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, 2019

Commission file number 000-26591

RGC RESOURCES, INC.

(Exact name of registrant as specified in its charter)

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

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

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

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

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

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

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

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

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

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

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

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

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

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

State the aggregate market value of the voting and non voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity as of the last business day of the registrant’s most recently completed second fiscal quarter: March 31, 2019. $199,858,266

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 22, 2019
COMMON STOCK, $5 PAR VALUE	8,081,123 SHARES

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the RGC Resources, Inc. Proxy Statement for the 2020 Annual Meeting of Shareholders are incorporated by reference into Part III hereof.

TABLE OF CONTENTS
			Page Number
		Glossary		2
		Cautionary Note Regarding Forward Looking Statements		4
PART I
	Item 1.	Business		5
	Item 1A.	Risk Factors		8
	Item 1B.	Unresolved Staff Comments		12
	Item 2.	Properties		13
	Item 3.	Legal Proceedings		13
	Item 4.	Mine Safety Disclosures		13
PART II
	Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		14
	Item 6.	Selected Financial Data		16
	Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations		16
	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		33
	Item 8.	Financial Statements and Supplementary Data		34
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosures		77
	Item 9A.	Controls and Procedures		77
	Item 9B.	Other Information		79
PART III
	Item 10.	Directors, Executive Officers and Corporate Governance		80
	Item 11.	Executive Compensation		80
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		80
	Item 13.	Certain Relationships and Related Transactions, and Director Independence		80
	Item 14.	Principal Accounting Fees and Services		80
PART IV
	Item 15.	Exhibits and Financial Statement Schedules		81
	Item 16.	Form 10-K Summary		87
	Signatures			88

GLOSSARY OF TERMS

AFUDC	Allowance for Funds Used During Construction
AOCI/AOCL	Accumulated Other Comprehensive Income (Loss)
ARO	Asset Retirement Obligation
ARP	Alternative Revenue Program, regulatory or rate recovery mechanisms approved by the SCC that allow for the adjustment of revenues for certain broad, external factors, or for additional billings if the entity achieves certain performance targets.
ASC	Accounting Standards Codification
ASU	Accounting Standards Update as issued by the FASB
Company	RGC Resources, Inc. or Roanoke Gas Company
CPCN	Certificate of Public Convenience
Diversified Energy	Diversified Energy Company, a wholly-owned subsidiary of Resources
DRIP	Dividend Reinvestment and Stock Purchase Plan of RGC Resources, Inc.
DTH	Decatherm
EPS	Earnings Per Share
ERISA	Employee Retirement Income Security Act of 1974
ESAC	Eligible Safety Activity Costs, a Virginia natural gas utility’s operation and maintenance expenditures that are related to the development, implementation, or execution of the natural gas utility’s integrity management plan or programs and measures implemented to comply with regulations issued by the SCC or a federal regulatory body with jurisdiction over pipeline safety.
FASB	Financial Accounting Standards Board
FDIC	Federal Deposit Insurance Corporation
FERC	Federal Energy Regulatory Commission
Fourth Circuit	U.S. Fourth Circuit Court of Appeals
GAAP	U.S. Generally Accepted Accounting Principles
HDD	Heating degree day, a measurement designed to quantify the demand for energy. It is the number of degrees that a day’s average temperature falls below 65 degrees Fahrenheit.
ICC	Inventory carrying cost revenue, an SCC approved rate structure that mitigates the impact of financing costs on natural gas inventory.
IRS	Internal Revenue Service
KEYSOP	RGC Resources, Inc. Key Employee Stock Option Plan
LDI	Liability Driven Investment approach, a strategy which reduces the volatility in the pension and postretirement plans’ funded status and expense by matching the duration of the fixed income investments with the duration of the corresponding pension liabilities.
LIBOR	London Inter-Bank Offered Rate
LLC	Mountain Valley Pipeline, L.L.C., a joint venture established to design, construct and operate the Mountain Valley Pipeline and MVP Southgate.

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LNG	Liquefied natural gas, the cryogenic liquid form of natural gas of which Roanoke Gas operates and maintains a plant capable of producing and storing up to 200,000 dth of natural gas in liquid form.
MGP	Manufactured gas plant
Midstream	RGC Midstream, L.L.C., a wholly-owned subsidiary of Resources created to invest in pipeline projects including MVP and Southgate.
MVP	Mountain Valley Pipeline, a natural gas pipeline project intended to connect the Equitran's gathering and transmission system in northern West Virginia to the Transco interstate pipeline in south central Virginia with a planned interconnect to Roanoke Gas’ natural gas distribution system.
Normal Weather	The average number of heating degree days over the most recent 30-year period
PBGC	Pension Benefit Guaranty Corporation
Pension Plan	Defined benefit plan that provides pension benefits to employees hired prior to January 1, 2017 who meet certain years of service criteria.
PGA	Purchased Gas Adjustment, a regulatory mechanism, which adjusts natural gas customer rates to reflect changes in the forecasted cost of gas and actual gas costs.
Postretirement Plan	Defined benefit plan that provides postretirement medical and life insurance benefits to eligible employees hired prior to January 1, 2000 who meet years of service and other criteria.
Resources	RGC Resources, Inc., parent company of Roanoke Gas, Midstream and Diversified Energy
RGCO	Trading symbol for RGC Resources, Inc. on the NASDAQ Global Stock Market
Roanoke Gas	Roanoke Gas Company, a wholly-owned subsidiary of Resources
RSPD	RGC Resources, Inc. Restricted Stock Plan for Outside Directors
RSPO	RGC Resources, Inc. Restricted Stock Plan
SAVE	Steps to Advance Virginia's Energy Plan, a regulatory mechanism that allows natural gas utilities to recover the investment in eligible infrastructure replacement projects without the filing of a formal non-gas rate application.
SAVE Plan	Steps to Advance Virginia's Energy Plan, a regulatory mechanism to recover the related depreciation and expenses and return on rate base of eligible infrastructure replacement projects on a prospective basis without the filing of a formal application for increases in non-gas base rates.
SAVE Rider	Steps to Advance Virginia's Energy Rider, the rate component of the SAVE Plan as approved by the SCC that is billed monthly to the natural gas utility’s customers to recover the costs associated with eligible infrastructure projects including the related depreciation and expenses and return on rate base of the investment.
SCC	Virginia State Corporation Commission, the regulatory body with oversight responsibilities of the utility operations of Roanoke Gas.
SEC	U.S. Securities and Exchange Commission
Southgate	Mountain Valley Pipeline, LLC’s Southgate project, which extends from the MVP in south central Virginia to central North Carolina, of which Midstream holds less than a 1% investment
S&P 500 Index	Standard & Poor’s 500 Stock Index
TCJA	Tax Cuts and Jobs Act of 2017
WNA	Weather Normalization Adjustment, an ARP mechanism which adjusts revenues for the effects of weather temperature variations as compared to the 30-year average.

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Cautionary Note Regarding Forward Looking Statements

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

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

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PART I

Item 1. Business.

General and Historical Development

Resources was incorporated in the state of Virginia on July 31, 1998, for the primary purpose of becoming the holding company for 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 and Midstream.

Roanoke Gas, originally established in 1883, was organized as a public service corporation under the laws of the Commonwealth of Virginia in 1912. The principal service of Roanoke Gas is the distribution and sale of natural gas to residential, commercial and industrial customers within its service territory in Roanoke, Virginia and the surrounding localities. Roanoke Gas also provides certain non-regulated services which account for less than 2% of consolidated revenues.

In July 2015, the Company formed Midstream for the purpose of becoming a 1% investor in Mountain Valley Pipeline, LLC. The LLC was created to construct and operate interstate natural gas pipelines. Additional information regarding this investment is provided under Note 5 of the Company's annual consolidated financial statements and under the Equity Investment in Mountain Valley Pipeline section of Item 7.

Diversified Energy currently has no active operations.

Services

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

	2019
	Customers		Volume		Revenue			Margin
Residential	91.2	%	39	%	58		%	60		%
Commercial	8.7	%	31	%	33		%	26		%
Industrial	0.1	%	30	%	7		%	11		%
Other Utility	0.0	%	0	%	1		%	2		%
Other Non-Utility	0.0	%	0	%	1		%	1		%
Total Percent	100.0	%	100	%	100		%	100		%
Total Value	60,741		9,876,493		$	68,026,525		$	35,205,551

	2018
	Customers		Volume		Revenue			Margin
Residential	91.2	%	39	%	58		%	61		%
Commercial	8.7	%	32	%	33		%	25		%
Industrial	0.1	%	29	%	6		%	10		%
Other Utility	0.0	%	0	%	1		%	2		%
Other Non-Utility	0.0	%	0	%	2		%	2		%
Total Percent	100.0	%	100	%	100		%	100		%
Total Value	60,228		9,925,974		$	65,534,736		$	32,776,289

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	2017
	Customers		Volume		Revenue			Margin
Residential	91.2	%	37	%	57		%	61		%
Commercial	8.7	%	31	%	33		%	25		%
Industrial	0.1	%	32	%	7		%	10		%
Other Utility	0.0	%	0	%	1		%	2		%
Other Non-Utility	0.0	%	0	%	2		%	2		%
Total Percent	100.0	%	100	%	100		%	100		%
Total Value	59,847		8,562,582		$	62,296,870		$	32,809,157

Roanoke Gas’ regulated natural gas distribution business accounted for approximately 98% of Resources total revenues for fiscal years ending September 30, 2019, 2018 and 2017. The tables above indicate that residential customers represent over 91% of the Company’s customer total; however, they represent less than 40% of the total gas volumes delivered and more than half of the Company’s consolidated revenues and margin. Industrial customers include primarily transportation customers that purchase their natural gas requirements directly from a supplier other than the Company and utilize Roanoke Gas’ natural gas distribution system for delivery to their operations. Most of the revenue billed for these customers relates only to transportation service, and not to the purchase of natural gas, causing total revenues generated by these deliveries to be approximately 7% of total revenues, even though they represent 30% of total natural gas deliveries for the year ended September 30, 2019 and approximately 10% to 11% of margin for each of the years presented.

The Company’s revenues are affected by changes in gas costs as well as by changes in consumption volume due to weather and economic conditions and changes in the non-gas portion of customer billing rates. Increases or decreases in the cost of natural gas are passed on to customers through the PGA mechanism as explained in Note 1 of the Company’s annual consolidated financial statements.

The Company’s residential and commercial sales are seasonal and temperature-sensitive as the majority of the gas sold by Roanoke Gas to these customers is used for heating. For the fiscal year ended September 30, 2019, approximately 67% of the Company’s total DTH of natural gas deliveries and 76% of the residential and commercial deliveries were made in the five-month period of November through March. Total natural gas deliveries were approximately 9.9 million DTH in fiscal 2019 and 2018 and 8.6 million DTH in fiscal 2017.

Suppliers

Roanoke Gas relies on multiple interstate pipelines including those operated by Columbia Gas Transmission Corporation, LLC and Columbia Gulf Transmission Corporation, LLC (together “Columbia”), and East Tennessee Natural Gas, LLC (“East Tennessee”), Tennessee Gas Pipeline, Midwestern Gas Transmission Company and Saltville Gas Storage Company, LLC ("Saltville") to transport natural gas from the production and storage fields to Roanoke Gas’ distribution system. Roanoke Gas is directly served by two pipelines, Columbia and East Tennessee. Columbia historically has delivered more than 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 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 2022 to 2027. The Company anticipates being able to renew these contracts or enter into other contracts to meet customers’ continued demand for natural gas.

The Company manages its pipeline contracts and LNG facility in order to provide for sufficient capacity to meet the natural gas demands of its customers. The maximum daily winter capacity available for delivery into Roanoke Gas’ distribution system under the interstate pipelines is 78,606 DTH per day. The LNG facility is capable of storing up to 200,000 DTH of natural gas in a liquid state for use during peak demand. Combined, the pipelines and LNG facility may provide up to 103,606 DTH on a single winter day.

The Company uses multi-year contracts to meet its natural gas supply needs. The Company currently contracts with Sequent Energy Management, L.P. to manage its pipeline transportation, storage rights, gas supply inventories and deliveries and serve as the primary supplier of natural gas for Roanoke Gas. Natural gas purchased under the asset management agreement is priced at indexed-based market prices as reported in major industry pricing publications. The Company renewed its contract with the asset manager in March 2018. The new agreement expires March 31, 2021.

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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 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 CPCNs to distribute natural gas in its Virginia service areas. These franchises generally extend for multi-year periods and are renewable by the municipalities, including exclusive franchises in the cities of Roanoke and Salem and the Town of Vinton, Virginia. All three franchise agreements were recently renewed for a term of 20 years and will expire December 31, 2035. In 2019, the SCC issued a final order granting a CPCN to furnish gas to all of Franklin County. Unlike the CPCNs for the other counties served by Roanoke Gas, the Franklin County CPCN will be terminated within five years of the date of the order if Roanoke Gas does not furnish gas service to the designated service area. Roanoke Gas plans to serve the Franklin County area with natural gas delivered through the MVP once that pipeline goes in service.

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. CPCNs, issued by the SCC, are generally of perpetual duration and subject to compliance with regulatory standards.

Although Roanoke Gas has exclusive rights for the distribution of natural gas in its service area, the Company competes with suppliers of other forms of energy such as fuel oil, electricity, propane, coal, wind and solar. Competition can be intense among the other energy sources with price being the primary driver in most instances. This is particularly true for those industrial applications that have the ability to switch to alternative fuels. The relationship between supply and demand has the greatest impact on the price of natural gas. Greater demand for natural gas for electric generation and other uses can provide upward pressure on the price of natural gas. Currently, a plentiful supply of natural gas, mostly due to improved drilling and extraction processes in shale formations, has served to maintain prices at lower levels.

Competition from renewable "clean" energy sources like solar and wind may increase as the political environment may favor these energy sources through incentives or by placing restrictions on emissions from the burning of fossil fuels. Nevertheless, the Company continues to see a demand for its product. Construction activity for new business and growth in residential service has remained steady as the Company continues to grow its customer base through a combination of extending service by new construction and converting existing alternative energy source users to natural gas.

Regulation

In addition to the regulatory requirements generally applicable to all companies, Roanoke Gas is also subject to additional regulation at the federal, state and local levels. At the federal level, the Company is subject to pipeline safety regulations issued by the Department of Transportation and the Pipeline and Hazardous Materials Safety Administration.

At the state level, the SCC performs regulatory oversight including the approval of rates and other charges for natural gas sold to customers, the approval of agreements between or among affiliated companies involving the provision of goods and services, pipeline safety, and certain other corporate activities of the Company, including mergers and acquisitions related to utility operations.

At the local level, Roanoke Gas is further regulated by the municipalities and localities that grant franchises for the placement of gas distribution pipelines and the operation of gas distribution networks within their jurisdictions.

Employees

At September 30, 2019, Resources had 106 full-time employees and 107 total employees. As of that date, 26 employees, or 24%, 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

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

Website Access to Reports

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

Item 1A. Risk Factors

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

OPERATIONAL RISKS

Availability of sufficient and reliable pipeline capacity.

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

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

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

Supply disruptions due to weather or other forces.

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

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

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

Security incident or cyber-attacks on the Company’s computer or information technology systems.

The Company’s business operations and information technology systems may be vulnerable to an attack by individuals or organizations intending to disrupt the operations of the Company. Such an attack or cyber-security incident on the Company’s information technology systems could result in corruption of the Company’s financial information; the unauthorized release of confidential customer, employee or vendor information; the interruption of natural gas deliveries to our customers; or compromise the safety of our distribution, transmission and storage systems. The Company has implemented policies, procedures and controls to prevent and detect these activities; however, there are no guarantees that Company processes will adequately protect against unauthorized access. In the event of a successful attack, the Company could be exposed to material financial and reputational risks, possible disruptions in natural gas deliveries or a compromise of the safety of the natural gas distribution system, as well as be exposed to claims by persons harmed by such an attack, all of which could materially increase the Company's costs to protect against such risks.

Inability to attract and retain professional and technical employees.

The ability to implement the Company’s business strategy and serve customers is dependent upon employing talented professionals and attracting, training, developing and retaining a skilled workforce. As the Company will be facing retirements of key personnel over the next several years, the failure to replace those departing employees with skilled and qualified employees could increase operating costs and expose the Company to other operational and financial risks.

Geographic concentration of business activities.

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

Impact of weather conditions and related regulatory mechanisms.

The Company’s revenues and earnings are dependent upon weather conditions. The Company’s rate structure currently has a WNA factor that results in either a recovery or refund of revenues due to any variation from the 30-year average for heating degree-days. If the provision for the WNA 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.

Volatility in the price and availability of natural gas.

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

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

In order to serve new customers or expand service to existing customers, the Company needs to install new pipeline and maintain, expand or upgrade its existing distribution, transmission and/or storage infrastructure. Various factors may prevent or delay the completion of such projects or make them more costly, such as the inability to obtain required approval from local, state and/or federal regulatory and governmental bodies, public opposition to the projects, inability to obtain adequate financing, competition for labor and materials, construction delays, cost overruns,

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and an inability to negotiate acceptable agreements relating to rights-of-way, construction or other material development components. As a result, the Company may not be able to adequately serve existing customers or expand its distribution system to support customer growth. This could include any potential customer growth or system reliability enhancement resulting from connection to the MVP. Any of these factors could negatively impact earnings.

Competition from other energy providers.

The Company competes with other energy providers in its service territory, including those that provide electricity, propane, coal, fuel oil, wind and solar. Price is a significant competitive factor. Higher natural gas costs or decreases in the price of other energy sources may enhance competition and encourage customers to convert their natural gas-fueled equipment to systems that use alternative energy sources, thus lowering natural gas deliveries and earnings. Price considerations could also inhibit customer and revenue growth if builders and developers do not perceive natural gas to be a better value than other energy options and elect to install heating systems that use an energy source other than natural gas.

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

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

REGULATORY RISKS

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

Several federal and state legislative and regulatory initiatives have been proposed in recent years in an attempt to limit the effects of global warming and climate change, including greenhouse gas emissions such as those created by the combustion of fossil fuels such as natural gas. Passage of new environmental legislation or implementation of regulations that mandate reductions in greenhouse gas emissions or other similar restrictions could have a negative effect on the Company’s core operations and its investment in the LLC. Such legislation could impose limitations on greenhouse gas emissions, require funding of new energy efficiency objectives, impose new operational requirements or lead to other additional costs to the Company. Regulations restricting or prohibiting the use of coal as a fuel for electric power generation has increased the demand for natural gas, and could at some point potentially result in natural gas supply concerns and higher costs for natural gas. Legislation or regulations could limit the exploration and development of natural gas reserves, making the price of natural gas less competitive and less attractive as a fuel source for consumers, resulting in reduced deliveries and earnings. The current Presidential administration is de-emphasizing climate change initiatives; however, future administrations might prioritize climate change and greenhouse gas emissions, which could lead to new and stricter environmental laws.

Increased compliance and pipeline safety requirements and fines.

The Company is committed to the safe and reliable delivery of natural gas to its customers. Working in concert with this commitment are numerous federal and state laws and regulations. Failure to comply with these laws and regulations could result in the levy of significant fines. There are inherent risks that may be beyond the Company’s control, including third party actions, which could result in damage to pipeline facilities, injury and even death. Such incidents could subject the Company to lawsuits, large fines, increased scrutiny and loss of customers, all of which could have a significant effect on the Company’s financial position and results of operations.

Regulatory actions or failure to obtain timely rate relief.

The Company’s natural gas distribution operations are regulated by the SCC. The SCC approves the rates that the Company charges its customers. If the SCC did not authorize rates that provided for the timely recovery of costs or a reasonable rate of return on investment in natural gas distribution facilities, earnings could be negatively impacted. Issuance of debt and equity by Roanoke Gas is also subject to SCC regulation and approval. Delays or lack of approvals could inhibit the ability to access capital markets and negatively impact liquidity or earnings.

10

Compliance with and Changes in Tax Laws.

The Company is subject to extensive tax laws and regulations. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future. Many of these tax liabilities are subject to audits by the respective taxing authority. These audits may result in additional taxes as well as interest and penalties.

FINANCIAL RISKS

Investment in Mountain Valley Pipeline, LLC.

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

Although the LLC initially received the necessary federal and state permits to construct the pipeline, progress on the MVP has been hindered by several legal and regulatory obstacles as both the Fourth Circuit and FERC have issued stays or stop orders affecting portions or all of the project pending resolution of issues or concerns raised as the project has progressed. Actions taken or imposed by the Fourth Circuit or FERC that are currently impeding the completion of the pipeline include the following: In July 2018, the Fourth Circuit rescinded permits allowing the pipeline to cross a 3.6 mile section of the Jefferson National Forest. In October 2018, the same court vacated the West Virginia water crossing permits with the Army Corp of Engineers subsequently rescinding the permits in Virginia. In October 2019, FERC issued a project-wide order halting forward-construction progress in response to the October 11, 2019, Fourth Circuit order granting a stay of Mountain Valley Pipeline's Biological Opinion and Incidental Take Statement issued by the U.S. Fish and Wildlife Service in November 2017.

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

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

Once in operation, the LLC’s gas infrastructure facilities are subject to many operational risks. Operational risks could result in, among other things, lost revenues due to prolonged outages, increased expenses due to monetary penalties or fines for compliance failures, liability to third parties for property and personal injury damage, a failure to perform under applicable sales agreements and associated loss of revenues from terminated agreements or liability for liquidated damages under continuing agreements. The consequences of these risks could have a material adverse effect on the LLC’s business, financial condition, results of operations and prospects. Uncertainties and risks inherent in operating and maintaining the LLC's facilities include, but are not limited to, risks associated with facility start-up operations, such as whether the facility will achieve projected operating performance on schedule and otherwise as planned. The LLC’s business, financial condition, results of operations and prospects can be materially adversely affected by weather conditions, including, but not limited to, the impact of severe weather. Threats of terrorism and catastrophic events resulting from terrorism, cyber-attacks, or individuals and/or groups attempting to disrupt the LLC’s business, or the businesses of third parties, may materially adversely affect the LLC’s business, financial condition, results of operations and prospects.

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Access to capital to maintain liquidity.

The Company relies on a variety of capital sources to operate its business and fund capital expenditures, including internally generated cash from operations, short-term borrowings under its line-of-credit, proceeds from the issuance of additional shares of its common stock and other sources. Access to a line-of-credit is essential to provide seasonal funding of natural gas operations and provide capital budget bridge financing. Access to capital markets and other long-term funding sources is important for capital outlays and funding of the LLC investment. The ability of the Company to maintain and renew its line-of-credit and to secure longer-term financing is critical to operations. Adverse market trends, market disruptions or deterioration in the financial condition of the Company could increase the cost of borrowing, restrict the Company's ability to issue additional shares of its common stock or otherwise limit the Company’s ability to secure adequate funding.

