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, 2015 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: None

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

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

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, or a smaller reporting company. See definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one).

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

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, 2015. $89,254,811

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 30, 2015
COMMON STOCK, $5 PAR VALUE	4,750,645 SHARES

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the RGC Resources, Inc. Proxy Statement for the 2016 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		10
	Item 4.	Mine Safety Disclosures		10
PART II
	Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.		11
	Item 6.	Selected Financial Data		12
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		13
	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		27
	Item 8.	Financial Statements and Supplementary Data		28
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosures		60
	Item 9A.	Controls and Procedures		60
	Item 9B.	Other Information		63
PART III
	Item 10.	Directors, Executive Officers and Corporate Governance		64
	Item 11.	Executive Compensation		64
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		64
	Item 13.	Certain Relationships and Related Transactions, and Director Independence		64
	Item 14.	Principal Accounting Fees and Services		64
Part IV
	Item 15.	Exhibits and Financial Statement Schedules		65
	Signatures			66

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, RGC Ventures of Virginia, Inc 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 most of the non-gas utility revenue of Resources.

In 2000, the information technology department of Resources formed Application Resources, Inc. under RGC Ventures of Virginia, Inc. to provide information technology consulting services. In 2011, the Company also formed The Utility Consultants under RGC Ventures of Virginia, Inc to provide utility and regulatory consulting services to other utilities. The operations of RGC Ventures of Virginia, Inc. contributed less than 6% of other revenues and less than 1% of total revenues of Resources during fiscal 2015. The Utility Consultants portion of RGC Ventures of Virginia, Inc. and Diversified Energy Company currently have no active operations.

In July 2015, the Company formed RGC Midstream, LLC, a limited liability company established for the purpose of becoming a 1% investor in Mountain Valley Pipeline, LLC. Mountain Valley Pipeline, LLC was created for the purpose of constructing a natural gas pipeline in West Virginia and Virginia. Additional information regarding this investment is provided under Note 12 of the Company’s annual consolidated financial statements and under the Equity Investment in Mountain Valley Pipeline section of Item 7.

Services

Roanoke Gas maintains an integrated natural gas distribution system to deliver natural gas purchased from suppliers to residential, commercial and industrial users in its service territory. The schedule below is a summary of customers, delivered volumes (expressed in decatherms), revenues and margin as a percentage of the total for each category:

	2015
	Customers			Volume			Revenue			Margin
Residential		91.2	%		40	%		58	%		58	%
Commercial		8.7	%		30	%		33	%		26	%
Industrial		0.1	%		30	%		6	%		11	%
Other Utility		0.0	%		0	%		1	%		3	%
Other Non-Utility		0.0	%		0	%		2	%		2	%
Total Percent		100.0	%		100	%		100	%		100	%
Total Value		59,080			9,875,007		$	68,189,607		$	30,206,433
	2014
	Customers			Volume			Revenue			Margin
Residential		91.2	%		40	%		57	%		58	%
Commercial		8.7	%		29	%		34	%		25	%
Industrial		0.1	%		31	%		6	%		12	%
Other Utility		0.0	%		0	%		1	%		3	%
Other Non-Utility		0.0	%		0	%		2	%		2	%
Total Percent		100.0	%		100	%		100	%		100	%
Total Value		58,553			10,087,651		$	75,016,134		$	29,337,089

3

	2013
	Customers			Volume			Revenue			Margin
Residential		91.2	%		41	%		57	%		58	%
Commercial		8.7	%		28	%		33	%		25	%
Industrial		0.1	%		31	%		6	%		12	%
Other Utility		0.0	%		0	%		2	%		3	%
Other Non-Utility		0.0	%		0	%		2	%		2	%
Total Percent		100.0	%		100	%		100	%		100	%
Total Value		58,238			9,408,894		$	63,205,666		$	27,602,891

Roanoke Gas’ regulated natural gas distribution business accounted for approximately 98% of Resources total revenues for fiscal years ending September 30, 2015, 2014 and 2013. The table above indicates that residential customers represent over 91% of the Company’s customer total; however, they represent less than 50% 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 30% of total natural gas deliveries for the year ended September 30, 2015 and approximately 11% to 12% of gross margin for each of the years presented.

The Company’s revenues are affected by changes in gas costs as well as by changes in consumption volume due to weather and economic conditions and changes in the non 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 further detail in Note 1 of the Company’s annual consolidated financial statements. Significant increases in gas costs may cause customers to conserve or, in the case of industrial customers, to switch to alternative energy sources.

The Company’s residential and commercial sales are seasonal and temperature-sensitive as the majority of the gas sold by Resources to these customers is used for heating. For the fiscal year ended September 30, 2015, approximately 68% of the Company’s total DTH of natural gas deliveries and 77% of the residential and commercial deliveries were made in the five-month period of November through March. These percentages are consistent with prior years. Total natural gas deliveries were 9.9 million DTH, 10.1 million DTH and 9.4 million DTH in fiscal 2015, 2014 and 2013, respectively.

Suppliers

Roanoke Gas relies on multiple interstate pipelines including those operated by Columbia Gas Transmission Corporation and Columbia Gulf Transmission Corporation (together “Columbia”), and East Tennessee Natural Gas Company (“East Tennessee”), Tennessee Gas Pipeline, Midwestern Gas Transmission 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 between 50% and 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 2017 to 2020. 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 for delivery into Roanoke Gas’ distribution system under the interstate pipelines is 78,606 DTH per day. The LNG facility, which is capable of storing up to 220,000 DTH of natural gas in a liquid state for use during peak demand, has the capability of providing an additional 33,000 DTH per day. Combined, the pipelines and LNG facility can provide more than 111,000 DTH on a single winter day. In fiscal 2015, the Company realized a maximum one day-customer demand of 91,341 DTH which represented the highest single day volume delivery in the Company’s history.

4

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 and storage rights and gas supply inventories and deliveries and serve as the primary supplier of natural gas for Roanoke Gas. Natural gas purchased under the asset management agreement is priced at indexed-based market prices as reported in major industry pricing publications. The Company expects its firm supply agreements will be sufficient to meet customer demands for natural gas during the term of the agreement, which expires March 31, 2017.

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 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, which all expire December 31, 2015.

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. Certificates of public convenience and necessity, issued by the Virginia State Corporation Commission (the “SCC”), are of perpetual duration, subject to compliance with regulatory standards.

Although Roanoke Gas has exclusive rights for the distribution of natural gas in its service area, the Company competes with suppliers of other energy sources such as fuel oil, electricity, propane, coal and solar. Competition can be intense among the other energy sources and can be based primarily on price. 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 new 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 and extends service to the new residential construction markets located along or near gas distribution mains in its service area. Although new construction activity has been limited over the last few years, the Company has been able to grow its customer base through customer conversions from an alternative energy source to natural gas along its distribution lines.

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 charges at which natural gas is 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. The SCC also grants certificates of public convenience and necessity to distribute natural gas in Virginia.

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, 2015, Resources had 125 full-time employees and 133 total employees. As of that date, 33 employees, or 26% of the Company’s full-time employees, belonged to the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied-Industrial International Union, Local No. 515 and were represented under a collective bargaining agreement. The union has been in place at the Company since 1952. The Company and the union successfully negotiated a new collective bargaining agreement during 2015 that will expire on July 31, 2020. Management maintains an amicable relationship with the union.

5

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 quarter 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 and is where you can obtain other Company filings with the SEC.

Item 1A. Risk Factors

Please carefully consider the risks described below regarding the Company. The risks described below 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 an investor could lose all or part of his, her or its investment.

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 laws and regulations at both the federal and state levels. The Company is subject to ongoing inspections and reviews. Failure to comply with such requirements could result in the levy of significant fines. Recent enforcement actions by the Virginia Division of Utility and Railroad Safety have resulted in increased fines for gas distribution companies across the state. 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 operation.

Availability of adequate and reliable pipeline capacity.

The Company is 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.

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, accidents, equipment breakdowns, failure of upstream pipelines and storage facilities, as well as catastrophic events such as explosions, fires, earthquakes, floods, or other similar events. These risks could result in injury or loss of life, property damage, pollution and customer service disruption resulting in potentially significant financial losses. The Company maintains insurance policies with financially sound carriers to protect against many of these risks. If losses result from a risk 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, ultimately resulting in a longer-term negative impact on earnings.

6

Investment in Mountain Valley Pipeline.

The success or failure of the Company’s investment in Mountain Valley Pipeline, LLC (the “LLC”) is predicated on several key factors including but not limited to the ability of all investors to meet their capital calls when due, the timely approval of the pipeline project by FERC, completing the construction of the pipeline within the targeted time frame and budget and fully subscribing the capacity of the pipeline once in service. Any significant delay, cost over-run or the failure to receive the requisite approvals could have a significant effect on the Company’s earnings and financial position.

In addition, there are also numerous risks facing the LLC over time, which in turn could adversely affect the Company’s earnings and financial performance through its 1% investment. The LLC’s ability to complete construction of, and capital improvement to, facilities on schedule and within budget may be adversely affected by escalating costs for materials and labor and regulatory compliance, inability to obtain or renew necessary licenses, rights-of-way, permits or other approvals on acceptable terms or on schedule, disputes involving contractors, labor organizations, land owners, governmental entities, environmental groups, Native American and aboriginal groups, and other third parties, negative publicity, transmission interconnection issues, and other factors. If any development project or construction or capital improvement project is not completed, is delayed or is subject to cost overruns, certain associated costs may not be approved for recovery or recoverable through regulatory mechanisms that may otherwise be available, and the LLC could become obligated to make delay or termination payments or become obligated for other damages under contracts, could 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. Any of these events could have a material adverse effect on the LLC’s business, financial condition, results of operations and prospects. project siting, financing, construction, permitting, governmental approvals and the negotiation of project development agreements that may impede its development and operating activities. The LLC may face risks related to project siting, financing, construction, permitting, governmental approvals and the negotiation of project development agreements that may impede its development and operating activities. The LLC must periodically apply for licenses and permits from various local, state, federal and other regulatory authorities and abide by their respective conditions. Should the LLC be unsuccessful in obtaining necessary licenses or permits on acceptable terms, should there be a delay in obtaining or renewing necessary licenses or permits or should regulatory authorities initiate any associated investigations or enforcement actions or impose related penalties or disallowances on the LLC, the LLC’s business, financial condition, results of operations and prospects could be materially adversely affected. Any failure to negotiate successful project development agreements for new facilities with third parties could have similar results. The LLC’s gas infrastructure facilities and other facilities are subject to many operational risks. Operational risks could result in, among other things, lost revenues due to prolonged outages, increased expenses due to monetary penalties or fines for compliance failures, liability to third parties for property and personal injury damage, a failure to perform under applicable sales agreements and associated loss of revenues from terminated agreements or liability for liquidated damages under continuing agreements. The consequences of these risks could have a material adverse effect on the LLC’s business, financial condition, results of operations and prospects. Uncertainties and risks inherent in operating and maintaining the LLC’s facilities include, but are not limited to, risks associated with facility start-up operations, such as whether the facility will achieve projected operating performance on schedule and otherwise as planned. The LLC’s business, financial condition, results of operations and prospects can be materially adversely affected by weather conditions, including, but not limited to, the impact of severe weather. Threats of terrorism and catastrophic events that could result 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.

Supply disruptions due to weather or other forces.

Hurricanes and other natural or man-made disasters could damage or inhibit production and/or pipeline transportation facilities, which could result in decreased supplies of natural gas. Decreased supplies could result in an inability to meet customer demand leading to higher prices or service disruptions. Disasters could also lead to additional governmental regulations that limit production activity or increase production and transportation costs.

7

Security breach or cyber-attacks on the Company’s computer systems could corrupt financial information, expose confidential personal information or compromise the safe and reliable delivery of natural gas.

A breach of the Company’s information systems from cyber-attacks or other sources could lead to disruptions in natural gas deliveries or compromise the safety of our distribution system. Such attacks could also result in corruption of the Company’s financial information or the unauthorized release of confidential customer, employee or vendor information. The Company takes reasonable precautions to safeguard its computer systems from attack; however, there is no guarantee that Company processes will adequately protect against unauthorized access to data. In the event of a successful attack, the Company could be exposed to material financial and reputational 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 as well as slow or declining growth in new customer additions, both 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 result in increased customer delinquencies and bad debt expense.

Environmental laws or regulations.

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. Natural gas is a clean and efficient energy source; however, the combustion of natural gas results in carbon related emissions. 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. New regulations could result in a significant reduction in the use of coal as a fuel for electric power generation, potentially resulting in natural gas supply concerns and higher cost 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.

Regulatory actions or failure to obtain timely rate relief could decrease future profitability.

The Company’s natural gas operations are regulated by the SCC. The SCC approves the rates that the Company charges its natural gas customers. If the SCC did not allow rates that provided for the timely recovery of costs or a reasonable rate of return on investment in natural gas distribution facilities, earnings could be negatively impacted. Issuance of debt and equity 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.

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 stock issued under the Dividend Reinvestment and Stock Purchase Plan (“DRIP”) 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 to provide more predictable financing for capital outlays and funding of the investment in the LLC. 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 or deterioration in the financial condition of the Company could increase the cost of borrowing or limit the Company’s ability to secure adequate funding.

8

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 electric generation, natural gas prices are currently expected to remain stable in the near term, although there can be no guarantee to that effect. However, if restrictions on drilling for natural gas in the shale rock formations are imposed at either federal, state or local levels due to environmental or other concerns or other exploration and development restrictions on conventional drilling are enacted, the price of natural gas could escalate. The economic viability of the LLC could be significantly impacted by such restrictions. Furthermore, if demand for natural gas increases at a rate in excess of current expectations, natural gas prices could also face upward pressure. Increasing natural gas prices could make natural gas a less attractive energy source to the Company’s customers; thereby potentially resulting in declining sales as well as increases in bad debt expense.

Business activities are concentrated in a limited geographic region.

Changes in the Roanoke Valley’s economy, politics, regulations and weather patterns could negatively impact the existing customer base, leading to declining usage patterns and financial condition of customers, both of which could adversely affect earnings.

The cost of providing post-retirement benefits and related funding obligations may increase.

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 of these plans. Such funding obligations could have a material impact on liquidity by reducing cash flows and could negatively affect results of operations.

Weather conditions may cause revenues and earnings to vary from year to year.

The Company’s revenues and earnings are highly 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 with no benefit of additional revenues to offset those costs as a result of the weather normalization adjustment.

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. A significant competitive factor is price. Higher natural gas costs or decreases in the price of other energy sources may enhance competition and encourage customers to convert their gas-fired 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.

Failure to comply with debt covenant requirements could lead to adverse financial consequences that could affect the Company’s liquidity and ability to borrow funds.

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.

9

Inability to complete necessary or desirable pipeline expansion or infrastructure development projects may delay or prevent the Company from adequately serving its customers or expanding its distribution system.

In order to serve new customers or expand service to existing customers, the Company needs to maintain, expand or upgrade its distribution, transmission and/or storage infrastructure, including new pipeline installation. Various factors may prevent or delay the completion of such projects or make them more costly, such as the inability to obtain required approval from local, state and/or federal regulatory and governmental bodies, public opposition to the projects, inability to obtain adequate financing, competition for labor and materials, construction delays, cost overruns, and an inability to negotiate acceptable agreements relating to rights-of-way, construction or other material development components. As a result, the Company may not be able to adequately serve existing customers or support customer growth, which would negatively impact earnings.

Item 1B. Unresolved Staff Comments.

Not applicable.

Item 2. Properties.

Included in “Utility Plant” 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 1,125 miles of transmission and distribution pipeline with transmission and distribution plant representing more than 85% of the total investment in plant. The transmission and distribution pipelines are located on or under public roads and highways or private property for which the Company has obtained the legal authorization and rights to operate.

Roanoke Gas 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 Botetourt County that has the capacity to store up to 220,000 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 adequate, management continues to evaluate the adequacy of its current facilities and intends to complete the replacement of its remaining cast iron and bare steel pipeline within the next two years.

Item 3. Legal Proceedings.

The Company was a defendant in two civil lawsuits associated with a November 2009 explosion and fire at a West Virginia residence. The first lawsuit was dismissed by order on March 31, 2015, and the second lawsuit was dismissed by order on April 27, 2015. The final resolution was consistent with management’s expectations as the settlement did not materially affect the Company’s financial position, results of operation, or liquidity.

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

Item 4. Mine Safety Disclosures.

Not applicable.

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PART II

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

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 will depend 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, 2015	High		Low		Declared
First Quarter	$	22.45	$	19.28	$	0.1925
Second Quarter		25.67		20.20		0.1925
Third Quarter		22.99		19.78		0.1925
Fourth Quarter		21.96		19.95		0.1925
Year Ending September 30, 2014
First Quarter	$	19.98	$	18.10	$	0.185
Second Quarter		20.06		18.46		0.185
Third Quarter		19.73		19.00		0.185
Fourth Quarter		20.51		19.17		0.185

As of November 30, 2015, there were 1,209 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, 2010 through September 30, 2015 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, 2010 in the Company’s common stock and in each index as of September 30, 2015, 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 $172 for the Company’s common stock, $181 for the Dow Jones US Utilities Index and $187 for the S&P 500 Index.

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A summary of the Company’s equity compensation plans follows as of September 30, 2015:

	(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		52,400	$	19.83		128,134
Equity compensation plans not approved by security holders		—		—		—
Total		52,400	$	19.83		128,134

Item 6. Selected Financial Data.

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	Year Ending September 30,
	2015		2014		2013		2012		2011
Operating Revenues	$	68,189,607	$	75,016,134	$	63,205,666	$	58,799,687	$	70,798,871
Gross Margin		30,206,433		29,337,089		27,602,891		26,933,097		27,269,566
Operating Income		10,006,192		9,681,868		8,795,055		8,786,535		9,313,046
Net Income		5,094,415		4,708,440		4,262,052		4,296,745		4,653,473
Basic Earnings Per Share	$	1.08	$	1.00	$	0.91	$	0.92	$	1.01
Cash Dividends Declared Per Share	$	0.77	$	0.74	$	1.72	$	0.70	$	0.68
Book Value Per Share	$	11.14	$	11.02	$	10.51	$	10.85	$	10.55
Average Shares Outstanding		4,728,210		4,715,478		4,698,727		4,647,439		4,592,713
Total Assets	$	148,140,730	$	139,127,641	$	124,510,870	$	129,735,019	$	125,522,242
Long-Term Debt (Less Current Portion)	$	30,500,000	$	30,500,000	$	13,000,000	$	13,000,000	$	13,000,000
Stockholders’ Equity		52,840,991		52,020,847		49,502,422		50,682,930		48,785,778
Shares Outstanding at Sept. 30		4,741,498		4,720,378		4,709,326		4,670,567		4,624,682

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 59,100 residential, commercial and industrial customers in Roanoke, Virginia and the surrounding localities, through its Roanoke Gas Company (“Roanoke Gas”) subsidiary. Resources also provides certain unregulated services through Roanoke Gas and utility information system services through RGC Ventures of Virginia, Inc., which operates as The Utility Consultants and Application Resources. The Company also formed a new wholly-owned

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subsidiary, RGC Midstream, LLC (“Midstream”), which was created to invest in the Mountain Valley Pipeline (“MVP”) project. On October 1, 2015, Midstream executed the agreements to become a 1% member in the MVP project. More information is provided under the Equity Investment in Mountain Valley Pipeline section below. The unregulated operations represent less than 3% 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. The Federal Energy Regulatory Commission (“FERC”) regulates prices for the transportation and delivery of natural gas to the Company’s distribution system and underground storage services. The Company is also subject to other regulations which are not necessarily industry specific.

The Company is 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. With recent regulatory actions placing a greater emphasis on pipeline safety, the Company continues to focus its efforts on completing its renewal and replacement program. Management anticipates replacing all remaining cast iron and bare steel pipe within the next two years and expects to continue its renewal program with plans to replace first generation pre-1973 plastic pipe.

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 security attacks and other types of breaches; however, there can be no guarantee that a breach will not occur. In the event of a breach, the Company will execute its Security Incident Response Plan to assist with managing the incident. The Company also maintains cyber-insurance coverage to mitigate financial implications resulting from a breach of confidential information.

Over 97% 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 previous 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 increased infrastructure investment. These mechanisms include a purchased gas adjustment factor (“PGA”), weather normalization adjustment factor (“WNA”), inventory carrying cost revenue 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 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, 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 a weather measurement band around the most recent 30-year temperature average. The WNA provides the Company with a level of earnings protection when weather is warmer than normal and provides its customers with

14

price protection when the weather is colder than normal. Prior to April 2014, the WNA provided a weather band of 3% above and below normal, whereby the Company would bill its customers for the lost margin (excluding gas costs) for the impact of weather that was more than 3% warmer than normal or refund customers the excess margin earned for weather that was more than 3% colder than normal. Effective with the WNA year that began April 2014, the 3% weather band was removed and the WNA is now based strictly on temperature variations from normal. For the fiscal year ended September 30, 2015, the Company recorded a $609,000 reduction in revenue for weather that was approximately 6.5% colder than normal. During the fiscal year ended September 30, 2014, the Company recorded a reduction in revenue of $563,000 to reflect the WNA adjustment for weather that was 8.8% colder than normal. If the WNA weather band had been 0% for the entire fiscal 2014 instead of 3% for the period October 1, 2013 through March 31, 2014, revenue would have been adjusted down by $814,000. No revenue adjustment for WNA was made for fiscal 2013 as the number of heating degree days fell within the 3% band then in effect.

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 carrying cost revenue (“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 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. As the commodity price for natural gas has declined by more than $1.00 a decatherm compared to the same period last year, the price of gas delivered into storage during the current year has declined by a similar amount. The result was a decline in the price of gas in storage to $3.38 per decatherm at September 30, 2015 compared to a price in storage of $4.71 and $4.08 at September 30, 2014 and 2013, respectively. However, the average dollar balance of gas in storage inventory actually increased over the prior fiscal year due to the higher-priced gas in storage at the beginning of fiscal 2015 combined with a greater level of withdrawals in fiscal 2014 due to the colder winter. Although the average balance of gas in storage during the current year was higher than the prior fiscal year, ICC revenues during fiscal 2015 declined by approximately $46,000 due to a reduction in the weighted-average cost of capital. The weighted-average cost of capital declined from last year due to the refinancing of the Company’s long-term debt in September 2014 combined with an increasing allocation of low cost short-term debt in the determination of the ICC rate. Based on the current prices of natural gas futures, the average dollar balance of gas in storage is expected to be much lower in the next fiscal year, resulting in lower ICC revenues in fiscal 2016.

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 carrying cost revenues is based on the Company’s weighted-average cost of capital, carrying cost revenues do not directly correspond with incremental short-term financing costs. Therefore, when inventory balances decline due to a reduction in commodity prices, net income will decline as carrying cost revenues decrease by a greater amount than short-term financing costs decrease. The inverse occurs when inventory costs increase.

The Company’s non-gas rates provide for the recovery of non-gas related expenses and a reasonable return to shareholders. These rates are determined based on the filing of a formal rate application with the SCC utilizing historical information including investment in natural gas facilities. Generally, investments related to extending service to new customers are recovered through the non-gas rates currently in place. The investment in replacing and upgrading existing infrastructure is not recoverable until a formal rate application is made 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 related to these 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. As the Company did not file for an increase in the non-gas rates during the prior year and the level of capital investment continues to grow, SAVE Plan revenues have increased significantly. The Company recognized approximately $1,308,000, $292,000 and $169,000 in SAVE Plan revenues for years ended September 30, 2015, 2014 and 2013. SAVE revenues will be included as part of the new non-gas base rates the next time the Company files for a non-gas rate increase. Additional information regarding the SAVE Rider is provided under the Regulatory Affairs section.

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The economic environment has a direct correlation with business and industrial production, customer growth and natural gas utilization. The local economy has lost some key business activities over the last year as some companies have either shut down or relocated all or portions of their operations elsewhere. In addition, a couple of the Company’s larger industrial customers have reduced natural gas consumption amid lower production activities. The impact of these relocations or the duration of these curtailments is unknown at this time. However, despite these losses, the local economy appears relatively stable and should continue to slowly improve absent a major economic setback, on either a local or national level.

Results of Operations

Fiscal Year 2015 Compared with Fiscal Year 2014

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

Operating Revenues

Year Ended September 30,	2015		2014		Decrease			Percentage
Gas Utilities	$	67,094,290	$	73,865,487	$	(6,771,197	)		(9	)%
Other		1,095,317		1,150,647		(55,330	)		(5	)%
Total Operating Revenues	$	68,189,607	$	75,016,134	$	(6,826,527	)		(9	)%

Delivered Volumes

Year Ended September 30,	2015		2014		Decrease			Percentage
Regulated Natural Gas (DTH)
Residential and Commercial		6,955,594		7,005,920		(50,326	)		(1	)%
Transportation and Interruptible		2,919,413		3,081,731		(162,318	)		(5	)%
Total Delivered Volumes		9,875,007		10,087,651		(212,644	)		(2	)%
Heating Degree Days (Unofficial)		4,253		4,351		(98	)		(2	)%

Total gas utility operating revenues for the year ended September 30, 2015 decreased by 9% from the year ended September 30, 2014 primarily due to lower gas costs and a reduction in natural gas deliveries. The average commodity price of natural gas declined by 21% per decatherm sold. Delivered volumes declined due in part to weather, as reflected in the decline in residential and commercial volumes, and a reduction in industrial consumption. Residential and commercial deliveries tend to be more weather sensitive as reflected by a decline of 1% in volumes on 2% fewer heating degree days. Transportation and interruptible volumes, which are primarily driven by production activities rather than weather, decreased by 5%. Other revenues decreased by 5% as well.

Gross Margin

Year Ended September 30,	2015		2014		Increase / (Decrease)			Percentage
Gas Utility	$	29,656,975	$	28,774,213	$	882,762			3	%
Other		549,458		562,876		(13,418	)		(2	)%
Total Gross Margin	$	30,206,433	$	29,337,089	$	869,344			3	%

Regulated natural gas margins from utility operations increased by 3% from fiscal 2014, primarily as a result of higher SAVE Plan revenues and customer base charges more than offsetting lower volumetric margins and ICC revenues. SAVE Plan revenues increased by $1,016,000. As the Company continues to invest in eligible SAVE Plan infrastructure, the associated SAVE Plan revenues will continue to increase. Customer base charges also increased due

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to modest customer growth. As discussed above, volumetric margin declined due to a reduction in total volumes delivered. Residential and commercial volumes declined primarily due to slightly warmer weather. Interruptible and transportation volumes declined due to the loss of a customer and decreased usage at two of the Company’s largest customers. The effect of the warmer weather was mitigated in part by the WNA mechanism. The prior year WNA mechanism provided for a weather band of 3% variance around normal during the winter heating season while the current heating season had a 0% weather band. Because the prior year had a 3% weather band in place for part of the year and weather was colder than normal, the Company was able to retain approximately $251,000 in excess margin realized on the 3% weather band, while the current year WNA with a 0% weather band required the adjustment of margin back to the level expected for normal weather.

Other margins, consisting of non-utility related services, decreased by $13,418 on comparable activity. The Utility Consultants, which ceased activity during fiscal 2015, contributed $17,000 to the non-utility related margin. The service contracts that comprise most of the non-utility related activities are subject to annual or semi-annual renewal provisions and the potential exists that these contracts may not be renewed or extended by the customer. In addition, the level of activity under these contracts will fluctuate based on customer requirements which may result in fluctuations in revenues and margins.

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

	Twelve Months Ended September 30,						Increase
	2015			2014			(Decrease)
Customer Base Charge	$	12,240,580		$	12,064,764		$	175,816
SAVE Plan		1,307,795			291,946			1,015,849
Volumetric		15,757,907			15,990,704			(232,797	)
WNA		(608,560	)		(563,187	)		(45,373	)
Carrying Cost		833,291			879,381			(46,090	)
Other		125,962			110,605			15,357
Total	$	29,656,975		$	28,774,213		$	882,762

Operations and Maintenance Expense - Operations and maintenance expenses increased by $103,497, or 1%, in fiscal 2015 compared with fiscal 2014 due to higher benefit costs and professional services and less overhead capitalization more than offsetting reductions in the level of bad debt expense, labor and contracted labor. Employee benefit expenses increased by $260,000 primarily due to higher medical, defined benefit pension plan (“pension plan”) and postretirement medical plan (“postretirement plan”) expense. The actuarially determined expenses for the pension and postretirement plans increased in fiscal 2015 due to a decline in the discount rate for valuing both plans’ liabilities at September 30, 2014. More information on these plans and the impact on the financial statements are provided under the Pension and Postretirement Benefits section of the Critical Accounting Policies and Estimates below and in Note 6 of the consolidated financial statements. Professional services increased by $77,000 primarily due to legal expenses associated with the new union contract, the formation of the Company’s new subsidiary and the due diligence work related to the investment in MVP. Additional information on the investment in MVP is provided under the Equity Investment in Mountain Valley Pipeline section below and in Note 12 of the consolidated financial statements. Total capitalized overheads declined by $106,000 because of delays in the production of liquified natural gas due to maintenance down time, lower capital expenditures and a reduction in the capitalization rate compared to the prior year. Bad debt expense decreased by $61,000 due to lower customer billings resulting from warmer weather and a lower commodity price of gas. Labor and contracted services costs declined by $133,000 due to timing of pipeline right-of-way clearing and prior year costs related to updating the Company’s corrosion control processes. The remaining decrease relates to a variety of areas including the level of facility and equipment maintenance, advertising and administrative costs.

General Taxes - General taxes increased $46,035, or 3%, primarily due to higher property taxes associated with increases in utility property.

Depreciation - Depreciation expense increased by $395,488, or 8%, corresponding to a similar increase in utility plant investment.

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Other Expense—Other expense, net, increased by $21,909, or 11%, primarily due to an increase in charitable requests related to specific campaigns.

