UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
Form10-K
ANNUAL REPORT PURSUANT TO SECTION 13 or
(Mark One)
☒
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended September 30, 20192020
OR
☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 000-26591
RGC RESOURCES, INC.
(Exact name of registrant as specified in its charter)
Virginia54-1909697RGC Resources, Inc.
(Exact name of Registrant as Specified in its Charter)
Virginia54-1909697
(State or other jurisdictionOther Jurisdiction of
incorporation Incorporation or organization)
Organization)
(I.R.S. Employer
Identification No.)
519 Kimball Avenue,Ave., N.E., Roanoke, VARoanoke,VA24016
(Address of principal executive offices)Principal Executive Offices)(Zip Code)
Registrant’s telephone number, including area code (540) 777-4427
(Registrant’s Telephone Number, Including Area Code)
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 ValueRGCONASDAQ Global Market
Securities registered pursuant to Section 12(g) of the Act:
None

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 filerx☐
Non-accelerated filer
¨ (Do not check if smaller reporting company)
☒		Smaller reporting companyx☒
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
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 equityRGC Resources, Inc. as of March 31, 2020, the last business day of the registrant’sits most recently completed second fiscal quarter: March 31, 2019. $199,858,266quarter, based on the last sale price on that date, as reported by NASDAQ, was approximately $219,692,926.

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the last practicable date.
ClassOutstanding at November 22, 201925, 2020
COMMON STOCK,Common Stock, $5 PAR VALUEPar Value8,081,123 SHARES8,170,701
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the RGC Resources, Inc. Proxy Statement for the 20202021 Annual Meeting of Shareholders are incorporated by reference into Part III hereof.



TABLE OF CONTENTS
Page Number
2
4
Item 1.
5
Item 1A.
8
Item 1B.
13
Item 2.
13
Item 3.
14
Item 4.
14
TABLE OF CONTENTS
Page Number
Item 5.
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
1415
Item 6.
1615
Item 7.
16
Item 7A.
3331
Item 8.
3431
Item 9.
7770
Item 9A.
7770
Item 9B.
7971
Item 10.
8072
Item 11.
8072
Item 12.
8072
Item 13.
8072
Item 14.
8072
Item 15.
8173
Item 16.
8779
8880




GLOSSARY OF TERMS
AFUDCAllowance for Funds Used During Construction
AOCI/AOCLAccumulated Other Comprehensive Income (Loss)
AROAsset Retirement Obligation
ARPAlternative 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.targets
ASCAccounting Standards Codification
ASUAccounting Standards Update as issued by the FASB
CompanyRGC Resources, Inc. or Roanoke Gas Company
CPCNCOVID-19 or CoronavirusA pandemic disease that causes respiratory illness similar to the flu with symptoms such as coughing, fever, and in more severe cases, difficulty in breathing
CPCNCertificate of Public Convenience and Necessity
Diversified EnergyDiversified Energy Company, a wholly-owned subsidiary of Resources
DRIPDividend Reinvestment and Stock Purchase Plan of RGC Resources, Inc.
DTHDecatherm (a measure of energy used primarily to measure natural gas)
EPSEarnings Per Share
ERISAEmployee Retirement Income Security Act of 1974
ESACEligible 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.safety
FASBFinancial Accounting Standards Board
FDICFederal Deposit Insurance Corporation
FERCFederal Energy Regulatory Commission
Fourth CircuitU.S. Fourth Circuit Court of Appeals
GAAPU.S.Accounting Principles Generally Accepted Accounting Principlesin the United States
HDDHeating 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.Fahrenheit
ICCInventory carrying cost revenue, an SCC approved rate structure that mitigates the impact of financing costs on natural gas inventory.inventory
IRSInternal Revenue Service
KEYSOPRGC Resources, Inc. Key Employee Stock Option Plan
LDILiability Driven Investment approach, a strategy which reduces the volatility in the pension and postretirement plans’plan's funded status and expense by matching the duration of the fixed income investments with the duration of the corresponding pension liabilities.liabilities
LIBORLondon Inter-Bank Offered Rate
2

LLCMountain Valley Pipeline, L.L.C., a joint venture established to design, construct and operate the Mountain Valley Pipeline and MVP Southgate.

Southgate
LNGLiquefied natural gas, the cryogenic liquid form of natural gas of whichgas. Roanoke Gas operates and maintains a plant capable of producing and storing up to 200,000 dth of liquefied natural gas in liquid form.
MGPManufactured gas plant
MidstreamRGC Midstream, L.L.C., a wholly-owned subsidiary of Resources created to invest in pipeline projects including MVP and Southgate.Southgate
MVPMountain Valley Pipeline, a FERC-regulated 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.system
Normal WeatherThe average number of heating degree days over the most recent 30-year period
PBGCPension Benefit Guaranty Corporation
Pension PlanDefined benefit plan that provides pension benefits to employees hired prior to January 1, 2017 who meet certain years of service criteria.criteria
PGAPurchased Gas Adjustment, a regulatory mechanism, which adjusts natural gas customer rates to reflect changes in the forecasted cost of gas and actual gas costs.costs
Postretirement PlanDefined 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.criteria
ResourcesRGC Resources, Inc., parent company of Roanoke Gas, Midstream and Diversified Energy
RGCOTrading symbol for RGC Resources, Inc. on the NASDAQ Global Stock Market
Roanoke GasRoanoke Gas Company, a wholly-owned subsidiary of Resources
RSPDRGC Resources, Inc. Restricted Stock Plan for Outside Directors
RSPORGC Resources, Inc. Restricted Stock Plan for Officers
SAVESteps to Advance Virginia's Energy, Plan, a regulatory mechanism per Chapter 26 of Title 56 of the Code of Virginia 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 PlanSteps to Advance Virginia's Energy Plan, a regulatory mechanism to recover theincluding related depreciation and expenses and provide return on rate base, ofin eligible infrastructure replacement projects on a prospective basis without the filing of a formal application for increases in non-gas base rates.rate application
SAVE RiderPlanSteps to Advance Virginia's Energy Plan, the Company's proposed and approved operational replacement plan and related spending under the SAVE regulatory mechanism
SAVE RiderSteps to Advance Virginia's Energy Plan Rider, the rate component of the SAVE Plan as approved by the SCC that is billed monthly to the natural gas utility’sCompany’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.investment
SCCVirginia State Corporation Commission, the regulatory body with oversight responsibilities of the utility operations of Roanoke Gas.Gas
SECU.S. Securities and Exchange Commission
SouthgateMountain 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 IndexStandard & Poor’s 500 Stock Index
TCJATax Cuts and Jobs Act of 2017
WNAWeather Normalization Adjustment, an ARP mechanism which adjusts revenues for the effects of weather temperature variations as compared to the 30-year average.average
Some of the terms above may not be included in this filing

3



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.

4

PART I
 
Item 1.
Business.

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.
 2020
 CustomersVolumeRevenueMargin
Residential91.3 %35 %60 %63 %
Commercial8.6 %27 %30 %23 %
Industrial0.1 %38 %8 %12 %
Other Utility0.0 %0 %1 %1 %
Other Non-Utility0.0 %0 %1 %1 %
Total Percent100.0 %100 %100 %100 %
Total Value61,964 10,357,174 $63,075,391 $38,783,925 
 2019
 CustomersVolumeRevenueMargin
Residential91.2 %39 %58 %60 %
Commercial8.7 %31 %33 %26 %
Industrial0.1 %30 %7 %11 %
Other Utility0.0 %0 %1 %2 %
Other Non-Utility0.0 %0 %1 %1 %
Total Percent100.0 %100 %100 %100 %
Total Value60,741 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

  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, 20182020 and 2017.2019. 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
5

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%8% of total revenues, even thoughalthough they represent 30%38% of total natural gas deliveries for the year ended September 30, 20192020 and approximately 10%11% to 11%12% 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, 2019,2020, approximately 67%59% of the Company’s total DTH of natural gas deliveries and 76%72% of the residential and commercial deliveries were made in the five-month period of November through March. Total natural gas deliveries were approximately 10.4 million DTH in fiscal 2020 and 9.9 million DTH in fiscal 2019 and 2018 and 8.6 million DTH in fiscal 2017.2019.

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 itscurrent contract with the asset manager in March 2018. The new agreement expireswas extended to March 31, 2021.2022.


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 20-year term, of 20 years and willset to expire December 31, 2035. In 2019, the SCC issued a final order granting a CPCN to furnish gas to all of Franklin County. Unlike the CPCNs for the other counties served by Roanoke Gas, the Franklin County CPCN will 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 init is placed into service.


6

Management anticipates that the Company will be able to renew all of its franchises when they expire. Thereprior to their current expiration date; however, there can be no assurance however, that a given jurisdiction will not refuse to renew a franchise or will not, in connection with the renewal of a franchise, attempt to impose restrictions or conditions that could adversely affect the Company’s business operations or financial condition. 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.


EmployeesHuman Capital Resources

At September 30, 2019,2020, Resources had 106101 full-time employees, and 107 total employees. As of that date, 26which 18 employees, or 24%18%, belonged to the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied-Industrial International Union, Local No. 515 and were represented under a collective bargaining agreement. The union has been

in place at the Company since 1952. The currentunion and the Company agreed to a new collective bargaining agreement will expireeffective August 1, 2020 and expiring on July 31, 2020.2022. Management maintains an amicable relationship with the union.


The Company’s business strategy and ability to serve customers relies on employing talented professionals and attracting, training, developing and retaining a skilled workforce. This is particularly relevant as the Company is facing retirements of key personnel over the next several years.

With respect to the current COVID-19 pandemic, the Company has updated and implemented its pandemic plan to ensure the continuation of safe and reliable service to customers and to maintain the safety of the Company's employees, as well as to incorporate any new governmental guidance and rules and regulations regarding workplace safety. Since the beginning of the pandemic, the Company has been deemed an essential entity by virtue of the utility services provided through Roanoke Gas.






7

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 onDue to COVID-19, the operation ofSEC public reference room is closed until further notice. Questions about information available from the Public Reference Room canpublic reference room should be obtaineddirected to SEC staff at library@sec.gov or by calling the SEC at 1-800-SEC-0330.1-202-551-5450. The SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding the Company’s filings at www.sec.gov.
 
Item 1A.Risk Factors

Item 1A.Risk Factors

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


OPERATIONAL RISKS


Availability of sufficient and reliable pipeline capacity.


The Company is currently served directly by two interstate pipelines. These two pipelines carry 100% of the natural gas transported to the Company’s distribution system. Depending on weather conditions and the level of customer demand, failure of one or both of these interstate transmission pipelines could have a major impact on the Company’s ability to meet customer demand for natural gas and adversely affect the Company’s earnings as a result of lost revenue and the cost of service restoration. Frequent or prolonged failure could lead customers to switch to alternative energy sources. Capacity limitations on existing pipeline and storage infrastructure could impact the Company’s ability to obtain additional natural gas supplies, thereby limiting its ability to 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, fires and other natural or man-made disasters could damage or inhibit production and/or pipeline transportation facilities, which could result in decreased natural gas supplies. Decreased supplies could result in an inability to meet customer demand, service new franchise areas or lead to higher prices and/or service disruptions. Disasters could alsoincrease costs to repair damaged facilities and result in delays to restore service to interrupted customers as well as lead to additional governmental regulations that may limit production activity and/or increase production and transportation costs.





8
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. Resources maintains cyber-insurance coverage, which does not protect the Company from cyber incidents but does provide some level of protection to mitigate the financial impacts resulting from such attacks.


Volatility in the price and availability of natural gas.

Natural gas purchases represent the single largest expense of the Company. 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 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 beis facing retirements of key personnel over the next several years, the failure to replace those transition the skills and knowledge of the
departing employees with skilled andto qualified existing or new employees could increase operating costs and expose the Company to other operational, reputational and financial risks.


Geographic concentration of business activities.


The Company's business activities are concentrated in the Roanoke Valley.Valley and surrounding areas. Changes in the local economy, politics, regulations and weather patterns or other factors limiting demand for natural gas could negatively impact the Company's existing customer base, leading to declining usage patterns and financial condition of customers. Furthermore, these changes could also limit the Company's ability to serve its customers bothor add new customers within its service territory. Any of whichthese factors could adversely affect earnings.
    
Inability to complete necessary or desirable pipeline expansion or infrastructure improvement projects.

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

Impact of weather conditions and related regulatory mechanisms.
    
The Company’s revenues and earnings are dependent upon weather conditions. The Company’s rate structure currently has a WNA factor that results in either a recovery or refund of revenues due to 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 incosts without the price and availability of natural gas.

Natural gas purchases representadditional revenues to offset 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 salesincreased costs, as well as increases inhigher bad debt expense and increased competition from other energy providers.expenses, particularly in the context of the

9

Inability to complete necessary or desirable pipeline expansion or infrastructure development projects.current pandemic-related restrictions.

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,

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 equipmentswitch 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 convenienceconvenience.


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,consumers. Future legislation could also place limitations on the amount of natural gas used by businesses and homeowners to reduce the level of emissions, resulting in reduced deliveries and earnings. 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.



Compliance with and Changeschanges in Tax Laws.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.
10

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, FERC and FERCother governmental agencies have issued stays, or stop orders or delayed authorizations affecting portions or all of the project pending resolution of issues or concerns raised as the project has progressed. Actions taken or imposed byThe LLC is currently waiting on resolution of the Fourth Circuit or FERC that are currently impeding the completionCircuit's stay of the pipeline include the following: In July 2018, the Fourth Circuit rescinded permits allowingNationwide Permit 12 imposed in October 2020 preventing the pipeline from crossing streams and wetlands. FERC has not yet granted a revised authorization to crosscomplete construction work in a 3.625 mile section of the Jefferson National Forest. In October 2018,pipeline route. The LLC also needs authorizations from the same court vacatedBureau of Land Management and the West Virginia water crossing permits with the Army CorpUnited States Forest Service and resolution of Engineers subsequently rescinding the permits in Virginia. In October 2019, FERC issued a project-wide order halting forward-construction progress in responsechallenges 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.Service.