Insurance coverage may not be sufficient.

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

Post-retirement benefits and related funding of obligations.

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

Failure to comply with debt covenant requirements.

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

Exposure to Market Risks.

The Company is subject to market risks that are beyond the Company’s control, such as commodity price volatility and interest rate risk. The Company is generally isolated from commodity price risk through the PGA mechanism the Company has in place. With respect to interest rate risk, the Company has been operating in a relatively low interest rate environment for both short and long-term interest rates. However, increases in interest rates could adversely affect the Company’s future financial results.

Item 1B. Unresolved Staff Comments.

Not applicable.

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Item 2. Properties.

Included in “Utility Property” on the Company’s consolidated balance sheet are storage plant, transmission plant, distribution plant and general plant of Roanoke Gas as categorized by natural gas utilities. The Company has approximately 1,146 miles of transmission and distribution pipeline with transmission and distribution plant representing 88% of the total utility plant investment. The transmission and distribution pipelines are located on or under public roads and highways or private property for which the Company has obtained the legal authorization and rights to operate.

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

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

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

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

Item 3. Legal Proceedings.

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

Item 4. Mine Safety Disclosures.

Not applicable.

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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 depends on, among other factors, earnings, capital requirements, and the operating and financial condition of the Company.

	Range of Bid Prices				Cash Dividends
Year Ending September 30, 2019	High		Low		Declared
First Quarter	$	30.71	$	24.16	$	0.1650
Second Quarter	30.51		26.50		0.1650
Third Quarter	30.52		25.63		0.1650
Fourth Quarter	31.00		26.46		0.1650
Year Ending September 30, 2018
First Quarter	$	31.57	$	25.01	$	0.1550
Second Quarter	27.49		22.16		0.1550
Third Quarter	29.46		23.61		0.1550
Fourth Quarter	31.33		25.85		0.1550

As of November 22, 2019, there were 1,106 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, 2014 through September 30, 2019 with the Dow Jones US Utility Index, a utility based index, and the S&P 500 Index, a broad market index.

The graph below reflects the value of a hypothetical investment of $100 made September 30, 2014 in the Company’s common stock and in each index as of September 30, 2019, 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 $250 for the Company’s common stock, $185 for the Dow Jones US Utilities Index and $167 for the S&P 500 Index.

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A summary of the Company’s equity compensation plans follows as of September 30, 2019:

	(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	68,492	$14.91	535,144
Equity compensation plans not approved by security holders	—	—	—
Total	68,492	$14.91	535,144

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Item 6. Selected Financial Data.

	Year Ending September 30,
	2019		2018		2017		2016		2015
Operating Revenues	$	68,026,525	$	65,534,736	$	62,296,870	$	59,063,291	$	68,189,607
Operating Income (1)	11,595,464		11,470,507		12,192,742		11,644,839		10,129,130
Net Income	8,698,412		7,297,205		6,232,865		5,806,866		5,094,415
Basic Earnings Per Share	$	1.08	$	0.95	$	0.86	$	0.81	$	0.72
Cash Dividends Declared Per Share	$	0.66	$	0.62	$	0.58	$	0.54	$	0.51
Book Value Per Share	$	10.29	$	9.95	$	8.29	$	7.75	$	7.43
Average Shares Outstanding	8,039,484		7,649,025		7,218,686		7,149,906		7,092,315
Total Assets	$	258,353,696	$	219,560,106	$	183,135,071	$	165,552,849	$	145,847,194
Long-Term Debt (Less Unamortized Debt Expense)	$	103,371,358	$	70,321,936	$	61,312,011	$	33,636,051	$	30,316,573
Stockholders' Equity	83,096,392		79,583,112		60,040,472		55,667,072		52,840,991
Shares Outstanding at Sept. 30	8,073,264		7,994,615		7,240,846		7,182,434		7,112,247

⁽¹⁾Operating income for the prior years were revised due to the adoption of ASU 2017-07 - Compensation Retirement Benefits. Net income remained unaffected. See Note 1 of the Consolidated Financial Statements for additional information.

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

Overview

Resources is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately 60,700 residential, commercial and industrial customers in Roanoke, Virginia, and the surrounding localities, through its Roanoke Gas subsidiary. Roanoke Gas also provides certain unregulated services. As a wholly-owned subsidiary of Resources, Midstream is a 1% member in the Mountain Valley Pipeline, LLC. More information regarding the investment in MVP is provided under the Equity Investment in Mountain Valley Pipeline section below. The unregulated operations represent less than 2% of revenues and margins of Resources.

The utility operations of Roanoke Gas are regulated by the 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. Roanoke Gas is also subject to federal regulation from the Department of Transportation in regard to the construction, operation, maintenance, safety and integrity of its transmission and distribution pipelines. FERC regulates prices for the transportation and delivery of natural gas to the Company's distribution system and underground storage services. Roanoke Gas is also subject to other regulations which are not necessarily industry specific.

More than 98% of the Company’s revenues, excluding equity in earnings of MVP, are derived from the sale and delivery of natural gas to Roanoke Gas customers. 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.

The Company has completed the transition to the 21% federal statutory income tax rate as a result of the TCJA that was signed into law in December 2017. Since the implementation of the new tax rates, the Company has recorded a provision for refund related to estimated excess revenues collected from customers under approved billing rates designed to recover expenses and provide a rate of return based on a federal tax rate of 34%. Beginning January 1, 2019, Roanoke Gas incorporated the effect of the 21% federal tax rate with the implementation of new non-gas base rates, as filed in its current rate application, and began refunding the excess revenues associated with the change in the tax rate over the subsequent 12-month period. The Company also recorded a regulatory liability related to the excess deferred income taxes on the regulated operations of Roanoke Gas. These excess deferred income taxes are being

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refunded to customers over a 28-year period. The SCC staff report issued, as part of the audit of the Company's non-gas rate application, indicated no changes to the amounts for excess revenue collected and the excess deferred taxes to be refunded to customers. The Company expects to complete the refund of the excess revenues by December and will continue to refund the excess deferred taxes over time. Additional information regarding the TCJA and non-gas base rate application is provided under the Regulatory and Tax Reform section below.

As mentioned above, the Company currently has a non-gas base rate application pending before the SCC. Roanoke Gas implemented the non-gas rates contained in its rate application for natural gas service rendered to customers on or after January 1, 2019. These non-gas rates are subject to refund pending audit, hearing and a final order issued by the SCC. On June 28, 2019, the SCC staff issued its report and findings from the audit of the rate application. In its report, the SCC staff recommended a lower non-gas base rate increase than was requested in the rate application, which is normal and expected. In addition, the SCC staff recommended a change in rate design between customer base charge and volumetric rates, shifting much of the increase in non-gas base rates from customer base charges to the volumetric components. At the hearing held in August 2019, management provided additional testimony and rebuttal to certain proposed adjustments in response to the SCC staff report. After evaluating the adjustments proposed by the SCC staff and the testimony provided at the hearing, management updated its assumptions used in estimating the refund amount included in the financial statements. The hearing examiner's report and final order from the SCC is not expected until December 2019 or early 2020. Upon receipt of the final order, the Company will adjust the interim rates to the those approved in the rate order and finalize the rate refund based on the approved rates. Subsequent to year end, the Company received the hearing examiner's reports. See Note 15 and the Regulatory and Tax Reform section below for additional information.

The Company is committed to the safe and reliable delivery of natural gas to its customers. Since 1991, the Company has placed an emphasis on the modernization of its distribution system through the renewal and replacement of its cast iron and bare steel natural gas distribution pipelines and other system improvements. In 2017, the Company completed the replacement of all cast iron and bare steel pipe and is continuing its renewal program with other qualified infrastructure replacement programs including the renewal of 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 attacks and other types of incidents; however, there can be no guarantee that an incident will not occur.  In the event of a cyber incident, the Company will execute its Security Incident Response Plan.  The Company maintains cyber-insurance coverage to mitigate financial expense that may result from a cyber incident.

As the Company’s business is seasonal in nature, volatility in winter weather and the commodity price of natural gas, can impact the effectiveness of the Company’s rates in recovering its costs and providing a reasonable return for its shareholders. In order to mitigate the effect of weather variations and other factors not provided for in the Company's base rates, Roanoke Gas has certain approved rate mechanisms in place that help provide stability in earnings, adjust for volatility in the price of natural gas and provide a return on qualified infrastructure investment. These mechanisms include the SAVE Rider, WNA, ICC revenue and PGA.

The Company’s non-gas base rates are designed to allow for the recovery of non-gas related expenses and provide a reasonable return to shareholders. These rates are determined based on the filing of a formal rate application with the SCC. Generally, investments related to extending service to new customers are recovered through the additional revenues generated by the non-gas base rates currently in place. The investment in replacing and upgrading existing infrastructure is generally not recoverable until a formal rate application is filed to include the additional investment, and new non-gas base rates are approved. The SAVE Plan and Rider provides the Company with the ability to recover costs related to these SAVE qualified infrastructure investments on a prospective basis. The SAVE Plan provides a mechanism through which the Company may recover the related depreciation and expenses and provides 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 base rates. Since the Company's previous non-gas base rate application in 2013, SAVE Plan revenues have grown each year corresponding to the level of SAVE qualifying capital investment. With the filing of the new non-gas base rate application, the SAVE Rider has been reset as the qualified SAVE Plan investment through December 2018 has been incorporated into the current application. Accordingly, SAVE Plan revenues declined to $1,599,000 in fiscal 2019 compared to $4,469,000 and $3,813,000 for fiscal 2018 and 2017. Additional information regarding the SAVE Rider is provided under the Regulatory Affairs section.

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The WNA reduces the volatility in earnings due to the variability in temperatures during the heating season. The WNA is based on the most recent 30-year temperature average and provides the Company with a level of earnings protection when weather is warmer than normal and provides its customers with price protection when the weather is colder than normal. The WNA allows the Company to recover from its customers the lost margin (excluding gas costs) from the impact of weather that is warmer than normal and correspondingly requires the Company to refund the excess margin earned for weather that is colder than normal. Any billings or refunds related to the WNA are completed following the WNA year end, which runs from April to March. For the fiscal year ended September 30, 2019, the Company recorded approximately $453,000 in additional revenue from the WNA for weather that was approximately 4% warmer than normal. For the fiscal years ended September 30, 2018 and 2017, the Company recorded $45,000 and $1,839,000 in additional revenue from the WNA for weather that was approximately 1% and 18% warmer than normal, respectively. As normal weather is based on the most recent 30-year temperature average, the number of heating degree days used to determine normal will change annually as a new year is added to the 30-year period and the oldest year is removed. As a result of adding recent warmer than normal years to replace colder historical years to the 30-year period, the number of heating degree days that defines normal has declined from 3,998 in fiscal 2013 to 3,925 in fiscal 2019. The Company's prior rates were designed on 4,000 heating degree days based on its last non-gas rate filing; however, the 2019 WNA model is recovering based on 3,949 heating degree days, or about 1% less than what the prior non-gas rates were designed to recover. The 30-year normal has been reset to 3,959 in the determination of the new non-gas base rates in the current rate application.

The Company also has an approved rate structure in place that mitigates the impact of financing costs of its natural gas inventory. Under this rate structure, Roanoke Gas recognizes revenue for the financing costs, or “carrying costs,” of its investment in natural gas inventory. The ICC factor applied to average inventory is based on the Company’s weighted-average cost of capital, including interest rates on short-term and long-term debt, and the Company’s authorized return on equity.

During times of rising gas costs and rising inventory levels, Roanoke Gas recognizes ICC revenues to offset higher financing costs associated with higher inventory balances. Conversely, during times of decreasing gas costs and declining inventory balances, Roanoke Gas recognizes less ICC revenue as financing costs are lower. In addition, ICC revenues are impacted by changes in the weighted-average cost of capital. The combination of a 10% reduction in the average cost of gas in storage during fiscal 2019 and a 5% reduction in the ICC factor, resulted in a decline in ICC revenues of approximately $92,000 from fiscal 2018. This compares to a decline of $35,000 in ICC revenues for fiscal 2018 compared to fiscal 2017. Based on current storage balances and natural gas futures, the average dollar balance of gas in storage should remain stable and, with a more consistent ICC factor, should result in less volatility in ICC revenues.

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, allows the Company to pass along to its customers increases and decreases in natural gas costs incurred by its regulated operations. On at least 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 economic environment has a direct correlation with business and industrial production, customer growth and natural gas utilization. Currently, the local economy continues to show modest growth and should continue to improve absent a major economic setback on a local, regional or national level.

Results of Operations

The analysis on the results of operations is based on the consolidated operations of the Company, which is primarily associated with the utility segment. Additional segment analysis is provided in areas where the investment in affiliates segment (investment in MVP and Southgate) represent a significant component of the expense comparison.

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Fiscal Year 2019 Compared with Fiscal Year 2018

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

Operating Revenues
Year Ended September 30,	2019		2018		Increase / (Decrease)			Percentage
Gas Utilities	$	67,306,260	$	64,341,783	$	2,964,477		5	%
Other	720,265		1,192,953		(472,688		)	(40	)%
Total Operating Revenues	$	68,026,525	$	65,534,736	$	2,491,789		4	%

Delivered Volumes
Year Ended September 30,	2019	2018	Increase / (Decrease)		Percentage
Regulated Natural Gas (DTH)
Residential and Commercial	6,901,181	7,103,825	(202,644	)	(3	)%
Transportation and Interruptible	2,975,312	2,822,149	153,163		5	%
Total Delivered Volumes	9,876,493	9,925,974	(49,481	)	—	%
Heating Degree Days (Unofficial)	3,791	3,954	(163	)	(4	)%

Total gas utility operating revenues for the year ended September 30, 2019increased by 5% from the year ended September 30, 2018 primarily due to the implementation of higher non-gas rates and slightly higher gas costs. The Company implemented new non-gas base rates effective for natural gas service rendered on or after January 1, 2019, subject to refund. The revenues have been reduced by management's estimate of a rate refund pending final resolution of the rate application and order by the SCC. Total natural gas deliveries decreased by less than 1% from last year primarily due to warmer weather, offset by increased industrial consumption. Industrial consumption, as reflected in the transportation and interruptible volumes, increased due to a significant increase in usage by one customer and a large commercial customer that transferred to firm transportation during fiscal 2019. Residential and commercial customers' natural gas usage tends to be more weather sensitive as reflected by a 3%decline in volumes on 4%fewer heating degree days. After adjusting for WNA and the transfer of the large commercial customer to firm transportation, total residential and commercial volumes reflect an increase of more than 1%. The average commodity price of natural gas delivered during fiscal 2019 was approximately 4% per decatherm higher than for fiscal 2018. Natural gas commodity prices spiked during December 2018 due to weather, but have since returned to lower levels. The prior year included a reserve of $1,320,167 associated with the accumulated excess revenues billed to customers as a result of the reduction in the corporate federal income tax rate. The current fiscal year includes a reserve of $523,881 as the accrual for excess revenues ended with the implementation of new non-gas rates, which incorporated the reduction in the federal income tax rate. Other revenues decreased by 40% due to a significant reduction in services during the last half of the year.

The Company's operations are affected by the cost of natural gas, as reflected in the consolidated income statement under the line item cost of gas - utility. The cost of natural gas is passed through to customers at cost, which includes commodity price, transportation, storage, injection and withdrawal fees with any increase or decrease offset by a correlating change in revenue through the PGA. Accordingly, management believes that gross utility margin, a non-GAAP financial measure defined as utility revenues less cost of gas, is a more useful and relevant measure to analyze financial performance. The term gross utility margin is not intended to represent operating income, the most comparable GAAP financial measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. Therefore, the following discussion of financial performance will reference gross utility margin as part of the analysis of the results of operations.

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Gross Utility Margin
Year Ended September 30,	2019		2018		Increase		Percentage
Utility revenues	$	67,306,260	$	64,341,783	$	2,964,477	5	%
Cost of gas	32,401,123		32,091,923		309,200		1	%
Gross Utility Margin	$	34,905,137	$	32,249,860	$	2,655,277	8	%

Gross utility margins increased over last year primarily as a result of implementing higher non-gas base rates effective January 1, 2019. SAVE Plan revenues declined by nearly $2,900,000 as all related SAVE investment through December 31, 2018 was incorporated into the new non-gas base rates. As noted above, the SCC staff recommended a change in the proposed rate design of the non-gas rate increase between customer base charge and volumetric rates. In designing the rates submitted in the rate application, the Company included SAVE related revenues in the base charge component as the SAVE rider was previously reflected as a fixed fee on customers bills. As a result, the new rates implemented in January 2019 included a much larger allocation of the rate increase to the customer base charge. The SCC staff recommended in their report to significantly reduce the customer base charge rate and move it to the volumetric component of non-gas rates. Due to the staff's position and the results of non-gas rate applications from other Virginia utilities, the Company incorporated into its rate refund assumptions a significant reduction in customer base charge revenue and an increase in volumetric revenue. As a result, the net impact of the rate increase incorporating the rate refund assumptions resulted in an increase in the customer base charge of $1,009,479 and an increase in the volumetric margin of $3,409,095. As noted above, WNA revenues were higher due to warmer weather, while excess revenues related to tax reform were lower during the current year as new non-gas rates were implemented that incorporated the effects of the TCJA.

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

	Years Ended September 30,
	2019			2018			Increase / (Decrease)
Customer Base Charge	$	13,486,234		$	12,476,755		$	1,009,479
SAVE Plan	1,599,281			4,468,556			(2,869,275		)
Volumetric	19,298,454			15,889,359			3,409,095
WNA	452,892			44,569			408,323
Carrying Cost	462,260			554,090			(91,830		)
Excess Revenues - Tax Reform	(523,881		)	(1,320,167		)	796,286
Other Revenues	129,897			136,698			(6,801		)
Total	$	34,905,137		$	32,249,860		$	2,655,277

Operations and Maintenance Expense - Operations and maintenance expense increased by $1,617,591, or 13%, from last year primarily due to higher compensation costs, amortization of regulatory assets, corporate insurance costs, lower capitalized overheads, maintenance activities and higher bad debt expense. Total compensation costs increased by $647,000 due to higher staffing levels in regulatory and operations support combined with wage increases. Beginning in January 2019, concurrent with the implementation of new non-gas rates, the Company began amortizing certain regulatory assets for which recovery was included in the rate application. A total of $372,000 was charged to expense related to the amortization of these assets. Most of the regulatory assets have a 5-year amortization period. Corporate insurance expense increased by $125,000 due to higher premiums related to increased liability limits and higher deductible reserves. Capitalized overheads declined by $255,000 due to lower overall capital expenditures and reduced LNG production related to timing of facility upgrades at the plant. Contracted maintenance related to work on the LNG plant and brush clearing along the Company's transmission right of way increased maintenance costs by $186,000. Bad debt expense increased by $55,000 associated with increased customer billings.

General Taxes - General taxes increased$188,784, or 10%, primarily due to higher property taxes associated with increases in utility property and higher payroll taxes.

20

Depreciation - Depreciation expense increased by $497,930, or 7%, corresponding to a 6% increase in utility plant investment.

Equity in Earnings of Unconsolidated Affiliate - The equity in earnings of the MVP investment increased by $2,081,817 due to AFUDC related to increased investment in the project. Total cash investment in fiscal 2019 was nearly $21 million. The investment in Mountain Valley Pipeline and the related AFUDC earnings are discussed further under the Equity Investment in Mountain Valley Pipeline section below.

Other Income (Expense), net - Other income increased by $107,014 primarily due to a full year of revenue sharing received by the Company under the gas supply asset management agreement and the adoption of ASU 2017-07. Revenue sharing fees increased by $313,000 as the incentive mechanism was only in effect for a portion of last year. ASU 2017-07 requires that net periodic benefit costs, other than service cost, be presented outside of income from operations. As a result of the adoption of this ASU, the prior years financial statements have been adjusted retrospectively with the reclassification of $123,000 in net expense reduction from operations and maintenance to other income for fiscal 2018. Current year net expense reductions related to other benefit costs were less than $2,000. The remaining difference is attributable to pipeline assessments and charitable contributions. See the Regulatory and Tax Reform section below for more information on revenue sharing and Note 1 for information on the adoption of ASU 2017-07.

Interest Expense - Total interest expense increased by $1,156,986, or 47%, due to a 41% increase in the average total debt outstanding during the year attributed to the investment in MVP and financing expenditures in support of Roanoke Gas' capital budget. The Company contributed nearly $21 million to its investment in MVP during the year as Midstream's borrowing increased by more than $22 million with a corresponding increase in interest expense of $832,000. Roanoke Gas' total borrowing increased by more than $10 million related to the issuance of an unsecured note to refinance a portion of the line-of-credit, which accounted for the remaining increase in interest expense. The average interest rate on consolidated borrowings increased during the current year from 3.80% to 3.92%.

Income Taxes - Income tax expense decreased by $244,405, or 8%, even though pre-tax earnings increased. The effective tax rate was 23.4% for fiscal 2019 compared to 28.4% for fiscal 2018. These decreases in the effective tax rate and income tax expense correspond to the reduction in the corporate federal income tax rate from the 24.3% blended federal tax rate in fiscal 2018 to the 21% statutory rate in fiscal 2019. Fiscal 2018 income tax expense also included $256,444 of additional tax expense for the revaluation of net deferred tax assets of the unregulated operations to the 21% federal tax rate. Income tax expense related to the MVP investment increased by $359,000 due to the significant growth in pre-tax earnings. Additional information regarding the impact of tax reform can be found in Note 8 and under the Regulatory and Tax Reform section below.

Net Income and Dividends - Net income for fiscal 2019 was $8,698,412 compared to $7,297,205 for fiscal 2018. Basic and diluted earnings per share were $1.08 in fiscal 2019 compared to $0.95 in fiscal 2018. Dividends declared per share of common stock were $0.66 in fiscal 2019 compared to $0.62 in fiscal 2018.

Fiscal Year 2018 Compared with Fiscal Year 2017

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

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

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

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

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

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

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

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

Operations and Maintenance Expense - Operations and maintenance expense decreased by $102,180, or 1%, from fiscal 2017 primarily due to reductions in compensation costs, contracted services and benefit costs partially offset by the reclassification of net periodic benefit costs other than service cost from operating and maintenance expense to non-operating expense and higher bad debt expense. Compensation declined by $127,000 in large part due to the reduction in employees related to the outsourcing of the customer service function, net of additions in other areas. Contracted services also declined as the higher costs related to outsourcing the customer service function were offset by declines in meter reading costs, due to the implementation of an automated meter reading system in fiscal 2017, and the insourcing of the utility line locating function. Employee benefit costs declined by $705,000 primarily as a result of decreases in the actuarially determined expenses of both the pension and other post-retirement benefit plans. Strong asset performance and funding combined with an increase in the discount rate served to reduce the actuarially determined expenses of the plans and improve the overall funded status. Bad debt expense increased by $85,000 on higher gross customer billings due to a much colder heating season compared to the prior year. Operating and maintenance expense has been revised for fiscal 2018 and 2017 due to the adoption of ASU 2017-07 related to the change in financial presentation of other net periodic benefit costs. As a result of this reclassification, operation and maintenance expense increased by $648,971, while at the same time other income (expense), net increased by the same amount. See Note 1 for more information regarding the ASU 2017-07.