Interest Expense—Total interest expense decreased by $314,582, or 17%, due to a lower interest rate on long-term debt. In September 2014, the Company refinanced its $28,000,000 in long-term debt, which had an average interest rate of 6.30% with $30,500,000 in new debt having a rate of 4.26%.

Income Taxes—Income tax expense increased by $231,022 on higher pre-tax earnings. The effective tax rate was 38.4% for both fiscal 2015 and 2014.

Net Income and Dividends—Net income for fiscal 2015 was $5,094,415 compared to $4,708,440 for fiscal 2014. Basic and diluted earnings per share were $1.08 in fiscal 2015 compared to $1.00 in fiscal 2014. Dividends declared per share of common stock were $0.77 in fiscal 2015 compared to $0.74 in fiscal 2014.

Fiscal Year 2014 Compared with Fiscal Year 2013

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

Operating Revenues

					Increase /
Year Ended September 30,	2014		2013		(Decrease)			Percentage
Gas Utilities	$	73,865,487	$	62,024,174	$	11,841,313			19	%
Other		1,150,647		1,181,492		(30,845	)		(3	)%
Total Operating Revenues		75,016,134		63,205,666		11,810,468			19	%
Delivered Volumes
Year Ended September 30,	2014		2013		Increase			Percentage
Regulated Natural Gas (DTH)
Residential and Commercial		7,005,920		6,498,783		507,137			8	%
Transportation and Interruptible		3,081,731		2,910,111		171,620			6	%
Total Delivered Volumes		10,087,651		9,408,894		678,757			7	%
Heating Degree Days (Unofficial)		4,351		4,001		350			9	%

Total gas utility operating revenues for the year ended September 30, 2014 increased by 19% from the year ended September 30, 2013. The increase in gas revenues was primarily attributable to a combination of a 7% increase in total delivered natural gas volumes, a 30% per decatherm increase in the average commodity price of natural gas, implementation of a non-gas rate increase and higher SAVE Plan revenues. The increase in delivered volumes was driven by the colder winter heating season where total heating degree days increased by 9% over fiscal 2013 and were above the 30-year average by the same percentage. Transportation and interruptible volumes, which are primarily driven by production activities rather than weather, increased by 6%. Other revenues decreased by 3% due to the completion of a one-time project during the prior year more than offsetting increases in the level of certain other contract services during fiscal 2014.

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Gross Margin

Year Ended September 30,	2014		2013		Increase		Percentage
Gas Utility	$	28,774,213	$	27,108,112	$	1,666,101		6	%
Other		562,876		494,779		68,097		14	%
Total Gross Margin	$	29,337,089	$	27,602,891	$	1,734,198		6	%

Regulated natural gas margins from utility operations increased by 6% from fiscal 2013, primarily as a result of higher residential and commercial sales volumes, the implementation of a non-gas rate increase and the addition of the SAVE Plan rider. Residential and commercial volumes (which are strongly correlated to the weather) increased due to the much colder winter season. The higher margins generated by the increased residential and commercial volume were mostly offset by a net WNA refund of $563,000 recognized in fiscal 2014. The Company also implemented a non-gas rate increase effective November 1, 2013 and an increased SAVE Plan Rider beginning January 1, 2014. The non-gas rate increase was designed to provide approximately $887,000 in additional annual non-gas revenues. The implementation of the increased non-gas rates in November 2013 accounted for approximately $422,000 of the increase in customer base charges, a flat monthly fee billed to each natural gas customer, and $474,000 of the additional volumetric revenue. The SAVE Plan Rider provided an additional $123,000 in margin. ICC revenues continued to decline with a $58,000 reduction in fiscal 2014 compared to fiscal 2013 due to the larger storage withdrawals and lower ICC factor.

Other margins, consisting of non-utility related services, increased by $68,097 due to an increased level of activity under one of the contracted services. The service contracts that comprise most of the non-utility related activities are subject to annual or semi-annual renewal provisions and the potential exists that these contracts may not be renewed or extended by the customer. In addition, the level of activity under these contracts will fluctuate based on customer requirements.

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

	Twelve Months Ended September 30,					Increase
	2014			2013		(Decrease)
Customer Base Charge	$	12,064,764		$	11,405,093	$	659,671
SAVE Plan		291,946			168,747		123,199
Volumetric		15,990,704			14,497,351		1,493,353
WNA		(563,187	)		—		(563,187	)
Carrying Cost		879,381			937,684		(58,303	)
Other		110,605			99,237		11,368
Total	$	28,774,213		$	27,108,112	$	1,666,101

Operations and Maintenance Expense—Operations and maintenance expenses increased by $529,789, or 4%, in fiscal 2014 compared with fiscal 2013 primarily due to higher labor costs, contracted services, bad debt expense and corporate insurance expense more than offsetting significant reductions in employee benefit costs and greater capitalization of Company overheads on construction projects and LNG (liquefied natural gas) production. Labor costs and contracted services increased by $1,128,000 primarily due to a full year of increased operations staffing, timing of pipeline right-of-way clearing, a full year of costs related to an SCC mandated meter installation inspection and remediation program, expenses related to updating the Company’s corrosion control processes, benefit consulting services and network services support and training. Bad debt expense increased by approximately $64,000 related to much higher customer billings due to a colder winter heating season. Corporate property and liability insurance increased by $93,000 due to a combination of higher premiums and increased general liability coverage limits. These higher costs were partially offset by a $605,000 reduction in employee benefit expenses, specifically in the pension plan and postretirement plan. These actuarially determined expenses declined in fiscal 2014 due to a combination of a higher discount rate for valuing both plans’ liabilities at September 30, 2013 and strong investment performance of both plans’ assets. In addition, $339,000 of additional overheads was capitalized due to a significantly higher level of

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construction expenditures related to the Company’s renewal program and other projects. Total capital expenditures rose by more than $4.7 million over the prior year. The remaining increase of $188,000 relates to a variety of areas including additional facility and equipment maintenance and support costs, higher utility expenses and increased administrative costs related to the Company’s operations.

General Taxes—General taxes increased $79,640, or 5%, primarily due to higher property taxes associated with increases in utility property and greater payroll taxes related to increased operations staffing.

Depreciation—Depreciation expense increased by $237,956, or 5%, corresponding to the increase in utility plant investment partially offset by lower depreciation rates.

Other Expense—Other expense, net, increased by $146,770 primarily due to the absence of interest income related to the ANGD note which was paid off in fiscal 2013 combined with a greater level of corporate charitable giving and increased SCC pipeline assessments.

Interest Expense—Total interest expense remained virtually unchanged from fiscal 2013 as the Company benefited in September from lower interest expense due to its debt refinancing which offset the increased interest incurred under the line-of-credit.

Income Taxes—Income tax expense increased by $294,753 on higher pre-tax earnings. The effective tax rate for fiscal 2014 was 38.4% compared to 38.3% for 2013.

Net Income and Dividends—Net income for fiscal 2014 was $4,708,440 compared to $4,262,052 for fiscal 2013. Basic and diluted earnings per share were $1.00 in fiscal 2014 compared to $0.91 in fiscal 2013. Dividends declared per share of common stock were $0.74 in fiscal 2014 compared to $1.72 in fiscal 2013, which included the one-time special dividend of $1.00.

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 to a lesser extent, capital raised through the Company’s stock plans.

Cash and cash equivalents increased by $135,477 in fiscal 2015 compared to decreases of $1,996,467 in fiscal 2014 and $6,063,647 in fiscal 2013. The following table summarizes the categories of sources and uses of cash:

Cash Flow Summary

	Year Ended September 30,
	2015			2014			2013
Provided by operating activities	$	16,760,827		$	6,839,738		$	10,037,070
Used in investing activities		(13,750,274	)		(14,698,570	)		(9,947,510	)
Provided by (used in) financing activities		(2,875,076	)		5,862,365			(6,153,207	)
Increase (decrease) in cash and cash equivalents	$	135,477		$	(1,996,467	)	$	(6,063,647	)

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 increases in natural gas storage levels and rising customer receivable balances.

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Cash provided by operating activities was $16,761,000 in fiscal 2015, $6,840,000 in fiscal 2014 and $10,037,000 in fiscal 2013. Cash provided by operating activities increased by nearly $10,000,000 from last year primarily as a result of lower natural gas commodity prices and the extension of 50% bonus depreciation for tax purposes for calendar 2014. The gas cost component of the Company’s natural gas billing rates for the high volume winter period from January through March were derived based on natural gas futures pricing in early December 2014 when expectations were that prices would rise slightly during the period. Instead, the commodity price of gas declined by nearly $1.50 per decatherm from December 2014 until early February 2015, at which time the price leveled off. As a result, the Company was over-recovered on gas costs for billings rendered during this time period. The Company also benefited from the decline in natural gas prices as natural gas purchased for storage was at lower rates than in fiscal 2014. The Company purchases natural gas for storage purposes during the spring and summer months for use during the fall and winter heating season. As natural gas prices remained at lower levels during the spring and summer, the price of gas in storage declined from $4.71 per decatherm at September 30, 2014 to $3.38 at September 30, 2015, which resulted in an overall decline in storage inventory of $3,242,000. In addition, the extension of bonus depreciation to the end of calendar 2014 accounted for most of the increase in the deferred tax liability. Operating cash flow also increased due to higher net income and depreciation amounts. The cash windfall on the over-recovery of gas costs will be short-lived as the excess collected will be refunded to customers in 2016. In addition, deferred tax liabilities related to accelerated and bonus depreciation on the Company’s utility plant at September 30, 2015 will begin to reverse in 2016 or later, resulting in additional cash outflows for payment of the taxes. Conversely, during fiscal 2014 storage inventory balances increased by more than $1,000,000 and the Company went from an over-collected position to an under-collected position, resulting in a $1,208,000 use of operating cash.

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 bare steel and cast iron pipe with new plastic or coated steel pipe, making improvements to the LNG plant and expansion of its natural gas system to meet the demands of customer growth. The Company’s expenditures related to its pipeline renewal program and other system and infrastructure improvements and expansion have continued at elevated levels with total expenditures of $13,800,000 in fiscal 2015, $14,700,000 in fiscal 2014 and approximately $10,000,000 in fiscal 2013. The Company renewed 10 miles of bare steel and cast iron natural gas distribution main and replaced 594 services in fiscal 2015. This compares to 13.6 miles of main and 942 services in fiscal 2014 and 13 miles of main and 1,064 services in fiscal 2013. Total costs related to the renewal program continue to increase as the less complex and highly concentrated customer areas of the Company’s natural gas distribution system have been completed, leaving the more difficult sections to be done. Completion of the remaining pipeline replacement will more than likely be at a higher cost. The Company’s capital expenditures also included costs to extend mains and services to 609 new customers in fiscal 2015 compared to 673 in fiscal 2014 and 468 in fiscal 2013. In addition, the Company completed a significant main relocation and replacement of the compressor at the LNG plant in fiscal 2015.

RGC Resources is committed to the safe and reliable delivery of natural gas to its customers and, as a result, plans to commit the necessary resources to its pipeline renewal program with an expectation to replace all remaining cast iron and bare steel pipe within the next two years. As a reflection of this commitment, the Company’s capital budget for next year is currently estimated to be in excess of fiscal 2015 with the continuation of the pipeline replacement program and the replacement of two additional transfer stations. Depreciation provided approximately 38% of the current year’s capital expenditures compared to 33% for 2014 and 47% for 2013. Upon completion of the bare steel and cast iron pipe replacement, the Company plans to direct its efforts to replacing all pre-1973 plastic mains with polyethylene pipe. This project encompasses approximately 40 miles of natural gas main with a 2019 anticipated completion. The Company expects to increase its borrowing activity to meet the funding requirements of these plans.

Cash Flows Provided by (Used in) Financing Activities:

Financing activities generally consist of long-term and short-term borrowings and repayments, issuance of stock and the payment of dividends. As mentioned above, the Company uses its line-of-credit arrangement to fund seasonal working capital and provide temporary financing for capital projects. Cash flows used by financing activities were $2,875,000 for fiscal 2015 compared to cash provided by financing activities of $5,862,000 for fiscal 2014 and cash used in financing activities of $6,153,000 for fiscal 2013. After significant activity in the financing area in 2014,

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financing cash flow returned to a more normal pattern in fiscal 2015. In 2014, the Company refinanced $28,000,000 of its debt, including $2,238,000 in early termination fees on notes and interest rate swaps with $30,500,000 in unsecured 20-year term notes. The early termination fees were deferred as a regulatory asset and are being amortized over the term of the new notes as a component of interest expense. The $28,000,000 in retired debt had an average interest rate of 6.30% with an effective rate of 6.43%. The new debt has a stated interest rate of 4.26% and an effective rate of 4.67%. The nearly $315,000 reduction in interest expense in fiscal 2015 is entirely due to the refinancing. The Company’s utilization of its line-of-credit to fund both the Company’s seasonal working capital needs as well as bridge financing for its capital budget increased but not nearly to the extent expected due to the higher cash flows from operations. Dividends increased as the annualized dividend rate went from $0.74 per share to $0.77 per share in 2015. Fiscal 2013 included a special one-time dividend of $1.00 per share in addition to the regular quarterly dividend. The special dividend totaled $4,675,337, of which $425,630 was returned to the Company under the DRIP Plan. The Company’s consolidated capitalization was 63.4% equity and 36.6% long-term debt at September 30, 2015. This compares to 63.0% equity and 37.0% long-term debt at September 30, 2014

Effective March 31, 2015, the Company entered into a new line-of-credit agreement. This new agreement maintains the same terms and rates as provided for under the expired agreement with an increase in the total borrowing limit. The interest rate is based on 30-day LIBOR plus 100 basis points and includes an availability fee of 15 basis points applied to the difference between the face amount of the note and the average outstanding balance during the period. The Company maintained multi-tiered borrowing limits to accommodate seasonal borrowing demands and minimize overall borrowing costs, with available limits ranging from $6,000,000 to $24,000,000 during the term of the agreement. The upper limit of the line-of-credit increased over prior years due to expected capital expenditure funding needs. The line-of-credit agreement will expire March 31, 2016. The Company anticipates being able to extend or replace the line-of-credit upon expiration; however, there is no guarantee that the line-of-credit will be extended or replaced under the same or equivalent terms currently in place.

In addition to the Company’s ongoing capital projects, Midstream has a commitment to invest approximately $35 million over the next three years under the agreement as a 1% member of Mountain Valley Pipeline, LLC. The Company plans to use a combination of debt and equity financing to meet this commitment.

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, 2015, the estimated recorded and unrecorded obligations are as follows:

	Less than 1		1-3		4-5		After
Recorded contractual obligations:	year		Years		Years		5 Years		Total
Long-Term Debt (1)	$	—	$	—	$	—	$	30,500,000	$	30,500,000
Short-Term Debt (2)		9,340,997		—		—		—		9,340,997
Total	$	9,340,997	$	—	$	—	$	30,500,000	$	39,840,997

(1) See Note 4 to the consolidated financial statements.

(2) See Note 3 to the consolidated financial statements.

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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)	$	11,392,645	$	17,787,400	$	8,599,382	$	—	$	37,779,427
Gas Supply (4)		—		—		—		—		—
Interest on Short-Term Debt (5)		24,457		—		—		—		24,457
Interest on Long-Term Debt (6)		1,299,300		2,598,600		2,598,600		18,192,200		24,688,700
Pension Plan Funding (7)		—		—		—		—		—
Investment in MVP (8)		5,300,000		25,000,000		4,700,000		—		35,000,000
Other Obligations (9)		114,501		34,598		2,340		27,380		178,819
Total	$	18,130,903	$	45,420,598	$	15,900,322	$	18,219,580	$	97,671,403

(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 9 to the consolidated financial statements.

(5) Accrued interest on line-of-credit balance at September 30, 2015, including minimum facility fee on unused line-of-credit. See Note 3 to the consolidated financial statements.

(6) Semi-annual interest payment on 20-year $30.5 million note payable September 18, 2034. See Note 4 to the consolidated financial statements.

(7) Estimated minimum funding assuming application of credit balances in plan to offset funding. Minimum funding requirements beyond five years is not available. See Note 6 to the consolidated financial statements.

(8) Projected funding of the Company’s 1% interest in MVP as entered into on October 1, 2015.

(9) Various lease, maintenance, equipment and service contracts.

Equity Investment in Mountain Valley Pipeline

On October 1, 2015, the Company, through its newly formed wholly-owned subsidiary, Midstream, entered into an agreement to become a 1% member in Mountain Valley Pipeline, LLC (the “LLC”), an investment in the Mountain Valley Pipeline project. The purpose of the LLC is to construct and operate a natural gas pipeline connecting an existing transmission system in northern West Virginia to another interstate pipeline in south central Virginia. This project falls under the jurisdiction of FERC and is subject to its approval prior to beginning construction. In October 2015, the LLC filed the application with FERC to construct the pipeline with an expected decision in late 2016. Assuming a favorable response by FERC, the pipeline is expected to be in service by the end of calendar 2018.

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, the Company 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 pipeline would reduce the risk related to 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.

The total project cost is anticipated to be $3.5 billion. As a 1% member in the LLC, Midstream’s contribution is expected to be approximately $35 million. The agreement provides for a schedule of cash draws to fund the project. The initial payments are for the acquisition of land and materials related to the construction of the pipeline and other pre-construction costs. Once approved, more significant cash draws will be required.

Regulatory Affairs

On June 30, 2015, the Company filed an application for modification of the SAVE (Steps to Advance Virginia’s Energy) Plan and Rider. The original SAVE Plan and Rider were approved by the SCC through an order issued on August 29, 2012 and has been modified or amended each year since. The original SAVE Plan was designed to facilitate the accelerated replacement of the remaining bare steel and cast iron natural gas pipe by providing a mechanism for the

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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. The amendments in 2013 and 2014 included additional projects related to the replacement of bare steel and cast iron natural gas pipe in addition to two other major projects and added the investment for the related meter and regulator installations located on customer premises. On September 25, 2015, the Company received approval for its most recent amendment to the SAVE Plan effective for calendar year 2016, which included an increase in the investment to complete replacement of the bare steel and cast iron natural gas pipe in addition to the replacement of first generation plastic pipe. The SCC also approved the inclusion of the replacement of two of the Company’s natural gas transfer stations and an increase in the allowed spending variance for projects under the SAVE Plan. The projects included under the SAVE Plan will enhance the safety and reliability of the Company’s gas distribution system and reduce greenhouse emissions. In addition, the recovery of the depreciation and related expenses on these projects through the SAVE Plan rider will allow the Company to forego a formal non-gas rate increase at this time.

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 franchises with the City of Roanoke, the City of Salem and the Town of Vinton will expire January 1, 2016. The Company is currently in negotiations to renew the franchises in each of these localities. Management anticipates that it will be able to renew all of its franchises.

On March 25, 2015, the Company filed an application for approval of a Certificate of Public Convenience and Necessity with the SCC to include the remaining uncertificated portions of Franklin County into its authorized natural gas service territory. On July 30, 2015, the Company filed a Motion to Stay Proceeding requesting the SCC stay the application request pending further progress in the review of the Mountain Valley Pipeline project by FERC and reconsider the application at a later date. The SCC granted the stay on July 31, 2015, which permitted the Company to continue its application request at a later date.

On June 4, 2014, the Company filed an application with the SCC requesting approval to extend its authority to incur short-term indebtedness of up to $30,000,000 and to issue up to $60,000,000 in long-term debt securities as part of its long-term financing plan, which included the refinancing of higher interest rate debt and funding for the Company’s pipeline replacement program and other infrastructure projects. On June 25, 2014, the SCC issued an order granting the approval of the Company’s request. The authority to issue long-term debt extends through September 30, 2019. In September 2014, the Company retired $28,000,000 in outstanding debt and replaced it with $30,500,000 in lower interest rate long-term debt. With significant capital expenditures planned over the next few years related to the SAVE Plan and other projects, the Company will have the flexibility to seek and manage the timing of long-term financing.

The Company’s provision for depreciation is computed principally based on composite rates determined by depreciation studies. These depreciation studies are required to be performed on the regulated utility assets of Roanoke Gas Company at least every five years. In June 2014, the Company filed an updated depreciation study with the SCC to update the previous study that was implemented in fiscal 2009. The SCC approved new rates in September 2014 which resulted in a small reduction in the overall composite depreciation rate from 3.35% in 2013 to 3.25% in fiscal 2014 and 2015. The new rates were implemented retroactive to October 1, 2013.

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.

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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 required under the provisions of FASB ASC No. 980, Regulated Operations, the Company recognizes billed revenue related to the SAVE projects to the extent such revenues have been earned under the provisions of the SAVE Plan.

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 $1,001,418 and $1,071,128 as of September 30, 2015 and 2014, respectively.

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.

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 6 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 4.22% and 4.15% for valuing its pension plan liability and postretirement plan liability at September 30, 2015. This rate was unchanged for the pension plan and increased by only 0.05% from the prior year for the postretirement plan. The ongoing low interest rate environment has kept the discount rate depressed thereby keeping the liabilities at higher levels. Although the 30-year Treasury rate decreased from 3.21% to 2.87%, the Moody’s Aaa was nearly unchanged decreasing by only 0.05% which corresponds to the minimal change in the discount rates used by the benefit plans. As the discount rates remained at or near last year’s levels, the increase in each plan’s liability was

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driven in part to an additional year of accreated service. However, the most significant impact to the liabilities is attributed to the adoption of new mortality tables. On October 27, 2014, the Society of Actuaries released the final reports of the pension plan RP-2014 Mortality Tables and the Mortality Improvement Scale MP-2014. The new mortality tables, which were adopted by the Company for its current defined benefit plan valuations, extend the assumed life expectancy of participants in the plans and provide a better measure of defined benefit plan liabilities. The impact of the change in assumed mortality increased the Company’s pension liability by approximately 5% or nearly $1.3 million and the postretirement liability by approximately 7% or about $1 million, thereby increasing future expense.

Following better than expected returns in fiscal 2013 and 2014, the returns on the related pension and postretirement assets for fiscal 2015 fell short of the corresponding long-term rate of return assumptions. During fiscal 2015 fourth quarter, the equity markets experienced a greater than 10% market correction which was reflected in the plans’ asset balances at September 30, 2015. The Company took advantage of lower equity prices and contributed an additional $900,000 during the quarter, over and above the previously projected $800,000 annual contribution to the pension plan. The increased contributions served to mitigate the impact of the adoption of the RP-2014 Mortiality Tables and lower investment returns. As a result of the increase in the funded deficit, pension and postretirement medical plan expense will increase in fiscal 2016 due to an increase in the amortization of the actuarial loss. The following tables reflect the funded status of both plans at the corresponding fiscal year ends.

Funded status - September 30, 2015	Pension			Postretirement			Total
Benefit obligation	$	27,167,621		$	15,355,668		$	42,523,289
Fair value of assets		21,394,399			10,443,629			31,838,028
Funded status	$	(5,773,222	)	$	(4,912,039	)	$	(10,685,261	)
Funded status - September 30, 2014	Pension			Postretirement			Total
Benefit obligation	$	24,636,695		$	14,983,169		$	39,619,864
Fair value of assets		20,514,179			10,646,249			31,160,428
Funded status	$	(4,122,516	)	$	(4,336,920	)	$	(8,459,436	)

The economic environment makes it difficult to project interest rates and future investment returns. Current indications tend to support an increase in interest rates; however, any expectation or trend beyond an initial increase is indeterminable. If the economy improves, long-term interest rates could increase thereby reducing the benefit liabilities. However, increasing interest rates could have a negative effect on investment returns, especially in the fixed income allocation, and any benefit obtained from reduced benefit liabilities could be mitigated by less than expected returns on assets. Conversely, if the economy stagnates or declines, interest rates could remain at lower levels or even drop, leading to an increase in the benefit liabilities. The Company annually evaluates the returns on its targeted investment allocation model. The investment policy as of the measurement date in September reflected a targeted allocation of 60% equity and 40% fixed income on the pension plan and a targeted allocation of 50% equity and 50% fixed income for the postretirement plan. As a result of this evaluation, the Company set its expected long-term annual return on pension assets at 7.00% and postretirement assets at 4.89% (net of income taxes) for fiscal 2016. These rates are consistent with the expected long-term rates in place during fiscal 2015.

In August 2014, the Highway and Transportation Funding Act of 2014 (“HATFA”) was signed into law, which included a provision to extend the interest rate corridors introduced in 2012 under the Moving Ahead for Progress in the 21st Century Act (“MAP-21”). MAP-21 provided temporary funding relief for defined benefit pension plans. The requirements of the Employee Retirement Income Security Act of 1974 (ERISA) and the Pension Protection Act of 2006 (PPA) subject defined benefit plans to minimum funding rules. As a result, when interest rates are low, pension plan liabilities increase thereby resulting in higher mandatory contributions to meet minimum funding obligations. MAP-21 provided funding relief by allowing pension plans to adjust the interest rates used in determining funding requirements so that they are within 10% of the average of interest rates for the 25-year period preceding the current year for funding calculations for 2013 to within 30% for funding periods beginning in 2016. HATFA extended the period of time that the 10% corridor instituted by MAP-21 may be used for funding calculations. Under HATFA, the

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10% corridor extends through plan years that begin in 2017 and phases out to a 30% corridor in 2021 and later. HATFA significantly increases the effective interest rates used in determining funding requirements and could result in a deterioration of the pension plan funded status resulting in much greater funding requirements in the future as well as higher PBGC (Pension Benefit Guaranty Corporation) premiums paid by sponsors of pension plans to protect participants in the event of default by the employer. Management estimates that, under the provisions of HATFA, the Company will have no minimum funding requirements next year. Although HATFA and MAP-21 allow the Company some short-term funding relief, management expects to continue its pension funding plan by contributing the greater of the minimum annual pension contribution requirement or its expense level for subsequent years. The Company currently expects to contribute approximately $500,000 to its pension plan and $500,000 to its postretirement plan in fiscal 2016. With pension expense expected to be approximately $837,000 in fiscal 2016, management is still following the funding strategy when considering the $900,000 in additional funding made in the fiscal fourth quarter of 2015. 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.

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	Change in Assumption			Increase in Pension Cost		Increase in Projected Benefit Obligation
Discount rate		-0.25	%	$	114,000	$	1,132,000
Rate of return on plan assets		-0.25	%		53,000		N/A
Rate of increase in compensation		0.25	%		55,000		306,000

The following schedule reflects the sensitivity of postretirement benefit costs from changes in certain actuarial assumptions, while the other components of the calculation remain constant.

Actuarial Assumptions	Change in Assumption			Increase in Postretirement Benefit Cost		Increase in Accumulated Postretirement Benefit Obligation
Discount rate		-0.25	%	$	35,000	$	569,000
Rate of return on plan assets		-0.25	%		26,000		N/A
Medical claim cost increase		0.25	%		78,000		596,000

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 no commodity or interest rate derivatives outstanding at September 30, 2015 and 2014.

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.

27

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, 2015, the Company has $9,340,997 outstanding under its variable rate line-of-credit. 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 $64,700. 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, 2015, the Company had no outstanding derivative instruments to hedge the price of natural gas. The Company had approximately 2,418,000 decatherms of gas in storage, including LNG, at an average price of $3.38 per decatherm compared to 2,424,000 decatherms at an average price of $4.71 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 the derivative contracts and other price hedging techniques are passed through to customers when realized through the regulated natural gas PGA mechanism.

Item 8. Financial Statements and Supplementary Data.

28

 RGC Resources, Inc. and Subsidiaries

 Consolidated Financial Statements

 for the Years Ended September 30, 2015, 2014

 and 2013, and Report of Independent

 Registered Public Accounting Firm

29

RGC RESOURCES, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

	Page
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM		31
CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED SEPTEMBER 30, 2015, 2014 and 2013:
Consolidated Balance Sheets		32
Consolidated Statements of Income		34
Consolidated Statements of Comprehensive Income		35
Consolidated Statements of Stockholders’ Equity		36
Consolidated Statements of Cash Flows		37
Notes to Consolidated Financial Statements		38

30

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

RGC Resources, Inc.

Roanoke, Virginia

We have audited the accompanying consolidated balance sheets of RGC Resources, Inc. and Subsidiaries (“the Company”) as of September 30, 2015 and 2014, 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, 2015. RGC Resources, Inc.’s management is responsible for these financial statements. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of RGC Resources, Inc. and Subsidiaries as of September 30, 2015 and 2014, and the consolidated results of its operations and its cash flows for each of the years in the three-year period ended September 30, 2015, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), RGC Resources, Inc. and Subsidiaries’ internal control over financial reporting as of September 30, 2015, based on criteria established in Internal Control-Integrated Framework —1992 issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated December 4, 2015 expressed an unqualified opinion.