The LLC continues to respond toSeveral of the prior issues and concerns raised;have been resolved; however, the ongoing obstacles have causedas discussed above continue to cause delays in construction and have resulted in significantly higher projected costs and an extended targeted in-service date for the pipeline. These cost overruns may not be approved for recovery or be recovered through other regulatory mechanisms, and the LLC could be obligated to make delay or termination payments or be responsible for other contractual damages. The LLC could also experience the loss of tax 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 or challenges could lead to additional delays and even higher costs, which could affect future returns for the LLC and materially impact Resources consolidated financial position and results of 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.








11

Pandemic Outbreak.

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

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

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

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

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

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

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

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 coverageFailure to comply with debt covenant requirements.

The Company's long-term debt obligations and bank line-of-credit contain financial covenants. Noncompliance with any of these covenants could result in an event of default which, if not cured or waived, could accelerate payment on outstanding debt obligations or cause prepayment penalties. In such an event, the Company may not be sufficient.

The Company currently has liabilityable to refinance or repay all of its indebtedness, pay dividends or have sufficient liquidity to meet operating 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 orcapital expenditure requirements. Any 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 haveacceleration would cause a material adverse effect onchange in the Company’sCompany's financial position, results of operations and cash flows.condition.


12

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. BothAlthough the Company has soft-frozen both plans to limit future growth in each plan's liabilities, ongoing funding obligations and increased expenseexpenses 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.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.


GENERAL RISKS

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

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

Insurance coverage may not be sufficient.

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

Item 1B.Unresolved Staff Comments.

Item 1B.Unresolved Staff Comments.
Not applicable.

None.






Item 2.Properties.

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 1,1461,144 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.

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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.

Item 3.Legal Proceedings.

The Company is not known to be a party to any pending legal proceedings.
 
Item 4.Mine Safety Disclosures.

Item 4.Mine Safety Disclosures.

Not applicable.
 

14

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

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 PricesCash Dividends
Year Ending September 30, 2020HighLowDeclared
 First Quarter$30.00 $27.53 $0.1750 
 Second Quarter31.98 24.55 0.1750 
 Third Quarter28.85 23.15 0.1750 
 Fourth Quarter24.86 22.58 0.1750 
Year Ending September 30, 2019
First Quarter$30.71 $24.16 $0.1650 
Second Quarter30.51 26.50 0.1650 
Third Quarter30.52 25.63 0.1650 
Fourth Quarter31.00 26.46 0.1650 
  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, 2019,25, 2020, there were 1,106were 1,058 holders of recordrecord 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.





chart-a07a7d952c695f03bd6a06.jpg
A summary of the Company’s equity compensation plans follows as of September 30, 2019:2020:

(a)(b)(c)
Plan categoryNumber 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 holders51,500 $18.34493,532 
Equity compensation plans not approved by security holders— — — 
Total51,500 $18.34493,532 

Item 6.Selected Financial Data.
  (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

Item 6.Not applicable.
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.


15


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

COVID-19

COVID-19 and the resulting pandemic continues to have a significant impact on local, state, national and global economies. The actions taken by governments, as well as businesses and individuals, to limit the spread and overcome the virus has significantly disrupted normal activities throughout the Company's service territory. Management has updated and implemented its pandemic plan to ensure the continuation of safe and reliable service to customers and to maintain the safety of the Company's employees. Additionally, the Company regularly evaluates its pandemic plan for adherence to new rules and regulations issued by the Department of Labor and the Occupational Safety and Health Administration regarding workplace safety. Since the beginning of the pandemic, Resources has been deemed an essential entity by virtue of the utility services provided through Roanoke Gas.

As a result of the pandemic, the Company saw a decline in natural gas consumption in most categories of its commercial customers; however, certain industrial customers have increased gas consumption, primarily for use in their business process, more than offsetting the commercial declines. The Company’s volume of gas delivered to residential customers has remained relatively consistent with the prior year. The Company expects a continued overall decline in gas consumption by its commercial customers throughout fiscal 2021.

The SCC issued an order in March 2020, which was extended to October 5, 2020, prohibiting any utility operating in Virginia from disconnecting utility service to customers for non-payment or applying late payment fees to delinquent accounts. During the special session of the Virginia General Assembly, HB5005 was enacted and extended the above moratorium until the Governor determines that the economic and public health conditions have improved such that the prohibition does not need to be in place, or until at least 60 days after such declared state of emergency ends, whichever is sooner. Accordingly, the Company has increased its provision for bad debts, based on information currently available.

Additionally, in April 2020, the SCC issued an order granting potential relief from bad debts and other incremental expenses, directly related to the pandemic. While the Company is tracking these costs and will file for relief with the SCC as appropriate, the full extent of these costs and the impact to the Company's results of operations and financial position remains unpredictable.

The full extent to which the COVID-19 pandemic will impact the Company depends on future developments, which are highly uncertain and cannot be reasonably predicted, including the duration, scope and severity of the pandemic, the increase or reduction in governmental restrictions to businesses and individuals, the potential resurgence of the virus, as well as the timing and efficacy of a vaccine. The longer the pandemic continues, the greater the potential negative financial effect on the Company and its customers. Management believes the economic impact of the pandemic will continue well into calendar 2021.

Cyber Risk

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









16

Overview


Resources is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately 60,70062,000 residential, commercial and industrial customers in Roanoke, Virginia, and the surrounding localities, through its Roanoke Gas subsidiary. Roanoke Gas also provides certain unregulated services. As a wholly-owned subsidiary of Resources, Midstream is a more than 1% 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 annual 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 GasThe Company is also subject to federal regulation from the Department of Transportation in regard to the construction, operation, maintenance, safety and integrity of its transmission and distribution pipelines. FERC regulates the prices for the transportation and delivery of natural gas to the Company's distribution system and underground storage services. In addition, Roanoke Gas is 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.


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

In fiscal 2019, the Company completed theits transition to the 21% federal statutory income tax rate as a result of the TCJA that was signed into law in December 2017. SinceBetween the implementationenactment of the new tax rates and the Company's implementation of new non-gas rates effective January 1, 2019, the Company haswas recovering revenues based on a 34% federal income tax rate rather than a 21% federal tax rate. As a result, during this period, the Company recorded a provision for refund related to estimated excess revenues collected from customers for the difference in non-gas rates derived under approved billing rates designed to recover expenses and provide a rate of return based on athe lower federal tax rate ofand the 34%. Beginning January 1, 2019, rate included in non-gas rates. Roanoke Gas incorporated the effect of the 21% federal income tax rate with the implementation of new non-gas base rates, as filed in its currentgeneral non-gas rate application, and began refundingrefunded the excess revenues associated with the change in the tax rate over the subsequent 12-month period.a 12 month period ending December 2019. 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

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 applicationaward 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 non-gas rate application with the SCC. Generally, investments related to extending service to new customers are recovered through the additional revenues generated by the non-gas base rates currently in place. The investment in replacing and upgrading existing infrastructure is generally not recoverable until a formal rate application is filed to include the additional investment, and new non-gas base rates are approved. The SAVE 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
17

until such time a formal rate application is filed to incorporate this investmentthese investments in the Company's non-gas base rates. SinceWith the Company's previousimplementation of new non-gas baserates effective January 1, 2019, the SAVE Rider was reset as the cumulative qualifying SAVE Plan investment through December 31, 2018 was incorporated into the non-gas rate application in 2013, SAVE Plan revenues have grown each year corresponding to the level of SAVE qualifying capital investment. With the filingas part 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.rates. Accordingly, SAVE Plan revenues declined to $1,272,000 in fiscal 2020 from $1,599,000 in fiscal 2019. Fiscal 2019 comparedincluded three months of SAVE revenue under the SAVE Plan rates in effect prior to $4,469,000the revenue being incorporated into the new non-gas base rates. In 2017, the Company completed the replacement of all cast iron and $3,813,000 for fiscal 2018bare steel pipe and 2017.is continuing its renewal program under the SAVE Plan and Rider by renewing its first generation, pre-1973 plastic pipe. Additional information regarding the SAVE Rider is provided under the Regulatory Affairsand Tax Reform section.


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 theeach WNA year end, which runs from April to March. For the fiscal year ended September 30, 2019, theThe Company recorded approximately $1,193,000 and $453,000 in additional revenue from the WNA for weather that was approximately 8% and 4% warmer than normal. Fornormal for the fiscal years ended September 30, 20182020 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,2019, 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 historical 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 in3,914 when incorporating fiscal 2019. The Company's prior rates were designed on 4,0002020 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.days.


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%12% reduction in the average cost of gas in storage during fiscal 20192020 and a 5%6% reduction in the ICC factor, resulted in a decline in ICC revenues of approximately $92,000$74,000 from fiscal 2018. This compares to a decline of $35,000 in ICC revenues for fiscal 2018 compared to fiscal 2017.2019. Based on current storage balances and natural gas futures prices, the average dollar balance of gas in storage in fiscal 2021 should remain stable and,be similar to 2020, which, in combination with a more consistentstable ICC factor due to the current low interest rate environment, should result in less volatility insimilar 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.


Roanoke Gas is required to submit an Annual Information Filing ("AIF") each year to the SCC. Included as part of this filing is an earnings test, which is required when the Company has certain regulatory assets. If the results of the earnings test indicate that the Company's regulatory earnings exceed the mid-point of its authorized return on equity range, then certain regulatory assets are written-down and recovery accelerated to the point where the actual return for the period adjusts to the mid-point of the range. The economic environment has a direct correlationCompany's earnings test is required for its fiscal year ended September 30, 2020 and must be filed 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.SCC by January 2021. As Roanoke Gas' fiscal 2020 earnings exceed the mid-point, the Company accelerated recovery of $525,000 in ESAC assets.


18

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.


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 %
Other720,265
 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 Commercial6,901,181
 7,103,825
 (202,644) (3)%
 Transportation and Interruptible2,975,312
 2,822,149
 153,163
 5 %
 Total Delivered Volumes9,876,493
 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, 2019 increased 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 or replace operating income, the most comparable GAAP financial measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. Therefore, theThe following discussionresults of financial performanceoperations analyses will reference gross utility margin as partmargin.

Fiscal Year 2020 Compared with Fiscal Year 2019

The table below reflects operating revenues, volume activity and heating degree days.
Operating Revenues
Year Ended September 30,20202019DecreasePercentage
Gas Utilities$62,408,925 $67,306,260 $(4,897,335)(7)%
Other666,466 720,265 (53,799)(7)%
Total Operating Revenues$63,075,391 $68,026,525 $(4,951,134)(7)%
Delivered Volumes
Year Ended September 30,20202019Increase / (Decrease)Percentage
Regulated Natural Gas (DTH)
 Residential and Commercial6,419,031 6,901,181 (482,150)(7)%
 Transportation and Interruptible3,938,143 2,975,312 962,831 32 %
 Total Delivered Volumes10,357,174 9,876,493 480,681 5 %
Heating Degree Days (Unofficial)3,623 3,791 (168)(4)%

Total gas utility operating revenues for the year ended September 30, 2020 decreased by 7% from the year ended September 30, 2019 primarily due to a reduction in residential and commercial volumes, lower natural gas commodity prices and reduced SAVE Plan revenue more than offsetting a full year impact of the analysisnon-gas rate increase and higher transportation volumes. The primarily weather sensitive residential and commercial natural gas deliveries declined by 7%, corresponding to a 4% decline in heating degree days during the period, while transportation volumes increased by 32%. After adjusting for WNA, residential volumes declined by more than 2% and commercial volumes fell by more than 6%. These WNA adjusted lower volumes reflect the impact of COVID-19 on local businesses and other entities through closings and reduced operations. The significant increase in transportation and interruptible volumes is attributable to a single multi-fuel use industrial customer that switched its primary fuel source to natural gas due to favorable natural gas commodity price levels; however, this customer's natural gas usage has since returned to prior consumption patterns. The average commodity price of natural gas delivered declined by 29% per decatherm from the same period last year due to available supplies and higher storage levels from a mild winter. SAVE Plan revenues declined by $327,000 as the SAVE Rider reset effective January 1, 2019, and all qualifying SAVE Plan investments through December 31, 2018 were included in rate base and used to derive the new non-gas base rates. For the first three months of fiscal 2019, SAVE Plan revenues represented a return on a five-year accumulation of SAVE investment. Subsequent to January 1, 2019, the SAVE Plan investments reset and currently include less than two years of qualifying investments on which to earn a return. As discussed above, the Company placed new non-gas base rates into effect for natural gas service rendered on or after January 1, 2019, subject to refund. As a result, fiscal 2020 includes a full year of revenues under the new non-gas base rates, while the prior year revenues include only nine-months of the resultshigher non-gas rates.
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Other revenues decreased by 7% from the same period last year due to the unregulated operations contract completion. The contract ended in August 2020 and accounted for approximately 75% of operations.other revenues for fiscal 2020. The Company does not currently anticipate pursuing other customers for these services.



Gross Utility Margin
Year Ended September 30,20202019Increase / (Decrease)Percentage
Utility revenues$62,408,925 $67,306,260 $(4,897,335)(7)%
Cost of gas23,949,481 32,401,123 (8,451,642)(26)%
Gross Utility Margin$38,459,444 $34,905,137 $3,554,307 10 %
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 gas32,401,123
 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 higherthe non-gas base ratesrate increase effective January 1, 2019 and higher delivered transportation and interruptible volumes. The new non-gas rates were in effect for the entire fiscal 2020 year compared to only nine months for fiscal 2019. SAVE PlanAs a result, customer base charge revenues declinedincreased by nearly $2,900,000$927,475. Volumetric margin increased by $1,792,553, attributable to 80% of the non-gas base rate increase being allocated to volumetric margin and the single industrial customer previously discussed, net of the effect of lower residential and commercial volumes due to warmer weather and the effects from COVID-19. WNA margin increased by $739,823 as all related SAVE investmentweather was 8% warmer than normal and more than 4% warmer than the same period last year. In addition, the current year WNA margin reflects the pricing from a full year implementation of the higher non-gas rates in the calculation. The prior year also included a reserve for excess revenues attributable to the reduction in the corporate federal income tax rates for the period of October 1, 2018 through December 31, 2018 was incorporated intoprior to the implementation of the new non-gas base rates. As noted above, the SCC staff recommended a changeThese excess revenues were subsequently refunded to customers 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 componentcalendar 2019. The current fiscal year has no such adjustment 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 effectseffect of the TCJA.lower federal income tax rate.