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

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

Equity in Earnings of Unconsolidated Affiliate - The equity in earnings of the MVP investment increased by $516,885 due to the ongoing investment in the Mountain Valley Pipeline.

Other Income (Expense), net - Other income (expense) moved from $658,879 in net other expense to $224,868 in net other income primarily due to the reclassification of other net periodic benefit costs out of operation and maintenance expense into other income (expense) as required under ASU 2017-07. The reclassification accounted for $648,971 of the change with most of the remaining difference resulting from the implementation of the revenue sharing incentive mechanism, lower pipeline assessments and charitable commitments and higher interest earnings. See Note 1 for additional information regarding ASU 2017-07.

Interest Expense - Total interest expense increased by $544,311, or 28%, due to a 20% increase in the average total debt outstanding during the year. Most of the net increase in borrowing is attributable to the investment in Mountain Valley Pipeline, which accounted for $244,000 of the increase in interest expense. Roanoke Gas funded its capital expenditures for 2018 through the $15 million equity infusion from Resources. The average interest rate increased during the current year from 3.56% to 3.80%. The increase in the average interest rate is due to the issuance of the $8,000,000 unsecured notes on October 2, 2017 at a rate of 3.58% which replaced a portion of the lower-rate balance under the line-of-credit combined with the rising interest rate on the Company's variable-rate debt.

Income Taxes - Income tax expense decreased by $910,254, or 24%, even though pre-tax earnings increased. The effective tax rate was 28.4% for fiscal 2018 compared to 37.9% for fiscal 2017. This decrease in the effective tax rate and income tax expense corresponds to the reduction in the corporate federal income tax rate from 34% for fiscal 2017

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to a 24.3% blended rate for fiscal 2018, and ultimately to 21% in fiscal 2019. Income tax expense related to the MVP investment was nearly unchanged as a reduced federal income tax rate offset growth in pre-tax earnings.

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

Capital Resources and Liquidity

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

Cash and cash equivalents increased by $1,383,937 in fiscal 2019 compared to an increase of $177,771 in fiscal 2018 and a decrease of $573,612 in fiscal 2017. The following table summarizes the categories of sources and uses of cash:

Cash Flow Summary	Year Ended September 30,
	2019			2018			2017
Net cash provided by operating activities	$	14,697,704		$	13,503,795		$	12,980,978
Net cash used in investing activities	(42,830,005		)	(34,166,578		)	(23,492,555		)
Net cash provided by financing activities	29,516,238			20,840,554			9,937,965
Increase (decrease) in cash and cash equivalents	$	1,383,937		$	177,771		$	(573,612	)

Cash Flows Provided by Operating Activities:

The seasonal nature of the natural gas business causes operating cash flows to fluctuate significantly during the year as well as from year to year. Factors, including weather, energy prices, natural gas storage levels and customer collections, all contribute to working capital levels and related cash flows. Generally, operating cash flows are positive during the second and third quarters as a combination of earnings, declining storage gas levels and collections on customer accounts all contribute to higher cash levels. During the first and fourth quarters, operating cash flows generally decrease due to the combination of increasing natural gas storage levels and rising customer receivable balances.

Cash provided by operating activities was approximately $14,698,000 in fiscal 2019, $13,504,000 in fiscal 2018 and $12,981,000 in fiscal 2017. Cash provided by operating activities increased by nearly $1.2 million over last year primarily as the net result of several items including net income, depreciation, estimated provision for rate refund, gas in storage and change in over/under collection of gas costs, offset by equity in earnings and additional pension funding. Although net income increased by $1.4 million, most of the earnings growth derived from the non-cash $2.1 million growth in equity in earnings on the investment in MVP. Increased depreciation contributed more than $500,000 in additional operating cash, related to the increasing investment in natural gas infrastructure. The combination of lower commodity prices during the summer injection period and lower storage levels contributed $1.1 million in additional cash over last year. The net rate refund estimate increased by $1.2 million due to the collection of revenues in excess of management's estimate of the final rate award related to the non-gas base rate application, net of the partial refunding of the excess tax revenues collected in rates prior to the implementation of the new non-gas rates in January 2019. Over-collections of gas cost increased by more than $3.4 million over the same period last year. Natural gas prices spiked in December and futures prices at the time indicated that natural gas commodity prices would remain at an elevated level during the winter months. Based on this information, the Company filed its quarterly PGA adjustment reflecting higher prices; however, commodity prices quickly declined to levels below the prior year during the second and third fiscal quarters resulting in the move to an over-collected position. A $1.2 million decrease in cash resulted from the change in prepaid income taxes, as adjustments were made in the prior year to reduce estimated tax payments as a result of TCJA. Accounts payable and accrued expenses used an additional $2.9 million due to reduction in accounts payable balances associated with lower gas costs and additional funding provided to the pension plan as reflected in Note 9. The table below summarizes the significant operating cash flow components:

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	Years Ended September 30,
Cash Flows From Operating Activities:	2019			2018			Increase (Decrease)
Net Income	$	8,698,412		$	7,297,205		$	1,401,207
Depreciation	7,600,852			7,090,169			510,683
Equity in earnings	(3,020,348		)	(938,531		)	(2,081,817		)
Gas in storage	1,178,889			74,698			1,104,191
Prepaid income taxes	(320,297		)	959,142			(1,279,439		)
Change in over-collection of gas costs	1,084,735			(2,360,972		)	3,445,707
Deferred taxes	684,028			755,994			(71,966		)
Accounts payable and accrued expenses	(2,745,377		)	191,054			(2,936,431		)
Rate refund	2,507,422			1,320,167			1,187,255
Other	(970,612		)	(885,131		)	(85,481		)
Net cash provided by operating activities	$	14,697,704		$	13,503,795		$	1,193,909

Cash Flows Used in Investing Activities:

Investing activities primarily consist of expenditures related to investment in Roanoke Gas' utility plant projects, which includes replacing aging natural gas pipe with new plastic or coated steel pipe, improvements to the LNG plant and gas distribution system facilities and expansion of its natural gas system to meet the demands of customer growth, as well as the continued investment by Midstream in the MVP. Roanoke Gas' expenditures related to its pipeline renewal program and other system and infrastructure improvements were nearly $21.9 million in fiscal 2019 compared to $23.3 million in fiscal 2018 and $20.7 million in fiscal 2017. Roanoke Gas renewed 8.4 miles of natural gas distribution main and replaced 875 service lines to customers in fiscal 2019. This compares to 8.3 miles of main and 496 service lines in fiscal 2018 and 9 miles of main and 459 service lines in fiscal 2017. The current renewal program is focused on the replacement of pre-1973 first generation plastic pipe. In addition, the Company’s capital expenditures included costs to extend natural gas distribution mains and services to 553 new customers in fiscal 2019 compared to 451 new customers in fiscal 2018 and 499 new customers in fiscal 2017. Roanoke Gas is constructing two gate stations to access the MVP and has nearly completed the extension of the gas distribution system to connect to these stations. These two stations will provide additional gas supply as well as provide natural gas to currently unserved areas once MVP is operational. The LNG facility is being upgraded with the installation of two new boilers and a new natural gas generator. The MVP interconnect projects and the LNG upgrades account for 70% of the construction work in progress as of September 30, 2019. Fiscal 2018 projects included a major system reinforcement to increase capacity within certain areas of the Company's natural gas distribution system, the extension of gas service to a new industrial park, which included system reinforcement to the surrounding service area, and progress toward extending Roanoke Gas' distribution pipeline to interconnect with the MVP. Depreciation covered approximately 35% of the current year's capital expenditures compared to 30% for 2018 and 31% for 2017, with the balance provided from other operating cash flows and borrowings.

Capital expenditures are expected to remain at elevated levels over the next few years. The Company is continuing its focus on replacing the remaining pre-1973 first generation plastic pipe with modern polyethylene pipe. This renewal project is expected to be completed by 2024. The current capital budget for fiscal 2020 is expected to be on a level consistent with fiscal 2019 and 2018. Under this budget, the Company plans to complete its interconnect with the MVP, finish the LNG upgrades, conduct system reinforcements and expand service to new customers. The Company expects to increase its borrowing activity, as well as consider additional equity investment, to meet the funding requirements of these planned expenditures.

Investing cash flows also reflect Midstream's $20,965,907 fiscal 2019 funding of its participation in the LLC. Midstream's total expected funding increased to between $53 and $55 million as discussed below, with anticipated cash investment for fiscal 2020 to be as much as $15 million. Funding for the investment in the LLC is provided through the $26 million credit facility, which matures in 2020 and two unsecured notes in the combined amount of $24 million. The Company is in the process of negotiating additional funding to meet the projected increase as well as an extension of the credit facility beyond 2020. More information regarding the credit facility is provided in Note 7 and under the Equity Investment in Mountain Valley Pipeline section below.

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Cash Flows Provided by Financing Activities:

Financing activities generally consist of borrowings and repayments under debt agreements, issuance of stock and the payment of dividends. Net cash flows provided by financing activities were $29,516,000, $20,841,000 and $9,938,000 in fiscal 2019, 2018 and 2017, respectively. As mentioned above, the Company uses its line-of-credit to fund seasonal working capital and provide temporary financing for capital projects, which is then converted into longer-term debt or equity financing. The increase in financing cash flows derived from Midstream's net borrowings of more than $22 million to finance its investment in MVP and the issuance of notes by Roanoke Gas. The Company also realized $1.7 million from the issuance of stock through DRIP activity and the exercise of options. Dividend payments exceeded $5.2 million as the annualized dividend rate per share increased from $0.62 to $0.66. In fiscal 2018, Resources issued 700,000 shares of stock through an equity offering for $15.1 million and invested the proceeds in Roanoke Gas to convert a portion of the debt financing of the capital budget provided by the line-of-credit to equity by refinancing the outstanding balance under the line-of-credit. The Company’s consolidated capitalization was 44.5% equity and 55.5% long-term debt at September 30, 2019, exclusive of unamortized debt expense. This compares to 53.0% equity and 47.0% long-term debt at September 30, 2018. The long-term debt as a percent of long-term capitalization increased from last year due to the debt issues listed below.

In June 2019, Midstream entered into two unsecured promissory notes and loan agreements in the total aggregate principal amount of $24,000,000. The first note was for a 7-year term in the amount of $14,000,000 at an interest rate of 30-day LIBOR plus 115 basis points. Midstream entered into a related swap agreement to convert the variable interest rate to a 3.24% fixed rate. The second note was for a 5-year term in the amount of $10,000,000 at an interest rate of 30-day LIBOR plus 120 basis points. Midstream also entered into a swap agreement on this note to convert the variable interest rate to a 3.14% fixed rate.

On June 5, 2019, Roanoke Gas entered into an agreement to issue notes in the aggregate principal amount of $10,000,000. These notes are scheduled to be issued on the day of closing currently proposed for December 6, 2019. These notes will have a 10-year term from the date of issue at a fixed interest rate of 3.60%. The proceeds from these notes will be used to finance a portion of Roanoke Gas' capital budget.

On March 28, 2019, Roanoke Gas issued notes in the aggregate principal amount of $10,000,000. These notes have a 12-year term with a fixed interest rate of 4.41%.

On March 26, 2019, Roanoke Gas entered into a new unsecured line-of-credit agreement with a two-year term expiring March 31, 2021, replacing the prior line-of-credit agreement scheduled to expire March 31, 2020. The new agreement maintains the same variable interest rate based on 30-day LIBOR plus 100 basis points and availability fee of 15 basis points applied to the unused balance on the note. The agreement retains the multi-tiered borrowing limits to accommodate seasonal borrowing demands and minimize borrowing costs. The total available borrowing limits during the term of the agreement range from $3,000,000 to $30,000,000. As the agreement is for a two-year term, amounts drawn against the new agreement are generally considered to be non-current.

On February 19, 2019, Midstream entered into an agreement with the lending institutions to amend its existing non-revolving credit agreement and related notes that provide financing for the MVP project. The amendment increased total borrowing limits to $50 million through the date of maturity to meet the projected funding requirements for completion of the MVP. With the exception of the increase in borrowing limits, all remaining terms under the notes remain unchanged including the variable-interest rate based on 30-day LIBOR plus 135 basis points. Midstream used the proceeds from the two notes issued in June 2019 to pay down the balance on the notes. As the notes were issued under a non-revolving credit agreement, the borrowing limit under this credit facility was reduced from $50 million to $26 million.

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, 2019, the estimated recorded and unrecorded obligations are as follows:

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Recorded contractual obligations:	Less than 1 year		1-3 Years		4-5 Years		After 5 Years		Total
Long-Term Debt - Notes Payable (1)	$	—	$	23,012,200	$	10,000,000	$	62,500,000	$	95,512,200
Long-Term Debt - Line of Credit (2)	—		8,172,473		—		—		8,172,473
Total	$	—	$	31,184,673	$	10,000,000	$	62,500,000	$	103,684,673
(1) See Note 7 to the consolidated financial statements.
(2) See Notes 6 and 7 to the consolidated financial statements. New line-of-credit agreement executed for a 2-year term, expiring March 31, 2021. Amounts drawn against agreement are considered non-current as they are not subject to repayment within 12-months.

Unrecorded contractual obligations, not reflected in consolidated balance sheets in accordance with US GAAP:	Less than 1 year		1-3 Years		4-5 Years		After 5 Years		Total
Pipeline and Storage Capacity (3)	$	11,532,130	$	22,391,052	$	12,944,441	$	1,950,134	$	48,817,757
Gas Supply (4)	—		—		—		—		—
Interest on Line-of-Credit (5)	40,806		22,750		—		—		63,556
Interest on Notes Payable (6)	3,509,997		5,902,370		3,185,711		15,396,752		27,994,830
Pension Plan Funding (7)	—		—		—		—		—
Investment in MVP (8)	14,917,024		1,354,456		—		—		16,271,480
Franchise Agreements (9)	110,521		231,088		245,161		1,818,339		2,405,109
Other Obligations (10)	207,085		228,116		3,596		12,105		450,902
Total	$	30,317,563	$	30,129,832	$	16,378,909	$	19,177,330	$	96,003,634
(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 12 to the consolidated financial statements.
(5) Accrued interest on line-of-credit balance at September 30, 2019, including minimum facility fee on unused line-of-credit. See Note 6 to the consolidated financial statements.
(6) Calculated interest payments notes payable included in Note 7 to the consolidated financial statements.
(7) Estimated minimum funding requirement assuming application of credit balances in plan to offset funding. Minimum funding requirements beyond five years is not available. See Note 9 to the consolidated financial statements for the planned funding in fiscal 2019.
(8) Projected remaining funding of the Company's 1% interest in the LLC as entered into on October 1, 2015.
(9) Franchise tax obligations due Roanoke City, Salem City and Town of Vinton per 20-year term agreements. See Note 12 to the consolidated financial statements.
(10) Various lease, maintenance, equipment and service contracts.

Equity Investment in Mountain Valley Pipeline

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

Management believes the investment in the LLC will be beneficial for the Company, its shareholders and southwest Virginia. In addition to the Midstream's potential returns from its investment in the LLC, Roanoke Gas will benefit from another delivery source of natural gas into its distribution system. Currently, Roanoke Gas is served by two pipelines and a liquefied natural gas storage facility. Damage to or interruption of 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 will reduce the impact from such an event. In addition, the current pipeline path provides the Company with a more economically feasible opportunity to provide natural gas service to currently unserved areas within the Company's certificated service territory.

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On October 13, 2017, FERC issued the CPCN for the MVP. In January 2018, FERC began issuing Notices to Proceed, which granted the LLC permission to begin construction activities as the LLC also had received the necessary federal permits and the required Virginia and West Virginia environmental agency permits specified by FERC. Since construction began on the pipeline, the LLC has encountered various challenges, including pipeline protesters, legal challenges to various federal and state permits resulting in stop orders and FERC intervention. In July 2018, the Fourth Circuit rescinded permits allowing the pipeline to cross a 3.6 mile section of the Jefferson National Forest. In October 2018, the same court vacated the West Virginia water crossing permits with the Army Corp of Engineers subsequently pulling the related Virginia permits. In October 2019, FERC issued a project-wide order halting forward-construction progress in response to the October 11, 2019, order by the Fourth Circuit granting a stay of MVP's Biological Opinion and Incidental Take Statement issued by the U.S. Fish and Wildlife Service in November 2017. The FERC order directed activity on the pipeline to be focused on restoration and stabilization activities to protect the environment along the pipeline. The LLC is currently working with all regulatory entities and the Fourth Circuit to resolve these issues and the managing partner anticipates the reinstatement of these permits and authorization.

As a result of the most recent action by FERC, the managing partner of the LLC has revised the timeline for completing the MVP. The full in-service date for the pipeline to be operational is now targeted for late 2020. Although the total MVP project is approximately 90% completed, additional time is needed to resolve the issues above for the remaining construction to be completed. Furthermore, these delays have resulted in a revised estimate for the total project cost of between $5.3 and $5.5 billion, of which Midstream's portion is expected to be between $53 million and $55 million. The additional delays in completing the project combined with the increased costs will reduce the corresponding return on investment, absent a regulatory action, which could provide for the recovery of these higher costs. With the recently revised extended time line and higher projected costs, Midstream will need additional funding to fulfill its obligation. The Company is in the process of negotiating with Midstream's existing debt holders for additional funding and an extension of the credit facility beyond 2020. See Note 15 regarding an increase in the Company's participation in MVP and corresponding $1.6 million expected funding increase in its investment.

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

On April 11, 2018, the LLC announced the MVP Southgate project, which is a planned 70 mile pipeline extending from the MVP mainline in Virginia to delivery points in North Carolina. Midstream will be a less than 1% investor in the Southgate project and, based on current project cost estimates, will invest between $1.8 million and $2.5 million toward the project. On November 6, 2018, the LLC filed with FERC the formal application request to construct the Southgate pipeline. Unlike with its investment in the MVP, where the Company was an important member of the project and where the pipeline would benefit Roanoke Gas by providing additional natural gas access to its distribution system, Midstream's participation in the Southgate project is for investment purposes only. The targeted in-service date for Southgate is the end of calendar 2020. Any further delays in the completion of the MVP will extend the completion date of Southgate.

Regulatory and Tax Reform

On October 10, 2018, Roanoke Gas filed a general rate case application requesting an annual increase in customer non-gas base rates of approximately $10.5 million. This application incorporated into the non-gas base rates the impact of tax reform, non-SAVE utility plant investment, increased operating costs, recovery of regulatory assets and SAVE plan investments and related costs previously recovered through the SAVE rider. The new non-gas base rates were placed into effect for gas service rendered on or after January 1, 2019, subject to refund, pending audit by SCC staff, hearing and final order by the SCC.

On June 28, 2019, the SCC staff issued their report and recommendations related to the rate application. The SCC staff report included a recommendation for a non-gas rate increase of approximately $6.5 million. Management reviewed the SCC staff report and submitted rebuttal testimony to certain proposed adjustments included in the report. At the hearing held on August 14 and 15, the Company addressed specific differences with SCC staff, including the proposed return on equity, the exclusion of certain infrastructure items from rate base, changes in customer class rate design and the exclusion of a portion of the regulatory assets associated with the ESAC costs. The hearing examiner's report is not expected until December 2019, with a final order expected from the SCC in early 2020. Based on its assessment of the

28

SCC staff report and the rebuttal testimony and evidence presented at the hearing, management has established a provision for a refund of revenues collected in excess of management's expectations regarding the final rate award. On November 19, 2019, the hearing examiner issued his report, which was subsequently revised on November 26, 2019. Although the revised report indicated a more favorable result than reflected in management's estimates, no adjustment was made to the rate refund estimate included in the September 30, 2019 financial statements, as recent rate orders from the SCC Commissioners have differed from the findings included in the hearing examiners' reports. The Company will continue to monitor information and refine its assumptions regarding its refund estimates until such time as the SCC issues its final order and new billing rates are finalized.

Since its prior rate case in 2013, Roanoke Gas has deferred costs attributable to compliance and safety related expenses. These ESAC expenses were above and beyond a base line for those costs previously provided for in non-gas base rates and have been included in the current rate application for recovery over a five-year period. As noted above, the SCC staff report recommended excluding a portion of these costs from rate recovery. The Company has evaluated the situation and adjusted the valuation based on its assessment of the resolution. If the ultimate result is different from management's assessment, any difference would be further adjusted following a final order from the SCC.

As noted above, the general rate case application incorporated the effects of tax reform, which reduced the federal tax rate for the Company from 34% to 21%. Roanoke Gas recorded two regulatory liabilities to account for this change in the federal tax rate. The first regulatory liability relates to the excess deferred taxes associated with the regulated operations of Roanoke Gas. As Roanoke Gas had a net deferred tax liability, the reduction in the federal tax rate required the revaluation of these excess deferred income taxes to the 21% rate at which the deferred taxes are expected to reverse. The excess net deferred tax liability for Roanoke Gas' regulated operations was transferred to a regulatory liability, while the revaluation of excess deferred taxes on the unregulated operations of the Company was recognized in income tax expense in the first quarter of fiscal 2018. A majority of the regulatory liability for excess deferred taxes was attributable to accelerated tax depreciation related to utility property. In order to comply with the IRS normalization rules, these excess deferred income taxes must be refunded to customers and flowed through income tax expense based on the average remaining life of the corresponding assets, which approximates 28 years. The current and non-current portions are reflected in regulatory liabilities and detailed in Note 1.

The second regulatory liability relates to the excess revenues collected from customers. The non-gas base rates used since the passage of the TCJA in December 2017 through December 2018 were derived from a 34% federal tax rate. As a result, the Company over-recovered from its customers the difference between the federal tax rate at 34% and the 24.3% blended rate in fiscal 2018 and 21% in fiscal 2019. To comply with an SCC directive issued in January 2018, Roanoke Gas recorded a refund for the excess revenues collected in fiscal 2018 and the first quarter of fiscal 2019. Beginning with the implementation of the new non-gas base rates in January 2019, Roanoke Gas began returning the excess revenues to customers over a 12-month period. The estimated refund amounts for both the excess deferred taxes and the excess revenues associated with the reduction in the federal income tax rate were subject to review and adjustment by the SCC, which was done by its staff in connection with its audit of the rate case application. The SCC staff report agreed with the refund amounts reflected in the Company's financial statements, and, assuming no changes as a result of the hearing examiner's report or by the Commissioners, these amounts will be reflected in the final order.