CERTIFIED PUBLIC ACCOUNTANTS

1715 Pratt Drive, Suite 2700

Blacksburg, Virginia

December 4, 2015

31

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

AS OF SEPTEMBER 30, 2015 AND 2014

	2015			2014
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	985,234		$	849,757
Accounts receivable, net		3,196,573			3,730,173
Materials and supplies		968,108			893,672
Gas in storage		8,160,498			11,402,990
Prepaid income taxes		1,657,066			1,144,214
Deferred income taxes		2,293,536			1,704,320
Under-recovery of gas costs		—			180,831
Other		1,182,343			1,104,660
Total current assets		18,443,358			21,010,617
UTILITY PROPERTY:
In service		168,033,032			155,360,200
Accumulated depreciation and amortization		(53,307,079	)		(50,645,642	)
In service, net		114,725,953			104,714,558
Construction work in progress		3,903,599			4,029,019
Utility plant, net		118,629,552			108,743,577
OTHER ASSETS:
Regulatory assets		10,923,243			9,273,389
Other		144,577			100,058
Total other assets		11,067,820			9,373,447
TOTAL ASSETS	$	148,140,730		$	139,127,641

(Continued)

32

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

AS OF SEPTEMBER 30, 2015 AND 2014

	2015			2014
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Borrowings under line-of-credit	$	9,340,997		$	9,045,050
Dividends payable		912,995			873,326
Accounts payable		5,141,677			5,367,299
Customer credit balances		1,560,351			1,373,927
Customer deposits		1,579,441			1,492,150
Accrued expenses		2,766,097			2,200,882
Over-recovery of gas costs		1,901,426			—
Total current liabilities		23,202,984			20,352,634
LONG-TERM DEBT
Principal amount		30,500,000			30,500,000
Less unamortized debt issuance costs		(183,427	)		(193,081	)
Long-term debt net of unamortized debt issuance costs		30,316,573			30,306,919
DEFERRED CREDITS AND OTHER LIABILITIES:
Asset retirement obligations		5,295,868			4,802,015
Regulatory cost of retirement obligations		8,885,486			8,575,147
Benefit plan liabilities		10,685,261			8,459,436
Deferred income taxes		16,913,567			14,610,643
Total deferred credits and other liabilities		41,780,182			36,447,241
COMMITMENTS AND CONTINGENCIES (Note 9)
CAPITALIZATION:
Stockholders’ Equity:
Common stock, $5 par value; authorized 10,000,000 shares; issued and outstanding 4,741,498 and 4,720,378 shares in 2015 and 2014, respectively		23,707,490			23,601,890
Preferred stock, no par; authorized 5,000,000 shares; no shares issued and outstanding in 2015 and 2014		—			—
Capital in excess of par value		8,647,669			8,237,228
Retained earnings		22,772,377			21,321,055
Accumulated other comprehensive loss		(2,286,545	)		(1,139,326	)
Total stockholders’ equity		52,840,991			52,020,847
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	148,140,730		$	139,127,641

(Concluded)

See notes to consolidated financial statements.

33

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

YEARS ENDED SEPTEMBER 30, 2015, 2014 AND 2013

	2015		2014		2013
OPERATING REVENUES:
Gas utilities	$	67,094,290	$	73,865,487	$	62,024,174
Other		1,095,317		1,150,647		1,181,492
Total operating revenues		68,189,607		75,016,134		63,205,666
COST OF SALES:
Gas utilities		37,437,315		45,091,274		34,916,062
Other		545,859		587,771		686,713
Total cost of sales		37,983,174		45,679,045		35,602,775
GROSS MARGIN		30,206,433		29,337,089		27,602,891
OTHER OPERATING EXPENSES:
Operations and maintenance		13,486,885		13,383,388		12,853,599
General taxes		1,606,421		1,560,386		1,480,746
Depreciation and amortization		5,106,935		4,711,447		4,473,491
Total other operating expenses		20,200,241		19,655,221		18,807,836
OPERATING INCOME		10,006,192		9,681,868		8,795,055
OTHER EXPENSE, net		228,796		206,887		60,117
INTEREST EXPENSE		1,512,419		1,827,001		1,828,099
INCOME BEFORE INCOME TAXES		8,264,977		7,647,980		6,906,839
INCOME TAX EXPENSE		3,170,562		2,939,540		2,644,787
NET INCOME	$	5,094,415	$	4,708,440	$	4,262,052
EARNINGS PER COMMON SHARE:
Basic	$	1.08	$	1.00	$	0.91
Diluted	$	1.08	$	1.00	$	0.91
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic		4,728,210		4,715,478		4,698,727
Diluted		4,731,676		4,716,282		4,698,766

See notes to consolidated financial statements.

34

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

YEARS ENDED SEPTEMBER 30, 2015, 2014 AND 2013

	2015			2014			2013
NET INCOME	$	5,094,415		$	4,708,440		$	4,262,052
Other comprehensive income, net of tax:
Interest rate swaps		—			1,232,546			576,985
Defined benefit plans		(1,147,219	)		(220,638	)		1,221,866
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX		(1,147,219	)		1,011,908			1,798,851
COMPREHENSIVE INCOME	$	3,947,196		$	5,720,348		$	6,060,903

See notes to consolidated financial statements.

35

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

YEARS ENDED SEPTEMBER 30, 2015, 2014 AND 2013

	Common Stock		Capital in Excess of Par Value		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Stockholders’ Equity
Balance - September 30, 2012	$	23,352,835	$	7,375,666	$	23,904,514		$	(3,950,085	)	$	50,682,930
Net income		—		—		4,262,052			—			4,262,052
Other comprehensive income		—		—		—			1,798,851			1,798,851
Stock option grants		—		84,840		—			—			84,840
Cash dividends declared ($1.72 per share)		—		—		(8,063,327	)		—			(8,063,327	)
Issuance of common stock (38,759 shares)		193,795		543,281		—			—			737,076
Balance - September 30, 2013	$	23,546,630	$	8,003,787	$	20,103,239		$	(2,151,234	)	$	49,502,422
Net income		—		—		4,708,440			—			4,708,440
Other comprehensive income		—		—		—			1,011,908			1,011,908
Stock option grants		—		75,310		—			—			75,310
Cash dividends declared ($0.74 per share)		—		—		(3,490,624	)		—			(3,490,624	)
Issuance of common stock (11,052 shares)		55,260		158,131		—			—			213,391
Balance - September 30, 2014	$	23,601,890	$	8,237,228	$	21,321,055		$	(1,139,326	)	$	52,020,847
Net income		—		—		5,094,415			—			5,094,415
Other comprehensive loss		—		—		—			(1,147,219	)		(1,147,219	)
Exercise of stock options (2,600 shares)		13,000		36,366		—			—			49,366
Stock option grants		—		83,640		—			—			83,640
Cash dividends declared ($0.77 per share)		—		—		(3,643,093	)		—			(3,643,093	)
Issuance of common stock (18,520 shares)		92,600		290,435		—			—			383,035
Balance - September 30, 2015	$	23,707,490	$	8,647,669	$	22,772,377		$	(2,286,545	)	$	52,840,991

See notes to consolidated financial statements.

36

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

YEARS ENDED SEPTEMBER 30, 2015, 2014 AND 2013

	2015			2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	5,094,415		$	4,708,440		$	4,262,052
Adjustments to reconcile net income to net cash provided by operations:
Depreciation and amortization		5,219,893			4,838,062			4,656,716
Cost of retirement of utility plant, net		(406,731	)		(452,834	)		(502,587	)
Stock option grants		83,640			75,310			84,840
Deferred taxes and investment tax credits		2,416,841			859,788			786,990
Other noncash items, net		105,815			38,073			39,186
Changes in assets and liabilities which provided (used) cash:
Accounts receivable and customer deposits, net		638,917			12,424			(374,682	)
Inventories and gas in storage		3,168,056			(1,219,641	)		(997,378	)
Over/under recovery of gas costs		2,082,257			(1,208,134	)		1,714,497
Other assets		(768,922	)		(306,744	)		1,106,590
Accounts payable, customer credit balances and accrued expenses, net		(873,354	)		(505,006	)		(739,154	)
Total adjustments		11,666,412			2,131,298			5,775,018
Net cash provided by operating activities		16,760,827			6,839,738			10,037,070
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for utility property		(13,780,356	)		(14,715,428	)		(9,977,433	)
Proceeds from disposal of utility property		30,082			16,858			29,923
Net cash used in investing activities		(13,750,274	)		(14,698,570	)		(9,947,510	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds on collection of notes		—			—			1,142,770
Borrowings under line-of-credit		34,698,924			25,363,774			4,354,402
Repayments under line-of-credit		(34,402,977	)		(16,318,724	)		(4,354,402	)
Proceeds from issuance of unsecured notes		—			30,500,000			—
Retirement of note payable		—			(15,000,000	)		—
Retirement of long-term debt		—			(13,000,000	)		—
Early termination fees		—			(2,237,961	)		—
Debt issuance expenses		—			(193,081	)		—
Proceeds from issuance of stock		432,401			213,391			737,076
Cash dividends paid		(3,603,424	)		(3,465,034	)		(8,033,053	)
Net cash provided by (used in) financing activities		(2,875,076	)		5,862,365			(6,153,207	)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		135,477			(1,996,467	)		(6,063,647	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		849,757			2,846,224			8,909,871
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	985,234		$	849,757		$	2,846,224
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the year for:
Interest	$	1,002,462		$	1,966,263		$	1,803,528
Income taxes		1,266,573			2,387,000			622,076

See notes to consolidated financial statements.

37

RGC RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2015, 2014 AND 2013

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation—RGC Resources, Inc. is an energy services company 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; RGC Ventures of Virginia, Inc., operating as Application Resources and The Utility Consultants; and RGC Midstream, LLC. Roanoke Gas is a natural gas utility, which distributes and sells natural gas to approximately 59,100 residential, commercial and industrial customers within its service areas in Roanoke, Virginia and the surrounding localities. The Company’s business is seasonal in nature and weather dependent 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”). Application Resources provides information system services to software providers in the utility industry. The Utility Consultants, which provided regulatory consulting services to other utilities, ceased operations in 2015. RGC Midstream, LLC is a new wholly-owned subsidiary created in 2015 to invest in a pipeline project. More information is provided in Note 12. Diversified Energy Company is currently inactive.

The Company follows accounting and reporting standards set 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.

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.

38

Regulatory assets and liabilities included in the Company’s consolidated balance sheets as of September 30, 2015 and 2014 are as follows:

	September 30
	2015		2014
Regulatory Assets:
Current Assets:
Accounts receivable:
Accrued WNA revenues	$	229,281	$	143,753
Under-recovery of gas costs		—		180,831
Other:
Accrued pension and postretirement medical		530,781		394,215
Utility Property:
In service:
Other		11,945		11,945
Other Assets:
Regulatory assets:
Premium on early retirement of debt		2,169,556		2,283,744
Accrued pension and postretirement medical		8,378,419		6,884,812
Other		375,268		104,833
Total regulatory assets	$	11,695,250	$	10,004,133
Regulatory Liabilities:
Current Liabilities:
Over-recovery of gas costs	$	1,901,426	$	—
Accrued expenses:
Over-recovery of SAVE Plan revenues		153,365		187,203
Deferred Credits and Other Liabilities:
Asset retirement obligations		5,295,868		4,802,015
Regulatory cost of retirement obligations		8,885,486		8,575,147
Total regulatory liabilities	$	16,236,145	$	13,564,365

As of September 30, 2015, the Company had regulatory assets in the amount of $9,513,749 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. The cost of additions to utility plant includes direct charges and overhead. The cost of depreciable property retired is 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. Maintenance, repairs, and minor renewals and betterments of property are charged to operations and maintenance.

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

	Years Ended September 30
	2015		2014
Distribution and transmission	$	143,172,628	$	134,439,225
LNG storage		12,501,179		9,163,158
General and miscellaneous		12,359,225		11,757,817
Total utility plant in service	$	168,033,032	$	155,360,200

39

Provisions for depreciation are computed principally at composite straight-line rates as determined by depreciation studies required to be performed on the regulated utility assets of Roanoke Gas Company at least every five years. The Company completed its most recent depreciation study in June 2014. The composite weighted-average depreciation rates provided for under the new depreciation study were 3.25% for the fiscal years ended September 30, 2015 and 2014 compared to 3.35% for the fiscal year ended September 30, 2013 under the prior rates. For the year ended September 30, 2014, the implementation of the new depreciation rates reduced depreciation expense by $126,875 and increased net income by $78,713 and earnings per share by $0.02.

The composite rates are comprised 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 evacuating 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 2015, 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
	2015			2014
Beginning balance	$	4,802,015		$	4,525,355
Liabilities incurred		62,890			74,276
Liabilities settled		(162,072	)		(165,845	)
Accretion		281,762			258,763
Revisions to estimated cash flows		311,273			109,466
Ending balance	$	5,295,868		$	4,802,015

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, 2015, 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.

40

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

	Years Ended September 30
	2015			2014			2013
Beginning balance	$	70,747		$	68,539		$	65,219
Provision for doubtful accounts		87,908			148,881			85,033
Recoveries of accounts written off		139,282			136,369			122,432
Accounts written off		(245,216	)		(283,042	)		(204,145	)
Ending balance	$	52,721		$	70,747		$	68,539

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 are the Company’s one primary type of financing receivables, resulting from the sale of natural gas and other services to its customers. These receivable are short-term in nature with a provision for uncollectible balances included in the financial statements.

Inventories—Inventories, consisting of natural gas in storage and materials and supplies, are recorded at average cost. Injections into storage are priced at the purchase cost at the time of injection and withdrawals from storage are priced at the weighted average price 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, 2015 and 2014 were $1,001,418 and $1,071,128, 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 amortized over the lives of the debt instruments.

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 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 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.

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• 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 6 and 10.

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
	2015		2014		2013
Net Income	$	5,094,415	$	4,708,440	$	4,262,052
Weighted-average common shares		4,728,210		4,715,478		4,698,727
Effect of dilutive securities:
Options to purchase common stock		3,466		804		39
Diluted average common shares		4,731,676		4,716,282		4,698,766
Earnings Per Share of Common Stock:
Basic	$	1.08	$	1.00	$	0.91
Diluted	$	1.08	$	1.00	$	0.91

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, 2016. 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 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. hedges 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, 2015 and 2014, the Company had no outstanding derivative instruments for the purchase of natural gas.

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The Company also had two interest rate swaps that essentially converted its variable interest rate notes to fixed rate debt instruments. Both swaps were terminated in September 2014 as part of the Company’s debt refinancing. These swaps qualified as cash flow hedges with changes in fair value reported in other comprehensive income.

No derivative instruments were deemed to be ineffective for any period presented.

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, 2015:
Defined benefit plans:
Net loss arising during period	$	(1,910,573	)	$	726,017		$	(1,184,556	)
Amortization of actuarial losses		60,221			(22,884	)		37,337
Other comprehensive loss	$	(1,850,352	)	$	703,133		$	(1,147,219	)
Year Ended September 30, 2014:
Interest rate swaps:
Unrealized losses	$	(58,800	)	$	22,321		$	(36,479	)
Transfer of realized losses to interest expense		926,262			(351,609	)		574,653
Transfer of realized losses to regulatory asset		1,119,233			(424,861	)		694,372
Net interest rate swaps		1,986,695			(754,149	)		1,232,546
Defined benefit plans:
Net loss arising during period		(397,714	)		151,131			(246,583	)
Amortization of actuarial losses		41,846			(15,901	)		25,945
Net defined benefit plans		(355,868	)		135,230			(220,638	)
Other comprehensive income	$	1,630,827		$	(618,919	)	$	1,011,908
Year Ended September 30, 2013:
Interest rate swaps:
Unrealized losses	$	(20,479	)	$	7,774		$	(12,705	)
Transfer of realized losses to interest expense		950,501			(360,811	)		589,690
Net interest rate swaps		930,022			(353,037	)		576,985
Defined benefit plans:
Net gain arising during period		1,714,890			(651,659	)		1,063,231
Amortization of actuarial losses		219,890			(83,558	)		136,332
Amortization of transition obligation		35,972			(13,669	)		22,303
Net defined benefit plans		1,970,752			(748,886	)		1,221,866
Other comprehensive income	$	2,900,774		$	(1,101,923	)	$	1,798,851

The amortization of actuarial losses and transition obligation is included as components of net periodic pension and postretirement benefit costs and is included in operations and maintenance expense.

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Composition of Accumulated Other Comprehensive Income (Loss)

	Interest Rate Swaps			Defined  Benefit Plans			Accumulated Other Comprehensive Income (Loss)
Balance September 30, 2012	$	(1,809,531	)	$	(2,140,554	)	$	(3,950,085	)
Other comprehensive income (loss)		576,985			1,221,866			1,798,851
Balance September 30, 2013		(1,232,546	)		(918,688	)		(2,151,234	)
Other comprehensive income (loss)		1,232,546			(220,638	)		1,011,908
Balance September 30, 2014		—			(1,139,326	)		(1,139,326	)
Other comprehensive income (loss)		—			(1,147,219	)		(1,147,219	)
Balance September 30, 2015	$	—		$	(2,286,545	)	$	(2,286,545	)

Change in Method of Accounting for Long-term Debt—During the fiscal year ended September 30, 2015, the Company adopted the provisions of ASU 2015-03 as described further under the Recently Adopted Accounting Standards section below. Under ASU 2015-03, the unamortized balance of debt issuance costs are reclassified from assets to liabilities and netted against the carrying value of long-term debt. The change had no impact on net income.

Management retrospectively applied the change. The carrying value of long-term debt and the reclassified debt issuance costs are presented separately on the Company’s Consolidated Balance Sheets and in Note 4 for the periods ended September 30, 2015 and 2014.

Recently Adopted Accounting Standards—In June 2011, the FASB issued guidance under FASB ASC No. 220—Comprehensive Income that defines the presentation of Comprehensive Income in the financial statements. According to the guidance, an entity may present a single continuous statement of comprehensive income or two separate statements—a statement of income and a statement of other comprehensive income that immediately follows the statement of income. In either presentation, the entity is required to present on the face of the financial statement the components of other comprehensive income including the reclassification adjustment for items that are reclassified from other comprehensive income to net income. In December 2011, the FASB issued additional guidance under FASB ASC No. 220 that deferred the effective date of earlier guidance with regard to the presentation of reclassifications of items out of accumulated other comprehensive income. All other provisions of the original guidance remain in effect. In February 2013, the FASB issued additional guidance regarding the reporting of amounts reclassified out of accumulated other comprehensive income. Under the new provisions, an entity must present the effects on the line items of net income of significant amounts reclassified out of accumulated other comprehensive income. The disclosures required under this guidance are provided above.

In April 2015, the FASB issued ASU 2015-03, Interest-Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs. This ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. The Company previously recognized debt issuance costs in assets and amortized those costs over the term of the debt. This guidance is effective for the Company for the annual reporting period ending September 30, 2017 and interim periods within that annual period. Early application is permitted. The Company adopted the ASU during the current reporting period. The adoption of this ASU did not have an effect on the Company’s results of operations or cash flows; however, the unamortized balance of debt issuance costs were reclassified from assets to an offset against long-term debt. Certain deferred costs related to the early retirement of debt in 2014 are classified as regulatory assets and are not offset against debt. The changes required under this guidance are presented in Note 1, Note 4 and the Consolidated Balance Sheets.

Recently Issued Accounting Standards—In May 2014, the FASB issued guidance under FASB ASC No. 606—Revenue from Contracts with Customers 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 these 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 Accounting Standards Update (ASU) 2015-14 that deferred the effective date of this guidance by one year. Therefore, the new guidance is effective for the Company for the

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annual reporting period ended September 30, 2019 and interim periods within that annual period. Early application is not permitted. Management has not completed its evaluation of the new guidance; however, the Company does not currently expect it 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. REGULATORY MATTERS

The SCC exercises regulatory authority over the natural gas operations of Roanoke Gas Company. Such regulation encompasses terms, conditions and rates to be charged to customers for natural gas service, safety standards, service extension, accounting and depreciation.

On September 25, 2015, the Company received approval of its application for a modification to the SAVE (Steps to Advance Virginia’s Energy) Plan and Rider. The original SAVE Plan filed in 2012 has been modified each year to incorporate certain changes and to include new projects that qualify for recovery under the Plan. The SAVE Rider provides a mechanism for the Company to recover the related depreciation and expenses and return on rate base of the additional capital investment without the filing of a formal application for an increase in non-gas base rates.

On June 25, 2014, the SCC approved the Company’s application requesting approval to extend its authority to incur short-term indebtedness of up to $30,000,000 and to issue up to $60,000,000 in long-term securities. The short-term indebtedness authority allows the Company to continue to access its line-of-credit to provide seasonal funding of its working capital needs as well as provide temporary bridge financing for its capital expenditures. The authority to issue long-term securities allowed the Company to refinance its higher interest debt in September 2014 and provides the Company with the approval to secure longer term funding for its capital expenditures.

3. SHORT-TERM DEBT

The Company has available an unsecured line-of-credit with a bank which will expire March 31, 2016. The Company anticipates being able to extend or replace this line-of-credit upon expiration. The Company’s available unsecured line-of-credit varies during the year to accommodate its seasonal borrowing demands. Available limits under this agreement for the remaining term are as follows:

Effective	Available Line-of-Credit
September 30, 2015	$	24,000,000
March 1, 2016		17,000,000

A summary of the line-of-credit follows:

	September 30
	2015			2014			2013
Line-of-credit at year-end	$	24,000,000		$	15,000,000		$	5,000,000
Outstanding balance at year-end		9,340,997			9,045,050			—
Highest month-end balance outstanding		17,366,052			9,045,050			1,414,955
Average daily balance		6,377,040			1,340,833			80,593
Average rate of interest during year on outstanding balances		1.17	%		1.16	%		1.21	%
Interest rate at year-end		1.20	%		1.16	%		1.18	%
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 provisions including a financial ratio that requires the Company to maintain an interest coverage ratio of not less than 1.5 to 1.

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4. LONG-TERM DEBT

Long-term debt consists of the following:

	September 30
	2015				2014
	Principal		Unamortized Debt Issuance Costs		Principal		Unamortized Debt Issuance Costs
Unsecured senior notes payable, at 4.26%, due on September 18, 2034	$	30,500,000	$	183,427	$	30,500,000	$	193,081
Total	$	30,500,000	$	183,427	$	30,500,000	$	193,081

Debt issuance costs are amortized over the life of the related debt. As of September 30, 2015 and 2014, the Company also had an unamortized loss on the early retirement of debt of $2,169,556 and $2,283,744, respectively, which has been deferred as a regulatory asset and is being amortized over a 20 year period.

The unsecured notes payable contain various provisions, including two financial covenants. First, total long-term debt, including current maturities, shall not exceed 65% of total capitalization. Second, the Company shall not allow priority indebtedness to exceed 15% of total assets.

The aggregate annual maturities of long-term debt for the next five years ending after September 30, 2015 are as follows:

Year Ending September 30	Maturities
2016	$	—
2017		—
2018		—
2019		—
2020		—
Thereafter		30,500,000
Total	$	30,500,000

5. INCOME TAXES

The details of income tax expense are as follows:

	Years Ended September 30
	2015		2014			2013
Current income taxes:
Federal	$	379,180	$	1,789,294		$	1,404,450
State		374,541		290,458			453,347
Total current income taxes		753,721		2,079,752			1,857,797
Deferred income taxes:
Federal		2,289,729		687,417			829,080
State		127,112		175,464			(33,051	)
Total deferred income taxes		2,416,841		862,881			796,029
Amortization of investment tax credits		—		(3,093	)		(9,039	)
Total income tax expense	$	3,170,562	$	2,939,540		$	2,644,787

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Income tax expense for the years ended September 30, 2015, 2014 and 2013 differed from amounts computed by applying the U.S. Federal income tax rate of 34% to earnings before income taxes due to the following:

	Years Ended September 30
	2015		2014			2013
Income before income taxes	$	8,264,977	$	7,647,980		$	6,906,839
Income tax expense computed at the federal statutory rate	$	2,810,092	$	2,600,313		$	2,348,325
State income taxes, net of federal income tax benefit		331,091		307,509			277,395
Amortization of investment tax credits		—		(3,093	)		(9,039	)
Other, net		29,379		34,811			28,106
Total income tax expense	$	3,170,562	$	2,939,540		$	2,644,787

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

	September 30
	2015		2014
Deferred tax assets:
Allowance for uncollectibles	$	20,012	$	26,855
Accrued pension and postretirement medical benefits		2,502,774		2,077,409
Accrued vacation		249,837		230,842
Over-recovery of gas costs		721,782		—
Costs of gas held in storage		930,524		973,651
Accrued gas costs		—		36,305
Deferred compensation		651,336		579,451
Other		265,951		295,654
Total gross deferred tax assets		5,342,216		4,220,167
Deferred tax liabilities:
Utility plant		19,804,862		17,057,847
Under-recovery of gas costs		—		68,643
Accrued gas costs		157,385		—
Total gross deferred tax liabilities		19,962,247		17,126,490
Net deferred tax liability	$	14,620,031	$	12,906,323
Deferred Income Tax - Balance Sheet
	September 30
	2015		2014
Deferred income taxes (net current assets)	$	2,293,536	$	1,704,320
Deferred income taxes (net non-current liabilities)		16,913,567		14,610,643
Net deferred tax liability	$	14,620,031	$	12,906,323

Current federal tax expense for fiscal 2015 reflected the effect of 50% bonus depreciation for the entire calendar year of 2014, which included nine months of the prior fiscal year. The extension of bonus depreciation for 2014 was signed into law subsequent to the issuance of the Company’s financial statements for the year ended September 30, 2014. As a result, $1,442,211 of deferred taxes that related to the prior year were reflected in the current year tax provision, thereby reducing the current tax expense by the same amount. Total income tax expense was not impacted by the classification change between current and deferred income taxes.

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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, 2012 are no longer subject to examination.

6. EMPLOYEE BENEFIT PLANS

The Company sponsors both a noncontributory defined benefit pension plan and a postretirement benefit plan (“Plans”). The defined benefit 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. The postretirement benefit plan provides certain healthcare, 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 its statement 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.

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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
	2015			2014			2015			2014
Accumulated benefit obligation	$	22,853,206		$	20,697,734		$	15,355,668		$	14,983,169
Change in benefit obligation:
Benefit obligation at beginning of year	$	24,636,695		$	21,468,769		$	14,983,169		$	13,028,628
Service cost		654,782			553,291			167,580			168,634
Interest cost		1,025,908			1,020,302			600,096			602,684
Actuarial loss		1,487,278			2,199,697			70,196			1,673,552
Benefit payments, net of retiree contributions		(637,042	)		(605,364	)		(465,373	)		(490,329	)
Benefit obligation at end of year	$	27,167,621		$	24,636,695		$	15,355,668		$	14,983,169
Change in fair value of plan assets:
Fair value of plan assets at beginning of year	$	20,514,179		$	18,801,262		$	10,646,249		$	10,114,062
Actual return on plan assets, net of taxes		(182,738	)		1,750,033			(237,247	)		522,516
Employer contributions		1,700,000			568,248			500,000			500,000
Benefit payments, net of retiree contributions		(637,042	)		(605,364	)		(465,373	)		(490,329	)
Fair value of plan assets at end of year	$	21,394,399		$	20,514,179		$	10,443,629		$	10,646,249
Funded status	$	(5,773,222	)	$	(4,122,516	)	$	(4,912,039	)	$	(4,336,920	)
Amounts recognized in the balance sheets consist of:
Noncurrent liabilities	$	(5,773,222	)	$	(4,122,516	)	$	(4,912,039	)	$	(4,336,920	)
Amounts recognized in accumulated other comprehensive loss:
Transition obligation, net of tax	$	—		$	—		$	—		$	—
Net actuarial loss, net of tax		1,694,924			616,352			591,621			522,974
Total amounts included in other comprehensive loss, net of tax	$	1,694,924		$	616,352		$	591,621		$	522,974
Amounts deferred to a regulatory asset:
Transition obligation	$	—		$	—		$	—		$	—
Net actuarial loss		5,280,756			4,166,900			3,628,448			3,112,127
Amounts recognized as regulatory assets	$	5,280,756		$	4,166,900		$	3,628,448		$	3,112,127

Effective with the valuation of the September 30, 2015 defined benefit obligations, the Company adopted the new RP-2014 Mortality Tables as issued by the Society of Actuaries in late 2014. The adoption of the new tables, which reflected an increase in assumed life expectancy, increased the September 30, 2015 pension liability by an estimated $1,300,000 and the postretirement liability by an estimated $1,000,000.

The Company expects that approximately $221,000 before tax, of accumulated other comprehensive loss will be recognized as a portion of net periodic benefit costs in fiscal 2016 and approximately $531,000 of amounts deferred as regulatory assets will be amortized and recognized in net periodic benefit costs in fiscal 2016.

The Company amortized the unrecognized transition obligation over 20 years ending in June 2013.

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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 2015, 2014 and 2013.

	Pension Plan									Postretirement Plan
	2015			2014			2013			2015			2014			2013
Assumptions used to determine benefit obligations:
Discount rate		4.22	%		4.22	%		4.82	%		4.15	%		4.10	%		4.73	%
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		4.22	%		4.82	%		4.06	%		4.10	%		4.73	%		3.95	%
Expected long-term rate of return on plan assets		7.00	%		7.00	%		7.25	%		4.90	%		4.92	%		5.11	%
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
	2015			2014			2013			2015			2014			2013
Service cost	$	654,782		$	553,291		$	634,892		$	167,580		$	168,634		$	213,131
Interest cost		1,025,908			1,020,302			946,247			600,096			602,684			531,845
Expected return on plan assets		(1,440,846	)		(1,312,354	)		(1,184,787	)		(516,656	)		(496,476	)		(452,383	)
Amortization of unrecognized transition obligation		—			—			—			—			—			141,671
Recognized loss		257,378			136,394			578,263			197,058			89,515			241,747
Net periodic benefit cost	$	497,222		$	397,633		$	974,615		$	448,078		$	364,357		$	676,011

The assumed health care cost trend rates used in measuring the accumulated benefit obligation for the postretirement medical plan as of September 30, 2015, 2014 and 2013 are presented below:

	Pre 65									Post 65
	2015			2014			2013			2015			2014			2013
Health care cost trend rate assumed for next year		8.00	%		8.50	%		9.00	%		5.00	%		5.00	%		5.00	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)		5.00	%		5.00	%		5.00	%		5.00	%		5.00	%		5.00	%
Year that the rate reaches the ultimate trend rate		2021			2021			2021			2015			2014			2013

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	$	137,000	$	(109,000	)
Effect on accumulated postretirement benefit obligation		2,383,000		(1,938,000	)

The primary objectives of the Plan’s investment policy 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. The investment policy provides for a range of investment allocations to allow for flexibility in responding to market conditions. The investment policy is periodically reviewed by the Company and a third-party fiduciary for investment matters.