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

Years Ended September 30,
20202019Increase / (Decrease)
Customer Base Charge$14,413,709 $13,486,234 $927,475 
SAVE Plan1,272,070 1,599,281 (327,211)
Volumetric21,091,007 19,298,454 1,792,553 
WNA1,192,715 452,892 739,823 
Carrying Cost388,607 462,260 (73,653)
Excess Revenues - Tax Reform— (523,881)523,881 
Other Revenues101,336 129,897 (28,561)
Total$38,459,444 $34,905,137 $3,554,307 

 Years Ended September 30,  
 2019 2018 Increase / (Decrease)
Customer Base Charge$13,486,234
 $12,476,755
 $1,009,479
SAVE Plan1,599,281
 4,468,556
 (2,869,275)
Volumetric19,298,454
 15,889,359
 3,409,095
WNA452,892
 44,569
 408,323
Carrying Cost462,260
 554,090
 (91,830)
Excess Revenues - Tax Reform(523,881) (1,320,167) 796,286
Other Revenues129,897
 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,$2,091,210, or 13%15%, from lastprior year primarily due to higherthe accelerated recovery of ESAC regulatory assets, increased bad debt expense, compensation costs and professional services. As previously mentioned, the SCC final order on Roanoke's non-gas base rate increase directed the Company to write-down $317,000 of ESAC assets that were not subject to recovery. In addition to the annual amortization of regulatoryESAC assets, corporate insurance costs, lower capitalized overheads, maintenance activitiesRoanoke Gas accelerated the recovery of the remaining $525,000 balance of ESAC assets as a result of the preliminary earnings test performed by the Company. Bad debt expense increased by $336,000 related primarily to the ramifications of COVID-19. With the service cut-off moratorium and delinquencies, the corresponding bad debt expense has continued in an upward trend. Additionally, as the number of COVID cases continue to increase, the negative economic impact is expected to continue resulting in the potential for higher bad debt expense.levels next year. See the Regulatory and Tax Reform section below for more information regarding the moratorium and ESAC assets. Total compensation costs increased by $647,000$400,000 primarily due to higher staffing levels in regulatory and operations support combined with wage increases. Beginning in January 2019, concurrent with the implementationvesting of new non-gas rates, the Company began amortizing certain regulatory assets for which recovery was includedofficer stock awards. Professional services increased by $323,000 due to a variety of factors including legal assistance provided in the non-gas rate application. A total of $372,000 was charged to expenseapplication, services 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 premiumsunion contract negotiations, services related to increased liability limitsemployee benefit plans, network systems support 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.other project support activities.

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General Taxes - General taxes increased $188,784,$127,995, or 10%6%, primarily due to higher property taxes associated with increasesa nearly 9% increase in utility property and higher payroll taxes.property.

Depreciation - Depreciation expense increased by $497,930,$436,451, or 7%6%, corresponding to a 6%similar increase in depreciable utility plant investment.plant.


Equity in Earnings of Unconsolidated Affiliate - The equity in earnings of the MVP investment increased by $2,081,817$1,794,526 due to AFUDC related to increased investment in the project. TotalThe total MVP cash investment in fiscal 20192020 was nearly $21approximately $7.8 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$284,414 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$248,000 equity portion of last year. ASU 2017-07 requiresAFUDC income related to the two Roanoke Gas transfer stations 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 retrospectivelywill interconnect with the reclassification of $123,000MVP. The Company recorded AFUDC based on activity retro-active to January 1, 2019 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. Seeaccordance with the provisions included in the SCC's final rate order on the non-gas base rates as discussed in 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.section.


Interest Expense - Total interest expense increased by $1,156,986,$480,607, or 47%13%, due to a 41%28% increase in the average total debt outstanding during the yearyear. This increase is attributed to the continued investment in MVP and financing expenditures in support of Roanoke Gas' capital budget. The Company contributed nearly $21 million to its investmentbudget, partially offset by a reduction in MVPthe weighted-average interest rate during the year as Midstream's borrowingperiod and the capitalization of $82,000 for the interest portion of AFUDC.

Roanoke Gas' interest expense increased by more than $22 million$326,304 as total average debt outstanding increased by $10,200,000 associated with a correspondingthe debt issuance in December 2019 and an increase in the borrowings under the line-of-credit. The average interest rate decreased slightly from 3.80% in fiscal 2019 to 3.76% in fiscal 2020. The increase in interest expense was mitigated by the capitalization of $832,000. Roanoke Gas' total borrowing increased by more than $10 million$82,000 related to the issuance of an unsecured note to refinance ainterest portion of AFUDC as authorized by the line-of-credit, which accounted forSCC's final order on the remaining increasenon-gas rate increase.

Midstream's interest expense increased by $154,303 as total average debt outstanding increased by $14,400,000 associated with the its investment in interest expense.MVP. The average interest rate on consolidated borrowings increased duringdecreased from 3.59% in fiscal 2019 to 2.76% in the current year from 3.80%due to 3.92%.the decline in the variable interest rate on Midstream's credit facility.

Income Taxes - Income tax expense decreasedincreased by $244,405,$654,929, or 8%25%, even thoughon a 22% increase in pre-tax earnings increased.earnings. The effective tax rate was 23.8% for fiscal 2020 compared to 23.4% for fiscal 2019 compared to 28.4% for fiscal 2018. These decreases in the2019. The effective tax rate for both years is below the combined state and income tax expense correspondfederal statutory rate of 25.74% due to the reduction inamortization of the corporate federalexcess deferred income tax rate fromtaxes and the 24.3% blended federal tax rate in fiscal 2018excess deductions related to the 21% statutory rate in fiscal 2019. Fiscal 2018 income tax expense also included $256,444vesting of additional tax expense forrestricted stock and the revaluationexercise of net deferred tax assets of the unregulated operations to the 21% federal tax rate.stock options. Income tax expense related to the MVP investment increased by $359,000$405,000 due to the significant growth in pre-tax earnings. Additional information regardingThe majority of the impactremaining $250,000 increase in income tax expense is related to the increase in pre-tax earnings of tax reform can be found in Note 8 and under the Regulatory and Tax Reform section below.Roanoke Gas.


Net Income and Dividends - Net income for fiscal 20192020 was $8,698,412$10,564,534 compared to $7,297,205$8,698,412 for fiscal 2018.2019. Basic and diluted earnings per share were $1.30 in fiscal 2020 compared to $1.08 in fiscal 2019 compared to $0.95 in fiscal 2018.2019. Dividends declared per share of common stock were $0.70 in fiscal 2020 compared to $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%
Other1,192,953
 1,044,855
 148,098
 14%
Total Operating Revenues$65,534,736
 $62,296,870
 $3,237,866
 5%


Delivered Volumes       
        
Year Ended September 30,2018 2017 Increase Percentage
Regulated Natural Gas (DTH)       
 Residential and Commercial7,103,825
 5,840,883
 1,262,942
 22%
 Transportation and Interruptible2,822,149
 2,721,699
 100,450
 4%
 Total Delivered Volumes9,925,974
 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 gas32,091,923
 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:



 Years Ended September 30,  
 2018 2017 Increase / (Decrease)
Customer Base Charge$12,476,755
 $12,412,753
 $64,002
SAVE Plan4,468,556
 3,813,043
 655,513
Volumetric15,889,359
 13,573,704
 2,315,655
WNA44,569
 1,839,454
 (1,794,885)
Carrying Cost554,090
 588,624
 (34,534)
Rate Refund(1,320,167) —
 (1,320,167)
Other Revenues136,698
 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

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,capital projects, investment in MVP, the seasonal funding of its natural gas inventories and accounts receivables and payment of dividends. To meet these needs, the Company primarily relies on its operating cash flows line-of-credit agreement,and availability under short-term and long-term debt and capital raised through the issuance of common stock.credit agreements.











21

Cash and cash equivalents increaseddecreased by $1,383,937approximately $1.3 million in fiscal 20192020 compared to an increase of $177,771$1.4 million in fiscal 2018 and a decrease of $573,612 in fiscal 2017.2019. The following table summarizes the categories of sources and uses of cash:

Cash Flow SummaryYears Ended September 30,
20202019
Net cash provided by operating activities$12,823,903 $14,697,704 
Net cash used in investing activities(30,721,011)(42,830,005)
Net cash provided by financing activities16,556,826 29,516,238 
Increase (decrease) in cash and cash equivalents$(1,340,282)$1,383,937 
Cash Flow SummaryYear 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 activities29,516,238
 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 fiscal quarters as a combination of earnings, declining storage gas levels and collections on customer accounts all contribute to higher cash levels. During the first and fourth fiscal quarters, operating cash flows generally decrease due to the combination of increasing natural gas storage levels and rising customer receivable balances.


Cash provided byflow from 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 increaseddecreased by nearly $1.2$1.9 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, relatedwhen compared 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 lastprior 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 changeflow provided by operations was primarily driven by changes in prepaidregulatory assets and liabilities, partially offset by net 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 reductionchanges in accounts payable balances associated with lower gas costs and additional funding provided to the pension plan as reflected in Note 9. payable.

The table below summarizes the significant operating cash flow components:

Years Ended September 30,
Cash Flows From Operating Activities:20202019Increase (Decrease)
Net Income$10,564,534 $8,698,412 $1,866,122 
Non-cash adjustments:
Depreciation8,126,427 7,600,852 525,575 
Equity in earnings(4,814,874)(3,020,348)(1,794,526)
AFUDC(330,208)— (330,208)
Allowance for doubtful accounts592,398 7,167 585,231 
ESAC assets1,022,195 303,470 718,725 
Changes in working capital and regulatory assets and liabilities:
Accounts receivable(141,482)(258,024)116,542 
Prepaid income taxes510,357 (320,297)830,654 
Accounts payable and accrued expenses659,276 (2,745,377)3,404,653 
Change in over (under) collection of gas costs(1,895,555)1,084,735 (2,980,290)
Rate refund(3,827,589)2,507,422 (6,335,011)
WNA1,171,342 (399,956)1,571,298 
Other1,187,082 1,239,648 (52,566)
Net cash provided by operating activities$12,823,903 $14,697,704 $(1,873,801)

In 2020, Roanoke Gas issued $3.8 million of refunds related to interim rates that began in fiscal 2019, resulting in a $6.3 million change in operating cash flow. As natural gas commodity prices rapidly declined in 2020, the Company’s gas cost recovery moved from an over-collected position at the end of 2019 to an under-collected position in 2020, driving a $3.0 million decrease in operating cash flow. These significant year-over-year decreases were offset by increases in net income, net of AFUDC earnings, and depreciation. Fiscal 2020 also had non-cash expense for uncollectible accounts and the ESAC accelerated recovery. Colder than normal weather for the WNA period ended September 30, 2020 resulted in a net payable versus a net receivable at September 30, 2019, driving an increase in
22

 Years Ended September 30,  
Cash Flows From Operating Activities:2019 2018 Increase (Decrease)
Net Income$8,698,412
 $7,297,205
 $1,401,207
Depreciation7,600,852
 7,090,169
 510,683
Equity in earnings(3,020,348) (938,531) (2,081,817)
Gas in storage1,178,889
 74,698
 1,104,191
Prepaid income taxes(320,297) 959,142
 (1,279,439)
Change in over-collection of gas costs1,084,735
 (2,360,972) 3,445,707
Deferred taxes684,028
 755,994
 (71,966)
Accounts payable and accrued expenses(2,745,377) 191,054
 (2,936,431)
Rate refund2,507,422
 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
operating cash flows of $1.6 million. In addition, the $3.4 million operating cash increase from accounts payable and accrued expenses is primarily attributable to changes in natural gas commodity prices year-over-year and fiscal 2019 elevated employee benefit plan funding.


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 programwere approximately $22.9 million and other system and infrastructure improvements were nearly $21.9 million in fiscal 2020 and 2019, compared to $23.3 million in fiscal 2018 and $20.7 million in fiscal 2017.respectively. Roanoke Gas renewed 8.4 miles of natural gas distribution main and replaced 875 service lines to customers in fiscal 2019. This compares to 8.39.6 miles of main and 496592 service lines and 8.4 miles of main and 875 service lines in fiscal 2018years 2020 and 9 miles of main and 459 service lines in fiscal 2017.2019, respectively. The current renewal programSAVE Plan is focused on the replacement of pre-1973 first generation plastic pipe. In addition, the Company’sRoanoke Gas’ capital expenditures included costs to extend natural gas distribution mains and services to 553 new448 customers in fiscal 20192020, compared to 451 new553 customers in fiscal 2018 and 499 new customers in fiscal 2017.2019. Roanoke Gas is constructing two gate stations to access the MVP and has nearly completed the extension of the gas distribution system necessary to connect tointerconnect with the MVP. Once MVP is operational, these stations. These two stations will provide additional natural gas supply to Roanoke Gas' existing customers 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.areas. Depreciation covered approximately 35% of the current and prior year's capital expenditures, compared to 30% for 2018 and 31% for 2017, with the balance provided from other operating cash flows and borrowings.financing activities.


Capital expenditures are expected to remain at elevatedcurrent levels over the next few years. The Company is continuing itsyears as Roanoke Gas continues to focus on replacing the remaining pre-1973 first generation plastic pipe with modern polyethylene pipe. This renewal projectits SAVE Plan, which 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 increaseutilize its borrowing activity,credit facilities, as well as consider additional equity investment,capital, to meet the funding requirements of these planned expenditures.


