90,066
Total derivatives designated as hedging instruments	$	310,563	$	116,843

The fair value of the interest rate swap is determined by using the counter party's proprietary models and certain assumptions regarding past, present and future market conditions. See Note 12 for additional information on fair value.

Non-Cash Activity — A non-cash increase in investment in unconsolidated affiliate and corresponding increase in capital contributions payable of $9,087,262 and $767,710 occurred for the fiscal years ended September 30, 2018 and 2017, respectively.

46

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, 2018:
Interest rate swap:
Unrealized gains	$	217,773		$	(62,807	)	$	154,966
Transfer of realized gains to interest expense	(24,053		)	6,937			(17,116		)
Net interest rate swap	193,720			(55,870		)	137,850
Defined benefit plans:
Net gain arising during period	$	595,570		$	(171,775	)	$	423,795
Amortization of actuarial gains	(23,887		)	6,890			(16,997		)
Net defined benefit plans	571,683			(164,885		)	406,798
Other comprehensive income	$	765,403		$	(220,755	)	$	544,648
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	)

The amortization of actuarial gains or losses are included as a component of net periodic pension and postretirement benefit costs 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, 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		)
Other comprehensive income (loss)	137,850		406,798			544,648
Reclassification adjustment for the effect of change in tax law	20,285		(234,337		)	(214,052		)
Balance September 30, 2018	$	230,624	$	(1,102,292	)	$	(871,668	)

47

The reclassification related to the interest rate swap was charged to regulatory liability - deferred taxes to offset the adjustment made when revaluing the deferred tax liability of the interest rate swap for the reduction in corporate income tax rates. See recently adopted accounting standards for more information on the reclassification from accumulated other comprehensive income.

Recently Adopted Accounting Standards

In March 2016, the FASB issued ASU 2016-09, Compensation - Stock Compensation: Improvements to Employee Share-Based Payment Accounting. The guidance simplifies several aspects of the accounting for share-based payment award transactions, including income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. The new guidance is effective for the Company for the annual reporting period ending September 30, 2018 and interim periods within that annual period. Early adoption is permitted. The Company adopted this ASU for the quarter ended September 30, 2016. Under the prior guidance, excess tax benefits were to be tracked in an APIC pool and not recognized in the income statement. Tax deficiencies were netted against the accumulated APIC pool and only recognized in the income statement starting at the time tax deficiencies exceeded the pool. Under ASU 2016-09, the APIC pool is eliminated with all excess tax benefits and deficiencies recognized in income tax expense on the income statement. Prior to the adoption of this ASU, stock option activity did not result in the accumulation of an APIC pool; therefore, adopting the ASU had minimal impact on the Company’s current financial position, results of operations or cash flows and no impact on prior results.

In January 2017, the FASB issued ASU 2017-03, Accounting Changes and Error Corrections and Investments - Equity Method and Joint Ventures. This update adds the text of the SEC Staff Announcement, Disclosure of the Impact That Recently Issued Accounting Standards Will Have on the Financial Statements of a Registrant When Such Standards Are Adopted in a Future Period (in accordance with Staff Accounting Bulletin Topic 11.M) as paragraph 250-10-S99-6. Related specifically to ASU 2014-09, ASU 2016-02 and ASU 2016-13, an SEC registrant should evaluate ASUs that have not yet been adopted to determine and include appropriate financial disclosures and MD&A discussions, including consideration of additional qualitative disclosures, to assist financial statement readers in assessing the significance of impact on adoption. The new guidance is effective immediately. The nature of this guidance relates to the effectiveness and quality of disclosures related to ASUs not yet adopted; however, there is no effect on the Company's financial position, results of operations or cash flows.

In February 2018, the FASB issued ASU 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220) - Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. The ASU provides the option to reclassify stranded tax effects within Accumulated Other Comprehensive Income ("AOCI") to retained earnings in each period in which the effects of the change in the U.S. federal corporate income tax rate, per the Tax Cuts and Jobs Act, is recorded. The new guidance is effective for the Company for the annual reporting period ending September 30, 2020 and interim periods within that annual period. Early adoption is permitted. Management completed its evaluation and adopted the new guidance in the fourth quarter of fiscal 2018. As a result, the Company reclassified $234,337 in stranded tax expense out of AOCI to retained earnings related to pension and postretirement plans for the unregulated operations of Resources. In addition, the Company also reclassified $20,285 out of AOCI to the regulatory liability for the stranded tax expense related to the interest rate swap. See the Other Comprehensive Income section above and Note 3 below for more information.

Recently Issued Accounting Standards

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) that affects any entity that enters into contracts with customers for the transfer of goods or services or transfer of non-financial assets. This guidance supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. The core principle of the new guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve that core principle, an entity should apply the following steps: (1) identify the contract with the customer, (2) identify the performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to the performance obligations in the contract, and (5) recognize revenue when, or as, the entity satisfies the performance obligation. In August 2015, the FASB issued ASU 2015-14 that deferred the effective date of this guidance by one year making the standard effective for the Company's annual reporting period ending September 30, 2019 and interim periods within that annual period. Subsequent ASUs have been issued, which provide additional guidance to assist in the implementation of the new revenue standard. Based on the evaluation of the ASU, management has determined that the adoption of the new standard will not have a material impact on the Company's financial position, results of operations or cash flows. However, significant new disclosures will be required as a result of the guidance. The Company is completing the

48

review and updating of its disclosures and will reflect the changes with the adoption of the standard in the first quarter of fiscal 2019 using the modified retrospective approach.

In January 2016, the FASB issued ASU 2016-01, Financial Instruments - Overall: Recognition and Measurement of Financial Assets and Financial Liabilities. The ASU enhances the reporting model for financial instruments to provide users of the financial statements with more useful information through several provisions, including the following: (1) requires equity investments, excluding investments accounted for under the equity method, be measured at fair value with changes in fair value recognized in net income, (2) simplifies the impairment assessment of equity investments without readily determinable fair values, (3) eliminates the requirement to disclose the method(s) and significant assumptions used to estimate the fair value that is required to be disclosed for financial instruments measured at amortized cost on the balance sheet, (4) requires entities to use the exit price notion when measuring the fair value of financial instruments for disclosure purposes, and (5) requires separate presentation of financial assets and financial liabilities by measurement category and form of financial asset on the balance sheet or the accompanying notes to the financial statements. The new guidance is effective for the Company for the annual reporting period ending September 30, 2019 and interim periods within that annual period. Management is in the process of completing its evaluation of the standard, but does not anticipate the new guidance to have a material effect on its financial position, results of operations or cash flows.

In February 2016, the FASB issued ASU 2016-02, Leases. The ASU leaves the accounting for leases mostly unchanged for lessors, with the exception of targeted improvements for consistency; however, the new guidance requires lessees to recognize assets and liabilities for leases with terms of more than 12 months. The ASU also revises the definition of a lease as a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment for a period of time in exchange for consideration. Consistent with current GAAP, the presentation and cash flows arising from a lease by a lessee will primarily depend on its classification as a finance or operating lease. In contrast, the new ASU requires both types of leases to be recognized on the balance sheet. In addition, the new guidance includes quantitative and qualitative disclosure requirements to aid financial statement users in better understanding the amount, timing and uncertainty of cash flows arising from leases. The new guidance is effective for the Company for the annual reporting period ending September 30, 2020 and interim periods within that annual period. Early adoption is permitted. The Company has completed its inventory of leases and does not currently expect the new guidance to have a material effect on its financial position, results of operations or cash flows.

In March 2017, the FASB issued ASU 2017-07, Compensation - Retirement Benefits. The primary objective of this guidance is to improve the financial statement presentation of net periodic pension and postretirement benefit costs; however, it also changes which cost components are eligible for capitalization. The amendments in the ASU require that an employer report the service cost component in the same line item or items as other compensation costs arising from services rendered by the employees during the period. The other components of net benefit cost are required to be presented in the income statement separately from the service cost component and, if a subtotal for income from operations is presented, outside of income from operations. In addition, the ASU allows only the service cost component of periodic benefit cost to be eligible for capitalization when applicable. This change to capitalization eligibility differs from the treatment currently applied by the Company and from allowed regulatory accounting. The new guidance is effective for the Company for the annual reporting period ending September 30, 2019 and interim periods within that annual period. Early adoption is permitted. Management has had discussions with its state regulators regarding the adoption of this ASU for regulatory purposes. The regulatory body has not taken a position on the change in capitalization requirements for these benefit costs and will evaluate the impact of this ASU on a case by case basis. The Company intends to adopt this ASU effective October 1, 2018 with the change in expense classification on a retrospective basis and the change in capitalization of costs on a prospective basis. If the regulatory body ultimately determines that changes to the capitalization of these retirement benefits is not appropriate for regulatory purposes, the Company may have to establish regulatory assets or liabilities for those costs or benefits excluded from capitalization under this ASU. Management does not expect the new guidance to have a material effect on the Company's consolidated financial statements.

In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging: Targeted Improvements to Accounting For Hedging Activities. The ASU is meant to simplify recognition and presentation guidance in an effort to improve financial reporting of cash flow and fair value hedging relationships to better portray the economic results of an entity's risk management activities. This is achieved through changes to both the designation and measurement guidance for qualifying hedging relationships, as well as changes to the presentation of hedge results. The new guidance is effective for the Company for the annual reporting period ending September 30, 2020 and interim periods within that annual period. Early adoption is permitted. Management has not completed its evaluation of the new

49

guidance; however, it does not currently expect the new guidance to have a material effect on its financial position, results of operations or cash flows.

In August 2018, the FASB issued ASU 2018-14, Compensation - Retirement Benefits - Defined Benefit Plans - General (Subtopic 715-20) - Disclosure Framework - Changes to the Disclosure Requirements for Defined Benefit Plans. This ASU modifies disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The new guidance is effective for the Company for the annual reporting period ending September 30, 2021. Early adoption is permitted. Management has not completed its evaluation of the new guidance; however, the ASU only modifies disclosure requirements and will not effect financial position, results of operations or cash flows.

In August 2018, the FASB issued ASU 2018-15, Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer's Accounting for Implementation Costs incurred in a Cloud Computing Arrangement that is a Service Contract. This ASU reduces the complexity of accounting for costs of implementing a cloud computing service arrangement and aligns the following requirements to capitalize implementation costs: 1) those incurred in a hosting arrangement that is a service contract, and 2) those incurred to develop or obtain internal-use software, including hosting arrangements that include an internal software license. The new guidance is effective for the Company for the annual reporting period beginning October 1, 2020. Management has not completed its evaluation of the new guidance; however, it believes the new guidance will change the future treatment of certain contracts by allowing related implementation costs to be capitalized and amortized over time, rather than directly expensed. Management does not currently expect the new guidance to have a material effect on its financial position, results of operations or 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.

2. STOCK ISSUE

In March 2018, the Company issued 700,000 shares of common stock resulting in proceeds of $15,109,541 net of underwriting and other expenses. The Company issued the common shares to strengthen its balance sheet by increasing the equity component of its total capitalization ratio. The net proceeds were invested in Roanoke Gas to supplement the funding of its infrastructure improvement and replacement programs.

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.

On October 10, 2018, Roanoke Gas filed a general rate case application requesting an increase in annual customer non-gas rates of $10.5 million. This increase incorporates into the non-gas rate the impact of recent tax reform, non-SAVE utility plant investment, increased operating costs and approximately $4.7 million in SAVE plan ("Steps to Advance Virginia's Energy") revenues that are currently being billed through the SAVE rider. The new non-gas rates will be placed in effect for service rendered on or after January 1, 2019, subject to refund pending a final order by the SCC. The last non-gas rate increase was filed in 2013 with rates effective November 1, 2013.

On June 29, 2018, the Company filed with the SCC its most recent SAVE 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 on a prospective basis 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 refunding the over-collection of revenues under the 2017 SAVE Plan and proposed new 2019 SAVE rates to be implemented for the investment in 2019 SAVE Plan projects. With the filing of the application for the general rate case, all SAVE Plan revenues related to SAVE projects completed or in process through December 2018 will be incorporated into the new non-gas rates effective January 1, 2019. Accordingly, the SAVE Plan rider will reset beginning January 1, 2019 and will relate only to SAVE projects and expenditures incurred on and after this date. On September 27, 2018, the SCC issued their order approving the new 2019 SAVE rider, which is expected to provide approximately $362,000 in revenue. The SCC also approved the True-up factor to provide for the refund of approximately $163,000 in over-collected balance from the 2017 SAVE Plan.

50

As discussed in Note 7, the Tax Cut and Jobs Act ("TCJA") provided for a reduction in the federal corporate income tax rate to 21%. The Company revalued its deferred tax assets and liabilities to reflect the new federal tax rate. Under the provisions of ASC 740, the corresponding adjustment to deferred income taxes generally flows through to income tax expense. For rate regulated entities such as Roanoke Gas, these excess deferred income taxes were originally recovered from its customers based on billing rates derived using a federal income tax rate of 34%. Therefore, the adjustment to the net deferred tax liability of Roanoke Gas, to the extent such net deferred tax liabilities are attributable to rate base or cost of service for customers, are refundable to or collectible from customers. As of September 30, 2018, Roanoke Gas has a net deferred tax regulatory liability in the amount of approximately $11.4 million composed of $12.7 million related to excess tax depreciation that will be refunded back to customers over 28 years using the Reverse South Georgia method and $1.3 million in net deferred tax assets that will be collected from customers over a period yet to be determined.

With the implementation of the TCJA, the change in federal income tax rates occurred during the Company's fiscal year resulting in the use of a 24.3% blended rate for fiscal 2018 and a conversion to the 21% in fiscal 2019. On January 8, 2018, the SCC issued a directive requiring the accrual of a regulatory liability for excess revenues collected from customers attributable to the higher federal income tax rate, currently included as a component of customer billing rates, until such time as the SCC approves revised billing rates incorporating the lower tax rate. For the year ended September 30, 2018, Roanoke Gas has recorded a reduction to revenue and established a regulatory liability in the amount of $1,320,167 related to the excess revenues collected from customers during the year. The reduction in excess revenues corresponds with a similar reduction in corporate income tax expense for the regulated operations of Roanoke Gas. The excess revenues related to the SAVE Plan and inventory carrying cost have already been reflected separately from the refund liability. The actual refund will not be finalized until the SCC completes their review and makes any adjustments to the Company's calculations.

4. OTHER INVESTMENTS

In October 2015, the Company, through its wholly-owned subsidiary, RGC Midstream, LLC ("Midstream"), acquired a 1% equity interest in the Mountain Valley Pipeline, LLC (the “LLC”). The LLC was established to construct and operate a natural gas pipeline originating in northern West Virginia and extending through south central Virginia. The proposed pipeline will have the capacity to transport approximately 2 million decatherms of natural gas per day.

The estimated total project cost has increased from $3.7 billion to $4.6 billion, thereby increasing Midstream's estimated total contributions to approximately $46 million. This increase is due to delays in construction resulting from judicial and regulatory actions. Primarily, these actions relate to the adequacy of reviews performed by various permit-granting agencies related to the construction of the pipeline under waterways and through the Jefferson National Forest. The pipeline is under construction as it had received Federal Energy Regulatory Commission ("FERC") approval as well as the necessary federal and state permits; however, several recent FERC and Fourth Circuit Court rulings have led to work stoppages and imposed construction limitations. As a result, construction progress has slowed significantly and delayed the projected in-service date to the end of calendar 2019.

In April 2018, the LLC announced the MVP Southgate project ("Southgate"), which is a planned 70 mile pipeline extending from the Mountain Valley Pipeline mainline in Virginia to delivery points in North Carolina. Midstream is a less than 1% investor in this project, which will be accounted for under the cost method. Total estimated project cost is between $350 and $500 million of which Midstream's portion will be approximately $1.8 to $2.5 million. The Southgate in-service date is currently targeted for the end of calendar 2020.

Midstream held an approximate $28.5 million investment in the LLC and Southgate project at September 30, 2018. Initial funding for Midstream's investment is provided through two unsecured Promissory Notes, each with a 5-year term, as further described in Note 6 below.

The Company will participate in the earnings generated from the transportation of natural gas through both pipelines proportionate to its level of investment once the pipelines are placed in service.

The financial statement locations of the investments by Midstream are as follows:

51

	September 30
Balance Sheet Location of Other Investments:	2018		2017
Other Assets:
Investment in unconsolidated affiliate	$	28,507,146	$	7,445,106
Current Liabilities:
Capital contributions payable	$	10,142,766	$	1,055,504
	For the Years ended September 30
Income Statement Location of Other Investments:	2018		2017		2016
Equity in earnings of unconsolidated affiliate	$	938,531	$	421,646	$	152,864

The change in the investment in unconsolidated affiliate are provided below:

	For the Years ended September 30,
	2018		2017		2016
Cash investment	$	11,036,247	$	2,759,346	$	3,055,746
Change in accrued capital calls	9,087,262		767,710		287,794
Equity in earnings of unconsolidated affiliate	938,531		421,646		152,864
Change in investment in unconsolidated affiliate	$	21,062,040	$	3,948,702	$	3,496,404

5. LINE-OF-CREDIT

On March 26, 2018, Roanoke Gas entered into a new unsecured line-of-credit agreement. This line-of-credit agreement replaced the agreement scheduled to expire on March 31, 2019. The new agreement is for a 2-year term expiring March 31, 2020 with a maximum borrowing limit of $25,000,000. 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.

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 as the previous agreement. The new agreement also maintains the multi-tiered borrowing limits to accommodate seasonal borrowing demands and minimize borrowing costs. Available limits under this agreement for the remaining term are as follows:

As of	Available Line-of-Credit
September 30, 2018	$	20,000,000
November 21, 2018	21,000,000
March 1, 2019	17,000,000
July 22, 2019	22,000,000
September 22, 2019	25,000,000
March 1, 2020	22,000,000

52

A summary of the line-of-credit follows:

	September 30
	2018			2017			2016
Available line-of-credit at year-end	$	20,000,000		$	21,000,000		$	24,000,000
Outstanding balance at year-end	7,361,017			17,791,760			14,556,785
Highest month-end balance outstanding	17,054,377			17,791,760			15,246,089
Average daily balance	6,730,334			10,936,114			9,620,914
Average rate of interest during year on outstanding balances	2.53		%	1.92		%	1.40		%
Interest rate at year-end	3.26		%	2.23		%	1.53		%
Interest rate on unused line-of-credit	0.15		%	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%.

6. LONG-TERM DEBT

On October 2, 2017, the Company issued 10-year unsecured notes in the principal amount of $8,000,000 with a fixed interest rate of 3.58% per annum. The proceeds from the notes were used to refinance a portion of the Company's line-of-credit balance into longer-term financing.

Roanoke Gas has a 5-year unsecured variable rate note in the principal amount of $7,000,000 and an interest rate swap agreement, which converts the variable rate debt into a fixed-rate instrument with an annual interest rate of 2.30%. The swap agreement became effective on November 1, 2017 and will continue through the duration of the note.

Midstream has two5-year unsecured Promissory Notes ("Notes") which provide financing for capital investment in its 1% interest in the LLC. In April 2018, the Notes and corresponding credit agreement were amended to increase the total borrowing limits to $38 million and reduce the variable interest rate to 30-day LIBOR plus 135 basis points. Furthermore, the amended credit agreement removed the requirement for Midstream to provide $5 million in funding outside of the Notes.

Long-term debt consists of the following:

	September 30
	2018				2017
	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	$	154,465	$	30,500,000	$	164,119
Unsecured term note payable, at 30-day LIBOR plus 0.90%, November 1, 2021	7,000,000		10,283		7,000,000		13,618
Unsecured term notes payable, at 3.58% due on October 2, 2027	8,000,000		43,343		—		48,160
RGC Midstream, LLC:
Unsecured term notes payable, at 30-day LIBOR plus 1.35% due December 29, 2020	$	17,743,200	$	74,190	$	6,312,200	$	66,052
Total notes payable	$	63,243,200	$	282,281	$	43,812,200	$	291,949
Line-of-credit, at 30-day LIBOR plus 1.00%, due March 31, 2020	7,361,017		—		17,791,760		—
Total long-term debt	$	70,604,217	$	282,281	$	61,603,960	$	291,949

Debt issuance costs are amortized over the life of the related debt. As of September 30, 2018 and 2017, the Company also had an unamortized loss on the early retirement of debt of $1,826,995 and $1,941,182, respectively, which has been deferred as a regulatory asset and is being amortized over a 20 year period.

53

All of the debt agreements set forth certain representations, warranties and covenants to which the Company is subject, including financial covenants that requires the ratio of long-term debt to long-term capitalization to not exceed 65%. 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, 2018 are as follows:

Year Ending September 30	Maturities
2019	$	—
2020	7,361,017
2021	17,743,200
2022	7,000,000
2023	—
Thereafter	38,500,000
Total	$	70,604,217

7. INCOME TAXES

On December 22, 2017, the President signed into law the TCJA, which enacted significant changes to the Internal Revenue Code, including the reduction in the maximum federal corporate income tax rate from 35% to 21% effective January 1, 2018. As the Company is a fiscal year taxpayer, the Company applied a blended federal tax rate of 24.3% for the fiscal year ended September 30, 2018 as determined on the number of days of the Company's fiscal year at 34% and the number of days at 21%.

Under the provisions of ASC 740 - Income Taxes, the deferred tax assets and liabilities of the Company must be revalued to reflect the reduction in the corporate federal income tax rate. The result of this revaluation was a reduction in the net deferred tax liability of approximately $9 million, including approximately $11.8 million reclassified to regulatory liability, a $3 million gross up to reflect pre-tax basis, and $0.26 million increase in income tax expense related to unregulated operations. The excess deferred income taxes are reflected on a pretax basis to appropriately contemplate future tax consequences in the periods when the regulatory liability is settled. Approximately $13.1 million of the excess deferred taxes related to certain depreciable property that must be returned to customers subject to normalization requirements. The excess deferred taxes related to the depreciable property will be returned to customers over the remaining weighted average useful life of the property using the Reverse South Georgia method beginning January 2018. The remaining balance in the regulatory liability relates to approximately $1.3 million in deferred tax assets that will be collected from customers over a yet to be determined period.

The details of income tax expense are as follows:

	Years Ended September 30
	2018		2017		2016
Current income taxes:
Federal	$	1,831,085	$	72,368	$	(1,216,745	)
State	308,057		407,643		415,975
Total current income taxes	2,139,142		480,011		(800,770		)
Deferred income taxes:
Federal	440,282		3,129,925		4,302,906
State	315,712		195,454		164,048
Total deferred income taxes	755,994		3,325,379		4,466,954
Total income tax expense	$	2,895,136	$	3,805,390	$	3,666,184

54

Income tax expense for the years ended September 30, 2018, 2017 and 2016 differed from amounts computed by applying the U.S. federal income tax rate to earnings before income taxes due to the following:

	Years Ended September 30
	2018			2017			2016
Income before income taxes	$	10,192,341		$	10,038,255		$	9,473,050
Corporate federal income tax rate	24.3		%	34.0		%	34.0		%
Income tax expense computed at the federal statutory rate	$	2,476,739		$	3,413,007		$	3,220,837
State income taxes, net of federal income tax benefit	472,193			398,044			382,815
Revaluation of unregulated deferred taxes to 21%	256,444			—			—
Net amortization of excess deferred taxes on regulated operations	(264,106		)	—			—
Other, net	(46,134		)	(5,661		)	62,532
Total income tax expense	$	2,895,136		$	3,805,390		$	3,666,184

The tax effects of temporary differences that give rise to the deferred tax assets and deferred tax liabilities are as follows:

	September 30
	2018		2017
Deferred tax assets:
Allowance for uncollectibles	$	26,658	$	37,752
Accrued pension and postretirement medical benefits	897,834		1,747,429
Regulatory effect of change in federal income tax rate	2,946,649		—
Accrued vacation	160,001		239,414
Over-recovery of gas costs	—		545,894
Costs of gas held in storage	591,899		1,009,206
Deferred compensation	716,843		824,281
Rate refund	339,812		—
Other	298,129		348,833
Total gross deferred tax assets	5,977,825		4,752,809
Deferred tax liabilities:
Utility plant	17,982,215		27,630,486
Under-recovery of gas costs	255,570		—
MVP investment	245,678		154,817
Other	79,939		44,354
Total gross deferred tax liabilities	18,563,402		27,829,657
Net deferred tax liability	$	12,585,577	$	23,076,848

The current federal 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 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.

Under the PATH Act, 50% bonus depreciation extended through December 31, 2017, with 40% for calendar 2018 and 30% for calendar 2019 with no provision for bonus depreciation after 2019. Effective with the TCJA, utilities are no longer eligible to take bonus depreciation.

55

FASB ASC No. 740 - Income Taxes provides for the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recognized in the financial statements. The Company has evaluated its tax positions and accordingly has not identified any significant uncertain tax positions. The Company’s policy is to classify interest associated with uncertain tax positions as interest expense in the financial statements. Penalties are classified under other expense.

The Company files a consolidated federal income tax return and state income tax returns in Virginia and West Virginia. The federal returns and the state returns for both Virginia and West Virginia for the tax years ended prior to September 30, 2015 are no longer subject to examination.

8. EMPLOYEE BENEFIT PLANS

The Company sponsors both a noncontributory defined benefit pension plan ("pension plan") and a postretirement benefit plan ("postretirement plan"). The pension plan covers substantially all employees and benefits fully vest after 5 years of credited service. Benefits paid to retirees are based on age at retirement, years of service and average compensation. Effective January 1, 2017, a "soft freeze" to the pension plan was implemented, and employees hired on or after that date are no longer eligible to participate. Employees hired prior to January 1, 2017 will continue to participate in the plan and accrue benefits. Commensurate with the "soft freeze" in the pension plan, the Company amended its 401(k) Plan, allowing management to authorize a discretionary contribution to the 401(k) account for those employees hired on or after January 1, 2017. The amount, if any, of this discretionary contribution would be determined each year and would be applied to the eligible employees at the end of the calendar year. This Company contribution would be in addition to any employee elected deferrals and employer match as provided for under the 401(k) Plan.

The postretirement 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 benefit 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 in 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.

56

The following tables set forth the benefit obligation, fair value of plan assets, the funded status of the benefit plans, amounts recognized in the Company’s financial statements and the assumptions used.

	Pension Plan						Postretirement Plan
	2018			2017			2018			2017
Accumulated benefit obligation	$	25,199,762		$	25,481,993		$	16,207,322		$	17,666,812
Change in benefit obligation:
Benefit obligation at beginning of year	$	29,657,347		$	29,494,950		$	17,666,812		$	18,504,710
Service cost	665,235			706,677			167,220			183,267
Interest cost	1,088,180			995,598			640,602			626,822
Actuarial gain	(1,727,767		)	(824,361		)	(1,774,320		)	(1,199,722		)
Benefit payments, net of retiree contributions	(832,696		)	(715,517		)	(492,992		)	(448,265		)
Benefit obligation at end of year	$	28,850,299		$	29,657,347		$	16,207,322		$	17,666,812
Change in fair value of plan assets:
Fair value of plan assets at beginning of year	$	26,418,671		$	23,113,057		$	12,691,162		$	11,122,783
Actual return on plan assets, net of taxes	1,798,722			3,021,131			426,787			1,016,644
Employer contributions	800,000			1,000,000			300,000			1,000,000
Benefit payments, net of retiree contributions	(832,696		)	(715,517		)	(492,992		)	(448,265		)
Fair value of plan assets at end of year	$	28,184,697		$	26,418,671		$	12,924,957		$	12,691,162
Funded status	$	(665,602	)	$	(3,238,676	)	$	(3,282,365	)	$	(4,975,650	)
Amounts recognized in the balance sheet consist of:
Noncurrent liabilities	$	(665,602	)	$	(3,238,676	)	$	(3,282,365	)	$	(4,975,650	)
Amounts recognized in accumulated other comprehensive loss:
Net actuarial loss, net of tax	$	361,215		$	572,740		$	741,077		$	702,013
Total amounts included in other comprehensive loss, net of tax	$	361,215		$	572,740		$	741,077		$	702,013
Amounts deferred to a regulatory asset:
Net actuarial loss	$	3,894,221		$	5,471,547		$	2,103,497		$	3,830,763
Amounts recognized as regulatory assets	$	3,894,221		$	5,471,547		$	2,103,497		$	3,830,763

The Company expects that approximately $10,000 before tax, of accumulated other comprehensive income will be recognized as a reduction in net periodic benefit costs in fiscal 2019 and approximately $293,000 of amounts deferred as regulatory assets will be amortized and recognized in net periodic benefit costs in fiscal 2019.

The following table details the actuarial assumptions used in determining the projected benefit obligations and net benefit cost of the pension and the accumulated benefit obligations and net benefit cost of the postretirement plan for 2018, 2017 and 2016.

	Pension Plan						Postretirement Plan
	2018		2017		2016		2018		2017		2016
Assumptions used to determine benefit obligations:
Discount rate	4.11	%	3.72	%	3.42	%	4.09	%	3.69	%	3.33	%
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	3.72	%	3.42	%	4.22	%	3.69	%	3.33	%	4.15	%
Expected long-term rate of return on plan assets	7.00	%	7.00	%	7.00	%	4.84	%	4.84	%	4.89	%
Expected rate of compensation increase	4.00	%	4.00	%	4.00	%	N/A		N/A		N/A

57

To develop the expected long-term rate of return on assets assumption, the Company, with input from the plans' actuaries and investment advisors, considered the historical returns and the future expectations for returns for each asset class, as well as the target asset allocation of each plan’s portfolio.