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The Company’s target and actual asset allocation in the pension and postretirement benefit plans as of September 30, 2015 and 2014 were:

	Pension Plan									Postretirement Plan
	Target			2015			2014			Target			2015			2014
Asset category:
Equity securities		60	%		64	%		60	%		50	%		52	%		55	%
Debt securities		40	%		35	%		39	%		50	%		47	%		44	%
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 all 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, 2015
	Fair Value		Level 1		Level 2		Level 3
Asset Class:
Cash	$	106,502	$	106,502	$	—	$	—
Common and Collective Trust and
Pooled Funds:
Bonds
Domestic Fixed Income		3,996,246		—		3,996,246		—
Equities
Domestic Large Cap Growth		3,150,561		—		3,150,561		—
Domestic Large Cap Value		4,183,172		—		4,183,172		—
Domestic Small/Mid Cap Core		1,937,613		—		1,937,613		—
Foreign Large Cap Value		1,873,313		—		1,873,313		—
Mutual Funds:
Bonds
Domestic Fixed Income		3,313,331		—		3,313,331		—
Foreign Fixed Income		213,118		—		213,118		—
Equities
Domestic Large Cap Growth		1,030,957		—		1,030,957		—
Foreign Large Cap Value		653,276		—		653,276		—
Foreign Large Cap Core		936,310		—		936,310		—
Total	$	21,394,399	$	106,502	$	21,287,897	$	—

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			Defined Benefit Pension Plan Fair Value Measurements - September 30, 2014
	Fair Value		Level 1		Level 2		Level 3
Asset Class:
Cash	$	182,644	$	182,644	$	—	$	—
Common and Collective Trust and Pooled Funds:
Bonds
Domestic Fixed Income		1,455,153		—		1,455,153		—
Equities
Domestic Large Cap Growth		2,079,566		—		2,079,566		—
Domestic Large Cap Value		3,295,144		—		3,295,144		—
Domestic Small/Mid Cap Core		1,850,340		—		1,850,340		—
Foreign Large Cap Value		1,641,619		—		1,641,619		—
Mutual Funds:
Bonds
Domestic Fixed Income		6,289,437		—		6,289,437		—
Foreign Fixed Income		204,747		—		204,747		—
Equities
Domestic Large Cap Growth		2,088,528		—		2,088,528		—
Foreign Large Cap Value		608,787		—		608,787		—
Foreign Large Cap Core		818,214		—		818,214		—
Total	$	20,514,179	$	182,644	$	20,331,535	$	—
			Postretirement Benefit Plan Fair Value Measurements - September 30, 2015
	Fair Value		Level 1		Level 2		Level 3
Asset Class:
Cash	$	58,749	$	58,749	$	—	$	—
Mutual Funds
Bonds
Domestic Fixed Income		4,845,174		—		4,845,174		—
Foreign Fixed Income		38,654		—		38,654		—
Equities
Domestic Large Cap Growth		1,746,621		—		1,746,621		—
Domestic Large Cap Value		1,638,695		—		1,638,695		—
Domestic Small/Mid Cap
Growth		194,260		—		194,260		—
Domestic Small/Mid Cap
Value		186,344		—		186,344		—
Domestic Small/Mid Cap Core		417,980		—		417,980		—
Foreign Large Cap Value		893,115		—		893,115		—
Foreign Large Cap Core		378,596		—		378,596		—
Other		45,441		—		45,441		—
Total	$	10,443,629	$	58,749	$	10,384,880	$	—

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			Postretirement Benefit Plan Fair Value Measurements - September 30, 2014
	Fair Value		Level 1		Level 2		Level 3
Asset Class:
Cash	$	116,173	$	116,173	$	—	$	—
Mutual Funds
Bonds
Domestic Fixed Income		4,658,299		—		4,658,299		—
Foreign Fixed Income		101,904		—		101,904		—
Equities
Domestic Large Cap Growth		1,789,381		—		1,789,381		—
Domestic Large Cap Value		1,759,740		—		1,759,740		—
Domestic Small/Mid Cap Growth		400,898		—		400,898		—
Domestic Small/Mid Cap Value		396,537		—		396,537		—
Domestic Small/Mid Cap Core		37,741		—		37,741		—
Foreign Large Cap Value		941,153		—		941,153		—
Foreign Large Cap Core		394,769		—		394,769		—
Other		49,654		—		49,654		—
Total	$	10,646,249	$	116,173	$	10,530,076	$	—

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

The Company expects to contribute $500,000 to its pension plan and $500,000 to its postretirement benefit plan in fiscal 2016.

The following table reflects expected future benefit payments:

Fiscal year ending September 30	Pension Plan		Postretirement Plan
2016	$	655,968	$	617,386
2017		698,403		625,167
2018		773,580		634,509
2019		818,585		655,095
2020		944,944		695,924
2021-2025		6,531,464		4,012,407

The Company also sponsors a defined contribution plan (“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 $338,896, $330,241 and $306,382 for 2015, 2014 and 2013, respectively.

7. 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, 2015, the number of shares available for future grants was 49,000.

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 2015, 2014 and 2013, 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.

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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,
	2015			2014			2013
Expected volatility		34.34	%		35.01	%		34.75	%
Expected dividends		4.11	%		4.21	%		4.32	%
Expected exercise term (years)		7.00			7.00			7.00
Risk-free interest rate		1.98	%		2.23	%		1.23	%

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.

No forfeitures are assumed to occur.

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Stock option transactions under the Company’s plans for the years ended September 30, 2015, 2014 and 2013 are summarized below:

						Weighted-
						Average
				Weighted-		Remaining
	Number of			Average-Exercise		Contractual		Aggregate
	Shares			Price		Terms (years)		Intrinsic Value  1
Options outstanding, September 30, 2012		—		$	—		0.0	$	—
Options granted		21,000			19.01
Options exercised		—			—
Options expired		—			—
Options forfeited		—			—
Options outstanding, September 30, 2013		21,000			19.01		9.5		5,229
Options granted		17,000			18.95
Options exercised		—			—
Options expired		—			—
Options forfeited		—			—
Options outstanding, September 30, 2014		38,000			18.98		8.8		34,840
Options granted		17,000			21.60
Options exercised		(2,600	)		18.99
Options expired		—			—
Options forfeited		—			—
Options outstanding, September 30, 2015		52,400		$	19.83		8.3	$	43,086
Vested and exercisable at September 30, 2015		52,400		$	19.83		8.3	$	43,086

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

The weighted-average grant-date fair value of options granted during the years ended September 30, 2015, 2014 and 2013 was $4.92, $4.43 and $4.04, respectively. The intrinsic value of the options exercised during fiscal 2015 was $5,624. The Company recognized $83,640, $75,310 and $84,840 in stock option expense in fiscal 2015, 2014 and 2013, respectively.

The Company received $49,366 from the exercise of options in 2015. No options were exercised in 2013 or 2014.

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8. OTHER STOCK PLANS

Dividend Reinvestment and Stock Purchase Plan

The Company offers a Dividend Reinvestment and Stock Purchase Plan (“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 plan, the Company issued 8,431, 7 and 24,905 shares in 2015, 2014 and 2013, respectively. As of September 30, 2015, the Company had 358,377 shares of stock available for issuance under the DRIP Plan.

Restricted Stock Plan

The Board of Directors of the Company implemented the Restricted Stock Plan for Outside Directors (“Plan”) effective January 27, 1997. Under the Plan, a minimum of 40% of the monthly retainer fee paid to each non-employee director of Resources is paid in shares of common stock (“Restricted Stock”). The number of shares of Restricted Stock is calculated each month based on the closing sales price of Resources’ common stock on the NASDAQ Global Market on the first business day of the month. The Restricted Stock issued under this 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 Restricted Stock may not be sold, transferred, assigned or pledged by the participant until the shares have vested under the terms of this Plan. The shares of 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 Restricted Stock Plan:

	2015				2014				2013
			Weighted-Average				Weighted-Average				Weighted-Average
			Fair Value on				Fair Value on				Fair Value on
	Shares		Date of Grant		Shares		Date of Grant		Shares		Date of Grant
Beginning of year balance		62,844	$	14.29		59,064	$	13.97		54,011	$	13.51
Granted		4,071		20.88		3,780		19.37		5,053		18.93
Vested		—		—		—		—		—		—
Forfeited		—		—		—		—		—		—
End of year balance		66,915	$	14.70		62,844	$	14.29		59,064	$	13.97

The fair market value of the Restricted Stock issued as compensation during fiscal 2015, 2014 and 2013 was $85,000, $73,200 and $95,667. No Restricted Stock vested or was forfeited during fiscal 2015, 2014 and 2013.

As of September 30, 2015, the Company had 70,960 shares available for issuance under the Restricted Stock Plan.

Stock Bonus Plan

Under the Stock Bonus Plan, executive officers are encouraged to own a position in the Company’s common stock of at least 50% of the value of their annual salary. To promote this policy, the Plan provides that all officers with stock ownership positions below 50% of the value of their annual salaries must, unless approved by the Committee, receive no less than 50% of any performance bonus in the form of Company common stock. Shares from the Stock Bonus Plan may also be issued to certain employees and management personnel in recognition of their performance and service. Under the Stock Bonus Plan, the Company issued 2,731, 4,098 and 4,022 shares valued at $59,332, $78,841 and $72,580, respectively, in 2015, 2014 and 2013. As of September 30, 2015 the Company had 8,174 shares of stock available for issuance under the Stock Bonus Plan.

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9. COMMITMENTS AND CONTINGENCIES

Long-Term Contracts

Due to the nature of the natural gas distribution business, the Company enters into agreements with both suppliers and pipelines to contract for natural gas commodity purchases, storage capacity and pipeline delivery capacity. The Company obtains most of its regulated natural gas supply through an asset management contract between Roanoke Gas and a third party asset manager. The Company utilizes an asset manager to optimize the use of its transportation, storage rights, and gas supply inventories which helps to ensure a secure and reliable source of natural gas. Under the current asset management contract, the Company has designated the asset manager to act as agent for the Company’s storage capacity and all gas balances in storage. The Company retains ownership of gas in storage. Under provisions of this contract, the Company 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, 2015 for the remainder of the contract period.

	Natural Gas Contracts
Year	(In Decatherms)
2015-2016		2,071,061
2016-2017		295,866
Total		2,366,927

The Company 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, 2015. 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. The Company expended approximately $33,405,000, $44,884,000 and $35,348,000 under the asset management, pipeline and storage contracts for Roanoke Gas in fiscal years 2015, 2014 and 2013, respectively. The table below details the pipeline and storage capacity obligations as of September 30, 2015 for the remainder of the contract period.

	Pipeline and
Year	Storage Capacity
2015-2016	$	11,392,645
2016-2017		9,999,402
2017-2018		7,787,998
2018-2019		6,171,421
2019-2020		2,427,961
Thereafter		—
Total	$	37,779,427

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 Company 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 on-site 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.

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10. 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, 2015 and 2014, respectively:

			Fair Value Measurements - September 30, 2015
					Significant Other		Significant
			Quoted Prices in		Observable		Unobservable
			Active Markets		Inputs		Inputs
	Fair Value		Level 1		Level 2		Level 3
Liabilities:
Natural gas purchases	$	712,710	$	—	$	712,710	$	—
Total	$	712,710	$	—	$	712,710	$	—
			Fair Value Measurements - September 30,  2014
					Significant Other		Significant
			Quoted Prices in		Observable		Unobservable
			Active Markets		Inputs		Inputs
	Fair Value		Level 1		Level 2		Level 3
Liabilities:
Natural gas purchases	$	795,019	$	—	$	795,019	$	—
Total	$	795,019	$	—	$	795,019	$	—

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, 2015 and 2014, 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 short-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, 2015 and 2014.

			Fair Value Measurements - September 30,  2015
					Significant Other		Significant
			Quoted Prices in		Observable		Unobservable
	Carrying		Active Markets		Inputs		Inputs
	Amount		Level 1		Level 2		Level 3
Liabilities:
Long-term debt	$	30,500,000	$	—	$	—	$	28,570,585
Total	$	30,500,000	$	—	$	—	$	28,570,585
			Fair Value Measurements - September 30,  2014
					Significant Other		Significant
			Quoted Prices in		Observable		Unobservable
	Carrying		Active Markets		Inputs		Inputs
	Amount		Level 1		Level 2		Level 3
Liabilities:
Long-term debt	$	30,500,000	$	—	$	—	$	30,622,664
Total	$	30,500,000	$	—	$	—	$	30,622,664

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The fair value of long-term debt is estimated by discounting the future cash flows of the fixed rate debt based on the underlying 20-year Treasury rate and estimated credit spread extrapolated based on market conditions since the issuance of the debt.

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.

11. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Quarterly financial data for the years ended September 30, 2015 and 2014 is summarized as follows:

2015	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Operating revenues	$	21,250,065	$	26,431,729	$	10,774,409	$	9,733,404
Gross margin	$	8,622,143	$	10,213,770	$	5,961,828	$	5,408,692
Operating income	$	3,514,352	$	4,879,469	$	956,219	$	656,152
Net income	$	1,924,376	$	2,779,344	$	354,940	$	35,755
Earnings per share of common stock:
Basic	$	0.41	$	0.59	$	0.08	$	0.01
Diluted	$	0.41	$	0.59	$	0.07	$	0.01
2014	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Operating revenues	$	20,011,194	$	32,699,965	$	12,024,817	$	10,280,158
Gross margin	$	8,202,992	$	10,161,125	$	5,721,551	$	5,251,421
Operating income	$	3,272,646	$	5,121,022	$	940,691	$	347,509
Net income (loss)	$	1,722,788	$	2,846,795	$	283,194	$	(144,337	)
Earnings per share of common stock:
Basic	$	0.37	$	0.60	$	0.06	$	(0.03	)
Diluted	$	0.37	$	0.60	$	0.06	$	(0.03	)

12. SUBSEQUENT EVENTS

On October 1, 2015, the Company, through its newly formed wholly-owned subsidiary, RGC Midstream, LLC, entered into an agreement to become a 1% member 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. This project, if approved by the Federal Energy Regulatory Commission, will require an estimated $35 million investment by the Company to support the construction of the pipeline over the next 3 years. The projected in service date of the pipeline is late 2018. The Company will participate in the earnings generated from the transportation of natural gas on the pipeline in proportion to its level of investment. The Company will apply the equity method to account for the transactions and activity of the investment.

On October 1, 2015, RGC Midstream borrowed $1,500,000 under a temporary line-of-credit agreement to make its initial investment in the LLC.

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

*  *  *  *  *  *

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Item 9. Changes in and Disagreements with Accountants 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, 2015, 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, 2015.

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.

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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, 2015, based on the framework set forth in “Internal Control - Integrated Framework (1992)”issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based upon such evaluation, the Company concluded that, as of September 30, 2015, 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, 2015.

61

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

RGC Resources, Inc.

Roanoke, Virginia

We have audited RGC Resources, Inc. and Subsidiaries (“the Company”)’s internal control over financial reporting as of September 30, 2015, based on criteria established in Internal Control-Integrated Framework - 1992 issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). RGC Resources, Inc. and Subsidiaries’ 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 conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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.

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.

In our opinion, RGC Resources, Inc. and Subsidiaries (“the Company”) maintained, in all material respects, effective internal control over financial reporting as of September 30, 2015, based on criteria established in Internal Control-Integrated Framework - 1992 issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets as of September 30, 2015 and 2014 and the related consolidated statements of income, comprehensive income, stockholders’ equity, and cash flows of RGC Resources, Inc. and Subsidiaries for each of the years in the three year period ended September 30, 2015, and our report dated December 4, 2015 expressed an unqualified opinion.

CERTIFIED PUBLIC ACCOUNTANTS

1715 Pratt Drive, Suite 2700

Blacksburg, Virginia

December 4, 2015

62

Item 9B. Other Information

None

63

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 2016 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 2016 Annual Meeting of Shareholders of Resources, which information is incorporated herein by reference. In addition, the Board of Directors has determined that George W. Logan 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 2016 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 Compliance” in the Proxy Statement for the 2016 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 2016 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 2016 Annual Meeting of Shareholders of Resources, is incorporated herein by reference.

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

For information with respect to certain relationships and related transactions, see “Transactions with Related Persons” section in the Proxy Statement for the 2016 Annual Meeting of Shareholders of Resources, which is incorporated herein by reference.

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 2016 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 2016 Annual Meeting of Shareholders of Resources is incorporated herein by reference.

64

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	2015 Annual Report to Shareholders (such report, except to the extent incorporated herein by reference, is being furnished for the information of the Commission only and is not to be deemed filed as part of this Annual Report on Form 10-K)
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, 2015, 2014 and 2013, formatted in XBRL (eXtensible Business Reporting Language); Consolidated Balance Sheets at September 30, 2015 and 2014, (ii) Consolidated Statements of Income for the years ended September 30, 2015, 2014 and 2013, (iii) Consolidated Statements of Comprehensive Income for the years ended September 30, 2015, 2014 and 2013, (iv) Consolidated Statements of Stockholders’ Equity for the years ended September 30, 2015, 2014 and 2013, (v) Consolidated Statements of Cash Flows for the years ended September 30, 2015, 2014 and 2013, 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.

65

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 10, 2015
	Paul W. Nester	Date
	Vice President, Secretary, Treasurer and CFO
	(principal accounting and financial officer)

66

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         John S. D’Orazio	December 10, 2015   Date	President and Chief Executive Officer, Director
/S/    PAUL W. NESTER         Paul W. Nester	December 10, 2015 Date	Vice President, Treasurer and CFO (principal accounting and financial officer)
/S/    JOHN B. WILLIAMSON, III         John B. Williamson, III	December 10, 2015 Date	Chairman of the Board and Director
/S/    NANCY H. AGEE         Nancy H. Agee	December 10, 2015 Date	Director
/S/  ABNEY S. BOXLEY, III         Abney S. Boxley, III	December 10, 2015 Date	Director
/S/    MARYELLEN F. GOODLATTE         Maryellen F. Goodlatte	December 10, 2015 Date	Director
/S/    J. ALLEN LAYMAN         J. Allen Layman	December 10, 2015 Date	Director
/S/    GEORGE W. LOGAN         George W. Logan	December 10, 2015 Date	Director
/S/    S. FRANK SMITH         S. Frank Smith	December 10, 2015 Date	Director
/S/    RAYMOND D. SMOOT, JR.         Raymond D. Smoot, Jr.	December 10, 2015 Date	Director

67

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 10-K for the year ended September 30, 2011)
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)
10 (a)	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-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 (g)	ITS-1 Service Agreement between Columbia Gulf Transmission Company and Roanoke Gas Company dated November 1, 1993 (incorporated herein by reference to Exhibit 10(j) of the Annual Report on Form 10-K for the fiscal year ended September 30, 1994 (SEC file number reference 0-367))
10 (h)	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)	Gas Transportation Agreement, for use under IT rate schedule, between Tennessee Gas Pipeline Company and Roanoke Gas Company dated September 1, 1993 (incorporated herein by reference to Exhibit 10(l) of the Annual Report on Form 10-K for the fiscal year ended September 30, 1994 (SEC file number reference 0-367))
10 (j)	Gas Storage Contract under rate schedule FS (Production Area) Bear Creek II between Tennessee Gas Pipeline Company and Roanoke Gas Company dated November 1, 1993 (incorporated herein by reference to Exhibit 10(m) of the Annual Report on Form 10-K for the fiscal year ended September 30, 1994 (SEC file number reference 0-367))

68

10 (k)	Gas Storage Contract under rate schedule FS (Production Area) Bear Creek I between Tennessee Gas Pipeline Company and Roanoke Gas Company dated September 1, 1993 (incorporated herein by reference to Exhibit 10(n) of the Annual Report on Form 10-K for the fiscal year ended September 30, 1994 (SEC file number reference 0-367))
10 (l)	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 (m)	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 (n)	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 (o)	Firm Storage Service Agreement effective March 19, 1997, between Virginia Gas Storage Company and Roanoke Gas Company (incorporated herein by reference to Exhibit 10(w)(w) of Annual Report on Form 10-K for the fiscal year ended September 30, 1998 (SEC file reference number 0-367))
10 (p)	Firm Storage Service Agreement by and between Roanoke Gas Company and Virginia Gas Pipeline Company, dated June 1, 2001 (incorporated herein by reference to Exhibit 10(b)(b)(b) of Annual Report on Form 10-K for the fiscal year ended September 30, 2001 (SEC file number reference 0-367))
10 (q)	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 (r)	Natural Gas Asset Management Agreement by and between Roanoke Gas Company and Sequent Energy Management LP effective as of November 1, 2013 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed October 9, 2013 (SEC file number reference 0-367))
10 (s)	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 (t)	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 (u)	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 (v)	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 (w)	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)

69

10 (x)	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 (y)	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 (z)	Gas Franchise Agreement between the Town of Vinton, Virginia, and Roanoke Gas Company dated July 2, 1996 (incorporated herein by reference to Exhibit 10(n)(n) of Annual Report on Form 10-K for the fiscal year ended September 30, 1996 (SEC file number reference 0-367))
10 (a) (a)	Gas Franchise Agreement between the City of Salem, Virginia, and Roanoke Gas Company dated July 9, 1996 (incorporated herein by reference to Exhibit 10(o)(o) of Annual Report on Form 10-K for the fiscal year ended September 30, 1996 (SEC file number reference 0-367))
10 (b) (b)	Gas Franchise Agreement between the City of Roanoke, Virginia, and Roanoke Gas Company dated July 12, 1996 (incorporated herein by reference to Exhibit 10(p)(p) of Annual Report on Form 10-K for the fiscal year ended September 30, 1996 (SEC file number reference 0-367))
10 (c) (c)	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 (d) (d)	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 (e) (e)	RGC Resources, Inc. Restricted Stock Plan for Outside Directors (incorporated herein by reference to Exhibit 10(r)(r) of Annual Report on Form 10-K for the fiscal year ended September 30, 1999 SEC file reference number 0-367)
10 (f) (f)	Change in Control Agreement between RGC Resources, Inc. and Paul W. Nester effective May 1, 2015 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed May 5, 2015)
10 (g) (g)	Change in Control Agreement by and between RGC Resources, Inc. and Robert L. Wells, II effective May 1, 2015 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed May 5, 2015)
10 (h) (h)	Change in Control Agreement between RGC Resources, Inc. and Mr. Carl J. Shockley effective May 1, 2015 (incorporated herein by reference to Exhibit 10.3 on Form 8-K as filed May 5, 2015)
10 (i) (i)	Change in Control Agreement between John S. D’Orazio and RGC Resources, Inc. effective April 1, 2011 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed April 4, 2011 (SEC file number reference 0-367))
10 (j) (j)	Revolving Line of Credit Note in the original principal amount of $24,000,000 by Roanoke Gas Company in favor of Wells Fargo Bank, N.A. dated March 31, 2015 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed April 3, 2015)
10 (k)(k)	Credit Agreement by and between Roanoke Gas Company and Wells Fargo Bank, N.A. dated March 31, 2015 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed April 3, 2015)
10 (l)(l)	Continuing guaranty by RGC Resources, Inc. and Wells Fargo Bank, N. A. dated March 31, 2015 (incorporated by reference to Exhibit 10.3 on Form 8-K as filed April 3, 2015)
10 (m)(m)	Indemnification and Cost Sharing Agreement by and between RGC Resources, Inc., Bluefield Gas Company and ANGD, LLC (incorporated herein by reference to Exhibit 10(x)(x) on Form 10-K as filed December 21, 2007 (SEC file number reference 0-367))

70

10 (n)(n)	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 (o)(o)	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 (p)(p)	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 (q)(q)	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 (r)(r)	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 (s)(s)	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 (t)(t)	Unconditional guaranty by and between RGC Resources, Inc. and Wachovia Bank, National Association, dated March 23, 2009 for the benefit of Roanoke Gas Company (incorporated by reference to Exhibit 10.2 on Form 8-K as filed March 26, 2009 (SEC file number reference 0-367))
13	2015 Annual Report to Shareholders (such report, except to the extent incorporated herein by reference, is being furnished for the information of the Commission only and is not to be deemed filed as part of this Annual Report on Form 10-K)
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, 2015, 2014 and 2013, formatted in XBRL (eXtensible Business Reporting Language); Consolidated Balance Sheets at September 30, 2015 and 2014, (ii) Consolidated Statements of Income for the years ended September 30, 2015, 2014 and 2013, (iii) Consolidated Statements of Comprehensive Income for the years ended September 30, 2015. 2014 and 2013, (iv) Consolidated Statements of Stockholders’ Equity for the years ended September 30, 2015, 2014 and 2013, (v) Consolidated Statements of Cash Flows for the years ended September 30, 2015, 2014 and 2013, 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.

71

EX-13

RGC Resources TM

811 Call 811 Before You Dig

Dig With C.A.R.E.

2015 ANNUAL REPORT

KEY FINANCIAL INFORMATION

Year Ending September 30	2015	2014	2013
Natural Gas Deliveries (DTH’s)	9,875,007	10,087,651	9,408,894
Net Income	$ 5,094,415	$ 4,708,440	$ 4,262,052
Earnings Per Share	$ 1.08	$ 1.00	$ 0.91
Natural Gas Customers	59,080	58,553	58,238
Additions to Plan	$ 13,780,356	$ 14,715,428	$ 9,977,433

Regular Annualized Dividends Per Share

Earnings Per Share

Stock Price, September 30

$19.29

$19.90

$20.20

$0.91

$1.00

$1.08

$0.72

$0.74

$0.77

2013

2014

2015

PRESIDENT’S LETTER

John S. D’Orazio,

President and Chief Executive Officer

To Our Shareholders

I am very pleased to report earnings of $5.1 million or $1.08 per share outstanding compared to $1.00 per share last year or an 8% improvement. I am also pleased to report that our Board of Directors approved an annualized dividend increase from $0.77 per share to $0.81 per share, effective with the February 1, 2016, quarterly dividend payments. The February dividend will reflect 71 years of continuous quarterly dividend payments and 19 annual dividend increases in the past 20 years.

We announced on October 1, 2015 that RGC Resources, through its newly formed subsidiary RGC Midstream, LLC, acquired a 1% ownership interest in Mountain Valley Pipeline LLC, which is a joint venture between EQT Midstream Partners LP, affiliates of NextEra Energy Inc., WGL Holdings Inc. and Vega Energy Partners Ltd. The Mountain Valley Pipeline (MVP) will be a 301 mile,

42-inch diameter pipeline with an approximate total cost of $3.5 billion. It will transport natural gas from the Marcellus and Utica production areas through West Virginia and Southwest Virginia to the growing natural gas markets in the Southeast and mid-Atlantic region. This pipeline is subject to approval and regulation by the Federal Energy Regulatory Commission (FERC). The MVP is expected to be in service during the fourth quarter of 2018. The MVP will address the growing demand for natural gas in our region and enhance the reliability of the Roanoke Gas distribution system. It will also improve our ability to expand our natural gas system into areas that currently do not have access and promote economic growth and new investments in these areas. Our investment in this project is projected to be $35 million over the next three years. We believe this strategic investment will complement our core business and enhance shareholder value.

Special points of interest:

Earnings of $5.1 million or $1.08 per share outstanding compared to $1.00 per share last year or an 8% improvement.

Dividend increase from $0.77 per share to $0.81 per share, effective February 1, 2016.

Mountain Valley Pipeline 1% ownership interest.

1% increase in new customer additions.

KUBOTA

PRESIDENT’S LETTER (continued)

The economy in the Roanoke area continues to grow at a steady pace and, as a result, Roanoke Gas experienced a 1% increase in new customer additions. Approximately 71% of the new customer additions were conversions, with the remainder from new construction. Conversions occur when existing homes or businesses convert to natural gas from other fuel sources. Industrial demand was soft in 2015. Future industrial demand will depend upon the state of the economy and market conditions. During the past year, we provided gas service to a new manufacturing customer, who quickly became one of our top customers based on gas usage. We are also excited to provide natural gas service to the first compressed natural gas station in the Roanoke Valley. The station will be owned and operated by a major fleet operator and is projected to be operational in the first quarter of fiscal 2016.

We experienced another strong year in the operations side of the business. Weather was 6% colder than the 30-year average. In February, we experienced two days where natural gas deliveries ranked in the top five days in the Company’s history. As a result of the efforts to modernize our system, the distribution system operated as designed without any issues during those extremely cold periods.

We continue to invest in capital improvements for Roanoke Gas Company. In fiscal 2015, we invested $13.8 million with the primary focus on the modernization of our distribution system. We replaced approximately 10 miles of cast iron and bare steel pipe with polyethylene pipe. When we began our renewal program in 1991, bare steel and cast iron mains represented 25% of our distribution system. Cast iron and bare steel pipe now represent less than 2% of our distribution system. We anticipate replacing the remaining bare steel and cast iron pipe by 2017. We will maintain our focus of further enhancing the safety and reliability of our system with a fiscal 2016 capital budget of $15.2 million. This will include the replacement and upgrade of two natural gas transfer stations.

On a national level, the natural gas industry continues to increase production in the various shale formations through improved drilling and fracking technologies. There are numerous interstate pipeline projects, either under construction or in the process of filing for FERC approval, to transport supply from the shale formations to areas of the country where the demand for natural gas is increasing. Natural gas prices are forecasted to remain low and stable on both a near and intermediate term basis due to production and infrastructure improvements.

On behalf of our employees and Board of Directors, I thank you for your continuing decision to invest in RGC Resources. We are pleased to be part of an exciting era for the natural gas industry and I look forward to reporting to you at the end of 2016 on what I anticipate to be another year of solid performance.

John S. D’Orazio

President and Chief Executive Officer

Visit us on the Web:

www.rgcresources.com

BOARD OF DIRECTORS

Nancy Howell Agee

President and Chief Executive Officer

Carilion Clinic

Abney S. Boxley, III

President and Chief Executive Officer

Boxley Materials Company

John S. D’Orazio

President and Chief Executive Officer

RGC Resources, Inc.

Maryellen F. Goodlatte

Attorney and Principal

Glenn Feldmann Darby & Goodlatte

J. Allen Layman

Private Investor

George Logan

Principal

Pine Street Partners, LLC

Faculty, University of VA Darden Graduate School of Business

S. Frank Smith

Consultant

Alpha Coal Sales Co., LLC

Raymond D. Smoot, Jr.