The Company continues to recover the costs of its infrastructure replacement program through its SAVE Plan. The original SAVE Plan was designed to facilitate the accelerated replacement of aging natural gas pipe by providing a mechanism for the Company to recover the related depreciation and expenses and return on rate base of the additional capital investment without the filing of a formal application for an increase in non-gas base rates. Since the implementation and approval of the original SAVE Plan in 2012, the Company has modified, amended or updated the Plan each year to incorporate various qualifying projects. In May 2019, the Company filed its most recent SAVE Plan and Rider, which continues the focus on the ongoing replacement of pre-1973 plastic pipe and the replacement of a natural gas transfer station as well as extending the SAVE Plan to September 30, 2024. In September 2019, the SCC approved the updated SAVE Plan and Rider effective with the October 2019 billing cycle. The new SAVE Rider is designed to collect approximately $1.1 million in annual revenues, an increase from the approximate $500,000 in annual revenues under the prior SAVE rates. With the inclusion of all previous SAVE investments through December 31, 2018 into the base non-gas rate application, the current SAVE Rider reflects only the recovery of qualifying SAVE Plan investments made since January 2019. In addition, the SAVE application includes a refund factor to return approximately $543,000 in SAVE revenue over-collections from 2018, primarily resulting from the effect of the reduction in the federal income tax rate.

As noted above, Roanoke Gas contracts with a third-party asset manager to manage its pipeline transportation, storage rights and gas supply inventories and deliveries. In return for the right to utilize the excess capacities of the

29

transportation and storage rights, the asset manager credits Roanoke Gas monthly for an amount referred to as a utilization fee. In June 2018, the SCC issued an order, retroactive to April 1, 2018, approving implementation of an incentive mechanism, whereby the Company shares the utilization fee with its customers. Under the incentive mechanism beginning April 1 each year, customers receive the initial $700,000 of the utilization fee collected through reduced gas costs, and thereafter, every additional dollar received during the annual period is split 25% to the Company and 75% to its customers. Being in effect for the entire 2019 fiscal year, revenue sharing revenues increased by $313,000 over fiscal 2018.

On February 7, 2019, the SCC issued a final order granting a CPCN to furnish gas service to all of Franklin County, Virginia. If the Company does not furnish gas service to the designated area within five years of the date of the order, the CPCN granting authority to serve Franklin County will be terminated. All other CPCNs held by the Company are for territories currently served by Roanoke Gas and are intended for perpetual duration.

On August 8, 2019, the SCC issued an order granting Roanoke Gas' authority to issue up to $40 million in short-term debt and up to $100 million of long-term debt and/or common equity. This order replaces the prior financing authorization that expired on September 30, 2019. The new authorization request is for 5 years ending on September 30, 2024 and will allow Roanoke Gas to continue to finance its infrastructure replacement program and system growth.

Roanoke Gas' 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 at least every five years. The previous depreciation study was completed and implemented in fiscal 2014. On June 11, 2019, Roanoke Gas submitted its current depreciation study, which incorporates all of the new and replacement infrastructure and equipment placed in service since the last study. In September 2019, the SCC administratively approved the depreciation study and directed the Company to implement the new rates retroactive to October 1, 2018. The new depreciation rates resulted in a reduction of total depreciation expense of $32,570 for fiscal 2019.

Critical Accounting Policies and Estimates

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

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

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

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

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

30

order. Under these circumstances, the Company estimates the amount of increase it anticipates will be approved based on the best available information.

The Company has recorded an estimate for a refund related to the implementation of the new non-gas base rates effective January 1, 2019. This estimate reflects management's evaluation of adjustments proposed by the SCC staff in their report issued on June 28, 2019, the rebuttal testimony provided by the Company and an assessment of the pending determinations from the hearing. This estimate could change as more information becomes available and until a final order is issued. The actual refund may be more or less than the amount included in the consolidated financial statements.

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

The Company bills its regulated natural gas customers on a monthly cycle. The billing cycle for most customers does not coincide with the accounting periods used for financial reporting. The Company accrues 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 consolidated financial statements include unbilled revenue of $1,236,384 and $911,657 as of September 30, 2019 and 2018, respectively.

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

Allowance for Doubtful Accounts - The Company evaluates the collectability of its accounts receivable balances based upon a variety of factors including loss history, level of delinquent account balances, collections on previously written off accounts and general economic conditions. The Company outsourced its credit and collections function in 2017 as part of its strategic decision to move the call center, billing and other customer service functions to a third-party provider with significant utility experience. These changes have been incorporated into the current valuation model for accounts receivable, which used historical information based on collection functions previously handled in-house.

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

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In selecting the discount rate to be used in determining the benefit liability, the Company utilized the FTSE Pension Discount Curve, formerly 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 3.03% and 3.00%, respectively, for valuing its pension plan liability and postretirement plan liability at September 30, 2019. These discount rates represent a significant decline from the 4.11% and 4.09% rates used for valuing the corresponding liabilities at September 30, 2018. The drop in the discount rates is evidenced by the change in 30-year Treasury yield, which decreased from 3.19% last year to 2.12% at September 30, 2019 as well as corporate bond rates, which experienced a similar decline. The reduction in the discount rates was the primary variable in increasing the benefit obligations of both the pension and the postretirement plan. Mortality assumptions were based on the RP-2014 Mortality Table, adjusted to 2006, with generational mortality improvements using Projection Scale MP-2018 for the current year valuation.

Over the last few years, management has focused on reducing risk in the Company's defined benefit plans with a greater emphasis on pension plan risk. In 2016, the Company offered a one-time, lump-sum payout of the pension benefit to vested employees who were not receiving payments under the plan. In 2017, the Company implemented a "soft freeze" to the pension plan whereby employees hired on or after January 1, 2017 would not be eligible to participate. Employees hired prior to that date continue to accrue benefits based on compensation and years of service. This "soft freeze" mirrored the strategy in 2000 when the Company implemented a similar freeze in its postretirement medical plan. These strategies have reduced liability growth by not allowing new employees into the plans and reducing the number of participants entitled to future benefits.

The Company also has focused on its asset investment strategy. An aggressive funding strategy combined with strong investment returns have allowed pension plan assets to increase by $10.5 million over the last three years, while liabilities increased only $6.1 million during the same period for the reasons noted above. As of September 30, 2019, the pension plan is at a 94% funded status. With future pension liability growth associated with increasing benefits limited to employees hired prior to the freeze, the Company evaluated measures that would mitigate the effect of changing interest rates on the pension liability. As the pension liability represents the present value of future pension payments, an increase in the discount rate used to value the pension obligation would reduce the liability while a reduction in the discount rate would lead to an increase in the pension liability. With plan funded status above 90%, the Company moved to a more conservative asset allocation model in fiscal 2018 by transitioning from a 60% equity and 40% fixed income allocation to a 40% equity and 60% fixed income allocation for pension assets. The fixed income portion of the investments were invested using an LDI approach. As a result, the valuation of the fixed income investments will move inversely to the corresponding pension liabilities as a result of changes in interest rates, which in turn will reduce the volatility in the plan's funded status and expense. The Company continued to retain a 40% investment in equities to provide asset growth potential to offset the growth in pension liability related to those employees continuing to accrue benefits. The Company will continue to evaluate the investment allocation as the liabilities mature and the funded status continues to improve and make adjustments as necessary. The Company has not made a change in investment allocation for the postretirement assets as increasing medical and insurance costs warrant the need for a continued higher allocation to equities for future plan asset growth potential. Though not to the same magnitude, the postretirement plan assets increased by $2 million and liabilities decreased by $0.5 million over the last three-year period.

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

Funded status - September 30, 2019	Pension			Postretirement			Total
Benefit Obligation	$	35,550,987		$	18,030,399		$	53,581,386
Fair value of assets	33,586,671			13,082,610			46,669,281
Funded status	$	(1,964,316	)	$	(4,947,789	)	$	(6,912,105	)

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

The Company annually evaluates the returns on its targeted investment allocation model as well as the overall asset allocation of its benefit plans. Understanding the volatility in the markets, the Company reviews both plans' potential

32

long-term rate of return with its investment advisors to determine the rates used in each plan's actuarial assumptions. Under the current allocation model for the pension plan, management determined that a 5.50% long-term rate of return assumption remained appropriate considering the asset allocation and market environment. Likewise, as the asset allocation remained unchanged for the postretirement plan, management determined that a 4.26% expected long-term rate of return is reasonable. Management will continue to re-evaluate the return assumptions and asset allocation and adjust both as market conditions warrant.

Management estimates that, under the current provisions regarding defined benefit pension plans, the Company will have no minimum funding requirements next year. However, management plans to continue its pension funding plan by contributing at least the minimum annual pension contribution requirement or its expense level for subsequent years. The Company currently expects to contribute approximately $800,000 to its pension plan and $400,000 to its postretirement plan in fiscal 2020 with an ongoing goal to improve both plans' funded status. The Company will continue to evaluate its benefit plan funding levels in light of funding requirements and ongoing investment returns and make adjustments, as necessary, to avoid benefit restrictions and minimize PBGC premiums.

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

Actuarial Assumptions - Pension Plan	Change in Assumption		Increase in Pension Cost		Increase in Projected Benefit Obligation
Discount rate	-0.25	%	$	145,000	$	1,497,000
Rate of return on plan assets	-0.25	%	83,000		N/A
Rate of increase in compensation	0.25	%	53,000		280,000

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

Actuarial Assumptions - Postretirement Plan	Change in Assumption		Increase in Postretirement Benefit Cost		Increase in Accumulated Postretirement Benefit Obligation
Discount rate	-0.25	%	$	39,000	$	753,000
Rate of return on plan assets	-0.25	%	32,000		N/A
Medical claim cost increase	0.25	%	78,000		722,000

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 consolidated balance sheet at fair value. In most instances, fair value is based upon quoted futures prices for natural gas commodities and interest rate futures for interest rate swaps. Changes in the commodity and futures markets will impact the estimates of fair value in the future. Furthermore, the actual market value at the point of realization of the derivative may be significantly different from the values used in determining fair value in prior financial statements. The Company had three interest-rate swaps outstanding at September 30, 2019 related to the three variable rate notes held by the Company. See Note 7 for additional information regarding the swaps.

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.

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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, 2019, the Company has $8,172,473 outstanding under its variable-rate line-of-credit with an average balance outstanding during the year of $6,049,527. The Company also had $16,012,200 outstanding under two 5-year variable rate unsecured term loans. 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 $314,128. The Company’s remaining debt is at a fixed rate or have interest rate swaps in place to convert variable rate debt to a fixed interest 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 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, 2019, the Company had no outstanding derivative instruments to hedge the price of natural gas. The Company had approximately 2,390,000 dths of gas in storage, including LNG, at an average price of $2.70 per dth compared to 2,441,000 dths at an average price of $3.13 per dth last year. The SCC currently allows for full recovery of prudent costs associated with natural gas purchases, and any additional costs or benefits associated with the settlement of derivative contracts and other price hedging techniques are passed through to customers when realized through the regulated natural gas PGA mechanism.

Item 8. Financial Statements and Supplementary Data.

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RGC Resources, Inc.

and Subsidiaries

Consolidated Financial Statements

for the Years Ended September 30, 2019, 2018

and 2017, and Report of Independent

Registered Public Accounting Firm

35

RGC RESOURCES, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

	Page
Report of Independent Registered Public Accounting Firm	37
Consolidated Financial Statements for the Years Ended September 30, 2019, 2018 and 2017:
Consolidated Balance Sheets	38
Consolidated Statements of Income	40
Consolidated Statements of Comprehensive Income	41
Consolidated Statements of Stockholders’ Equity	42
Consolidated Statements of Cash Flows	43
Notes to Consolidated Financial Statements	44

36

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

RGC Resources, Inc.

Roanoke, Virginia

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of RGC Resources, Inc. and Subsidiaries (“the Company”) as of September 30, 2019 and 2018, 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, 2019, and the related notes (collectively referred to as the financial statements). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of September 30, 2019 and 2018, and the results of its operations and its cash flows for each of the years in the three-year period ended September 30, 2019, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of September 30, 2019, based on criteria established in Internal Control-Integrated Framework - 2013 issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated December 3, 2019, expressed an unqualified opinion.

Basis for Opinion

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

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

              CERTIFIED PUBLIC ACCOUNTANTS

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

Blacksburg, Virginia

December 3, 2019

37

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

AS OF SEPTEMBER 30, 2019 AND 2018

	2019			2018
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1,631,348		$	247,411
Accounts receivable, net	3,870,211			3,744,228
Materials and supplies	1,021,882			913,889
Gas in storage	6,448,307			7,627,196
Prepaid income taxes	1,157,980			837,683
Regulatory assets	1,521,939			1,385,500
Interest rate swap	—			100,723
Other	733,525			687,972
Total current assets	16,385,192			15,544,602
UTILITY PROPERTY:
In service	237,786,964			224,854,320
Accumulated depreciation and amortization	(67,207,334		)	(63,099,306		)
In service, net	170,579,630			161,755,014
Construction work in progress	11,423,326			4,208,614
Utility plant, net	182,002,956			165,963,628
OTHER ASSETS:
Regulatory assets	12,178,853			8,862,147
Investment in unconsolidated affiliate	47,375,459			28,507,146
Interest rate swap	—			209,840
Other	411,236			472,743
Total other assets	59,965,548			38,051,876
TOTAL ASSETS	$	258,353,696		$	219,560,106

(Continued)

38

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

AS OF SEPTEMBER 30, 2019 AND 2018

	2019			2018
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Dividends payable	$	1,339,522		$	1,242,753
Accounts payable	4,483,233			5,211,032
Capital contributions payable	5,024,824			10,142,766
Customer credit balances	880,295			1,003,622
Customer deposits	1,432,031			1,421,043
Accrued expenses	3,448,000			3,080,432
Interest rate swap	147,556			—
Regulatory liabilities	4,877,603			1,990,201
Total current liabilities	21,633,064			24,091,849
LONG-TERM DEBT:
Notes payable	95,512,200			63,243,200
Line-of-credit	8,172,473			7,361,017
Less unamortized debt issuance costs	(313,315		)	(282,281		)
Long-term debt net of unamortized debt issuance costs	103,371,358			70,321,936
DEFERRED CREDITS AND OTHER LIABILITIES:
Interest rate swap	746,785			—
Asset retirement obligations	6,788,683			6,417,948
Regulatory cost of retirement obligations	11,892,352			11,163,981
Benefit plan liabilities	6,912,105			3,947,967
Deferred income taxes	12,978,523			12,585,577
Regulatory liabilities	10,934,434			11,447,736
Total deferred credits and other liabilities	50,252,882			45,563,209
COMMITMENTS AND CONTINGENCIES (Note 12)
CAPITALIZATION:
Stockholders’ Equity:
Common Stock, $5 par value; authorized 10,000,000 shares; issued and outstanding 8,073,264 and 7,994,615 shares in 2019 and 2018, respectively	40,366,320			39,973,075
Preferred stock, no par; authorized 5,000,000 shares; no shares issued and outstanding in 2019 and 2018	—			—
Capital in excess of par value	14,397,072			13,043,656
Retained earnings	30,821,917			27,438,049
Accumulated other comprehensive loss	(2,488,917		)	(871,668		)
Total stockholders’ equity	83,096,392			79,583,112
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	258,353,696		$	219,560,106

(Concluded)

See notes to consolidated financial statements.

39

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

YEARS ENDED SEPTEMBER 30, 2019, 2018 AND 2017

	2019		2018		2017
OPERATING REVENUES:
Gas utilities	$	67,306,260	$	64,341,783	$	61,252,015
Other	720,265		1,192,953		1,044,855
Total operating revenues	68,026,525		65,534,736		62,296,870
OPERATING EXPENSES:
Cost of gas - utility	32,401,123		32,091,923		28,919,625
Cost of sales - non utility	419,851		666,524		568,088
Operations and maintenance	14,089,019		12,471,428		12,573,608
General taxes	2,066,794		1,878,010		1,786,070
Depreciation and amortization	7,454,274		6,956,344		6,256,737
Total operating expenses	56,431,061		54,064,229		50,104,128
OPERATING INCOME	11,595,464		11,470,507		12,192,742
Equity in earnings of unconsolidated affiliate	3,020,348		938,531		421,646
Other income (expense), net	351,882		244,868		(658,879		)
Interest expense	3,618,551		2,461,565		1,917,254
INCOME BEFORE INCOME TAXES	11,349,143		10,192,341		10,038,255
INCOME TAX EXPENSE	2,650,731		2,895,136		3,805,390
NET INCOME	$	8,698,412	$	7,297,205	$	6,232,865
EARNINGS PER COMMON SHARE:
Basic	$	1.08	$	0.95	$	0.86
Diluted	$	1.08	$	0.95	$	0.86
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic	8,039,484		7,649,025		7,218,686
Diluted	8,078,950		7,695,712		7,256,046

See notes to consolidated financial statements.

40

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

YEARS ENDED SEPTEMBER 30, 2019, 2018 AND 2017

	2019			2018		2017
NET INCOME	$	8,698,412		$	7,297,205	$	6,232,865
Other comprehensive income, net of tax:
Interest rate swaps	(894,761		)	137,850		72,489
Defined benefit plans	(722,488		)	406,798		1,222,478
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX	(1,617,249		)	544,648		1,294,967
COMPREHENSIVE INCOME	$	7,081,163		$	7,841,853	$	7,527,832

See notes to consolidated financial statements.

41

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

YEARS ENDED SEPTEMBER 30, 2019, 2018 AND 2017

	Common Stock		Capital in Excess of Par Value			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Stockholders’ Equity
Balance - September 30, 2016	$	23,941,445	$	9,509,548		$	24,713,310		$	(2,497,231	)	$	55,667,072
Net income	—		—			6,232,865			—			6,232,865
Other comprehensive income	—		—			—			1,294,967			1,294,967
Exercise of stock options (11,225 shares)	50,250		91,991			—			—			142,241
Stock option grants	—		73,780			—			—			73,780
Cash dividends declared ($0.58 per share)	—		—			(4,195,910		)	—			(4,195,910		)
Stock split	12,029,790		(10,025,546		)	(2,004,244		)	—			—
Issuance costs	—		(96,508		)	—			—			(96,508		)
Issuance of common stock (47,187 shares)	182,745		739,220			—			—			921,965
Balance - September 30, 2017	$	36,204,230	$	292,485		$	24,746,021		$	(1,202,264	)	$	60,040,472
Net income	—		—			7,297,205			—			7,297,205
Other comprehensive income	—		—			—			544,648			544,648
Exercise of stock options (1,575 shares)	7,875		12,070			—			—			19,945
Cash dividends declared ($0.62 per share)	—		—			(4,839,514		)	—			(4,839,514		)
Issuance costs	—		(990,459		)	—			—			(990,459		)
Issuance of common stock (752,194 shares)	3,760,970		13,729,560			—			—			17,490,530
Reclassification adjustment for effect of change in tax law	—		—			234,337			(214,052		)	20,285
Balance - September 30, 2018	$	39,973,075	$	13,043,656		$	27,438,049		$	(871,668	)	$	79,583,112
Net income	—		—			8,698,412			—			8,698,412
Other comprehensive loss	—		—			—			(1,617,249		)	(1,617,249		)
Exercise of stock options (31,508 shares)	157,540		254,639			—			—			412,179
Cash dividends declared ($0.66 per share)	—		—			(5,314,544		)	—			(5,314,544		)
Issuance of common stock (47,141 shares)	235,705		1,098,777			—			—			1,334,482
Balance - September 30, 2019	$	40,366,320	$	14,397,072		$	30,821,917		$	(2,488,917	)	$	83,096,392

See notes to consolidated financial statements.

42

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

YEARS ENDED SEPTEMBER 30, 2019, 2018 AND 2017

	2019			2018			2017
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	8,698,412		$	7,297,205		$	6,232,865
Adjustments to reconcile net income to net cash provided by operations:
Depreciation and amortization	7,600,852			7,090,169			6,378,368
Cost of retirement of utility plant, net	(443,586		)	(288,222		)	(354,744		)
Stock option grants	—			—			73,780
Equity in earnings of unconsolidated affiliate	(3,020,348		)	(938,531		)	(421,646		)
Deferred income taxes	684,028			755,994			3,325,379
Other noncash items, net	488,202			163,482			203,743
Changes in assets and liabilities which provided (used) cash:
Accounts receivable and customer deposits, net	(122,165		)	(476,161		)	(191,386		)
Inventories and gas in storage	1,070,896			182,000			(462,161		)
Regulatory and other assets	(156,799		)	(138,332		)	(956,894		)
Accounts payable, customer credit balances and accrued expenses, net	(2,745,377		)	(25,902		)	(1,374,713		)
Regulatory liabilities	2,643,589			(117,907		)	528,387
Total adjustments	5,999,292			6,206,590			6,748,113
Net cash provided by operating activities	14,697,704			13,503,795			12,980,978
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for utility property	(21,884,317		)	(23,290,994		)	(20,750,181		)
Investment in unconsolidated affiliate	(20,965,907		)	(11,036,247		)	(2,759,346		)
Proceeds from disposal of utility property	20,219			160,663			16,972
Net cash used in investing activities	(42,830,005		)	(34,166,578		)	(23,492,555		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under line-of-credit	33,735,144			29,814,468			42,569,303
Repayments under line-of-credit	(32,923,688		)	(40,245,210		)	(39,334,328		)
Proceeds from issuance of unsecured notes	56,269,000			19,431,000			9,916,000
Retirement of notes payable	(24,000,000		)	—			—
Debt issuance expenses	(93,104		)	(32,678		)	(64,835		)
Proceeds from issuance of stock	1,746,661			16,520,016			967,698
Cash dividends paid	(5,217,775		)	(4,647,042		)	(4,115,873		)
Net cash provided by financing activities	29,516,238			20,840,554			9,937,965
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	1,383,937			177,771			(573,612		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	247,411			69,640			643,252
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	1,631,348		$	247,411		$	69,640
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid (refunded) during the year for:
Interest	$	3,328,130		$	2,137,782		$	1,734,178
Income taxes	2,287,000			1,180,000			726,000

See notes to consolidated financial statements.

43

RGC RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2019, 2018 AND 2017

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation—RGC Resources, Inc. is an energy services company primarily engaged in the sale and distribution of natural gas. The consolidated financial statements include the accounts of Resources and its wholly owned subsidiaries: Roanoke Gas, Diversified Energy and Midstream. Roanoke Gas is a natural gas utility, which distributes and sells natural gas to approximately 60,700 residential, commercial and industrial customers within its service areas in Roanoke, Virginia and the surrounding localities. The Company’s business is seasonal in nature as a majority of natural gas sales are for space heating during the winter season. Roanoke Gas is regulated by the SCC. Midstream is a wholly-owned subsidiary created primarily to invest in the Mountain Valley Pipeline project. Diversified Energy is inactive.