Components of net periodic benefit cost are as follows:

	Pension Plan									Postretirement Plan
	2018			2017			2016			2018			2017			2016
Service cost	$	665,235		$	706,677		$	694,375		$	167,220		$	183,267		$	148,018
Interest cost	1,088,180			995,598			1,132,776			640,602			626,822			624,579
Expected return on plan assets	(1,862,838		)	(1,616,412		)	(1,492,241		)	(623,381		)	(571,513		)	(507,858		)
Recognized loss	351,030			662,180			501,678			283,868			429,758			250,173
Net periodic benefit cost	$	241,607		$	748,043		$	836,588		$	468,309		$	668,334		$	514,912

The assumed health care cost trend rates used in measuring the accumulated benefit obligation for the postretirement medical plan as of September 30, 2018, 2017 and 2016 are presented below:

	Pre 65						Post 65
	2018		2017		2016		2018		2017		2016
Health care cost trend rate assumed for next year	7.00	%	7.00	%	7.50	%	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	2026		2021		2021		2018		2017		2016

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	$	155,000	$	(123,000	)
Effect on accumulated postretirement benefit obligation	2,487,000		(2,025,000		)

The primary objectives of the Plans' investment policies are to maintain investment portfolios that diversify risk through prudent asset allocation parameters, achieve asset returns that meet or exceed the plans’ 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. In 2018, the Company revised its targeted pension plan investment allocation by rebalancing the assets from a 60% equity allocation to a 40% equity allocation. This change in investment strategy was in response to the pension plan approaching a fully funded position, thereby allowing the opportunity to reduce investment risk and volatility in asset performance while providing for asset growth through the remaining equity investments. As a result, the Company updated its long-term rate of return on pension and postretirement plan assets for fiscal 2019 to 5.5% and 4.3%, respectively. The investment policy continues to provide for a range of investment allocations to allow for continued flexibility in responding to market conditions.

The Company’s target and actual asset allocation in the pension and postretirement benefit plans as of September 30, 2018 and 2017 were:

	Pension Plan						Postretirement Plan
	Target		2018		2017		Target		2018		2017
Asset category:
Equity securities	40	%	40	%	63	%	50	%	49	%	51	%
Debt securities	60	%	59	%	36	%	50	%	50	%	48	%
Cash	—	%	1	%	1	%	—	%	1	%	1	%
Other	—	%	—	%	—	%	—	%	—	%	—	%

58

The assets of the plans are invested in mutual funds. The Company uses the fair value hierarchy described in Note 1 to classify these assets. The mutual funds are included under Level 2 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 market prices for each security; however, certain fixed income securities and other investments are not actively traded and are valued based on similar investments. The following table contains the fair value classifications of the benefit plan assets:

			Defined Benefit Pension Plan Fair Value Measurements - September 30, 2018
	Fair Value		Level 1		Level 2		Level 3
Asset Class:
Cash	$	282,478	$	282,478	$	—	$	—
Common and Collective Trust and Pooled Funds:
Bonds
Liability Driven Investment	16,504,956		—		16,504,956		—
Equities
Domestic Large Cap Growth	3,449,486		—		3,449,486		—
Domestic Large Cap Value	3,381,285		—		3,381,285		—
Domestic Small/Mid Cap Core	1,685,352		—		1,685,352		—
Foreign Large Cap Value	1,527,796		—		1,527,796		—
Mutual Funds:
Equities
Foreign Large Cap Growth	1,060,383		—		1,060,383		—
Foreign Large Cap Value	292,961		—		292,961		—
Total	$	28,184,697	$	282,478	$	27,902,219	$	—

			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:
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	$	—

59

			Postretirement Benefit Plan Fair Value Measurements - September 30, 2018
	Fair Value		Level 1		Level 2		Level 3
Asset Class:
Cash	$	96,117	$	96,117	$	—	$	—
Mutual Funds
Bonds
Domestic Fixed Income	5,859,588		—		5,859,588		—
Foreign Fixed Income	609,722		—		609,722		—
Equities
Domestic Large Cap Growth	1,926,076		—		1,926,076		—
Domestic Large Cap Value	1,874,643		—		1,874,643		—
Domestic Small/Mid Cap Growth	214,180		—		214,180		—
Domestic Small/Mid Cap Value	210,891		—		210,891		—
Domestic Small/Mid Cap Core	459,363		—		459,363		—
Foreign Large Cap Growth	525,720		—		525,720		—
Foreign Large Cap Value	1,090,851		—		1,090,851		—
Foreign Large Cap Core	28,786		—		28,786		—
Other	29,020		—		29,020		—
Total	$	12,924,957	$	96,117	$	12,828,840	$	—

			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	$	—

Each mutual fund has been categorized based on its primary investment strategy.

60

The Company expects to contribute $800,000 to its pension plan and $300,000 to its postretirement benefit plan in fiscal 2019.

The following table reflects expected future benefit payments:

Fiscal year ending September 30	Pension Plan		Postretirement Plan
2019	$	934,935	$	688,340
2020	983,862		685,088
2021	1,042,332		725,587
2022	1,124,774		778,814
2023	1,220,246		834,042
2024-2028	7,346,304		4,230,466

The Company sponsors a defined contribution plan (the “401k Plan”) covering all 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. The Company matches 100% of the participant’s first 4% of contributions and 50% on the next 2% of contributions. Company matching contributions were $338,066, $361,702 and $353,793 for 2018, 2017 and 2016, respectively. The Company also provided for $9,637 in discretionary contributions in 2018 for those employees hired on or after January 1, 2017.

9. COMMON STOCK OPTIONS

The Company’s stockholders approved the RGC Resources, Inc. Key Employee Stock Option Plan (“KESOP”). 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, 2018, the number of shares available for future grants was 36,000.

FASB ASC No. 718 - Compensation-Stock Compensation requires that compensation expense be recognized for the issuance of equity instruments to employees. During the fiscal years ended 2017 and 2016, the Board approved stock option grants to certain officers. As required by the KESOP, each option's exercise price per share equaled the fair value of the Company's common stock on the grant date. Pursuant to the Plan, the options vest over a six-month period and are exercisable over a ten-year period from the date of issuance. No options were granted in fiscal 2018.

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,
	2018	2017	2016
Expected volatility	N/A	26.09%	28.78%
Expected dividends	N/A	3.81%	3.99%
Expected exercise term (years)	N/A	7.00	7.00
Risk-free interest rate	N/A	2.20%	2.10%

The underlying methods regarding each assumption are as follows:

Expected volatility is based on the historical volatilities of the daily closing price of the Company's common stock.

Expected dividend rate is based on historical dividend payout trends.

Expected exercise term is based on the average time historical option grants were outstanding before being exercised.

Risk-free interest rate is based on the 7-year Treasury rate on the date of option grant.

Forfeitures are recognized when they occur.

Stock option transactions under the Company's plans for the years ended September 30, 2018, 2017 and 2016 are summarized below. The information contained in the tables below have been restated to reflect the effect of the stock split:

61

	Number of Shares		Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Terms (years)	Aggregate Intrinsic Value 1
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
Options granted	—		—
Options exercised	(1,575	)	12.66
Options expired	—		—
Options forfeited	—		—
Options outstanding, September 30, 2018	100,000		$	14.34	6.6	$	1,237,286
Vested and exercisable at September 30, 2018	100,000		$	14.34	6.6	$	1,237,286

¹Aggregate intrinsic value includes only those options where the exercise price is below the market price.

	Years Ended September 30,
	2018		2017		2016
Weighted-average grant date option fair value	$	—	$	2.89	$	2.69
Stock option expense	—		73,780		64,640
Intrinsic value of options exercised	15,256		99,929		8,418
Proceeds from exercise of stock options	19,945		142,241		41,762

10. OTHER STOCK PLANS

Dividend Reinvestment and Stock Purchase Plan

The Company offers a Dividend Reinvestment and Stock Purchase Plan (the “DRIP”) to shareholders of record for the reinvestment of dividends and the purchase of up to $40,000 per year in additional shares of common stock of the Company. Under the DRIP, the Company issued 31,744, 36,446 and 52,146 shares in 2018, 2017 and 2016, respectively. As of September 30, 2018, the Company had 417,229 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, 1997. Under the Plan, each director may elect annually to have up to 100% of his or her fees paid in shares of common stock ("Director Restricted Stock"); however, a minimum of 40% of the monthly retainer fee must be paid to each non-employee director of Resources in shares of Director Restricted Stock until such time as the director has accumulated at least 10,000 shares. The number of shares of 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

62

business day of the month. The Director Restricted Stock issued under the Plan vests only in the case of a participant's death, disability, retirement, or in the event of a change in control of Resources. The Director Restricted Stock may not be sold, transferred, assigned or pledged by the participant until the shares have vested under the terms of the Plan. The shares of Director Restricted Stock will be forfeited to Resources by a participant's voluntary resignation during his or her term on the Board or removal for cause as a director.

The Company assumes all directors will complete their term and there will be no forfeiture of the Restricted Stock. Since the inception of the Plan, no director has forfeited any shares of Restricted Stock. The Company recognizes as compensation the market value of the Restricted Stock in the period it is issued.

The following table reflects the director compensation activity pursuant to the Plan:

	2018				2017			2016
	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	111,893		$	10.56	107,023	$	10.11	100,373	$	9.80
Granted	6,692		26.57		4,870	16.77		6,650	14.79
Vested	(20,283	)	11.20		—	—		—	—
Forfeited	—		—		—	—		—	—
End of year balance	98,302		$	11.51	111,893	$	10.56	107,023	$	10.11

The fair market value of the Director Restricted Stock included in compensation during fiscal 2018, 2017 and 2016 was $177,800, $99,400 and $98,334. No Director Restricted Stock vested or was forfeited during fiscal 2017 and 2016.

As of September 30, 2018, the Company had 75,049 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”) in 2017 following approval by the shareholders at the Company's annual meeting held on February 6, 2017. Under the Restricted Stock Plan, the Compensation Committee of the Board of Directors may grant shares of restricted 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 Plan 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 Restricted Stock Plan:

	2018
	Shares		Weighted-Average Fair Value on Date of Grant
Beginning of year balance	—		$	—
Granted	10,101		26.33
Vested	(3,367	)	26.33
Forfeited	—		—
End of year balance	6,734		$	26.33

The fair market value of the Officer Restricted Stock included as compensation during fiscal 2018 was $188,388. As of September 30, 2018, the Company had 439,734 shares available for issuance under the Plan.

63

Stock Bonus Plan

Shares from the Stock Bonus Plan may be issued to certain employees and management personnel in recognition of their performance and service. Under the Stock Bonus Plan, the Company issued 1,628 and 2,813 shares valued at $30,154 and $39,819, respectively, in 2017 and 2016. No shares were issued in 2018. As of September 30, 2018 the Company had 4,785 shares of stock available for issuance under the Stock Bonus Plan. This Plan is currently inactive and has been replaced by the Restricted Stock Plan.

11. COMMITMENTS AND CONTINGENCIES

Long-Term Contracts

Due to the nature of the natural gas distribution business, Roanoke Gas enters into agreements with both suppliers and pipelines to contract for natural gas commodity purchases, storage capacity and pipeline delivery capacity. Roanoke Gas obtains most of its regulated natural gas supply through an asset management contract with a third party asset manager. Roanoke Gas 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, Roanoke Gas has designated the asset manager to act as agent for its storage capacity and all gas balances in storage. Roanoke Gas retains ownership of gas in storage. Under provisions of this contract, Roanoke Gas is obligated to purchase its winter storage requirements from the asset manager during the spring and summer injection periods at market price. The table below details the volumetric obligations as of September 30, 2018 for the remainder of the contract period. The asset management contract was renewed for another three year period at essentially the same terms and conditions as the prior agreement. The current asset management agreement will expire in March 2021.

Year	Natural Gas Contracts (In Decatherms)
2018-2019	2,089,578
2019-2020	2,071,061
2020-2021	295,866
Total	4,456,505

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, 2018. 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 $31,137,000, $28,496,000 and $24,852,000 under the asset management, pipeline and storage contracts in fiscal years 2018, 2017 and 2016, respectively. The table below details the pipeline and storage capacity obligations as of September 30, 2018 for the remainder of the contract period.

Year	Pipeline and Storage Capacity
2018-2019	$	11,184,000
2019-2020	8,856,915
2020-2021	6,503,953
2021-2022	5,847,945
2022-2023	2,369,904
Thereafter	1,950,134
Total	$	36,712,851

64

Roanoke Gas maintains franchise agreements granted by the local cities and towns served by the Company. Roanoke Gas recently renewed it's franchise agreements with the City of Roanoke, the City of Salem and the Town of Vinton for 20-year terms expiring in December 2035. Per the agreements, franchise fees will increase 3% per year through the term of the agreements for a total cost of $2,512,411.

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

Both Roanoke Gas and a previously owned gas subsidiary operated manufactured gas plants (MGPs) as a source of fuel for lighting and heating until the early 1950’s. A by-product of operating MGPs was coal tar, and the potential exists for tar waste contaminants at the former plant sites. 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 either 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.

12. 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, 2018 and 2017, respectively:

			Fair Value Measurements - September 30, 2018
	Fair Value		Quoted Prices in Active Markets Level 1		Significant  Other Observable Inputs Level 2		Significant Unobservable Inputs Level 3
Assets:
Interest rate swaps	$	310,563	$	—	$	310,563	$	—
Total	$	310,563	$	—	$	310,563	$	—
Liabilities:
Natural gas purchases	$	693,495	$	—	$	693,495	$	—
Total	$	693,495	$	—	$	693,495	$	—

			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	$	—

65

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, 2018 and 2017, the Company had recorded in accounts payable the estimated fair value of the liability determined on the corresponding first of month index prices for which the liability was expected to be settled.

The Company’s nonfinancial 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 financial statements as of September 30, 2018 and 2017.

			Fair Value Measurements - September 30, 2018
	Carrying Amount		Quoted Prices in Active Markets Level 1		Significant Other Observable  Inputs Level 2		Significant Unobservable Inputs Level 3
Liabilities:
Notes payable	$	63,243,200	$	—	$	—	$	62,435,237
Total	$	63,243,200	$	—	$	—	$	62,435,237

			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:
Notes payable	$	43,812,200	$	—	$	—	$	45,689,238
Total	$	43,812,200	$	—	$	—	$	45,689,238

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-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. Increasing interest rates during 2018 resulted in the reduction in the fair value of the Company's outstanding debt. The fair value for the RGC Midstream debt is estimated by discounting the estimated credit spread extrapolated based on market conditions.

FASB ASC 825 – Financial Instruments requires disclosures regarding concentrations of credit risk from financial instruments. Cash equivalents are investments in high-grade, short-term securities (original maturity less than three months), placed with financially sound institutions. Accounts receivable are from a diverse group of customers including individuals and small and large companies in various industries. The Company maintains certain credit standards with its customers and requires a customer deposit if such evaluation warrants.

66

13. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Quarterly financial data for the years ended September 30, 2018 and 2017 is summarized as follows:

2018	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Operating revenues	$	18,756,051	$	24,917,973	$	11,889,570	$	9,971,142
Operating income	$	3,675,124	$	5,306,718	$	1,866,223	$	744,980
Net income	$	2,059,462	$	3,465,929	$	1,087,355	$	684,459
Earnings per share of common stock:
Basic	$	0.28	$	0.47	$	0.14	$	0.09
Diluted	$	0.28	$	0.47	$	0.14	$	0.09

2017	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Operating revenues	$	18,788,585	$	21,900,013	$	11,435,824	$	10,172,448
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

14. SUBSEQUENT EVENTS

The Company has evaluated subsequent events through the date the financial statements were issued. There were no other items not otherwise disclosed which would have materially impacted the Company’s consolidated financial statements.

* * * * * *

67

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

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”), and that such information is accumulated and communicated to management to allow for timely decisions regarding required disclosure.

As of September 30, 2018, 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, 2018.

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 America 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, 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, 2018, based on the framework set forth in ”Internal Control - Integrated Framework (2013)” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based upon such evaluation, the Company concluded that, as of September 30, 2018, the Company’s internal control over financial reporting was effective.

The Company’s independent registered public accounting firm, Brown, Edwards & Company, LLP, has issued its report on the effectiveness of the Company’s internal control over financial reporting as of September 30, 2018.

68

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

RGC Resources, Inc.

Roanoke, Virginia

Opinion on Internal Control over Financial Reporting

We have audited RGC Resources, Inc. and Subsidiaries (“the Company's”)’internal control over financial reporting as of September 30, 2018, based on criteria established in Internal Control-Integrated Framework - 2013 issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of September 30, 2018, based on criteria established in Internal Control-Integrated Framework - 2013 issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets and the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows of the Company, and our report dated December 3, 2018, expressed an unqualified opinion.

Basis for Opinion

The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitation of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) 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 its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

              CERTIFIED PUBLIC ACCOUNTANTS

Blacksburg, Virginia

December 3, 2018

69

Item 9B. Other Information.

None

70

PART III

Item 10. Directors, Executive Officers and Corporate Governance.

For information with respect to the executive officers of the registrant, see “Executive Officers" section in the Proxy Statement for the 2019 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 2019 Annual Meeting of Shareholders of Resources, which information is incorporated herein by reference. In addition, the Board of Directors has determined that Abney S. Boxley, III and Raymond D. Smoot, Jr. are audit committee financial experts under applicable SEC rules.

For information regarding the process for identifying and evaluating candidates to be nominated as directors, see "Director Nominations" in the Proxy Statement for the 2019 Annual Meeting of Shareholders of Resources, which is incorporated herein by reference.

Information with respect to compliance with Section 16(a) of the Exchange Act, which is set forth under the caption "Section 16 (a) Beneficial Ownership Reporting Compliance" in the Proxy Statement for the 2019 Annual Meeting of Shareholders of Resources, is incorporated herein by reference.

The Company has adopted a Code of Ethics applicable to all of its officers, directors and employees. The Company has posted the text of its Code of Ethics on its website at www.rgcresources.com. The Board of Directors has adopted charters for the Audit, Compensation, and 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.

The information set forth under "Compensation of Directors", "Compensation Discussion and Analysis" and "Report of the Compensation Committee" in the Proxy Statement for the 2019 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.

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 2019 Annual Meeting of Shareholders of Resources, is incorporated herein by reference.

Item 13. Certain Relationships and Related Transactions, and Director Independence.

The information pertaining to director independence is set forth under the caption “Board of Directors and Committees of the Board of Directors” and pertaining to transactions with related persons is set forth under the caption "Transactions with Related Persons" in the Proxy Statement for the 2019 Annual Meeting of Shareholders of Resources, which information is incorporated herein by reference.

Item 14. Principal Accounting Fees and Services.

The information set forth under the caption "Report of the Audit Committee" in the Proxy Statement for the 2019 Annual Meeting of Shareholders of Resources is incorporated herein by reference.

71

PART IV

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 to this Form 10-K filed as part of this report:

13	Annual Report
21	Subsidiaries of the Company
23	Consent of Brown, Edwards & Company, LLP
31.1	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer
31.2	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer
32.1*	Section 1350 Certification of Principal Executive Officer
32.2*	Section 1350 Certification of Principal Financial Officer
101	The following documents from the Registrant’s Annual Report on Form 10-K for the years ended September 30, 2018, 2017 and 2016, formatted in XBRL (eXtensible Business Reporting Language); Consolidated Balance Sheets at September 30, 2018 and 2017, (ii) Consolidated Statements of Income for the years ended September 30, 2018, 2017 and 2016, (iii) Consolidated Statements of Comprehensive Income for the years ended September 30, 2018, 2017 and 2016, (iv) Consolidated Statements of Stockholders’ Equity for the years ended September 30, 2018, 2017 and 2016, (v) Consolidated Statements of Cash Flows for the years ended September 30, 2018, 2017 and 2016, 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.

72

SIGNATURES

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/    PAUL W. NESTER	December 3, 2018
	Paul W. Nester	Date
	Vice President, Secretary, Treasurer and CFO
	(principal accounting and financial officer)

73

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 3, 2018	President and Chief Executive Officer, Director
John S. D'Orazio	Date
/S/    PAUL W. NESTER	December 3, 2018	Vice President, Treasurer and CFO (principal accounting and financial officer)
Paul W. Nester	Date
/S/    JOHN B. WILLIAMSON, III	December 3, 2018	Chairman of the Board and Director
John B. Williamson, III	Date
/S/    NANCY H. AGEE	December 3, 2018	Director
Nancy H. Agee	Date
/S/    ABNEY S. BOXLEY, III	December 3, 2018	Director
Abney S. Boxley, III	Date
/S/  T. JOE CRAWFORD	December 3, 2018	Director
T. Joe Crawford	Date
/S/    MARYELLEN F. GOODLATTE	December 3, 2018	Director
Maryellen F. Goodlatte	Date
/S/    J. ALLEN LAYMAN	December 3, 2018	Director
J. Allen Layman	Date
/S/    S. FRANK SMITH	December 3, 2018	Director
S. Frank Smith	Date
/S/    RAYMOND D. SMOOT, JR.	December 3, 2018	Director
Raymond D. Smoot, Jr.	Date

74

EXHIBIT INDEX

Exhibit No.		Description
3 (a)		Articles of Incorporation of RGC Resources, Inc. (incorporated herein by reference to Exhibit 3(a) of Registration Statement No. 33-67311, on Form S-4, filed with the Commission on November 13, 1998, and amended by Amendment No. 5, filed with the Commission on January 28, 1999)
3 (b)		Amended and Restated Bylaws of RGC Resources, Inc. (incorporated herein by reference to Exhibit 3(b) on the Form 8-K filed on February 7, 2014)
4 (a)		Specimen copy of certificate for RGC Resources, Inc. common stock, $5.00 par value (incorporated herein by reference to Exhibit 3(b) of Registration Statement No. 33-67311, on Form S-4, filed with the Commission on November 13, 1998, and amended by Amendment No. 5, filed with the Commission on January 28, 1999)
4 (b)		RGC Resources, Inc., Amended and Restated Dividend Reinvestment and Stock Purchase Plan (incorporated by reference to Exhibit 4(b) of the Form 10-K for the year ended September 30, 2014)
4 (c)		Description of RGC Resources, Inc. Common Stock (incorporated by reference to Exhibit 99.1 on Form 8-K as filed on August 10, 2017)
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)		NTS Service Agreement between Columbia Gas Transmission Corporation and Roanoke Gas Company dated September 3, 2004 (incorporated herein by reference to Exhibit 10(g)(g)(g) of the Quarterly Report on Form 10-Q for the period ended December 31, 2004)
10 (c)		FSS Service Agreement between Columbia Gas Transmission Corporation and Roanoke Gas Company dated September 3, 2004 (incorporated herein by reference to Exhibit 10(h)(h)(h) of the Quarterly Report Form 10-Q for the period ended December 31, 2004)
10 (d)		FTS Service Agreement between Columbia Gas Transmission Corporation and Roanoke Gas Company dated September 3, 2004 (incorporated herein by reference to Exhibit 10(i)(i)(i) of the Quarterly Report on Form 10-Q for the period ended December 31, 2004)
10 (e)		SST Service Agreement between Columbia Gas Transmission Corporation and Roanoke Gas Company dated September 3, 2004 (incorporated herein by reference to Exhibit 10(j)(j)(j) of the Quarterly Report on Form 10-Q for the period ended December 31, 2004)
10 (f)		FTS Service Agreement effective April 1, 2017 between Columbia Gas Transmission LLC and Roanoke Gas Company (incorporated herein by reference to Exhibit 10(f) of the Annual Report on Form 10-K as filed December 8, 2017)
10 (g)		FTS-1 Service Agreement between Columbia Gulf Transmission Corporation and Roanoke Gas Company dated September 3, 2004 (incorporated herein by reference to Exhibit 10(k)(k)(k) of the Quarterly Report on Form 10-Q for period ended December 31, 2004)
10 (h)	P	Gas Transportation Agreement, for use under FT-A rate schedule, between Tennessee Gas Pipeline Company and Roanoke Gas Company dated November 1, 1993 (incorporated herein by reference to Exhibit 10(k) of the Annual Report on Form 10-K for the fiscal year ended September 30, 1994 (SEC file number reference 0-367))
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)	P	Gas Storage Contract under rate schedule FS (Market Area) Portland between Tennessee Gas Pipeline Company and Roanoke Gas Company dated November 1, 1993 (incorporated herein by reference to Exhibit 10(k)(k) of the Annual Report on Form 10-K for the fiscal year ended September 30, 1994 (SEC file number reference 0-367))

10 (k)		FTA Gas Transportation Agreement effective November 1, 1998, between East Tennessee Natural Gas Company and Roanoke Gas Company (incorporated herein by reference to Exhibit 10(s)(s) of Annual Report on Form 10-K for the fiscal year ended September 30, 1998 (SEC file reference number 0-367))
10 (l)		FTS Service Agreement effective November 1, 1999, between Columbia Gas Transmission Corporation and Roanoke Gas Company (incorporated herein by reference to Exhibit 10(p)(p) of Annual Report on Form 10-K for the fiscal year ended September 30, 2001 (SEC file reference number 0-367))
10 (m)		Firm Storage Service Agreement effective March 19, 1997, between Virginia Gas Storage Company and Roanoke Gas Company (incorporated herein by reference to Exhibit 10(w)(w) of Annual Report on Form 10-K for the fiscal year ended September 30, 1998 (SEC file reference number 0-367))
10 (n)		Firm Storage Service Agreement by and between Roanoke Gas Company and Virginia Gas Pipeline Company, dated June 1, 2001 (incorporated herein by reference to Exhibit 10(b)(b)(b) of Annual Report on Form 10-K for the fiscal year ended September 30, 2001 (SEC file number reference 0-367))
10(o)		FSS Service Agreement between Saltville Gas Storage Company L.L.C. and Roanoke Gas Company dated November 21, 2012 (incorporated herein by reference to Exhibit 10(o) of the Annual Report on Form 10-K as filed December 8, 2017)
10 (p)		Firm Pipeline Service Agreement by and between Roanoke Gas Company and Virginia Gas Pipeline Company, dated June 1, 2001 (incorporated herein by reference to Exhibit 10(c)(c)(c) of Annual Report on Form 10-K for the fiscal year ended September 30, 2001 (SEC file number reference 0-367))
10 (q)		Natural Gas Asset Management Agreement by and between Roanoke Gas Company and Sequent Energy Management LP effective April 1, 2018 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed on March 27, 2018)
10 (r)		Parental Guaranty by RGC Resources, Inc. in favor of Sequent Energy Management LP effective April 1, 2018 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed on March 27, 2018)
10 (s)		Gas Transportation Agreement between Tennessee Gas Pipeline Company and Roanoke Gas Company originally dated November 1, 1999 as amended May 17, 2016 (incorporated herein by reference to Exhibit 10.3 of Form 10-Q as filed August 4, 2016)
10 (t)		Amendment dated May 17, 2016 to Gas Transportation Agreement originally dated December 1, 1993 between Tennessee Gas Pipeline Company and Roanoke Gas Company (incorporated herein by reference to Exhibit 10.1 of Form 10-Q as filed August 4, 2016)
10 (u)		Amendment dated May 17, 2016 to Gas Transportation Agreement originally dated November 1, 1993 between Tennessee Gas Pipeline Company and Roanoke Gas Company (incorporated herein by reference to Exhibit 10.2 of Form 10-Q as filed August 4, 2016)
10 (v)	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 (w)	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, 1990)
10 (x)	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, 1990)

10 (y)	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, 1990)
10 (z)	P	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 (a)(a)	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, 1987)
10 (b)(b)	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, 1987)
10 (c)(c)		Gas Franchise Agreement between the City of Roanoke, Virginia, and Roanoke Gas Company dated December 14, 2015 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed December 16, 2015)
10 (d)(d)		Gas Franchise Agreement between the City of Salem, Virginia, and Roanoke Gas Company dated December 14, 2015 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed December 16, 2015)
10 (e)(e)		Gas Franchise Agreement between the Town of Vinton, Virginia, and Roanoke Gas Company dated November 17, 2015 (incorporated herein by reference to Exhibit 10.3 on Form 8-K as filed December 16, 2015)
10 (f)(f)		RGC Resources Amended and Restated Key Employee Stock Option Plan (incorporated herein by reference to Exhibit 4(c) of Registration Statement No. 333-02455, Post Effective Amendment on Form S-8, filed with the Commission on July 2, 1999)
10 (g)(g)		RGC Resources, Inc. Amended and Restated Stock Bonus Plan (incorporated herein by reference to Exhibit 10 on Form 8-K filed on January 27, 2005 (SEC file reference number 0-367))
10 (h)(h)		RGC Resources, Inc. Amended And Restated Restricted Stock Plan for Outside Directors (incorporated herein by reference to Exhibit 10(i)(i) to the Annual Report on Form 10-K as filed December 8, 2017)
10 (i)(i)		RGC Resources, Inc. Restricted Stock Plan (incorporated herein by reference to Exhibit 10.1 of Form 8-K as filed February 9, 2017)
10 (j)(j)		Change in Control Agreement between RGC Resources, Inc. and Mr. John S. D'Orazio effective May 1, 2018 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed May 1, 2018)
10 (k)(k)		Change in Control Agreement between RGC Resources, Inc. and Mr. Paul W. Nester effective May 1, 2018 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed May 1, 2018)
10 (l)(l)		Change in Control Agreement between RGC Resources, Inc. and Mr. Robert L. Wells, II effective May 1, 2018 (incorporated herein by reference to Exhibit 10.3 on Form 8-K as filed May 1, 2018)
10 (m)(m)		Change in Control Agreement between RGC Resources, Inc. and Mr. Carl J. Shockley effective May 1, 2018 (incorporated herein by reference to Exhibit 10.4 on Form 8-K as filed May 1, 2018)
10 (n)(n)		Revolving Line of Credit Note in the original principal amount of $25,000,000 by Roanoke Gas Company in favor of Wells Fargo Bank, N.A. dated as of March 26, 2018 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed March 27, 2018)
10 (o)(o)		Credit Agreement by and between Roanoke Gas Company and Wells Fargo Bank, N.A. dated March 31, 2016 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed April 4, 2016)