Senior Fellow

Virginia Tech Foundation, Inc.

John B. Williamson, III

CHAIRMAN OF THE BOARD

OFFICERS

John S. D’Orazio

President and Chief Executive Officer

Howard T. Lyon

Assistant Secretary and Assistant Treasurer

Paul W. Nester

Vice President, Secretary, Treasurer and Chief Financial Officer

Robert L. Wells, II

Vice President,

Information Technology

Carl J. Shockley, Jr.

Vice President,

Operations—Roanoke Gas Company

INFRASTRUCTURE RENEWALS

Miles Remaining

100

90

80

70

60

50

40

30

20

10

0

Cast Iron

Bare Steel

1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015

“In fiscal 2015… We replaced approximately 10 miles of cast iron and bare steel pipe… we anticipate replacing the remaining bare steel and cast iron pipe by 2017.”

CORPORATE INFORMATION

DIVIDEND REINVESTMENT AND STOCK PURCHASE PLAN SHAREHOLDER INQUIRIES

Through the Dividend Reinvestment and Stock Purchase Plan, shareholders of record are offered a convenient way to acquire and reinvest cash dividends in additional shares of the Company’s common stock and avoid commissions or other charges. Additionally, shareholders are given on-line access to make transfers, consolidate accounts, replace stock certificates or dividend checks, establish direct deposit, update personal information and much more. American Stock Transfer and Trust Company, LLC administers the plan and is the agent for participants. For more information, inquiries may be directed to RGC Resources, Inc., Shareholder Information Services, P.O. Box 13007, Roanoke, VA 24030, (540) 777-3853.

STOCK PLAN ADMINISTRATOR AND AGENT

American Stock Transfer & Trust

Company, LLC

6201 15th Avenue

Brooklyn, NY 11219

(800) 937-5449

INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Brown Edwards & Company, L.L.P.

1715 Pratt Drive, Suite 2700

Blacksburg, VA 24060

ANNUAL REPORT AND 10-K

This annual report, 10-K and the financial statements contained herein are submitted to the shareholders of the Company for their general information and not in connection with any sale or offer to sell, or solicitation of any offer to buy, any securities.

ANNUAL MEETING

The annual meeting of shareholders of the Company will be held at The Hotel Roanoke and Conference Center, 110 Shenandoah Avenue, Roanoke, Virginia, 24016 on Monday, February 1, 2016, at 9:00 a.m. Proxies for the annual meeting will be requested from shareholders when notice of meeting, proxy statement and form of proxy are mailed on or about December 16, 2015.

FINANCIAL INQUIRIES

All financial analysts and professional investment managers should direct their questions and requests for information to:

RGC Resources, Inc.

VP, Treasurer, Secretary & CFO

P.O. Box 13007

Roanoke, VA 24030

(540) 777-3853

Access up-to-date information on RGC Resources, Inc. and its subsidiaries at www.rgcresources.com.

RGC Resources TM

519 Kimball Avenue, N.E.

P.O. Box 13007

Roanoke, Virginia, 24030

www.rgcresources.com

EX-21

EXHIBIT 21

RGC Resources, Inc.

Subsidiaries of Registrant

Roanoke Gas Company

Diversified Energy Company

RGC Ventures of Virginia, Inc.

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. 333-187529 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. 333-122742 on Form S-3 of RGC Resources, Inc. of our report dated December 4, 2015 appearing in this Annual Report on Form 10-K of RGC Resources, Inc. for the year ended September 30, 2015.

CERTIFIED PUBLIC ACCOUNTANTS

1715 Pratt Drive, Suite 2700

Blacksburg, Virginia

December 9, 2015

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 10, 2015	/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 10, 2015	/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, 2015 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 10, 2015

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, 2015 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Paul W. Nester, Vice-President, 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 10, 2015

XML

Summary of Significant Accounting Policies (Components of Accumulated Comprehensive Income (Loss)) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Interest Rate Swaps
Balance at beginning of period	$ 0	$ (1,232,546)	$ (1,809,531)
Other comprehensive income (loss)	0	1,232,546	576,985
Balance at end of period	0	0	(1,232,546)
Defined Benefit Plans
Balance at beginning of period	(1,139,326)	(918,688)	(2,140,554)
Other comprehensive income (loss)	(1,147,219)	(220,638)	1,221,866
Balance at end of period	(2,286,545)	(1,139,326)	(918,688)
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	(1,139,326)	(2,151,234)	(3,950,085)
Other comprehensive income (loss)	(1,147,219)	1,011,908	1,798,851
Balance at end of period	$ (2,286,545)	$ (1,139,326)	$ (2,151,234)

XML

Employee Benefit Plans (Schedule of Components of Net Periodic Cost) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 654,782	$ 553,291	$ 634,892
Interest cost	1,025,908	1,020,302	946,247
Expected return on plan assets	(1,440,846)	(1,312,354)	(1,184,787)
Amortization of unrecognized transition obligation	0	0	0
Recognized loss	257,378	136,394	578,263
Net periodic benefit cost	497,222	397,633	974,615
Postretirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	167,580	168,634	213,131
Interest cost	600,096	602,684	531,845
Expected return on plan assets	(516,656)	(496,476)	(452,383)
Amortization of unrecognized transition obligation	0	0	141,671
Recognized loss	197,058	89,515	241,747
Net periodic benefit cost	$ 448,078	$ 364,357	$ 676,011

XML

Income Taxes (Details of Income Tax Expense) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Current income taxes:
Federal	$ 379,180	$ 1,789,294	$ 1,404,450
State	374,541	290,458	453,347
Total current income taxes	753,721	2,079,752	1,857,797
Deferred income taxes:
Federal	2,289,729	687,417	829,080
State	127,112	175,464	(33,051)
Total deferred income taxes	2,416,841	862,881	796,029
Amortization of investment tax credits	0	(3,093)	(9,039)
Total income tax expense	$ 3,170,562	$ 2,939,540	$ 2,644,787

XML

Employee Benefit Plans (Summary of Assumed Health Care Cost Trend Rates Used) (Details)	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Pre 65 [Member]
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for next year	8.00%	8.50%	9.00%
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	2021	2021	2021
Post 65 [Member]
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	2015	2014	2013

XML

Long-Term Debt (Summary of Aggregate Maturities of Long-Term Debt) (Details) - USD ($)	Sep. 30, 2015	Sep. 30, 2014
Debt Disclosure [Abstract]
2016	$ 0
2017	0
2018	0
2019	0
2020	0
Thereafter	30,500,000
Total	$ 30,500,000	$ 30,500,000

XML

Summary of Significant Accounting Policies (Schedule of Regulatory Assets and Liabilities) (Details) - USD ($)	Sep. 30, 2015	Sep. 30, 2014
Regulatory Assets And Liabilities [Line Items]
Noncurrent regulatory assets	$ 10,923,243	$ 9,273,389
Total regulatory assets	11,695,250	10,004,133
Total regulatory liabilities	16,236,145	13,564,365
Over-recovery of Gas Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Current regulatory liabilities	1,901,426	0
Over-recovery of SAVE Plan Revenues [Member]
Regulatory Assets And Liabilities [Line Items]
Current regulatory liabilities	153,365	187,203
Asset Retirement Obligations [Member]
Regulatory Assets And Liabilities [Line Items]
Noncurrent regulatory liabilities	5,295,868	4,802,015
Regulatory cost of retirement obligations [Member]
Regulatory Assets And Liabilities [Line Items]
Noncurrent regulatory liabilities	8,885,486	8,575,147
Accrued WNA Revenues [Member]
Regulatory Assets And Liabilities [Line Items]
Current regulatory assets	229,281	143,753
Under-Recovery of Gas Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Current regulatory assets	0	180,831
Accrued Pension and Postretirement Medical [Member]
Regulatory Assets And Liabilities [Line Items]
Current regulatory assets	530,781	394,215
Noncurrent regulatory assets	8,378,419	6,884,812
Utility Property, In Service, Other [Member]
Regulatory Assets And Liabilities [Line Items]
Noncurrent regulatory assets	11,945	11,945
Premium on Early Retirement of Debt [Member]
Regulatory Assets And Liabilities [Line Items]
Noncurrent regulatory assets	2,169,556	2,283,744
Other [Member]
Regulatory Assets And Liabilities [Line Items]
Noncurrent regulatory assets	$ 375,268	$ 104,833

XML

Employee Benefit Plans (Schedule of Target and Actual Asset Allocation) (Details)	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Pension Plan [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target	60.00%
Actual	64.00%	60.00%
Pension Plan [Member] | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target	40.00%
Actual	35.00%	39.00%
Pension Plan [Member] | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Target	0.00%
Actual	1.00%	1.00%
Pension Plan [Member] | Other [Member]
Defined Benefit Plan Disclosure [Line Items]
Target	0.00%
Actual	0.00%	0.00%
Postretirement Plan [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target	50.00%
Actual	52.00%	55.00%
Postretirement Plan [Member] | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target	50.00%
Actual	47.00%	44.00%
Postretirement Plan [Member] | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Target	0.00%
Actual	1.00%	1.00%
Postretirement Plan [Member] | Other [Member]
Defined Benefit Plan Disclosure [Line Items]
Target	0.00%
Actual	0.00%	0.00%

XML

Quarterly Financial Information (Unaudited) (Details) - USD ($)	3 Months Ended								12 Months Ended
	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Quarterly Financial Information Disclosure [Abstract]
Operating revenues	$ 9,733,404	$ 10,774,409	$ 26,431,729	$ 21,250,065	$ 10,280,158	$ 12,024,817	$ 32,699,965	$ 20,011,194	$ 68,189,607	$ 75,016,134	$ 63,205,666
Gross margin	5,408,692	5,961,828	10,213,770	8,622,143	5,251,421	5,721,551	10,161,125	8,202,992	30,206,433	29,337,089	27,602,891
Operating income	656,152	956,219	4,879,469	3,514,352	347,509	940,691	5,121,022	3,272,646	10,006,192	9,681,868	8,795,055
Net income (loss)	$ 35,755	$ 354,940	$ 2,779,344	$ 1,924,376	$ (144,337)	$ 283,194	$ 2,846,795	$ 1,722,788	$ 5,094,415	$ 4,708,440	$ 4,262,052
Earnings per share of common stock:
Basic (in usd per share)	$ 0.01	$ 0.08	$ 0.59	$ 0.41	$ (0.03)	$ 0.06	$ 0.60	$ 0.37	$ 1.08	$ 1.00	$ 0.91
Diluted (in usd per share)	$ 0.01	$ 0.07	$ 0.59	$ 0.41	$ (0.03)	$ 0.06	$ 0.60	$ 0.37	$ 1.08	$ 1.00	$ 0.91

XML

Income Taxes (Tables)

12 Months Ended

Sep. 30, 2015

Income Tax Disclosure [Abstract]

Details of Income Tax Expense

The details of income tax expense are as follows:

	Years Ended September 30
	2015		2014			2013
Current income taxes:
Federal	$	379,180	$	1,789,294		$	1,404,450
State	374,541		290,458			453,347
Total current income taxes	753,721		2,079,752			1,857,797
Deferred income taxes:
Federal	2,289,729		687,417			829,080
State	127,112		175,464			(33,051		)
Total deferred income taxes	2,416,841		862,881			796,029
Amortization of investment tax credits	—		(3,093		)	(9,039		)
Total income tax expense	$	3,170,562	$	2,939,540		$	2,644,787

Reconciliation of Income Tax Expense Based on Federal Statutory Rate

Income tax expense for the years ended September 30, 2015, 2014 and 2013 differed from amounts computed by applying the U.S. Federal income tax rate of 34% to earnings before income taxes due to the following:

	Years Ended September 30
	2015		2014			2013
Income before income taxes	$	8,264,977	$	7,647,980		$	6,906,839
Income tax expense computed at the federal statutory rate	$	2,810,092	$	2,600,313		$	2,348,325
State income taxes, net of federal income tax benefit	331,091		307,509			277,395
Amortization of investment tax credits	—		(3,093		)	(9,039		)
Other, net	29,379		34,811			28,106
Total income tax expense	$	3,170,562	$	2,939,540		$	2,644,787

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
	2015		2014
Deferred tax assets:
Allowance for uncollectibles	$	20,012	$	26,855
Accrued pension and postretirement medical benefits	2,502,774		2,077,409
Accrued vacation	249,837		230,842
Over-recovery of gas costs	721,782		—
Costs of gas held in storage	930,524		973,651
Accrued gas costs	—		36,305
Deferred compensation	651,336		579,451
Other	265,951		295,654
Total gross deferred tax assets	5,342,216		4,220,167
Deferred tax liabilities:
Utility plant	19,804,862		17,057,847
Under-recovery of gas costs	—		68,643
Accrued gas costs	157,385		—
Total gross deferred tax liabilities	19,962,247		17,126,490
Net deferred tax liability	$	14,620,031	$	12,906,323

Deferred Income Tax - Balance Sheet	September 30
	2015		2014
Deferred income taxes (net current assets)	$	2,293,536	$	1,704,320
Deferred income taxes (net non-current liabilities)	16,913,567		14,610,643
Net deferred tax liability	$	14,620,031	$	12,906,323

XML

Income Taxes (Schedule of Deferred Tax Assets and Liabilities) (Details) - USD ($)	Sep. 30, 2015	Sep. 30, 2014
Deferred tax assets:
Allowance for uncollectibles	$ 20,012	$ 26,855
Accrued pension and postretirement medical benefits	2,502,774	2,077,409
Accrued vacation	249,837	230,842
Over-recovery of gas costs	721,782	0
Costs of gas held in storage	930,524	973,651
Accrued gas costs	0	36,305
Deferred compensation	651,336	579,451
Other	265,951	295,654
Total gross deferred tax assets	5,342,216	4,220,167
Deferred tax liabilities:
Utility plant	19,804,862	17,057,847
Under-recovery of gas costs	0	68,643
Accrued gas costs	157,385	0
Total gross deferred tax liabilities	19,962,247	17,126,490
Deferred income taxes (net current assets)	2,293,536	1,704,320
Deferred income taxes (net non-current liabilities)	16,913,567	14,610,643
Net deferred tax liability	$ 14,620,031	$ 12,906,323

XML

Short-Term Debt (Summary of Available Limits Under Line of Credit Agreement) (Details)	12 Months Ended
	Sep. 30, 2015 USD ($)
September 30, 2015
Short-term Debt [Line Items]
Effective	Sep. 30, 2015
Available Line-of-Credit	$ 24,000,000
March 1, 2016
Short-term Debt [Line Items]
Effective	Mar. 01, 2016
Available Line-of-Credit	$ 17,000,000

XML

Summary of Significant Accounting Policies (Reconciliation of Basic and Diluted Earnings Per Share) (Details) - USD ($)	3 Months Ended								12 Months Ended
	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Net income	$ 35,755	$ 354,940	$ 2,779,344	$ 1,924,376	$ (144,337)	$ 283,194	$ 2,846,795	$ 1,722,788	$ 5,094,415	$ 4,708,440	$ 4,262,052
Weighted-average common shares (in shares)									4,728,210	4,715,478	4,698,727
Effect of dilutive securities:
Options to purchase common stock (in shares)									3,466	804	39
Diluted average common shares (in shares)									4,731,676	4,716,282	4,698,766
Earnings Per Share of Common Stock:
Basic (in usd per share)	$ 0.01	$ 0.08	$ 0.59	$ 0.41	$ (0.03)	$ 0.06	$ 0.60	$ 0.37	$ 1.08	$ 1.00	$ 0.91
Diluted (in usd per share)	$ 0.01	$ 0.07	$ 0.59	$ 0.41	$ (0.03)	$ 0.06	$ 0.60	$ 0.37	$ 1.08	$ 1.00	$ 0.91

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, 2015	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2012
Change in fair value of plan assets:
Amounts recognized in the balance sheet, Noncurrent liabilities	$ (10,685,261)	$ (8,459,436)
Total amounts included in other comprehensive loss, net of tax	2,286,545	1,139,326	$ 918,688	$ 2,140,554
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	22,853,206	20,697,734
Change in benefit obligation:
Benefit obligation at beginning of year	24,636,695	21,468,769
Service cost	654,782	553,291	634,892
Interest cost	1,025,908	1,020,302	946,247
Actuarial loss	1,487,278	2,199,697
Benefit payments, net of retiree contributions	(637,042)	(605,364)
Benefit obligation at end of year	27,167,621	24,636,695	21,468,769
Change in fair value of plan assets:
Fair value of plan assets at beginning of year	20,514,179	18,801,262
Actual return on plan assets, net of taxes	(182,738)	1,750,033
Employer contributions	1,700,000	568,248
Benefit payments, net of retiree contributions	(637,042)	(605,364)
Fair value of plan assets at end of year	21,394,399	20,514,179	18,801,262
Funded status	(5,773,222)	(4,122,516)
Amounts recognized in the balance sheet, Noncurrent liabilities	(5,773,222)	(4,122,516)
Amounts recognized in accumulated other comprehensive loss, Transition obligation, net of tax	0	0
Amounts recognized in accumulated other comprehensive loss, Net actuarial loss, net of tax	1,694,924	616,352
Total amounts included in other comprehensive loss, net of tax	1,694,924	616,352
Amounts deferred to a regulatory asset, Transition obligation	0	0
Amounts deferred to a regulatory asset, Net actuarial loss	5,280,756	4,166,900
Amounts recognized as regulatory assets	5,280,756	4,166,900
Postretirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	15,355,668	14,983,169
Change in benefit obligation:
Benefit obligation at beginning of year	14,983,169	13,028,628
Service cost	167,580	168,634	213,131
Interest cost	600,096	602,684	531,845
Actuarial loss	70,196	1,673,552
Benefit payments, net of retiree contributions	(465,373)	(490,329)
Benefit obligation at end of year	15,355,668	14,983,169	13,028,628
Change in fair value of plan assets:
Fair value of plan assets at beginning of year	10,646,249	10,114,062
Actual return on plan assets, net of taxes	(237,247)	522,516
Employer contributions	500,000	500,000
Benefit payments, net of retiree contributions	(465,373)	(490,329)
Fair value of plan assets at end of year	10,443,629	10,646,249	$ 10,114,062
Funded status	(4,912,039)	(4,336,920)
Amounts recognized in the balance sheet, Noncurrent liabilities	(4,912,039)	(4,336,920)
Amounts recognized in accumulated other comprehensive loss, Transition obligation, net of tax	0	0
Amounts recognized in accumulated other comprehensive loss, Net actuarial loss, net of tax	591,621	522,974
Total amounts included in other comprehensive loss, net of tax	591,621	522,974
Amounts deferred to a regulatory asset, Transition obligation	0	0
Amounts deferred to a regulatory asset, Net actuarial loss	3,628,448	3,112,127
Amounts recognized as regulatory assets	$ 3,628,448	$ 3,112,127

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Commitments and Contingencies (Schedule of Pipeline and Storage Capacity Obligations) (Details)	Sep. 30, 2015 USD ($)
Commitments and Contingencies Disclosure [Abstract]
2015-2016	$ 11,392,645
2016-2017	9,999,402
2017-2018	7,787,998
2018-2019	6,171,421
2019-2020	2,427,961
Thereafter	0
Total	$ 37,779,427

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Common Stock Options (Fair Value Assumptions) (Details)	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Expected volatility	34.34%	35.01%	34.75%
Expected dividends	4.11%	4.21%	4.32%
Expected exercise term (years)	7 years	7 years	7 years
Risk-free interest rate	1.98%	2.23%	1.23%

XML

Income Taxes (Narrative) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Income Tax Disclosure [Abstract]
Federal income tax rate	34.00%	34.00%	34.00%
Bonus depreciation, percent	50.00%
Prior year deferred taxes reflected in the current year tax provision	$ 1,442,211

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Summary of Significant Accounting Policies

12 Months Ended

Sep. 30, 2015

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 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; RGC Ventures of Virginia, Inc., operating as Application Resources and The Utility Consultants; and RGC Midstream, LLC. Roanoke Gas is a natural gas utility, which distributes and sells natural gas to approximately 59,100 residential, commercial and industrial customers within its service areas in Roanoke, Virginia and the surrounding localities. The Company’s business is seasonal in nature and weather dependent 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”). Application Resources provides information system services to software providers in the utility industry. The Utility Consultants, which provided regulatory consulting services to other utilities, ceased operations in 2015. RGC Midstream, LLC is a new wholly-owned subsidiary created in 2015 to invest in a pipeline project. More information is provided in Note 12. Diversified Energy Company is currently inactive.

The Company follows accounting and reporting standards set 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.

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, 2015 and 2014 are as follows:

	September 30
	2015		2014
Regulatory Assets:
Current Assets:
Accounts receivable:
Accrued WNA revenues	$	229,281	$	143,753
Under-recovery of gas costs	—		180,831
Other:
Accrued pension and postretirement medical	530,781		394,215
Utility Property:
In service:
Other	11,945		11,945
Other Assets:
Regulatory assets:
Premium on early retirement of debt	2,169,556		2,283,744
Accrued pension and postretirement medical	8,378,419		6,884,812
Other	375,268		104,833
Total regulatory assets	$	11,695,250	$	10,004,133
Regulatory Liabilities:
Current Liabilities:
Over-recovery of gas costs	$	1,901,426	$	—
Accrued expenses:
Over-recovery of SAVE Plan revenues	153,365		187,203
Deferred Credits and Other Liabilities:
Asset retirement obligations	5,295,868		4,802,015
Regulatory cost of retirement obligations	8,885,486		8,575,147
Total regulatory liabilities	$	16,236,145	$	13,564,365

As of September 30, 2015, the Company had regulatory assets in the amount of $9,513,749 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. The cost of additions to utility plant includes direct charges and overhead. The cost of depreciable property retired is 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. Maintenance, repairs, and minor renewals and betterments of property are charged to operations and maintenance.

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

	Years Ended September 30
	2015		2014
Distribution and transmission	$	143,172,628	$	134,439,225
LNG storage	12,501,179		9,163,158
General and miscellaneous	12,359,225		11,757,817
Total utility plant in service	$	168,033,032	$	155,360,200

Provisions for depreciation are computed principally at composite straight-line rates as determined by depreciation studies required to be performed on the regulated utility assets of Roanoke Gas Company at least every five years. The Company completed its most recent depreciation study in June 2014. The composite weighted-average depreciation rates provided for under the new depreciation study were 3.25% for the fiscal years ended September 30, 2015 and 2014 compared to 3.35% for the fiscal year ended September 30, 2013 under the prior rates. For the year ended September 30, 2014, the implementation of the new depreciation rates reduced depreciation expense by $126,875 and increased net income by $78,713 and earnings per share by $0.02.

The composite rates are comprised 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 evacuating 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 2015, 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
	2015			2014
Beginning balance	$	4,802,015		$	4,525,355
Liabilities incurred	62,890			74,276
Liabilities settled	(162,072		)	(165,845		)
Accretion	281,762			258,763
Revisions to estimated cash flows	311,273			109,466
Ending balance	$	5,295,868		$	4,802,015

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, 2015, 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
	2015			2014			2013
Beginning balance	$	70,747		$	68,539		$	65,219
Provision for doubtful accounts	87,908			148,881			85,033
Recoveries of accounts written off	139,282			136,369			122,432
Accounts written off	(245,216		)	(283,042		)	(204,145		)
Ending balance	$	52,721		$	70,747		$	68,539

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 are the Company's one primary type of financing receivables, resulting from the sale of natural gas and other services to its customers. These receivable are short-term in nature with a provision for uncollectible balances included in the financial statements.

Inventories—Inventories, consisting of natural gas in storage and materials and supplies, are recorded at average cost. Injections into storage are priced at the purchase cost at the time of injection and withdrawals from storage are priced at the weighted average price 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, 2015 and 2014 were $1,001,418 and $1,071,128, 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 amortized over the lives of the debt instruments.

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 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 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 6 and 10.

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
	2015		2014		2013
Net Income	$	5,094,415	$	4,708,440	$	4,262,052
Weighted-average common shares	4,728,210		4,715,478		4,698,727
Effect of dilutive securities:
Options to purchase common stock	3,466		804		39
Diluted average common shares	4,731,676		4,716,282		4,698,766
Earnings Per Share of Common Stock:
Basic	$	1.08	$	1.00	$	0.91
Diluted	$	1.08	$	1.00	$	0.91

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, 2016. 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 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. hedges 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, 2015 and 2014, the Company had no outstanding derivative instruments for the purchase of natural gas.

The Company also had two interest rate swaps that essentially converted its variable interest rate notes to fixed rate debt instruments. Both swaps were terminated in September 2014 as part of the Company's debt refinancing. These swaps qualified as cash flow hedges with changes in fair value reported in other comprehensive income.

No derivative instruments were deemed to be ineffective for any period presented.

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, 2015:
Defined benefit plans:
Net loss arising during period	$	(1,910,573	)	$	726,017		$	(1,184,556	)
Amortization of actuarial losses	60,221			(22,884		)	37,337
Other comprehensive loss	$	(1,850,352	)	$	703,133		$	(1,147,219	)
Year Ended September 30, 2014:
Interest rate swaps:
Unrealized losses	$	(58,800	)	$	22,321		$	(36,479	)
Transfer of realized losses to interest expense	926,262			(351,609		)	574,653
Transfer of realized losses to regulatory asset	1,119,233			(424,861		)	694,372
Net interest rate swaps	1,986,695			(754,149		)	1,232,546
Defined benefit plans:
Net loss arising during period	(397,714		)	151,131			(246,583		)
Amortization of actuarial losses	41,846			(15,901		)	25,945
Net defined benefit plans	(355,868		)	135,230			(220,638		)
Other comprehensive income	$	1,630,827		$	(618,919	)	$	1,011,908
Year Ended September 30, 2013:
Interest rate swaps:
Unrealized losses	$	(20,479	)	$	7,774		$	(12,705	)
Transfer of realized losses to interest expense	950,501			(360,811		)	589,690
Net interest rate swaps	930,022			(353,037		)	576,985
Defined benefit plans:
Net gain arising during period	1,714,890			(651,659		)	1,063,231
Amortization of actuarial losses	219,890			(83,558		)	136,332
Amortization of transition obligation	35,972			(13,669		)	22,303
Net defined benefit plans	1,970,752			(748,886		)	1,221,866
Other comprehensive income	$	2,900,774		$	(1,101,923	)	$	1,798,851

The amortization of actuarial losses and transition obligation is included as components of net periodic pension and postretirement benefit costs and is included 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, 2012	$	(1,809,531	)	$	(2,140,554	)	$	(3,950,085	)
Other comprehensive income (loss)	576,985			1,221,866			1,798,851
Balance September 30, 2013	(1,232,546		)	(918,688		)	(2,151,234		)
Other comprehensive income (loss)	1,232,546			(220,638		)	1,011,908
Balance September 30, 2014	—			(1,139,326		)	(1,139,326		)
Other comprehensive income (loss)	—			(1,147,219		)	(1,147,219		)
Balance September 30, 2015	$	—		$	(2,286,545	)	$	(2,286,545	)

Change in Method of Accounting for Long-term Debt—During the fiscal year ended September 30, 2015, the Company adopted the provisions of ASU 2015-03 as described further under the Recently Adopted Accounting Standards section below. Under ASU 2015-03, the unamortized balance of debt issuance costs are reclassified from assets to liabilities and netted against the carrying value of long-term debt. The change had no impact on net income.

Management retrospectively applied the change. The carrying value of long-term debt and the reclassified debt issuance costs are presented separately on the Company’s Consolidated Balance Sheets and in Note 4 for the periods ended September 30, 2015 and 2014.

Recently Adopted Accounting Standards—In June 2011, the FASB issued guidance under FASB ASC No. 220 - Comprehensive Income that defines the presentation of Comprehensive Income in the financial statements. According to the guidance, an entity may present a single continuous statement of comprehensive income or two separate statements - a statement of income and a statement of other comprehensive income that immediately follows the statement of income. In either presentation, the entity is required to present on the face of the financial statement the components of other comprehensive income including the reclassification adjustment for items that are reclassified from other comprehensive income to net income. In December 2011, the FASB issued additional guidance under FASB ASC No. 220 that deferred the effective date of earlier guidance with regard to the presentation of reclassifications of items out of accumulated other comprehensive income. All other provisions of the original guidance remain in effect. In February 2013, the FASB issued additional guidance regarding the reporting of amounts reclassified out of accumulated other comprehensive income. Under the new provisions, an entity must present the effects on the line items of net income of significant amounts reclassified out of accumulated other comprehensive income. The disclosures required under this guidance are provided above.

In April 2015, the FASB issued ASU 2015-03, Interest-Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs. This ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. The Company previously recognized debt issuance costs in assets and amortized those costs over the term of the debt. This guidance is effective for the Company for the annual reporting period ending September 30, 2017 and interim periods within that annual period. Early application is permitted. The Company adopted the ASU during the current reporting period. The adoption of this ASU did not have an effect on the Company's results of operations or cash flows; however, the unamortized balance of debt issuance costs were reclassified from assets to an offset against long-term debt. Certain deferred costs related to the early retirement of debt in 2014 are classified as regulatory assets and are not offset against debt. The changes required under this guidance are presented in Note 1, Note 4 and the Consolidated Balance Sheets.

Recently Issued Accounting Standards—In May 2014, the FASB issued guidance under FASB ASC No. 606 - Revenue from Contracts with Customers 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 these 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 Accounting Standards Update (ASU) 2015-14 that deferred the effective date of this guidance by one year. Therefore, the new guidance is effective for the Company for the annual reporting period ended September 30, 2019 and interim periods within that annual period. Early application is not permitted. Management has not completed its evaluation of the new guidance; however, the Company does not currently expect it 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.