The Company follows accounting and reporting standards established by the FASB and the SEC.

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

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

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Regulatory assets and liabilities included in the Company’s consolidated balance sheets as of September 30, 2019 and 2018 are as follows:

	September 30
	2019		2018
Assets:
Current Assets:
Regulatory assets:
Accrued WNA revenues	$	569,558	$	169,602
Under-recovery of gas costs	—		922,898
ESAC assets	265,392		—
Accrued pension and postretirement medical	602,674		293,000
Other deferred expenses	84,315		—
Total current	1,521,939		1,385,500
Utility Property:
In service:
Other	11,945		11,945
Other Assets:
Regulatory assets:
Premium on early retirement of debt	1,712,808		1,826,995
Accrued pension and postretirement medical	9,414,695		5,704,718
ESAC assets	756,803		1,330,434
Other deferred expenses	294,547		—
Total non-current	12,178,853		8,862,147
Total regulatory assets	$	13,712,737	$	10,259,592
Liabilities and Stockholders' Equity:
Current Liabilities:
Regulatory liabilities:
Over-recovery of gas costs	$	161,837	$	—
Over-recovery of SAVE Plan revenues	574,181		670,034
Rate refund	3,827,588		1,320,167
Excess deferred income taxes	205,353		—
Other deferred liabilities	108,644		—
Total current	4,877,603		1,990,201
Deferred Credits and Other Liabilities:
Asset retirement obligations	6,788,683		6,417,948
Regulatory cost of retirement obligations	11,892,352		11,163,981
Regulatory liabilities:
Excess deferred income taxes	10,934,434		11,447,736
Total non-current	$	29,615,469	$	29,029,665
Total regulatory liabilities	$	34,493,072	$	31,019,866

As of September 30, 2019, the Company had regulatory assets in the amount of $13,700,792 on which the Company did not earn a return during the recovery period.

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

45

accumulated depreciation. The cost of asset removals, less salvage, is charged to “regulatory cost of retirement obligations” or “asset retirement obligations” as explained under Asset Retirement Obligations below.

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

	September 30
	2019		2018
Distribution and transmission	$	209,171,339	$	196,778,546
LNG storage	13,417,077		13,413,175
General and miscellaneous	15,198,548		14,662,599
Total utility plant in service	$	237,786,964	$	224,854,320

Provisions for depreciation are computed principally at composite straight-line rates over periods ranging from 5 to 76 years. Rates are determined by depreciation studies which are required to be performed at least every 5 years on the regulated utility assets of Roanoke Gas. In September 2019, the SCC staff approved the Company's most recent depreciation study. The SCC directed the Company to implement the new rates retroactive to October 1, 2018. As a result of the new rates, the composite weighted-average depreciation rate was 3.31% for the year ended September 30, 2019 as compared to 3.32% and 3.29% for fiscal years ended September 30, 2018 and 2017, respectively. The implementation of the new depreciation rates reduced total depreciation expense by $32,570 for fiscal 2019 and increased net income by $24,187 or less than $0.01 per share.

The composite rates are composed of two components, one based on average service life and one based on cost of retirement. As a result, the Company accrues the estimated cost of retirement of long-lived assets through depreciation expense. These retirement costs are not a legal obligation but rather the result of cost-based regulation and are accounted for under the provisions of FASB ASC No. 980. Such amounts are classified as a regulatory liability.

The Company reviews long-lived assets and certain identifiable intangibles for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. These reviews have not identified any impairments which would have a material effect on the results of operations or financial condition.

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

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

The following is a summary of the AROs:

	Years Ended September 30
	2019			2018
Beginning balance	$	6,417,948		$	6,069,993
Liabilities incurred	177,646			79,608
Liabilities settled	(177,755		)	(126,907		)
Accretion	370,844			332,537
Revisions to estimated cash flows	—			62,717
Ending balance	$	6,788,683		$	6,417,948

Cash, Cash Equivalents and Short-Term Investments—From time to time, the Company will have balances on deposit at banks in excess of the amount insured by the FDIC. The Company has not experienced any losses on these

46

accounts and does not consider these amounts to be at credit risk. As of September 30, 2019, 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
	2019			2018			2017
Beginning balance	$	103,573		$	99,456		$	76,934
Provision for doubtful accounts	220,039			169,096			84,587
Recoveries of accounts written off	96,614			78,919			110,725
Accounts written off	(309,483		)	(243,898		)	(172,790		)
Ending balance	$	110,743		$	103,573		$	99,456

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

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

Unbilled Revenues—The Company bills its natural gas customers on a monthly cycle; however, the billing cycle 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, 2019 and 2018 were $1,236,384 and $911,657, respectively.

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

Debt Expenses—Debt issuance expenses are deferred and amortized over the lives of the debt instruments. The unamortized balances are offset against the carrying value of long-term debt.

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

47

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 9 and 13.

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

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

Earnings Per Share—Basic EPS and diluted EPS are calculated by dividing net income by the weighted-average common shares outstanding during the period and the weighted-average common shares outstanding during the period plus dilutive potential common shares, respectively. Dilutive potential common shares are calculated in accordance with the treasury stock method, which assumes that proceeds from the exercise of all options are used to repurchase common stock at market value. The amount of shares remaining after the proceeds are exhausted represents the potentially dilutive effect of the securities. A reconciliation of basic and diluted EPS is presented below:

	Years Ended September 30
	2019		2018		2017
Net Income	$	8,698,412	$	7,297,205	$	6,232,865
Weighted-average common shares	8,039,484		7,649,025		7,218,686
Effect of dilutive securities:
Options to purchase common stock	39,466		46,687		37,360
Diluted average common shares	8,078,950		7,695,712		7,256,046
Earnings Per Share of Common Stock:
Basic	$	1.08	$	0.95	$	0.86
Diluted	$	1.08	$	0.95	$	0.86

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

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

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

48

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

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

The Company’s hedging and derivatives policy allows management to enter into derivatives for the purpose of managing the commodity and financial market risks of its business operations. The Company’s hedging and derivatives policy specifically prohibits the use of derivatives for speculative purposes. The key market risks that the Company may hedge against include the price of natural gas and the cost of borrowed funds.

The Company historically has entered into collars, swaps and caps for the purpose of hedging the price of natural gas in order to provide price stability during the winter months. The fair value of these instruments is recorded in the consolidated balance sheets with the offsetting entry to either under- or over-recovery of gas costs. Net income and other comprehensive income are not affected by the change in market value as any cost incurred or benefit received from these instruments is recoverable or refunded through the PGA as the SCC allows for full recovery of prudent costs associated with natural gas purchases. At September 30, 2019 and 2018, the Company had no outstanding derivative instruments for the purchase of natural gas.

The Company has three interest rate swaps associated with its variable rate debt. Roanoke Gas has a swap on its $7,000,000 term note that effectively converts the variable interest rate into a 2.30% fixed interest rate. In June 2019, Midstream entered into two variable-rate term notes in the amount of $14,000,000 and $10,000,000 with corresponding swap agreements to convert the variable interest rates into fixed rates of 3.24% and 3.14%, respectively. All swaps qualify as a cash flow hedge with changes in fair value reported in other comprehensive income. No portion of the swaps were deemed ineffective during the period.

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

Non-Cash Activity — A non-cash decrease in unconsolidated affiliate and corresponding decrease in capital contributions payable of $5,117,942 occurred for the fiscal year ended September 30, 2019, while an increase in investment in unconsolidated affiliate and corresponding increase in capital contributions payable of $9,087,262 and $767,710 occurred for the fiscal years ended September 30, 2018 and 2017, respectively.

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

49

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, 2019:
Interest rate swap:
Unrealized losses	$	(1,117,595	)	$	287,669		$	(829,926	)
Transfer of realized gains to interest expense	(87,309		)	22,474			(64,835		)
Net interest rate swap	(1,204,904		)	310,143			(894,761		)
Defined benefit plans:
Net loss arising during period	$	(962,612	)	$	247,777		$	(714,835	)
Amortization of actuarial gains	(10,305		)	2,652			(7,653		)
Net defined benefit plans	(972,917		)	250,429			(722,488		)
Other comprehensive loss	$	(2,177,821	)	$	560,572		$	(1,617,249	)
Year Ended September 30, 2018:
Interest rate swap:
Unrealized gains	$	217,773		$	(62,807	)	$	154,966
Transfer of realized gains to interest expense	(24,053		)	6,937			(17,116		)
Net interest rate swap	193,720			(55,870		)	137,850
Defined benefit plans:
Net gain arising during period	$	595,570		$	(171,775	)	$	423,795
Amortization of actuarial gains	(23,887		)	6,890			(16,997		)
Net defined benefit plans	571,683			(164,885		)	406,798
Other comprehensive income	$	765,403		$	(220,755	)	$	544,648
Year Ended September 30, 2017:
Interest rate swaps:
Unrealized gains	$	116,843		$	(44,354	)	$	72,489
Net interest rate swaps	116,843			(44,354		)	72,489
Defined benefit plans:
Net gain arising during period	$	1,715,505		$	(651,892	)	$	1,063,613
Amortization of actuarial losses	256,234			(97,369		)	158,865
Net defined benefit plans	1,971,739			(749,261		)	1,222,478
Other comprehensive income	$	2,088,582		$	(793,615	)	$	1,294,967

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

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Composition of AOCI:

	Interest Rate Swaps			Defined Benefit Plans			Accumulated Other Comprehensive Income (Loss)
Balance September 30, 2016	$	—		$	(2,497,231	)	$	(2,497,231	)
Other comprehensive income (loss)	72,489			1,222,478			1,294,967
Balance September 30, 2017	72,489			(1,274,753		)	(1,202,264		)
Other comprehensive income (loss)	137,850			406,798			544,648
Reclassification adjustment for the effect of change in tax law	20,285			(234,337		)	(214,052		)
Balance September 30, 2018	230,624			(1,102,292		)	(871,668		)
Other comprehensive income (loss)	(894,761		)	(722,488		)	(1,617,249		)
Balance September 30, 2019	$	(664,137	)	$	(1,824,780	)	$	(2,488,917	)

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

Financial Statement Reclassifications

Reclassifications to certain line items of the prior years' consolidated balance sheet and consolidated income statements were made to place them on a comparable basis with the current year. The changes to the consolidated income statements are associated with the adoption of ASU 2017-07, Compensation - Retirement Benefits, which changed the income statement location of the components of net periodic benefit costs other than service cost. The changes to the consolidated income statements for the years ended September 30, 2018 and 2017 are reflected below and discussed in more detail under the recently adopted accounting standards section.

	Year Ended September 30, 2018
	As Previously Reported	Effect of Change		As Adjusted
Operation and maintenance	12,348,890	122,538		12,471,428
Total operating expenses	53,941,691	122,538		54,064,229
Operating income	11,593,045	(122,538	)	11,470,507
Other income (expense), net	122,330	122,538		244,868
Income before income taxes	10,192,341	—		10,192,341

	Year Ended September 30, 2017
	As Previously Reported		Effect of Change		As Adjusted
Operation and maintenance	13,100,041		(526,433	)	12,573,608
Total operating expenses	50,630,561		(526,433	)	50,104,128
Operating income	11,666,309		526,433		12,192,742
Other income (expense), net	(132,446	)	(526,433	)	(658,879	)
Income before income taxes	10,038,255		—		10,038,255

The changes to the balance sheet relate to aggregating regulatory assets and liabilities that had been previously included in other financial statement line items into their own financial statement line item. This change allows for better presentation in the financial statements.

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	September 30, 2018
	As Previously Reported	Effect of Change		As Adjusted
Current Assets:
Accounts receivable, net	3,913,830	(169,602	)	3,744,228
Under-recovery of gas cost	922,898	(922,898	)	—
Other	980,972	(293,000	)	687,972
Regulatory assets	—	1,385,500		1,385,500
Current Liabilities:
Accrued expenses	3,750,466	(670,034	)	3,080,432
Rate refund	1,320,167	(1,320,167	)	—
Regulatory liabilities	—	1,990,201		1,990,201

Recently Adopted Accounting Standards

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) that affects any entity that enters into contracts with customers for the transfer of goods or services or transfer of non-financial assets. This guidance supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. The core principle of the new guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve that core principle, an entity should apply the following steps: (1) identify the contract with the customer, (2) identify the performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to the performance obligations in the contract, and (5) recognize revenue when, or as, the entity satisfies the performance obligation. Subsequently issued ASUs provided additional guidance to assist in the implementation of the new revenue standard.

The Company adopted ASU 2014-09 and all amendments beginning in fiscal 2019. Consistent with the modified retrospective adoption method, prior reporting period results remain unchanged and reported in accordance with ASC 605. As it relates to the Company’s contracts to deliver natural gas to customers, the guidance in ASC 606 is consistent with the guidance in ASC 605; therefore, the modified retrospective approach resulted in no cumulative catch-up to retained earnings. Furthermore, there was no significant impact to revenues recognized and no significant changes to the Company’s related business processes, systems or internal controls over financial reporting because of the new guidance. See Note 2 for additional information.

In March 2017, the FASB issued ASU 2017-07, Compensation - Retirement Benefits. The primary objective of this guidance is to improve the financial statement presentation of net periodic pension and postretirement benefit costs; however, it also changes which cost components are eligible for capitalization. The amendments in the ASU require that an employer report the service cost component in the same line item or items as other compensation costs arising from services rendered by the employees during the period. The other components of net benefit cost are required to be presented in the income statement separately from the service cost component and, if a subtotal for income from operations is presented, outside of income from operations. In addition, the ASU allows only the service cost component of periodic benefit cost to be eligible for capitalization when applicable. This change to capitalization eligibility differs from the treatment currently applied by the Company and from allowed regulatory accounting.

The Company adopted the new guidance in fiscal 2019 and has reclassified the other components of net periodic benefit costs for prior years to other income (deductions) in the non-operating section of the consolidated income statements. The impact to the income statement for the adoption of this ASU is reflected under the Financial Statement Reclassifications section above. The Company also implemented the change in capitalization costs on a prospective basis. This change did not have a significant impact on the Company's consolidated financial statements.

In January 2016, the FASB issued ASU 2016-01, Financial Instruments - Overall: Recognition and Measurement of Financial Assets and Financial Liabilities. The ASU enhances the reporting model for financial instruments to provide users of the financial statements with more useful information through several provisions, including the following: (1) requires equity investments, excluding investments accounted for under the equity method, be measured at fair value with changes in fair value recognized in net income, (2) simplifies the impairment assessment of equity investments without readily determinable fair values, (3) eliminates the requirement to disclose the method(s) and significant

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assumptions used to estimate the fair value that is required to be disclosed for financial instruments measured at amortized cost on the balance sheet, (4) requires entities to use the exit price notion when measuring the fair value of financial instruments for disclosure purposes, and (5) requires separate presentation of financial assets and financial liabilities by measurement category and form of financial asset on the balance sheet or the accompanying notes to the financial statements. The Company adopted the ASU in fiscal 2019. The new guidance did not have a material effect on its financial position, results of operations or cash flows. See Note 13 for more information on fair value.

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

Recently Issued Accounting Standards

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

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

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

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

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allowing related implementation costs to be capitalized and amortized over time, rather than directly expensed. Management does not currently expect the new guidance to have a material effect on its financial position, results of operations or cash flows.

Other accounting standards that have been issued or proposed by the FASB or other standard–setting bodies are not currently applicable to the Company or are not expected to have a significant impact on the Company’s financial position, results of operations and cash flows.

2. REVENUE

The Company assesses new contracts and identifies related performance obligations for promises to transfer distinct goods or services to the customer. Revenue is recognized when performance obligations have been satisfied. In the case of Roanoke Gas, the Company contracts with its customers for the sale and/or delivery of natural gas.

The following tables summarize revenue by customer, product and income statement classification for the years ended September 30:

	2019
	Gas utility			Non-utility		Total operating revenues
Natural Gas (Billed and Unbilled):
Residential	$	39,519,618		$	—	$	39,519,618
Commercial	22,562,265			—		22,562,265
Industrial and Transportation	4,770,657			—		4,770,657
Revenue reductions (TCJA) (1)	(523,881		)	—		(523,881		)
Other	592,156			720,265		1,312,421
Total contracts with customers	66,920,815			720,265		67,641,080
Alternative Revenue Programs	385,445			—		385,445
Total operating revenues	$	67,306,260		$	720,265	$	68,026,525
	2018
	Gas utility			Non-utility		Total operating revenues
Natural Gas (Billed and Unbilled):
Residential	$	38,926,710		$	—	$	38,926,710
Commercial	22,158,226			—		22,158,226
Industrial and Transportation	4,316,526			—		4,316,526
Revenue reductions (TCJA) (1)	(1,320,167		)	—		(1,320,167		)
Other	690,787			1,192,953		1,883,740
Total contracts with customers	64,772,082			1,192,953		65,965,035
Alternative Revenue Programs	(430,299		)	—		(430,299		)
Total operating revenues	$	64,341,783		$	1,192,953	$	65,534,736
	2017
	Gas utility			Non-utility		Total operating revenues
Natural Gas (Billed and Unbilled):
Residential	$	34,462,456		$	—	$	34,462,456
Commercial	19,913,853			—		19,913,853
Industrial and Transportation	4,400,731			—		4,400,731
Other	693,435			1,044,855		1,738,290
Total contracts with customers	59,470,475			1,044,855		60,515,330
Alternative Revenue Programs	1,781,540			—		1,781,540
Total operating revenues	$	61,252,015		$	1,044,855	$	62,296,870

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⁽¹⁾ Accrued refund associated with excess revenue collected in tariff rates associated with the reduction in federal income tax rates. See Note 3 for more information.

Gas utility revenues

Substantially all of Roanoke Gas’ revenues are derived from rates authorized by the SCC as reflected in its tariffs. Based on its evaluation, the Company has concluded that these tariff-based revenues fall within the scope of ASC 606. Tariff rates represent the transaction price. Performance obligations created under these tariff-based sales include commodity (the cost of natural gas sold to customers) and delivery (transporting natural gas through the Company’s distribution system to customers). The sale and/or delivery of natural gas to customers result in the satisfaction of the Company’s performance obligation over time as natural gas is delivered.

All customers are billed monthly based on consumption as measured by metered usage. Revenue is recognized as bills are issued for natural gas that has been delivered or transported. In addition, the Company utilizes the practical expedient that allows an entity to recognize the invoiced amount as revenue, if that amount corresponds to the value received by the customer. Since customers are billed tariff rates, there is no variable consideration in the transaction price.

Unbilled revenue is included in residential and commercial revenues above. Natural gas consumption is estimated for the period subsequent to the last billed date and up through the last day of the month. Estimated volumes and approved tariff rates are utilized to calculate unbilled revenue. The following month, the unbilled estimate is reversed, the actual usage is billed and a new unbilled estimate is calculated. The Company obtains metered usage for industrial customers at the end of each month, thereby eliminating any unbilled consideration for these rate classes.

Other revenues

Other revenues primarily consist of miscellaneous fees and charges, utility-related revenues not directly billed to utility customers and billings for non-utility activities. Non-utility (unregulated) activities provided by the Company include contract paving and other similar services. Regarding these activities, the customer is invoiced monthly based on services provided. The Company utilizes the practical expedient allowing revenue to be recognized based on invoiced amounts. The transaction price is based on a contractually predetermined rate schedule; therefore, the transaction price represents total value to the customer and no variable price consideration exists.

Alternative Revenue Program revenues

ARPs, which fall outside the scope of ASC 606, are SCC approved mechanisms that allow for the adjustment of revenues for certain broad, external factors, or for additional billings if the entity achieves certain performance targets. The Company's ARPs include its WNA, which adjusts revenues for the effects of weather temperature variations as compared to the 30-year average, and the SAVE Plan over/under collection mechanism, which adjusts revenues for the differences between SAVE Plan revenues billed to customers in the current tariff rates and the revenues earned, as calculated based on the timing and extent of infrastructure replacement completed during the period. These amounts are ultimately collected from, or returned to, customers through future changes to tariff rates.

Customer Accounts Receivable

Accounts receivable, as reflected in the consolidated balance sheets, includes both billed and unbilled customer revenues, as well as amounts that are not related to customers. The balances of customer receivables are provided below:

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	Current Assets					Current Liabilities
	Trade accounts receivable (1)			Unbilled revenue (1)		Customer credit balances			Customer deposits
September 30, 2018	$	2,675,611		$	911,657	$	1,003,622		$	1,421,043
September 30, 2019	2,590,702			1,236,384		880,295			1,432,031
Increase (decrease)	$	(84,909	)	$	324,727	$	(123,327	)	$	10,988
(1) Included in "Accounts receivable, net" in the condensed consolidated balance sheet. Amounts shown net of reserve for bad debts.

The Company had no significant contract assets or liabilities during the period. Furthermore, the Company did not incur any significant costs to obtain contracts.

3. REGULATORY MATTERS

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

On October 10, 2018, Roanoke Gas filed a general rate case application requesting an increase in annual customer non-gas rates of $10.5 million. This application incorporated into the non-gas rate the impact of tax reform, non-SAVE utility plant investment, increased operating costs, recovery of regulatory assets associated with eligible safety activity costs and SAVE Plan investments and related costs that were previously recovered through the SAVE Rider. The new non-gas rates were placed in effect for service rendered on or after January 1, 2019, subject to refund pending audit and final order by the SCC. On June 28, 2019, the SCC staff issued their report including a recommendation for an annual non-gas rate increase of approximately $6.5 million. Management reviewed the SCC staff report and submitted rebuttal testimony in preparation for the hearing on the rate application. On August 14th and 15th, the SCC conducted a hearing on the rate application. The hearing examiner's report was not expected until December 2019 with a final order from the SCC not expected until early 2020. As a result of the assessment of the SCC staff report, in addition to the rebuttal testimony and positions taken by the Company, management has accrued an estimate for a refund for the difference between the rates placed into effect on January 1, 2019 and management's estimate of the non-gas rates that will be approved by the SCC. The amount reflected in the financial statements is an estimate and the final order could result in a higher or lower refund.

On November 19, 2019, the hearing examiner issued his report that was subsequently revised on November 26, 2019. See Note 15 for more information.