Investing cash flows also reflect Midstream's $20,965,907 fiscal 2019the 2020 funding of its$7.9 million for Midstream's participation in the LLC. Midstream's total expected funding increased to between $53$60 and $55$62 million as discussed below, with anticipated cash investment for fiscal 20202021 to be as much as $15approximately $17 million. Funding for the investment in the LLC is provided through the $26$41 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 facilityfacilities is provided in Note 7 and under the Equity Investment in Mountain Valley Pipeline section below.




Cash Flows Provided by Financing Activities:


Financing activities generally consist of borrowings and repayments under debtcredit agreements, issuance of stock and the payment of dividends. Net cash flows provided by financing activities were $29,516,000, $20,841,000$16.6 million and $9,938,000$29.5 million in fiscal 2020 and 2019, 2018 and 2017, respectively. As mentioned above, theThe Company uses its line-of-credit to fund seasonal working capital needs and provide temporary financing for capital projects, which is then converted into longer-term debt or equity financing.projects. The increase in financing cash flows was derived from Midstream's net borrowings of more than $22$9 million to finance its investment in MVP and the $10 million issuance of notes by Roanoke Gas. The Company also realized $1.7$1.8 million from the issuance of stock through DRIP activity and the exercise of options. DividendCash out-flows for dividend payments exceeded $5.2$5.6 million as the annualized dividend rate per share increased from $0.62$0.66 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. $0.70 per share. The Company’s consolidated capitalization was 41.7% equity and 58.3% long-term debt at September 30, 2020, exclusive of unamortized debt expense. This compares to 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, 2018.2019. The long-term debt as a percent of long-term capitalization increased from last year due to the debt issues listed below.issuances described above compared to retained earnings increases, net of dividend payments.


In JuneOn March 26, 2020, Roanoke Gas renewed its unsecured line-of-credit agreement, which was scheduled to expire March 31, 2021. The new agreement is for a two-year term expiring March 31, 2022 with a maximum borrowing limit of $28,000,000. Amounts drawn against the agreement are considered to be non-current as the balance under the line-of-credit is not subject to repayment within the next 12-month period. The agreement has a variable-interest rate based on 30-day LIBOR plus 100 basis points and an availability fee of 15 basis points and provides multi-tiered borrowing limits aligned with the Company's seasonal borrowing demand. The Company's total available borrowing limits range from $3,000,000 to $28,000,000.

On December 23, 2019, Midstream entered into two unsecured promissory notesthe Third Amendment to Credit Agreement ("Amendment") and loan agreementsamendments to the related Promissory Notes ("Notes") with the corresponding banks. The Amendment modified the original Credit Agreement and prior amendments between Midstream and the banks by increasing the total borrowing capacity to $41,000,000 from its previous $26,000,000 limit and extending the maturity date to December 29, 2022. The Amendment retained all of the other provisions contained in the total aggregate principal amount of $24,000,000. The first note was for a 7-year term inprevious credit agreements and amendments
23

including the amount of $14,000,000 at an interest rate ofon the notes based on a 30-day LIBOR plus 115 basis points. Midstream entered into a related swap agreement to convert1.35%. The additional limits under the variable interest rate to a 3.24% fixed rate. The second note wasAmendment provide additional financing for a 5-year termthe investment 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.MVP.


On June 5,December 6, 2019, Roanoke Gas entered into an agreement to issueunsecured 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 ofprovided financing for Roanoke Gas' capital budget.


On March 28,December 6, 2019, Roanoke Gas issuedamended its existing private shelf facility agreement. This "Second Amendment" pre-authorized the Company to issue notes up to an additional $40,000,000, in aggregate, while also extending the aggregate principal amount of $10,000,000. These notesterm 3-years. At this time, no funds have a 12-year term with a fixed interest rate of 4.41%.been drawn since the amendment.


On March 26, 2019,September 30, 2020, Roanoke Gas entered into a new unsecured line-of-creditsecond private shelf facility agreement with a two-year term expiring March 31, 2021, replacingfor the prior line-of-credit agreement scheduledpre-authorization to expire March 31, 2020. The new agreement maintainsissue notes up to $70 million, in aggregate, during 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 the5-year term of the agreement. No funds have been drawn under the shelf agreement rangeat this time.

At the Company's annual meeting, held on February 3, 2020, Resources shareholders approved an amendment to the Articles of Incorporation that increased the total number of authorized common shares from $3,000,00010 million 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.20 million. The amendment became effective on February 4, 2020.


On February 19, 2019, Midstream entered into an agreement14, 2020, Resources filed a prospectus with the lending institutionsSEC utilizing a shelf registration process where the Company may sell shares of common stock, in one or more offerings, of an aggregate amount up to amend$40,000,000. The prospectus was filed including a supplement allowing the Company to offer a portion of these shares, up to an aggregate of $15,000,000, utilizing the at the market ("ATM") approach as defined in Rule 415 under the Securities Act. The ATM approach allows Resources flexibility in the frequency, timing and amount of share offerings in supplementing its existing non-revolving credit agreement and related notes that provide financing for the MVP project. The amendment increased total borrowing limits to $50 millioncapital funding needs. As of September 30, 2020, no shares had been issued 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.ATM.


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:

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,MVP. On November 19, 2019, the Company's Board of Directors approved a natural gas pipeline connectingpro-rata increase in its participation in MVP. As a result, based on the Equitrans gatheringmidpoint of the targeted total project cost for the MVP discussed below, Midstream's equity interest will increase to approximately 1.03% by the pipeline’s in-service date and transmission system in northern West Virginiathe Company’s total estimated cash investment is expected to the Transco interstate pipeline in south central Virginia.range from $60 to $62 million.


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 anotherthis additional delivery source of natural gas into its distribution system.source. Currently, Roanoke Gas is served by two pipelines and a liquefied natural gas storagean LNG peak-shaving facility. Damage to or interruption ofin 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 willThis additional capacity would reduce the impact from such an event.event as well as allow the Company to better meet both current and future demands for natural gas. In addition, the currentproposed pipeline path provideswould provide the Company with a more economically feasible opportunity to provide natural gas service to currently unserved areas within the Company'sits certificated service territory.



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 beganTotal MVP project work is approximately 92% complete. Activity on the pipeline, the LLC has encountered various challenges, including pipeline protesters,MVP was limited for most of fiscal 2020 due to legal and regulatory challenges to various federal and state permits resulting in stop orders and FERC intervention. In July 2018, the Fourth Circuit rescinded permits allowingproject, including 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 progressprogress. On October 9, 2020 the FERC partially lifted this order, allowing some upland construction to resume. Although certain permits and authorizations for the MVP project were received in responsethe fourth quarter of fiscal 2020, there remain pending legal and regulatory challenges and authorization requests to, or otherwise affecting, certain aspects of the project and certain of such permits and authorizations, which the LLC is working to resolve.

As of November 3, 2020, based primarily on unanticipated delays during the prime summer and fall 2020 construction seasons resulting from the LLC’s inability to complete MVP project work under Nationwide Permit 12 authority (which was received in September 2020 and subsequently temporarily stayed in October 11, 2019, order2020 by the Fourth Circuit grantingCourt of Appeals and then further stayed by the Fourth Circuit Court on November 9, 2020) and the continued need for
24

authorization from the FERC to complete construction work on approximately 25 miles of the project route, the full in-service date for the MVP project has been extended to the second half of calendar 2021 at a staytotal project cost of MVP's$5.8 billion to $6.0 billion, excluding AFUDC. Completion of the project in accordance with the targeted full in-service date and cost will require, among other things, timely authorization by the FERC to complete construction work in the portion of the project route currently remaining subject to the FERC’s previous stop work order, timely reinstatement of the LLC’s Nationwide Permit 12 permits or utilization of alternative permitting authority and/or construction methods to cross streams and wetlands in a manner not requiring a Nationwide Permit 12, as well as resolution of challenges to the Biological Opinion and Incidental Take Statement issued by the U.S. Fish and Wildlife Service in November 2017. The FERC order directed activity onfor the pipelineMVP project and receipt of authorizations from the Bureau of Land Management and U.S. Forest Service. Due to be focused on restoration and stabilization activities to protect the environment alonguncertainty regarding the pipeline. The LLC is currently working with all regulatory entitiestiming of permitting and the Fourth Circuit to resolve these issues and the managing partner anticipates the reinstatementoutcome of these permits and authorization.

As a result of the most recent action by FERC, the managing partner ofany legal challenges, on August 25, 2020, 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 infiled 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 combinedrequest with the increased costs will reduce the corresponding return on investment, absent a regulatory action, which could provideFERC 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 time to complete the MVP project for an additional two years through October 13, 2022. On October 9, 2020, the FERC granted this request.

In December 2019, Midstream entered into the Third Amendment to Credit Agreement and amended the corresponding associated notes to increase the borrowing capacity under the credit facility beyond 2020. See Note 15 regarding an increase infrom $26 million to $41 million and extend the Company's participation inmaturity date to December 29, 2022. The amended agreement and notes will provide additional financing capacity for MVP funding; however, due to the ongoing delays, additional financing may be required. If the legal and regulatory challenges are not resolved and/or restrictions are imposed by the government related to COVID-19 that impact future construction, the cost of the MVP and corresponding $1.6 million expected fundingMidstream's capital contributions may increase above current estimates, resulting in its investment.additional financing requirements, and a delayed in-service date.


The current earnings from the MVP investment in MVP relatesare attributable 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 construction 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. WhenHowever, when the pipeline, or a portion of the pipeline, is completed and approved by FERC to be placed into service, recognition of AFUDC income will be reduced proportionally or cease. Once operational,in service, earnings will be derived from cash flows for pipeline utilization capacity charges, for utilizingper contract. It is expected that Midstream's future earnings will be less than the pipeline.current level of AFUDC recognized.


On April 11,In 2018, the LLC announced the MVPMidstream became a participant in Southgate, a project which isto construct a planned 70 mile75-mile pipeline extending from the MVP mainline at the Transco interconnect in Virginia to delivery points in North Carolina. Midstream will beis a less than 1% investor in the Southgate project and, based on current project cost estimates, will invest between $1.8approximately $2.1 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,Southgate. Midstream's participation in the Southgate project is for investment purposes only. The targeted in-service dateFERC issued the CPCN for Southgate isin June 2020; however, the endFERC, while authorizing the project, directed the Office of calendar 2020. Any further delays inEnergy Projects to not issue a notice to proceed with construction until necessary federal permits are received for the MVP project and the Director of the Office of Energy Projects lifts the stop work order and authorizes the LLC to continue constructing the MVP project. On August 11, 2020, North Carolina regulators denied the Southgate project's application for a Clean Water Act Section 401 Individual Water Quality Certification and Jordan Lake Riparian Buffer Authorization due to uncertainty surrounding the completion of the MVP will extendproject, which denial was appealed by the completion dateLLC on September 10, 2020. The Southgate project is targeted to be placed in-service in 2022, depending upon, among other things, favorable and timely resolution of Southgate.the foregoing and other regulatory decisions and processes.


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.rates. 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, including all ESAC related costs, and SAVE plan investments and related costs previously recovered through the SAVE rider. Approximately $4.7 million of the rate increase request was attributable to moving the SAVE Plan related revenues into non-gas base rates. 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,Following the completion of the SCC staff audit and the issuance of the hearing examiner's report, the SCC issued their report and recommendations related to the rate application.its final order on January 24, 2020. The SCC staff report included a recommendation for aorder awarded Roanoke Gas an annualized non-gas rate increase of $7.25 million with approximately $6.5 million. Management reviewed80% of the SCC staff report and submitted rebuttal testimonyincrease allocated 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 proposedvolumetric component of rates. The non-gas rate award provided for a 9.44% return on equity but excluded from rates, at the exclusioncurrent time, a return on the investment of certain infrastructure items from rate base, changes in customer class rate design andtwo interconnect stations with the exclusion ofMVP. In addition, the final order directed the Company to write-off a portion of ESAC assets that were excluded from recovery under the regulatoryrate award. As a result, in the first quarter the Company expensed an
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additional $317,000 of ESAC assets associated withabove the ESAC costs. The hearing examiner's report is not expected until December 2019, with aannual amortization amount. Rates authorized by the SCC's final order expected fromrequired the SCCCompany to issue customers $3.8 million in earlyrate refunds, which the Company completed in March 2020. Based on its assessment of the


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 excludingorder excluded a portionreturn on investment of the two interconnect stations currently under construction that will connect the MVP pipeline into the Company's distribution system; however, the order did provide for the ability to defer financing costs of these investments for future recovery. After conferring with SCC staff regarding proper treatment, the Company began recognizing AFUDC to capitalize both the equity and debt financing costs incurred during the construction phases retroactive to January 1, 2019, the rate award's effective date. For the fiscal year ended September 30, 2020, the Company included a total of $330,000 in AFUDC income, with $248,000 reflected in other income, net and $82,000 as an offset to interest expense.

On March 16, 2020, in response to COVID-19, the SCC issued an order applicable to all utilities operating in Virginia to suspend disconnection of service to all customers until May 15, 2020. The Commission extended the moratorium on disconnections through October 5, 2020. These moratorium orders prohibited utilities from rate recovery.disconnecting any customer for non-payment of their natural gas service and from assessing late payment fees. Subsequently, during the 2020 special session of the Virginia General Assembly, HB5005 was enacted and extended the moratorium for residential customers until the Governor determines that the economic and public health conditions have improved such that the prohibition does not need to be in place, or until at least 60 days after such declared state of emergency ends, whichever is sooner. Therefore, residential customers that would normally be disconnected for non-payment will continue incurring costs for gas service during the moratorium, resulting in higher potential write-offs. The Company has evaluatedincreased its provision for bad debts for fiscal 2020; however, the potential magnitude of the combined impact from the economy and the moratorium on bad debts continues to be uncertain. The Company supported the decision to suspend service disconnections in light of the current economic situation and adjustedcontinues to work with its customers in making arrangements to keep or bring their accounts current. In April 2020, the valuation basedSCC issued an order allowing regulated utilities in Virginia to defer certain incremental, prudently incurred costs associated with the COVID-19 pandemic and to apply for recovery at a future date. Formal guidance has not been provided by the SCC at this time. The Company did not defer any costs in 2020 due to the results of its earnings test, described below. In addition, HB5005 provides The Coronavirus Aid, Relief, and Economic Security (CARES) Act's funds to assist customers with past due balances. The amount of funding and the potential impact on its assessmentbad debt reserves is currently unknown at this time; however, management continues to evaluate the potential application of the resolution.order and possible funding relief on the consolidated financial statements.