10 (p)(p)	First Amendment to Credit Agreement by and between Roanoke Gas Company and Wells Fargo Bank, N.A. dated March 27, 2017 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed March 29, 2017)
10 (q)(q)	Second Amendment to Credit Agreement by and between Roanoke Gas Company and Wells Fargo Bank, N.A. dated as of March 26, 2018 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed March 27, 2018)
10 (r)(r)	Continuing Guaranty by RGC Resources, Inc. in favor of Wells Fargo Bank, N.A. dated March 31, 2016 (incorporated by reference to Exhibit 10.3 on Form 8-K as filed April 4, 2016)
10 (s)(s)	Indemnification and Cost Sharing Agreement by and between RGC Resources, Inc., Bluefield Gas Company and ANGD, LLC (incorporated herein by reference to Exhibit 10.2 on Form 10-K as filed December 21, 2007 (SEC file number reference 0-367))
10 (t)(t)	Note Purchase Agreement for 4.26% Senior Guaranteed Notes due September 18, 2034 in the original principal amount of $30,500,000 in favor of The Prudential Insurance Company of America, PAR U Hartford Life & Annuity Comfort Trust and PRUCO Life Insurance Company of New Jersey (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed August 4, 2014)
10 (u)(u)	Unconditional Parent Guaranty by RGC Resources, Inc. in favor of each of the olders of the notes: The Prudential Life Insurance Company of America, PAR U Hartford Life & Annuity Comfort Trust and PRUCO Life Insurance Company of New Jersey (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed August 4, 2014)
10 (v)(v)	4.26% Senior Guaranteed Notes due September 18, 2034 in the original principal amount of $15,250,000 in favor of The Prudential Insurance Company of America (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed September 23, 2014)
10 (w)(w)	4.26% Senior Guaranteed Notes due September 18, 2034 in the original principal amount of $9,700,000 in favor of PAR U Hartford Life & Annuity Comfort Trust (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed September 23, 2014)
10 (x)(x)	4.26% Senior Guaranteed Notes due September 18, 2034 in the original principal amount of $5,550,000 in favor of PRUCO Life Insurance Company of New Jersey (incorporated herein by reference to Exhibit 10.3 on Form 8-K as filed September 23, 2014)
10 (y)(y)	ISDA Master Agreement by and between Roanoke Gas Company and Branch Bank and Trust dated as of October 27, 2008 (incorporated herein by reference to Exhibit 10.3 on Form 8-K as filed November 5, 2008 (SEC file number reference 0-367))
10 (z)(z)	Credit Agreement between RGC Midstream, LLC, Union Bank & Trust and Branch Banking and Trust Company dated December 29, 2015 (incorporated by reference to Exhibit 10.1 on Form 8-K as filed December 31, 2015)
10 (a)(a)(a)	First Amendment to Credit Agreement between RGC Midstream, LLC and the lenders Union Bank & Trust and Branch Banking and Trust dated April 11, 2018 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed April 12, 2018)
10 (b)(b)(b)	Amended and Restated Note in the principal amount of $22,800,000 in favor of Union Bank & Trust due December 29, 2020 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed April 12, 2018)
10 (c)(c)(c)	Amended and Restated Note in the principal amount of $15,200,000 in favor of Branch Banking and Trust due December 29, 2020 (incorporated herein by reference to Exhibit 10.3 on Form 8-K as filed April 12, 2018)
10 (d)(d)(d)	Guaranty by RGC Resources, Inc. in favor of Union Bank & Trust and Branch Banking and Trust Company dated December 29, 2015 (incorporated herein by reference to Exhibit 10.4 on Form 8-K as filed December 31, 2015)
10 (e)(e)(e)	Term Loan Agreement dated November 1, 2016 in favor of Branch Banking and Trust Company dated November 1, 2016 (incorporated by reference to Exhibit 10.1 on Form 8-K as filed November 7, 2016)

10 (f)(f)(f)		Promissory Note dated November 1, 2016 in the principle amount of $7,000,000 in favor of Branch Banking and Trust Company due November 1, 2021 (incorporated by reference to Exhibit 10.2 on Form 8-K as filed November 7, 2016)
10 (g)(g)(g)		Guaranty Agreement between RGC Resources, Inc. and Branch Banking and Trust Company on behalf of Roanoke Gas Company dated November 1, 2016 (incorporated herein by reference to Exhibit 10.3 on Form 8-K as filed November 7, 2016)
10 (h)(h)(h)		Swap Agreement by and between Roanoke Gas Company and Branch Banking and Trust Company dated November 1, 2016 (incorporated herein by reference to Exhibit 10.4 on Form 8-K as filed November 7, 2016)
10 (i)(i)(i)		Private Shelf Agreement by and between Roanoke Gas Company and Prudential Investment Management, Inc. for the pre-authorization to issue notes up to $29,500,000 in total during the term of the agreement (incorporated herein by reference to Exhibit 10.4 on Form 8-K as filed October 4, 2017)
10 (j)(j)(j)		Unsecured Note in the original principal amount of $4,000,000 by and between Roanoke Gas Company and PRUCO Life Insurance Company of New Jersey, dated October 2, 2017 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed October 4, 2017)
10 (k)(k)(k)		Unsecured Note in the original principal amount of $4,000,000 by and between Roanoke Gas Company and Prudential Arizona Reinsurance Captive Company, dated October 2, 2017 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed October 4, 2017)
10 (l)(l)(l)		Unconditional Parent Guaranty by RGC Resources, Inc. in favor of each of the olders of the notes: The PRUCO Life Insurance Company of New Jersey and the Prudential Arizona Reinsurance Captive Company (incorporated herein by reference to Exhibit 10.3 on Form 8-K as filed October 4, 2017)
10 (m)(m)(m)	**	Third Amended and Restated Limited Liability Company Agreement of Mountain Valley Pipeline, LLC dated April 6, 2018 (incorporated by reference to Exhibit 10.1 on the Quarterly Report on Form 10-Q as filed May 7, 2018)
10 (n)(n)(n)		Guaranty Agreement by RGC Resources, Inc. in favor of Mountain Valley Pipeline, LLC (incorporated herein by reference to Exhibit 10.2 on Form 10-Q as filed May 7, 2018)
13		Annual Report
21		Subsidiaries of the Company
23		Consent of Brown, Edwards & Company, LLP
31.1		Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer
31.2		Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer
32.1*		Section 1350 Certification of Principal Executive Officer
32.2*		Section 1350 Certification of Principal Financial Officer
101		The following documents from the Registrant’s Annual Report on Form 10-K for the years ended September 30, 2018, 2017 and 2016, formatted in XBRL (eXtensible Business Reporting Language); Consolidated Balance Sheets at September 30, 2018 and 2017, (ii) Consolidated Statements of Income for the years ended September 30, 2018, 2017 and 2016, (iii) Consolidated Statements of Comprehensive Income for the years ended September 30, 2018. 2017 and 2016, (iv) Consolidated Statements of Stockholders’ Equity for the years ended September 30, 2018, 2017 and 2016, (v) Consolidated Statements of Cash Flows for the years ended September 30, 2018, 2017 and 2016, 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.

** 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.

EX-13

2018 Annual Report

PRESIDENT’S LETTER To Our Shareholders: I am delighted to report that 2018 was an exceptional year for RGC Resources. Net income improved 17% from 2017 to $7.3 million, our fourth consecutive year of record earnings. In March, Resources successfully raised $15.1 million through its first public offering in over 20 years. In June, Resources was included in the Russell 2000 index for the second consecutive year. Our Board of Directors approved a 6.5% annualized dividend increase to $0.66 per share, effective with the February 1, 2019 quarterly dividend payment. The February dividend will reflect 75 years of continuous quarterly dividend payments and 15 years of consecutive annual dividend increases. Roanoke Gas continues to experience consistent customer growth. The number of residential and small commercial customers increased approximately 1%. Commercial customer volumes increased 20%, industrial customer volumes increased 4% and our top 10 customer usage increased 7% over 2017. Looking forward, we expect the trend of increasing commercial and industrial gas usage to continue as several new manufacturers come on‐line, and the Virginia Tech Carilion Strategic Partnership expands its research institute and medical school. Construction on the Mountain Valley Pipeline (MVP) started in January 2018. Since then, MVP has encountered legal challenges to various federal and state permits as well as anti‐pipeline protests. Both have led to periods of work stoppages and schedule changes. Combined with unusually high rainfall, the projected in‐service date has been moved to the end of calendar 2019. Roanoke Gas will have two interconnects with the MVP. The first interconnect, located near the southern end of our system, will provide additional supply to address the growing demand for natural gas in the Roanoke Valley. The second interconnect will be located in the new Summit View business park in Franklin County, Virginia. This interconnect will provide Roanoke Gas the opportunity to build a distribution system in Franklin County, which currently does not have access to natural gas, and extend gas service to new industrial, commercial and residential customers. The strategic investment in MVP continues to complement our core business and enhance shareholder value. In April 2018, MVP announced the MVP Southgate project, a proposed interstate natural gas pipeline anchored by a firm capacity commitment from PSNC Energy. MVP Southgate will provide a much needed additional natural gas supply source to southern Virginia and central North Carolina. RGC Midstream will have a small investment in this project. MVP Southgate is scheduled to be completed and in‐service at the end of 2020. In 2018, we invested a record $23.3 million in Roanoke Gas, focusing on the modernization of our distribution system, new customer additions and system reinforcement projects that improved system safety and reliability. This past year we replaced approximately 8.3 miles of first generation plastic mains and 496 services. Looking into 2019, in addition to the aforementioned MVP interconnects, we will continue our first generation plastic renewals and undertake several large steel main reinforcement projects. In closing, we are pleased to provide you with our 2018 annual report reflecting our long‐term commitment of delivering shareholder value and providing safe and reliable natural gas service. On behalf of our Board of Directors and dedicated employees, I thank you for your continued interest in our Company and for your ongoing decision to invest in RGC Resources. John S. D’Orazio CEO & President

CORPORATE INFORMATION Nancy Howell Agee Board of President & CEO, Carilion Clinic Directors Abney S. Boxley, III President – East Region, Summit Materials T. Joe Crawford Vice President & General Manager, Steel Dynamics Roanoke Bar Division John S. D’Orazio President & CEO, RGC Resources, Inc. Maryellen F. Goodlatte Attorney & Principal, Glenn, Feldmann, Darby & Goodlatte J. Allen Layman Private Investor & Retired Utility Executive S. Frank Smith Private Investor & Retired Energy Industry Executive Raymond D. Smoot, Jr. Chairman, Union Bankshares Corporation John B. Williamson, III Chairman of the Board DIVIDEND REINVESTMENT AND  STOCK          ANNUAL REPORT AND 10‐K PURCHASE PLAN INQUIRIES This annual report, 10‐Kandthefinancial Through the Company’s Dividend Reinvestment statements contained herein are submitted and Stock Purchase Plan, shareholders of record to the shareholders of the Company for their are offered a convenient way to acquire and general information and not in connection reinvest cash dividends in additional shares of the with any sale or offer to sell, or solicitation Company’s common stock and avoid commissions of any offer to buy, any securities. or other charges. Additionally, shareholders are given on‐line access to make transfers, consolidate ANNUAL MEETING accounts, replace stock certificates and dividend The annual meeting of shareholders of the payments, set‐up direct deposit, update personal Company will be held at The Hotel Roanoke information and much more. Broadridge Corporate and Conference Center, 110 Shenandoah Issuer Solutions administers the plan and is the Avenue, Roanoke, Virginia, 24016 on agent for participants. For more information, Monday, February 4, 2019, at 9:00 a.m. inquiries may be directed to RGC Resources, Inc., Proxies for the annual meeting will be Shareholder Information Services, P.O. Box 13007, requested from shareholders when notice of Roanoke, VA 24030, (540) 777‐3853. meeting, proxy statement and form of proxy are mailed on or about December 14, 2018.

519 Kimball Avenue, NE P.O. Box 13007 Roanoke, Virginia 24030‐3007 www.rgcresources.com Facebook.com/RoanokeGas Twitter.com/RoanokeGas Trading on NASDAQ as RGCO

EX-21

Exhibit 21

RGC Resources, Inc.

Subsidiaries of Registrant

Roanoke Gas Company

Diversified Energy Company

RGC Midstream, LLC

EX-23

Exhibit 23

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-218966 on Form S-8, Registration Statement No. 333-187529 on Form S-8, Registration Statement No. 333-178136 on Form S-8, Registration Statement No. 333-122746 on Form S-8, Registration Statement No. 333-219876 on Form S-3, Registration Statement No. 333-122742 on Form S-3 of RGC Resources, Inc. of our report dated December 3, 2018 appearing in this Annual Report on Form 10-K of RGC Resources, Inc. for the year ended September 30, 2018.

              CERTIFIED PUBLIC ACCOUNTANTS

Blacksburg, Virginia

December 3, 2018

EX-31.1

Exhibit 31.1

CERTIFICATION

I, John S. D'Orazio, certify that:

1. I have reviewed this annual report on Form 10-K of RGC Resources, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: December 3, 2018	/s/ John S. D'Orazio
	President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Paul W. Nester, certify that:

1. I have reviewed this annual report on Form 10-K of RGC Resources, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: December 3, 2018	/s/ Paul W. Nester
	Vice-President, Secretary,Treasurer and CFO

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of RGC Resources, Inc. (the “Company”) on Form 10-K for the period ended September 30, 2018 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John S. D'Orazio, President and Chief Executive Officer of the Company, certify to my knowledge, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

/s/ John S. D'Orazio

John S. D'Orazio

President and Chief Executive Officer

December 3, 2018

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of RGC Resources, Inc. (the “Company”) on Form 10-K for the period ended September 30, 2018 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Paul W. Nester, Vice-President, Secretary, Treasurer and CFO of the Company, certify to my knowledge, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

/s/ Paul W. Nester

Paul W. Nester

Vice-President, Secretary,

Treasurer and CFO

December 3, 2018

XML

Document And Entity Information - USD ($)	12 Months Ended
	Sep. 30, 2018	Nov. 23, 2018	Mar. 31, 2018
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Sep. 30, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	FY
Entity Registrant Name	RGC RESOURCES INC
Entity Central Index Key	0001069533
Current Fiscal Year End Date	--09-30
Entity Filer Category	Smaller Reporting Company
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Common Stock, Shares Outstanding		8,003,606
Entity Public Float			$ 188,207,371

XML

Consolidated Balance Sheets - USD ($)	Sep. 30, 2018	Sep. 30, 2017
CURRENT ASSETS:
Cash and cash equivalents	$ 247,411	$ 69,640
Accounts receivable, net	3,913,830	3,492,703
Materials and supplies	913,889	1,021,191
Gas in storage	7,627,196	7,701,894
Prepaid income taxes	837,683	1,796,825
Under-recovery of gas costs	922,898	0
Interest rate swap	100,723	26,777
Other	980,972	1,576,574
Total current assets	15,544,602	15,685,604
UTILITY PROPERTY:
In service	224,854,320	204,223,714
Accumulated depreciation and amortization	(63,099,306)	(59,765,987)
In service, net	161,755,014	144,457,727
Construction work in progress	4,208,614	3,470,244
Utility plant, net	165,963,628	147,927,971
OTHER ASSETS:
Regulatory assets	8,862,147	11,796,260
Investment in unconsolidated affiliate	28,507,146	7,445,106
Interest rate swap	209,840	90,066
Other	472,743	190,064
Total other assets	38,051,876	19,521,496
TOTAL ASSETS	219,560,106	183,135,071
CURRENT LIABILITIES:
Dividends payable	1,242,753	1,050,281
Accounts payable	5,211,032	5,122,899
Capital contributions payable	10,142,766	1,055,504
Customer credit balances	1,003,622	1,220,578
Customer deposits	1,421,043	1,471,960
Accrued expenses	3,750,466	3,006,936
Over-recovery of gas costs	0	1,438,074
Rate refund	1,320,167	0
Total current liabilities	24,091,849	14,366,232
LONG-TERM DEBT:
Notes payable	63,243,200	43,812,200
Line-of-credit	7,361,017	17,791,760
Less unamortized debt issuance costs	(282,281)	(291,949)
Long-term debt net of unamortized debt issuance costs	70,321,936	61,312,011
DEFERRED CREDITS AND OTHER LIABILITIES:
Asset retirement obligations	6,417,948	6,069,993
Regulatory cost of retirement obligations	11,163,981	10,055,189
Benefit plan liabilities	3,947,967	8,214,326
Deferred income taxes	12,585,577	23,076,848
Regulatory liability - deferred income taxes	11,447,736	0
Total deferred credits and other liabilities	45,563,209	47,416,356
COMMITMENTS AND CONTINGENCIES (Note 11)
Stockholders’ Equity:
Common Stock, $5 par value; authorized 10,000,000 shares; issued and outstanding 7,994,615 and 7,240,846 shares in 2018 and 2017, respectively	39,973,075	36,204,230
Preferred stock, no par; authorized 5,000,000 shares; no shares issued and outstanding in 2018 and 2017	0	0
Capital in excess of par value	13,043,656	292,485
Retained earnings	27,438,049	24,746,021
Accumulated other comprehensive loss	(871,668)	(1,202,264)
Total stockholders’ equity	79,583,112	60,040,472
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$ 219,560,106	$ 183,135,071

XML

Consolidated Balance Sheets (Parenthetical) - $ / shares	Sep. 30, 2018	Sep. 30, 2017
Statement of Financial Position [Abstract]
Common stock, par value (in usd per share)	$ 5	$ 5
Common stock, shares authorized	10,000,000	10,000,000
Common stock, shares issued	7,994,615	7,240,846
Common stock, shares outstanding	7,994,615	7,240,846
Preferred stock, no par value (in usd per share)
Preferred stock, shares authorized	5,000,000	5,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0

XML

Consolidated Statements of Income - USD ($)	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
OPERATING REVENUES:
Gas utilities	$ 64,341,783	$ 61,252,015	$ 58,079,990
Other	1,192,953	1,044,855	983,301
Total operating revenues	65,534,736	62,296,870	59,063,291
OPERATING EXPENSES:
Cost of gas - utility	32,091,923	28,919,625	27,009,330
Cost of sales - non utility	666,524	568,088	489,047
Operations and maintenance	12,348,890	13,100,041	13,098,086
General taxes	1,878,010	1,786,070	1,663,126
Depreciation and amortization	6,956,344	6,256,737	5,591,610
Total operating expenses	53,941,691	50,630,561	47,851,199
OPERATING INCOME	11,593,045	11,666,309	11,212,092
Equity in earnings of unconsolidated affiliate	938,531	421,646	152,864
Other (income) expense, net	(122,330)	132,446	255,585
Interest expense	2,461,565	1,917,254	1,636,321
INCOME BEFORE INCOME TAXES	10,192,341	10,038,255	9,473,050
INCOME TAX EXPENSE	2,895,136	3,805,390	3,666,184
NET INCOME	$ 7,297,205	$ 6,232,865	$ 5,806,866
EARNINGS PER COMMON SHARE:
Basic (in usd per share)	$ 0.95	$ 0.86	$ 0.81
Diluted (in usd per share)	$ 0.95	$ 0.86	$ 0.81
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic (in shares)	7,649,025	7,218,686	7,149,906
Diluted (in shares)	7,695,712	7,256,046	7,159,763

XML

Consolidated Statements of Comprehensive Income - USD ($)	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Statement of Comprehensive Income [Abstract]
NET INCOME	$ 7,297,205	$ 6,232,865	$ 5,806,866
Other comprehensive income, net of tax:
Interest rate swaps	137,850	72,489	0
Defined benefit plans	406,798	1,222,478	(210,686)
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX	544,648	1,294,967	(210,686)
COMPREHENSIVE INCOME	$ 7,841,853	$ 7,527,832	$ 5,596,180

XML

Consolidated Statements of Stockholders' Equity - USD ($)	Total	Common Stock	Capital in Excess of Par Value	Retained Earnings	Accumulated Other Comprehensive Income (Loss)
Beginning balance at Sep. 30, 2015	$ 52,840,991	$ 23,707,490	$ 8,647,669	$ 22,772,377	$ (2,286,545)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	5,806,866			5,806,866
Other comprehensive income (loss)	(210,686)				(210,686)
Exercise of stock options	41,762	11,000	30,762
Stock option grants	64,640		64,640
Cash dividends declared	(3,865,933)			(3,865,933)
Issuance of common stock	989,432	222,955	766,477
Ending balance at Sep. 30, 2016	55,667,072	23,941,445	9,509,548	24,713,310	(2,497,231)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	6,232,865			6,232,865
Other comprehensive income (loss)	1,294,967				1,294,967
Exercise of stock options	142,241	50,250	91,991
Stock option grants	73,780		73,780
Cash dividends declared	(4,195,910)			(4,195,910)
Stock split	0	12,029,790	(10,025,546)	(2,004,244)
Issuance costs	(96,508)		(96,508)
Issuance of common stock	921,965	182,745	739,220
Ending balance at Sep. 30, 2017	60,040,472	36,204,230	292,485	24,746,021	(1,202,264)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	7,297,205			7,297,205
Other comprehensive income (loss)	544,648				544,648
Exercise of stock options	19,945	7,875	12,070
Cash dividends declared	(4,839,514)			(4,839,514)
Issuance costs	(990,459)		(990,459)
Issuance of common stock	17,490,530	3,760,970	13,729,560
Reclassification adjustment for effect of change in tax law	20,285			234,337	(214,052)
Ending balance at Sep. 30, 2018	$ 79,583,112	$ 39,973,075	$ 13,043,656	$ 27,438,049	$ (871,668)

XML

Consolidated Statements of Stockholders' Equity (Parenthetical) - $ / shares	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Statement of Stockholders' Equity [Abstract]
Dividends declared (in usd per share)	$ 0.62	$ 0.58	$ 0.54
Issuance of stock (in shares)	752,194	47,187	66,887
Options exercised (in shares)	1,575	11,225	3,300

XML

Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 7,297,205	$ 6,232,865	$ 5,806,866
Adjustments to reconcile net income to net cash provided by operations:
Depreciation and amortization	7,090,169	6,378,368	5,709,525
Cost of retirement of utility plant, net	(288,222)	(354,744)	(449,201)
Stock option grants	0	73,780	64,640
Equity in earnings of unconsolidated affiliate	(938,531)	(421,646)	(152,864)
Deferred income taxes	755,994	3,325,379	4,466,954
Other noncash items, net	163,482	203,743	197,298
Changes in assets and liabilities which provided (used) cash:
Accounts receivable and customer deposits, net	(476,161)	(191,386)	(258,960)
Inventories and gas in storage	182,000	(462,161)	867,682
Over/under recovery of gas costs	(2,360,972)	528,387	(991,739)
Other assets	784,566	(956,894)	(398,864)
Accounts payable, customer credit balances and accrued expenses, net	(25,902)	(1,374,713)	60,303
Rate refund	1,320,167	0	0
Total adjustments	6,206,590	6,748,113	9,114,774
Net cash provided by operating activities	13,503,795	12,980,978	14,921,640
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for utility property	(23,290,994)	(20,750,181)	(17,945,719)
Investment in unconsolidated affiliate	(11,036,247)	(2,759,346)	(3,055,746)
Proceeds from disposal of utility property	160,663	16,972	4,964
Net cash used in investing activities	(34,166,578)	(23,492,555)	(20,996,501)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under line-of-credit	29,814,468	42,569,303	38,310,326
Repayments under line-of-credit	(40,245,210)	(39,334,328)	(33,094,539)
Proceeds from issuance of unsecured notes	19,431,000	9,916,000	3,396,200
Debt issuance expenses	(32,678)	(64,835)	(101,619)
Proceeds from issuance of stock	16,520,016	967,698	1,031,194
Cash dividends paid	(4,647,042)	(4,115,873)	(3,808,683)
Net cash provided by financing activities	20,840,554	9,937,965	5,732,879
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	177,771	(573,612)	(341,982)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	69,640	643,252	985,234
CASH AND CASH EQUIVALENTS AT END OF YEAR	247,411	69,640	643,252
Cash paid (refunded) during the year for:
Interest	2,137,782	1,734,178	1,480,665
Income taxes	$ 1,180,000	$ 726,000	$ (907,000)

XML

Summary of Significant Accounting Policies

12 Months Ended

Sep. 30, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Summary of Significant Accounting Policies

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation—RGC Resources, Inc. is an energy services company primarily engaged in the sale and distribution of natural gas. The consolidated financial statements include the accounts of RGC Resources, Inc. and its wholly owned subsidiaries (“Resources” or the “Company”): Roanoke Gas Company (“Roanoke Gas”), Diversified Energy Company and RGC Midstream, LLC. Roanoke Gas is a natural gas utility, which distributes and sells natural gas to approximately 60,200 residential, commercial and industrial customers within its service areas in Roanoke, Virginia and the surrounding localities. The Company’s business is seasonal in nature as a majority of natural gas sales are for space heating during the winter season. Roanoke Gas is regulated by the Virginia State Corporation Commission (“SCC” or “Virginia Commission”). RGC Midstream, LLC is a wholly-owned subsidiary created primarily to invest in the Mountain Valley Pipeline project. Diversified Energy Company is inactive.

The Company follows accounting and reporting standards established by the Financial Accounting Standards Board (“FASB”) and the Securities and Exchange Commission (“SEC”).

Resources has only one reportable segment as defined under FASB ASC No. 280 – Segment Reporting. All intercompany transactions have been eliminated in consolidation.

Certain reclassifications have been made to the prior year income statements to be consistent with the current year presentation by moving cost of gas - utility and cost of sales - non utility under the operating expenses caption. This presentation makes the Company's income statement presentation consistent with industry peers.

On June 28, 2018, the SEC adopted amendments to the definition of a "smaller reporting company' that became effective on September 10, 2018. Under the rules for smaller reporting companies, certain disclosures required of larger public business entities are reduced or eliminated. As it has met the qualifications under the definition of smaller reporting company, the Company has used the smaller reporting company exception on a limited basis, but in most instances, disclosures have been consistent with the prior year.

Rate Regulated Basis of Accounting—The Company’s regulated operations follow the accounting and reporting requirements of FASB ASC No. 980, Regulated Operations. The economic effects of regulation can result in a regulated company deferring costs that have been or are expected to be recovered from customers in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this situation occurs, costs are deferred as assets in the consolidated balance sheet (regulatory assets) and recorded as expenses when such amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for current collection in rates of costs that are expected to be incurred in the future (regulatory liabilities). In the event the provisions of FASB ASC No. 980 no longer apply to any or all regulatory assets or liabilities, the Company would write off such amounts and include them in the consolidated statements of income and comprehensive income in the period for which FASB ASC No. 980 no longer applied.

Regulatory assets and liabilities included in the Company’s consolidated balance sheets as of September 30, 2018 and 2017 are as follows:

	September 30
	2018		2017
Regulatory Assets:
Current Assets:
Accounts receivable:
Accrued WNA revenues	$	169,602	$	248,840
Under-recovery of gas costs	922,898		—
Other:
Accrued pension and postretirement medical	293,000		658,786
Utility Property:
In service:
Other	11,945		11,945
Other Assets:
Regulatory assets:
Premium on early retirement of debt	1,826,995		1,941,182
Accrued pension and postretirement medical	5,704,718		8,643,524
Other	1,330,434		1,211,554
Total regulatory assets	$	10,259,592	$	12,715,831
Regulatory Liabilities:
Current Liabilities:
Over-recovery of gas costs	$	—	$	1,438,074
Accrued expenses:
Over-recovery of SAVE Plan revenues	670,034		215,514
Rate refund	1,320,167		—
Deferred Credits and Other Liabilities:
Asset retirement obligations	6,417,948		6,069,993
Regulatory cost of retirement obligations	11,163,981		10,055,189
Regulatory liability - deferred income taxes	11,447,736		—
Total regulatory liabilities	$	31,019,866	$	17,778,770

As of September 30, 2018, the Company had regulatory assets in the amount of $10,247,647 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 Plant and Depreciation—Utility plant is stated at original cost and includes direct labor and materials, contractor costs, and all allocable overhead charges. The Company applies the group method of accounting, where the costs of like assets are aggregated and depreciated by applying a rate based on the average expected useful life of the assets. In accordance with Company policy, expenditures for depreciable assets with a life greater than one year are capitalized, along with any upgrades or improvements to existing assets, when they significantly improve or extend the original expected useful life of an asset. Expenditures for maintenance, repairs, and minor renewals and betterments are expensed as incurred. The original cost of depreciable property retired is removed from utility plant and charged to accumulated depreciation. The cost of asset removals, less salvage, is charged to “regulatory cost of retirement obligations” or “asset retirement obligations” as explained under Asset Retirement Obligations below.

Utility plant is composed of the following major classes of assets:

	Years Ended September 30
	2018		2017
Distribution and transmission	$	196,778,546	$	177,845,619
LNG storage	13,413,175		13,299,288
General and miscellaneous	14,662,599		13,078,807
Total utility plant in service	$	224,854,320	$	204,223,714

Provisions for depreciation are computed principally at composite straight-line rates over periods ranging from 5 to 76 years. 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 in June 2014 and will be required to complete a new depreciation study in fiscal 2019. The composite weighted-average depreciation rate realized using the most recently completed depreciation study was 3.32%, 3.29% and 3.25% for fiscal years ended September 30, 2018, 2017 and 2016.

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. 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.

Asset Retirement Obligations—FASB ASC No. 410, Asset Retirement and Environmental Obligations, requires entities to record the fair value of a liability for an asset retirement obligation when there exists a legal obligation for the retirement of the asset. When the liability is initially recorded, the entity capitalizes the cost, thereby increasing the carrying amount of the underlying asset. In subsequent periods, the liability is accreted, and the capitalized cost is depreciated over the useful life of the underlying asset. The Company has recorded asset retirement obligations for its future legal obligations related to purging and capping its distribution mains and services upon retirement, although the timing of such retirements is uncertain.

The Company’s composite depreciation rates include a component to provide for the cost of retirement of assets. As a result, the Company accrues the estimated cost of retirement of its utility plant through depreciation expense and creates a corresponding regulatory liability. The costs of retirement considered in the development of the depreciation component include those costs associated with the legal liability. Therefore, the asset retirement obligation 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, the Company increased its asset retirement obligation to reflect revisions to the estimated cash flows for asset retirements.