As referenced in Note 8, the TCJA reduced the federal corporate tax rate to 21%. The Company revalued its deferred tax assets and liabilities to reflect the new federal tax rate. Under the provisions of ASC 740, the corresponding adjustment to deferred income taxes generally flows directly to income tax expense. For rate regulated entities such as Roanoke Gas, these excess deferred taxes were originally recovered from its customers based on billing rates derived using a federal income tax rate of 34%. Therefore, the adjustment to the net deferred tax liabilities of Roanoke Gas, to the extent such net deferred tax liabilities are attributable to rate base or cost of service for customers, are refundable to customers. Roanoke Gas began accounting for the refund of these excess deferred taxes in fiscal 2018 along with reflecting a corresponding reduction in income tax expense. As of September 30, 2019, Roanoke Gas had approximately $11,100,000 remaining in the net regulatory liability related to these excess deferred income taxes, most of which will be refunded over a 28 year period per IRS normalization requirements. The SCC staff report on the general rate case application had no significant changes to the provision for and refund timing of the excess deferred taxes included in regulatory liabilities.

The Company has transitioned to a corporate federal income tax rate of 21% and a combined 25.74% state and federal tax rate in fiscal 2019. In January 2018, the SCC issued a directive requiring the accrual of a regulatory liability for excess revenues collected from customers attributable to the higher federal income tax rate, included as a component of customer billing rates, until such time as the SCC approves revised billing rates incorporating the lower tax rate. Effective with January 2019 customer billings, the Company began refunding the excess revenues to customers. The SCC staff report on the general rate case application had no significant changes to the provision for and refund timing of the excess deferred taxes or the refund amount for excess revenues included in regulatory liabilities. The remaining balance of excess revenues related to the reduction in the federal income tax rate and the estimated accrued rate refund

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associated with the non-gas general rate application are reflected in the rate refund line item under the regulatory liabilities as detailed in Note 1.

In June 2019, the Company submitted its updated depreciation study with the SCC staff. The depreciation study, which is based on average remaining service life, resulted in an overall composite weighted-average depreciation rate of 3.31%. In September 2019, the SCC staff approved the depreciation study filing and instructed the Company to implement the new rates retroactive to October 1, 2018. As a result, the Company recorded a $32,570 reduction in annual depreciation expense for the fiscal year ended September 30, 2019. See Note 1 for more information.

In May 2019, the Company filed with the SCC its most recent SAVE Plan and Rider update. The SAVE Plan provides a mechanism for the Company to recover the related depreciation and expenses and return on rate base of its infrastructure replacement program. The updated SAVE filing continues the replacement of first generation plastic main and related services and includes the replacement of a natural gas transfer station. The filing also proposes to extend the Company's SAVE Plan to September 30, 2024. In September 2019, the SCC issued a final order on the SAVE Plan approving the extension of the SAVE Plan through September 30, 2024 and authorizing a SAVE Rider that provides up to $1.1 million in revenue in fiscal 2020 for SAVE Plan investment since January 1, 2019 and proposed fiscal 2020 SAVE investment. The SCC also approved the True-up factor to provide for the refund of approximately $543,000 in over-collected balance from the 2018 SAVE Plan.

4. SEGMENT INFORMATION

Operating segments are defined as components of an enterprise for which separate financial information is available and is evaluated regularly by the Company's chief operating decision maker in deciding how to allocate resources and assess performance. The Company uses operating income and equity in earnings to assess segment performance.

Intersegment transactions are recorded at cost.

The reportable segments disclosed herein are defined as follows:

Gas Utility - The natural gas segment of the Company generates revenue from its tariff rates and other regulatory mechanisms through which it provides the sale and distribution of natural gas to its residential, commercial and industrial customers.

Investment in Affiliates - The investment in affiliates segment reflects the income generated through the activities of the Company's investment in MVP and Southgate projects.

Parent and Other - Parent and other include the unregulated activities of the Company as well as certain corporate eliminations.

Information related to the segments of the Company are provided below:

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	Gas Utility		Investment in Affiliates			Parent and Other		Consolidated Total
For the Year Ended September 30, 2019:
Operating revenues	$	67,306,260	$	—		$	720,265	$	68,026,525
Depreciation	7,454,274		—			—		7,454,274
Operating income (loss)	11,458,679		(153,149		)	289,934		11,595,464
Equity in earnings	—		3,020,348			—		3,020,348
Interest expense	2,404,518		1,214,033			—		3,618,551
Income before income taxes	9,400,869		1,657,988			290,286		11,349,143
As of September 30, 2019:
Total assets	$	195,969,019	$	47,429,368		$	14,955,309	$	258,353,696
Gross additions to utility property	21,884,317		—			—		21,884,317
Gross investment in MVP and Southgate	—		20,965,907			—		20,965,907

	Gas Utility		Investment in Affiliates			Parent and Other		Consolidated Total
For the Year Ended September 30, 2018:
Operating revenues	$	64,341,783	$	—		$	1,192,953	$	65,534,736
Depreciation	6,956,344		—			—		6,956,344
Operating income (loss)	11,043,609		(92,981		)	519,879		11,470,507
Equity in earnings	—		938,531			—		938,531
Interest expense	2,079,553		382,012			—		2,461,565
Income before income taxes	9,208,921		463,541			519,879		10,192,341
As of September 30, 2018:
Total assets	$	181,360,570	$	28,540,978		$	9,658,558	$	219,560,106
Gross additions to utility property	23,290,994		—			—		23,290,994
Gross investment in MVP and Southgate	—		11,036,247			—		11,036,247

For the Year Ended September 30, 2017:
Operating revenues	$	61,252,015	$	—		$	1,044,855	$	62,296,870
Depreciation	6,256,737		—			—		6,256,737
Operating income (loss)	11,790,728		(69,515		)	471,529		12,192,742
Equity in earnings	—		421,646			—		421,646
Interest expense	1,778,763		138,491			—		1,917,254
Income before income taxes	9,353,085		213,641			471,529		10,038,255
As of September 30, 2017:
Total assets	$	162,727,812	$	7,496,965		$	12,910,294	$	183,135,071
Gross additions to utility property	20,750,181		—			—		20,750,181
Gross investment in MVP and Southgate	—		2,759,346			—		2,759,346

5. OTHER INVESTMENTS

In October 2015, Midstream, acquired a 1% equity interest in the Mountain Valley Pipeline, LLC. The LLC was established to construct and operate a natural gas pipeline originating in northern West Virginia and extending through south central Virginia. The proposed pipeline will have the capacity to transport approximately 2 million dths of natural gas per day.

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According to the LLC's managing partner, the anticipated project in-service date has been extended to late calendar 2020. The latest delay is due to a FERC issued project-wide stop order on October 15th, which halted construction in response to the Fourth Circuit granting a stay on a permit issued by the U.S. Fish and Wildlife Service in November 2017. The FERC order directed activity on the pipeline to be focused on restoration and stabilization activities along the pipeline. As a result of this recent FERC action and other judicial and regulatory actions, the estimated total project cost has grown to between $5.3 and $5.5 billion, thereby increasing Midstream's estimated total cash contributions to between $53 and $55 million. See Note 15 regarding an increase in the Company's participation in MVP.

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

Midstream held an approximate $47.4 million investment in the MVP and Southgate projects at September 30, 2019. Funding for Midstream's investment is provided through unsecured Promissory Notes as further described in Note 7 below.

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

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

	September 30
Balance Sheet Location of Other Investments:	2019		2018
Other Assets:
MVP	$	47,055,426	$	28,387,032
Southgate	320,033		120,114
Investment in unconsolidated affiliate	$	47,375,459	$	28,507,146
Current Liabilities:
MVP	$	4,958,260	$	10,022,652
Southgate	66,564		120,114
Capital contributions payable	$	5,024,824	$	10,142,766
	Years ended September 30
Income Statement Location of Other Investments:	2019		2018		2017
Equity in earnings of unconsolidated affiliate	$	3,020,348	$	938,531	$	421,646

	September 30
	2019		2018
Undistributed earnings, net of income taxes, of MVP in retained earnings	$	3,267,176	$	1,024,266

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

	September 30
	2019			2018		2017
Cash investment	$	20,965,907		$	11,036,247	$	2,759,346
Change in accrued capital calls	(5,117,942		)	9,087,262		767,710
Equity in earnings of unconsolidated affiliates	3,020,348			938,531		421,646
Change in investment in unconsolidated affiliates	$	18,868,313		$	21,062,040	$	3,948,702

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Summary unaudited financial statements of Mountain Valley Pipeline are presented below. Southgate financial statements, which is accounted for under the cost method, are not included:

	Income Statement
	Years Ended September 30,
	2019		2018		2017
AFUDC	$	295,430,776	$	90,096,350	$	41,848,389
Net Other Income	5,655,644		3,433,365		327,078
Net Income	$	301,086,420	$	93,529,715	$	42,175,467

	Balance Sheet
	September 30
	2019		2018
Assets:
Current Assets	$	485,323,892	$	1,237,237,542
Construction Work in Progress	4,675,267,389		2,301,591,079
Other Assets	13,190,816		18,165,856
Total Assets	$	5,173,782,097	$	3,556,994,477
Liabilities and Equity:
Current Liabilities	$	466,776,233	$	715,879,655
Capital	4,707,005,864		2,841,114,822
Total Liabilities and Equity	$	5,173,782,097	$	3,556,994,477

6. LINE-OF-CREDIT

On March 26, 2019, Roanoke Gas entered into a new unsecured line-of-credit agreement. This agreement replaced the prior line-of-credit agreement scheduled to expire March 31, 2020. The new agreement is for a 2-year term expiring March 31, 2021 with a maximum borrowing limit of $30,000,000. Amounts drawn against the new agreement are considered to be non-current, as the balance under the line-of-credit is not subject to repayment within the next 12-month period. The new agreement maintains the same variable interest rate based on 30-day LIBOR plus 100 basis points and availability fee of 15 basis points and provides multi-tiered borrowing limits to accommodate seasonal borrowing demands and minimize borrowing costs. The Company's total available borrowing limits under this agreement for the remaining term are as follows:

As of	Available Line-of-Credit
September 30, 2019	$	22,000,000
April 1, 2020	16,000,000
July 17, 2020	21,000,000
September 18, 2020	30,000,000

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A summary of the line-of-credit follows:

	September 30
	2019			2018			2017
Available line-of-credit at year-end	$	22,000,000		$	20,000,000		$	21,000,000
Outstanding balance at year-end	8,172,473			7,361,017			17,791,760
Highest month-end balance outstanding	15,801,798			17,054,377			17,791,760
Average daily balance	6,049,527			6,730,334			10,936,114
Average rate of interest during year on outstanding balances	3.40		%	2.53		%	1.92		%
Interest rate at year-end	3.02		%	3.26		%	2.23		%
Interest rate on unused line-of-credit	0.15		%	0.15		%	0.15		%

Associated with the line-of-credit is a credit agreement that contains various representations, warranties and covenants including a requirement that the Company maintain an interest coverage ratio of not less than 1.5 to 1 and a long-term debt to long-term capitalization ratio of less than 65%.

7. LONG-TERM DEBT

In June 2019, Midstream entered into two unsecured promissory notes and loan agreements. On June 12, 2019, Midstream entered into a 7-year unsecured note in the aggregate principal amount of $14,000,000 at an interest rate of 30-day LIBOR plus 115 basis points. Midstream also entered into an interest rate swap agreement that converts the note's variable interest rate to a 3.24% fixed rate. On June 13, 2019, Midstream entered into a 5-year unsecured note in the aggregate principal amount of $10,000,000 at an interest rate of 30-day LIBOR plus 120 basis points. Beginning in July 2022, the second note's terms require monthly principal repayments with the remaining unpaid balance due on June 1, 2024. In addition, Midstream entered into a second interest rate swap agreement that converts the second note's variable interest rate to a 3.14% fixed rate.

The proceeds from the notes issued in June 2019 were used to pay down Midstream's notes under the existing non-revolving credit agreement as amended in February 2019. As a result, the corresponding available balances on the prior notes declined by $24,000,000, thereby reducing the previously amended available balance from $50,000,000 to $26,000,000.

On June 5, 2019, Roanoke Gas entered into an agreement to issue notes in the aggregate principal amount of $10,000,000. These notes are scheduled to be issued on the day of closing currently proposed for December 6, 2019. These notes will have a 10-year term from the date of issue at a fixed interest rate of 3.60%. The proceeds from these notes will be used to finance a portion of Roanoke Gas' capital budget.

On March 28, 2019, Roanoke Gas entered into 12-year unsecured notes in the total principal amount of $10,000,000 with a fixed interest rate of 4.41% per annum. Proceeds from these notes were used to refinance a portion of Roanoke Gas' debt under the line-of-credit.

Roanoke Gas also has other unsecured notes at varying fixed interest rates as well as a variable-rate note with interest based on 30-day LIBOR plus 90 basis points. The variable rate note is hedged by a swap agreement, which converts the debt into a fixed-rate instrument with an annual interest rate of 2.30%.

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Long-term debt consists of the following:

	September 30
	2019				2018
	Principal		Unamortized Debt Issuance Costs		Principal		Unamortized Debt Issuance Costs
Roanoke Gas:
Unsecured senior notes payable, at 4.26%, due on September 18, 2034	$	30,500,000	$	144,811	$	30,500,000	$	154,465
Unsecured term note payable, at 30-day LIBOR plus 0.90%, November 1, 2021	7,000,000		6,948		7,000,000		10,283
Unsecured term notes payable, at 3.58% due on October 2, 2027	8,000,000		38,528		8,000,000		43,343
Unsecured term notes payable at 4.41%, due on March 28, 2031	10,000,000		36,272		—		—
Midstream:
Unsecured term notes payable, at 30-day LIBOR plus 1.35% due December 29, 2020	16,012,200		59,504		17,743,200		74,190
Unsecured term note payable, at 30-day LIBOR plus 1.15%, due June 12, 2026	14,000,000		16,252		—		—
Unsecured term note payable, at 30-day LIBOR plus 1.20%, due June 1, 2024	10,000,000		11,000		—		—
Total notes payable	$	95,512,200	$	313,315	$	63,243,200	$	282,281
Line-of-credit, at 30-day LIBOR plus 1.00%, due March 31, 2021	8,172,473		—		7,361,017		—
Total long-term debt	$	103,684,673	$	313,315	$	70,604,217	$	282,281

Debt issuance costs are amortized over the life of the related debt. As of September 30, 2019 and 2018, the Company also had an unamortized loss on the early retirement of debt of $1,712,808 and $1,826,995, respectively, which has been deferred as a regulatory asset and is being amortized over a 20 year period.

All of the debt agreements set forth certain representations, warranties and covenants to which the Company is subject, including financial covenants that require the ratio of long-term debt to long-term capitalization to not exceed 65%. All of the debt agreements except for the line-of-credit provide for priority indebtedness to not exceed 15% of consolidated total assets.

The aggregate annual maturities of long-term debt for the next five years ending after September 30, 2019 are as follows:

Year Ending September 30	Maturities
2020	$	—
2021	24,184,673
2022	7,000,000
2023	—
2024	10,000,000
Thereafter	62,500,000
Total	$	103,684,673

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8. INCOME TAXES

On December 22, 2017, the President signed into law the TCJA, which enacted significant changes to the Internal Revenue Code, including the reduction in the maximum federal corporate income tax rate from 35% to 21% effective January 1, 2018. As a result, the Company's statutory federal income tax rate transitioned from 34% in fiscal 2017 to 24.3% in fiscal 2018 and 21% in fiscal 2019. With a fiscal tax year ending in September, the Company applied a blended federal tax rate of 24.3% for the fiscal year ended September 30, 2018 as determined on the number of days of the Company's fiscal year at 34% and the number of days at 21%.

Under the provisions of ASC 740 - Income Taxes, the deferred tax assets and liabilities of the Company were revalued in fiscal 2018 to reflect the reduction in the corporate federal income tax rate. The result of this revaluation was a reduction in the net deferred tax liability of approximately $9 million, including approximately $11.8 million reclassified to regulatory liability, a $3 million gross up to reflect pre-tax basis, and $0.26 million increase in income tax expense related to unregulated operations for fiscal 2018. The excess deferred income taxes are reflected on a pretax basis to appropriately contemplate future tax consequences in the periods when the regulatory liability is settled. The excess deferred taxes related to the depreciable property is being returned to customers through reduced billings over the remaining weighted average useful life of the property with a corresponding reduction in income tax expense.

The details of income tax expense are as follows:

	Years Ended September 30
	2019		2018		2017
Current income taxes:
Federal	$	1,698,215	$	1,831,085	$	72,368
State	268,488		308,057		407,643
Total current income taxes	1,966,703		2,139,142		480,011
Deferred income taxes:
Federal	272,079		440,282		3,129,925
State	411,949		315,712		195,454
Total deferred income taxes	684,028		755,994		3,325,379
Total income tax expense	$	2,650,731	$	2,895,136	$	3,805,390

Income tax expense for the years ended September 30, 2019, 2018 and 2017 differed from amounts computed by applying the U.S. federal income tax rate to earnings before income taxes due to the following:

	Years Ended September 30
	2019			2018			2017
Income before income taxes	$	11,349,143		$	10,192,341		$	10,038,255
Corporate federal income tax rate	21.0		%	24.3		%	34.0		%
Income tax expense computed at the federal statutory rate	$	2,383,320		$	2,476,739		$	3,413,007
State income taxes, net of federal income tax benefit	537,545			472,193			398,044
Revaluation of unregulated deferred taxes to 21%	—			256,444			—
Net amortization of excess deferred taxes on regulated operations	(212,896		)	(264,106		)	—
Tax benefit recognized on stock compensation	(96,499		)	(68,364		)	(26,421		)
Other, net	39,261			22,230			20,760
Total income tax expense	$	2,650,731		$	2,895,136		$	3,805,390

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

	September 30
	2019		2018
Deferred tax assets:
Allowance for uncollectibles	$	28,503	$	26,658
Accrued pension and postretirement medical benefits	782,592		897,834
Regulatory effect of change in federal income tax rate	2,867,383		2,946,649
Accrued vacation	150,882		160,001
Over-recovery of gas costs	23,979		—
Cost of gas held in storage	590,495		591,899
Deferred compensation	803,979		716,843
Interest rate swap	230,204		—
Rate refund	130,063		339,812
Other	261,125		298,129
Total gross deferred tax assets	5,869,205		5,977,825
Deferred tax liabilities:
Utility plant	18,132,022		17,982,215
Under-recovery of gas costs	—		255,570
MVP investment	705,193		245,678
Other	10,513		79,939
Total gross deferred tax liabilities	18,847,728		18,563,402
Net deferred tax liability	$	12,978,523	$	12,585,577

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, 2016 are no longer subject to examination.

9. EMPLOYEE BENEFIT PLANS

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

The postretirement plan provides certain health care, supplemental retirement and life insurance benefits to retired employees who meet specific age and service requirements. Employees hired prior to January 1, 2000 are eligible to participate in the postretirement plan. Employees must have a minimum of 10 years of service and retire after attaining the age of 55 in order to vest in the postretirement plan. Retiree contributions to the plan are based on the number of years of service to the Company as determined under the pension plan.

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Employers who sponsor defined benefit plans must recognize the funded status of defined benefit pension and other postretirement plans as an asset or liability in their statements of financial position and recognize changes in that funded status in the year in which the changes occur through comprehensive income. For pension plans, the benefit obligation is the projected benefit obligation, and for other postretirement plans, the benefit obligation is the accumulated benefit obligation. The Company established a regulatory asset for the portion of the obligation expected to be recovered in rates in future periods. The regulatory asset is adjusted for the amortization of the transition obligation and recognition of actuarial gains and losses. The portion of the obligation attributable to the unregulated operations of the holding company is recognized in other comprehensive income.

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

	Pension Plan						Postretirement Plan
	2019			2018			2019			2018
Accumulated benefit obligation	$	30,927,973		$	25,199,762		$	18,030,399		$	16,207,322
Change in benefit obligation:
Benefit obligation at beginning of year	$	28,850,299		$	29,657,347		$	16,207,322		$	17,666,812
Service cost	537,268			665,235			132,882			167,220
Interest cost	1,166,728			1,088,180			648,944			640,602
Actuarial (gain) loss	5,901,915			(1,727,767		)	1,530,522			(1,774,320		)
Benefit payments, net of retiree contributions	(905,223		)	(832,696		)	(489,271		)	(492,992		)
Benefit obligation at end of year	$	35,550,987		$	28,850,299		$	18,030,399		$	16,207,322
Change in fair value of plan assets:
Fair value of plan assets at beginning of year	$	28,184,697		$	26,418,671		$	12,924,957		$	12,691,162
Actual return on plan assets, net of taxes	3,907,197			1,798,722			346,924			426,787
Employer contributions	2,400,000			800,000			300,000			300,000
Benefit payments, net of retiree contributions	(905,223		)	(832,696		)	(489,271		)	(492,992		)
Fair value of plan assets at end of year	$	33,586,671		$	28,184,697		$	13,082,610		$	12,924,957
Funded status	$	(1,964,316	)	$	(665,602	)	$	(4,947,789	)	$	(3,282,365	)
Amounts recognized in the balance sheet consist of:
Noncurrent liabilities	$	(1,964,316	)	$	(665,602	)	$	(4,947,789	)	$	(3,282,365	)
Amounts recognized in accumulated other comprehensive loss:
Net actuarial loss, net of tax	$	1,047,063		$	361,215		$	777,717		$	741,077
Total amounts included in other comprehensive loss, net of tax	$	1,047,063		$	361,215		$	777,717		$	741,077
Amounts deferred to a regulatory asset:
Net actuarial loss	$	6,356,201		$	3,894,221		$	3,661,168		$	2,103,497
Amounts recognized as regulatory assets	$	6,356,201		$	3,894,221		$	3,661,168		$	2,103,497

The Company expects that approximately $90,000 before tax, of AOCI will be recognized in net periodic benefit costs in fiscal 2020 and approximately $603,000 of amounts deferred as regulatory assets will be amortized and recognized in net periodic benefit costs in fiscal 2020.

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 2019, 2018 and 2017:

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	Pension Plan						Postretirement Plan
	2019		2018		2017		2019		2018		2017
Assumptions used to determine benefit obligations:
Discount rate	3.03	%	4.11	%	3.72	%	3.00	%	4.09	%	3.69	%
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	4.11	%	3.72	%	3.42	%	4.09	%	3.69	%	3.33	%
Expected long-term rate of return on plan assets	5.50	%	7.00	%	7.00	%	4.30	%	4.84	%	4.84	%
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
	2019			2018			2017			2019			2018			2017
Service cost	$	537,268		$	665,235		$	706,677		$	132,882		$	167,220		$	183,267
Interest cost	1,166,728			1,088,180			995,598			648,944			640,602			626,822
Expected return on plan assets	(1,549,437		)	(1,862,838		)	(1,616,412		)	(547,218		)	(623,381		)	(571,513		)
Recognized loss	158,599			351,030			662,180			123,805			283,868			429,758
Net periodic benefit cost	$	313,158		$	241,607		$	748,043		$	358,413		$	468,309		$	668,334

Service cost is included in operation and maintenance expense of the consolidated income statement. All other components of net periodic benefit costs are included in the other income (expense), net line.