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Common Stock Options (Schedule of Stock Option Activity) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2012
Number of Shares
Options outstanding, beginning balance (in shares)	38,000	21,000	0
Options granted (in shares)	17,000	17,000	21,000
Options exercised (in shares)	(2,600)	0	0
Options expired (in shares)	0	0	0
Options forfeited (in shares)	0	0	0
Options outstanding, ending balance (in shares)	52,400	38,000	21,000	0
Vested and exercisable at end of period (in shares)	52,400
Weighted- Average Exercise Price
Options outstanding, beginning balance (in usd per share)	$ 18.98	$ 19.01	$ 0.00
Options granted (in usd per share)	21.60	18.95	19.01
Options exercised (in usd per share)	18.99	0.00	0.00
Options expired (in usd per share)	0.00	0.00	0.00
Options forfeited (in usd per share)	0.00	0.00	0.00
Options outstanding, ending balance (in usd per share)	19.83	$ 18.98	$ 19.01	$ 0.00
Vested and exercisable at end of period (in usd per share)	$ 19.83
Options, Additional Disclosures
Weighted- Average Remaining Contractual Terms (years)	8 years 4 months	8 years 9 months	9 years 6 months	0 years
Weighted-Average Remaining Contractual Term, Vested and exercisable at September 30, 2015	8 years 4 months
Aggregate Intrinsic Value	$ 43,086	$ 34,840	$ 5,229	$ 0
Aggregate Intrinsic Value, Vested and exercisable at end of period	$ 43,086

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Short-Term Debt (Summary of Line-Of-Credit) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Short-term Debt [Abstract]
Line-of-credit at year-end	$ 24,000,000	$ 15,000,000	$ 5,000,000
Outstanding balance at year-end	9,340,997	9,045,050	0
Highest month-end balance outstanding	17,366,052	9,045,050	1,414,955
Average daily balance	$ 6,377,040	$ 1,340,833	$ 80,593
Average rate of interest during year on outstanding balances	1.17%	1.16%	1.21%
Interest rate at year-end	1.20%	1.16%	1.18%
Interest rate on unused line-of-credit	0.15%	0.15%	0.15%

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Commitments and Contingencies (Tables)

12 Months Ended

Sep. 30, 2015

Volumetric Obligation

Schedule of Volumetric and Pipeline and Storage Capacity Obligations

The table below details the volumetric obligations as of September 30, 2015 for the remainder of the contract period.

Year	Natural Gas Contracts (In Decatherms)
2015-2016	2,071,061
2016-2017	295,866
Total	2,366,927

Pipeline and Storage Capacity Obligation

Schedule of Volumetric and Pipeline and Storage Capacity Obligations

The table below details the pipeline and storage capacity obligations as of September 30, 2015 for the remainder of the contract period.

Year	Pipeline and Storage Capacity
2015-2016	$	11,392,645
2016-2017	9,999,402
2017-2018	7,787,998
2018-2019	6,171,421
2019-2020	2,427,961
Thereafter	—
Total	$	37,779,427

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Other Stock Plans (Tables)

12 Months Ended

Sep. 30, 2015

Other Stock Plans [Abstract]

Director Compensation Activity

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

	2015			2014			2013
	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	62,844	$	14.29	59,064	$	13.97	54,011	$	13.51
Granted	4,071	20.88		3,780	19.37		5,053	18.93
Vested	—	—		—	—		—	—
Forfeited	—	—		—	—		—	—
End of year balance	66,915	$	14.70	62,844	$	14.29	59,064	$	13.97

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Employee Benefit Plans (Effect of a 1% Change in Health Care Cost Trend Rate Assumptions) (Details) $ in Thousands	12 Months Ended
	Sep. 30, 2015 USD ($)
1% Increase
Effect on total service and interest cost components	$ 137
Effect on accumulated postretirement benefit obligation	2,383
1% Decrease
Effect on total service and interest cost components, 1% Decrease	(109)
Effect on accumulated postretirement benefit obligation, 1% Decease	$ (1,938)

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Long-Term Debt (Narrative) (Details)	12 Months Ended
	Sep. 30, 2015 USD ($) debt_covenant	Sep. 30, 2014 USD ($)
Debt Instrument [Line Items]
Unamortized loss on early retirement of debt deferred as regulatory asset | $	$ 2,169,556	$ 2,283,744
Unamortized loss on early retirement of debt, amortization period	20 years
Unsecured Senior Notes | Unsecured senior notes payable, at 4.26%, due on September 18, 2034
Debt Instrument [Line Items]
Number of debt covenants | debt_covenant	2
Debt covenant, maximum ratio of total long-term debt to total capitalization	65.00%
Debt covenant, maximum ratio of priority indebtedness to total assets	15.00%

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Fair Value Measurements (Tables)

12 Months Ended

Sep. 30, 2015

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, 2015 and 2014, respectively:

			Fair Value Measurements - September 30, 2015
	Fair Value		Quoted Prices in Active Markets Level 1		Significant  Other Observable Inputs Level 2		Significant Unobservable Inputs Level 3
Liabilities:
Natural gas purchases	$	712,710	$	—	$	712,710	$	—
Total	$	712,710	$	—	$	712,710	$	—

			Fair Value Measurements - September 30, 2014
	Fair Value		Quoted Prices in Active Markets Level 1		Significant Other Observable Inputs Level  2		Significant Unobservable Inputs Level 3
Liabilities:
Natural gas purchases	$	795,019	$	—	$	795,019	$	—
Total	$	795,019	$	—	$	795,019	$	—

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, 2015 and 2014.

			Fair Value Measurements - September 30, 2015
	Carrying Amount		Quoted Prices in Active Markets Level 1		Significant Other Observable  Inputs Level 2		Significant Unobservable Inputs Level 3
Liabilities:
Long-term debt	$	30,500,000	$	—	$	—	$	28,570,585
Total	$	30,500,000	$	—	$	—	$	28,570,585

			Fair Value Measurements - September 30, 2014
	Carrying Amount		Quoted Prices in Active  Markets Level 1		Significant Other Observable  Inputs Level 2		Significant Unobservable Inputs Level 3
Liabilities:
Long-term debt	$	30,500,000	$	—	$	—	$	30,622,664
Total	$	30,500,000	$	—	$	—	$	30,622,664

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Quarterly Financial Information (Unaudited) (Tables)

12 Months Ended

Sep. 30, 2015

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Data

Quarterly financial data for the years ended September 30, 2015 and 2014 is summarized as follows:

2015	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Operating revenues	$	21,250,065	$	26,431,729	$	10,774,409	$	9,733,404
Gross margin	$	8,622,143	$	10,213,770	$	5,961,828	$	5,408,692
Operating income	$	3,514,352	$	4,879,469	$	956,219	$	656,152
Net income	$	1,924,376	$	2,779,344	$	354,940	$	35,755
Earnings per share of common stock:
Basic	$	0.41	$	0.59	$	0.08	$	0.01
Diluted	$	0.41	$	0.59	$	0.07	$	0.01

2014	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Operating revenues	$	20,011,194	$	32,699,965	$	12,024,817	$	10,280,158
Gross margin	$	8,202,992	$	10,161,125	$	5,721,551	$	5,251,421
Operating income	$	3,272,646	$	5,121,022	$	940,691	$	347,509
Net income (loss)	$	1,722,788	$	2,846,795	$	283,194	$	(144,337	)
Earnings per share of common stock:
Basic	$	0.37	$	0.60	$	0.06	$	(0.03	)
Diluted	$	0.37	$	0.60	$	0.06	$	(0.03	)

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Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 5,094,415	$ 4,708,440	$ 4,262,052
Adjustments to reconcile net income to net cash provided by operations:
Depreciation and amortization	5,219,893	4,838,062	4,656,716
Cost of retirement of utility plant, net	(406,731)	(452,834)	(502,587)
Stock option grants	83,640	75,310	84,840
Deferred taxes and investment tax credits	2,416,841	859,788	786,990
Other noncash items, net	105,815	38,073	39,186
Changes in assets and liabilities which provided (used) cash:
Accounts receivable and customer deposits, net	638,917	12,424	(374,682)
Inventories and gas in storage	3,168,056	(1,219,641)	(997,378)
Over/under recovery of gas costs	2,082,257	(1,208,134)	1,714,497
Other assets	(768,922)	(306,744)	1,106,590
Accounts payable, customer credit balances and accrued expenses, net	(873,354)	(505,006)	(739,154)
Total adjustments	11,666,412	2,131,298	5,775,018
Net cash provided by operating activities	16,760,827	6,839,738	10,037,070
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for utility property	(13,780,356)	(14,715,428)	(9,977,433)
Proceeds from disposal of utility property	30,082	16,858	29,923
Net cash used in investing activities	(13,750,274)	(14,698,570)	(9,947,510)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds on collection of notes	0	0	1,142,770
Borrowings under line-of-credit	34,698,924	25,363,774	4,354,402
Repayments under line-of-credit	(34,402,977)	(16,318,724)	(4,354,402)
Proceeds from issuance of unsecured notes	0	30,500,000	0
Retirement of note payable	0	(15,000,000)	0
Retirement of long-term debt	0	(13,000,000)	0
Early termination fees	0	(2,237,961)	0
Debt issuance expenses	0	(193,081)	0
Proceeds from issuance of stock	432,401	213,391	737,076
Cash dividends paid	(3,603,424)	(3,465,034)	(8,033,053)
Net cash provided by (used in) financing activities	(2,875,076)	5,862,365	(6,153,207)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	135,477	(1,996,467)	(6,063,647)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	849,757	2,846,224	8,909,871
CASH AND CASH EQUIVALENTS AT END OF YEAR	985,234	849,757	2,846,224
Cash paid during the year for:
Interest	1,002,462	1,966,263	1,803,528
Income taxes	$ 1,266,573	$ 2,387,000	$ 622,076

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Summary of Significant Accounting Policies (Narrative) (Details)	12 Months Ended
	Sep. 30, 2015 USD ($) pipeline instruments_held segment customer	Sep. 30, 2014 USD ($) instruments_held $ / shares	Sep. 30, 2013
Summary Of Significant Accounting Policies [Line Items]
Number of customers | customer	59,100
Number of reportable segments | segment	1
Remaining amount of regulatory assets that did not earn a return during the recovery period	$ 9,513,749
Regulatory utility assets provision, review period	5 years
Composite weighted-average depreciation rate	3.25%	3.25%	3.35%
Effect of change in deprecation rate on depreciation expense		$ 126,875
Effect of change in depreciation rate on net income		$ 78,713
Effect of change in deprecation rate on EPS (in usd per share) | $ / shares		$ 0.02
Unbilled revenue	$ 1,001,418	$ 1,071,128
Deferred charges, amortization period	12 months
Percentage of total revenue	5.00%
Maximum percentage of accounts receivable from a single customer	5.00%
Franchise effective date	Jan. 01, 2016
Number of pipelines | pipeline	2
Natural Gas [Member]
Summary Of Significant Accounting Policies [Line Items]
Number of derivative instruments | instruments_held	0	0
Interest Rate Swap [Member]
Summary Of Significant Accounting Policies [Line Items]
Number of derivative instruments | instruments_held		2

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Regulatory Matters (Details)	Jun. 25, 2014 USD ($)
Regulated Operations [Abstract]
Approved short term indebtedness authority (up to)	$ 30,000,000
Approved long term indebtedness authority (up to)	$ 60,000,000

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Employee Benefit Plans (Schedule of Actuarial Assumptions Used) (Details)	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Pension Plan [Member]
Assumptions used to determine benefit obligations:
Discount rate	4.22%	4.22%	4.82%
Expected rate of compensation increase	4.00%	4.00%	4.00%
Assumptions used to determine benefit costs:
Discount rate	4.22%	4.82%	4.06%
Expected long-term rate of return on plan assets	7.00%	7.00%	7.25%
Expected rate of compensation increase	4.00%	4.00%	4.00%
Postretirement Plan [Member]
Assumptions used to determine benefit obligations:
Discount rate	4.15%	4.10%	4.73%
Assumptions used to determine benefit costs:
Discount rate	4.10%	4.73%	3.95%
Expected long-term rate of return on plan assets	4.90%	4.92%	5.11%

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Subsequent Events (Details) - USD ($)	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Subsequent Event [Line Items]
Borrowings under a temporary line-of-credit	$ 34,698,924	$ 25,363,774	$ 4,354,402
RGC Midstream, LLC [Member]
Subsequent Event [Line Items]
Ownership interest (as a percent)	1.00%
Estimated future investment to LLC	$ 35,000,000
Support for the construction of the pipeline, period	3 years
Borrowings under a temporary line-of-credit	$ 1,500,000

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Consolidated Balance Sheets - USD ($)	Sep. 30, 2015	Sep. 30, 2014
ASSETS
Cash and cash equivalents	$ 985,234	$ 849,757
Accounts receivable, net	3,196,573	3,730,173
Materials and supplies	968,108	893,672
Gas in storage	8,160,498	11,402,990
Prepaid income taxes	1,657,066	1,144,214
Deferred income taxes	2,293,536	1,704,320
Under-recovery of gas costs	0	180,831
Other	1,182,343	1,104,660
Total current assets	18,443,358	21,010,617
UTILITY PROPERTY:
In service	168,033,032	155,360,200
Accumulated depreciation and amortization	(53,307,079)	(50,645,642)
In service, net	114,725,953	104,714,558
Construction work in progress	3,903,599	4,029,019
Utility plant, net	118,629,552	108,743,577
OTHER ASSETS:
Regulatory assets	10,923,243	9,273,389
Other	144,577	100,058
Total other assets	11,067,820	9,373,447
TOTAL ASSETS	148,140,730	139,127,641
LIABILITIES AND STOCKHOLDERS’ EQUITY
Borrowings under line-of-credit	9,340,997	9,045,050
Dividends payable	912,995	873,326
Accounts payable	5,141,677	5,367,299
Customer credit balances	1,560,351	1,373,927
Customer deposits	1,579,441	1,492,150
Accrued expenses	2,766,097	2,200,882
Over-recovery of gas costs	1,901,426	0
Total current liabilities	23,202,984	20,352,634
Principal amount	30,500,000	30,500,000
Less unamortized debt issuance costs	(183,427)	(193,081)
Long-term debt net of unamortized debt issuance costs	30,316,573	30,306,919
DEFERRED CREDITS AND OTHER LIABILITIES:
Asset retirement obligations	5,295,868	4,802,015
Regulatory cost of retirement obligations	8,885,486	8,575,147
Benefit plan liabilities	10,685,261	8,459,436
Deferred income taxes	16,913,567	14,610,643
Total deferred credits and other liabilities	$ 41,780,182	$ 36,447,241
COMMITMENTS AND CONTINGENCIES (Note 9)
Stockholders’ Equity:
Common stock, $5 par value; authorized 10,000,000 shares; issued and outstanding 4,741,498 and 4,720,378 shares in 2015 and 2014, respectively	$ 23,707,490	$ 23,601,890
Preferred stock, no par; authorized 5,000,000 shares; no shares issued and outstanding in 2015 and 2014	0	0
Capital in excess of par value	8,647,669	8,237,228
Retained earnings	22,772,377	21,321,055
Accumulated other comprehensive loss	(2,286,545)	(1,139,326)
Total stockholders’ equity	52,840,991	52,020,847
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$ 148,140,730	$ 139,127,641

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Long-Term Debt (Schedule of Long-Term Debt) (Details) - USD ($)	Sep. 30, 2015	Sep. 30, 2014
Debt Instrument [Line Items]
Unamortized Debt Issuance Costs	$ 183,427	$ 193,081
Total, Principal	30,500,000	30,500,000
Unsecured Senior Notes | Unsecured senior notes payable, at 4.26%, due on September 18, 2034
Debt Instrument [Line Items]
Principal	30,500,000	30,500,000
Unamortized Debt Issuance Costs	$ 183,427	$ 193,081
Stated percentage rate	4.26%

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Consolidated Statements of Stockholders' Equity - USD ($)	Total	Common Stock	Capital in Excess of Par Value	Retained Earnings	Accumulated Other Comprehensive Income (Loss)
Balance at Sep. 30, 2012	$ 50,682,930	$ 23,352,835	$ 7,375,666	$ 23,904,514	$ (3,950,085)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	4,262,052			4,262,052
Other comprehensive income (loss)	1,798,851				1,798,851
Stock option grants	84,840		84,840
Cash dividends declared	(8,063,327)			(8,063,327)
Issuance of common stock	737,076	193,795	543,281
Balance at Sep. 30, 2013	49,502,422	23,546,630	8,003,787	20,103,239	(2,151,234)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	4,708,440			4,708,440
Other comprehensive income (loss)	1,011,908				1,011,908
Stock option grants	75,310		75,310
Cash dividends declared	(3,490,624)			(3,490,624)
Issuance of common stock	213,391	55,260	158,131
Balance at Sep. 30, 2014	52,020,847	23,601,890	8,237,228	21,321,055	(1,139,326)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	5,094,415			5,094,415
Other comprehensive income (loss)	(1,147,219)				(1,147,219)
Exercise of stock options (2,600 shares)	49,366	13,000	36,366
Stock option grants	83,640		83,640
Cash dividends declared	(3,643,093)			(3,643,093)
Issuance of common stock	383,035	92,600	290,435
Balance at Sep. 30, 2015	$ 52,840,991	$ 23,707,490	$ 8,647,669	$ 22,772,377	$ (2,286,545)

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Employee Benefit Plans (Schedule of Expected Future Benefit Payments) (Details)	Sep. 30, 2015 USD ($)
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
2016	$ 655,968
2017	698,403
2018	773,580
2019	818,585
2020	944,944
2021-2025	6,531,464
Postretirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
2016	617,386
2017	625,167
2018	634,509
2019	655,095
2020	695,924
2021-2025	$ 4,012,407

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Summary of Significant Accounting Policies (Summary of Asset Retirement Obligations) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	$ 4,802,015	$ 4,525,355
Liabilities incurred	62,890	74,276
Liabilities settled	(162,072)	(165,845)
Accretion	281,762	258,763
Revisions to estimated cash flows	311,273	109,466
Ending balance	$ 5,295,868	$ 4,802,015

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Commitments and Contingencies (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Commitments and Contingencies Disclosure [Abstract]
Expenditures under asset management agreement	$ 33,405	$ 44,884	$ 35,348

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Sep. 30, 2015

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, 2015 and 2014 are as follows:

	September 30
	2015		2014
Regulatory Assets:
Current Assets:
Accounts receivable:
Accrued WNA revenues	$	229,281	$	143,753
Under-recovery of gas costs	—		180,831
Other:
Accrued pension and postretirement medical	530,781		394,215
Utility Property:
In service:
Other	11,945		11,945
Other Assets:
Regulatory assets:
Premium on early retirement of debt	2,169,556		2,283,744
Accrued pension and postretirement medical	8,378,419		6,884,812
Other	375,268		104,833
Total regulatory assets	$	11,695,250	$	10,004,133
Regulatory Liabilities:
Current Liabilities:
Over-recovery of gas costs	$	1,901,426	$	—
Accrued expenses:
Over-recovery of SAVE Plan revenues	153,365		187,203
Deferred Credits and Other Liabilities:
Asset retirement obligations	5,295,868		4,802,015
Regulatory cost of retirement obligations	8,885,486		8,575,147
Total regulatory liabilities	$	16,236,145	$	13,564,365

Schedule of Regulatory Liabilities

Regulatory assets and liabilities included in the Company’s consolidated balance sheets as of September 30, 2015 and 2014 are as follows:

	September 30
	2015		2014
Regulatory Assets:
Current Assets:
Accounts receivable:
Accrued WNA revenues	$	229,281	$	143,753
Under-recovery of gas costs	—		180,831
Other:
Accrued pension and postretirement medical	530,781		394,215
Utility Property:
In service:
Other	11,945		11,945
Other Assets:
Regulatory assets:
Premium on early retirement of debt	2,169,556		2,283,744
Accrued pension and postretirement medical	8,378,419		6,884,812
Other	375,268		104,833
Total regulatory assets	$	11,695,250	$	10,004,133
Regulatory Liabilities:
Current Liabilities:
Over-recovery of gas costs	$	1,901,426	$	—
Accrued expenses:
Over-recovery of SAVE Plan revenues	153,365		187,203
Deferred Credits and Other Liabilities:
Asset retirement obligations	5,295,868		4,802,015
Regulatory cost of retirement obligations	8,885,486		8,575,147
Total regulatory liabilities	$	16,236,145	$	13,564,365

Schedule of Utility Plant

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

	Years Ended September 30
	2015		2014
Distribution and transmission	$	143,172,628	$	134,439,225
LNG storage	12,501,179		9,163,158
General and miscellaneous	12,359,225		11,757,817
Total utility plant in service	$	168,033,032	$	155,360,200

Summary of Asset Retirement Obligation

The following is a summary of the asset retirement obligation:

	Years Ended September 30
	2015			2014
Beginning balance	$	4,802,015		$	4,525,355
Liabilities incurred	62,890			74,276
Liabilities settled	(162,072		)	(165,845		)
Accretion	281,762			258,763
Revisions to estimated cash flows	311,273			109,466
Ending balance	$	5,295,868		$	4,802,015

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
	2015			2014			2013
Beginning balance	$	70,747		$	68,539		$	65,219
Provision for doubtful accounts	87,908			148,881			85,033
Recoveries of accounts written off	139,282			136,369			122,432
Accounts written off	(245,216		)	(283,042		)	(204,145		)
Ending balance	$	52,721		$	70,747		$	68,539

Reconciliation of Basic and Diluted Earnings Per Share

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

	Years Ended September 30
	2015		2014		2013
Net Income	$	5,094,415	$	4,708,440	$	4,262,052
Weighted-average common shares	4,728,210		4,715,478		4,698,727
Effect of dilutive securities:
Options to purchase common stock	3,466		804		39
Diluted average common shares	4,731,676		4,716,282		4,698,766
Earnings Per Share of Common Stock:
Basic	$	1.08	$	1.00	$	0.91
Diluted	$	1.08	$	1.00	$	0.91

Summary of Other Comprehensive Income

A summary of other comprehensive income is provided below:

	Before Tax Amount			Tax (Expense) or Benefit			Net-of Tax Amount
Year Ended September 30, 2015:
Defined benefit plans:
Net loss arising during period	$	(1,910,573	)	$	726,017		$	(1,184,556	)
Amortization of actuarial losses	60,221			(22,884		)	37,337
Other comprehensive loss	$	(1,850,352	)	$	703,133		$	(1,147,219	)
Year Ended September 30, 2014:
Interest rate swaps:
Unrealized losses	$	(58,800	)	$	22,321		$	(36,479	)
Transfer of realized losses to interest expense	926,262			(351,609		)	574,653
Transfer of realized losses to regulatory asset	1,119,233			(424,861		)	694,372
Net interest rate swaps	1,986,695			(754,149		)	1,232,546
Defined benefit plans:
Net loss arising during period	(397,714		)	151,131			(246,583		)
Amortization of actuarial losses	41,846			(15,901		)	25,945
Net defined benefit plans	(355,868		)	135,230			(220,638		)
Other comprehensive income	$	1,630,827		$	(618,919	)	$	1,011,908
Year Ended September 30, 2013:
Interest rate swaps:
Unrealized losses	$	(20,479	)	$	7,774		$	(12,705	)
Transfer of realized losses to interest expense	950,501			(360,811		)	589,690
Net interest rate swaps	930,022			(353,037		)	576,985
Defined benefit plans:
Net gain arising during period	1,714,890			(651,659		)	1,063,231
Amortization of actuarial losses	219,890			(83,558		)	136,332
Amortization of transition obligation	35,972			(13,669		)	22,303
Net defined benefit plans	1,970,752			(748,886		)	1,221,866
Other comprehensive income	$	2,900,774		$	(1,101,923	)	$	1,798,851

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, 2012	$	(1,809,531	)	$	(2,140,554	)	$	(3,950,085	)
Other comprehensive income (loss)	576,985			1,221,866			1,798,851
Balance September 30, 2013	(1,232,546		)	(918,688		)	(2,151,234		)
Other comprehensive income (loss)	1,232,546			(220,638		)	1,011,908
Balance September 30, 2014	—			(1,139,326		)	(1,139,326		)
Other comprehensive income (loss)	—			(1,147,219		)	(1,147,219		)
Balance September 30, 2015	$	—		$	(2,286,545	)	$	(2,286,545	)

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Summary of Significant Accounting Policies (Reconciliation of Changes in Allowance for Doubtful Accounts) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Allowance for Doubtful Accounts Receivable [Roll Forward]
Beginning balance	$ 70,747	$ 68,539	$ 65,219
Provision for doubtful accounts	87,908	148,881	85,033
Recoveries of accounts written off	139,282	136,369	122,432
Accounts written off	(245,216)	(283,042)	(204,145)
Ending balance	$ 52,721	$ 70,747	$ 68,539

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Long-Term Debt (Tables)

12 Months Ended

Sep. 30, 2015

Debt Disclosure [Abstract]

Schedule of Long-Term Debt

Long-term debt consists of the following:

	September 30
	2015				2014
	Principal		Unamortized Debt Issuance Costs		Principal		Unamortized Debt Issuance Costs
Unsecured senior notes payable, at 4.26%, due on September 18, 2034	$	30,500,000	$	183,427	$	30,500,000	$	193,081
Total	$	30,500,000	$	183,427	$	30,500,000	$	193,081

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, 2015 are as follows:

Year Ending September 30	Maturities
2016	$	—
2017	—
2018	—
2019	—
2020	—
Thereafter	30,500,000
Total	$	30,500,000

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Fair Value Measurements (Schedule of Fair Value of Financial Assets and Liabilities Measured on a Recurring Basis) (Details) - USD ($)	Sep. 30, 2015	Sep. 30, 2014
Schedule of Fair Value Assets and Liabilities Measured on Recurring Basis and Fair Value Measurement Inputs [Line Items]
Natural gas purchases	$ 712,710	$ 795,019
Total	712,710	795,019
Quoted Prices In Active Markets Level 1 [Member]
Schedule of Fair Value Assets and Liabilities Measured on Recurring Basis and Fair Value Measurement Inputs [Line Items]
Natural gas purchases	0	0
Total	0	0
Significant Other Observable Inputs Level 2 [Member]
Schedule of Fair Value Assets and Liabilities Measured on Recurring Basis and Fair Value Measurement Inputs [Line Items]
Natural gas purchases	712,710	795,019
Total	712,710	795,019
Significant Unobservable Inputs Level 3 [Member]
Schedule of Fair Value Assets and Liabilities Measured on Recurring Basis and Fair Value Measurement Inputs [Line Items]
Natural gas purchases	0	0
Total	$ 0	$ 0

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Consolidated Statements of Stockholders' Equity (Parenthetical) - $ / shares	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Statement of Stockholders' Equity [Abstract]
Dividends declared (in usd per share)	$ 0.77	$ 0.74	$ 1.72
Issuance of stock, shares	18,520	11,052	38,759
Options exercised (in shares)	2,600	0	0

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Consolidated Balance Sheets (Parenthetical) - $ / shares	Sep. 30, 2015	Sep. 30, 2014
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	4,741,498	4,720,378
Common stock, share outstanding	4,741,498	4,720,378
Preferred stock, no par value (in usd per share)	$ 0	$ 0
Preferred stock, shares authorized	5,000,000	5,000,000
Preferred stock, shares issued	0	0
Preferred stock, share outstanding	0	0

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Commitments and Contingencies

12 Months Ended

Sep. 30, 2015

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

COMMITMENTS AND CONTINGENCIES

Long-Term Contracts

Due to the nature of the natural gas distribution business, the Company enters into agreements with both suppliers and pipelines to contract for natural gas commodity purchases, storage capacity and pipeline delivery capacity. The Company obtains most of its regulated natural gas supply through an asset management contract between Roanoke Gas and a third party asset manager. The Company utilizes an asset manager to optimize the use of its transportation, storage rights, and gas supply inventories which helps to ensure a secure and reliable source of natural gas. Under the current asset management contract, the Company has designated the asset manager to act as agent for the Company's storage capacity and all gas balances in storage. The Company retains ownership of gas in storage. Under provisions of this contract, the Company 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, 2015 for the remainder of the contract period.

Year	Natural Gas Contracts (In Decatherms)
2015-2016	2,071,061
2016-2017	295,866
Total	2,366,927

The Company 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, 2015. 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. The Company expended approximately $33,405,000, $44,884,000 and $35,348,000 under the asset management, pipeline and storage contracts for Roanoke Gas in fiscal years 2015, 2014 and 2013, respectively. The table below details the pipeline and storage capacity obligations as of September 30, 2015 for the remainder of the contract period.

Year	Pipeline and Storage Capacity
2015-2016	$	11,392,645
2016-2017	9,999,402
2017-2018	7,787,998
2018-2019	6,171,421
2019-2020	2,427,961
Thereafter	—
Total	$	37,779,427

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 Company 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 on-site 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.

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Document And Entity Information - USD ($)	12 Months Ended
	Sep. 30, 2015	Nov. 30, 2015	Mar. 31, 2015
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Sep. 30, 2015
Document Fiscal Year Focus	2015
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	Accelerated Filer
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Common Stock, Shares Outstanding		4,750,645
Entity Public Float			$ 89,254,811

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Fair Value Measurements

12 Months Ended

Sep. 30, 2015

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, 2015 and 2014, respectively:

			Fair Value Measurements - September 30, 2015
	Fair Value		Quoted Prices in Active Markets Level 1		Significant  Other Observable Inputs Level 2		Significant Unobservable Inputs Level 3
Liabilities:
Natural gas purchases	$	712,710	$	—	$	712,710	$	—
Total	$	712,710	$	—	$	712,710	$	—

			Fair Value Measurements - September 30, 2014
	Fair Value		Quoted Prices in Active Markets Level 1		Significant Other Observable Inputs Level  2		Significant Unobservable Inputs Level 3
Liabilities:
Natural gas purchases	$	795,019	$	—	$	795,019	$	—
Total	$	795,019	$	—	$	795,019	$	—

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, 2015 and 2014, 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 short-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, 2015 and 2014.