The following is a summary of the asset retirement obligation:

	Years Ended September 30
	2018			2017
Beginning balance	$	6,069,993		$	5,682,556
Liabilities incurred	79,608			65,556
Liabilities settled	(126,907		)	(137,304		)
Accretion	332,537			312,503
Revisions to estimated cash flows	62,717			146,682
Ending balance	$	6,417,948		$	6,069,993

Cash, Cash Equivalents and Short-Term Investments—From time to time, the Company will have balances on deposit at banks in excess of the amount insured by the Federal Deposit Insurance Corporation (“FDIC”). The Company has not experienced any losses on these accounts and does not consider these amounts to be at credit risk. As of September 30, 2018, the Company did not have any bank deposits in excess of the FDIC insurance limits. For purposes of the consolidated statements of cash flows, the Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents.

Customer Receivables and Allowance for Doubtful Accounts—Accounts receivable include amounts billed to customers for natural gas sales and related services and gas sales occurring subsequent to normal billing cycles but before the end of the period. The Company provides an estimate for losses on these receivables by utilizing historical information, current account balances, account aging and current economic conditions. Customer accounts are charged off annually when deemed uncollectible or when turned over to a collection agency for action.

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

	Years Ended September 30
	2018			2017			2016
Beginning balance	$	99,456		$	76,934		$	52,721
Provision for doubtful accounts	169,096			84,587			14,074
Recoveries of accounts written off	78,919			110,725			137,055
Accounts written off	(243,898		)	(172,790		)	(126,916		)
Ending balance	$	103,573		$	99,456		$	76,934

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

Inventories—Natural gas in storage and materials and supplies inventories are recorded at average cost. Natural gas storage injections are priced at the purchase cost at the time of injection and storage withdrawals are priced at the weighted average cost of gas in storage. Materials and supplies are removed from inventory at average cost.

Unbilled Revenues—The Company bills its natural gas customers on a monthly cycle; however, the billing cycle period for most customers does not coincide with the accounting periods used for financial reporting. As the Company recognizes revenue when gas is delivered, an accrual is made to estimate revenues for natural gas delivered to customers but not billed during the accounting period. The amounts of unbilled revenue receivable included in accounts receivable on the consolidated balance sheets at September 30, 2018 and 2017 were $911,657 and $965,683, respectively.

Income Taxes—Income taxes are accounted for using the asset and liability method. Under the asset and liability method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the years in which those temporary differences are expected to be recovered or settled. A valuation allowance against deferred tax assets is provided if it is more likely than not the deferred tax asset will not be realized. The Company and its subsidiaries file 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’s Purchased Gas Adjustment (“PGA”) clause, the SCC provides the Company with a method of passing along to its customers increases or decreases in natural gas costs incurred by its regulated operations, including gains and losses on natural gas derivative hedging instruments. On a quarterly basis, the Company files a PGA rate adjustment request with the SCC to increase or decrease the gas cost component of its rates, based on projected price and activity. Once administrative approval is received, the Company adjusts the gas cost component of its rates to reflect the approved amount. As actual costs will differ from the projections used in establishing the PGA rate, the Company may either over-recover or under-recover its actual gas costs during the period. Any difference between actual costs incurred and costs recovered through the application of the PGA is recorded as a regulatory asset or liability. At the end of the deferral period, the balance of the net deferred charge or credit is amortized over an ensuing 12-month period as amounts are reflected in customer billings.

Fair Value—Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The Company determines fair value based on the following fair value hierarchy which prioritizes each input to the valuation methods into one of the following three broad levels:

• Level 1 – Unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date.

• Level 2 – Inputs other than quoted prices in Level 1 that are either for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability, or inputs that are derived principally from or corroborated by observable market data by correlation or other means.

• Level 3 – Unobservable inputs for the asset or liability where there is little, if any, market activity which require the Company to develop its own assumptions.

The fair value hierarchy gives the highest priority to unadjusted quoted prices in active markets (Level 1) and the lowest priority to unobservable inputs (Level 3). All fair value disclosures are categorized within one of the three categories in the hierarchy. See fair value disclosures below and in Notes 8 and 12.

Use of Estimates—The preparation of financial statements in conformity with Generally Accepted Accounting Principles in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Excise and Sales Taxes—Certain excise and sales taxes imposed by the state and local governments in the Company’s service territory are collected by the Company from its customers. These taxes are accounted for on a net basis and therefore are not included as revenues in the Company’s Consolidated Statements of Income.

Earnings Per Share—Basic earnings per share and diluted earnings per share 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 share is presented below:

	Years Ended September 30
	2018		2017		2016
Net Income	$	7,297,205	$	6,232,865	$	5,806,866
Weighted-average common shares	7,649,025		7,218,686		7,149,906
Effect of dilutive securities:
Options to purchase common stock	46,687		37,360		9,857
Diluted average common shares	7,695,712		7,256,046		7,159,763
Earnings Per Share of Common Stock:
Basic	$	0.95	$	0.86	$	0.81
Diluted	$	0.95	$	0.86	$	0.81

Business and Credit Concentrations—The primary business of the Company is the distribution of natural gas to residential, commercial and industrial customers in its service territories.

No sales to individual customers accounted for more than 5% of total revenue in any period or amounted to more than 5% of total accounts receivable.

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

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

Derivative and Hedging Activities—FASB ASC No. 815, Derivatives and Hedging, requires the recognition of all derivative instruments as assets or liabilities in the Company’s balance sheet and measurement of those instruments at fair value.

The Company’s hedging and derivatives policy allows management to enter into derivatives for the purpose of managing the commodity and financial market risks of its business operations. The Company’s hedging and derivatives policy specifically prohibits the use of derivatives for speculative purposes. The key market risks that RGC Resources, Inc. 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 balance sheet with the offsetting entry to either under-recovery of gas costs 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, 2018 and 2017, the Company had no outstanding derivative instruments for the purchase of natural gas.

The Company has one interest rate swap associated with its $7,000,000 term note as discussed in Note 6. Effective November 1, 2017, the swap agreement converted the floating rate note based on LIBOR into a fixed rate debt with a 2.30% effective interest rate. The swap qualifies as a cash flow hedge with changes in fair value reported in other comprehensive income. No portion of the swap was deemed ineffective during the period.

The table below reflects the fair value of the derivative instrument and its corresponding classification in the consolidated balance sheets.

	September 30
	2018		2017
Derivatives designated as hedging instruments:
Current assets:
Interest rate swap	$	100,723	$	26,777
Other assets:
Interest rate swap	$	209,840	$	90,066
Total derivatives designated as hedging instruments	$	310,563	$	116,843

The fair value of the interest rate swap is determined by using the counter party's proprietary models and certain assumptions regarding past, present and future market conditions. See Note 12 for additional information on fair value.

Non-Cash Activity — A non-cash increase in investment in unconsolidated affiliate and corresponding increase in capital contributions payable of $9,087,262 and $767,710 occurred for the fiscal years ended September 30, 2018 and 2017, 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, 2018:
Interest rate swap:
Unrealized gains	$	217,773		$	(62,807	)	$	154,966
Transfer of realized gains to interest expense	(24,053		)	6,937			(17,116		)
Net interest rate swap	193,720			(55,870		)	137,850
Defined benefit plans:
Net gain arising during period	$	595,570		$	(171,775	)	$	423,795
Amortization of actuarial gains	(23,887		)	6,890			(16,997		)
Net defined benefit plans	571,683			(164,885		)	406,798
Other comprehensive income	$	765,403		$	(220,755	)	$	544,648
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	)

The amortization of actuarial gains or losses are included as a component of net periodic pension and postretirement benefit costs 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, 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		)
Other comprehensive income (loss)	137,850		406,798			544,648
Reclassification adjustment for the effect of change in tax law	20,285		(234,337		)	(214,052		)
Balance September 30, 2018	$	230,624	$	(1,102,292	)	$	(871,668	)

The reclassification related to the interest rate swap was charged to regulatory liability - deferred taxes to offset the adjustment made when revaluing the deferred tax liability of the interest rate swap for the reduction in corporate income tax rates. See recently adopted accounting standards for more information on the reclassification from accumulated other comprehensive income.

Recently Adopted Accounting Standards

In March 2016, the FASB issued ASU 2016-09, Compensation - Stock Compensation: Improvements to Employee Share-Based Payment Accounting. The guidance simplifies several aspects of the accounting for share-based payment award transactions, including income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. The new guidance is effective for the Company for the annual reporting period ending September 30, 2018 and interim periods within that annual period. Early adoption is permitted. The Company adopted this ASU for the quarter ended September 30, 2016. Under the prior guidance, excess tax benefits were to be tracked in an APIC pool and not recognized in the income statement. Tax deficiencies were netted against the accumulated APIC pool and only recognized in the income statement starting at the time tax deficiencies exceeded the pool. Under ASU 2016-09, the APIC pool is eliminated with all excess tax benefits and deficiencies recognized in income tax expense on the income statement. Prior to the adoption of this ASU, stock option activity did not result in the accumulation of an APIC pool; therefore, adopting the ASU had minimal impact on the Company’s current financial position, results of operations or cash flows and no impact on prior results.

In January 2017, the FASB issued ASU 2017-03, Accounting Changes and Error Corrections and Investments - Equity Method and Joint Ventures. This update adds the text of the SEC Staff Announcement, Disclosure of the Impact That Recently Issued Accounting Standards Will Have on the Financial Statements of a Registrant When Such Standards Are Adopted in a Future Period (in accordance with Staff Accounting Bulletin Topic 11.M) as paragraph 250-10-S99-6. Related specifically to ASU 2014-09, ASU 2016-02 and ASU 2016-13, an SEC registrant should evaluate ASUs that have not yet been adopted to determine and include appropriate financial disclosures and MD&A discussions, including consideration of additional qualitative disclosures, to assist financial statement readers in assessing the significance of impact on adoption. The new guidance is effective immediately. The nature of this guidance relates to the effectiveness and quality of disclosures related to ASUs not yet adopted; however, there is no effect on the Company's financial position, results of operations or cash flows.

In February 2018, the FASB issued ASU 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220) - Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. The ASU provides the option to reclassify stranded tax effects within Accumulated Other Comprehensive Income ("AOCI") to retained earnings in each period in which the effects of the change in the U.S. federal corporate income tax rate, per the Tax Cuts and Jobs Act, is recorded. The new guidance is effective for the Company for the annual reporting period ending September 30, 2020 and interim periods within that annual period. Early adoption is permitted. Management completed its evaluation and adopted the new guidance in the fourth quarter of fiscal 2018. As a result, the Company reclassified $234,337 in stranded tax expense out of AOCI to retained earnings related to pension and postretirement plans for the unregulated operations of Resources. In addition, the Company also reclassified $20,285 out of AOCI to the regulatory liability for the stranded tax expense related to the interest rate swap. See the Other Comprehensive Income section above and Note 3 below for more information.

Recently Issued Accounting Standards

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) that affects any entity that enters into contracts with customers for the transfer of goods or services or transfer of non-financial assets. This guidance supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. The core principle of the new guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve that core principle, an entity should apply the following steps: (1) identify the contract with the customer, (2) identify the performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to the performance obligations in the contract, and (5) recognize revenue when, or as, the entity satisfies the performance obligation. In August 2015, the FASB issued ASU 2015-14 that deferred the effective date of this guidance by one year making the standard effective for the Company's annual reporting period ending September 30, 2019 and interim periods within that annual period. Subsequent ASUs have been issued, which provide additional guidance to assist in the implementation of the new revenue standard. Based on the evaluation of the ASU, management has determined that the adoption of the new standard will not have a material impact on the Company's financial position, results of operations or cash flows. However, significant new disclosures will be required as a result of the guidance. The Company is completing the review and updating of its disclosures and will reflect the changes with the adoption of the standard in the first quarter of fiscal 2019 using the modified retrospective approach.

In January 2016, the FASB issued ASU 2016-01, Financial Instruments - Overall: Recognition and Measurement of Financial Assets and Financial Liabilities. The ASU enhances the reporting model for financial instruments to provide users of the financial statements with more useful information through several provisions, including the following: (1) requires equity investments, excluding investments accounted for under the equity method, be measured at fair value with changes in fair value recognized in net income, (2) simplifies the impairment assessment of equity investments without readily determinable fair values, (3) eliminates the requirement to disclose the method(s) and significant assumptions used to estimate the fair value that is required to be disclosed for financial instruments measured at amortized cost on the balance sheet, (4) requires entities to use the exit price notion when measuring the fair value of financial instruments for disclosure purposes, and (5) requires separate presentation of financial assets and financial liabilities by measurement category and form of financial asset on the balance sheet or the accompanying notes to the financial statements. The new guidance is effective for the Company for the annual reporting period ending September 30, 2019 and interim periods within that annual period. Management is in the process of completing its evaluation of the standard, but does not anticipate the new guidance to have a material effect on its financial position, results of operations or cash flows.

In February 2016, the FASB issued ASU 2016-02, Leases. The ASU leaves the accounting for leases mostly unchanged for lessors, with the exception of targeted improvements for consistency; however, the new guidance requires lessees to recognize assets and liabilities for leases with terms of more than 12 months. The ASU also revises the definition of a lease as a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment for a period of time in exchange for consideration. Consistent with current GAAP, the presentation and cash flows arising from a lease by a lessee will primarily depend on its classification as a finance or operating lease. In contrast, the new ASU requires both types of leases to be recognized on the balance sheet. In addition, the new guidance includes quantitative and qualitative disclosure requirements to aid financial statement users in better understanding the amount, timing and uncertainty of cash flows arising from leases. The new guidance is effective for the Company for the annual reporting period ending September 30, 2020 and interim periods within that annual period. Early adoption is permitted. The Company has completed its inventory of leases and does not currently expect the new guidance to have a material effect on its financial position, results of operations or cash flows.

In March 2017, the FASB issued ASU 2017-07, Compensation - Retirement Benefits. The primary objective of this guidance is to improve the financial statement presentation of net periodic pension and postretirement benefit costs; however, it also changes which cost components are eligible for capitalization. The amendments in the ASU require that an employer report the service cost component in the same line item or items as other compensation costs arising from services rendered by the employees during the period. The other components of net benefit cost are required to be presented in the income statement separately from the service cost component and, if a subtotal for income from operations is presented, outside of income from operations. In addition, the ASU allows only the service cost component of periodic benefit cost to be eligible for capitalization when applicable. This change to capitalization eligibility differs from the treatment currently applied by the Company and from allowed regulatory accounting. The new guidance is effective for the Company for the annual reporting period ending September 30, 2019 and interim periods within that annual period. Early adoption is permitted. Management has had discussions with its state regulators regarding the adoption of this ASU for regulatory purposes. The regulatory body has not taken a position on the change in capitalization requirements for these benefit costs and will evaluate the impact of this ASU on a case by case basis. The Company intends to adopt this ASU effective October 1, 2018 with the change in expense classification on a retrospective basis and the change in capitalization of costs on a prospective basis. If the regulatory body ultimately determines that changes to the capitalization of these retirement benefits is not appropriate for regulatory purposes, the Company may have to establish regulatory assets or liabilities for those costs or benefits excluded from capitalization under this ASU. Management does not expect the new guidance to have a material effect on the Company's consolidated financial statements.

In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging: Targeted Improvements to Accounting For Hedging Activities. The ASU is meant to simplify recognition and presentation guidance in an effort to improve financial reporting of cash flow and fair value hedging relationships to better portray the economic results of an entity's risk management activities. This is achieved through changes to both the designation and measurement guidance for qualifying hedging relationships, as well as changes to the presentation of hedge results. The new guidance is effective for the Company for the annual reporting period ending September 30, 2020 and interim periods within that annual period. Early adoption is permitted. Management has not completed its evaluation of the new guidance; however, it does not currently expect the new guidance to have a material effect on its financial position, results of operations or cash flows.

In August 2018, the FASB issued ASU 2018-14, Compensation - Retirement Benefits - Defined Benefit Plans - General (Subtopic 715-20) - Disclosure Framework - Changes to the Disclosure Requirements for Defined Benefit Plans. This ASU modifies disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The new guidance is effective for the Company for the annual reporting period ending September 30, 2021. Early adoption is permitted. Management has not completed its evaluation of the new guidance; however, the ASU only modifies disclosure requirements and will not effect financial position, results of operations or cash flows.

In August 2018, the FASB issued ASU 2018-15, Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer's Accounting for Implementation Costs incurred in a Cloud Computing Arrangement that is a Service Contract. This ASU reduces the complexity of accounting for costs of implementing a cloud computing service arrangement and aligns the following requirements to capitalize implementation costs: 1) those incurred in a hosting arrangement that is a service contract, and 2) those incurred to develop or obtain internal-use software, including hosting arrangements that include an internal software license. The new guidance is effective for the Company for the annual reporting period beginning October 1, 2020. Management has not completed its evaluation of the new guidance; however, it believes the new guidance will change the future treatment of certain contracts by allowing related implementation costs to be capitalized and amortized over time, rather than directly expensed. Management does not currently expect the new guidance to have a material effect on its financial position, results of operations or 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.

XML

Stock Issue

12 Months Ended

Sep. 30, 2018

Equity [Abstract]

Stock Issue

STOCK ISSUE

In March 2018, the Company issued 700,000 shares of common stock resulting in proceeds of $15,109,541 net of underwriting and other expenses. The Company issued the common shares to strengthen its balance sheet by increasing the equity component of its total capitalization ratio. The net proceeds were invested in Roanoke Gas to supplement the funding of its infrastructure improvement and replacement programs.

XML

Regulatory Matters

12 Months Ended

Sep. 30, 2018

Regulated Operations [Abstract]

Regulatory Matters

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.

On October 10, 2018, Roanoke Gas filed a general rate case application requesting an increase in annual customer non-gas rates of $10.5 million. This increase incorporates into the non-gas rate the impact of recent tax reform, non-SAVE utility plant investment, increased operating costs and approximately $4.7 million in SAVE plan ("Steps to Advance Virginia's Energy") revenues that are currently being billed through the SAVE rider. The new non-gas rates will be placed in effect for service rendered on or after January 1, 2019, subject to refund pending a final order by the SCC. The last non-gas rate increase was filed in 2013 with rates effective November 1, 2013.

On June 29, 2018, the Company filed with the SCC its most recent SAVE 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 on a prospective basis 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 refunding the over-collection of revenues under the 2017 SAVE Plan and proposed new 2019 SAVE rates to be implemented for the investment in 2019 SAVE Plan projects. With the filing of the application for the general rate case, all SAVE Plan revenues related to SAVE projects completed or in process through December 2018 will be incorporated into the new non-gas rates effective January 1, 2019. Accordingly, the SAVE Plan rider will reset beginning January 1, 2019 and will relate only to SAVE projects and expenditures incurred on and after this date. On September 27, 2018, the SCC issued their order approving the new 2019 SAVE rider, which is expected to provide approximately $362,000 in revenue. The SCC also approved the True-up factor to provide for the refund of approximately $163,000 in over-collected balance from the 2017 SAVE Plan.

As discussed in Note 7, the Tax Cut and Jobs Act ("TCJA") provided for a reduction in the federal corporate income tax rate to 21%. The Company revalued its deferred tax assets and liabilities to reflect the new federal tax rate. Under the provisions of ASC 740, the corresponding adjustment to deferred income taxes generally flows through to income tax expense. For rate regulated entities such as Roanoke Gas, these excess deferred income taxes were originally recovered from its customers based on billing rates derived using a federal income tax rate of 34%. Therefore, the adjustment to the net deferred tax liability of Roanoke Gas, to the extent such net deferred tax liabilities are attributable to rate base or cost of service for customers, are refundable to or collectible from customers. As of September 30, 2018, Roanoke Gas has a net deferred tax regulatory liability in the amount of approximately $11.4 million composed of $12.7 million related to excess tax depreciation that will be refunded back to customers over 28 years using the Reverse South Georgia method and $1.3 million in net deferred tax assets that will be collected from customers over a period yet to be determined.

With the implementation of the TCJA, the change in federal income tax rates occurred during the Company's fiscal year resulting in the use of a 24.3% blended rate for fiscal 2018 and a conversion to the 21% in fiscal 2019. On January 8, 2018, the SCC issued a directive requiring the accrual of a regulatory liability for excess revenues collected from customers attributable to the higher federal income tax rate, currently included as a component of customer billing rates, until such time as the SCC approves revised billing rates incorporating the lower tax rate. For the year ended September 30, 2018, Roanoke Gas has recorded a reduction to revenue and established a regulatory liability in the amount of $1,320,167 related to the excess revenues collected from customers during the year. The reduction in excess revenues corresponds with a similar reduction in corporate income tax expense for the regulated operations of Roanoke Gas. The excess revenues related to the SAVE Plan and inventory carrying cost have already been reflected separately from the refund liability. The actual refund will not be finalized until the SCC completes their review and makes any adjustments to the Company's calculations.

XML

Other Investments

12 Months Ended

Sep. 30, 2018

Other Investments [Abstract]

Other Investments

OTHER INVESTMENTS

In October 2015, the Company, through its wholly-owned subsidiary, RGC Midstream, LLC ("Midstream"), acquired a 1% equity interest in the Mountain Valley Pipeline, LLC (the “LLC”). The LLC was established to construct and operate a natural gas pipeline originating in northern West Virginia and extending through south central Virginia. The proposed pipeline will have the capacity to transport approximately 2 million decatherms of natural gas per day.

The estimated total project cost has increased from $3.7 billion to $4.6 billion, thereby increasing Midstream's estimated total contributions to approximately $46 million. This increase is due to delays in construction resulting from judicial and regulatory actions. Primarily, these actions relate to the adequacy of reviews performed by various permit-granting agencies related to the construction of the pipeline under waterways and through the Jefferson National Forest. The pipeline is under construction as it had received Federal Energy Regulatory Commission ("FERC") approval as well as the necessary federal and state permits; however, several recent FERC and Fourth Circuit Court rulings have led to work stoppages and imposed construction limitations. As a result, construction progress has slowed significantly and delayed the projected in-service date to the end of calendar 2019.

In April 2018, the LLC announced the MVP Southgate project ("Southgate"), which is a planned 70 mile pipeline extending from the Mountain Valley Pipeline mainline in Virginia to delivery points in North Carolina. Midstream is a less than 1% investor in this project, which will be accounted for under the cost method. Total estimated project cost is between $350 and $500 million of which Midstream's portion will be approximately $1.8 to $2.5 million. The Southgate in-service date is currently targeted for the end of calendar 2020.

Midstream held an approximate $28.5 million investment in the LLC and Southgate project at September 30, 2018. Initial funding for Midstream's investment is provided through two unsecured Promissory Notes, each with a 5-year term, as further described in Note 6 below.

The Company will participate in the earnings generated from the transportation of natural gas through both pipelines proportionate to its level of investment once the pipelines are placed in service.

The financial statement locations of the investments by Midstream are as follows:

	September 30
Balance Sheet Location of Other Investments:	2018		2017
Other Assets:
Investment in unconsolidated affiliate	$	28,507,146	$	7,445,106
Current Liabilities:
Capital contributions payable	$	10,142,766	$	1,055,504
	For the Years ended September 30
Income Statement Location of Other Investments:	2018		2017		2016
Equity in earnings of unconsolidated affiliate	$	938,531	$	421,646	$	152,864

The change in the investment in unconsolidated affiliate are provided below:

	For the Years ended September 30,
	2018		2017		2016
Cash investment	$	11,036,247	$	2,759,346	$	3,055,746
Change in accrued capital calls	9,087,262		767,710		287,794
Equity in earnings of unconsolidated affiliate	938,531		421,646		152,864
Change in investment in unconsolidated affiliate	$	21,062,040	$	3,948,702	$	3,496,404

XML

Line-of-Credit

12 Months Ended

Sep. 30, 2018

Debt Disclosure [Abstract]

Line-of-Credit

LINE-OF-CREDIT

On March 26, 2018, Roanoke Gas entered into a new unsecured line-of-credit agreement. This line-of-credit agreement replaced the agreement scheduled to expire on March 31, 2019. The new agreement is for a 2-year term expiring March 31, 2020 with a maximum borrowing limit of $25,000,000. 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.

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 as the previous agreement. The new agreement also maintains the multi-tiered borrowing limits to accommodate seasonal borrowing demands and minimize borrowing costs. Available limits under this agreement for the remaining term are as follows:

As of	Available Line-of-Credit
September 30, 2018	$	20,000,000
November 21, 2018	21,000,000
March 1, 2019	17,000,000
July 22, 2019	22,000,000
September 22, 2019	25,000,000
March 1, 2020	22,000,000

A summary of the line-of-credit follows:

	September 30
	2018			2017			2016
Available line-of-credit at year-end	$	20,000,000		$	21,000,000		$	24,000,000
Outstanding balance at year-end	7,361,017			17,791,760			14,556,785
Highest month-end balance outstanding	17,054,377			17,791,760			15,246,089
Average daily balance	6,730,334			10,936,114			9,620,914
Average rate of interest during year on outstanding balances	2.53		%	1.92		%	1.40		%
Interest rate at year-end	3.26		%	2.23		%	1.53		%
Interest rate on unused line-of-credit	0.15		%	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%.

XML

Long-Term Debt

12 Months Ended

Sep. 30, 2018

Debt Disclosure [Abstract]

Long-Term Debt

LONG-TERM DEBT

On October 2, 2017, the Company issued 10-year unsecured notes in the principal amount of $8,000,000 with a fixed interest rate of 3.58% per annum. The proceeds from the notes were used to refinance a portion of the Company's line-of-credit balance into longer-term financing.

Roanoke Gas has a 5-year unsecured variable rate note in the principal amount of $7,000,000 and an interest rate swap agreement, which converts the variable rate debt into a fixed-rate instrument with an annual interest rate of 2.30%. The swap agreement became effective on November 1, 2017 and will continue through the duration of the note.

Midstream has two5-year unsecured Promissory Notes ("Notes") which provide financing for capital investment in its 1% interest in the LLC. In April 2018, the Notes and corresponding credit agreement were amended to increase the total borrowing limits to $38 million and reduce the variable interest rate to 30-day LIBOR plus 135 basis points. Furthermore, the amended credit agreement removed the requirement for Midstream to provide $5 million in funding outside of the Notes.

Long-term debt consists of the following:

	September 30
	2018				2017
	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	$	154,465	$	30,500,000	$	164,119
Unsecured term note payable, at 30-day LIBOR plus 0.90%, November 1, 2021	7,000,000		10,283		7,000,000		13,618
Unsecured term notes payable, at 3.58% due on October 2, 2027	8,000,000		43,343		—		48,160
RGC Midstream, LLC:
Unsecured term notes payable, at 30-day LIBOR plus 1.35% due December 29, 2020	$	17,743,200	$	74,190	$	6,312,200	$	66,052
Total notes payable	$	63,243,200	$	282,281	$	43,812,200	$	291,949
Line-of-credit, at 30-day LIBOR plus 1.00%, due March 31, 2020	7,361,017		—		17,791,760		—
Total long-term debt	$	70,604,217	$	282,281	$	61,603,960	$	291,949

Debt issuance costs are amortized over the life of the related debt. As of September 30, 2018 and 2017, the Company also had an unamortized loss on the early retirement of debt of $1,826,995 and $1,941,182, 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 requires the ratio of long-term debt to long-term capitalization to not exceed 65%. 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, 2018 are as follows:

Year Ending September 30	Maturities
2019	$	—
2020	7,361,017
2021	17,743,200
2022	7,000,000
2023	—
Thereafter	38,500,000
Total	$	70,604,217

XML

Income Taxes

12 Months Ended

Sep. 30, 2018

Income Tax Disclosure [Abstract]

Income Taxes

INCOME TAXES

On December 22, 2017, the President signed into law the TCJA, which enacted significant changes to the Internal Revenue Code, including the reduction in the maximum federal corporate income tax rate from 35% to 21% effective January 1, 2018. As the Company is a fiscal year taxpayer, the Company applied a blended federal tax rate of 24.3% for the fiscal year ended September 30, 2018 as determined on the number of days of the Company's fiscal year at 34% and the number of days at 21%.

Under the provisions of ASC 740 - Income Taxes, the deferred tax assets and liabilities of the Company must be revalued to reflect the reduction in the corporate federal income tax rate. The result of this revaluation was a reduction in the net deferred tax liability of approximately $9 million, including approximately $11.8 million reclassified to regulatory liability, a $3 million gross up to reflect pre-tax basis, and $0.26 million increase in income tax expense related to unregulated operations. The excess deferred income taxes are reflected on a pretax basis to appropriately contemplate future tax consequences in the periods when the regulatory liability is settled. Approximately $13.1 million of the excess deferred taxes related to certain depreciable property that must be returned to customers subject to normalization requirements. The excess deferred taxes related to the depreciable property will be returned to customers over the remaining weighted average useful life of the property using the Reverse South Georgia method beginning January 2018. The remaining balance in the regulatory liability relates to approximately $1.3 million in deferred tax assets that will be collected from customers over a yet to be determined period.

The details of income tax expense are as follows:

	Years Ended September 30
	2018		2017		2016
Current income taxes:
Federal	$	1,831,085	$	72,368	$	(1,216,745	)
State	308,057		407,643		415,975
Total current income taxes	2,139,142		480,011		(800,770		)
Deferred income taxes:
Federal	440,282		3,129,925		4,302,906
State	315,712		195,454		164,048
Total deferred income taxes	755,994		3,325,379		4,466,954
Total income tax expense	$	2,895,136	$	3,805,390	$	3,666,184

Income tax expense for the years ended September 30, 2018, 2017 and 2016 differed from amounts computed by applying the U.S. federal income tax rate to earnings before income taxes due to the following:

	Years Ended September 30
	2018			2017			2016
Income before income taxes	$	10,192,341		$	10,038,255		$	9,473,050
Corporate federal income tax rate	24.3		%	34.0		%	34.0		%
Income tax expense computed at the federal statutory rate	$	2,476,739		$	3,413,007		$	3,220,837
State income taxes, net of federal income tax benefit	472,193			398,044			382,815
Revaluation of unregulated deferred taxes to 21%	256,444			—			—
Net amortization of excess deferred taxes on regulated operations	(264,106		)	—			—
Other, net	(46,134		)	(5,661		)	62,532
Total income tax expense	$	2,895,136		$	3,805,390		$	3,666,184

The tax effects of temporary differences that give rise to the deferred tax assets and deferred tax liabilities are as follows:

	September 30
	2018		2017
Deferred tax assets:
Allowance for uncollectibles	$	26,658	$	37,752
Accrued pension and postretirement medical benefits	897,834		1,747,429
Regulatory effect of change in federal income tax rate	2,946,649		—
Accrued vacation	160,001		239,414
Over-recovery of gas costs	—		545,894
Costs of gas held in storage	591,899		1,009,206
Deferred compensation	716,843		824,281
Rate refund	339,812		—
Other	298,129		348,833
Total gross deferred tax assets	5,977,825		4,752,809
Deferred tax liabilities:
Utility plant	17,982,215		27,630,486
Under-recovery of gas costs	255,570		—
MVP investment	245,678		154,817
Other	79,939		44,354
Total gross deferred tax liabilities	18,563,402		27,829,657
Net deferred tax liability	$	12,585,577	$	23,076,848

The current federal 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 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.