The assumed health care cost trend rates used in measuring the accumulated benefit obligation for the postretirement plan as of September 30, 2019, 2018 and 2017 are presented below:

	Pre 65						Post 65
	2019		2018		2017		2019		2018		2017
Health care cost trend rate assumed for next year	7.00	%	7.00	%	7.00	%	5.20	%	5.00	%	5.00	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	5.50	%	5.00	%	5.00	%	5.20	%	5.00	%	5.00	%
Year that the rate reaches the ultimate trend rate	2022		2026		2021		2019		2018		2017

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	$	136,000	$	(109,000	)
Effect on accumulated postretirement benefit obligation	2,954,000		(2,387,000		)

The primary objectives of both plans' investment policies are to maintain investment portfolios that diversify risk through prudent asset allocation parameters, achieve asset returns that meet or exceed the corresponding actuarial assumptions, achieve asset returns that are competitive with like institutions employing similar investment strategies and meet expected future benefits in both the short-term and long-term. In 2018, the Company revised its targeted pension plan investment allocation by rebalancing the assets from a 60% equity allocation to a 40% equity allocation. This change in investment strategy was in response to the pension plan's improved funded position and the implementation of a "soft freeze", which will limit future growth in liabilities as no new employees will enter the plan. The change in investment allocation will allow the opportunity to reduce investment risk and volatility in asset performance while providing for asset growth through the reduced equity exposure. As a result, the Company's assumed long-term rate of return on pension and postretirement plan assets for fiscal 2019 was adjusted down to 5.5%

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and 4.3%, respectively. The investment policy continues to provide for a range of investment allocations to allow for continued flexibility in responding to market conditions.

The Company’s target and actual asset allocation in the pension and postretirement plans as of September 30, 2019 and 2018 were:

	Pension Plan						Postretirement Plan
	Target		2019		2018		Target		2019		2018
Asset category:
Equity securities	40	%	40	%	40	%	50	%	49	%	49	%
Debt securities	60	%	59	%	59	%	50	%	50	%	50	%
Cash	—	%	1	%	1	%	—	%	1	%	1	%
Other	—	%	—	%	—	%	—	%	—	%	—	%

The assets of the plans are invested in mutual funds. The Company uses the fair value hierarchy described in Note 1 to classify these assets. The mutual funds are included under Level 2 in the fair value hierarchy as their fair values are determined based on individual prices for each security that comprises the mutual funds. Most of the individual investments are determined based on quoted market prices for each security; however, certain fixed income securities and other investments are not actively traded and are valued based on similar investments. The following tables contains the fair value classifications of the plans' assets:

			Pension Plan Fair Value Measurements - September 30, 2019
	Fair Value		Level 1		Level 2		Level 3
Asset Class:
Cash	$	371,780	$	371,780	$	—	$	—
Common and Collective Trust and Pooled Funds:
Bonds
Liability Driven Investment	19,702,561		—		19,702,561		—
Equities
Domestic Large Cap Growth	4,069,197		—		4,069,197		—
Domestic Large Cap Value	4,055,518		—		4,055,518		—
Domestic Small/Mid Cap Core	2,032,084		—		2,032,084		—
Foreign Large Cap Value	1,783,990		—		1,783,990		—
Mutual Funds:
Equities
Foreign Large Cap Growth	1,227,981		1,227,981		—		—
Foreign Large Cap Value	343,560		343,560		—		—
Total	$	33,586,671	$	1,943,321	$	31,643,350	$	—

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			Pension Plan Fair Value Measurements - September 30, 2018
	Fair Value		Level 1		Level 2		Level 3
Asset Class:
Cash	$	282,478	$	282,478	$	—	$	—
Common and Collective Trust and Pooled Funds:
Bonds
Liability Driven Investment	16,504,956		—		16,504,956		—
Equities
Domestic Large Cap Growth	3,449,486		—		3,449,486		—
Domestic Large Cap Value	3,381,285		—		3,381,285		—
Domestic Small/Mid Cap Core	1,685,352		—		1,685,352		—
Foreign Large Cap Value	1,527,796		—		1,527,796		—
Mutual Funds:
Equities
Foreign Large Cap Growth	1,060,383		1,060,383		—		—
Foreign Large Cap Value	292,961		292,961		—		—
Total	$	28,184,697	$	1,635,822	$	26,548,875	$	—

			Postretirement Plan Fair Value Measurements - September 30, 2019
	Fair Value		Level 1		Level 2		Level 3
Asset Class:
Cash	$	66,860	$	66,860	$	—	$	—
Mutual Funds
Bonds
Domestic Fixed Income	5,987,248		5,987,248		—		—
Foreign Fixed Income	611,196		611,196		—		—
Equities
Domestic Large Cap Growth	1,909,836		1,909,836		—		—
Domestic Large Cap Value	1,931,615		1,931,615		—		—
Domestic Small/Mid Cap Growth	210,251		210,251		—		—
Domestic Small/Mid Cap Value	214,034		214,034		—		—
Domestic Small/Mid Cap Core	464,526		464,526		—		—
Foreign Large Cap Growth	489,286		489,286		—		—
Foreign Large Cap Value	1,098,992		1,098,992		—		—
Foreign Large Cap Core	70,782		70,782		—		—
Other	27,984		—		27,984		—
Total	$	13,082,610	$	13,054,626	$	27,984	$	—

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			Postretirement Plan Fair Value Measurements - September 30, 2018
	Fair Value		Level 1		Level 2		Level 3
Asset Class:
Cash	$	96,117	$	96,117	$	—	$	—
Mutual Funds
Bonds
Domestic Fixed Income	5,859,588		5,859,588		—		—
Foreign Fixed Income	609,722		609,722		—		—
Equities
Domestic Large Cap Growth	1,926,076		1,926,076		—		—
Domestic Large Cap Value	1,874,643		1,874,643		—		—
Domestic Small/Mid Cap Growth	214,180		214,180		—		—
Domestic Small/Mid Cap Value	210,891		210,891		—		—
Domestic Small/Mid Cap Core	459,363		459,363		—		—
Foreign Large Cap Growth	525,720		525,720		—		—
Foreign Large Cap Value	1,090,851		1,090,851		—		—
Foreign Large Cap Core	28,786		28,786		—		—
Other	29,020		—		29,020		—
Total	$	12,924,957	$	12,895,937	$	29,020	$	—

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

Management has re-evaluated the fair value classifications for the investments in the pension and postretirement plans. The investments in mutual funds fit more closely to the Level 1 definition and have been reassigned accordingly. Prior year balances in mutual funds have been reclassified from Level 2 to Level 1 to place them on a basis consistent with the current year. All other investments remain at Level 2.

The Company expects to contribute $800,000 to its pension plan and $400,000 to its postretirement plan in fiscal 2020.

The following table reflects expected future benefit payments:

Fiscal year ending September 30	Pension Plan		Postretirement Plan
2020	$	995,393	$	633,473
2021	1,050,564		685,678
2022	1,134,262		732,085
2023	1,222,806		790,242
2024	1,316,860		794,515
2025-2029	7,825,994		4,039,665

The Company sponsors a 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 IRS. The Company matches 100% of the participant’s first 4% of contributions and 50% on the next 2% of contributions. Company matching contributions were $348,369, $338,066 and $361,702 for 2019, 2018 and 2017, respectively. The Company also provided for $21,829 and $9,637 in discretionary contributions in 2019 and 2018 for those employees hired on or after January 1, 2017.

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10. COMMON STOCK OPTIONS

The KESOP provides for the issuance of common stock options to officers and certain other full-time salaried employees to acquire shares of the Company’s common stock. As of September 30, 2019, the number of shares available for future grants was 36,000.

FASB ASC No. 718 - Compensation-Stock Compensation requires that compensation expense be recognized for the issuance of equity instruments to employees. During the fiscal year ended 2017, the Board approved stock option grants to certain officers. As required by the KESOP, each option's exercise price per share equaled the fair value of the Company's common stock on the grant date. Pursuant to the plan, the options vest over a six-month period and are exercisable over a ten-year period from the date of issuance. No options were granted in fiscal 2019 or 2018.

As the Company's stock options are not traded on the open market, the fair value of each grant is estimated on the date of grant using the Black-Scholes option pricing model including the following assumptions:

	Years Ended September 30,
	2019	2018	2017
Expected volatility	N/A	N/A	26.09%
Expected dividends	N/A	N/A	3.81%
Expected exercise term (years)	N/A	N/A	7.00
Risk-free interest rate	N/A	N/A	2.20%

The underlying methods regarding each assumption are as follows:

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

Expected dividend rate is based on historical dividend payout trends.

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

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

Forfeitures are recognized when they occur.

Stock option transactions under the Company's plans for the years ended September 30, 2019, 2018 and 2017 are summarized below.

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	Number of Shares		Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Terms (years)	Aggregate Intrinsic Value 1
Options outstanding, September 30, 2016	87,300		$	13.50	7.8	$	200,211
Options granted	25,500		16.37
Options exercised	(11,225	)	12.67
Options expired	—		—
Options forfeited	—		—
Options outstanding, September 30, 2017	101,575		14.31		7.6	1,448,338
Options granted	—		—
Options exercised	(1,575	)	12.66
Options expired	—		—
Options forfeited	—		—
Options outstanding, September 30, 2018	100,000		14.34		6.6	1,237,286
Options granted	—		—
Options exercised	(31,508	)	13.08
Options expired	—		—
Options forfeited	—		—
Options outstanding, September 30, 2019	68,492		$	14.91	6.2	$	981,170
Vested and exercisable at September 30, 2019	68,492		$	14.91	6.2	$	981,170

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

	Years Ended September 30,
	2019		2018		2017
Weighted-average grant date option fair value	$	—	$	—	$	2.89
Stock option expense	—		—		73,780
Intrinsic value of options exercised	456,002		15,256		99,929
Proceeds from exercise of stock options	412,179		19,945		142,241

11. OTHER STOCK PLANS

Dividend Reinvestment and Stock Purchase Plan

The Company offers a DRIP Plan to shareholders of record for the reinvestment of dividends and the purchase of up to $40,000 per year in additional shares of common stock of the Company. Under the DRIP, the Company issued 26,716, 31,744 and 36,446 shares in 2019, 2018 and 2017, respectively. As of September 30, 2019, the Company had 390,513 shares of stock available for issuance under the DRIP.

Restricted Stock Plan for Outside Directors

The Board of Directors of the Company implemented the RSPD in 1997. Under the RSPD, each director may elect annually to have up to 100% of his or her fees paid in shares of common stock ("Director Restricted Stock"); however, a minimum of 40% of the monthly retainer fee must be paid to each non-employee director of Resources in shares of Director Restricted Stock until such time as the director has accumulated at least 10,000 shares. The number of shares of Director Restricted Stock awarded each month is determined based on the closing sales price of Resources' common stock on the NASDAQ Global Market on the first business day of the month. The Director Restricted Stock issued under the Plan vests only in the case of a participant's death, disability, retirement, or in the event of a change in control of Resources. The Director Restricted Stock may not be sold, transferred, assigned or pledged by the participant until the shares have vested under the terms of the Plan. The shares of Director Restricted Stock will be

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forfeited to Resources by a participant's voluntary resignation during his or her term on the Board or removal for cause as a director.

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

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

	2019			2018				2017
	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	98,302	$	11.51	111,893		$	10.56	107,023	$	10.11
Granted	6,378	27.93		6,692		26.57		4,870	16.77
Vested	—	—		(20,283	)	11.20		—	—
Forfeited	—	—		—		—		—	—
End of year balance	104,680	$	12.51	98,302		$	11.51	111,893	$	10.56

The fair market value of the Director Restricted Stock included in compensation during fiscal 2019, 2018 and 2017 was $178,100, $177,800 and $99,400. No Director Restricted Stock was forfeited during fiscal 2019, 2018 or 2017.

As of September 30, 2019, the Company had 65,208 shares available for issuance under the RSPD.

RGC Resources, Inc. Restricted Stock Plan

The Board of Directors of the Company implemented the RSPO in 2017 following approval by the shareholders at the Company's annual meeting held on February 6, 2017. Under the RSPO, the Compensation Committee of the Board of Directors may grant shares of common stock ("Officer Restricted Stock") that vest over time to key employees and officers for the purpose of attracting and retaining those individuals essential to the operation and growth of the Company. The RSPO provides for certain restrictions and non-transferability requirements until minimum levels of ownership are obtained. Such restrictions may continue beyond the vesting period.

The Company assumes all officers will complete their requirements and there will be no forfeiture of the Officer Restricted Stock.

The following table reflects the officer compensation activity pursuant to the RSPO:

	2019				2018
	Shares		Weighted-Average Fair Value on Date of Grant		Shares		Weighted-Average Fair Value on Date of Grant
Beginning of year balance	6,734		$	26.33	—		$	—
Granted	10,227		29.80		10,101		26.33
Vested	(6,776	)	28.08		(3,367	)	26.33
Forfeited	—		—		—		—
End of year balance	10,185		$	28.65	6,734		$	26.33

The fair market value of the Officer Restricted Stock included as compensation during fiscal 2019 and 2018 was $282,365 and $188,388. As of September 30, 2019, the Company had 429,151 shares available for issuance under the RSPO.

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Stock Bonus Plan

Shares from the Stock Bonus Plan may be issued to certain employees and management personnel in recognition of their performance and service. Under the Stock Bonus Plan, the Company issued no shares in 2019 and 2018 and 1,628 shares valued at $30,154 in 2017. As of September 30, 2019 the Company had 4,785 shares of stock available for issuance under the Stock Bonus Plan. The Stock Bonus Plan is currently inactive and has been currently replaced by the Restricted Stock Plan.

12. COMMITMENTS AND CONTINGENCIES

Long-Term Contracts

Due to the nature of the natural gas distribution business, Roanoke Gas enters into agreements with both suppliers and pipelines to contract for natural gas commodity purchases, storage capacity and pipeline delivery capacity. Roanoke Gas obtains most of its regulated natural gas supply through an asset management contract with a third party asset manager. Roanoke Gas utilizes an asset manager to optimize the use of its transportation, storage rights, and gas supply inventories which helps to ensure a secure and reliable source of natural gas. Under the current asset management contract, Roanoke Gas has designated the asset manager to act as agent for its storage capacity and all gas balances in storage. Roanoke Gas retains ownership of gas in storage. Under provisions of this contract, Roanoke Gas is obligated to purchase its winter storage requirements from the asset manager during the spring and summer injection periods at market price. The table below details the volumetric obligations as of September 30, 2019 for the remainder of the contract period. The current asset management contract was renewed in April 2018 for a three year period which will expire in March 2021. The new contract was renewed at essentially the same terms and conditions as the prior agreement.

Year	Natural Gas Contracts (In DTHs)
2019-2020	2,071,061
2020-2021	295,866
Total	2,366,927

Roanoke Gas also has contracts for pipeline and storage capacity which extend for various periods. These capacity costs and related fees are valued at tariff rates in place as of September 30, 2019. These rates may increase or decrease in the future based upon rate filings and rate orders granting a rate change to the pipeline or storage operator. Roanoke Gas expended approximately $30,317,000, $31,137,000 and $28,496,000 under the asset management, pipeline and storage contracts in fiscal years 2019, 2018 and 2017, respectively. The table below details the pipeline and storage capacity obligations as of September 30, 2019 for the remainder of the contract period.

Year	Pipeline and Storage Capacity
2019-2020	$	11,532,130
2020-2021	11,532,130
2021-2022	10,858,922
2022-2023	7,351,348
2023-2024	5,593,093
Thereafter	3,916,965
Total	$	50,784,588

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Roanoke Gas maintains franchise agreements granted by the local cities and towns served by the Company. Roanoke Gas renewed it's franchise agreements with the City of Roanoke, the City of Salem and the Town of Vinton in 2016 for 20-year terms to expire in December 2035. Per these agreements, franchise fees increase at a rate of 3% annually throughout the term of the agreements. As of September 30, 2019, $2,405,109 in future obligations remain under the franchise agreements.

Other Contracts

The Company maintains other agreements in the ordinary course of business covering various lease, maintenance, equipment and service contracts. These agreements currently extend through December 2031 and are not material to the Company.

Legal

From time to time, the Company may become involved in litigation or claims arising out of its operations in the normal course of business. At the current time, the Company is not known to be a party to any legal proceedings that would be expected to have a materially adverse impact on its financial position, results of operations or cash flows.

Environmental Matters

Both Roanoke Gas and a previously owned gas subsidiary operated MGPs as a source of fuel for lighting and heating until the early 1950’s. A by-product of operating MGPs was coal tar, and the potential exists for tar waste contaminants at the former plant sites. While the Company does not currently recognize any commitments or contingencies related to environmental costs at either site, should the Company ever be required to remediate either site, it will pursue all prudent and reasonable means to recover any related costs, including the use of insurance claims and regulatory approval for rate case recognition of expenses associated with any work required.

13. FAIR VALUE MEASUREMENTS

The following table summarizes the Company’s financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements by level within the fair value hierarchy as defined in Note 1 as of September 30, 2019 and 2018, respectively:

			Fair Value Measurements - September 30, 2019
	Fair Value		Quoted Prices in Active Markets Level 1		Significant  Other Observable Inputs Level 2		Significant Unobservable Inputs Level 3
Liabilities:
Natural gas purchases	$	397,757	$	—	$	397,757	$	—
Interest rate swaps	894,341		—		894,341		—
Total	$	1,292,098	$	—	$	1,292,098	$	—

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

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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, 2019 and 2018, 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 non-financial assets and liabilities that are measured at fair value on a nonrecurring basis consist of its asset retirement obligations. The asset retirement obligations are measured at fair value at initial recognition based on expected future cash flows to settle the obligation.

The carrying value of cash and cash equivalents, accounts receivable, borrowings under line-of-credit, accounts payable (with the exception of the timing difference under the asset management contract), customer credit balances and customer deposits is a reasonable estimate of fair value due to the shorter-term nature of these financial instruments. The following table summarizes the fair value of the Company’s financial assets and liabilities that are not adjusted to fair value in the financial statements as of September 30, 2019 and 2018.

			Fair Value Measurements - September 30, 2019
	Carrying Amount		Quoted Prices in Active Markets Level 1		Significant Other Observable  Inputs Level 2		Significant Unobservable Inputs Level 3
Liabilities:
Notes payable	$	95,512,200	$	—	$	—	$	100,900,952
Total	$	95,512,200	$	—	$	—	$	100,900,952

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

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 or other Treasury instrument with a corresponding maturity period and estimated credit spread extrapolated based on market conditions since the issuance of the debt. The decline in interest rates during fiscal 2019 resulted in an increase in the fair value of the Company's outstanding 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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14. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Quarterly financial data for the years ended September 30, 2019 and 2018 is summarized as follows:

2019	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Operating revenues	$	21,216,747	$	25,274,959	$	11,682,950	$	9,851,869
Operating income	$	3,264,222	$	6,203,483	$	1,637,057	$	490,702
Net income	$	2,434,162	$	4,670,090	$	1,138,555	$	455,605
Earnings per share of common stock:
Basic	$	0.30	$	0.58	$	0.14	$	0.06
Diluted	$	0.30	$	0.58	$	0.14	$	0.06

2018	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Operating revenues	$	18,756,051	$	24,917,973	$	11,889,570	$	9,971,142
Operating income	$	3,644,491	$	5,276,085	$	1,835,590	$	714,341
Net income	$	2,059,462	$	3,465,929	$	1,087,355	$	684,459
Earnings per share of common stock:
Basic	$	0.28	$	0.47	$	0.14	$	0.09
Diluted	$	0.28	$	0.47	$	0.14	$	0.09

15. SUBSEQUENT EVENTS

On November 8, 2019, the Company's Board of Directors approved a pro rata increase in its participation in MVP which will result in an estimated additional $1.6 million investment above the current projected levels. As a result of this additional investment, Midstream's equity interest will increase from 1.00% to approximately 1.03% by the time the pipeline is placed in service.

On November 19, 2019, the Company received the Hearing Examiner's report on Roanoke Gas' non-gas base rate application. The estimated rate refund included in the consolidated financial statements was consistent with the findings reflected in the hearing examiner's report. On November 26, 2019, the hearing examiner issued a revised report that currently would indicate a more favorable result to the Company. However, the final order is pending from the SCC, which may result in a different outcome than recommended in the hearing examiner's revised report. Accordingly, the final non-gas rate award and corresponding rate refund may be more or less than management's estimate reflected in the September 30, 2019 consolidated financial statements.

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

As of September 30, 2019, 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, 2019.

Management routinely reviews the Company’s internal control over financial reporting and makes changes, as necessary, to enhance the effectiveness of the internal controls over financial reporting. There were no changes in the internal controls over financial reporting during the fourth quarter of the fiscal year covered by this report that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) under the Securities and Exchange Act of 1934). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation and fair presentation of financial statements for external purposes in accordance with GAAP and include those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with 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, 2019, based on the framework set forth in ”Internal Control - Integrated Framework (2013)” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based upon such evaluation, the Company concluded that, as of September 30, 2019, 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, 2019.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

RGC Resources, Inc.

Roanoke, Virginia

Opinion on Internal Control over Financial Reporting

We have audited RGC Resources, Inc. and Subsidiaries (“the Company's”)’internal control over financial reporting as of September 30, 2019, based on criteria established in Internal Control-Integrated Framework - 2013 issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of September 30, 2019, based on criteria established in Internal Control-Integrated Framework - 2013 issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets and the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows of the Company, and our report dated December 3, 2019, expressed an unqualified opinion.

Basis for Opinion

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

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

Definition and Limitation of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

              CERTIFIED PUBLIC ACCOUNTANTS

Blacksburg, Virginia

December 3, 2019

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Item 9B. Other Information.

None

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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 2020 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 2020 Annual Meeting of Shareholders of Resources, which information is incorporated herein by reference. In addition, the Board of Directors has determined that Abney S. Boxley, III and Raymond D. Smoot, Jr. are audit committee financial experts under applicable SEC rules.

For information regarding the process for identifying and evaluating candidates to be nominated as directors, see "Director Nominations" in the Proxy Statement for the 2020 Annual Meeting of Shareholders of Resources, which is incorporated herein by reference.

Information with respect to compliance with Section 16(a) of the Exchange Act, which is set forth under the caption "Section 16 (a) Beneficial Ownership Reporting Compliance" in the Proxy Statement for the 2020 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 2020 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 2020 Annual Meeting of Shareholders of Resources, is incorporated herein by reference.