Roanoke Gas is required to submit an AIF each year to the SCC. Included as part of this filing is an earnings test, which is required when the Company has certain regulatory assets. If the ultimate resultresults of the earnings test indicate that the Company's regulatory earnings exceed the mid-point of its authorized return on equity range, then certain regulatory assets are written-down and recovery accelerated to the point where the actual return for the period adjusts to the mid-point of the range. The Company's earnings test is different from management's assessment, any difference wouldrequired for its fiscal year ended September 30, 2020 and must be further adjusted following a final order fromfiled with the SCC.SCC by January 2021. As Roanoke Gas' fiscal 2020 earnings exceed the mid-point, the Company accelerated recovery of $525,000 in ESAC assets.


As noted above, theThe 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 relatesrelated 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 inwere flowed into 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 refundedflowed back 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 portionsremaining excess deferred taxes not associated with utility property are reflectedbeing collected from customers over a 5-year period. The corresponding balances related to the net excess deferred taxes are included in the regulatory liabilities and detailedliability schedule in Note 1.1 of the consolidated financial statements.


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,
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Roanoke Gas recordedaccrued a refund for the excess revenues collected in fiscal 2018 and the first quarter of fiscal 2019. BeginningStarting 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 andof the excess revenues associated with the reductionwas completed 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.December 2019.


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 andincluding a return on rate base of the additionalqualifying capital investment without the filing of a formal application for an increase in non-gas base rates.rate application. Since the implementation and approval of the original SAVE Plan in 2012, the Company has modified, amended or updated theits SAVE Plan each year to incorporate various qualifying projects. In May 2019,2020, the Company filed its most recent SAVE application with the SCC to further amend its SAVE Plan and for approval of a SAVE Rider which continuesfor the focus onperiod October 2020 through September 2021. In its application, the ongoingCompany requested to continue to recover the costs of the replacement of pre-1973 plastic pipe andpipe. In addition, the Company requested to include the replacement of a natural gas transfer stationcertain regulator stations and pre-1971 coated steel pipe as well as extending thequalifying SAVE Plan to September 30, 2024.projects. In September 2019,2020, the SCC approvedissued its order approving the updated SAVE Plan and Rider effective with the October 20192020 billing cycle. The new SAVE Rider is designed to collect approximately $1.1$2.3 million in annual revenues, an increase from the approximate $500,000$1.2 million 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 approved SAVE applicationPlan includes a refund factor to return approximately $543,000$73,000 in SAVE revenue over-collections from 2018, primarily resulting from the effect of the reduction in the federal income tax rate.2019.

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

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 submittedfiled its current depreciation study, which incorporatesincorporated 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, which resulted in a very small net reduction in the overall weighted-average composite rate from 3.32% in fiscal 2018 to 3.31% in fiscal 2019 and directed the Company to implement the3.30% in fiscal 2020. The new depreciation rates were implemented 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. The write-down of the ESAC assets is consistent with the provisions of ASC No 980.


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

order. Under these circumstances, the Company estimates the amount of increase it anticipates will be approved based on the best available information.
The Company 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 estimated natural gas delivered to customers but not yet billed during the accounting period based on weather duringperiod. The following month, the periodunbilled estimate is reversed, the actual usage is billed and current and historical data.a new unbilled estimate is calculated. The consolidated financial statements include unbilled revenue of $1,236,384$1,041,518 and $911,657$1,236,384 as of September 30, 20192020 and 2018,2019, respectively.


The Company adopted ASU 2014-09, Revenue from Contracts with Customers, and subsequent guidance and amendments effective October 1, 2018. The adoption of the ASU did not have a significant effect on the Company's results of operations, financial position or cash flows as the new guidance resulted in essentially no change in the manner and timing in which the Company recognizes revenues. The primary operation of the Company is the sale and/or delivery of natural gas to customers (the performance obligation) based on SCC approved tariff rates (the transaction price). The Company recognizes revenue through billed and unbilled customer usage as natural gas is delivered. The Company also recognizes revenue through ARPs, including the WNA.
Allowance for Doubtful Accounts - The Company evaluates the collectability of its accounts receivable balances based upon a variety of factors including loss history, level of delinquent account balances, collections on previously written off accounts and general economic conditions. The historical model used in valuing reserve for bad debts has been consistently applied over the years and has produced reasonable estimates for valuing the potential loss on customer accounts receivable. With the arrival of COVID-19 and the related economic issues that have resulted from the pandemic, the estimation of bad debt reserves has become more subjective with greater reliance on qualitative assessments and judgement than on quantitative measures. The potential magnitude of bad debts has been significantly increased by the moratorium, which has prevented the Company outsourcedfrom disconnecting delinquent customers for non-payment since March 2020. Continuing business closures and employee layoffs compound the difficulty in estimating customers' ability to meet their obligations including payment for their gas service. The inability to limit losses due to the moratorium has significantly affected the Company's ability to estimate the level of bad debt. Furthermore, customers that elect not to pay their gas bill or are fully unable to make payments will continue to increase bad debt levels that would otherwise be limited in the absence of such a mandate.

The Company is committed to working with its creditcustomers during these difficult times by providing extended payment terms and collections functionassisting customers in 2017 as partfinding other sources of its strategic decisionfinancial aid. Furthermore, legislation signed into law in Virginia has provided some potential relief to moveutilities for the call center, billing and other customer service functionshigher bad debt levels. Under the provisions of HB5005, enacted subsequent to a third-party provider with significant utility experience. These changes have been incorporated intothe end of the current valuation model for accounts receivable,fiscal year, an allotment of CARES Act funds has been made available to assist Virginia utilities in covering customer delinquent balances. The extent to which used historical information based on collection functions previously handled in-house.these funds will provide relief is uncertain at this time; however, management will take advantage of assistance that will serve both the interest of the Company and its customers.


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
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obligations, expected long-term rate of return on plan assets, compensation increases and life expectancies. Similarly, the postretirement medical plan also requires the estimation of many of the same factors as the pension plan in addition to assumptions regarding the rate of medical inflation and Medicare availability. Actual results may differ materially from the results expected from the actuarial assumptions due to changing economic conditions, differences in actual returns on plan assets, different rates of medical inflation, volatility in interest rates and changes in life expectancy. Such differences may result in a material impact on the amount of expense recorded in future periods or the value of the obligations on the consolidated balance sheet.



In selecting the discount rate to be used in determining the benefit liability, the Company utilized the FTSE Pension Discount Curve, 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%2.47% and 3.00%2.44%, respectively, for valuing its pension plan liability and postretirement plan liability at September 30, 2019.2020. These discount rates represent a significant decline from the 4.11%3.03% and 4.09%3.00% 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.2019. The reduction in the discount rates corresponds to the Federal Reserve's actions to support and stimulate the economy through the reduction in interest rates in response to the economic effects arising from COVID. The yield on the 30-year Treasury declined from 2.12% last year to 1.46% at September 30, 2020. Corporate bond rates experienced a similar decline. The decline in the discount rates was the primary variabledriving force in increasing the benefit obligations of both the pension and the postretirement plan. Mortality assumptions were based on the RP-2014PRI-2012 Mortality Table adjusted to 2006, with generational mortality improvements using Projection Scale MP-2018MP-2019 for the current year valuation.


Over the last few years, managementManagement has focusedcontinued to focus on reducing risk in the Company's defined benefit plans with a greater emphasis on pension plan risk. In 2016, the Company offered a one-time, lump-sum payout of the pension benefit to vested former employees who were not receiving payments under the plan. In 2017, the Company implemented a "soft freeze" to the pension plan whereby employees hired on or after January 1, 2017 would not be eligible to participate. Employees hired prior to that date continue to accrue benefits based on compensation and years of service. This "soft freeze" mirrored the strategy in 2000 when the Company implemented a similar freeze in its postretirement medical plan. The Company has again offered a one-time lump-sum payout option of deferred pension benefits to those current vested terminated employees not currently receiving pension benefits. This offer was made in October 2020 and the lump sum payments made December 1, 2020 totaled $717,197 and removed approximately $965,000 in pension plan liabilities. These strategies have reducedserved to limit liability growth by not allowing new employees into the plans and reducing the number of participants entitled to future benefits.growth.


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$11.2 million over the last three years, while liabilities increased only $6.1by $10.3 million during the same period for the reasons noted above. As of September 30, 2019,2020, the pension plan is at a 94% funded status. With futurefunded. Future pension liability growth associated with increasing benefitsmarket value is limited to employees hired prior to the freeze,freeze. The Company desired to mitigate the Company evaluated measures that would mitigatevolatility of the pension plan's funded status due 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 planAs the pension plan's funded status abovehas continued to exceed 90%, the Company movedcontinued to increase the allocation of the plan's assets to fixed income investments as more of the plan's liability change is related to changes in the discount rate and the service accrual portion continues to become less of a more conservativefactor due to the plan being frozen to new employees. During fiscal 2020, the targeted asset allocation model in fiscal 2018 by transitioningtransitioned from a 60% equity and 40% fixed income allocation to a 40% equity and 60% fixed income allocation for pension assets.to 30% equity and 70% fixed income. The fixed income portion of the investments wereare invested using an LDI approach.approach with the fixed income assets invested with a duration that corresponds to the duration of the corresponding liability for benefits. 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%30% 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 plan 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, theThe postretirement plan assets increased by $2$1.4 million and liabilities decreased by $0.5$0.3 million over the last three-year period.





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


Funded status - September 30, 2020PensionPostretirementTotal
Benefit Obligation$39,998,002 $17,925,409 $57,923,411 
Fair value of assets37,657,631 14,116,253 51,773,884 
Funded status$(2,340,371)$(3,809,156)$(6,149,527)
Funded status - September 30, 2019Pension Postretirement TotalFunded status - September 30, 2019PensionPostretirementTotal
Benefit Obligation$35,550,987
 $18,030,399
 $53,581,386
Benefit Obligation$35,550,987 $18,030,399 $53,581,386 
Fair value of assets33,586,671
 13,082,610
 46,669,281
Fair value of assets33,586,671 13,082,610 46,669,281 
Funded status$(1,964,316) $(4,947,789) $(6,912,105)Funded status$(1,964,316)$(4,947,789)$(6,912,105)
Funded status - September 30, 2018Pension Postretirement Total
Benefit Obligation$28,850,299
 $16,207,322
 $45,057,621
Fair value of assets28,184,697
 12,924,957
 41,109,654
Funded status$(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

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%lowered the long-term rate of return assumption remained appropriate consideringfrom 5.50% in fiscal 2020 to 5.40% in fiscal 2021 based on the assetchange in the targeted equity allocation and market environment. Likewise, asof the asset allocation remainedpension plan assets. The long-term rate of return was virtually unchanged for the postretirement plan management determined that aat 4.26% expected long-term rate of return is reasonable.as the asset allocation remains at 50% equity and 50% fixed income. Management will continue to re-evaluate the return assumptions and asset allocation and adjust both as market conditions warrant.


Management estimates that, under the current provisions regarding defined benefit pension plans, the Company will have no minimum funding requirements next year. However, 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$500,000 to its pension plan and $400,000 to its postretirement plan in fiscal 2020 with an ongoing goal to improve both plans' funded status.2021. 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 PlanChange in AssumptionIncrease in Pension CostIncrease in Projected Benefit Obligation
Discount rate-0.25 %$161,000 $1,728,000 
Rate of return on plan assets-0.25 %93,000 N/A
Rate of increase in compensation0.25 %61,000 324,000 
Actuarial Assumptions - Pension PlanChange 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 compensation0.25 % 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 PlanChange in AssumptionIncrease in Postretirement Benefit CostIncrease in Accumulated Postretirement Benefit Obligation
Discount rate-0.25 %$42,000 $771,000 
Rate of return on plan assets-0.25 %32,000 N/A
Medical claim cost increase0.25 %85,000 735,000 
Actuarial Assumptions - Postretirement PlanChange 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 increase0.25 % 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, 20192020 related to theits three variable rate notes held by the Company.notes. See Note 7 to the consolidated financial statements for additional information regarding the swaps.
30


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

Item 7A.Quantitative and Qualitative Disclosures About Market Risk.
The Company is exposed to market risks associated with interest rates
Not applicable.

Item 8.Financial Statements 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.Supplementary Data.

31





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.

RGC Resources, Inc.
and Subsidiaries


Consolidated Financial Statements
for the Years Ended September 30, 2020 and 2019 2018
and 2017, and Report of Independent
Registered Public Accounting Firm

32


RGC RESOURCES, INC. AND SUBSIDIARIES
TABLE OF CONTENTS
 
 
Page
Page
3734
Consolidated Financial Statements for the Years Ended September 30, 2019, 20182020 and 2017:2019:
Consolidated Balance Sheets
3835
Consolidated Statements of Income
4037
Consolidated Statements of Comprehensive Income
4138
Consolidated Statements of Stockholders’ Equity
4239
Consolidated Statements of Cash Flows
4340
Notes to Consolidated Financial Statements
4441

33



rgco-20200930_g1.jpg




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, 20192020 and 2018,2019, and the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows for each of the years in the three-yeartwo-year period ended September 30, 2019,2020, 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, 20192020 and 2018,2019, and the results of its operations and its cash flows for each of the years in the three-yeartwo-year period ended September 30, 2019,2020, 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 PCAOBPublic Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.