			Fair Value Measurements - September 30, 2015
	Carrying Amount		Quoted Prices in Active Markets Level 1		Significant Other Observable  Inputs Level 2		Significant Unobservable Inputs Level 3
Liabilities:
Long-term debt	$	30,500,000	$	—	$	—	$	28,570,585
Total	$	30,500,000	$	—	$	—	$	28,570,585

			Fair Value Measurements - September 30, 2014
	Carrying Amount		Quoted Prices in Active  Markets Level 1		Significant Other Observable  Inputs Level 2		Significant Unobservable Inputs Level 3
Liabilities:
Long-term debt	$	30,500,000	$	—	$	—	$	30,622,664
Total	$	30,500,000	$	—	$	—	$	30,622,664

The fair value of long-term debt is estimated by discounting the future cash flows of the fixed rate debt based on the underlying 20-year Treasury rate and estimated credit spread extrapolated based on market conditions since the issuance of the debt.

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.

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Consolidated Statements of Income - USD ($)	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
OPERATING REVENUES:
Gas utilities	$ 67,094,290	$ 73,865,487	$ 62,024,174
Other	1,095,317	1,150,647	1,181,492
Total operating revenues	68,189,607	75,016,134	63,205,666
COST OF SALES:
Gas utilities	37,437,315	45,091,274	34,916,062
Other	545,859	587,771	686,713
Total cost of sales	37,983,174	45,679,045	35,602,775
GROSS MARGIN	30,206,433	29,337,089	27,602,891
OTHER OPERATING EXPENSES:
Operations and maintenance	13,486,885	13,383,388	12,853,599
General taxes	1,606,421	1,560,386	1,480,746
Depreciation and amortization	5,106,935	4,711,447	4,473,491
Total other operating expenses	20,200,241	19,655,221	18,807,836
OPERATING INCOME	10,006,192	9,681,868	8,795,055
OTHER EXPENSE, net	228,796	206,887	60,117
INTEREST EXPENSE	1,512,419	1,827,001	1,828,099
INCOME BEFORE INCOME TAXES	8,264,977	7,647,980	6,906,839
INCOME TAX EXPENSE	3,170,562	2,939,540	2,644,787
NET INCOME	$ 5,094,415	$ 4,708,440	$ 4,262,052
EARNINGS PER COMMON SHARE:
Basic (in usd per share)	$ 1.08	$ 1.00	$ 0.91
Diluted (in usd per share)	$ 1.08	$ 1.00	$ 0.91
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic (in shares)	4,728,210	4,715,478	4,698,727
Diluted (in shares)	4,731,676	4,716,282	4,698,766

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Long-Term Debt

12 Months Ended

Sep. 30, 2015

Debt Disclosure [Abstract]

Long-Term Debt

LONG-TERM DEBT

Long-term debt consists of the following:

	September 30
	2015				2014
	Principal		Unamortized Debt Issuance Costs		Principal		Unamortized Debt Issuance Costs
Unsecured senior notes payable, at 4.26%, due on September 18, 2034	$	30,500,000	$	183,427	$	30,500,000	$	193,081
Total	$	30,500,000	$	183,427	$	30,500,000	$	193,081

Debt issuance costs are amortized over the life of the related debt. As of September 30, 2015 and 2014, the Company also had an unamortized loss on the early retirement of debt of $2,169,556 and $2,283,744, respectively, which has been deferred as a regulatory asset and is being amortized over a 20 year period.

The unsecured notes payable contain various provisions, including two financial covenants. First, total long-term debt, including current maturities, shall not exceed 65% of total capitalization. Second, the Company shall not allow priority indebtedness to exceed 15% of total assets.

The aggregate annual maturities of long-term debt for the next five years ending after September 30, 2015 are as follows:

Year Ending September 30	Maturities
2016	$	—
2017	—
2018	—
2019	—
2020	—
Thereafter	30,500,000
Total	$	30,500,000

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Short-Term Debt

12 Months Ended

Sep. 30, 2015

Short-term Debt [Abstract]

Short-Term Debt

SHORT-TERM DEBT

The Company has available an unsecured line-of-credit with a bank which will expire March 31, 2016. The Company anticipates being able to extend or replace this line-of-credit upon expiration. The Company’s available unsecured line-of-credit varies during the year to accommodate its seasonal borrowing demands. Available limits under this agreement for the remaining term are as follows:

Effective	Available Line-of-Credit
September 30, 2015	$	24,000,000
March 1, 2016	17,000,000

A summary of the line-of-credit follows:

	September 30
	2015			2014			2013
Line-of-credit at year-end	$	24,000,000		$	15,000,000		$	5,000,000
Outstanding balance at year-end	9,340,997			9,045,050			—
Highest month-end balance outstanding	17,366,052			9,045,050			1,414,955
Average daily balance	6,377,040			1,340,833			80,593
Average rate of interest during year on outstanding balances	1.17		%	1.16		%	1.21		%
Interest rate at year-end	1.20		%	1.16		%	1.18		%
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 provisions including a financial ratio that requires the Company to maintain an interest coverage ratio of not less than 1.5 to 1.

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Short-Term Debt (Tables)

12 Months Ended

Sep. 30, 2015

Short-term Debt [Abstract]

Summary of Available Limits Under Line of Credit Agreement

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

Effective	Available Line-of-Credit
September 30, 2015	$	24,000,000
March 1, 2016	17,000,000

Summary of Line of Credit

A summary of the line-of-credit follows:

	September 30
	2015			2014			2013
Line-of-credit at year-end	$	24,000,000		$	15,000,000		$	5,000,000
Outstanding balance at year-end	9,340,997			9,045,050			—
Highest month-end balance outstanding	17,366,052			9,045,050			1,414,955
Average daily balance	6,377,040			1,340,833			80,593
Average rate of interest during year on outstanding balances	1.17		%	1.16		%	1.21		%
Interest rate at year-end	1.20		%	1.16		%	1.18		%
Interest rate on unused line-of-credit	0.15		%	0.15		%	0.15		%

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Quarterly Financial Information (Unaudited)

12 Months Ended

Sep. 30, 2015

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Information (Unaudited)

QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Quarterly financial data for the years ended September 30, 2015 and 2014 is summarized as follows:

2015	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Operating revenues	$	21,250,065	$	26,431,729	$	10,774,409	$	9,733,404
Gross margin	$	8,622,143	$	10,213,770	$	5,961,828	$	5,408,692
Operating income	$	3,514,352	$	4,879,469	$	956,219	$	656,152
Net income	$	1,924,376	$	2,779,344	$	354,940	$	35,755
Earnings per share of common stock:
Basic	$	0.41	$	0.59	$	0.08	$	0.01
Diluted	$	0.41	$	0.59	$	0.07	$	0.01

2014	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Operating revenues	$	20,011,194	$	32,699,965	$	12,024,817	$	10,280,158
Gross margin	$	8,202,992	$	10,161,125	$	5,721,551	$	5,251,421
Operating income	$	3,272,646	$	5,121,022	$	940,691	$	347,509
Net income (loss)	$	1,722,788	$	2,846,795	$	283,194	$	(144,337	)
Earnings per share of common stock:
Basic	$	0.37	$	0.60	$	0.06	$	(0.03	)
Diluted	$	0.37	$	0.60	$	0.06	$	(0.03	)

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Common Stock Options

12 Months Ended

Sep. 30, 2015

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, 2015, the number of shares available for future grants was 49,000.

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 2015, 2014 and 2013, 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.

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,
	2015	2014	2013
Expected volatility	34.34%	35.01%	34.75%
Expected dividends	4.11%	4.21%	4.32%
Expected exercise term (years)	7.00	7.00	7.00
Risk-free interest rate	1.98%	2.23%	1.23%

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.

No forfeitures are assumed to occur.

Stock option transactions under the Company's plans for the years ended September 30, 2015, 2014 and 2013 are summarized below:

	Number of Shares		Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Terms (years)	Aggregate Intrinsic Value 1
Options outstanding, September 30, 2012	—		$	—	0.0	$	—
Options granted	21,000		19.01
Options exercised	—		—
Options expired	—		—
Options forfeited	—		—
Options outstanding, September 30, 2013	21,000		19.01		9.5	5,229
Options granted	17,000		18.95
Options exercised	—		—
Options expired	—		—
Options forfeited	—		—
Options outstanding, September 30, 2014	38,000		18.98		8.8	34,840
Options granted	17,000		21.60
Options exercised	(2,600	)	18.99
Options expired	—		—
Options forfeited	—		—
Options outstanding, September 30, 2015	52,400		$	19.83	8.3	$	43,086
Vested and exercisable at September 30, 2015	52,400		$	19.83	8.3	$	43,086

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

The weighted-average grant-date fair value of options granted during the years ended September 30, 2015, 2014 and 2013 was $4.92, $4.43 and $4.04, respectively. The intrinsic value of the options exercised during fiscal 2015 was $5,624. The Company recognized $83,640, $75,310 and $84,840 in stock option expense in fiscal 2015, 2014 and 2013, respectively.

The Company received $49,366 from the exercise of options in 2015. No options were exercised in 2013 or 2014.

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Common Stock Options (Narrative) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Number of shares available for future grant	49,000
Award vesting period	6 months
Award expiration period	10 years
Weighted average grant-date fair value, options granted (in usd per share)	$ 4.92	$ 4.43	$ 4.04
Intrinsic value of options exercised	$ 5,624
Stock option grants	83,640	$ 75,310	$ 84,840
Amount received for exercise of options	$ 49,366	$ 0	$ 0

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Income Taxes

12 Months Ended

Sep. 30, 2015

Income Tax Disclosure [Abstract]

Income Taxes

INCOME TAXES

The details of income tax expense are as follows:

	Years Ended September 30
	2015		2014			2013
Current income taxes:
Federal	$	379,180	$	1,789,294		$	1,404,450
State	374,541		290,458			453,347
Total current income taxes	753,721		2,079,752			1,857,797
Deferred income taxes:
Federal	2,289,729		687,417			829,080
State	127,112		175,464			(33,051		)
Total deferred income taxes	2,416,841		862,881			796,029
Amortization of investment tax credits	—		(3,093		)	(9,039		)
Total income tax expense	$	3,170,562	$	2,939,540		$	2,644,787

Income tax expense for the years ended September 30, 2015, 2014 and 2013 differed from amounts computed by applying the U.S. Federal income tax rate of 34% to earnings before income taxes due to the following:

	Years Ended September 30
	2015		2014			2013
Income before income taxes	$	8,264,977	$	7,647,980		$	6,906,839
Income tax expense computed at the federal statutory rate	$	2,810,092	$	2,600,313		$	2,348,325
State income taxes, net of federal income tax benefit	331,091		307,509			277,395
Amortization of investment tax credits	—		(3,093		)	(9,039		)
Other, net	29,379		34,811			28,106
Total income tax expense	$	3,170,562	$	2,939,540		$	2,644,787

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

	September 30
	2015		2014
Deferred tax assets:
Allowance for uncollectibles	$	20,012	$	26,855
Accrued pension and postretirement medical benefits	2,502,774		2,077,409
Accrued vacation	249,837		230,842
Over-recovery of gas costs	721,782		—
Costs of gas held in storage	930,524		973,651
Accrued gas costs	—		36,305
Deferred compensation	651,336		579,451
Other	265,951		295,654
Total gross deferred tax assets	5,342,216		4,220,167
Deferred tax liabilities:
Utility plant	19,804,862		17,057,847
Under-recovery of gas costs	—		68,643
Accrued gas costs	157,385		—
Total gross deferred tax liabilities	19,962,247		17,126,490
Net deferred tax liability	$	14,620,031	$	12,906,323

Deferred Income Tax - Balance Sheet	September 30
	2015		2014
Deferred income taxes (net current assets)	$	2,293,536	$	1,704,320
Deferred income taxes (net non-current liabilities)	16,913,567		14,610,643
Net deferred tax liability	$	14,620,031	$	12,906,323

Current federal tax expense for fiscal 2015 reflected the effect of 50% bonus depreciation for the entire calendar year of 2014, which included nine months of the prior fiscal year. The extension of bonus depreciation for 2014 was signed into law subsequent to the issuance of the Company's financial statements for the year ended September 30, 2014. As a result, $1,442,211 of deferred taxes that related to the prior year were reflected in the current year tax provision, thereby reducing the current tax expense by the same amount. Total income tax expense was not impacted by the classification change between current and deferred income taxes.

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, 2012 are no longer subject to examination.

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Employee Benefit Plans

12 Months Ended

Sep. 30, 2015

Compensation and Retirement Disclosure [Abstract]

Employee Benefit Plans

EMPLOYEE BENEFIT PLANS

The Company sponsors both a noncontributory defined benefit pension plan and a postretirement benefit plan (“Plans”). The defined benefit 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. The postretirement benefit plan provides certain healthcare, 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 its statement 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
	2015			2014			2015			2014
Accumulated benefit obligation	$	22,853,206		$	20,697,734		$	15,355,668		$	14,983,169
Change in benefit obligation:
Benefit obligation at beginning of year	$	24,636,695		$	21,468,769		$	14,983,169		$	13,028,628
Service cost	654,782			553,291			167,580			168,634
Interest cost	1,025,908			1,020,302			600,096			602,684
Actuarial loss	1,487,278			2,199,697			70,196			1,673,552
Benefit payments, net of retiree contributions	(637,042		)	(605,364		)	(465,373		)	(490,329		)
Benefit obligation at end of year	$	27,167,621		$	24,636,695		$	15,355,668		$	14,983,169
Change in fair value of plan assets:
Fair value of plan assets at beginning of year	$	20,514,179		$	18,801,262		$	10,646,249		$	10,114,062
Actual return on plan assets, net of taxes	(182,738		)	1,750,033			(237,247		)	522,516
Employer contributions	1,700,000			568,248			500,000			500,000
Benefit payments, net of retiree contributions	(637,042		)	(605,364		)	(465,373		)	(490,329		)
Fair value of plan assets at end of year	$	21,394,399		$	20,514,179		$	10,443,629		$	10,646,249
Funded status	$	(5,773,222	)	$	(4,122,516	)	$	(4,912,039	)	$	(4,336,920	)
Amounts recognized in the balance sheets consist of:
Noncurrent liabilities	$	(5,773,222	)	$	(4,122,516	)	$	(4,912,039	)	$	(4,336,920	)
Amounts recognized in accumulated other comprehensive loss:
Transition obligation, net of tax	$	—		$	—		$	—		$	—
Net actuarial loss, net of tax	1,694,924			616,352			591,621			522,974
Total amounts included in other comprehensive loss, net of tax	$	1,694,924		$	616,352		$	591,621		$	522,974
Amounts deferred to a regulatory asset:
Transition obligation	$	—		$	—		$	—		$	—
Net actuarial loss	5,280,756			4,166,900			3,628,448			3,112,127
Amounts recognized as regulatory assets	$	5,280,756		$	4,166,900		$	3,628,448		$	3,112,127

Effective with the valuation of the September 30, 2015 defined benefit obligations, the Company adopted the new RP-2014 Mortality Tables as issued by the Society of Actuaries in late 2014. The adoption of the new tables, which reflected an increase in assumed life expectancy, increased the September 30, 2015 pension liability by an estimated $1,300,000 and the postretirement liability by an estimated $1,000,000.

The Company expects that approximately $221,000 before tax, of accumulated other comprehensive loss will be recognized as a portion of net periodic benefit costs in fiscal 2016 and approximately $531,000 of amounts deferred as regulatory assets will be amortized and recognized in net periodic benefit costs in fiscal 2016.

The Company amortized the unrecognized transition obligation over 20 years ending in June 2013.

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 2015, 2014 and 2013.

	Pension Plan						Postretirement Plan
	2015		2014		2013		2015		2014		2013
Assumptions used to determine benefit obligations:
Discount rate	4.22	%	4.22	%	4.82	%	4.15	%	4.10	%	4.73	%
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	4.22	%	4.82	%	4.06	%	4.10	%	4.73	%	3.95	%
Expected long-term rate of return on plan assets	7.00	%	7.00	%	7.25	%	4.90	%	4.92	%	5.11	%
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
	2015			2014			2013			2015			2014			2013
Service cost	$	654,782		$	553,291		$	634,892		$	167,580		$	168,634		$	213,131
Interest cost	1,025,908			1,020,302			946,247			600,096			602,684			531,845
Expected return on plan assets	(1,440,846		)	(1,312,354		)	(1,184,787		)	(516,656		)	(496,476		)	(452,383		)
Amortization of unrecognized transition obligation	—			—			—			—			—			141,671
Recognized loss	257,378			136,394			578,263			197,058			89,515			241,747
Net periodic benefit cost	$	497,222		$	397,633		$	974,615		$	448,078		$	364,357		$	676,011

The assumed health care cost trend rates used in measuring the accumulated benefit obligation for the postretirement medical plan as of September 30, 2015, 2014 and 2013 are presented below:

	Pre 65						Post 65
	2015		2014		2013		2015		2014		2013
Health care cost trend rate assumed for next year	8.00	%	8.50	%	9.00	%	5.00	%	5.00	%	5.00	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	5.00	%	5.00	%	5.00	%	5.00	%	5.00	%	5.00	%
Year that the rate reaches the ultimate trend rate	2021		2021		2021		2015		2014		2013

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	$	137,000	$	(109,000	)
Effect on accumulated postretirement benefit obligation	2,383,000		(1,938,000		)

The primary objectives of the Plan’s investment policy 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. The investment policy provides for a range of investment allocations to allow for flexibility in responding to market conditions. The investment policy is periodically reviewed by the Company and a third-party fiduciary for investment matters.

The Company’s target and actual asset allocation in the pension and postretirement benefit plans as of September 30, 2015 and 2014 were:

	Pension Plan						Postretirement Plan
	Target		2015		2014		Target		2015		2014
Asset category:
Equity securities	60	%	64	%	60	%	50	%	52	%	55	%
Debt securities	40	%	35	%	39	%	50	%	47	%	44	%
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 all 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, 2015
	Fair Value		Level 1		Level 2		Level 3
Asset Class:
Cash	$	106,502	$	106,502	$	—	$	—
Common and Collective Trust and Pooled Funds:
Bonds
Domestic Fixed Income	3,996,246		—		3,996,246		—
Equities
Domestic Large Cap Growth	3,150,561		—		3,150,561		—
Domestic Large Cap Value	4,183,172		—		4,183,172		—
Domestic Small/Mid Cap Core	1,937,613		—		1,937,613		—
Foreign Large Cap Value	1,873,313		—		1,873,313		—
Mutual Funds:
Bonds
Domestic Fixed Income	3,313,331		—		3,313,331		—
Foreign Fixed Income	213,118		—		213,118		—
Equities
Domestic Large Cap Growth	1,030,957		—		1,030,957		—
Foreign Large Cap Value	653,276		—		653,276		—
Foreign Large Cap Core	936,310		—		936,310		—
Total	$	21,394,399	$	106,502	$	21,287,897	$	—

			Defined Benefit Pension Plan Fair Value Measurements - September 30, 2014
	Fair Value		Level 1		Level 2		Level 3
Asset Class:
Cash	$	182,644	$	182,644	$	—	$	—
Common and Collective Trust and Pooled Funds:
Bonds
Domestic Fixed Income	1,455,153		—		1,455,153		—
Equities
Domestic Large Cap Growth	2,079,566		—		2,079,566		—
Domestic Large Cap Value	3,295,144		—		3,295,144		—
Domestic Small/Mid Cap Core	1,850,340		—		1,850,340		—
Foreign Large Cap Value	1,641,619		—		1,641,619		—
Mutual Funds:
Bonds
Domestic Fixed Income	6,289,437		—		6,289,437		—
Foreign Fixed Income	204,747		—		204,747		—
Equities
Domestic Large Cap Growth	2,088,528		—		2,088,528		—
Foreign Large Cap Value	608,787		—		608,787		—
Foreign Large Cap Core	818,214		—		818,214		—
Total	$	20,514,179	$	182,644	$	20,331,535	$	—

			Postretirement Benefit Plan Fair Value Measurements - September 30, 2015
	Fair Value		Level 1		Level 2		Level 3
Asset Class:
Cash	$	58,749	$	58,749	$	—	$	—
Mutual Funds
Bonds
Domestic Fixed Income	4,845,174		—		4,845,174		—
Foreign Fixed Income	38,654		—		38,654		—
Equities
Domestic Large Cap Growth	1,746,621		—		1,746,621		—
Domestic Large Cap Value	1,638,695		—		1,638,695		—
Domestic Small/Mid Cap Growth	194,260		—		194,260		—
Domestic Small/Mid Cap Value	186,344		—		186,344		—
Domestic Small/Mid Cap Core	417,980		—		417,980		—
Foreign Large Cap Value	893,115		—		893,115		—
Foreign Large Cap Core	378,596		—		378,596		—
Other	45,441		—		45,441		—
Total	$	10,443,629	$	58,749	$	10,384,880	$	—

			Postretirement Benefit Plan Fair Value Measurements - September 30, 2014
	Fair Value		Level 1		Level 2		Level 3
Asset Class:
Cash	$	116,173	$	116,173	$	—	$	—
Mutual Funds
Bonds
Domestic Fixed Income	4,658,299		—		4,658,299		—
Foreign Fixed Income	101,904		—		101,904		—
Equities
Domestic Large Cap Growth	1,789,381		—		1,789,381		—
Domestic Large Cap Value	1,759,740		—		1,759,740		—
Domestic Small/Mid Cap Growth	400,898		—		400,898		—
Domestic Small/Mid Cap Value	396,537		—		396,537		—
Domestic Small/Mid Cap Core	37,741		—		37,741		—
Foreign Large Cap Value	941,153		—		941,153		—
Foreign Large Cap Core	394,769		—		394,769		—
Other	49,654		—		49,654		—
Total	$	10,646,249	$	116,173	$	10,530,076	$	—

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

The Company expects to contribute $500,000 to its pension plan and $500,000 to its postretirement benefit plan in fiscal 2016.

The following table reflects expected future benefit payments:

Fiscal year ending September 30	Pension Plan		Postretirement Plan
2016	$	655,968	$	617,386
2017	698,403		625,167
2018	773,580		634,509
2019	818,585		655,095
2020	944,944		695,924
2021-2025	6,531,464		4,012,407

The Company also sponsors a defined contribution plan (“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 $338,896, $330,241 and $306,382 for 2015, 2014 and 2013, respectively.

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Other Stock Plans

12 Months Ended

Sep. 30, 2015

Other Stock Plans [Abstract]

Other Stock Plans

OTHER STOCK PLANS

Dividend Reinvestment and Stock Purchase Plan

The Company offers a Dividend Reinvestment and Stock Purchase Plan (“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 plan, the Company issued 8,431, 7 and 24,905 shares in 2015, 2014 and 2013, respectively. As of September 30, 2015, the Company had 358,377 shares of stock available for issuance under the DRIP Plan.

Restricted Stock Plan

The Board of Directors of the Company implemented the Restricted Stock Plan for Outside Directors (“Plan”) effective January 27, 1997. Under the Plan, a minimum of 40% of the monthly retainer fee paid to each non-employee director of Resources is paid in shares of common stock (“Restricted Stock”). The number of shares of Restricted Stock is calculated each month based on the closing sales price of Resources' common stock on the NASDAQ Global Market on the first business day of the month. The Restricted Stock issued under this 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 Restricted Stock may not be sold, transferred, assigned or pledged by the participant until the shares have vested under the terms of this Plan. The shares of 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 Restricted Stock Plan:

	2015			2014			2013
	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	62,844	$	14.29	59,064	$	13.97	54,011	$	13.51
Granted	4,071	20.88		3,780	19.37		5,053	18.93
Vested	—	—		—	—		—	—
Forfeited	—	—		—	—		—	—
End of year balance	66,915	$	14.70	62,844	$	14.29	59,064	$	13.97

The fair market value of the Restricted Stock issued as compensation during fiscal 2015, 2014 and 2013 was $85,000, $73,200 and $95,667. No Restricted Stock vested or was forfeited during fiscal 2015, 2014 and 2013.

As of September 30, 2015, the Company had 70,960 shares available for issuance under the Restricted Stock Plan.

Stock Bonus Plan

Under the Stock Bonus Plan, executive officers are encouraged to own a position in the Company’s common stock of at least 50% of the value of their annual salary. To promote this policy, the Plan provides that all officers with stock ownership positions below 50% of the value of their annual salaries must, unless approved by the Committee, receive no less than 50% of any performance bonus in the form of Company common stock. Shares from the Stock Bonus Plan may also be issued to certain employees and management personnel in recognition of their performance and service. Under the Stock Bonus Plan, the Company issued 2,731, 4,098 and 4,022 shares valued at $59,332, $78,841 and $72,580, respectively, in 2015, 2014 and 2013. As of September 30, 2015 the Company had 8,174 shares of stock available for issuance under the Stock Bonus Plan.

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Other Stock Plans (Director Compensation Activity) (Details) - Restricted Stock Plan [Member] - $ / shares	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Shares
Beginning of year balance (in shares)	62,844	59,064	54,011
Granted (in shares)	4,071	3,780	5,053
Vested (in shares)	0	0	0
Forfeited (in shares)	0	0	0
End of year balance (in shares)	66,915	62,844	59,064
Weighted-Average Fair Value on Date of Grant
Beginning of year balance (in usd per share)	$ 14.29	$ 13.97	$ 13.51
Granted (in usd per share)	20.88	19.37	18.93
Vested (in usd per share)	0.00	0.00	0.00
Forfeited (in usd per share)	0.00	0.00	0.00
End of year balance (in usd per share)	$ 14.70	$ 14.29	$ 13.97

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Commitments and Contingencies (Schedule of Volumetric Obligations) (Details)	Sep. 30, 2015 MMBTU
Commitments and Contingencies Disclosure [Abstract]
2015-2016	2,071,061
2016-2017	295,866
Total	2,366,927

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Other Stock Plans (Narrative) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares available for issuance	49,000
Dividend Reinvestment and Stock Purchase Plan [Member]
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	8,431	7	24,905
Shares of stock available for issuance under the DRIP Plan	358,377
Restricted Stock Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Minimum percentage of monthly retainer fee paid in shares of common stock	40.00%
Value of shares issued under the plan	$ 85,000	$ 73,200	$ 95,667
Stock vested during the period (in shares)	0	0	0
Stock forfeited during the period (in shares)	0	0	0
Shares available for issuance	70,960
Stock Bonus Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Value of shares issued under the plan	$ 59,332	$ 78,841	$ 72,580
Shares available for issuance	8,174
Percentage of officers' annually salary expected to be held in company stock	50.00%
Minimum percentage of performance bonus in stock	50.00%
Shares issued under the plan	2,731	4,098	4,022
Stock Bonus Plan [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of officers' annually salary expected to be held in company stock	50.00%

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Summary of Significant Accounting Policies (Components of Utility Plant) (Details) - USD ($)	Sep. 30, 2015	Sep. 30, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Distribution and transmission	$ 143,172,628	$ 134,439,225
LNG Storage	12,501,179	9,163,158
General and miscellaneous	12,359,225	11,757,817
Total utility plant in service	$ 168,033,032	$ 155,360,200

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Employee Benefit Plans (Narrative) (Details) - USD ($)	9 Months Ended	12 Months Ended
	Jun. 30, 2013	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Defined Benefit Plan Disclosure [Line Items]
Expected amount of accumulated other comprehensive loss recognized in net periodic benefit costs		$ 221,000
Expected amount of deferred regulatory assets to be recognized in net periodic benefit costs		$ 531,000
Unrecognized transition obligation amortization period	20 years
Minimum employee contribution percent		1.00%
Maximum employee contribution percent		50.00%
Company's matching contribution		$ 338,896	$ 330,241	$ 306,382
After April 2010 [Member] | First Portion Match [Member]
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%
After April 2010 [Member] | Second Portion Match [Member]
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%
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan Benefit Obligation Increase Decrease Related To Mortality Table Change		$ 1,300,000
Years until benefits are fully vested		5 years
Expected employer contributions in next fiscal year		$ 500,000
Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan Benefit Obligation Increase Decrease Related To Mortality Table Change		$ 1,000,000
Minimum service requirement for postretirement benefit vesting		10 years
Retirement age requirement, postretirement plan		55 years
Expected employer contributions in next fiscal year		$ 500,000

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Summary of Significant Accounting Policies (Policy)

12 Months Ended

Sep. 30, 2015

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Principles of Consolidation

Principles of Consolidation—RGC Resources, Inc. is an energy services company 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; RGC Ventures of Virginia, Inc., operating as Application Resources and The Utility Consultants; and RGC Midstream, LLC. Roanoke Gas is a natural gas utility, which distributes and sells natural gas to approximately 59,100 residential, commercial and industrial customers within its service areas in Roanoke, Virginia and the surrounding localities. The Company’s business is seasonal in nature and weather dependent 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”). Application Resources provides information system services to software providers in the utility industry. The Utility Consultants, which provided regulatory consulting services to other utilities, ceased operations in 2015. RGC Midstream, LLC is a new wholly-owned subsidiary created in 2015 to invest in a pipeline project. More information is provided in Note 12. Diversified Energy Company is currently inactive.

The Company follows accounting and reporting standards set 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.

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. The cost of additions to utility plant includes direct charges and overhead. The cost of depreciable property retired is 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. Maintenance, repairs, and minor renewals and betterments of property are charged to operations and maintenance.

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

	Years Ended September 30
	2015		2014
Distribution and transmission	$	143,172,628	$	134,439,225
LNG storage	12,501,179		9,163,158
General and miscellaneous	12,359,225		11,757,817
Total utility plant in service	$	168,033,032	$	155,360,200

Provisions for depreciation are computed principally at composite straight-line rates as determined by depreciation studies required to be performed on the regulated utility assets of Roanoke Gas Company at least every five years. The Company completed its most recent depreciation study in June 2014. The composite weighted-average depreciation rates provided for under the new depreciation study were 3.25% for the fiscal years ended September 30, 2015 and 2014 compared to 3.35% for the fiscal year ended September 30, 2013 under the prior rates. For the year ended September 30, 2014, the implementation of the new depreciation rates reduced depreciation expense by $126,875 and increased net income by $78,713 and earnings per share by $0.02.