Under the PATH Act, 50% bonus depreciation extended through December 31, 2017, with 40% for calendar 2018 and 30% for calendar 2019 with no provision for bonus depreciation after 2019. Effective with the TCJA, utilities are no longer eligible to take bonus depreciation.

FASB ASC No. 740 - Income Taxes provides for the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recognized in the financial statements. The Company has evaluated its tax positions and accordingly has not identified any significant uncertain tax positions. The Company’s policy is to classify interest associated with uncertain tax positions as interest expense in the financial statements. Penalties are classified under other expense.

The Company files a consolidated federal income tax return and state income tax returns in Virginia and West Virginia. The federal returns and the state returns for both Virginia and West Virginia for the tax years ended prior to September 30, 2015 are no longer subject to examination.

XML

Employee Benefit Plans

12 Months Ended

Sep. 30, 2018

Retirement Benefits [Abstract]

Employee Benefit Plans

EMPLOYEE BENEFIT PLANS

The Company sponsors both a noncontributory defined benefit pension plan ("pension plan") and a postretirement benefit plan ("postretirement plan"). The pension plan covers substantially all employees and benefits fully vest after 5 years of credited service. Benefits paid to retirees are based on age at retirement, years of service and average compensation. Effective January 1, 2017, a "soft freeze" to the pension plan was implemented, and employees hired on or after that date are no longer eligible to participate. Employees hired prior to January 1, 2017 will continue to participate in the plan and accrue benefits. Commensurate with the "soft freeze" in the pension plan, the Company amended its 401(k) Plan, allowing management to authorize a discretionary contribution to the 401(k) account for those employees hired on or after January 1, 2017. The amount, if any, of this discretionary contribution would be determined each year and would be applied to the eligible employees at the end of the calendar year. This Company contribution would be in addition to any employee elected deferrals and employer match as provided for under the 401(k) Plan.

The postretirement 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 benefit 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 in 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 set forth the benefit obligation, fair value of plan assets, the funded status of the benefit plans, amounts recognized in the Company’s financial statements and the assumptions used.

	Pension Plan						Postretirement Plan
	2018			2017			2018			2017
Accumulated benefit obligation	$	25,199,762		$	25,481,993		$	16,207,322		$	17,666,812
Change in benefit obligation:
Benefit obligation at beginning of year	$	29,657,347		$	29,494,950		$	17,666,812		$	18,504,710
Service cost	665,235			706,677			167,220			183,267
Interest cost	1,088,180			995,598			640,602			626,822
Actuarial gain	(1,727,767		)	(824,361		)	(1,774,320		)	(1,199,722		)
Benefit payments, net of retiree contributions	(832,696		)	(715,517		)	(492,992		)	(448,265		)
Benefit obligation at end of year	$	28,850,299		$	29,657,347		$	16,207,322		$	17,666,812
Change in fair value of plan assets:
Fair value of plan assets at beginning of year	$	26,418,671		$	23,113,057		$	12,691,162		$	11,122,783
Actual return on plan assets, net of taxes	1,798,722			3,021,131			426,787			1,016,644
Employer contributions	800,000			1,000,000			300,000			1,000,000
Benefit payments, net of retiree contributions	(832,696		)	(715,517		)	(492,992		)	(448,265		)
Fair value of plan assets at end of year	$	28,184,697		$	26,418,671		$	12,924,957		$	12,691,162
Funded status	$	(665,602	)	$	(3,238,676	)	$	(3,282,365	)	$	(4,975,650	)
Amounts recognized in the balance sheet consist of:
Noncurrent liabilities	$	(665,602	)	$	(3,238,676	)	$	(3,282,365	)	$	(4,975,650	)
Amounts recognized in accumulated other comprehensive loss:
Net actuarial loss, net of tax	$	361,215		$	572,740		$	741,077		$	702,013
Total amounts included in other comprehensive loss, net of tax	$	361,215		$	572,740		$	741,077		$	702,013
Amounts deferred to a regulatory asset:
Net actuarial loss	$	3,894,221		$	5,471,547		$	2,103,497		$	3,830,763
Amounts recognized as regulatory assets	$	3,894,221		$	5,471,547		$	2,103,497		$	3,830,763

The Company expects that approximately $10,000 before tax, of accumulated other comprehensive income will be recognized as a reduction in net periodic benefit costs in fiscal 2019 and approximately $293,000 of amounts deferred as regulatory assets will be amortized and recognized in net periodic benefit costs in fiscal 2019.

The following table details the actuarial assumptions used in determining the projected benefit obligations and net benefit cost of the pension and the accumulated benefit obligations and net benefit cost of the postretirement plan for 2018, 2017 and 2016.

	Pension Plan						Postretirement Plan
	2018		2017		2016		2018		2017		2016
Assumptions used to determine benefit obligations:
Discount rate	4.11	%	3.72	%	3.42	%	4.09	%	3.69	%	3.33	%
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	3.72	%	3.42	%	4.22	%	3.69	%	3.33	%	4.15	%
Expected long-term rate of return on plan assets	7.00	%	7.00	%	7.00	%	4.84	%	4.84	%	4.89	%
Expected rate of compensation increase	4.00	%	4.00	%	4.00	%	N/A		N/A		N/A

To develop the expected long-term rate of return on assets assumption, the Company, with input from the plans' actuaries and investment advisors, considered the historical returns and the future expectations for returns for each asset class, as well as the target asset allocation of each plan’s portfolio.

Components of net periodic benefit cost are as follows:

	Pension Plan									Postretirement Plan
	2018			2017			2016			2018			2017			2016
Service cost	$	665,235		$	706,677		$	694,375		$	167,220		$	183,267		$	148,018
Interest cost	1,088,180			995,598			1,132,776			640,602			626,822			624,579
Expected return on plan assets	(1,862,838		)	(1,616,412		)	(1,492,241		)	(623,381		)	(571,513		)	(507,858		)
Recognized loss	351,030			662,180			501,678			283,868			429,758			250,173
Net periodic benefit cost	$	241,607		$	748,043		$	836,588		$	468,309		$	668,334		$	514,912

The assumed health care cost trend rates used in measuring the accumulated benefit obligation for the postretirement medical plan as of September 30, 2018, 2017 and 2016 are presented below:

	Pre 65						Post 65
	2018		2017		2016		2018		2017		2016
Health care cost trend rate assumed for next year	7.00	%	7.00	%	7.50	%	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	2026		2021		2021		2018		2017		2016

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	$	155,000	$	(123,000	)
Effect on accumulated postretirement benefit obligation	2,487,000		(2,025,000		)

The primary objectives of the Plans' investment policies are to maintain investment portfolios that diversify risk through prudent asset allocation parameters, achieve asset returns that meet or exceed the plans’ 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. In 2018, the Company revised its targeted pension plan investment allocation by rebalancing the assets from a 60% equity allocation to a 40% equity allocation. This change in investment strategy was in response to the pension plan approaching a fully funded position, thereby allowing the opportunity to reduce investment risk and volatility in asset performance while providing for asset growth through the remaining equity investments. As a result, the Company updated its long-term rate of return on pension and postretirement plan assets for fiscal 2019 to 5.5% and 4.3%, respectively. The investment policy continues to provide for a range of investment allocations to allow for continued flexibility in responding to market conditions.

The Company’s target and actual asset allocation in the pension and postretirement benefit plans as of September 30, 2018 and 2017 were:

	Pension Plan						Postretirement Plan
	Target		2018		2017		Target		2018		2017
Asset category:
Equity securities	40	%	40	%	63	%	50	%	49	%	51	%
Debt securities	60	%	59	%	36	%	50	%	50	%	48	%
Cash	—	%	1	%	1	%	—	%	1	%	1	%
Other	—	%	—	%	—	%	—	%	—	%	—	%

The assets of the plans are invested in mutual funds. The Company uses the fair value hierarchy described in Note 1 to classify these assets. The mutual funds are included under Level 2 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 market prices for each security; however, certain fixed income securities and other investments are not actively traded and are valued based on similar investments. The following table contains the fair value classifications of the benefit plan assets:

			Defined Benefit Pension Plan Fair Value Measurements - September 30, 2018
	Fair Value		Level 1		Level 2		Level 3
Asset Class:
Cash	$	282,478	$	282,478	$	—	$	—
Common and Collective Trust and Pooled Funds:
Bonds
Liability Driven Investment	16,504,956		—		16,504,956		—
Equities
Domestic Large Cap Growth	3,449,486		—		3,449,486		—
Domestic Large Cap Value	3,381,285		—		3,381,285		—
Domestic Small/Mid Cap Core	1,685,352		—		1,685,352		—
Foreign Large Cap Value	1,527,796		—		1,527,796		—
Mutual Funds:
Equities
Foreign Large Cap Growth	1,060,383		—		1,060,383		—
Foreign Large Cap Value	292,961		—		292,961		—
Total	$	28,184,697	$	282,478	$	27,902,219	$	—

			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:
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	$	—

			Postretirement Benefit Plan Fair Value Measurements - September 30, 2018
	Fair Value		Level 1		Level 2		Level 3
Asset Class:
Cash	$	96,117	$	96,117	$	—	$	—
Mutual Funds
Bonds
Domestic Fixed Income	5,859,588		—		5,859,588		—
Foreign Fixed Income	609,722		—		609,722		—
Equities
Domestic Large Cap Growth	1,926,076		—		1,926,076		—
Domestic Large Cap Value	1,874,643		—		1,874,643		—
Domestic Small/Mid Cap Growth	214,180		—		214,180		—
Domestic Small/Mid Cap Value	210,891		—		210,891		—
Domestic Small/Mid Cap Core	459,363		—		459,363		—
Foreign Large Cap Growth	525,720		—		525,720		—
Foreign Large Cap Value	1,090,851		—		1,090,851		—
Foreign Large Cap Core	28,786		—		28,786		—
Other	29,020		—		29,020		—
Total	$	12,924,957	$	96,117	$	12,828,840	$	—

			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	$	—

Each mutual fund has been categorized based on its primary investment strategy.

The Company expects to contribute $800,000 to its pension plan and $300,000 to its postretirement benefit plan in fiscal 2019.

The following table reflects expected future benefit payments:

Fiscal year ending September 30	Pension Plan		Postretirement Plan
2019	$	934,935	$	688,340
2020	983,862		685,088
2021	1,042,332		725,587
2022	1,124,774		778,814
2023	1,220,246		834,042
2024-2028	7,346,304		4,230,466

The Company sponsors a defined contribution plan (the “401k Plan”) covering all 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. The Company matches 100% of the participant’s first 4% of contributions and 50% on the next 2% of contributions. Company matching contributions were $338,066, $361,702 and $353,793 for 2018, 2017 and 2016, respectively. The Company also provided for $9,637 in discretionary contributions in 2018 for those employees hired on or after January 1, 2017.

XML

Common Stock Options

12 Months Ended

Sep. 30, 2018

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Common Stock Options

COMMON STOCK OPTIONS

The Company’s stockholders approved the RGC Resources, Inc. Key Employee Stock Option Plan (“KESOP”). 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, 2018, the number of shares available for future grants was 36,000.

FASB ASC No. 718 - Compensation-Stock Compensation requires that compensation expense be recognized for the issuance of equity instruments to employees. During the fiscal years ended 2017 and 2016, the Board approved stock option grants to certain officers. As required by the KESOP, each option's exercise price per share equaled the fair value of the Company's common stock on the grant date. Pursuant to the Plan, the options vest over a six-month period and are exercisable over a ten-year period from the date of issuance. No options were granted in fiscal 2018.

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,
	2018	2017	2016
Expected volatility	N/A	26.09%	28.78%
Expected dividends	N/A	3.81%	3.99%
Expected exercise term (years)	N/A	7.00	7.00
Risk-free interest rate	N/A	2.20%	2.10%

The underlying methods regarding each assumption are as follows:

Expected volatility is based on the historical volatilities of the daily closing price of the Company's common stock.

Expected dividend rate is based on historical dividend payout trends.

Expected exercise term is based on the average time historical option grants were outstanding before being exercised.

Risk-free interest rate is based on the 7-year Treasury rate on the date of option grant.

Forfeitures are recognized when they occur.

Stock option transactions under the Company's plans for the years ended September 30, 2018, 2017 and 2016 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, 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
Options granted	—		—
Options exercised	(1,575	)	12.66
Options expired	—		—
Options forfeited	—		—
Options outstanding, September 30, 2018	100,000		$	14.34	6.6	$	1,237,286
Vested and exercisable at September 30, 2018	100,000		$	14.34	6.6	$	1,237,286

¹Aggregate intrinsic value includes only those options where the exercise price is below the market price.

	Years Ended September 30,
	2018		2017		2016
Weighted-average grant date option fair value	$	—	$	2.89	$	2.69
Stock option expense	—		73,780		64,640
Intrinsic value of options exercised	15,256		99,929		8,418
Proceeds from exercise of stock options	19,945		142,241		41,762

OTHER STOCK PLANS

Dividend Reinvestment and Stock Purchase Plan

The Company offers a Dividend Reinvestment and Stock Purchase Plan (the “DRIP”) to shareholders of record for the reinvestment of dividends and the purchase of up to $40,000 per year in additional shares of common stock of the Company. Under the DRIP, the Company issued 31,744, 36,446 and 52,146 shares in 2018, 2017 and 2016, respectively. As of September 30, 2018, the Company had 417,229 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, 1997. Under the Plan, each director may elect annually to have up to 100% of his or her fees paid in shares of common stock ("Director Restricted Stock"); however, a minimum of 40% of the monthly retainer fee must be paid to each non-employee director of Resources in shares of Director Restricted Stock until such time as the director has accumulated at least 10,000 shares. The number of shares of Restricted Stock awarded each month is determined based on the closing sales price of Resources' common stock on the NASDAQ Global Market on the first business day of the month. The Director Restricted Stock issued under the Plan vests only in the case of a participant's death, disability, retirement, or in the event of a change in control of Resources. The Director Restricted Stock may not be sold, transferred, assigned or pledged by the participant until the shares have vested under the terms of the Plan. The shares of Director Restricted Stock will be forfeited to Resources by a participant's voluntary resignation during his or her term on the Board or removal for cause as a director.

The Company assumes all directors will complete their term and there will be no forfeiture of the Restricted Stock. Since the inception of the Plan, no director has forfeited any shares of Restricted Stock. The Company recognizes as compensation the market value of the Restricted Stock in the period it is issued.

The following table reflects the director compensation activity pursuant to the Plan:

	2018				2017			2016
	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	111,893		$	10.56	107,023	$	10.11	100,373	$	9.80
Granted	6,692		26.57		4,870	16.77		6,650	14.79
Vested	(20,283	)	11.20		—	—		—	—
Forfeited	—		—		—	—		—	—
End of year balance	98,302		$	11.51	111,893	$	10.56	107,023	$	10.11

The fair market value of the Director Restricted Stock included in compensation during fiscal 2018, 2017 and 2016 was $177,800, $99,400 and $98,334. No Director Restricted Stock vested or was forfeited during fiscal 2017 and 2016.

As of September 30, 2018, the Company had 75,049 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”) in 2017 following approval by the shareholders at the Company's annual meeting held on February 6, 2017. Under the Restricted Stock Plan, the Compensation Committee of the Board of Directors may grant shares of restricted 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 Plan 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 Restricted Stock Plan:

	2018
	Shares		Weighted-Average Fair Value on Date of Grant
Beginning of year balance	—		$	—
Granted	10,101		26.33
Vested	(3,367	)	26.33
Forfeited	—		—
End of year balance	6,734		$	26.33

The fair market value of the Officer Restricted Stock included as compensation during fiscal 2018 was $188,388. As of September 30, 2018, the Company had 439,734 shares available for issuance under the Plan.

Stock Bonus Plan

Shares from the Stock Bonus Plan may be issued to certain employees and management personnel in recognition of their performance and service. Under the Stock Bonus Plan, the Company issued 1,628 and 2,813 shares valued at $30,154 and $39,819, respectively, in 2017 and 2016. No shares were issued in 2018. As of September 30, 2018 the Company had 4,785 shares of stock available for issuance under the Stock Bonus Plan. This Plan is currently inactive and has been replaced by the Restricted Stock Plan.

XML

Other Stock Plans

12 Months Ended

Sep. 30, 2018

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Other Stock Plans

COMMON STOCK OPTIONS

The Company’s stockholders approved the RGC Resources, Inc. Key Employee Stock Option Plan (“KESOP”). 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, 2018, the number of shares available for future grants was 36,000.

FASB ASC No. 718 - Compensation-Stock Compensation requires that compensation expense be recognized for the issuance of equity instruments to employees. During the fiscal years ended 2017 and 2016, the Board approved stock option grants to certain officers. As required by the KESOP, each option's exercise price per share equaled the fair value of the Company's common stock on the grant date. Pursuant to the Plan, the options vest over a six-month period and are exercisable over a ten-year period from the date of issuance. No options were granted in fiscal 2018.

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,
	2018	2017	2016
Expected volatility	N/A	26.09%	28.78%
Expected dividends	N/A	3.81%	3.99%
Expected exercise term (years)	N/A	7.00	7.00
Risk-free interest rate	N/A	2.20%	2.10%

The underlying methods regarding each assumption are as follows:

Expected volatility is based on the historical volatilities of the daily closing price of the Company's common stock.

Expected dividend rate is based on historical dividend payout trends.

Expected exercise term is based on the average time historical option grants were outstanding before being exercised.

Risk-free interest rate is based on the 7-year Treasury rate on the date of option grant.

Forfeitures are recognized when they occur.

Stock option transactions under the Company's plans for the years ended September 30, 2018, 2017 and 2016 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, 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
Options granted	—		—
Options exercised	(1,575	)	12.66
Options expired	—		—
Options forfeited	—		—
Options outstanding, September 30, 2018	100,000		$	14.34	6.6	$	1,237,286
Vested and exercisable at September 30, 2018	100,000		$	14.34	6.6	$	1,237,286

¹Aggregate intrinsic value includes only those options where the exercise price is below the market price.

	Years Ended September 30,
	2018		2017		2016
Weighted-average grant date option fair value	$	—	$	2.89	$	2.69
Stock option expense	—		73,780		64,640
Intrinsic value of options exercised	15,256		99,929		8,418
Proceeds from exercise of stock options	19,945		142,241		41,762

OTHER STOCK PLANS

Dividend Reinvestment and Stock Purchase Plan

The Company offers a Dividend Reinvestment and Stock Purchase Plan (the “DRIP”) to shareholders of record for the reinvestment of dividends and the purchase of up to $40,000 per year in additional shares of common stock of the Company. Under the DRIP, the Company issued 31,744, 36,446 and 52,146 shares in 2018, 2017 and 2016, respectively. As of September 30, 2018, the Company had 417,229 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, 1997. Under the Plan, each director may elect annually to have up to 100% of his or her fees paid in shares of common stock ("Director Restricted Stock"); however, a minimum of 40% of the monthly retainer fee must be paid to each non-employee director of Resources in shares of Director Restricted Stock until such time as the director has accumulated at least 10,000 shares. The number of shares of Restricted Stock awarded each month is determined based on the closing sales price of Resources' common stock on the NASDAQ Global Market on the first business day of the month. The Director Restricted Stock issued under the Plan vests only in the case of a participant's death, disability, retirement, or in the event of a change in control of Resources. The Director Restricted Stock may not be sold, transferred, assigned or pledged by the participant until the shares have vested under the terms of the Plan. The shares of Director Restricted Stock will be forfeited to Resources by a participant's voluntary resignation during his or her term on the Board or removal for cause as a director.

The Company assumes all directors will complete their term and there will be no forfeiture of the Restricted Stock. Since the inception of the Plan, no director has forfeited any shares of Restricted Stock. The Company recognizes as compensation the market value of the Restricted Stock in the period it is issued.

The following table reflects the director compensation activity pursuant to the Plan:

	2018				2017			2016
	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	111,893		$	10.56	107,023	$	10.11	100,373	$	9.80
Granted	6,692		26.57		4,870	16.77		6,650	14.79
Vested	(20,283	)	11.20		—	—		—	—
Forfeited	—		—		—	—		—	—
End of year balance	98,302		$	11.51	111,893	$	10.56	107,023	$	10.11

The fair market value of the Director Restricted Stock included in compensation during fiscal 2018, 2017 and 2016 was $177,800, $99,400 and $98,334. No Director Restricted Stock vested or was forfeited during fiscal 2017 and 2016.

As of September 30, 2018, the Company had 75,049 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”) in 2017 following approval by the shareholders at the Company's annual meeting held on February 6, 2017. Under the Restricted Stock Plan, the Compensation Committee of the Board of Directors may grant shares of restricted 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 Plan 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 Restricted Stock Plan:

	2018
	Shares		Weighted-Average Fair Value on Date of Grant
Beginning of year balance	—		$	—
Granted	10,101		26.33
Vested	(3,367	)	26.33
Forfeited	—		—
End of year balance	6,734		$	26.33

The fair market value of the Officer Restricted Stock included as compensation during fiscal 2018 was $188,388. As of September 30, 2018, the Company had 439,734 shares available for issuance under the Plan.

Stock Bonus Plan

Shares from the Stock Bonus Plan may be issued to certain employees and management personnel in recognition of their performance and service. Under the Stock Bonus Plan, the Company issued 1,628 and 2,813 shares valued at $30,154 and $39,819, respectively, in 2017 and 2016. No shares were issued in 2018. As of September 30, 2018 the Company had 4,785 shares of stock available for issuance under the Stock Bonus Plan. This Plan is currently inactive and has been replaced by the Restricted Stock Plan.

XML

Commitments and Contingencies

12 Months Ended

Sep. 30, 2018

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

COMMITMENTS AND CONTINGENCIES

Long-Term Contracts

Due to the nature of the natural gas distribution business, Roanoke Gas enters into agreements with both suppliers and pipelines to contract for natural gas commodity purchases, storage capacity and pipeline delivery capacity. Roanoke Gas obtains most of its regulated natural gas supply through an asset management contract with a third party asset manager. Roanoke Gas 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, Roanoke Gas has designated the asset manager to act as agent for its storage capacity and all gas balances in storage. Roanoke Gas retains ownership of gas in storage. Under provisions of this contract, Roanoke Gas is obligated to purchase its winter storage requirements from the asset manager during the spring and summer injection periods at market price. The table below details the volumetric obligations as of September 30, 2018 for the remainder of the contract period. The asset management contract was renewed for another three year period at essentially the same terms and conditions as the prior agreement. The current asset management agreement will expire in March 2021.

Year	Natural Gas Contracts (In Decatherms)
2018-2019	2,089,578
2019-2020	2,071,061
2020-2021	295,866
Total	4,456,505

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, 2018. 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 $31,137,000, $28,496,000 and $24,852,000 under the asset management, pipeline and storage contracts in fiscal years 2018, 2017 and 2016, respectively. The table below details the pipeline and storage capacity obligations as of September 30, 2018 for the remainder of the contract period.

Year	Pipeline and Storage Capacity
2018-2019	$	11,184,000
2019-2020	8,856,915
2020-2021	6,503,953
2021-2022	5,847,945
2022-2023	2,369,904
Thereafter	1,950,134
Total	$	36,712,851

Roanoke Gas maintains franchise agreements granted by the local cities and towns served by the Company. Roanoke Gas recently renewed it's franchise agreements with the City of Roanoke, the City of Salem and the Town of Vinton for 20-year terms expiring in December 2035. Per the agreements, franchise fees will increase 3% per year through the term of the agreements for a total cost of $2,512,411.

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

Both Roanoke Gas and a previously owned gas subsidiary operated manufactured gas plants (MGPs) as a source of fuel for lighting and heating until the early 1950’s. A by-product of operating MGPs was coal tar, and the potential exists for tar waste contaminants at the former plant sites. 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 either 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.

XML

Fair Value Measurements

12 Months Ended

Sep. 30, 2018

Fair Value Disclosures [Abstract]

Fair Value Measurements

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, 2018 and 2017, respectively:

			Fair Value Measurements - September 30, 2018
	Fair Value		Quoted Prices in Active Markets Level 1		Significant  Other Observable Inputs Level 2		Significant Unobservable Inputs Level 3
Assets:
Interest rate swaps	$	310,563	$	—	$	310,563	$	—
Total	$	310,563	$	—	$	310,563	$	—
Liabilities:
Natural gas purchases	$	693,495	$	—	$	693,495	$	—
Total	$	693,495	$	—	$	693,495	$	—

			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	$	—

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, 2018 and 2017, the Company had recorded in accounts payable the estimated fair value of the liability determined on the corresponding first of month index prices for which the liability was expected to be settled.

The Company’s nonfinancial 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 financial statements as of September 30, 2018 and 2017.

			Fair Value Measurements - September 30, 2018
	Carrying Amount		Quoted Prices in Active Markets Level 1		Significant Other Observable  Inputs Level 2		Significant Unobservable Inputs Level 3
Liabilities:
Notes payable	$	63,243,200	$	—	$	—	$	62,435,237
Total	$	63,243,200	$	—	$	—	$	62,435,237

			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:
Notes payable	$	43,812,200	$	—	$	—	$	45,689,238
Total	$	43,812,200	$	—	$	—	$	45,689,238

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-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. Increasing interest rates during 2018 resulted in the reduction in the fair value of the Company's outstanding debt. The fair value for the RGC Midstream debt is estimated by discounting the estimated credit spread extrapolated based on market conditions.

FASB ASC 825 – Financial Instruments requires disclosures regarding concentrations of credit risk from financial instruments. Cash equivalents are investments in high-grade, short-term securities (original maturity less than three months), placed with financially sound institutions. Accounts receivable are from a diverse group of customers including individuals and small and large companies in various industries. The Company maintains certain credit standards with its customers and requires a customer deposit if such evaluation warrants.

XML

Quarterly Financial Information (Unaudited)

12 Months Ended

Sep. 30, 2018

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Information (Unaudited)

QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Quarterly financial data for the years ended September 30, 2018 and 2017 is summarized as follows:

2018	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Operating revenues	$	18,756,051	$	24,917,973	$	11,889,570	$	9,971,142
Operating income	$	3,675,124	$	5,306,718	$	1,866,223	$	744,980
Net income	$	2,059,462	$	3,465,929	$	1,087,355	$	684,459
Earnings per share of common stock:
Basic	$	0.28	$	0.47	$	0.14	$	0.09
Diluted	$	0.28	$	0.47	$	0.14	$	0.09

2017	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Operating revenues	$	18,788,585	$	21,900,013	$	11,435,824	$	10,172,448
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

XML

Subsequent Events

12 Months Ended

Sep. 30, 2018

Subsequent Events [Abstract]

Subsequent Events

SUBSEQUENT EVENTS

The Company has evaluated subsequent events through the date the financial statements were issued. There were no other items not otherwise disclosed which would have materially impacted the Company’s consolidated financial statements.

XML

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Sep. 30, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Principles of Consolidation

Principles of Consolidation—RGC Resources, Inc. is an energy services company primarily engaged in the sale and distribution of natural gas. The consolidated financial statements include the accounts of RGC Resources, Inc. and its wholly owned subsidiaries (“Resources” or the “Company”): Roanoke Gas Company (“Roanoke Gas”), Diversified Energy Company and RGC Midstream, LLC. Roanoke Gas is a natural gas utility, which distributes and sells natural gas to approximately 60,200 residential, commercial and industrial customers within its service areas in Roanoke, Virginia and the surrounding localities. The Company’s business is seasonal in nature as a majority of natural gas sales are for space heating during the winter season. Roanoke Gas is regulated by the Virginia State Corporation Commission (“SCC” or “Virginia Commission”). RGC Midstream, LLC is a wholly-owned subsidiary created primarily to invest in the Mountain Valley Pipeline project. Diversified Energy Company is inactive.

The Company follows accounting and reporting standards established by the Financial Accounting Standards Board (“FASB”) and the Securities and Exchange Commission (“SEC”).

Resources has only one reportable segment as defined under FASB ASC No. 280 – Segment Reporting. All intercompany transactions have been eliminated in consolidation.

Reclassification

Certain reclassifications have been made to the prior year income statements to be consistent with the current year presentation by moving cost of gas - utility and cost of sales - non utility under the operating expenses caption. This presentation makes the Company's income statement presentation consistent with industry peers.

Rate Regulated Basis of Accounting

Rate Regulated Basis of Accounting—The Company’s regulated operations follow the accounting and reporting requirements of FASB ASC No. 980, Regulated Operations. The economic effects of regulation can result in a regulated company deferring costs that have been or are expected to be recovered from customers in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this situation occurs, costs are deferred as assets in the consolidated balance sheet (regulatory assets) and recorded as expenses when such amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for current collection in rates of costs that are expected to be incurred in the future (regulatory liabilities). In the event the provisions of FASB ASC No. 980 no longer apply to any or all regulatory assets or liabilities, the Company would write off such amounts and include them in the consolidated statements of income and comprehensive income in the period for which FASB ASC No. 980 no longer applied.