We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
 
rgco-20200930_g2.jpg
              CERTIFIED PUBLIC ACCOUNTANTS

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


Blacksburg, Virginia
December 3, 20192020

34


RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AS OF SEPTEMBER 30, 20192020 AND 20182019
 
 
20202019
ASSETS
CURRENT ASSETS:
Cash and cash equivalents$291,066 $1,631,348 
Accounts receivable, net3,404,044 3,870,211 
Materials and supplies1,027,191 1,021,882 
Gas in storage5,708,761 6,448,307 
Prepaid income taxes647,623 1,157,980 
Regulatory assets2,503,314 1,521,939 
Other854,562 733,525 
Total current assets14,436,561 16,385,192 
UTILITY PROPERTY:
In service258,342,372 237,786,964 
Accumulated depreciation and amortization(71,386,537)(67,207,334)
In service, net186,955,835 170,579,630 
Construction work in progress11,489,258 11,423,326 
Utility plant, net198,445,093 182,002,956 
OTHER ASSETS:
Regulatory assets10,970,094 12,178,853 
Investment in unconsolidated affiliates57,542,805 47,375,459 
Other284,954 411,236 
Total other assets68,797,853 59,965,548 
TOTAL ASSETS$281,679,507 $258,353,696 
 2019 2018
ASSETS   
CURRENT ASSETS:   
Cash and cash equivalents$1,631,348
 $247,411
Accounts receivable, net3,870,211
 3,744,228
Materials and supplies1,021,882
 913,889
Gas in storage6,448,307
 7,627,196
Prepaid income taxes1,157,980
 837,683
Regulatory assets1,521,939
 1,385,500
Interest rate swap—
 100,723
Other733,525
 687,972
Total current assets16,385,192
 15,544,602
UTILITY PROPERTY:   
In service237,786,964
 224,854,320
Accumulated depreciation and amortization(67,207,334) (63,099,306)
In service, net170,579,630
 161,755,014
Construction work in progress11,423,326
 4,208,614
Utility plant, net182,002,956
 165,963,628
OTHER ASSETS:   
Regulatory assets12,178,853
 8,862,147
Investment in unconsolidated affiliate47,375,459
 28,507,146
Interest rate swap—
 209,840
Other411,236
 472,743
Total other assets59,965,548
 38,051,876
TOTAL ASSETS$258,353,696
 $219,560,106


(Continued)

35

RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AS OF SEPTEMBER 30, 20192020 AND 20182019
 
 
20202019
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Dividends payable$1,428,268 $1,339,522 
Accounts payable4,442,182 4,483,233 
Capital contributions payable2,512,437 5,024,824 
Customer credit balances1,587,061 880,295 
Customer deposits1,611,476 1,432,031 
Accrued expenses3,565,210 3,448,000 
Interest rate swaps533,795 147,556 
Regulatory liabilities890,313 4,877,603 
Total current liabilities16,570,742 21,633,064 
LONG-TERM DEBT:
Notes payable114,975,200 95,512,200 
Line-of-credit9,143,606 8,172,473 
Less unamortized debt issuance costs(299,175)(313,315)
Long-term debt net of unamortized debt issuance costs123,819,631 103,371,358 
DEFERRED CREDITS AND OTHER LIABILITIES:
Interest rate swaps1,689,761 746,785 
Asset retirement obligations7,180,982 6,788,683 
Regulatory cost of retirement obligations12,678,043 11,892,352 
Benefit plan liabilities6,149,527 6,912,105 
Deferred income taxes13,973,762 12,978,523 
Regulatory liabilities10,729,082 10,934,434 
Total deferred credits and other liabilities52,401,157 50,252,882 
COMMITMENTS AND CONTINGENCIES (Note 12)
CAPITALIZATION:
Stockholders’ Equity:
Common Stock, $5 par value; authorized 20,000,000 and 10,000,000 shares; issued and outstanding 8,160,058 and 8,073,264 shares in 2020 and 2019, respectively40,800,290 40,366,320 
Preferred stock, 0 par; authorized 5,000,000 shares; 0 shares issued and outstanding in 2020 and 20190 0 
Capital in excess of par value15,847,121 14,397,072 
Retained earnings35,688,510 30,821,917 
Accumulated other comprehensive loss(3,447,944)(2,488,917)
Total stockholders’ equity88,887,977 83,096,392 
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY$281,679,507 $258,353,696 
 2019 2018
LIABILITIES AND STOCKHOLDERS’ EQUITY   
CURRENT LIABILITIES:   
Dividends payable$1,339,522
 $1,242,753
Accounts payable4,483,233
 5,211,032
Capital contributions payable5,024,824
 10,142,766
Customer credit balances880,295
 1,003,622
Customer deposits1,432,031
 1,421,043
Accrued expenses3,448,000
 3,080,432
Interest rate swap147,556
 —
Regulatory liabilities4,877,603
 1,990,201
Total current liabilities21,633,064
 24,091,849
LONG-TERM DEBT:   
Notes payable95,512,200
 63,243,200
Line-of-credit8,172,473
 7,361,017
Less unamortized debt issuance costs(313,315) (282,281)
Long-term debt net of unamortized debt issuance costs103,371,358
 70,321,936
DEFERRED CREDITS AND OTHER LIABILITIES:   
Interest rate swap746,785
 —
Asset retirement obligations6,788,683
 6,417,948
Regulatory cost of retirement obligations11,892,352
 11,163,981
Benefit plan liabilities6,912,105
 3,947,967
Deferred income taxes12,978,523
 12,585,577
Regulatory liabilities10,934,434
 11,447,736
Total deferred credits and other liabilities50,252,882
 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, respectively40,366,320
 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 value14,397,072
 13,043,656
Retained earnings30,821,917
 27,438,049
Accumulated other comprehensive loss(2,488,917) (871,668)
Total stockholders’ equity83,096,392
 79,583,112
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY$258,353,696
 $219,560,106
(Concluded)
See notes to consolidated financial statements.


36


RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
YEARS ENDED SEPTEMBER 30, 2019, 20182020 AND 20172019
 
 
20202019
OPERATING REVENUES:
Gas utilities$62,408,925 $67,306,260 
Other666,466 720,265 
Total operating revenues63,075,391 68,026,525 
OPERATING EXPENSES:
Cost of gas - utility23,949,481 32,401,123 
Cost of sales - non utility341,985 419,851 
Operations and maintenance16,180,229 14,089,019 
General taxes2,194,789 2,066,794 
Depreciation and amortization7,890,725 7,454,274 
Total operating expenses50,557,209 56,431,061 
OPERATING INCOME12,518,182 11,595,464 
Equity in earnings of unconsolidated affiliate4,814,874 3,020,348 
Other income, net636,296 351,882 
Interest expense4,099,158 3,618,551 
INCOME BEFORE INCOME TAXES13,870,194 11,349,143 
INCOME TAX EXPENSE3,305,660 2,650,731 
NET INCOME$10,564,534 $8,698,412 
EARNINGS PER COMMON SHARE:
Basic$1.30 $1.08 
Diluted$1.30 $1.08 
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic8,125,938 8,039,484 
Diluted8,146,666 8,078,950 
 2019 2018 2017
OPERATING REVENUES:     
Gas utilities$67,306,260
 $64,341,783
 $61,252,015
Other720,265
 1,192,953
 1,044,855
Total operating revenues68,026,525
 65,534,736
 62,296,870
OPERATING EXPENSES:     
Cost of gas - utility32,401,123
 32,091,923
 28,919,625
Cost of sales - non utility419,851
 666,524
 568,088
Operations and maintenance14,089,019
 12,471,428
 12,573,608
General taxes2,066,794
 1,878,010
 1,786,070
Depreciation and amortization7,454,274
 6,956,344
 6,256,737
Total operating expenses56,431,061
 54,064,229
 50,104,128
OPERATING INCOME11,595,464
 11,470,507
 12,192,742
Equity in earnings of unconsolidated affiliate3,020,348
 938,531
 421,646
Other income (expense), net351,882
 244,868
 (658,879)
Interest expense3,618,551
 2,461,565
 1,917,254
INCOME BEFORE INCOME TAXES11,349,143
 10,192,341
 10,038,255
INCOME TAX EXPENSE2,650,731
 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:     
Basic8,039,484
 7,649,025
 7,218,686
Diluted8,078,950
 7,695,712
 7,256,046

See notes to consolidated financial statements.

37


RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
YEARS ENDED SEPTEMBER 30, 2019, 20182020 AND 20172019
 
 
20202019
NET INCOME$10,564,534 $8,698,412 
Other comprehensive loss, net of tax:
Interest rate swaps(987,076)(894,761)
Defined benefit plans28,049 (722,488)
OTHER COMPREHENSIVE LOSS, NET OF TAX(959,027)(1,617,249)
COMPREHENSIVE INCOME$9,605,507 $7,081,163 
 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.

38


RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
YEARS ENDED SEPTEMBER 30, 2019, 20182020 AND 20172019
 
 
Common
Stock		Capital in
Excess of
Par Value		Retained
Earnings		Accumulated
Other
Comprehensive
Loss		Total
Stockholders’
Equity
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 
Net income— — 10,564,534 — 10,564,534 
Other comprehensive loss— — — (959,027)(959,027)
Exercise of stock options (29,992 shares)149,960 289,548 — — 439,508 
Stock option grants— 81,380 — — 81,380 
Cash dividends declared ($0.70 per share)— — (5,697,941)— (5,697,941)
Issuance costs— (147,517)— — (147,517)
Issuance of common stock (56,802 shares)284,010 1,226,638 — — 1,510,648 
Balance - September 30, 2020$40,800,290 $15,847,121 $35,688,510 $(3,447,944)$88,887,977 
 
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 split12,029,790
 (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.



39


RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED SEPTEMBER 30, 2019, 20182020 AND 20172019


 
20202019
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income$10,564,534 $8,698,412 
Adjustments to reconcile net income to net cash provided by operations:
Depreciation and amortization8,126,427 7,600,852 
Cost of retirement of utility plant, net(544,696)(443,586)
Stock option grants81,380 0 
Equity in earnings of unconsolidated affiliate(4,814,874)(3,020,348)
Allowance for funds used during construction(330,208)0 
Deferred income taxes1,122,303 684,028 
Other noncash items, net1,837,089 488,202 
Changes in assets and liabilities which provided (used) cash:
Accounts receivable and customer deposits, net53,213 (122,165)
Inventories and gas in storage734,237 1,070,896 
Regulatory and other assets(677,488)(156,799)
Accounts payable, customer credit balances and accrued expenses, net659,276 (2,745,377)
Regulatory liabilities(3,987,290)2,643,589 
Total adjustments2,259,369 5,999,292 
Net cash provided by operating activities12,823,903 14,697,704 
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for utility property(22,916,339)(21,884,317)
Investment in unconsolidated affiliate(7,864,859)(20,965,907)
Proceeds from disposal of utility property60,187 20,219 
Net cash used in investing activities(30,721,011)(42,830,005)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under line-of-credit24,341,134 33,735,144 
Repayments under line-of-credit(23,370,002)(32,923,688)
Proceeds from issuance of unsecured notes19,463,000 56,269,000 
Retirement of notes payable0 (24,000,000)
Debt issuance expenses(70,750)(93,104)
Proceeds from issuance of stock1,802,639 1,746,661 
Cash dividends paid(5,609,195)(5,217,775)
Net cash provided by financing activities16,556,826 29,516,238 
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS(1,340,282)1,383,937 
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR1,631,348 247,411 
CASH AND CASH EQUIVALENTS AT END OF YEAR$291,066 $1,631,348 
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the year for:
Interest$3,845,382 $3,328,130 
Income taxes1,673,000 2,287,000 
 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 amortization7,600,852
 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 taxes684,028
 755,994
 3,325,379
Other noncash items, net488,202
 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 storage1,070,896
 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 liabilities2,643,589
 (117,907) 528,387
Total adjustments5,999,292
 6,206,590
 6,748,113
Net cash provided by operating activities14,697,704
 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 property20,219
 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-credit33,735,144
 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 notes56,269,000
 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 stock1,746,661
 16,520,016
 967,698
Cash dividends paid(5,217,775) (4,647,042) (4,115,873)
Net cash provided by financing activities29,516,238
 20,840,554
 9,937,965
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS1,383,937
 177,771
 (573,612)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR247,411
 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 taxes2,287,000
 1,180,000
 726,000


See notes to consolidated financial statements.

40


RGC RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2019, 20182020 AND 20172019


1.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
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 60,70062,000 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 previously 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.exceptions.
Rate Regulated Basis of Accounting—The Company’s regulated operations follow the accounting and reporting requirements of FASB ASC No. 980, Regulated Operations. The economic effects of regulation can result in a regulated company deferring costs that have been or are expected to be recovered from customers in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this situation occurs, costs are deferred as assets in the consolidated balance sheet (regulatory assets) and recorded as expenses when such amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for current collection in rates of costs that are expected to be incurred in the future (regulatory liabilities). In the event the provisions of FASB ASC No. 980 no longer apply to any or all regulatory assets or liabilities, the Company would write off such amounts and include them in the consolidated statements of income and comprehensive income in the period which FASB ASC No. 980 no longer applied.