The composite rates are comprised 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 evacuating 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 2015, 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, 2015, 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 are the Company's one primary type of financing receivables, resulting from the sale of natural gas and other services to its customers. These receivable are short-term in nature with a provision for uncollectible balances included in the financial statements.

Inventories

Inventories—Inventories, consisting of natural gas in storage and materials and supplies, are recorded at average cost. Injections into storage are priced at the purchase cost at the time of injection and withdrawals from storage are priced at the weighted average price 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 amortized over the lives of the debt instruments.

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 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 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 6 and 10.

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, 2016. 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 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. hedges 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, 2015 and 2014, the Company had no outstanding derivative instruments for the purchase of natural gas.

The Company also had two interest rate swaps that essentially converted its variable interest rate notes to fixed rate debt instruments. Both swaps were terminated in September 2014 as part of the Company's debt refinancing. These swaps qualified as cash flow hedges with changes in fair value reported in other comprehensive income.

No derivative instruments were deemed to be ineffective for any period presented.

Other Comprehensive Income (Loss)

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, 2015:
Defined benefit plans:
Net loss arising during period	$	(1,910,573	)	$	726,017		$	(1,184,556	)
Amortization of actuarial losses	60,221			(22,884		)	37,337
Other comprehensive loss	$	(1,850,352	)	$	703,133		$	(1,147,219	)
Year Ended September 30, 2014:
Interest rate swaps:
Unrealized losses	$	(58,800	)	$	22,321		$	(36,479	)
Transfer of realized losses to interest expense	926,262			(351,609		)	574,653
Transfer of realized losses to regulatory asset	1,119,233			(424,861		)	694,372
Net interest rate swaps	1,986,695			(754,149		)	1,232,546
Defined benefit plans:
Net loss arising during period	(397,714		)	151,131			(246,583		)
Amortization of actuarial losses	41,846			(15,901		)	25,945
Net defined benefit plans	(355,868		)	135,230			(220,638		)
Other comprehensive income	$	1,630,827		$	(618,919	)	$	1,011,908
Year Ended September 30, 2013:
Interest rate swaps:
Unrealized losses	$	(20,479	)	$	7,774		$	(12,705	)
Transfer of realized losses to interest expense	950,501			(360,811		)	589,690
Net interest rate swaps	930,022			(353,037		)	576,985
Defined benefit plans:
Net gain arising during period	1,714,890			(651,659		)	1,063,231
Amortization of actuarial losses	219,890			(83,558		)	136,332
Amortization of transition obligation	35,972			(13,669		)	22,303
Net defined benefit plans	1,970,752			(748,886		)	1,221,866
Other comprehensive income	$	2,900,774		$	(1,101,923	)	$	1,798,851

The amortization of actuarial losses and transition obligation is included as components of net periodic pension and postretirement benefit costs and is included 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, 2012	$	(1,809,531	)	$	(2,140,554	)	$	(3,950,085	)
Other comprehensive income (loss)	576,985			1,221,866			1,798,851
Balance September 30, 2013	(1,232,546		)	(918,688		)	(2,151,234		)
Other comprehensive income (loss)	1,232,546			(220,638		)	1,011,908
Balance September 30, 2014	—			(1,139,326		)	(1,139,326		)
Other comprehensive income (loss)	—			(1,147,219		)	(1,147,219		)
Balance September 30, 2015	$	—		$	(2,286,545	)	$	(2,286,545	)

Change in Method of Accounting for Long-term Debt

Change in Method of Accounting for Long-term Debt—During the fiscal year ended September 30, 2015, the Company adopted the provisions of ASU 2015-03 as described further under the Recently Adopted Accounting Standards section below. Under ASU 2015-03, the unamortized balance of debt issuance costs are reclassified from assets to liabilities and netted against the carrying value of long-term debt. The change had no impact on net income.

Management retrospectively applied the change. The carrying value of long-term debt and the reclassified debt issuance costs are presented separately on the Company’s Consolidated Balance Sheets and in Note 4 for the periods ended September 30, 2015 and 2014.

Recently Adopted Accounting Standards

Recently Adopted Accounting Standards—In June 2011, the FASB issued guidance under FASB ASC No. 220 - Comprehensive Income that defines the presentation of Comprehensive Income in the financial statements. According to the guidance, an entity may present a single continuous statement of comprehensive income or two separate statements - a statement of income and a statement of other comprehensive income that immediately follows the statement of income. In either presentation, the entity is required to present on the face of the financial statement the components of other comprehensive income including the reclassification adjustment for items that are reclassified from other comprehensive income to net income. In December 2011, the FASB issued additional guidance under FASB ASC No. 220 that deferred the effective date of earlier guidance with regard to the presentation of reclassifications of items out of accumulated other comprehensive income. All other provisions of the original guidance remain in effect. In February 2013, the FASB issued additional guidance regarding the reporting of amounts reclassified out of accumulated other comprehensive income. Under the new provisions, an entity must present the effects on the line items of net income of significant amounts reclassified out of accumulated other comprehensive income. The disclosures required under this guidance are provided above.

In April 2015, the FASB issued ASU 2015-03, Interest-Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs. This ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. The Company previously recognized debt issuance costs in assets and amortized those costs over the term of the debt. This guidance is effective for the Company for the annual reporting period ending September 30, 2017 and interim periods within that annual period. Early application is permitted. The Company adopted the ASU during the current reporting period. The adoption of this ASU did not have an effect on the Company's results of operations or cash flows; however, the unamortized balance of debt issuance costs were reclassified from assets to an offset against long-term debt. Certain deferred costs related to the early retirement of debt in 2014 are classified as regulatory assets and are not offset against debt. The changes required under this guidance are presented in Note 1, Note 4 and the Consolidated Balance Sheets.

Recently Issued Accounting Standards

Recently Issued Accounting Standards—In May 2014, the FASB issued guidance under FASB ASC No. 606 - Revenue from Contracts with Customers 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 these 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 Accounting Standards Update (ASU) 2015-14 that deferred the effective date of this guidance by one year. Therefore, the new guidance is effective for the Company for the annual reporting period ended September 30, 2019 and interim periods within that annual period. Early application is not permitted. Management has not completed its evaluation of the new guidance; however, the Company does not currently expect it 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.

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Employee Benefit Plans (Tables)

12 Months Ended

Sep. 30, 2015

Compensation and Retirement Disclosure [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
	2015			2014			2015			2014
Accumulated benefit obligation	$	22,853,206		$	20,697,734		$	15,355,668		$	14,983,169
Change in benefit obligation:
Benefit obligation at beginning of year	$	24,636,695		$	21,468,769		$	14,983,169		$	13,028,628
Service cost	654,782			553,291			167,580			168,634
Interest cost	1,025,908			1,020,302			600,096			602,684
Actuarial loss	1,487,278			2,199,697			70,196			1,673,552
Benefit payments, net of retiree contributions	(637,042		)	(605,364		)	(465,373		)	(490,329		)
Benefit obligation at end of year	$	27,167,621		$	24,636,695		$	15,355,668		$	14,983,169
Change in fair value of plan assets:
Fair value of plan assets at beginning of year	$	20,514,179		$	18,801,262		$	10,646,249		$	10,114,062
Actual return on plan assets, net of taxes	(182,738		)	1,750,033			(237,247		)	522,516
Employer contributions	1,700,000			568,248			500,000			500,000
Benefit payments, net of retiree contributions	(637,042		)	(605,364		)	(465,373		)	(490,329		)
Fair value of plan assets at end of year	$	21,394,399		$	20,514,179		$	10,443,629		$	10,646,249
Funded status	$	(5,773,222	)	$	(4,122,516	)	$	(4,912,039	)	$	(4,336,920	)
Amounts recognized in the balance sheets consist of:
Noncurrent liabilities	$	(5,773,222	)	$	(4,122,516	)	$	(4,912,039	)	$	(4,336,920	)
Amounts recognized in accumulated other comprehensive loss:
Transition obligation, net of tax	$	—		$	—		$	—		$	—
Net actuarial loss, net of tax	1,694,924			616,352			591,621			522,974
Total amounts included in other comprehensive loss, net of tax	$	1,694,924		$	616,352		$	591,621		$	522,974
Amounts deferred to a regulatory asset:
Transition obligation	$	—		$	—		$	—		$	—
Net actuarial loss	5,280,756			4,166,900			3,628,448			3,112,127
Amounts recognized as regulatory assets	$	5,280,756		$	4,166,900		$	3,628,448		$	3,112,127

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 2015, 2014 and 2013.

	Pension Plan						Postretirement Plan
	2015		2014		2013		2015		2014		2013
Assumptions used to determine benefit obligations:
Discount rate	4.22	%	4.22	%	4.82	%	4.15	%	4.10	%	4.73	%
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	4.22	%	4.82	%	4.06	%	4.10	%	4.73	%	3.95	%
Expected long-term rate of return on plan assets	7.00	%	7.00	%	7.25	%	4.90	%	4.92	%	5.11	%
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
	2015			2014			2013			2015			2014			2013
Service cost	$	654,782		$	553,291		$	634,892		$	167,580		$	168,634		$	213,131
Interest cost	1,025,908			1,020,302			946,247			600,096			602,684			531,845
Expected return on plan assets	(1,440,846		)	(1,312,354		)	(1,184,787		)	(516,656		)	(496,476		)	(452,383		)
Amortization of unrecognized transition obligation	—			—			—			—			—			141,671
Recognized loss	257,378			136,394			578,263			197,058			89,515			241,747
Net periodic benefit cost	$	497,222		$	397,633		$	974,615		$	448,078		$	364,357		$	676,011

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, 2015, 2014 and 2013 are presented below:

	Pre 65						Post 65
	2015		2014		2013		2015		2014		2013
Health care cost trend rate assumed for next year	8.00	%	8.50	%	9.00	%	5.00	%	5.00	%	5.00	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	5.00	%	5.00	%	5.00	%	5.00	%	5.00	%	5.00	%
Year that the rate reaches the ultimate trend rate	2021		2021		2021		2015		2014		2013

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	$	137,000	$	(109,000	)
Effect on accumulated postretirement benefit obligation	2,383,000		(1,938,000		)

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, 2015 and 2014 were:

	Pension Plan						Postretirement Plan
	Target		2015		2014		Target		2015		2014
Asset category:
Equity securities	60	%	64	%	60	%	50	%	52	%	55	%
Debt securities	40	%	35	%	39	%	50	%	47	%	44	%
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, 2015
	Fair Value		Level 1		Level 2		Level 3
Asset Class:
Cash	$	106,502	$	106,502	$	—	$	—
Common and Collective Trust and Pooled Funds:
Bonds
Domestic Fixed Income	3,996,246		—		3,996,246		—
Equities
Domestic Large Cap Growth	3,150,561		—		3,150,561		—
Domestic Large Cap Value	4,183,172		—		4,183,172		—
Domestic Small/Mid Cap Core	1,937,613		—		1,937,613		—
Foreign Large Cap Value	1,873,313		—		1,873,313		—
Mutual Funds:
Bonds
Domestic Fixed Income	3,313,331		—		3,313,331		—
Foreign Fixed Income	213,118		—		213,118		—
Equities
Domestic Large Cap Growth	1,030,957		—		1,030,957		—
Foreign Large Cap Value	653,276		—		653,276		—
Foreign Large Cap Core	936,310		—		936,310		—
Total	$	21,394,399	$	106,502	$	21,287,897	$	—

			Defined Benefit Pension Plan Fair Value Measurements - September 30, 2014
	Fair Value		Level 1		Level 2		Level 3
Asset Class:
Cash	$	182,644	$	182,644	$	—	$	—
Common and Collective Trust and Pooled Funds:
Bonds
Domestic Fixed Income	1,455,153		—		1,455,153		—
Equities
Domestic Large Cap Growth	2,079,566		—		2,079,566		—
Domestic Large Cap Value	3,295,144		—		3,295,144		—
Domestic Small/Mid Cap Core	1,850,340		—		1,850,340		—
Foreign Large Cap Value	1,641,619		—		1,641,619		—
Mutual Funds:
Bonds
Domestic Fixed Income	6,289,437		—		6,289,437		—
Foreign Fixed Income	204,747		—		204,747		—
Equities
Domestic Large Cap Growth	2,088,528		—		2,088,528		—
Foreign Large Cap Value	608,787		—		608,787		—
Foreign Large Cap Core	818,214		—		818,214		—
Total	$	20,514,179	$	182,644	$	20,331,535	$	—

			Postretirement Benefit Plan Fair Value Measurements - September 30, 2015
	Fair Value		Level 1		Level 2		Level 3
Asset Class:
Cash	$	58,749	$	58,749	$	—	$	—
Mutual Funds
Bonds
Domestic Fixed Income	4,845,174		—		4,845,174		—
Foreign Fixed Income	38,654		—		38,654		—
Equities
Domestic Large Cap Growth	1,746,621		—		1,746,621		—
Domestic Large Cap Value	1,638,695		—		1,638,695		—
Domestic Small/Mid Cap Growth	194,260		—		194,260		—
Domestic Small/Mid Cap Value	186,344		—		186,344		—
Domestic Small/Mid Cap Core	417,980		—		417,980		—
Foreign Large Cap Value	893,115		—		893,115		—
Foreign Large Cap Core	378,596		—		378,596		—
Other	45,441		—		45,441		—
Total	$	10,443,629	$	58,749	$	10,384,880	$	—

			Postretirement Benefit Plan Fair Value Measurements - September 30, 2014
	Fair Value		Level 1		Level 2		Level 3
Asset Class:
Cash	$	116,173	$	116,173	$	—	$	—
Mutual Funds
Bonds
Domestic Fixed Income	4,658,299		—		4,658,299		—
Foreign Fixed Income	101,904		—		101,904		—
Equities
Domestic Large Cap Growth	1,789,381		—		1,789,381		—
Domestic Large Cap Value	1,759,740		—		1,759,740		—
Domestic Small/Mid Cap Growth	400,898		—		400,898		—
Domestic Small/Mid Cap Value	396,537		—		396,537		—
Domestic Small/Mid Cap Core	37,741		—		37,741		—
Foreign Large Cap Value	941,153		—		941,153		—
Foreign Large Cap Core	394,769		—		394,769		—
Other	49,654		—		49,654		—
Total	$	10,646,249	$	116,173	$	10,530,076	$	—

Schedule of Expected Future Benefit Payments

The following table reflects expected future benefit payments:

Fiscal year ending September 30	Pension Plan		Postretirement Plan
2016	$	655,968	$	617,386
2017	698,403		625,167
2018	773,580		634,509
2019	818,585		655,095
2020	944,944		695,924
2021-2025	6,531,464		4,012,407

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Income Taxes (Reconciliation of Income Tax Expense Based on Federal Statutory Rate) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Income Tax Disclosure [Abstract]
Income before income taxes	$ 8,264,977	$ 7,647,980	$ 6,906,839
Income tax expense computed at the federal statutory rate	2,810,092	2,600,313	2,348,325
State income taxes, net of federal income tax benefit	331,091	307,509	277,395
Amortization of investment tax credits	0	(3,093)	(9,039)
Other, net	29,379	34,811	28,106
Total income tax expense	$ 3,170,562	$ 2,939,540	$ 2,644,787

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Short-Term Debt (Narrative) (Details)	12 Months Ended
	Sep. 30, 2015
Short-term Debt [Abstract]
Expiration date	Mar. 31, 2016
Minimum interest coverage ratio	1.5

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Consolidated Statements of Comprehensive Income - USD ($)	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Statement of Comprehensive Income [Abstract]
NET INCOME	$ 5,094,415	$ 4,708,440	$ 4,262,052
Other comprehensive income, net of tax:
Interest rate swaps	0	1,232,546	576,985
Defined benefit plans	(1,147,219)	(220,638)	1,221,866
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX	(1,147,219)	1,011,908	1,798,851
COMPREHENSIVE INCOME	$ 3,947,196	$ 5,720,348	$ 6,060,903

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Regulatory Matters

12 Months Ended

Sep. 30, 2015

Regulated Operations [Abstract]

Regulatory Matters

REGULATORY MATTERS

The SCC exercises regulatory authority over the natural gas operations of Roanoke Gas Company. Such regulation encompasses terms, conditions and rates to be charged to customers for natural gas service, safety standards, service extension, accounting and depreciation.

On September 25, 2015, the Company received approval of its application for a modification to the SAVE (Steps to Advance Virginia's Energy) Plan and Rider. The original SAVE Plan filed in 2012 has been modified each year to incorporate certain changes and to include new projects that qualify for recovery under the Plan. The SAVE Rider provides a mechanism for the Company to recover the related depreciation and expenses and return on rate base of the additional capital investment without the filing of a formal application for an increase in non-gas base rates.

On June 25, 2014, the SCC approved the Company's application requesting approval to extend its authority to incur short-term indebtedness of up to $30,000,000 and to issue up to $60,000,000 in long-term securities. The short-term indebtedness authority allows the Company to continue to access its line-of-credit to provide seasonal funding of its working capital needs as well as provide temporary bridge financing for its capital expenditures. The authority to issue long-term securities allowed the Company to refinance its higher interest debt in September 2014 and provides the Company with the approval to secure longer term funding for its capital expenditures.

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Employee Benefit Plans (Summary of Fair Value Classifications of Benefit Plan Assets ) (Details) - USD ($)	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Defined Benefit Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 21,394,399	$ 20,514,179	$ 18,801,262
Defined Benefit Pension Plan [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	106,502	182,644
Defined Benefit Pension Plan [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	21,287,897	20,331,535
Defined Benefit Pension Plan [Member] | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	106,502	182,644
Defined Benefit Pension Plan [Member] | Cash [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	106,502	182,644
Defined Benefit Pension Plan [Member] | Cash [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Defined Benefit Pension Plan [Member] | Common and Collective Trust and Pooled Funds [Member] | Domestic Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	3,996,246	1,455,153
Defined Benefit Pension Plan [Member] | Common and Collective Trust and Pooled Funds [Member] | Domestic Fixed Income [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Defined Benefit Pension Plan [Member] | Common and Collective Trust and Pooled Funds [Member] | Domestic Fixed Income [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	3,996,246	1,455,153
Defined Benefit Pension Plan [Member] | Common and Collective Trust and Pooled Funds [Member] | Domestic Large Cap Growth [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	3,150,561	2,079,566
Defined Benefit Pension Plan [Member] | Common and Collective Trust and Pooled Funds [Member] | Domestic Large Cap Growth [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Defined Benefit Pension Plan [Member] | Common and Collective Trust and Pooled Funds [Member] | Domestic Large Cap Growth [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	3,150,561	2,079,566
Defined Benefit Pension Plan [Member] | Common and Collective Trust and Pooled Funds [Member] | Domestic Large Cap Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	4,183,172	3,295,144
Defined Benefit Pension Plan [Member] | Common and Collective Trust and Pooled Funds [Member] | Domestic Large Cap Value [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Defined Benefit Pension Plan [Member] | Common and Collective Trust and Pooled Funds [Member] | Domestic Large Cap Value [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	4,183,172	3,295,144
Defined Benefit Pension Plan [Member] | Common and Collective Trust and Pooled Funds [Member] | Domestic Small/Mid Cap Core [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	1,937,613	1,850,340
Defined Benefit Pension Plan [Member] | Common and Collective Trust and Pooled Funds [Member] | Domestic Small/Mid Cap Core [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Defined Benefit Pension Plan [Member] | Common and Collective Trust and Pooled Funds [Member] | Domestic Small/Mid Cap Core [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	1,937,613	1,850,340
Defined Benefit Pension Plan [Member] | Common and Collective Trust and Pooled Funds [Member] | Foreign Large Cap Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	1,873,313	1,641,619
Defined Benefit Pension Plan [Member] | Common and Collective Trust and Pooled Funds [Member] | Foreign Large Cap Value [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Defined Benefit Pension Plan [Member] | Common and Collective Trust and Pooled Funds [Member] | Foreign Large Cap Value [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	1,873,313	1,641,619
Defined Benefit Pension Plan [Member] | Mutual Funds [Member] | Domestic Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	3,313,331	6,289,437
Defined Benefit Pension Plan [Member] | Mutual Funds [Member] | Domestic Fixed Income [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Defined Benefit Pension Plan [Member] | Mutual Funds [Member] | Domestic Fixed Income [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	3,313,331	6,289,437
Defined Benefit Pension Plan [Member] | Mutual Funds [Member] | Foreign Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	213,118	204,747
Defined Benefit Pension Plan [Member] | Mutual Funds [Member] | Foreign Fixed Income [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Defined Benefit Pension Plan [Member] | Mutual Funds [Member] | Foreign Fixed Income [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	213,118	204,747
Defined Benefit Pension Plan [Member] | Mutual Funds [Member] | Domestic Large Cap Growth [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	1,030,957	2,088,528
Defined Benefit Pension Plan [Member] | Mutual Funds [Member] | Domestic Large Cap Growth [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Defined Benefit Pension Plan [Member] | Mutual Funds [Member] | Domestic Large Cap Growth [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	1,030,957	2,088,528
Defined Benefit Pension Plan [Member] | Mutual Funds [Member] | Foreign Large Cap Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	653,276	608,787
Defined Benefit Pension Plan [Member] | Mutual Funds [Member] | Foreign Large Cap Value [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Defined Benefit Pension Plan [Member] | Mutual Funds [Member] | Foreign Large Cap Value [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	653,276	608,787
Defined Benefit Pension Plan [Member] | Mutual Funds [Member] | Foreign Large Cap Core [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	936,310	818,214
Defined Benefit Pension Plan [Member] | Mutual Funds [Member] | Foreign Large Cap Core [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Defined Benefit Pension Plan [Member] | Mutual Funds [Member] | Foreign Large Cap Core [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	936,310	818,214
Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	10,443,629	10,646,249	$ 10,114,062
Postretirement Benefit Plan [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	58,749	116,173
Postretirement Benefit Plan [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	10,384,880	10,530,076
Postretirement Benefit Plan [Member] | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	58,749	116,173
Postretirement Benefit Plan [Member] | Cash [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	58,749	116,173
Postretirement Benefit Plan [Member] | Cash [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Postretirement Benefit Plan [Member] | Mutual Funds [Member] | Domestic Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	4,845,174	4,658,299
Postretirement Benefit Plan [Member] | Mutual Funds [Member] | Domestic Fixed Income [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Postretirement Benefit Plan [Member] | Mutual Funds [Member] | Domestic Fixed Income [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	4,845,174	4,658,299
Postretirement Benefit Plan [Member] | Mutual Funds [Member] | Foreign Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	38,654	101,904
Postretirement Benefit Plan [Member] | Mutual Funds [Member] | Foreign Fixed Income [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Postretirement Benefit Plan [Member] | Mutual Funds [Member] | Foreign Fixed Income [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	38,654	101,904
Postretirement Benefit Plan [Member] | Mutual Funds [Member] | Domestic Large Cap Growth [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	1,746,621	1,789,381
Postretirement Benefit Plan [Member] | Mutual Funds [Member] | Domestic Large Cap Growth [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Postretirement Benefit Plan [Member] | Mutual Funds [Member] | Domestic Large Cap Growth [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	1,746,621	1,789,381
Postretirement Benefit Plan [Member] | Mutual Funds [Member] | Domestic Large Cap Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	1,638,695	1,759,740
Postretirement Benefit Plan [Member] | Mutual Funds [Member] | Domestic Large Cap Value [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Postretirement Benefit Plan [Member] | Mutual Funds [Member] | Domestic Large Cap Value [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	1,638,695	1,759,740
Postretirement Benefit Plan [Member] | Mutual Funds [Member] | Domestic Small/Mid Cap Growth [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	194,260	400,898
Postretirement Benefit Plan [Member] | Mutual Funds [Member] | Domestic Small/Mid Cap Growth [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Postretirement Benefit Plan [Member] | Mutual Funds [Member] | Domestic Small/Mid Cap Growth [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	194,260	400,898
Postretirement Benefit Plan [Member] | Mutual Funds [Member] | Domestic Small/Mid Cap Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	186,344	396,537
Postretirement Benefit Plan [Member] | Mutual Funds [Member] | Domestic Small/Mid Cap Value [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Postretirement Benefit Plan [Member] | Mutual Funds [Member] | Domestic Small/Mid Cap Value [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	186,344	396,537
Postretirement Benefit Plan [Member] | Mutual Funds [Member] | Domestic Small/Mid Cap Core [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	417,980	37,741
Postretirement Benefit Plan [Member] | Mutual Funds [Member] | Domestic Small/Mid Cap Core [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Postretirement Benefit Plan [Member] | Mutual Funds [Member] | Domestic Small/Mid Cap Core [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	417,980	37,741
Postretirement Benefit Plan [Member] | Mutual Funds [Member] | Foreign Large Cap Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	893,115	941,153
Postretirement Benefit Plan [Member] | Mutual Funds [Member] | Foreign Large Cap Value [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Postretirement Benefit Plan [Member] | Mutual Funds [Member] | Foreign Large Cap Value [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	893,115	941,153
Postretirement Benefit Plan [Member] | Mutual Funds [Member] | Foreign Large Cap Core [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	378,596	394,769
Postretirement Benefit Plan [Member] | Mutual Funds [Member] | Foreign Large Cap Core [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Postretirement Benefit Plan [Member] | Mutual Funds [Member] | Foreign Large Cap Core [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	378,596	394,769
Postretirement Benefit Plan [Member] | Mutual Funds [Member] | Other [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	45,441	49,654
Postretirement Benefit Plan [Member] | Mutual Funds [Member] | Other [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
Postretirement Benefit Plan [Member] | Mutual Funds [Member] | Other [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 45,441	$ 49,654

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Fair Value Measurements (Summary of the Fair Value of Financial Assets and Liabilities Not Adjusted to Fair Value) (Details) - USD ($)	Sep. 30, 2015	Sep. 30, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 30,500,000	$ 30,500,000
Total	30,500,000	30,500,000
Quoted Prices In Active Markets Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	0	0
Total	0	0
Significant Other Observable Inputs Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	0	0
Total	0	0
Significant Unobservable Inputs Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	28,570,585	30,622,664
Total	$ 28,570,585	$ 30,622,664

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Common Stock Options (Tables)

12 Months Ended

Sep. 30, 2015

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,
	2015	2014	2013
Expected volatility	34.34%	35.01%	34.75%
Expected dividends	4.11%	4.21%	4.32%
Expected exercise term (years)	7.00	7.00	7.00
Risk-free interest rate	1.98%	2.23%	1.23%

Schedule of Stock Option Transactions

Stock option transactions under the Company's plans for the years ended September 30, 2015, 2014 and 2013 are summarized below:

	Number of Shares		Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Terms (years)	Aggregate Intrinsic Value 1
Options outstanding, September 30, 2012	—		$	—	0.0	$	—
Options granted	21,000		19.01
Options exercised	—		—
Options expired	—		—
Options forfeited	—		—
Options outstanding, September 30, 2013	21,000		19.01		9.5	5,229
Options granted	17,000		18.95
Options exercised	—		—
Options expired	—		—
Options forfeited	—		—
Options outstanding, September 30, 2014	38,000		18.98		8.8	34,840
Options granted	17,000		21.60
Options exercised	(2,600	)	18.99
Options expired	—		—
Options forfeited	—		—
Options outstanding, September 30, 2015	52,400		$	19.83	8.3	$	43,086
Vested and exercisable at September 30, 2015	52,400		$	19.83	8.3	$	43,086

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

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Summary of Significant Accounting Policies (Summary of Other Comprehensive Income) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Before Tax Amount
Net gain (loss) arising during period	$ (1,910,573)	$ (397,714)	$ 1,714,890
Amortization of actuarial losses	60,221	41,846	219,890
Amortization of transition obligation			35,972
Net defined benefit plans		(355,868)	1,970,752
Unrealized losses		(58,800)	(20,479)
Transfer of realized losses to interest expense		926,262	950,501
Transfer of realized losses to regulatory asset		1,119,233
Net interest rate swaps		1,986,695	930,022
Other comprehensive income (loss)	(1,850,352)	1,630,827	2,900,774
Tax (Expense) or Benefit
Net gain (loss) arising during period	726,017	151,131	(651,659)
Amortization of actuarial losses	(22,884)	(15,901)	(83,558)
Amortization of transition obligation			(13,669)
Net defined benefit plans		135,230	(748,886)
Unrealized losses		22,321	7,774
Transfer of realized losses to interest expense		(351,609)	(360,811)
Transfer of realized losses to regulatory asset		(424,861)
Net interest rate swaps		(754,149)	(353,037)
Other comprehensive income (loss)	703,133	(618,919)	(1,101,923)
Net-of Tax Amount
Net gain (loss) arising during period	(1,184,556)	(246,583)	1,063,231
Amortization of actuarial losses	37,337	25,945	136,332
Amortization of transition obligation			22,303
Net defined benefit plans	(1,147,219)	(220,638)	1,221,866
Unrealized losses		(36,479)	(12,705)
Transfer of realized losses to interest expense		574,653	589,690
Transfer of realized losses to regulatory asset		694,372
Net interest rate swaps	0	1,232,546	576,985
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX	$ (1,147,219)	$ 1,011,908	$ 1,798,851

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Subsequent Events

12 Months Ended

Sep. 30, 2015

Subsequent Events [Abstract]

Subsequent Events

SUBSEQUENT EVENTS

On October 1, 2015, the Company, through its newly formed wholly-owned subsidiary, RGC Midstream, LLC, entered into an agreement to become a 1% member 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. This project, if approved by the Federal Energy Regulatory Commission, will require an estimated $35 million investment by the Company to support the construction of the pipeline over the next 3 years. The projected in service date of the pipeline is late 2018. The Company will participate in the earnings generated from the transportation of natural gas on the pipeline in proportion to its level of investment. The Company will apply the equity method to account for the transactions and activity of the investment.

On October 1, 2015, RGC Midstream borrowed $1,500,000 under a temporary line-of-credit agreement to make its initial investment in the LLC.

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.