Utility Plant and Depreciation

Utility Plant and Depreciation—Utility plant is stated at original cost and includes direct labor and materials, contractor costs, and all allocable overhead charges. The Company applies the group method of accounting, where the costs of like assets are aggregated and depreciated by applying a rate based on the average expected useful life of the assets. In accordance with Company policy, expenditures for depreciable assets with a life greater than one year are capitalized, along with any upgrades or improvements to existing assets, when they significantly improve or extend the original expected useful life of an asset. Expenditures for maintenance, repairs, and minor renewals and betterments are expensed as incurred. The original cost of depreciable property retired is removed from utility plant and charged to accumulated depreciation. The cost of asset removals, less salvage, is charged to “regulatory cost of retirement obligations” or “asset retirement obligations” as explained under Asset Retirement Obligations below.

Utility plant is composed of the following major classes of assets:

	Years Ended September 30
	2018		2017
Distribution and transmission	$	196,778,546	$	177,845,619
LNG storage	13,413,175		13,299,288
General and miscellaneous	14,662,599		13,078,807
Total utility plant in service	$	224,854,320	$	204,223,714

Provisions for depreciation are computed principally at composite straight-line rates over periods ranging from 5 to 76 years. 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 in June 2014 and will be required to complete a new depreciation study in fiscal 2019. The composite weighted-average depreciation rate realized using the most recently completed depreciation study was 3.32%, 3.29% and 3.25% for fiscal years ended September 30, 2018, 2017 and 2016.

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. 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.

Asset Retirement Obligations

Asset Retirement Obligations—FASB ASC No. 410, Asset Retirement and Environmental Obligations, requires entities to record the fair value of a liability for an asset retirement obligation when there exists a legal obligation for the retirement of the asset. When the liability is initially recorded, the entity capitalizes the cost, thereby increasing the carrying amount of the underlying asset. In subsequent periods, the liability is accreted, and the capitalized cost is depreciated over the useful life of the underlying asset. The Company has recorded asset retirement obligations for its future legal obligations related to purging and capping its distribution mains and services upon retirement, although the timing of such retirements is uncertain.

The Company’s composite depreciation rates include a component to provide for the cost of retirement of assets. As a result, the Company accrues the estimated cost of retirement of its utility plant through depreciation expense and creates a corresponding regulatory liability. The costs of retirement considered in the development of the depreciation component include those costs associated with the legal liability. Therefore, the asset retirement obligation 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, the Company increased its asset retirement obligation to reflect revisions to the estimated cash flows for asset retirements.

Cash, Cash Equivalents and Short-Term Investments

Cash, Cash Equivalents and Short-Term Investments—From time to time, the Company will have balances on deposit at banks in excess of the amount insured by the Federal Deposit Insurance Corporation (“FDIC”). The Company has not experienced any losses on these accounts and does not consider these amounts to be at credit risk. As of September 30, 2018, the Company did not have any bank deposits in excess of the FDIC insurance limits. For purposes of the consolidated statements of cash flows, the Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents.

Customer Receivables and Allowance for Doubtful Accounts

Customer Receivables and Allowance for Doubtful Accounts—Accounts receivable include amounts billed to customers for natural gas sales and related services and gas sales occurring subsequent to normal billing cycles but before the end of the period. The Company provides an estimate for losses on these receivables by utilizing historical information, current account balances, account aging and current economic conditions. Customer accounts are charged off annually when deemed uncollectible or when turned over to a collection agency for action.

Financing Receivables

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

Inventories

Inventories—Natural gas in storage and materials and supplies inventories are recorded at average cost. Natural gas storage injections are priced at the purchase cost at the time of injection and storage withdrawals are priced at the weighted average cost of gas in storage. Materials and supplies are removed from inventory at average cost.

Unbilled Revenues

Unbilled Revenues—The Company bills its natural gas customers on a monthly cycle; however, the billing cycle period for most customers does not coincide with the accounting periods used for financial reporting. As the Company recognizes revenue when gas is delivered, an accrual is made to estimate revenues for natural gas delivered to customers but not billed during the accounting period.

Income Taxes

Income Taxes—Income taxes are accounted for using the asset and liability method. Under the asset and liability method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the years in which those temporary differences are expected to be recovered or settled. A valuation allowance against deferred tax assets is provided if it is more likely than not the deferred tax asset will not be realized. The Company and its subsidiaries file state and federal consolidated income tax returns.

Debt Expenses

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

Over/Under-Recovery of Natural Gas Costs—Pursuant to the provisions of the Company’s Purchased Gas Adjustment (“PGA”) clause, the SCC provides the Company with a method of passing along to its customers increases or decreases in natural gas costs incurred by its regulated operations, including gains and losses on natural gas derivative hedging instruments. On a quarterly basis, the Company files a PGA rate adjustment request with the SCC to increase or decrease the gas cost component of its rates, based on projected price and activity. Once administrative approval is received, the Company adjusts the gas cost component of its rates to reflect the approved amount. As actual costs will differ from the projections used in establishing the PGA rate, the Company may either over-recover or under-recover its actual gas costs during the period. Any difference between actual costs incurred and costs recovered through the application of the PGA is recorded as a regulatory asset or liability. At the end of the deferral period, the balance of the net deferred charge or credit is amortized over an ensuing 12-month period as amounts are reflected in customer billings.

Fair Value

Fair Value—Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The Company determines fair value based on the following fair value hierarchy which prioritizes each input to the valuation methods into one of the following three broad levels:

• Level 1 – Unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date.

• Level 2 – Inputs other than quoted prices in Level 1 that are either for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability, or inputs that are derived principally from or corroborated by observable market data by correlation or other means.

• Level 3 – Unobservable inputs for the asset or liability where there is little, if any, market activity which require the Company to develop its own assumptions.

The fair value hierarchy gives the highest priority to unadjusted quoted prices in active markets (Level 1) and the lowest priority to unobservable inputs (Level 3). All fair value disclosures are categorized within one of the three categories in the hierarchy. See fair value disclosures below and in Notes 8 and 12.

Use of Estimates

Use of Estimates—The preparation of financial statements in conformity with Generally Accepted Accounting Principles in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Excise and Sales Taxes

Excise and Sales Taxes—Certain excise and sales taxes imposed by the state and local governments in the Company’s service territory are collected by the Company from its customers. These taxes are accounted for on a net basis and therefore are not included as revenues in the Company’s Consolidated Statements of Income.

Earnings Per Share

Earnings Per Share—Basic earnings per share and diluted earnings per share 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.

Business and Credit Concentrations

Business and Credit Concentrations—The primary business of the Company is the distribution of natural gas to residential, commercial and industrial customers in its service territories.

No sales to individual customers accounted for more than 5% of total revenue in any period or amounted to more than 5% of total accounts receivable.

Roanoke Gas currently holds the only franchises and certificates of public convenience and necessity to distribute natural gas in its service area. These franchises are effective through January 1, 2036. The Company's current certificates of public convenience and necessity 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

Derivative and Hedging Activities—FASB ASC No. 815, Derivatives and Hedging, requires the recognition of all derivative instruments as assets or liabilities in the Company’s balance sheet and measurement of those instruments at fair value.

The Company’s hedging and derivatives policy allows management to enter into derivatives for the purpose of managing the commodity and financial market risks of its business operations. The Company’s hedging and derivatives policy specifically prohibits the use of derivatives for speculative purposes. The key market risks that RGC Resources, Inc. 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 balance sheet with the offsetting entry to either under-recovery of gas costs 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.

Recently Adopted Accounting Standards and Recently Issued Accounting Standards

Recently Adopted Accounting Standards

In March 2016, the FASB issued ASU 2016-09, Compensation - Stock Compensation: Improvements to Employee Share-Based Payment Accounting. The guidance simplifies several aspects of the accounting for share-based payment award transactions, including income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. The new guidance is effective for the Company for the annual reporting period ending September 30, 2018 and interim periods within that annual period. Early adoption is permitted. The Company adopted this ASU for the quarter ended September 30, 2016. Under the prior guidance, excess tax benefits were to be tracked in an APIC pool and not recognized in the income statement. Tax deficiencies were netted against the accumulated APIC pool and only recognized in the income statement starting at the time tax deficiencies exceeded the pool. Under ASU 2016-09, the APIC pool is eliminated with all excess tax benefits and deficiencies recognized in income tax expense on the income statement. Prior to the adoption of this ASU, stock option activity did not result in the accumulation of an APIC pool; therefore, adopting the ASU had minimal impact on the Company’s current financial position, results of operations or cash flows and no impact on prior results.

In January 2017, the FASB issued ASU 2017-03, Accounting Changes and Error Corrections and Investments - Equity Method and Joint Ventures. This update adds the text of the SEC Staff Announcement, Disclosure of the Impact That Recently Issued Accounting Standards Will Have on the Financial Statements of a Registrant When Such Standards Are Adopted in a Future Period (in accordance with Staff Accounting Bulletin Topic 11.M) as paragraph 250-10-S99-6. Related specifically to ASU 2014-09, ASU 2016-02 and ASU 2016-13, an SEC registrant should evaluate ASUs that have not yet been adopted to determine and include appropriate financial disclosures and MD&A discussions, including consideration of additional qualitative disclosures, to assist financial statement readers in assessing the significance of impact on adoption. The new guidance is effective immediately. The nature of this guidance relates to the effectiveness and quality of disclosures related to ASUs not yet adopted; however, there is no effect on the Company's financial position, results of operations or cash flows.

In February 2018, the FASB issued ASU 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220) - Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. The ASU provides the option to reclassify stranded tax effects within Accumulated Other Comprehensive Income ("AOCI") to retained earnings in each period in which the effects of the change in the U.S. federal corporate income tax rate, per the Tax Cuts and Jobs Act, is recorded. The new guidance is effective for the Company for the annual reporting period ending September 30, 2020 and interim periods within that annual period. Early adoption is permitted. Management completed its evaluation and adopted the new guidance in the fourth quarter of fiscal 2018. As a result, the Company reclassified $234,337 in stranded tax expense out of AOCI to retained earnings related to pension and postretirement plans for the unregulated operations of Resources. In addition, the Company also reclassified $20,285 out of AOCI to the regulatory liability for the stranded tax expense related to the interest rate swap. See the Other Comprehensive Income section above and Note 3 below for more information.

Recently Issued Accounting Standards

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) that affects any entity that enters into contracts with customers for the transfer of goods or services or transfer of non-financial assets. This guidance supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. The core principle of the new guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve that core principle, an entity should apply the following steps: (1) identify the contract with the customer, (2) identify the performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to the performance obligations in the contract, and (5) recognize revenue when, or as, the entity satisfies the performance obligation. In August 2015, the FASB issued ASU 2015-14 that deferred the effective date of this guidance by one year making the standard effective for the Company's annual reporting period ending September 30, 2019 and interim periods within that annual period. Subsequent ASUs have been issued, which provide additional guidance to assist in the implementation of the new revenue standard. Based on the evaluation of the ASU, management has determined that the adoption of the new standard will not have a material impact on the Company's financial position, results of operations or cash flows. However, significant new disclosures will be required as a result of the guidance. The Company is completing the review and updating of its disclosures and will reflect the changes with the adoption of the standard in the first quarter of fiscal 2019 using the modified retrospective approach.

In January 2016, the FASB issued ASU 2016-01, Financial Instruments - Overall: Recognition and Measurement of Financial Assets and Financial Liabilities. The ASU enhances the reporting model for financial instruments to provide users of the financial statements with more useful information through several provisions, including the following: (1) requires equity investments, excluding investments accounted for under the equity method, be measured at fair value with changes in fair value recognized in net income, (2) simplifies the impairment assessment of equity investments without readily determinable fair values, (3) eliminates the requirement to disclose the method(s) and significant assumptions used to estimate the fair value that is required to be disclosed for financial instruments measured at amortized cost on the balance sheet, (4) requires entities to use the exit price notion when measuring the fair value of financial instruments for disclosure purposes, and (5) requires separate presentation of financial assets and financial liabilities by measurement category and form of financial asset on the balance sheet or the accompanying notes to the financial statements. The new guidance is effective for the Company for the annual reporting period ending September 30, 2019 and interim periods within that annual period. Management is in the process of completing its evaluation of the standard, but does not anticipate the new guidance to have a material effect on its financial position, results of operations or cash flows.

In February 2016, the FASB issued ASU 2016-02, Leases. The ASU leaves the accounting for leases mostly unchanged for lessors, with the exception of targeted improvements for consistency; however, the new guidance requires lessees to recognize assets and liabilities for leases with terms of more than 12 months. The ASU also revises the definition of a lease as a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment for a period of time in exchange for consideration. Consistent with current GAAP, the presentation and cash flows arising from a lease by a lessee will primarily depend on its classification as a finance or operating lease. In contrast, the new ASU requires both types of leases to be recognized on the balance sheet. In addition, the new guidance includes quantitative and qualitative disclosure requirements to aid financial statement users in better understanding the amount, timing and uncertainty of cash flows arising from leases. The new guidance is effective for the Company for the annual reporting period ending September 30, 2020 and interim periods within that annual period. Early adoption is permitted. The Company has completed its inventory of leases and does not currently expect the new guidance to have a material effect on its financial position, results of operations or cash flows.

In March 2017, the FASB issued ASU 2017-07, Compensation - Retirement Benefits. The primary objective of this guidance is to improve the financial statement presentation of net periodic pension and postretirement benefit costs; however, it also changes which cost components are eligible for capitalization. The amendments in the ASU require that an employer report the service cost component in the same line item or items as other compensation costs arising from services rendered by the employees during the period. The other components of net benefit cost are required to be presented in the income statement separately from the service cost component and, if a subtotal for income from operations is presented, outside of income from operations. In addition, the ASU allows only the service cost component of periodic benefit cost to be eligible for capitalization when applicable. This change to capitalization eligibility differs from the treatment currently applied by the Company and from allowed regulatory accounting. The new guidance is effective for the Company for the annual reporting period ending September 30, 2019 and interim periods within that annual period. Early adoption is permitted. Management has had discussions with its state regulators regarding the adoption of this ASU for regulatory purposes. The regulatory body has not taken a position on the change in capitalization requirements for these benefit costs and will evaluate the impact of this ASU on a case by case basis. The Company intends to adopt this ASU effective October 1, 2018 with the change in expense classification on a retrospective basis and the change in capitalization of costs on a prospective basis. If the regulatory body ultimately determines that changes to the capitalization of these retirement benefits is not appropriate for regulatory purposes, the Company may have to establish regulatory assets or liabilities for those costs or benefits excluded from capitalization under this ASU. Management does not expect the new guidance to have a material effect on the Company's consolidated financial statements.

In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging: Targeted Improvements to Accounting For Hedging Activities. The ASU is meant to simplify recognition and presentation guidance in an effort to improve financial reporting of cash flow and fair value hedging relationships to better portray the economic results of an entity's risk management activities. This is achieved through changes to both the designation and measurement guidance for qualifying hedging relationships, as well as changes to the presentation of hedge results. The new guidance is effective for the Company for the annual reporting period ending September 30, 2020 and interim periods within that annual period. Early adoption is permitted. Management has not completed its evaluation of the new guidance; however, it does not currently expect the new guidance to have a material effect on its financial position, results of operations or cash flows.

In August 2018, the FASB issued ASU 2018-14, Compensation - Retirement Benefits - Defined Benefit Plans - General (Subtopic 715-20) - Disclosure Framework - Changes to the Disclosure Requirements for Defined Benefit Plans. This ASU modifies disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The new guidance is effective for the Company for the annual reporting period ending September 30, 2021. Early adoption is permitted. Management has not completed its evaluation of the new guidance; however, the ASU only modifies disclosure requirements and will not effect financial position, results of operations or cash flows.

In August 2018, the FASB issued ASU 2018-15, Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer's Accounting for Implementation Costs incurred in a Cloud Computing Arrangement that is a Service Contract. This ASU reduces the complexity of accounting for costs of implementing a cloud computing service arrangement and aligns the following requirements to capitalize implementation costs: 1) those incurred in a hosting arrangement that is a service contract, and 2) those incurred to develop or obtain internal-use software, including hosting arrangements that include an internal software license. The new guidance is effective for the Company for the annual reporting period beginning October 1, 2020. Management has not completed its evaluation of the new guidance; however, it believes the new guidance will change the future treatment of certain contracts by allowing related implementation costs to be capitalized and amortized over time, rather than directly expensed. Management does not currently expect the new guidance to have a material effect on its financial position, results of operations or 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.

XML

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Sep. 30, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of Regulatory Assets

Regulatory assets and liabilities included in the Company’s consolidated balance sheets as of September 30, 2018 and 2017 are as follows:

	September 30
	2018		2017
Regulatory Assets:
Current Assets:
Accounts receivable:
Accrued WNA revenues	$	169,602	$	248,840
Under-recovery of gas costs	922,898		—
Other:
Accrued pension and postretirement medical	293,000		658,786
Utility Property:
In service:
Other	11,945		11,945
Other Assets:
Regulatory assets:
Premium on early retirement of debt	1,826,995		1,941,182
Accrued pension and postretirement medical	5,704,718		8,643,524
Other	1,330,434		1,211,554
Total regulatory assets	$	10,259,592	$	12,715,831
Regulatory Liabilities:
Current Liabilities:
Over-recovery of gas costs	$	—	$	1,438,074
Accrued expenses:
Over-recovery of SAVE Plan revenues	670,034		215,514
Rate refund	1,320,167		—
Deferred Credits and Other Liabilities:
Asset retirement obligations	6,417,948		6,069,993
Regulatory cost of retirement obligations	11,163,981		10,055,189
Regulatory liability - deferred income taxes	11,447,736		—
Total regulatory liabilities	$	31,019,866	$	17,778,770

Schedule of Regulatory Liabilities

Regulatory assets and liabilities included in the Company’s consolidated balance sheets as of September 30, 2018 and 2017 are as follows:

	September 30
	2018		2017
Regulatory Assets:
Current Assets:
Accounts receivable:
Accrued WNA revenues	$	169,602	$	248,840
Under-recovery of gas costs	922,898		—
Other:
Accrued pension and postretirement medical	293,000		658,786
Utility Property:
In service:
Other	11,945		11,945
Other Assets:
Regulatory assets:
Premium on early retirement of debt	1,826,995		1,941,182
Accrued pension and postretirement medical	5,704,718		8,643,524
Other	1,330,434		1,211,554
Total regulatory assets	$	10,259,592	$	12,715,831
Regulatory Liabilities:
Current Liabilities:
Over-recovery of gas costs	$	—	$	1,438,074
Accrued expenses:
Over-recovery of SAVE Plan revenues	670,034		215,514
Rate refund	1,320,167		—
Deferred Credits and Other Liabilities:
Asset retirement obligations	6,417,948		6,069,993
Regulatory cost of retirement obligations	11,163,981		10,055,189
Regulatory liability - deferred income taxes	11,447,736		—
Total regulatory liabilities	$	31,019,866	$	17,778,770

Schedule of Utility Plant

Utility plant is composed of the following major classes of assets:

	Years Ended September 30
	2018		2017
Distribution and transmission	$	196,778,546	$	177,845,619
LNG storage	13,413,175		13,299,288
General and miscellaneous	14,662,599		13,078,807
Total utility plant in service	$	224,854,320	$	204,223,714

Summary of Asset Retirement Obligation

The following is a summary of the asset retirement obligation:

	Years Ended September 30
	2018			2017
Beginning balance	$	6,069,993		$	5,682,556
Liabilities incurred	79,608			65,556
Liabilities settled	(126,907		)	(137,304		)
Accretion	332,537			312,503
Revisions to estimated cash flows	62,717			146,682
Ending balance	$	6,417,948		$	6,069,993

Reconciliation of Changes in Allowance for Doubtful Accounts

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

	Years Ended September 30
	2018			2017			2016
Beginning balance	$	99,456		$	76,934		$	52,721
Provision for doubtful accounts	169,096			84,587			14,074
Recoveries of accounts written off	78,919			110,725			137,055
Accounts written off	(243,898		)	(172,790		)	(126,916		)
Ending balance	$	103,573		$	99,456		$	76,934

Reconciliation of Basic and Diluted Earnings Per Share

A reconciliation of basic and diluted earnings per share is presented below:

	Years Ended September 30
	2018		2017		2016
Net Income	$	7,297,205	$	6,232,865	$	5,806,866
Weighted-average common shares	7,649,025		7,218,686		7,149,906
Effect of dilutive securities:
Options to purchase common stock	46,687		37,360		9,857
Diluted average common shares	7,695,712		7,256,046		7,159,763
Earnings Per Share of Common Stock:
Basic	$	0.95	$	0.86	$	0.81
Diluted	$	0.95	$	0.86	$	0.81

Schedule of Interest Rate Derivative

The table below reflects the fair value of the derivative instrument and its corresponding classification in the consolidated balance sheets.

	September 30
	2018		2017
Derivatives designated as hedging instruments:
Current assets:
Interest rate swap	$	100,723	$	26,777
Other assets:
Interest rate swap	$	209,840	$	90,066
Total derivatives designated as hedging instruments	$	310,563	$	116,843

Summary of 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, 2018:
Interest rate swap:
Unrealized gains	$	217,773		$	(62,807	)	$	154,966
Transfer of realized gains to interest expense	(24,053		)	6,937			(17,116		)
Net interest rate swap	193,720			(55,870		)	137,850
Defined benefit plans:
Net gain arising during period	$	595,570		$	(171,775	)	$	423,795
Amortization of actuarial gains	(23,887		)	6,890			(16,997		)
Net defined benefit plans	571,683			(164,885		)	406,798
Other comprehensive income	$	765,403		$	(220,755	)	$	544,648
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	)

Components of Accumulated Comprehensive Income (Loss)

Composition of Accumulated Other Comprehensive Income (Loss):

	Interest Rate Swaps		Defined Benefit Plans			Accumulated Other Comprehensive Income (Loss)
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		)
Other comprehensive income (loss)	137,850		406,798			544,648
Reclassification adjustment for the effect of change in tax law	20,285		(234,337		)	(214,052		)
Balance September 30, 2018	$	230,624	$	(1,102,292	)	$	(871,668	)

XML

Other Investments (Tables)

12 Months Ended

Sep. 30, 2018

Other Investments [Abstract]

Schedule of Other Investments

The financial statement locations of the investments by Midstream are as follows:

	September 30
Balance Sheet Location of Other Investments:	2018		2017
Other Assets:
Investment in unconsolidated affiliate	$	28,507,146	$	7,445,106
Current Liabilities:
Capital contributions payable	$	10,142,766	$	1,055,504
	For the Years ended September 30
Income Statement Location of Other Investments:	2018		2017		2016
Equity in earnings of unconsolidated affiliate	$	938,531	$	421,646	$	152,864

The change in the investment in unconsolidated affiliate are provided below:

	For the Years ended September 30,
	2018		2017		2016
Cash investment	$	11,036,247	$	2,759,346	$	3,055,746
Change in accrued capital calls	9,087,262		767,710		287,794
Equity in earnings of unconsolidated affiliate	938,531		421,646		152,864
Change in investment in unconsolidated affiliate	$	21,062,040	$	3,948,702	$	3,496,404

XML

Line-of-Credit (Tables)

12 Months Ended

Sep. 30, 2018

Debt Disclosure [Abstract]

Summary of Available Limits Under Line of Credit Agreement

Available limits under this agreement for the remaining term are as follows:

As of	Available Line-of-Credit
September 30, 2018	$	20,000,000
November 21, 2018	21,000,000
March 1, 2019	17,000,000
July 22, 2019	22,000,000
September 22, 2019	25,000,000
March 1, 2020	22,000,000

Summary of Line of Credit

A summary of the line-of-credit follows:

	September 30
	2018			2017			2016
Available line-of-credit at year-end	$	20,000,000		$	21,000,000		$	24,000,000
Outstanding balance at year-end	7,361,017			17,791,760			14,556,785
Highest month-end balance outstanding	17,054,377			17,791,760			15,246,089
Average daily balance	6,730,334			10,936,114			9,620,914
Average rate of interest during year on outstanding balances	2.53		%	1.92		%	1.40		%
Interest rate at year-end	3.26		%	2.23		%	1.53		%
Interest rate on unused line-of-credit	0.15		%	0.15		%	0.15		%

XML

Long-Term Debt (Tables)

12 Months Ended

Sep. 30, 2018

Debt Disclosure [Abstract]

Schedule of Long-Term Debt

Long-term debt consists of the following:

	September 30
	2018				2017
	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	$	154,465	$	30,500,000	$	164,119
Unsecured term note payable, at 30-day LIBOR plus 0.90%, November 1, 2021	7,000,000		10,283		7,000,000		13,618
Unsecured term notes payable, at 3.58% due on October 2, 2027	8,000,000		43,343		—		48,160
RGC Midstream, LLC:
Unsecured term notes payable, at 30-day LIBOR plus 1.35% due December 29, 2020	$	17,743,200	$	74,190	$	6,312,200	$	66,052
Total notes payable	$	63,243,200	$	282,281	$	43,812,200	$	291,949
Line-of-credit, at 30-day LIBOR plus 1.00%, due March 31, 2020	7,361,017		—		17,791,760		—
Total long-term debt	$	70,604,217	$	282,281	$	61,603,960	$	291,949

Summary of Aggregate Annual Maturities of Long-Term Debt

The aggregate annual maturities of long-term debt for the next five years ending after September 30, 2018 are as follows:

Year Ending September 30	Maturities
2019	$	—
2020	7,361,017
2021	17,743,200
2022	7,000,000
2023	—
Thereafter	38,500,000
Total	$	70,604,217

XML

Income Taxes (Tables)

12 Months Ended

Sep. 30, 2018

Income Tax Disclosure [Abstract]

Details of Income Tax Expense

The details of income tax expense are as follows:

	Years Ended September 30
	2018		2017		2016
Current income taxes:
Federal	$	1,831,085	$	72,368	$	(1,216,745	)
State	308,057		407,643		415,975
Total current income taxes	2,139,142		480,011		(800,770		)
Deferred income taxes:
Federal	440,282		3,129,925		4,302,906
State	315,712		195,454		164,048
Total deferred income taxes	755,994		3,325,379		4,466,954
Total income tax expense	$	2,895,136	$	3,805,390	$	3,666,184

Reconciliation of Income Tax Expense Based on Federal Statutory Rate

Income tax expense for the years ended September 30, 2018, 2017 and 2016 differed from amounts computed by applying the U.S. federal income tax rate to earnings before income taxes due to the following:

	Years Ended September 30
	2018			2017			2016
Income before income taxes	$	10,192,341		$	10,038,255		$	9,473,050
Corporate federal income tax rate	24.3		%	34.0		%	34.0		%
Income tax expense computed at the federal statutory rate	$	2,476,739		$	3,413,007		$	3,220,837
State income taxes, net of federal income tax benefit	472,193			398,044			382,815
Revaluation of unregulated deferred taxes to 21%	256,444			—			—
Net amortization of excess deferred taxes on regulated operations	(264,106		)	—			—
Other, net	(46,134		)	(5,661		)	62,532
Total income tax expense	$	2,895,136		$	3,805,390		$	3,666,184

Schedule of Deferred Tax Assets and Liabilities

The tax effects of temporary differences that give rise to the deferred tax assets and deferred tax liabilities are as follows:

	September 30
	2018		2017
Deferred tax assets:
Allowance for uncollectibles	$	26,658	$	37,752
Accrued pension and postretirement medical benefits	897,834		1,747,429
Regulatory effect of change in federal income tax rate	2,946,649		—
Accrued vacation	160,001		239,414
Over-recovery of gas costs	—		545,894
Costs of gas held in storage	591,899		1,009,206
Deferred compensation	716,843		824,281
Rate refund	339,812		—
Other	298,129		348,833
Total gross deferred tax assets	5,977,825		4,752,809
Deferred tax liabilities:
Utility plant	17,982,215		27,630,486
Under-recovery of gas costs	255,570		—
MVP investment	245,678		154,817
Other	79,939		44,354
Total gross deferred tax liabilities	18,563,402		27,829,657
Net deferred tax liability	$	12,585,577	$	23,076,848

XML

Employee Benefit Plans (Tables)

12 Months Ended

Sep. 30, 2018

Retirement Benefits [Abstract]

Schedule of Changes in Benefit Obligations and Fair Value of Plan Assets, Funded Status of the Plan, and Amount Recognized in the Financial Statements

The following tables set forth the benefit obligation, fair value of plan assets, the funded status of the benefit plans, amounts recognized in the Company’s financial statements and the assumptions used.

	Pension Plan						Postretirement Plan
	2018			2017			2018			2017
Accumulated benefit obligation	$	25,199,762		$	25,481,993		$	16,207,322		$	17,666,812
Change in benefit obligation:
Benefit obligation at beginning of year	$	29,657,347		$	29,494,950		$	17,666,812		$	18,504,710
Service cost	665,235			706,677			167,220			183,267
Interest cost	1,088,180			995,598			640,602			626,822
Actuarial gain	(1,727,767		)	(824,361		)	(1,774,320		)	(1,199,722		)
Benefit payments, net of retiree contributions	(832,696		)	(715,517		)	(492,992		)	(448,265		)
Benefit obligation at end of year	$	28,850,299		$	29,657,347		$	16,207,322		$	17,666,812
Change in fair value of plan assets:
Fair value of plan assets at beginning of year	$	26,418,671		$	23,113,057		$	12,691,162		$	11,122,783
Actual return on plan assets, net of taxes	1,798,722			3,021,131			426,787			1,016,644
Employer contributions	800,000			1,000,000			300,000			1,000,000
Benefit payments, net of retiree contributions	(832,696		)	(715,517		)	(492,992		)	(448,265		)
Fair value of plan assets at end of year	$	28,184,697		$	26,418,671		$	12,924,957		$	12,691,162
Funded status	$	(665,602	)	$	(3,238,676	)	$	(3,282,365	)	$	(4,975,650	)
Amounts recognized in the balance sheet consist of:
Noncurrent liabilities	$	(665,602	)	$	(3,238,676	)	$	(3,282,365	)	$	(4,975,650	)
Amounts recognized in accumulated other comprehensive loss:
Net actuarial loss, net of tax	$	361,215		$	572,740		$	741,077		$	702,013
Total amounts included in other comprehensive loss, net of tax	$	361,215		$	572,740		$	741,077		$	702,013
Amounts deferred to a regulatory asset:
Net actuarial loss	$	3,894,221		$	5,471,547		$	2,103,497		$	3,830,763
Amounts recognized as regulatory assets	$	3,894,221		$	5,471,547		$	2,103,497		$	3,830,763

Schedule of Actuarial Assumptions Used

The following table details the actuarial assumptions used in determining the projected benefit obligations and net benefit cost of the pension and the accumulated benefit obligations and net benefit cost of the postretirement plan for 2018, 2017 and 2016.