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

The information pertaining to director independence is set forth under the caption “Board of Directors and Committees of the Board of Directors” and pertaining to transactions with related persons is set forth under the caption "Transactions with Related Persons" in the Proxy Statement for the 2020 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 2020 Annual Meeting of Shareholders of Resources is incorporated herein by reference.

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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.

3 (a)		Articles of Incorporation of RGC Resources, Inc. (incorporated herein by reference to Exhibit 3(a) of Registration Statement No. 33-67311, on Form S-4, filed with the Commission on November 13, 1998, and amended by Amendment No. 5, filed with the Commission on January 28, 1999)
3 (b)		Amended and Restated Bylaws of RGC Resources, Inc. (incorporated herein by reference to Exhibit 3(b) on the Form 8-K filed on February 7, 2014)
4 (a)		Specimen copy of certificate for RGC Resources, Inc. common stock, $5.00 par value (incorporated herein by reference to Exhibit 4(a) of Registration Statement No. 33-67311, on Form S-4, filed with the Commission on November 13, 1998, and amended by Amendment No. 5, filed with the Commission on January 28, 1999)
4 (b)		RGC Resources, Inc., Amended and Restated Dividend Reinvestment and Stock Purchase Plan (incorporated by reference to Exhibit 4(b) of the Form 10-K for the year ended September 30, 2014)
4 (c)		Description of RGC Resources, Inc. Common Stock (incorporated by reference to Exhibit 99.1 on Form 8-K as filed on August 10, 2017)
10 (a)	P	Firm Transportation Agreement between East Tennessee Natural Gas Company and Roanoke Gas Company dated November 1, 1993 (incorporated herein by reference to Exhibit 10(a) of the Annual Report on Form 10-K for the fiscal year ended September 30, 1994 (SEC file number reference 0-367))
10 (b)		NTS Service Agreement between Columbia Gas Transmission Corporation and Roanoke Gas Company dated September 3, 2004 (incorporated herein by reference to Exhibit 10(g)(g)(g) of the Quarterly Report on Form 10-Q for the period ended December 31, 2004)
10 (c)		FSS Service Agreement by and between Columbia Gas Transmission LLC and Roanoke Gas Company dated July 23, 2019 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed July 26, 2019)
10 (d)		FTS Service Agreement by and between Columbia Gas Transmission LLC and Roanoke Gas Company dated July 23, 2019 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed July 26, 2019)
10 (e)		SST Service Agreement by and between Columbia Gas Transmission LLC and Roanoke Gas Company dated July 23, 2019 (incorporated herein by reference to Exhibit 10.3 on Form 8-K as filed July 26, 2019)
10 (f)		FTS Service Agreement effective April 1, 2017 between Columbia Gas Transmission LLC and Roanoke Gas Company (incorporated herein by reference to Exhibit 10(f) of the Annual Report on Form 10-K as filed December 8, 2017)
10 (g)		FTS-1 Service Agreement between Columbia Gulf Transmission Corporation and Roanoke Gas Company dated September 3, 2004 (incorporated herein by reference to Exhibit 10(k)(k)(k) of the Quarterly Report on Form 10-Q for period ended December 31, 2004)
10 (h)	P	Gas Transportation Agreement, for use under FT-A rate schedule, between Tennessee Gas Pipeline Company and Roanoke Gas Company dated November 1, 1993 (incorporated herein by reference to Exhibit 10(k) of the Annual Report on Form 10-K for the fiscal year ended September 30, 1994 (SEC file number reference 0-367))

81

10 (i)	P	Gas Transportation Agreement, for use under IT rate schedule, between Tennessee Gas Pipeline Company and Roanoke Gas Company dated September 1, 1993 (incorporated herein by reference to Exhibit 10(l) of the Annual Report on Form 10-K for the fiscal year ended September 30, 1994 (SEC file number reference 0-367))
10 (j)	P	Gas Storage Contract under rate schedule FS (Market Area) Portland between Tennessee Gas Pipeline Company and Roanoke Gas Company dated November 1, 1993 (incorporated herein by reference to Exhibit 10(k)(k) of the Annual Report on Form 10-K for the fiscal year ended September 30, 1994 (SEC file number reference 0-367))
10 (k)		FTA Gas Transportation Agreement effective November 1, 1998, between East Tennessee Natural Gas Company and Roanoke Gas Company (incorporated herein by reference to Exhibit 10(s)(s) of Annual Report on Form 10-K for the fiscal year ended September 30, 1998 (SEC file reference number 0-367))
10 (l)		FTS Service Agreement effective November 1, 1999, between Columbia Gas Transmission Corporation and Roanoke Gas Company (incorporated herein by reference to Exhibit 10(p)(p) of Annual Report on Form 10-K for the fiscal year ended September 30, 2001 (SEC file reference number 0-367))
10 (m)		Firm Storage Service Agreement effective March 19, 1997, between Virginia Gas Storage Company and Roanoke Gas Company (incorporated herein by reference to Exhibit 10(w)(w) of Annual Report on Form 10-K for the fiscal year ended September 30, 1998 (SEC file reference number 0-367))
10 (n)		Firm Storage Service Agreement by and between Roanoke Gas Company and Virginia Gas Pipeline Company, dated June 1, 2001 (incorporated herein by reference to Exhibit 10(b)(b)(b) of Annual Report on Form 10-K for the fiscal year ended September 30, 2001 (SEC file number reference 0-367))
10(o)		FSS Service Agreement between Saltville Gas Storage Company L.L.C. and Roanoke Gas Company dated November 21, 2012 (incorporated herein by reference to Exhibit 10(o) of the Annual Report on Form 10-K as filed December 8, 2017)
10 (p)		Firm Pipeline Service Agreement by and between Roanoke Gas Company and Virginia Gas Pipeline Company, dated June 1, 2001 (incorporated herein by reference to Exhibit 10(c)(c)(c) of Annual Report on Form 10-K for the fiscal year ended September 30, 2001 (SEC file number reference 0-367))
10 (q)		Natural Gas Asset Management Agreement by and between Roanoke Gas Company and Sequent Energy Management LP effective April 1, 2018 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed on March 27, 2018)
10 (r)		Parental Guaranty by RGC Resources, Inc. in favor of Sequent Energy Management LP effective April 1, 2018 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed on March 27, 2018)
10 (s)		Gas Transportation Agreement between Tennessee Gas Pipeline Company and Roanoke Gas Company originally dated November 1, 1999 as amended May 17, 2016 (incorporated herein by reference to Exhibit 10.3 of Form 10-Q as filed August 4, 2016)
10 (t)		Amendment dated May 17, 2016 to Gas Transportation Agreement originally dated December 1, 1993 between Tennessee Gas Pipeline Company and Roanoke Gas Company (incorporated herein by reference to Exhibit 10.1 of Form 10-Q as filed August 4, 2016)
10 (u)		Amendment dated May 17, 2016 to Gas Transportation Agreement originally dated November 1, 1993 between Tennessee Gas Pipeline Company and Roanoke Gas Company (incorporated herein by reference to Exhibit 10.2 of Form 10-Q as filed August 4, 2016)
10 (v)		Gas Transportation Agreement, for use under FT-A rate schedule between Midwestern Gas Transmission Company and Roanoke Gas Company dated March 11, 2019 (incorporated herein by reference to Exhibit 10.1 on Form 10-Q as filed May 6, 2019)

82

10 (w)	P	Certificate of Public Convenience and Necessity for Bedford County dated February 21, 1966 (incorporated herein by reference to Exhibit 10(o) of Registration Statement No. 33-36605, on Form S-2, filed with the Commission on August 29, 1990, and amended by Amendment No. 1, filed with the Commission on September 19, 1990)
10 (x)	P	Certificate of Public Convenience and Necessity for Roanoke County dated October 19, 1965 (incorporated herein by reference to Exhibit 10(p) of Registration Statement No. 33-36605, on Form S-2, filed with the Commission on August 29, 1990, and amended by Amendment No. 1, filed with the Commission on September 19, 1990)
10 (y)	P	Certificate of Public Convenience and Necessity for Botetourt County dated August 30, 1966 (incorporated herein by reference to Exhibit 10(q) of Registration Statement No. 33-36605, on Form S-2, filed with the Commission on August 29, 1990, and amended by Amendment No. 1, filed with the Commission on September 19, 1990)
10 (z)	P	Certificate of Public Convenience and Necessity for Montgomery County dated July 8, 1985 (incorporated herein by reference to Exhibit 10(r) of Registration Statement No. 33-36605, on Form S-2, filed with the Commission on August 29, 1990, and amended by Amendment No. 1, filed with the Commission on September 19, 1990)
10 (a)(a)	P	Certificate of Public Convenience and Necessity for Franklin County dated September 8, 1964 (incorporated herein by reference to Exhibit 10(t) of Registration Statement No. 33-36605, on Form S-2, filed with the Commission on August 29, 1990, and amended by Amendment No. 1, filed with the Commission on September 19, 1990)
10 (b)(b)	P	Resolution of the Council for the Town of Fincastle, Virginia dated June 8, 1970 (incorporated herein by reference to Exhibit 10(f) of Registration Statement No. 33-11383, on Form S-4, filed with the Commission on January 16, 1987)
10 (c)(c)	P	Resolution of the Council for the Town of Troutville, Virginia dated November 4, 1968 (incorporated herein by reference to Exhibit 10(g) of Registration Statement No. 33-11383, on Form S-4, filed with the Commission on January 16, 1987)
10 (d)(d)		Certificate of Public Convenience and Necessity for Franklin County dated March 5, 2019 (incorporated herein by reference to Exhibit 10.2 on Form 10-Q as filed May 6, 2019)
10 (e)(e)		Gas Franchise Agreement between the City of Roanoke, Virginia, and Roanoke Gas Company dated December 14, 2015 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed December 16, 2015)
10 (f)(f)		Gas Franchise Agreement between the City of Salem, Virginia, and Roanoke Gas Company dated December 14, 2015 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed December 16, 2015)
10 (g)(g)		Gas Franchise Agreement between the Town of Vinton, Virginia, and Roanoke Gas Company dated November 17, 2015 (incorporated herein by reference to Exhibit 10.3 on Form 8-K as filed December 16, 2015)
10 (h)(h)		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 (i)(i)		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 (j)(j)		RGC Resources, Inc. Amended And Restated Restricted Stock Plan for Outside Directors (incorporated herein by reference to Exhibit 10(i)(i) to the Annual Report on Form 10-K as filed December 8, 2017)
10 (k)(k)		RGC Resources, Inc. Restricted Stock Plan (incorporated herein by reference to Exhibit 10.1 of Form 8-K as filed February 9, 2017)
10 (l)(l)		Change in Control Agreement between RGC Resources, Inc. and Mr. John S. D'Orazio effective May 1, 2018 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed May 1, 2018)

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10 (m)(m)	Change in Control Agreement between RGC Resources, Inc. and Mr. Paul W. Nester effective May 1, 2018 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed May 1, 2018)
10 (n)(n)	Change in Control Agreement between RGC Resources, Inc. and Mr. Robert L. Wells, II effective May 1, 2018 (incorporated herein by reference to Exhibit 10.3 on Form 8-K as filed May 1, 2018)
10 (o)(o)	Change in Control Agreement between RGC Resources, Inc. and Mr. Carl J. Shockley effective May 1, 2018 (incorporated herein by reference to Exhibit 10.4 on Form 8-K as filed May 1, 2018)
10 (p)(p)	Revolving Line of Credit Note in the original principal amount of $30,000,000 by Roanoke Gas Company in favor of Wells Fargo Bank, N.A. dated as of March 26, 2019 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed March 28, 2019)
10 (q)(q)	Credit Agreement by and between Roanoke Gas Company and Wells Fargo Bank, N.A. dated March 31, 2016 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed April 4, 2016)
10 (r)(r)	First Amendment to Credit Agreement by and between Roanoke Gas Company and Wells Fargo Bank, N.A. dated March 27, 2017 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed March 29, 2017)
10 (s)(s)	Second Amendment to Credit Agreement by and between Roanoke Gas Company and Wells Fargo Bank, N.A. dated as of March 26, 2018 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed March 27, 2018)
10 (t)(t)	Third Amendment to Credit Agreement by and between Roanoke Gas Company and Wells Fargo Bank, N.A. dated as of March 26, 2019 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed March 28, 2019)
10 (u)(u)	Continuing Guaranty by RGC Resources, Inc. in favor of Wells Fargo Bank, N.A. dated March 31, 2016 (incorporated by reference to Exhibit 10.3 on Form 8-K as filed April 4, 2016)
10 (v)(v)	Indemnification and Cost Sharing Agreement by and between RGC Resources, Inc., Bluefield Gas Company and ANGD, LLC (incorporated herein by reference to Exhibit 10.2 on Form 10-K as filed December 21, 2007 (SEC file number reference 0-367))
10 (w)(w)	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 (x)(x)	Unconditional Parent Guaranty by RGC Resources, Inc. in favor of each of the holders of the notes: The Prudential Life Insurance Company of America, PAR U Hartford Life & Annuity Comfort Trust and PRUCO Life Insurance Company of New Jersey (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed August 4, 2014)
10 (y)(y)	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 (z)(z)	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 (a)(a)(a)	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 (b)(b)(b)	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 (c)(c)(c)	Credit Agreement between RGC Midstream, LLC, Union Bank & Trust and Branch Banking and Trust Company dated December 29, 2015 (incorporated by reference to Exhibit 10.1 on Form 8-K as filed December 31, 2015)

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10 (d)(d)(d)	First Amendment to Credit Agreement between RGC Midstream, LLC and the lenders Union Bank & Trust and Branch Banking and Trust dated April 11, 2018 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed April 12, 2018)
10 (e)(e)(e)	Second Amendment to Credit Agreement between RGC Midstream, LLC and the lenders Union Bank & Trust and Branch Banking and Trust dated February 19, 2019 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed February 19, 2019)
10 (f)(f)(f)	Amended and Restated Note in the principal amount of $30,000,000 in favor of Union Bank &Trust due December 29, 2020 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed February 19, 2019)
10 (g)(g)(g)	Amended and Restated Note in the principal amount of $20,000,000 in favor of Branch Banking and Trust due December 29, 2020 (incorporated herein by reference to Exhibit 10.3 on Form 8-K as filed February 19, 2019)
10 (h)(h)(h)	Guaranty by RGC Resources, Inc. in favor of Union Bank & Trust and Branch Banking and Trust Company dated December 29, 2015 (incorporated herein by reference to Exhibit 10.4 on Form 8-K as filed December 31, 2015)
10 (i)(i)(i)	Term Loan Agreement dated November 1, 2016 in favor of Branch Banking and Trust Company dated November 1, 2016 (incorporated by reference to Exhibit 10.1 on Form 8-K as filed November 7, 2016)
10 (j)(j)(j)	Promissory Note dated November 1, 2016 in the principle amount of $7,000,000 in favor of Branch Banking and Trust Company due November 1, 2021 (incorporated by reference to Exhibit 10.2 on Form 8-K as filed November 7, 2016)
10 (k)(k)(k)	Guaranty Agreement between RGC Resources, Inc. and Branch Banking and Trust Company on behalf of Roanoke Gas Company dated November 1, 2016 (incorporated herein by reference to Exhibit 10.3 on Form 8-K as filed November 7, 2016)
10 (l)(l)(l)	Swap Agreement by and between Roanoke Gas Company and Branch Banking and Trust Company dated November 1, 2016 (incorporated herein by reference to Exhibit 10.4 on Form 8-K as filed November 7, 2016)
10 (m)(m)(m)	Private Shelf Agreement by and between Roanoke Gas Company and Prudential Investment Management, Inc. for the pre-authorization to issue notes up to $29,500,000 in total during the term of the agreement (incorporated herein by reference to Exhibit 10.4 on Form 8-K as filed October 4, 2017)
10 (n)(n)(n)	Unsecured Note in the original principal amount of $4,000,000 by and between Roanoke Gas Company and PRUCO Life Insurance Company of New Jersey, dated October 2, 2017 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed October 4, 2017)
10 (o)(o)(o)	Unsecured Note in the original principal amount of $4,000,000 by and between Roanoke Gas Company and Prudential Arizona Reinsurance Captive Company, dated October 2, 2017 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed October 4, 2017)
10 (p)(p)(p)	Unconditional Parent Guaranty by RGC Resources, Inc. in favor of each of the holders of the notes: The PRUCO Life Insurance Company of New Jersey and the Prudential Arizona Reinsurance Captive Company (incorporated herein by reference to Exhibit 10.3 on Form 8-K as filed October 4, 2017)
10(q)(q)(q)	Unsecured Note in the original principal amount of $5,000,000 by and between Roanoke Gas Company and Highmark, Inc. dated March 28, 2019 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed March 29, 2019)
10(r)(r)(r)	Unsecured Note in the original principal amount of $3,000,000 by and between Roanoke Gas Company and Prudential Arizona Reinsurance Term Company dated March 28, 2019 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed March 29, 2019)
10(s)(s)(s)	Unsecured Note in the original principal amount of $2,000,000 by and between Roanoke Gas Company and The Prudential Insurance Company of America dated March 28, 2019 (incorporated herein by reference to Exhibit 10.3 on Form 8-K as filed March 29, 2019)

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10(t)(t)(t)		Unconditional Guaranty by and between RGC Resources, Inc. and Prudential Investment Management and each Prudential Affiliate which is a party to the borrowing (incorporated herein by reference to Exhibit 10.4 on Form 8-K as filed March 29, 2019)
10(u)(u)(u)		Promissory Note in the original principal amount of $14,000,000 by and between RGC Midstream, LLC and Atlantic Union Bank, dated June 12, 2019 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed June 17, 2019)
10(v)(v)(v)		Loan Agreement between RGC Midstream, LLC and Atlantic Union Bank, dated June 12, 2019 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed June 17, 2019)
10(w)(w)(w)		Unconditional Guaranty by and between RGC Resources, Inc. and Atlantic Union Bank (incorporated herein by reference to Exhibit 10.3 on Form 8-K as filed June 17, 2019)
10(x)(x)(x)		Swap Agreement by and between RGC Midstream, LLC and Atlantic Union Bank, dated June 12, 2019 (incorporated herein by reference to Exhibit 10.4 on Form 8-K as filed June 17, 2019)
10(y)(y)(y)		Promissory Note in the original principal amount of $10,000,000 by and between RGC Midstream, LLC and Branch Banking and Trust, dated June 13, 2019 (incorporated herein by reference to Exhibit 10.5 on Form 8-K as filed June 17, 2019)
10(z)(z)(z)		Loan Agreement between RGC Midstream, LLC and Branch Banking and Trust Company, dated June 13, 2019 (incorporated herein by reference to Exhibit 10.6 on Form 8-K as filed June 17, 2019)
10(a)(a)(a)(a)		Unconditional Guaranty by and between RGC Resources, Inc. and Branch Banking and Trust Company (incorporated herein by reference to Exhibit 10.7 on Form 8-K as filed June 17, 2019)
10(b)(b)(b)(b)		Swap Agreement by and between RGC Midstream, LLC and Branch Banking and Trust Company, dated June 13, 2019 (incorporated herein by reference to Exhibit 10.8 on Form 8-K as filed June 17, 2019)
10(c)(c)(c)(c)	**	Third Amended and Restated Limited Liability Company Agreement of Mountain Valley Pipeline, LLC dated April 6, 2018 (incorporated by reference to Exhibit 10.1 on the Quarterly Report on Form 10-Q as filed May 7, 2018)
10(d)(d)(d)(d)		Guaranty Agreement by RGC Resources, Inc. in favor of Mountain Valley Pipeline, LLC (incorporated herein by reference to Exhibit 10.2 on Form 10-Q as filed May 7, 2018)
10(e)(e)(e)(e)		Consulting Agreement between John S. D'Orazio, retiring CEO, and Roanoke Gas Company dated December 2, 2019
13		Annual Report
21		Subsidiaries of the Company
23		Consent of Brown, Edwards & Company, LLP
31.1		Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer
31.2		Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer
32.1	*	Section 1350 Certification of Principal Executive Officer
32.2	*	Section 1350 Certification of Principal Financial Officer
101		The following documents from the Registrant’s Annual Report on Form 10-K for the years ended September 30, 2019, 2018 and 2017, formatted in XBRL (eXtensible Business Reporting Language); Consolidated Balance Sheets at September 30, 2019 and 2018, (ii) Consolidated Statements of Income for the years ended September 30, 2019, 2018 and 2017, (iii) Consolidated Statements of Comprehensive Income for the years ended September 30, 2019, 2018 and 2017, (iv) Consolidated Statements of Stockholders’ Equity for the years ended September 30, 2019, 2018 and 2017, (v) Consolidated Statements of Cash Flows for the years ended September 30, 2019, 2018 and 2017, and (vi) Notes to Consolidated Financial Statements.

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* These certifications are being furnished solely to accompany this annual report pursuant to 18 U.S.C. Section 1350, and are not being filed for purposes of Section 18 of the Securities Exchange Act of 1934 and are not to be incorporated by reference into any filing of the registrant, whether made before or after the date hereof, regardless of any general incorporation language in such filing.

** Confidential treatment has been granted with respect to portions of this exhibit, indicated by asterisks, which has been filed separately with the Securities and Exchange Commission.

P These original exhibits were filed with the SEC in paper form and therefore are not hyper-linked to the original filing.

Item 16. Form 10-K Summary.

Not applicable.

87

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Annual Report on Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized.

RGC RESOURCES, INC.
By:	/S/    PAUL W. NESTER	December 3, 2019
	Paul W. Nester	Date
	Vice President, Secretary, Treasurer and CFO
	(principal accounting and financial officer)

88

Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report on Form 10-K has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

/S/    JOHN S. D'ORAZIO	December 3, 2019	President and Chief Executive Officer, Director
John S. D'Orazio	Date
/S/    PAUL W. NESTER	December 3, 2019	Vice President, Treasurer and CFO (principal accounting and financial officer)
Paul W. Nester	Date
/S/    JOHN B. WILLIAMSON, III	December 3, 2019	Chairman of the Board and Director
John B. Williamson, III	Date
/S/    NANCY H. AGEE	December 3, 2019	Director
Nancy H. Agee	Date
/S/    ABNEY S. BOXLEY, III	December 3, 2019	Director
Abney S. Boxley, III	Date
/S/  T. JOE CRAWFORD	December 3, 2019	Director
T. Joe Crawford	Date
/S/    MARYELLEN F. GOODLATTE	December 3, 2019	Director
Maryellen F. Goodlatte	Date
/S/    J. ALLEN LAYMAN	December 3, 2019	Director
J. Allen Layman	Date
/S/    S. FRANK SMITH	December 3, 2019	Director
S. Frank Smith	Date
/S/    RAYMOND D. SMOOT, JR.	December 3, 2019	Director
Raymond D. Smoot, Jr.	Date

89