41

Regulatory assets and liabilities included in the Company’s consolidated balance sheets as of September 30, 20192020 and 20182019 are as follows:
 September 30
 20202019
Assets:
Current Assets:
Regulatory assets:
Accrued WNA revenues$0 $569,558 
Under-recovery of gas costs1,733,718 0 
     Under-recovery of SAVE Plan revenues108,550 0 
ESAC assets0 265,392 
Accrued pension and postretirement medical576,731 602,674 
Other deferred expenses84,315 84,315 
Total current2,503,314 1,521,939 
Utility Property:
In service:
Other11,945 11,945 
Construction work in progress:
AFUDC330,208 0 
Other Assets:
Regulatory assets:
Premium on early retirement of debt1,598,620 1,712,808 
Accrued pension and postretirement medical9,156,546 9,414,695 
ESAC assets0 756,803 
Other deferred expenses214,928 294,547 
Total non-current10,970,094 12,178,853 
Total regulatory assets$13,815,561 $13,712,737 
Liabilities and Stockholders' Equity:
Current Liabilities:
Regulatory liabilities:
Over-recovery of gas costs$0 $161,837 
WNA601,784 0 
            Over-recovery of SAVE Plan revenues0 574,181 
       Rate refund0 3,827,588 
Excess deferred income taxes205,353 205,353 
Other deferred liabilities83,176 108,644 
Total current890,313 4,877,603 
Deferred Credits and Other Liabilities:
Asset retirement obligations7,180,982 6,788,683 
Regulatory cost of retirement obligations12,678,043 11,892,352 
Regulatory liabilities:
Excess deferred income taxes10,729,082 10,934,434 
Total non-current$30,588,107 $29,615,469 
Total regulatory liabilities$31,478,420 $34,493,072 
 September 30
 2019 2018
Assets:   
Current Assets:   
Regulatory assets:   
Accrued WNA revenues$569,558
 $169,602
Under-recovery of gas costs—
 922,898
ESAC assets265,392
 —
Accrued pension and postretirement medical602,674
 293,000
Other deferred expenses84,315
 —
Total current1,521,939
 1,385,500
Utility Property:   
In service:   
Other11,945
 11,945
Other Assets:   
Regulatory assets:   
Premium on early retirement of debt1,712,808
 1,826,995
Accrued pension and postretirement medical9,414,695
 5,704,718
ESAC assets756,803
 1,330,434
Other deferred expenses294,547
 —
Total non-current12,178,853
 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 revenues574,181
 670,034
       Rate refund3,827,588
 1,320,167
Excess deferred income taxes205,353
 —
Other deferred liabilities108,644
 —
Total current4,877,603
 1,990,201
Deferred Credits and Other Liabilities:   
Asset retirement obligations6,788,683
 6,417,948
Regulatory cost of retirement obligations11,892,352
 11,163,981
Regulatory liabilities:   
Excess deferred income taxes10,934,434
 11,447,736
Total non-current$29,615,469
 $29,029,665
    
Total regulatory liabilities$34,493,072
 $31,019,866

Amortization of regulatory assets of $1,106,511 and $368,011 for the years ended September 30, 2020 and 2019, respectively, is included in operations and maintenance expense on the consolidated statements of income. See Note 3 for information on accelerated ESAC amortization.

As of September 30, 2019,2020, the Company had regulatory assets in the amount of $13,700,792$13,803,616 on which the Company did not earn a return during the recovery period.
42

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

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

Utility plant is composed of the following major classes of assets:
 September 30
 20202019
Distribution and transmission$227,753,620 $209,171,339 
LNG storage14,798,453 13,417,077 
General and miscellaneous15,790,299 15,198,548 
Total utility plant in service$258,342,372 $237,786,964 
 September 30
 2019 2018
Distribution and transmission$209,171,339
 $196,778,546
LNG storage13,417,077
 13,413,175
General and miscellaneous15,198,548
 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.a range of periods. Rates are determined by depreciation studies which are required to be performed at least every 5 years on the regulated utility assets of Roanoke Gas. 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 3.30% and 3.31% for the year ended September 30, 2019 as compared to 3.32% and 3.29% for fiscal years ended September 30, 20182020 and 2017,2019, 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.

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

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

The Company’s composite depreciation rates include a component to provide for the cost of retirement of assets. As a result, the Company accrues the estimated cost of retirement of its utility plant through depreciation expense and creates a corresponding regulatory liability. The costs of retirement considered in the development of the depreciation component include those costs associated with the legal liability. Therefore, the ARO is reclassified from the regulatory cost of retirement obligation. If the legal obligations were to exceed the regulatory liability provided for in the depreciation rates, the Company would establish a regulatory asset for such difference with the anticipation of future recovery through rates charged to customers.
43

The following is a summary of the AROs:
 Years Ended September 30
 20202019
Beginning balance$6,788,683 $6,417,948 
Liabilities incurred165,524 177,646 
Liabilities settled(150,345)(177,755)
Accretion377,120 370,844 
Ending balance$7,180,982 $6,788,683 
 Years Ended September 30
 2019 2018
Beginning balance$6,417,948
 $6,069,993
Liabilities incurred177,646
 79,608
Liabilities settled(177,755) (126,907)
Accretion370,844
 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

accounts and does not consider these amounts to be at credit risk. As of September 30, 2019,2020, 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 Years Ended September 30
2019 2018 2017 20202019
Beginning balance$103,573
 $99,456
 $76,934
Beginning balance$110,743 $103,573 
Provision for doubtful accounts220,039
 169,096
 84,587
Provision for doubtful accounts556,112 220,039 
Recoveries of accounts written off96,614
 78,919
 110,725
Recoveries of accounts written off139,113 96,614 
Accounts written off(309,483) (243,898) (172,790)Accounts written off(102,828)(309,483)
Ending balance$110,743
 $103,573
 $99,456
Ending balance$703,140 $110,743 

Due to the impact of COVID-19 on businesses and individuals, both bad debt expense and associated allowance for doubtful accounts increased significantly over prior years. See Note 3 for additional information, including regulatory restrictions, that contributed to the increase.

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, 2020 and 2019 were $1,041,518 and 2018 were $1,236,384, and $911,657, respectively.


44

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.bills.

Fair Value—Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between willing market participants at the measurement date. The Company determines fair value based on the following fair value hierarchy which prioritizes each input to the valuation methods into one of the following three broad levels:
•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.
45

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
 20202019
Net Income$10,564,534 $8,698,412 
Weighted-average common shares8,125,938 8,039,484 
Effect of dilutive securities:
Options to purchase common stock20,728 39,466 
Diluted average common shares8,146,666 8,078,950 
Earnings Per Share of Common Stock:
       Basic$1.30 $1.08 
       Diluted$1.30 $1.08 
 Years Ended September 30
 2019 2018 2017
Net Income$8,698,412
 $7,297,205
 $6,232,865
Weighted-average common shares8,039,484
 7,649,025
 7,218,686
Effect of dilutive securities:     
Options to purchase common stock39,466
 46,687
 37,360
Diluted average common shares8,078,950
 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.

Roanoke Gas is served directly by two2 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, 20192020 and 2018,2019, the Company had no0 outstanding derivative instruments for the purchase of natural gas.
The Company has three3 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 two2 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. Any cash flows from interest rate swaps are classified as interest expense. No portion of the swaps were deemed ineffective during the period.
See Notes 7 and 13 for additional information on the swaps and fair value.
46

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$2,512,387 and corresponding increase in capital contributions payable of $9,087,262 and $767,710$5,117,942 occurred for the fiscal years ended September 30, 20182020 and 2017,2019, 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.

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, 2020:
Interest rate swaps:
       Unrealized losses$(1,594,126)$410,328 $(1,183,798)
       Transfer of realized losses to interest expense264,911 (68,189)196,722 
Net interest rate swaps(1,329,215)342,139 (987,076)
Defined benefit plans:
       Net loss arising during period$(52,669)$13,557 $(39,112)
       Amortization of actuarial losses90,441 (23,280)67,161 
Net defined benefit plans37,772 (9,723)28,049 
Other comprehensive loss$(1,291,443)$332,416 $(959,027)
Year Ended September 30, 2019:
Interest rate swaps:
       Unrealized losses$(1,117,595)$287,669 $(829,926)
       Transfer of realized gains to interest expense(87,309)22,474 (64,835)
Net interest rate swaps(1,204,904)310,143 (894,761)
Defined benefit plans:
       Net loss arising during period$(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)
 
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 swap193,720
 (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 plans571,683
 (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 swaps116,843
 (44,354) 72,489
Defined benefit plans:     
       Net gain arising during period$1,715,505
 $(651,892) $1,063,613
       Amortization of actuarial losses256,234
 (97,369) 158,865
Net defined benefit plans1,971,739
 (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.
















Composition of AOCI:
Interest Rate
Swaps		Defined Benefit
Plans		Accumulated
Other
Comprehensive
Income (Loss)
Balance September 30, 2018230,624 (1,102,292)(871,668)
Other comprehensive loss(894,761)(722,488)(1,617,249)
Balance September 30, 2019(664,137)(1,824,780)(2,488,917)
Other comprehensive income (loss)(987,076)28,049 (959,027)
Balance September 30, 2020$(1,651,213)$(1,796,731)$(3,447,944)
 
Interest Rate
Swaps
 
Defined Benefit
Plans
 
Accumulated
Other
Comprehensive
Income (Loss)
Balance September 30, 2016$—
 $(2,497,231) $(2,497,231)
Other comprehensive income (loss)72,489
 1,222,478
 1,294,967
Balance September 30, 201772,489
 (1,274,753) (1,202,264)
Other comprehensive income (loss)137,850
 406,798
 544,648
Reclassification adjustment for the effect of change in tax law20,285
 (234,337) (214,052)
Balance September 30, 2018230,624
 (1,102,292) (871,668)
Other comprehensive income (loss)(894,761) (722,488) (1,617,249)
Balance September 30, 2019$(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.


47
 Year Ended September 30, 2018
 As Previously Reported Effect of Change As Adjusted
      
Operation and maintenance12,348,890
 122,538
 12,471,428
Total operating expenses53,941,691
 122,538
 54,064,229
Operating income11,593,045
 (122,538) 11,470,507
Other income (expense), net122,330
 122,538
 244,868
Income before income taxes10,192,341
 —
 10,192,341

 Year Ended September 30, 2017
 As Previously Reported Effect of Change As Adjusted
      
Operation and maintenance13,100,041
 (526,433) 12,573,608
Total operating expenses50,630,561
 (526,433) 50,104,128
Operating income11,666,309
 526,433
 12,192,742
Other income (expense), net(132,446) (526,433) (658,879)
Income before income taxes10,038,255
 —
 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.

 September 30, 2018
 As Previously Reported Effect of Change As Adjusted
Current Assets:     
Accounts receivable, net3,913,830
 (169,602) 3,744,228
Under-recovery of gas cost922,898
 (922,898) —
Other980,972
 (293,000) 687,972
Regulatory assets—
 1,385,500
 1,385,500
      
Current Liabilities:     
Accrued expenses3,750,466
 (670,034) 3,080,432
Rate refund1,320,167
 (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

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 This ASU leaves the accounting for leases mostly unchanged for lessors, with the exception of targeted improvements for consistency; however, the new guidance requires lessees to recognize assets and liabilities for leases with terms of more than 12 months. The ASU also revises the definition of a lease as a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment for a period of time in exchange for consideration. Consistent with currentUnder prior GAAP, the presentation and cash flows arising from a lease by a lessee will primarily dependdepended on its classification as a finance or operating lease. In contrast, theThe new ASU requires both types of leases to be recognized on the balance sheet. In addition, the new guidance includes quantitative and qualitative disclosure requirements to aid financial statement users in better understanding the amount, timing and uncertainty of cash flows arising from leases. In January 2018, the FASB issued ASU 2018-01, which provides a practical expedient that allows entities the option of not evaluating existing land easements under the new lease standard for those easements that were entered into prior to adoption. New or modified land easements will require evaluation on a prospective basis. The new guidance is effective for the Company for the annual reporting period ending September 30, 2020 and interim periods within that annual period. Early adoption is permitted.

The Company adopted ASU 2016-02 and related guidance effective October 1, 2019. At the time of adoption, the Company had 1 operating lease. This lease calls for quarterly payments in the amount of $3,240 and is set to expire in September 2021. As the value of this lease obligation was determined to be de minimis and the Company has completed its inventory of leases andnot entered into any additional lease obligations, this new guidance does not currently expect the new guidance to have a material effect on itsthe Company's financial position, results of operations or cash flows.

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

In August 2018, the FASB issued ASU 2018-15, Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer's Accounting for Implementation Costs incurred in a Cloud Computing Arrangement that is a Service Contract. This ASU reduces the complexity of accounting for costs of implementing a cloud computing service arrangement and aligns the following requirements to capitalize implementation costs: 1) those incurred in a hosting arrangement that is a service contract, and 2) those incurred to develop or obtain internal-use software, including hosting arrangements that include an internal software license. The Company adopted the new guidance effective October 1, 2019. The new guidance did not have a material effect on the Company's consolidated financial statements.
Recently Issued Accounting Standards
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,March 2020, the FASB issued ASU 2018-15, Intangibles2020-04, Reference Rate Reform (Topic 848) - GoodwillFacilitation of the Effects of Reference Rate Reform on Financial Reporting. This ASU provides temporary optional guidance to ease the potential burden in accounting for and Other - Internal-Use Software (Subtopic 350-40): Customer's Accounting for Implementation Costs incurred in a Cloud Computing Arrangementrecognizing the effects of reference rate change on financial reporting. The new guidance applies specifically to contracts and hedging relationships that reference LIBOR, or any other referenced rate that is a Service Contract. This ASU reduces the complexity of accounting for costs of implementing a cloud computing service arrangement and aligns the following requirementsexpected to capitalize implementation costs: 1) those incurred in a hosting arrangement that is a service contract, and 2) those incurredbe discontinued due to develop or obtain internal-use software, including hosting arrangements that include an internal software license.reference rate reform. The new guidance is effective for the Company for the annual reporting period beginning October 1, 2020.through December 31, 2022. Management has not yet completed its evaluation of the new guidance; however, it believesas the Company has several contracts and hedging relationships that currently reference LIBOR, this new guidance will changecould impact the future treatment of certain contracts by

allowing related implementation costs to be capitalized and amortized over time, rather than directly expensed. Management does not currently expect the new guidance to have a material effect on itsCompany's financial position, results of operations, or cash flows.flows for the period through which the ASU is effective.
48

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

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:
2020
Gas utilityNon-utilityTotal operating revenues
Natural Gas (Billed and Unbilled):
Residential$37,022,219 $0 $37,022,219 
Commercial18,387,674 0 18,387,674 
Industrial and Transportation5,188,069 0 5,188,069 
Other489,943 666,466 1,156,409 
Total contracts with customers61,087,905 666,466 61,754,371 
Alternative Revenue Programs1,321,020 0 1,321,020 
Total operating revenues$62,408,925 $666,466 $63,075,391 
2019
Gas utilityNon-utilityTotal operating revenues
Natural Gas (Billed and Unbilled):
Residential$39,519,618 $0 $39,519,618 
Commercial22,562,265 0 22,562,265 
Industrial and Transportation4,770,657 0 4,770,657 
Revenue reductions (TCJA) (1)
(523,881)0 (523,881)
Other592,156 720,265 1,312,421 
Total contracts with customers66,920,815 720,265 67,641,080 
Alternative Revenue Programs385,445 0 385,445 
Total operating revenues$67,306,260 $720,265 $68,026,525 
(1) Accrued refund associated with excess revenue collected in tariff rates associated with the reduction in federal income tax rates.
 2019
 Gas utilityNon-utilityTotal operating revenues
Natural Gas (Billed and Unbilled):   
Residential$39,519,618
$—
$39,519,618
Commercial22,562,265
—
22,562,265
Industrial and Transportation4,770,657
—
4,770,657
Revenue reductions (TCJA) (1)
(523,881)—
(523,881)
Other592,156
720,265
1,312,421
Total contracts with customers66,920,815
720,265
67,641,080
Alternative Revenue Programs385,445
—
385,445
Total operating revenues$67,306,260
$720,265
$68,026,525
    
 2018
 Gas utilityNon-utilityTotal operating revenues
Natural Gas (Billed and Unbilled):   
Residential$38,926,710
$—
$38,926,710
Commercial22,158,226
—
22,158,226
Industrial and Transportation4,316,526
—
4,316,526
Revenue reductions (TCJA) (1)
(1,320,167)—
(1,320,167)
Other690,787
1,192,953
1,883,740
Total contracts with customers64,772,082
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 utilityNon-utilityTotal operating revenues
Natural Gas (Billed and Unbilled):   
Residential$34,462,456
$—
$34,462,456
Commercial19,913,853
—
19,913,853
Industrial and Transportation4,400,731
—
4,400,731
Other693,435
1,044,855
1,738,290
Total contracts with customers59,470,475
1,044,855
60,515,330
Alternative Revenue Programs1,781,540
—
1,781,540
Total operating revenues$61,252,015
$1,044,855
$62,296,870
    

(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 inthrough 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 resultresults in the satisfaction of the Company’s respective performance obligationobligations over time as natural gas is delivered.time.