	Pension Plan						Postretirement Plan
	2018		2017		2016		2018		2017		2016
Assumptions used to determine benefit obligations:
Discount rate	4.11	%	3.72	%	3.42	%	4.09	%	3.69	%	3.33	%
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	3.72	%	3.42	%	4.22	%	3.69	%	3.33	%	4.15	%
Expected long-term rate of return on plan assets	7.00	%	7.00	%	7.00	%	4.84	%	4.84	%	4.89	%
Expected rate of compensation increase	4.00	%	4.00	%	4.00	%	N/A		N/A		N/A

Schedule of Components of Net Periodic Benefit Cost

Components of net periodic benefit cost are as follows:

	Pension Plan									Postretirement Plan
	2018			2017			2016			2018			2017			2016
Service cost	$	665,235		$	706,677		$	694,375		$	167,220		$	183,267		$	148,018
Interest cost	1,088,180			995,598			1,132,776			640,602			626,822			624,579
Expected return on plan assets	(1,862,838		)	(1,616,412		)	(1,492,241		)	(623,381		)	(571,513		)	(507,858		)
Recognized loss	351,030			662,180			501,678			283,868			429,758			250,173
Net periodic benefit cost	$	241,607		$	748,043		$	836,588		$	468,309		$	668,334		$	514,912

Summary of Assumed Health Care Cost Trend Rates Used

The assumed health care cost trend rates used in measuring the accumulated benefit obligation for the postretirement medical plan as of September 30, 2018, 2017 and 2016 are presented below:

	Pre 65						Post 65
	2018		2017		2016		2018		2017		2016
Health care cost trend rate assumed for next year	7.00	%	7.00	%	7.50	%	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	2026		2021		2021		2018		2017		2016

Effect of a 1% Change in Health Care Cost Trend Rate Assumptions

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	$	155,000	$	(123,000	)
Effect on accumulated postretirement benefit obligation	2,487,000		(2,025,000		)

Schedule of Target and Actual Asset Allocation

The Company’s target and actual asset allocation in the pension and postretirement benefit plans as of September 30, 2018 and 2017 were:

	Pension Plan						Postretirement Plan
	Target		2018		2017		Target		2018		2017
Asset category:
Equity securities	40	%	40	%	63	%	50	%	49	%	51	%
Debt securities	60	%	59	%	36	%	50	%	50	%	48	%
Cash	—	%	1	%	1	%	—	%	1	%	1	%
Other	—	%	—	%	—	%	—	%	—	%	—	%

Summary of Fair Value Classifications of Benefit Plan Assets

The following table contains the fair value classifications of the benefit plan assets:

			Defined Benefit Pension Plan Fair Value Measurements - September 30, 2018
	Fair Value		Level 1		Level 2		Level 3
Asset Class:
Cash	$	282,478	$	282,478	$	—	$	—
Common and Collective Trust and Pooled Funds:
Bonds
Liability Driven Investment	16,504,956		—		16,504,956		—
Equities
Domestic Large Cap Growth	3,449,486		—		3,449,486		—
Domestic Large Cap Value	3,381,285		—		3,381,285		—
Domestic Small/Mid Cap Core	1,685,352		—		1,685,352		—
Foreign Large Cap Value	1,527,796		—		1,527,796		—
Mutual Funds:
Equities
Foreign Large Cap Growth	1,060,383		—		1,060,383		—
Foreign Large Cap Value	292,961		—		292,961		—
Total	$	28,184,697	$	282,478	$	27,902,219	$	—

			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:
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	$	—

			Postretirement Benefit Plan Fair Value Measurements - September 30, 2018
	Fair Value		Level 1		Level 2		Level 3
Asset Class:
Cash	$	96,117	$	96,117	$	—	$	—
Mutual Funds
Bonds
Domestic Fixed Income	5,859,588		—		5,859,588		—
Foreign Fixed Income	609,722		—		609,722		—
Equities
Domestic Large Cap Growth	1,926,076		—		1,926,076		—
Domestic Large Cap Value	1,874,643		—		1,874,643		—
Domestic Small/Mid Cap Growth	214,180		—		214,180		—
Domestic Small/Mid Cap Value	210,891		—		210,891		—
Domestic Small/Mid Cap Core	459,363		—		459,363		—
Foreign Large Cap Growth	525,720		—		525,720		—
Foreign Large Cap Value	1,090,851		—		1,090,851		—
Foreign Large Cap Core	28,786		—		28,786		—
Other	29,020		—		29,020		—
Total	$	12,924,957	$	96,117	$	12,828,840	$	—

			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	$	—

Schedule of Expected Future Benefit Payments

The following table reflects expected future benefit payments:

Fiscal year ending September 30	Pension Plan		Postretirement Plan
2019	$	934,935	$	688,340
2020	983,862		685,088
2021	1,042,332		725,587
2022	1,124,774		778,814
2023	1,220,246		834,042
2024-2028	7,346,304		4,230,466

XML

Common Stock Options (Tables)

12 Months Ended

Sep. 30, 2018

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Schedule of Fair Value of Stock Options

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,
	2018	2017	2016
Expected volatility	N/A	26.09%	28.78%
Expected dividends	N/A	3.81%	3.99%
Expected exercise term (years)	N/A	7.00	7.00
Risk-free interest rate	N/A	2.20%	2.10%

Schedule of Stock Option Transactions

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, 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
Options granted	—		—
Options exercised	(1,575	)	12.66
Options expired	—		—
Options forfeited	—		—
Options outstanding, September 30, 2018	100,000		$	14.34	6.6	$	1,237,286
Vested and exercisable at September 30, 2018	100,000		$	14.34	6.6	$	1,237,286

¹Aggregate intrinsic value includes only those options where the exercise price is below the market price.

	Years Ended September 30,
	2018		2017		2016
Weighted-average grant date option fair value	$	—	$	2.89	$	2.69
Stock option expense	—		73,780		64,640
Intrinsic value of options exercised	15,256		99,929		8,418
Proceeds from exercise of stock options	19,945		142,241		41,762

XML

Other Stock Plans (Tables)

12 Months Ended

Sep. 30, 2018

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Director Compensation Activity

The following table reflects the director compensation activity pursuant to the Plan:

	2018				2017			2016
	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	111,893		$	10.56	107,023	$	10.11	100,373	$	9.80
Granted	6,692		26.57		4,870	16.77		6,650	14.79
Vested	(20,283	)	11.20		—	—		—	—
Forfeited	—		—		—	—		—	—
End of year balance	98,302		$	11.51	111,893	$	10.56	107,023	$	10.11

Officer Compensation Activity

The following table reflects the officer compensation activity pursuant to the Restricted Stock Plan:

	2018
	Shares		Weighted-Average Fair Value on Date of Grant
Beginning of year balance	—		$	—
Granted	10,101		26.33
Vested	(3,367	)	26.33
Forfeited	—		—
End of year balance	6,734		$	26.33

XML

Commitments and Contingencies (Tables)

12 Months Ended

Sep. 30, 2018

Commitments and Contingencies Disclosure [Abstract]

Schedule of Volumetric and Pipeline and Storage Capacity Obligations

The table below details the volumetric obligations as of September 30, 2018 for the remainder of the contract period. The asset management contract was renewed for another three year period at essentially the same terms and conditions as the prior agreement. The current asset management agreement will expire in March 2021.

Year	Natural Gas Contracts (In Decatherms)
2018-2019	2,089,578
2019-2020	2,071,061
2020-2021	295,866
Total	4,456,505

The table below details the pipeline and storage capacity obligations as of September 30, 2018 for the remainder of the contract period.

Year	Pipeline and Storage Capacity
2018-2019	$	11,184,000
2019-2020	8,856,915
2020-2021	6,503,953
2021-2022	5,847,945
2022-2023	2,369,904
Thereafter	1,950,134
Total	$	36,712,851

XML

Fair Value Measurements (Tables)

12 Months Ended

Sep. 30, 2018

Fair Value Disclosures [Abstract]

Schedule of Fair Value of Financial Assets and Liabilities Measured on a Recurring Basis

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, 2018 and 2017, respectively:

			Fair Value Measurements - September 30, 2018
	Fair Value		Quoted Prices in Active Markets Level 1		Significant  Other Observable Inputs Level 2		Significant Unobservable Inputs Level 3
Assets:
Interest rate swaps	$	310,563	$	—	$	310,563	$	—
Total	$	310,563	$	—	$	310,563	$	—
Liabilities:
Natural gas purchases	$	693,495	$	—	$	693,495	$	—
Total	$	693,495	$	—	$	693,495	$	—

			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	$	—

Summary of the Fair Value of Financial Assets and Liabilities Not Adjusted to Fair Value

The following table summarizes the fair value of the Company’s financial assets and liabilities that are not adjusted to fair value in the financial statements as of September 30, 2018 and 2017.

			Fair Value Measurements - September 30, 2018
	Carrying Amount		Quoted Prices in Active Markets Level 1		Significant Other Observable  Inputs Level 2		Significant Unobservable Inputs Level 3
Liabilities:
Notes payable	$	63,243,200	$	—	$	—	$	62,435,237
Total	$	63,243,200	$	—	$	—	$	62,435,237

			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:
Notes payable	$	43,812,200	$	—	$	—	$	45,689,238
Total	$	43,812,200	$	—	$	—	$	45,689,238

XML

Quarterly Financial Information (Unaudited) (Tables)

12 Months Ended

Sep. 30, 2018

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Data

Quarterly financial data for the years ended September 30, 2018 and 2017 is summarized as follows:

2018	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Operating revenues	$	18,756,051	$	24,917,973	$	11,889,570	$	9,971,142
Operating income	$	3,675,124	$	5,306,718	$	1,866,223	$	744,980
Net income	$	2,059,462	$	3,465,929	$	1,087,355	$	684,459
Earnings per share of common stock:
Basic	$	0.28	$	0.47	$	0.14	$	0.09
Diluted	$	0.28	$	0.47	$	0.14	$	0.09

2017	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Operating revenues	$	18,788,585	$	21,900,013	$	11,435,824	$	10,172,448
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

XML

Summary of Significant Accounting Policies (Narrative) (Details)	12 Months Ended
	Sep. 30, 2018 USD ($) pipeline segment instrument_held customer	Sep. 30, 2017 USD ($) instrument_held	Sep. 30, 2016 USD ($)	Nov. 01, 2017
Summary Of Significant Accounting Policies [Line Items]
Number of customers | customer	60,200
Number of reportable segments | segment	1
Remaining amount of regulatory assets that did not earn a return during the recovery period	$ 10,247,647
Regulatory utility assets provision, review period	5 years
Composite weighted-average depreciation rate	3.32%	3.29%	3.25%
Unbilled revenue	$ 911,657	$ 965,683
Deferred charges, amortization period	12 months
Number of pipelines | pipeline	2
Unsecured term note	$ 70,604,217	61,603,960
Non-cash change in investment in unconsolidated affiliate	9,087,262	$ 767,710	$ 287,794
Reclassification adjustment for the effect of change in tax law	20,285
Defined Benefit Plans
Summary Of Significant Accounting Policies [Line Items]
Reclassification adjustment for the effect of change in tax law	(234,337)
Interest Rate Swaps
Summary Of Significant Accounting Policies [Line Items]
Reclassification adjustment for the effect of change in tax law	$ 20,285
Natural Gas
Summary Of Significant Accounting Policies [Line Items]
Number of derivative instruments | instrument_held	0	0
Interest Rate Swap
Summary Of Significant Accounting Policies [Line Items]
Number of derivative instruments | instrument_held	1
Minimum
Summary Of Significant Accounting Policies [Line Items]
Useful life (in years)	5 years
Maximum
Summary Of Significant Accounting Policies [Line Items]
Useful life (in years)	76 years
Unsecured term note payable, at 30-day LIBOR plus 0.90%, November 1, 2021 | Roanoke Gas | Unsecured Debt
Summary Of Significant Accounting Policies [Line Items]
Unsecured term note	$ 7,000,000
Fixed rate related to interest rate swap				2.30%

XML

Summary of Significant Accounting Policies (Schedule of Regulatory Assets and Liabilities) (Details) - USD ($)	Sep. 30, 2018	Sep. 30, 2017
Regulatory Assets [Line Items]
Noncurrent regulatory assets	$ 8,862,147	$ 11,796,260
Total regulatory assets	10,259,592	12,715,831
Regulatory Liabilities [Line Items]
Total regulatory liabilities	31,019,866	17,778,770
Over-recovery of gas costs
Regulatory Liabilities [Line Items]
Current regulatory liabilities	0	1,438,074
Over-recovery of SAVE Plan revenues
Regulatory Liabilities [Line Items]
Current regulatory liabilities	670,034	215,514
Rate refund
Regulatory Liabilities [Line Items]
Current regulatory liabilities	1,320,167	0
Asset retirement obligations
Regulatory Liabilities [Line Items]
Noncurrent regulatory liabilities	6,417,948	6,069,993
Regulatory cost of retirement obligations
Regulatory Liabilities [Line Items]
Noncurrent regulatory liabilities	11,163,981	10,055,189
Regulatory liability - deferred income taxes
Regulatory Liabilities [Line Items]
Noncurrent regulatory liabilities	11,447,736	0
Accrued WNA revenues
Regulatory Assets [Line Items]
Current regulatory assets	169,602	248,840
Under-recovery of gas costs
Regulatory Assets [Line Items]
Current regulatory assets	922,898	0
Accrued pension and postretirement medical
Regulatory Assets [Line Items]
Current regulatory assets	293,000	658,786
Noncurrent regulatory assets	5,704,718	8,643,524
Utility property, in service, other
Regulatory Assets [Line Items]
Noncurrent regulatory assets	11,945	11,945
Premium on early retirement of debt
Regulatory Assets [Line Items]
Noncurrent regulatory assets	1,826,995	1,941,182
Other
Regulatory Assets [Line Items]
Noncurrent regulatory assets	$ 1,330,434	$ 1,211,554

XML

Summary of Significant Accounting Policies (Components of Utility Plant) (Details) - USD ($)	Sep. 30, 2018	Sep. 30, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Distribution and transmission	$ 196,778,546	$ 177,845,619
LNG storage	13,413,175	13,299,288
General and miscellaneous	14,662,599	13,078,807
Total utility plant in service	$ 224,854,320	$ 204,223,714

XML

Summary of Significant Accounting Policies (Summary of Asset Retirement Obligations) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	$ 6,069,993	$ 5,682,556
Liabilities incurred	79,608	65,556
Liabilities settled	(126,907)	(137,304)
Accretion	332,537	312,503
Revisions to estimated cash flows	62,717	146,682
Ending balance	$ 6,417,948	$ 6,069,993

XML

Summary of Significant Accounting Policies (Reconciliation of Changes in Allowance for Doubtful Accounts) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Allowance for Doubtful Accounts Receivable [Roll Forward]
Beginning balance	$ 99,456	$ 76,934	$ 52,721
Provision for doubtful accounts	169,096	84,587	14,074
Recoveries of accounts written off	78,919	110,725	137,055
Accounts written off	(243,898)	(172,790)	(126,916)
Ending balance	$ 103,573	$ 99,456	$ 76,934

XML

Summary of Significant Accounting Policies (Reconciliation of Basic and Diluted Earnings Per Share) (Details) - USD ($)	3 Months Ended								12 Months Ended
	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Net income	$ 684,459	$ 1,087,355	$ 3,465,929	$ 2,059,462	$ 159,886	$ 615,562	$ 3,225,199	$ 2,232,218	$ 7,297,205	$ 6,232,865	$ 5,806,866
Weighted-average common shares (in shares)									7,649,025	7,218,686	7,149,906
Effect of dilutive securities:
Options to purchase common stock (in shares)									46,687	37,360	9,857
Diluted average common shares (in shares)									7,695,712	7,256,046	7,159,763
Earnings Per Share of Common Stock:
Basic (in usd per share)	$ 0.09	$ 0.14	$ 0.47	$ 0.28	$ 0.02	$ 0.09	$ 0.45	$ 0.31	$ 0.95	$ 0.86	$ 0.81
Diluted (in usd per share)	$ 0.09	$ 0.14	$ 0.47	$ 0.28	$ 0.02	$ 0.08	$ 0.45	$ 0.31	$ 0.95	$ 0.86	$ 0.81

XML

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Schedule of Interest Rate Derivative) (Details) - USD ($)	Sep. 30, 2018	Sep. 30, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Interest rate swap, current assets	$ 100,723	$ 26,777
Interest rate swap, other assets	209,840	90,066
Total derivatives designated as hedging instruments	$ 310,563	$ 116,843

XML

Summary of Significant Accounting Policies (Summary of Other Comprehensive Income) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Before Tax Amount
Unrealized gains	$ 217,773	$ 116,843
Transfer of realized gains to interest expense	(24,053)
Net interest rate swap	193,720	116,843
Net gain (loss) arising during period	595,570	1,715,505	$ (560,887)
Amortization of actuarial gains	(23,887)	256,234	221,070
Net defined benefit plans	571,683	1,971,739	(339,817)
Other comprehensive income (loss)	765,403	2,088,582	(339,817)
Tax (Expense) or Benefit
Unrealized gains	(62,807)	(44,354)
Transfer of realized gains to interest expense	6,937
Net interest rate swap	(55,870)	(44,354)
Net gain (loss) arising during period	(171,775)	(651,892)	213,137
Amortization of actuarial gains	6,890	(97,369)	(84,006)
Net defined benefit plans	(164,885)	(749,261)	129,131
Other comprehensive income (loss)	(220,755)	(793,615)	129,131
Net of Tax Amount
Unrealized gains	154,966	72,489
Transfer of realized gains to interest expense	(17,116)
Net interest rate swap	137,850	72,489	0
Net gain (loss) arising during period	423,795	1,063,613	(347,750)
Amortization of actuarial gains	(16,997)	158,865	137,064
Net defined benefit plans	406,798	1,222,478	(210,686)
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX	$ 544,648	$ 1,294,967	$ (210,686)

XML

Summary of Significant Accounting Policies (Components of Accumulated Comprehensive Income (Loss)) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Increase (Decrease) in Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	$ 60,040,472	$ 55,667,072	$ 52,840,991
Other comprehensive income (loss)	544,648	1,294,967	(210,686)
Reclassification adjustment for the effect of change in tax law	20,285
Ending balance	79,583,112	60,040,472	55,667,072
Interest Rate Swaps
Increase (Decrease) in Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	72,489	0	0
Other comprehensive income (loss)	137,850	72,489	0
Reclassification adjustment for the effect of change in tax law	20,285
Ending balance	230,624	72,489	0
Defined Benefit Plans
Increase (Decrease) in Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	(1,274,753)	(2,497,231)	(2,286,545)
Other comprehensive income (loss)	406,798	1,222,478	(210,686)
Reclassification adjustment for the effect of change in tax law	(234,337)
Ending balance	(1,102,292)	(1,274,753)	(2,497,231)
Accumulated Other Comprehensive Income (Loss)
Increase (Decrease) in Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	(1,202,264)	(2,497,231)	(2,286,545)
Other comprehensive income (loss)	544,648	1,294,967	(210,686)
Reclassification adjustment for the effect of change in tax law	(214,052)
Ending balance	$ (871,668)	$ (1,202,264)	$ (2,497,231)

XML

Stock Issue (Details) - USD ($)	1 Months Ended	12 Months Ended
	Mar. 31, 2018	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Equity [Abstract]
Equity offering, common stock issued (in shares)	700,000	752,194	47,187	66,887
Schedule of Capitalization, Equity [Line Items]
Equity offering, net proceeds invested in subsidiary		$ 16,520,016	$ 967,698	$ 1,031,194
Roanoke Gas
Schedule of Capitalization, Equity [Line Items]
Equity offering, net proceeds invested in subsidiary	$ 15,109,541

XML

Regulatory Matters (Details) - USD ($)			12 Months Ended
	Oct. 10, 2018	Sep. 27, 2018	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Public Utilities, General Disclosures [Line Items]
Regulatory liability - deferred income taxes			$ 11,447,736	$ 0
Regulatory asset - deferred income taxes			$ 1,300,000
Corporate federal income tax rate			24.30%	34.00%	34.00%
Rate refund			$ 1,320,167	$ 0
Roanoke Gas
Public Utilities, General Disclosures [Line Items]
Regulatory liability - deferred income taxes			11,400,000
Depreciation regulatory liability - deferred income taxes			$ 12,700,000
Regulatory liability, refund period (in years)			28 years
Regulatory asset - deferred income taxes			$ 1,300,000
Rate refund			$ 1,320,167
General Rate Case | Virginia State Corporate Commission (SCC) | Roanoke Gas | Subsequent Event
Public Utilities, General Disclosures [Line Items]
Requested non-gas rates increase	$ 10,500,000
SAVE Program component of requested non-gas rates increase (in dollars)	$ 4,700,000
SAVE Plan and Rider Filing | Virginia State Corporate Commission (SCC) | Roanoke Gas
Public Utilities, General Disclosures [Line Items]
Approved SAVE rates		$ 362,000
Refund of SAVE over collection		$ 163,000

XML

Other Investments (Narrative) (Details) Bcf in Millions	1 Months Ended	12 Months Ended
	Apr. 30, 2018 USD ($) mi	Sep. 30, 2018 USD ($) debt_instrument	Sep. 30, 2017 USD ($)	Oct. 31, 2015 USD ($) Bcf
Investment [Line Items]
Investments unconsolidated affiliate		$ 28,507,146	$ 7,445,106
Promissory Notes term		20 years
RGC Midstream, LLC
Investment [Line Items]
Equity interest (as a percent)	1.00%
Number of unsecured Promissory Notes funding the investment | debt_instrument		2
Promissory Notes term		5 years
MVP Investment | RGC Midstream, LLC
Investment [Line Items]
Equity interest (as a percent)				1.00%
Pipeline capacity (in bcf per day) | Bcf				2
Total project cost		$ 4,600,000,000		$ 3,700,000,000
Total estimated investment		$ 46,000,000
MVP Southgate Investment | RGC Midstream, LLC
Investment [Line Items]
Length, planned natural gas pipeline (in miles) | mi	70
Ownership percentage (less than)	1.00%
MVP Southgate Investment | Minimum | RGC Midstream, LLC
Investment [Line Items]
Total project cost	$ 350,000,000
Total estimated investment	1,800,000
MVP Southgate Investment | Maximum | RGC Midstream, LLC
Investment [Line Items]
Total project cost	500,000,000
Total estimated investment	$ 2,500,000

XML

Other Investments (Schedule of Other Investments) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Other Investments [Abstract]
Investment in unconsolidated affiliate	$ 28,507,146	$ 7,445,106
Capital contributions payable	10,142,766	1,055,504
Equity in earnings of unconsolidated affiliate	938,531	421,646	$ 152,864
Change in investment in unconsolidated affiliate [Abstract]
Cash investment	11,036,247	2,759,346	3,055,746
Change in accrued capital calls	9,087,262	767,710	287,794
Equity in earnings of unconsolidated affiliate	938,531	421,646	152,864
Change in investment in unconsolidated affiliate	$ 21,062,040	$ 3,948,702	$ 3,496,404

XML

Line-of-Credit (Narrative) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Debt Instrument [Line Items]
Promissory Notes term	20 years
Interest rate on unused line-of-credit (as a percent)	0.15%	0.15%	0.15%
Debt covenant, maximum ratio of total long-term debt to total capitalization	65.00%
Roanoke Gas | Line of Credit | Line-of-credit, at 30-day LIBOR plus 1.00%, due March 31, 2020
Debt Instrument [Line Items]
Promissory Notes term	2 years
Line-of-credit, maximum borrowing limit	$ 25,000,000
Interest rate on unused line-of-credit (as a percent)	0.15%
Minimum interest coverage ratio	1.5
Debt covenant, maximum ratio of total long-term debt to total capitalization	65.00%
30-day LIBOR | Roanoke Gas | Line of Credit | Line-of-credit, at 30-day LIBOR plus 1.00%, due March 31, 2020
Debt Instrument [Line Items]
Variable rate basis points (as a percent)	1.00%

XML

Line-of-Credit (Summary of Available Limits Under Line of Credit Agreement) (Details)	Sep. 30, 2018 USD ($)
September 30, 2018
Short-term Debt [Line Items]
Available Line-of-Credit	$ 20,000,000
November 21, 2018
Short-term Debt [Line Items]
Available Line-of-Credit	21,000,000
March 1, 2019
Short-term Debt [Line Items]
Available Line-of-Credit	17,000,000
July 22, 2019
Short-term Debt [Line Items]
Available Line-of-Credit	22,000,000
September 22, 2019
Short-term Debt [Line Items]
Available Line-of-Credit	25,000,000
March 1, 2020
Short-term Debt [Line Items]
Available Line-of-Credit	$ 22,000,000

XML

Line-of-Credit (Summary of Line-of-Credit) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Debt Disclosure [Abstract]
Available line-of-credit at year-end	$ 20,000,000	$ 21,000,000	$ 24,000,000
Outstanding balance at year-end	7,361,017	17,791,760	14,556,785
Highest month-end balance outstanding	17,054,377	17,791,760	15,246,089
Average daily balance	$ 6,730,334	$ 10,936,114	$ 9,620,914
Average rate of interest during year on outstanding balances (as a percent)	2.53%	1.92%	1.40%
Interest rate at year-end (as a percent)	3.26%	2.23%	1.53%
Interest rate on unused line-of-credit (as a percent)	0.15%	0.15%	0.15%

XML

Long-Term Debt (Narrative) (Details)			1 Months Ended	6 Months Ended	12 Months Ended
	Nov. 01, 2017 USD ($)	Oct. 02, 2017 USD ($)	Apr. 30, 2018 USD ($) instrument_held	Mar. 31, 2018 USD ($)	Sep. 30, 2018 USD ($) debt_instrument	Sep. 30, 2017 USD ($)
Debt Instrument [Line Items]
Promissory Notes term					20 years
Unamortized loss on early retirement of debt deferred as regulatory asset					$ 1,826,995	$ 1,941,182
Unamortized loss on early retirement of debt, amortization period					20 years
Debt covenant, maximum ratio of total long-term debt to total capitalization					65.00%
Roanoke Gas | Unsecured Debt | Unsecured term notes payable, at 3.58%, due October 2, 2027
Debt Instrument [Line Items]
Promissory Notes term		10 years
Debt instrument, face amount		$ 8,000,000
Stated percentage rate		3.58%			3.58%
Debt covenant, maximum ratio of priority indebtedness to total assets					15.00%
Roanoke Gas | Unsecured Debt | Unsecured term note payable, at 30-day LIBOR plus 0.90%, November 1, 2021
Debt Instrument [Line Items]
Promissory Notes term	5 years
Debt instrument, face amount	$ 7,000,000
Fixed rate related to interest rate swap	2.30%
Debt covenant, maximum ratio of priority indebtedness to total assets					15.00%
Roanoke Gas | Unsecured Debt | Unsecured term note payable, at 30-day LIBOR plus 0.90%, November 1, 2021 | 30-day LIBOR
Debt Instrument [Line Items]
Variable rate basis points (as a percent)					0.90%
Roanoke Gas | Unsecured Senior Notes | Unsecured senior notes payable, at 4.26%, due on September 18, 2034
Debt Instrument [Line Items]
Stated percentage rate					4.26%
Debt covenant, maximum ratio of priority indebtedness to total assets					15.00%
RGC Midstream, LLC
Debt Instrument [Line Items]
Promissory Notes term					5 years
Number of unsecured Promissory Notes funding the investment | debt_instrument					2
Equity interest (as a percent)			1.00%
RGC Midstream, LLC | Unsecured Debt | Unsecured term notes payable, at 30-day LIBOR plus 1.35% due December 29, 2020
Debt Instrument [Line Items]
Promissory Notes term			5 years
Debt instrument, face amount			$ 38,000,000
Number of unsecured Promissory Notes funding the investment | instrument_held			2
Equity investment required by credit agreement				$ 5,000,000
Debt covenant, maximum ratio of priority indebtedness to total assets					15.00%
RGC Midstream, LLC | Unsecured Debt | Unsecured term notes payable, at 30-day LIBOR plus 1.35% due December 29, 2020 | 30-day LIBOR
Debt Instrument [Line Items]
Variable rate basis points (as a percent)			1.35%		1.35%

XML

Long-Term Debt (Schedule of Long-Term Debt) (Details) - USD ($)	1 Months Ended	12 Months Ended
	Apr. 30, 2018	Sep. 30, 2018	Oct. 02, 2017	Sep. 30, 2017	Sep. 30, 2016
Principal
Notes payable		$ 63,243,200		$ 43,812,200
Line-of-credit		7,361,017		17,791,760	$ 14,556,785
Total		70,604,217		61,603,960
Unamortized Debt Issuance Costs		282,281		291,949
Notes Payable
Principal
Notes payable		63,243,200		43,812,200
Unamortized Debt Issuance Costs		282,281		291,949
Roanoke Gas | Unsecured Senior Notes | Unsecured senior notes payable, at 4.26%, due on September 18, 2034
Principal
Notes payable		30,500,000		30,500,000
Unamortized Debt Issuance Costs		$ 154,465		164,119
Stated percentage rate		4.26%
Roanoke Gas | Unsecured Debt | Unsecured term note payable, at 30-day LIBOR plus 0.90%, November 1, 2021
Principal
Notes payable		$ 7,000,000		7,000,000
Total		7,000,000
Unamortized Debt Issuance Costs		$ 10,283		13,618
Roanoke Gas | Unsecured Debt | Unsecured term note payable, at 30-day LIBOR plus 0.90%, November 1, 2021 | 30-day LIBOR
Principal
Variable rate basis points (as a percent)		0.90%
Roanoke Gas | Unsecured Debt | Unsecured term notes payable, at 3.58% due on October 2, 2027
Principal
Notes payable		$ 8,000,000		0
Unamortized Debt Issuance Costs		$ 43,343		48,160
Stated percentage rate		3.58%	3.58%
Roanoke Gas | Line of Credit | Line-of-credit, at 30-day LIBOR plus 1.00%, due March 31, 2020
Principal
Line-of-credit		$ 7,361,017		17,791,760
Unamortized Debt Issuance Costs		$ 0		0
Roanoke Gas | Line of Credit | Line-of-credit, at 30-day LIBOR plus 1.00%, due March 31, 2020 | 30-day LIBOR
Principal
Variable rate basis points (as a percent)		1.00%
RGC Midstream, LLC | Unsecured Debt | Unsecured term notes payable, at 30-day LIBOR plus 1.35% due December 29, 2020
Principal
Notes payable		$ 17,743,200		6,312,200
Unamortized Debt Issuance Costs		$ 74,190		$ 66,052
RGC Midstream, LLC | Unsecured Debt | Unsecured term notes payable, at 30-day LIBOR plus 1.35% due December 29, 2020 | 30-day LIBOR
Principal
Variable rate basis points (as a percent)	1.35%	1.35%

XML

Long-Term Debt (Summary of Aggregate Maturities of Long-Term Debt) (Details) - USD ($)	Sep. 30, 2018	Sep. 30, 2017
Maturities
2019	$ 0
2020	7,361,017
2021	17,743,200
2022	7,000,000
2023	0
Thereafter	38,500,000
Total	$ 70,604,217	$ 61,603,960

XML

Income Taxes (Narrative) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Income Tax Disclosure [Abstract]
Corporate federal income tax rate	24.30%	34.00%	34.00%
Deferred tax liability decrease, tax reform	$ 9,000,000
Regulatory liability - deferred income taxes, gross	11,800,000
Gross-up to pre-tax basis, tax reform	3,000,000
Revaluation of unregulated deferred taxes to 21%	256,444	$ 0	$ 0
Depreciation regulatory liability - deferred income taxes, gross	13,100,000
Regulatory asset - deferred income taxes	$ 1,300,000
Prior year deferred taxes reflected in the current year tax provision			$ 1,283,925

XML

Income Taxes (Details of Income Tax Expense) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Current income taxes:
Federal	$ 1,831,085	$ 72,368	$ (1,216,745)
State	308,057	407,643	415,975
Total current income taxes	2,139,142	480,011	(800,770)
Deferred income taxes:
Federal	440,282	3,129,925	4,302,906
State	315,712	195,454	164,048
Total deferred income taxes	755,994	3,325,379	4,466,954
Total income tax expense	$ 2,895,136	$ 3,805,390	$ 3,666,184

XML

Income Taxes (Reconciliation of Income Tax Expense Based on Federal Statutory Rate) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Income Tax Disclosure [Abstract]
Income before income taxes	$ 10,192,341	$ 10,038,255	$ 9,473,050
Corporate federal income tax rate	24.30%	34.00%	34.00%
Income tax expense computed at the federal statutory rate	$ 2,476,739	$ 3,413,007	$ 3,220,837
State income taxes, net of federal income tax benefit	472,193	398,044	382,815
Revaluation of unregulated deferred taxes to 21%	256,444	0	0
Net amortization of excess deferred taxes on regulated operations	(264,106)	0	0
Other, net	(46,134)	(5,661)	62,532
Total income tax expense	$ 2,895,136	$ 3,805,390	$ 3,666,184

XML

Income Taxes (Schedule of Deferred Tax Assets and Liabilities) (Details) - USD ($)	Sep. 30, 2018	Sep. 30, 2017
Deferred tax assets:
Allowance for uncollectibles	$ 26,658	$ 37,752
Accrued pension and postretirement medical benefits	897,834	1,747,429
Regulatory effect of change in federal income tax rate	2,946,649	0
Accrued vacation	160,001	239,414
Over-recovery of gas costs	0	545,894
Costs of gas held in storage	591,899	1,009,206
Deferred compensation	716,843	824,281
Rate refund	339,812	0
Other	298,129	348,833
Total gross deferred tax assets	5,977,825	4,752,809
Deferred tax liabilities:
Utility plant	17,982,215	27,630,486
Under-recovery of gas costs	255,570	0
MVP investment	245,678	154,817
Other	79,939	44,354
Total gross deferred tax liabilities	18,563,402	27,829,657
Net deferred tax liability	$ 12,585,577	$ 23,076,848

XML

Employee Benefit Plans (Narrative) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Defined Benefit Plan Disclosure [Line Items]
Expected amount of accumulated other comprehensive loss recognized in net periodic benefit costs		$ 10,000
Expected amount of deferred regulatory assets to be recognized in net periodic benefit costs		293,000
Company's matching contribution		$ 338,066	$ 361,702	$ 353,793
First Portion Match
Defined Benefit Plan Disclosure [Line Items]
Employers percentage match of employees match percentage		100.00%
Percentage of employee's gross pay that is matched by the employer		4.00%
Second Portion Match
Defined Benefit Plan Disclosure [Line Items]
Employers percentage match of employees match percentage		50.00%
Percentage of employee's gross pay that is matched by the employer		2.00%
Additional discretionary payment to employees hired beginning January 2017
Defined Benefit Plan Disclosure [Line Items]
Company's matching contribution		$ 9,637
Minimum
Defined Benefit Plan Disclosure [Line Items]
Employee contribution percent		1.00%
Maximum
Defined Benefit Plan Disclosure [Line Items]
Employee contribution percent		50.00%
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Years until benefits are fully vested		5 years
Expected long-term rate of return on plan assets		7.00%	7.00%	7.00%
Expected employer contributions in next fiscal year		$ 800,000
Pension Plan | Scenario, Forecast
Defined Benefit Plan Disclosure [Line Items]
Expected long-term rate of return on plan assets	5.50%
Pension Plan | Equity securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets, target allocation, percentage		40.00%	60.00%
Postretirement Plan
Defined Benefit Plan Disclosure [Line Items]
Minimum service requirement for postretirement benefit vesting		10 years
Retirement age requirement, postretirement plan		55 years
Expected long-term rate of return on plan assets		4.84%	4.84%	4.89%
Expected employer contributions in next fiscal year		$ 300,000
Postretirement Plan | Scenario, Forecast
Defined Benefit Plan Disclosure [Line Items]
Expected long-term rate of return on plan assets	4.30%
Postretirement Plan | Equity securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets, target allocation, percentage		50.00%

XML

Employee Benefit Plans (Schedule of Changes in Benefit Obligations and Fair Value of Plan Assets, Funded Status of the Plan, and Amount Recognized in the Financial Statements) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Change in fair value of plan assets:
Noncurrent liabilities	$ (3,947,967)	$ (8,214,326)
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	25,199,762	25,481,993
Change in benefit obligation:
Benefit obligation at beginning of year	29,657,347	29,494,950
Service cost	665,235	706,677	$ 694,375
Interest cost	1,088,180	995,598	1,132,776
Actuarial gain	(1,727,767)	(824,361)
Benefit payments, net of retiree contributions	(832,696)	(715,517)
Benefit obligation at end of year	28,850,299	29,657,347	29,494,950
Change in fair value of plan assets:
Fair value of plan assets at beginning of year	26,418,671	23,113,057
Actual return on plan assets, net of taxes	1,798,722	3,021,131
Employer contributions	800,000	1,000,000
Benefit payments, net of retiree contributions	(832,696)	(715,517)
Fair value of plan assets at end of year	28,184,697	26,418,671	23,113,057
Funded status	(665,602)	(3,238,676)
Noncurrent liabilities	(665,602)	(3,238,676)
Net actuarial loss, net of tax	361,215	572,740
Total amounts included in other comprehensive loss, net of tax	361,215	572,740
Net actuarial loss	3,894,221	5,471,547
Amounts recognized as regulatory assets	3,894,221	5,471,547
Postretirement Plan
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	16,207,322	17,666,812
Change in benefit obligation:
Benefit obligation at beginning of year	17,666,812	18,504,710
Service cost	167,220	183,267	148,018
Interest cost	640,602	626,822	624,579
Actuarial gain	(1,774,320)	(1,199,722)
Benefit payments, net of retiree contributions	(492,992)	(448,265)
Benefit obligation at end of year	16,207,322	17,666,812	18,504,710
Change in fair value of plan assets:
Fair value of plan assets at beginning of year	12,691,162	11,122,783
Actual return on plan assets, net of taxes	426,787	1,016,644
Employer contributions	300,000	1,000,000
Benefit payments, net of retiree contributions	(492,992)	(448,265)
Fair value of plan assets at end of year	12,924,957	12,691,162	$ 11,122,783
Funded status	(3,282,365)	(4,975,650)
Noncurrent liabilities	(3,282,365)	(4,975,650)
Net actuarial loss, net of tax	741,077	702,013
Total amounts included in other comprehensive loss, net of tax	741,077	702,013
Net actuarial loss	2,103,497	3,830,763
Amounts recognized as regulatory assets	$ 2,103,497	$ 3,830,763

XML

Employee Benefit Plans (Schedule of Actuarial Assumptions Used) (Details)	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Pension Plan
Assumptions used to determine benefit obligations:
Discount rate	4.11%	3.72%	3.42%
Expected rate of compensation increase	4.00%	4.00%	4.00%
Assumptions used to determine benefit costs:
Discount rate	3.72%	3.42%	4.22%
Expected long-term rate of return on plan assets	7.00%	7.00%	7.00%
Expected rate of compensation increase	4.00%	4.00%	4.00%
Postretirement Plan
Assumptions used to determine benefit obligations:
Discount rate	4.09%	3.69%	3.33%
Assumptions used to determine benefit costs:
Discount rate	3.69%	3.33%	4.15%
Expected long-term rate of return on plan assets	4.84%	4.84%	4.89%

XML

Employee Benefit Plans (Schedule of Components of Net Periodic Cost) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 665,235	$ 706,677	$ 694,375
Interest cost	1,088,180	995,598	1,132,776
Expected return on plan assets	(1,862,838)	(1,616,412)	(1,492,241)
Recognized loss	351,030	662,180	501,678
Net periodic benefit cost	241,607	748,043	836,588
Postretirement Plan
Defined Benefit Plan Disclosure [Line Items]
Service cost	167,220	183,267	148,018
Interest cost	640,602	626,822	624,579
Expected return on plan assets	(623,381)	(571,513)	(507,858)
Recognized loss	283,868	429,758	250,173
Net periodic benefit cost	$ 468,309	$ 668,334	$ 514,912

XML

Employee Benefit Plans (Summary of Assumed Health Care Cost Trend Rates Used) (Details)	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Pre 65
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for next year	7.00%	7.00%	7.50%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	5.00%	5.00%	5.00%
Year that the rate reaches the ultimate trend rate	2026	2021	2021
Post 65
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for next year	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%
Year that the rate reaches the ultimate trend rate	2018	2017	2016

XML

Employee Benefit Plans (Effect of a 1% Change in Health Care Cost Trend Rate Assumptions) (Details) $ in Thousands	12 Months Ended
	Sep. 30, 2018 USD ($)
1% Increase
Effect on total service and interest cost components	$ 155
Effect on accumulated postretirement benefit obligation	2,487
1% Decrease
Effect on total service and interest cost components	(123)
Effect on accumulated postretirement benefit obligation	$ (2,025)

XML

Employee Benefit Plans (Schedule of Target and Actual Asset Allocation) (Details)	Sep. 30, 2018	Sep. 30, 2017
Pension Plan | Equity securities
Defined Benefit Plan Disclosure [Line Items]
Target	40.00%	60.00%
Actual	40.00%	63.00%
Pension Plan | Debt securities
Defined Benefit Plan Disclosure [Line Items]
Target	60.00%
Actual	59.00%	36.00%
Pension Plan | Cash
Defined Benefit Plan Disclosure [Line Items]
Target	0.00%
Actual	1.00%	1.00%
Pension Plan | Other
Defined Benefit Plan Disclosure [Line Items]
Target	0.00%
Actual	0.00%	0.00%
Postretirement Plan | Equity securities
Defined Benefit Plan Disclosure [Line Items]
Target	50.00%
Actual	49.00%	51.00%
Postretirement Plan | Debt securities
Defined Benefit Plan Disclosure [Line Items]
Target	50.00%
Actual	50.00%	48.00%
Postretirement Plan | Cash
Defined Benefit Plan Disclosure [Line Items]
Target	0.00%
Actual	1.00%	1.00%
Postretirement Plan | Other
Defined Benefit Plan Disclosure [Line Items]
Target	0.00%
Actual	0.00%	0.00%

XML

Employee Benefit Plans (Summary of Fair Value Classifications of Benefit Plan Assets ) (Details) - USD ($)	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 28,184,697	$ 26,418,671	$ 23,113,057
Pension Plan | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	282,478	265,100
Pension Plan | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	27,902,219	26,153,571
Pension Plan | Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Pension Plan | Cash
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	282,478	265,100
Pension Plan | Cash | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	282,478	265,100
Pension Plan | Cash | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Pension Plan | Cash | Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Pension Plan | Common and Collective Trust and Pooled Funds | Liability Driven Investment
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	16,504,956	9,635,998
Pension Plan | Common and Collective Trust and Pooled Funds | Liability Driven Investment | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Pension Plan | Common and Collective Trust and Pooled Funds | Liability Driven Investment | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	16,504,956	9,635,998
Pension Plan | Common and Collective Trust and Pooled Funds | Liability Driven Investment | Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Pension Plan | Common and Collective Trust and Pooled Funds | Domestic Large Cap Growth
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	3,449,486	5,068,282
Pension Plan | Common and Collective Trust and Pooled Funds | Domestic Large Cap Growth | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Pension Plan | Common and Collective Trust and Pooled Funds | Domestic Large Cap Growth | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	3,449,486	5,068,282
Pension Plan | Common and Collective Trust and Pooled Funds | Domestic Large Cap Growth | Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Pension Plan | Common and Collective Trust and Pooled Funds | Domestic Large Cap Value
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	3,381,285	5,046,530
Pension Plan | Common and Collective Trust and Pooled Funds | Domestic Large Cap Value | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Pension Plan | Common and Collective Trust and Pooled Funds | Domestic Large Cap Value | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	3,381,285	5,046,530
Pension Plan | Common and Collective Trust and Pooled Funds | Domestic Large Cap Value | Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Pension Plan | Common and Collective Trust and Pooled Funds | Domestic Small/Mid Cap Core
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	1,685,352	2,393,221
Pension Plan | Common and Collective Trust and Pooled Funds | Domestic Small/Mid Cap Core | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Pension Plan | Common and Collective Trust and Pooled Funds | Domestic Small/Mid Cap Core | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	1,685,352	2,393,221
Pension Plan | Common and Collective Trust and Pooled Funds | Domestic Small/Mid Cap Core | Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Pension Plan | Common and Collective Trust and Pooled Funds | Foreign Large Cap Value
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	1,527,796	2,139,733
Pension Plan | Common and Collective Trust and Pooled Funds | Foreign Large Cap Value | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Pension Plan | Common and Collective Trust and Pooled Funds | Foreign Large Cap Value | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	1,527,796	2,139,733
Pension Plan | Common and Collective Trust and Pooled Funds | Foreign Large Cap Value | Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Pension Plan | Mutual Funds | Foreign Large Cap Growth
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	1,060,383	399,909
Pension Plan | Mutual Funds | Foreign Large Cap Growth | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Pension Plan | Mutual Funds | Foreign Large Cap Growth | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	1,060,383	399,909
Pension Plan | Mutual Funds | Foreign Large Cap Growth | Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Pension Plan | Mutual Funds | Foreign Large Cap Value
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	292,961	398,995
Pension Plan | Mutual Funds | Foreign Large Cap Value | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Pension Plan | Mutual Funds | Foreign Large Cap Value | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	292,961	398,995
Pension Plan | Mutual Funds | Foreign Large Cap Value | Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Pension Plan | Mutual Funds | Foreign Large Cap Core
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets		1,070,903
Pension Plan | Mutual Funds | Foreign Large Cap Core | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets		0
Pension Plan | Mutual Funds | Foreign Large Cap Core | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets		1,070,903
Pension Plan | Mutual Funds | Foreign Large Cap Core | Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets		0
Postretirement Plan
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	12,924,957	12,691,162	$ 11,122,783
Postretirement Plan | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	96,117	64,616
Postretirement Plan | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	12,828,840	12,626,546
Postretirement Plan | Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Postretirement Plan | Cash
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	96,117	64,616
Postretirement Plan | Cash | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	96,117	64,616
Postretirement Plan | Cash | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Postretirement Plan | Cash | Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Postretirement Plan | Mutual Funds | Domestic Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	5,859,588	5,727,258
Postretirement Plan | Mutual Funds | Domestic Fixed Income | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Postretirement Plan | Mutual Funds | Domestic Fixed Income | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	5,859,588	5,727,258
Postretirement Plan | Mutual Funds | Domestic Fixed Income | Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Postretirement Plan | Mutual Funds | Foreign Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	609,722	359,460
Postretirement Plan | Mutual Funds | Foreign Fixed Income | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Postretirement Plan | Mutual Funds | Foreign Fixed Income | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	609,722	359,460
Postretirement Plan | Mutual Funds | Foreign Fixed Income | Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Postretirement Plan | Mutual Funds | Domestic Large Cap Growth
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	1,926,076	1,998,971
Postretirement Plan | Mutual Funds | Domestic Large Cap Growth | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Postretirement Plan | Mutual Funds | Domestic Large Cap Growth | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	1,926,076	1,998,971
Postretirement Plan | Mutual Funds | Domestic Large Cap Growth | Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Postretirement Plan | Mutual Funds | Domestic Large Cap Value
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	1,874,643	1,998,714
Postretirement Plan | Mutual Funds | Domestic Large Cap Value | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Postretirement Plan | Mutual Funds | Domestic Large Cap Value | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	1,874,643	1,998,714
Postretirement Plan | Mutual Funds | Domestic Large Cap Value | Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Postretirement Plan | Mutual Funds | Domestic Small/Mid Cap Growth
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	214,180	209,332
Postretirement Plan | Mutual Funds | Domestic Small/Mid Cap Growth | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Postretirement Plan | Mutual Funds | Domestic Small/Mid Cap Growth | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	214,180	209,332
Postretirement Plan | Mutual Funds | Domestic Small/Mid Cap Growth | Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Postretirement Plan | Mutual Funds | Domestic Small/Mid Cap Value
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	210,891	209,630
Postretirement Plan | Mutual Funds | Domestic Small/Mid Cap Value | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Postretirement Plan | Mutual Funds | Domestic Small/Mid Cap Value | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	210,891	209,630
Postretirement Plan | Mutual Funds | Domestic Small/Mid Cap Value | Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Postretirement Plan | Mutual Funds | Domestic Small/Mid Cap Core
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	459,363	455,867
Postretirement Plan | Mutual Funds | Domestic Small/Mid Cap Core | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Postretirement Plan | Mutual Funds | Domestic Small/Mid Cap Core | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	459,363	455,867
Postretirement Plan | Mutual Funds | Domestic Small/Mid Cap Core | Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Postretirement Plan | Mutual Funds | Foreign Large Cap Growth
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	525,720	39,107
Postretirement Plan | Mutual Funds | Foreign Large Cap Growth | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Postretirement Plan | Mutual Funds | Foreign Large Cap Growth | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	525,720	39,107
Postretirement Plan | Mutual Funds | Foreign Large Cap Growth | Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Postretirement Plan | Mutual Funds | Foreign Large Cap Value
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	1,090,851	1,079,766
Postretirement Plan | Mutual Funds | Foreign Large Cap Value | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Postretirement Plan | Mutual Funds | Foreign Large Cap Value | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	1,090,851	1,079,766
Postretirement Plan | Mutual Funds | Foreign Large Cap Value | Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Postretirement Plan | Mutual Funds | Foreign Large Cap Core
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	28,786	511,298
Postretirement Plan | Mutual Funds | Foreign Large Cap Core | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Postretirement Plan | Mutual Funds | Foreign Large Cap Core | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	28,786	511,298
Postretirement Plan | Mutual Funds | Foreign Large Cap Core | Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Postretirement Plan | Mutual Funds | Other
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	29,020	37,143
Postretirement Plan | Mutual Funds | Other | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Postretirement Plan | Mutual Funds | Other | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	29,020	37,143
Postretirement Plan | Mutual Funds | Other | Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 0	$ 0

XML

Employee Benefit Plans (Schedule of Expected Future Benefit Payments) (Details)	Sep. 30, 2018 USD ($)
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
2019	$ 934,935
2020	983,862
2021	1,042,332
2022	1,124,774
2023	1,220,246
2024-2028	7,346,304
Postretirement Plan
Defined Benefit Plan Disclosure [Line Items]
2019	688,340
2020	685,088
2021	725,587
2022	778,814
2023	834,042
2024-2028	$ 4,230,466

XML

Common Stock Options (Narrative) (Details) - shares	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Number of shares available for future grant (in shares)	36,000
Award vesting period	6 months
Award expiration period	10 years
Options granted (in shares)	0	25,500	24,000
Expected exercise term (years)		7 years	7 years

XML

Common Stock Options (Fair Value Assumptions) (Details)	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Expected volatility (as a percent)	26.09%	28.78%
Expected dividends (as a percent)	3.81%	3.99%
Expected exercise term (years)	7 years	7 years
Risk-free interest rate	2.20%	2.10%

XML

Common Stock Options (Schedule of Stock Option Activity) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Number of Shares
Options outstanding, beginning balance (in shares)	101,575	87,300	78,600
Options granted (in shares)	0	25,500	24,000
Options exercised (in shares)	(1,575)	(11,225)	(3,300)
Options expired (in shares)	0	0	0
Options forfeited (in shares)	0	0	(12,000)
Options outstanding, ending balance (in shares)	100,000	101,575	87,300	78,600
Vested and exercisable at end of period (in shares)	100,000
Weighted- Average Exercise Price
Options outstanding, beginning balance (in usd per share)	$ 14.31	$ 13.50	$ 13.22
Options granted (in usd per share)	0.00	16.37	14.15
Options exercised (in usd per share)	12.66	12.67	12.65
Options expired (in usd per share)	0.00	0.00	0.00
Options forfeited (in usd per share)	0.00	0.00	13.20
Options outstanding, ending balance (in usd per share)	14.34	$ 14.31	$ 13.50	$ 13.22
Vested and exercisable at end of period (in usd per share)	$ 14.34
Options, Additional Disclosures
Weighted- Average Remaining Contractual Terms (years)	6 years 7 months	7 years 7 months	7 years 10 months	8 years 4 months
Weighted-Average Remaining Contractual Term, Vested and exercisable at September 30, 2017	6 years 7 months
Aggregate Intrinsic Value	$ 1,237,286	$ 1,448,338	$ 200,211	$ 43,086
Aggregate Intrinsic Value, Vested and exercisable at end of period	$ 1,237,286
Weighted-average grant date option fair value (in usd per share)	$ 0.00	$ 2.89	$ 2.69
Stock option expense	$ 0	$ 73,780	$ 64,640
Intrinsic value of options exercised	15,256	99,929	8,418
Proceeds from exercise of stock options	$ 19,945	$ 142,241	$ 41,762

XML

Other Stock Plans (Narrative) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares available for issuance (in shares)	36,000
Dividend Reinvestment and Stock Purchase Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum amount shareholders can partake in the DRIP plan	$ 40,000
Number of shares issued under the Dividend Reinvestment and Stock Purchase Plan	31,744	36,446	52,146
Shares of stock available for issuance under the DRIP Plan	417,229
Restricted Stock Plan for Outside Directors | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum allowed percent of retainer fee that can be paid in common stock	100.00%
Minimum percentage of monthly retainer fee paid in shares of common stock	40.00%
Minimum number of shares that must be owned to avoid percentage of monthly retainer fee paid in shares of common stock	10,000
Value of shares issued under the plan	$ 177,800	$ 99,400	$ 98,334
Stock vested during the period (in shares)	20,283	0	0
Stock forfeited during the period (in shares)	0	0	0
Shares available for issuance (in shares)	75,049
RGC Resources, Inc. Restricted Stock Plan | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Value of shares issued under the plan	$ 188,388
Stock vested during the period (in shares)	3,367
Stock forfeited during the period (in shares)	0
Shares available for issuance (in shares)	439,734
Stock Bonus Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Value of shares issued under the plan		$ 30,154	$ 39,819
Shares available for issuance (in shares)	4,785
Shares issued under the plan	0	1,628	2,813

XML

Other Stock Plans (Director Compensation Activity) (Details) - Restricted Stock Plan for Outside Directors - Restricted Stock - $ / shares	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Shares
Beginning of year balance (in shares)	111,893	107,023	100,373
Granted (in shares)	6,692	4,870	6,650
Vested (in shares)	(20,283)	0	0
Forfeited (in shares)	0	0	0
End of year balance (in shares)	98,302	111,893	107,023
Weighted-Average Fair Value on Date of Grant
Beginning of year balance (in usd per share)	$ 10.56	$ 10.11	$ 9.80
Granted (in usd per share)	26.57	16.77	14.79
Vested (in usd per share)	11.20	0.00	0.00
Forfeited (in usd per share)	0.00	0.00	0.00
End of year balance (in usd per share)	$ 11.51	$ 10.56	$ 10.11

XML

Other Stock Plans Other Stock Plans (Officer Compensation Activity) (Details) - RGC Resources, Inc. Restricted Stock Plan - Restricted Stock	12 Months Ended
	Sep. 30, 2018 $ / shares shares
Shares
Beginning of year balance (in shares) | shares	0
Granted (in shares) | shares	10,101
Vested (in shares) | shares	(3,367)
Forfeited (in shares) | shares	0
End of year balance (in shares) | shares	6,734
Weighted-Average Fair Value on Date of Grant
Beginning of year balance (in usd per share) | $ / shares	$ 0.00
Granted (in usd per share) | $ / shares	26.33
Vested (in usd per share) | $ / shares	26.33
Forfeited (in usd per share) | $ / shares	0.00
End of year balance (in usd per share) | $ / shares	$ 26.33

XML

Commitments and Contingencies (Narrative) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Commitments and Contingencies Disclosure [Abstract]
Asset management contract term	3 years
Expenditures under asset management agreement	$ 31,137,000	$ 28,496,000	$ 24,852,000
Franchise agreement term	20 years
Franchise fee annual increase	3.00%
Franchise fee, total cost through end of agreement	$ 2,512,411

XML

Commitments and Contingencies (Schedule of Volumetric Obligations) (Details)	Sep. 30, 2018 MMBTU
Commitments and Contingencies Disclosure [Abstract]
2018-2019	2,089,578
2019-2020	2,071,061
2020-2021	295,866
Total	4,456,505

XML

Commitments and Contingencies (Schedule of Pipeline and Storage Capacity Obligations) (Details)	Sep. 30, 2018 USD ($)
Commitments and Contingencies Disclosure [Abstract]
2018-2019	$ 11,184,000
2019-2020	8,856,915
2020-2021	6,503,953
2021-2022	5,847,945
2022-2023	2,369,904
Thereafter	1,950,134
Total	$ 36,712,851

XML

Fair Value Measurements (Schedule of Fair Value of Financial Assets and Liabilities Measured on a Recurring Basis) (Details) - USD ($)	Sep. 30, 2018	Sep. 30, 2017
Assets:
Interest rate swaps	$ 310,563	$ 116,843
Total	310,563	116,843
Liabilities:
Natural gas purchases	693,495	805,159
Total	693,495	805,159
Quoted Prices in Active Markets Level 1
Assets:
Interest rate swaps	0	0
Total	0	0
Liabilities:
Natural gas purchases	0	0
Total	0	0
Significant Other Observable Inputs Level 2
Assets:
Interest rate swaps	310,563	116,843
Total	310,563	116,843
Liabilities:
Natural gas purchases	693,495	805,159
Total	693,495	805,159
Significant Unobservable Inputs Level 3
Assets:
Interest rate swaps	0	0
Total	0	0
Liabilities:
Natural gas purchases	0	0
Total	$ 0	$ 0

XML

Fair Value Measurements (Summary of the Fair Value of Financial Assets and Liabilities Not Adjusted to Fair Value) (Details) - USD ($)	Sep. 30, 2018	Sep. 30, 2017
Liabilities:
Notes payable	$ 63,243,200	$ 43,812,200
Total	63,243,200	43,812,200
Quoted Prices in Active Markets Level 1
Liabilities:
Notes payable	0	0
Total	0	0
Significant Other Observable Inputs Level 2
Liabilities:
Notes payable	0	0
Total	0	0
Significant Unobservable Inputs Level 3
Liabilities:
Notes payable	62,435,237	45,689,238
Total	$ 62,435,237	$ 45,689,238

XML

Fair Value Measurements (Narrative) (Details)	12 Months Ended
	Sep. 30, 2018
Fair Value Disclosures [Abstract]
Treasury rate, period	20 years

XML

Quarterly Financial Information (Unaudited) (Details) - USD ($)	3 Months Ended								12 Months Ended
	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Quarterly Financial Information Disclosure [Abstract]
Operating revenues	$ 9,971,142	$ 11,889,570	$ 24,917,973	$ 18,756,051	$ 10,172,448	$ 11,435,824	$ 21,900,013	$ 18,788,585	$ 65,534,736	$ 62,296,870	$ 59,063,291
Operating income	744,980	1,866,223	5,306,718	3,675,124	766,620	1,328,207	5,589,207	3,982,275	11,593,045	11,666,309	11,212,092
Net income	$ 684,459	$ 1,087,355	$ 3,465,929	$ 2,059,462	$ 159,886	$ 615,562	$ 3,225,199	$ 2,232,218	$ 7,297,205	$ 6,232,865	$ 5,806,866
Earnings per share of common stock:
Basic (in usd per share)	$ 0.09	$ 0.14	$ 0.47	$ 0.28	$ 0.02	$ 0.09	$ 0.45	$ 0.31	$ 0.95	$ 0.86	$ 0.81
Diluted (in usd per share)	$ 0.09	$ 0.14	$ 0.47	$ 0.28	$ 0.02	$ 0.08	$ 0.45	$ 0.31	$ 0.95	$ 0.86	$ 0.81