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
49

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 rate changes to tariff rates.approved by the SCC.


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:

Current AssetsCurrent Liabilities
Trade accounts receivable (1)
Unbilled revenue (1)
Customer credit balancesCustomer deposits
September 30, 2019$2,590,702 $1,236,384 $880,295 $1,432,031 
September 30, 20202,343,492 1,041,518 1,587,061 1,611,476 
Increase (decrease)$(247,210)$(194,866)$706,766 $179,445 
(1) Included in "Accounts receivable, net" in the consolidated balance sheet. Amounts shown net of reserve for bad debts.

 Current Assets Current Liabilities
 
Trade accounts receivable (1)
Unbilled revenue (1)
 Customer credit balancesCustomer deposits
September 30, 2018$2,675,611
$911,657
 $1,003,622
$1,421,043
September 30, 20192,590,702
1,236,384
 880,295
1,432,031
Increase (decrease)$(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

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.base rates. 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 on an interim basis for service rendered on or after January 1, 2019, subject to refund pending audit and final order by the SCC.

On June 28, 2019,January 24, 2020, the SCC staff issued their report including a recommendation forits final order on the general rate application. Under the provisions of this order, Roanoke Gas was granted an annualannualized non-gas rate increase of approximately $6.5 million. Management reviewed$7.25 million and provided for a 9.44% return on equity. In addition, 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 fromdirected the SCCCompany to write-down a portion of the ESAC assets deemed not expected until early 2020.eligible for recovery. As a result, ESAC regulatory assets were written down approximately $317,000 in the first
50

quarter of fiscal 2020. In March 2020, the Company completed the refund of $3.8 million for revenues collected from the interim rates in excess of the assessment of the SCC staff report, in addition to the rebuttal testimony and positions taken by the Company, management has accrued an estimatefinal approved rates, including interest.

The final order did not provide for a refundreturn on Roanoke Gas infrastructure investments associated with two gate stations that will interconnect with the MVP; however, the order did provide for the difference betweenability to defer financing costs related to these investments for consideration of future recovery. The Company is deferring these costs through the rates placed into effect onapplication of AFUDC, which capitalizes both the equity and debt financing costs during the construction phases. Roanoke Gas applied AFUDC treatment retroactively to January 1, 2019, the date new non-gas rates became effective. The January 1, 2019 date was affirmed by the Commission in its October 1, 2020 order in the Company’s 2019 annual informational filing docket. Amounts capitalized are disclosed in the Utility Plant and management's estimateDepreciation section of Note 1.

In 2020, Roanoke Gas accelerated amortization of the non-gas rates$525,000 remaining balance of its ESAC assets. This acceleration was the result of the Company's earnings test for fiscal 2020. The SCC requires regulated utilities with certain regulatory assets to perform and submit an annual earnings test. The Company's earnings test is required for its fiscal year ended September 30, 2020 and must be filed with the SCC in January 2021. Specific to ESAC assets, if the results indicate that earnings exceed the mid-point of its authorized return on equity range, the Company must write-down certain regulatory assets to the point where the actual return for the period falls to the mid-point. As Roanoke Gas' fiscal 2020 unadjusted earnings exceeded the mid-point, the Company accelerated amortization of the related ESAC assets.

On March 16, 2020, in response to the COVID-19 pandemic, the SCC issued an order applicable to all utilities operating in Virginia to suspend disconnection of service for non-payment by any customer until May 15, 2020, which was subsequently extended to October 5, 2020. These moratorium orders prohibited utilities from disconnecting any customer for non-payment of natural gas service and also prohibited utilities from assessing late payment fees. As a result, the amount of current receivables and future billings that may ultimately become uncollectible will likely increase. In October 2020, during the special session of the Virginia General Assembly, HB5005 was enacted and extended the moratorium until the Governor determines that the economic and public health conditions have improved such that the prohibition does not need to be approved byin place, or until at least 60 days after such declared state of emergency ends, whichever is sooner. Therefore, the SCC. The amount reflected inCompany has increased its provision for uncollectible accounts, based on information currently available and the expected continued aging of its accounts receivable at September 30, 2020. These estimates are subject to revision as the financial statements is an estimate andimpact of COVID-19 continues to ripple through the final order could result in a higher or lower refund.economy.
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, 2019,2020, Roanoke Gas had approximately $11,100,000$11,000,000 remaining in the net regulatory liability related to these excess deferred income taxes, mostthe majority 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 approvesapproved revised billing rates incorporating the lower tax rate. Effective with January 2019 customer billings, theThe Company began refundingrefunded 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

associated with the non-gas general rate application are reflectedchange in the tax rate refund line item under the regulatory liabilities as detailed in Note 1.over a 12-month period ended December 2019.


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%. for fiscal 2019. 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.



51

In May 2019,2020, 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 continuesIn addition to the replacementcontinued renewal of first generation plastic mainmains and related services, coated steel tubing services and includesspecifically identified gate stations, the replacement of a natural gas transfer station. The filing alsoapplication proposes to extendthat the Company's SAVE Plan be amended to September 30, 2024.include the renewal or removal of certain regulator stations and the renewal of pre-1971 coated steel mains and coated steel services. In September 2019,2020, 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$2.3 million in revenue in fiscal 20202021 for SAVE Plan investment since January 1, 2019 and proposed fiscal 20202021 SAVE investment. The SCC also approved the True-uptrue-up factor to provide for the refund of approximately $543,000$73,000 in over-collected balance from the 20182019 SAVE Plan.


4.SEGMENT INFORMATION

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:




Gas UtilityInvestment in AffiliatesParent and OtherConsolidated Total
For the Year Ended September 30, 2020:
Operating revenues$62,408,925 $0 $666,466 $63,075,391 
Depreciation7,890,725 0 0 7,890,725 
Operating income (loss)12,429,613 (220,194)308,763 12,518,182 
Equity in earnings0 4,814,874 0 4,814,874 
Interest expense2,730,822 1,368,336 0 4,099,158 
Income before income taxes10,350,946 3,233,233 286,015 13,870,194 
As of September 30, 2020:
Total assets$211,994,364 $57,660,105 $12,025,038 $281,679,507 
Gross additions to utility property22,916,339 0 0 22,916,339 
Gross investment in MVP and Southgate0 7,864,859 0 7,864,859 
52

Gas Utility Investment in Affiliates Parent and Other Consolidated TotalGas UtilityInvestment in AffiliatesParent and OtherConsolidated Total
For the Year Ended September 30, 2019:       For the Year Ended September 30, 2019:
Operating revenues$67,306,260
 $—
 $720,265
 $68,026,525
Operating revenues$67,306,260 $0 $720,265 $68,026,525 
Depreciation7,454,274
 —
 —
 7,454,274
Depreciation7,454,274 0 0 7,454,274 
Operating income (loss)11,458,679
 (153,149) 289,934
 11,595,464
Operating income (loss)11,458,679 (153,149)289,934 11,595,464 
Equity in earnings—
 3,020,348
 —
 3,020,348
Equity in earnings0 3,020,348 0 3,020,348 
Interest expense2,404,518
 1,214,033
 —
 3,618,551
Interest expense2,404,518 1,214,033 0 3,618,551 
Income before income taxes9,400,869
 1,657,988
 290,286
 11,349,143
Income before income taxes9,400,869 1,657,988 290,286 11,349,143 
       
As of September 30, 2019:       As of September 30, 2019:
Total assets$195,969,019
 $47,429,368
 $14,955,309
 $258,353,696
Total assets$195,969,019 $47,429,368 $14,955,309 $258,353,696 
Gross additions to utility property21,884,317
 —
 —
 21,884,317
Gross additions to utility property21,884,317 0 0 21,884,317 
Gross investment in MVP and Southgate—
 20,965,907
 —
 20,965,907
Gross investment in MVP and Southgate0 20,965,907 0 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
Depreciation6,956,344
 —
 —
 6,956,344
Operating income (loss)11,043,609
 (92,981) 519,879
 11,470,507
Equity in earnings—
 938,531
 —
 938,531
Interest expense2,079,553
 382,012
 —
 2,461,565
Income before income taxes9,208,921
 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 property23,290,994
 —
 —
 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
Depreciation6,256,737
 —
 —
 6,256,737
Operating income (loss)11,790,728
 (69,515) 471,529
 12,192,742
Equity in earnings—
 421,646
 —
 421,646
Interest expense1,778,763
 138,491
 —
 1,917,254
Income before income taxes9,353,085
 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 property20,750,181
 —
 —
 20,750,181
Gross investment in MVP and Southgate—
 2,759,346
 —
 2,759,346

5.OTHER INVESTMENTS

5.OTHER INVESTMENTS

In October 2015, Midstream, acquired a 1% equity interest in the Mountain Valley Pipeline, LLC. The LLC was establishedIn November 2019, the Company's Board of Directors approved a pro-rata increase in Midstream's participation that will increase its equity interest to construct and operate a natural gas pipeline originatingapproximately 1.03% at the MVP's completion. Once in northern West Virginia and extending through south central Virginia. The proposed pipelineservice, the MVP will have the capacity to transport approximately 2 million dthsdth of natural gas per day.

According to the LLC's managing partner, the anticipated project in-service datePipeline construction has been extended to late calendar 2020. The latest delay isdelayed due to a FERC issued project-wide stop order on October 15th, which halted construction in responseregulatory and legal challenges that have restricted the recent focus to the Fourth Circuit granting a stay on a permit issued by the U.S. Fishmaintenance 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.activities. As a result, of this recent FERC action and other judicial and regulatory actions, the estimated total projectprojected cost has grownis expected to between $5.3 and $5.5range from $5.8 to $6.0 billion, thereby increasingwith Midstream's estimated total cash contributions expected to between $53range from $60 and $55$62 million. See Note 15 regarding an increaseThe managing partner extended the estimated in-service date to the second half of calendar 2021. The Company is utilizing the equity method to account for the transactions related to the MVP investment and recognizes earnings in the Company's participation in MVP.proportion to its investment.
In April 2018, the LLC announced the MVP Southgate project, which is a planned 70an approximately 75 mile pipeline extending from the MVP mainline in Virginia to delivery points in North Carolina. Midstream is a less than 1% investor in thisthe project, which will beis being accounted for under the cost method. Total estimated project cost is between $350 andestimated to be nearly $500 million, of which Midstream's portion is estimated to be approximately $1.8 to $2.5$2.1 million. The Southgate in-service date is currently targeted for the end of calendar 2020, subject to any further delaysyear 2022.
Funding for Midstream's investments in the completion of the MVP mainline.
Midstream held an approximate $47.4 million investment inLLC for both the MVP and Southgate projects at September 30, 2019. Funding for Midstream's investment is being provided through 2 variable rate unsecured Promissory Notes as further describedpromissory notes, under a non-revolving credit agreement maturing in December 2022, and 2 additional notes issued in June 2019. See Note 7 below.for a schedule of debt instruments.
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 investments in the LLC are included in the consolidated financial statement locations of the investments by Midstream arestatements as follows:
September 30
Balance Sheet location:20202019
Other Assets:
     MVP$57,183,063 $47,055,426 
     Southgate359,742 320,033 
     Investment in unconsolidated affiliates$57,542,805 $47,375,459 
Current Liabilities:
     MVP$2,501,883 $4,958,260 
     Southgate10,554 66,564 
     Capital contributions payable$2,512,437 $5,024,824 
53

 September 30  
Balance Sheet Location of Other Investments:2019 2018  
Other Assets:     
     MVP$47,055,426
 $28,387,032
  
     Southgate320,033
 120,114
  
     Investment in unconsolidated affiliate$47,375,459
 $28,507,146
  
      
Current Liabilities:     
     MVP$4,958,260
 $10,022,652
  
     Southgate66,564
 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
Years ended September 30
Income Statement location:20202019
     Equity in earnings of unconsolidated affiliate$4,814,874 $3,020,348 
 September 30  
 2019 2018  
Undistributed earnings, net of income taxes, of MVP in retained earnings$3,267,176
 $1,024,266
  
September 30
20202019
Undistributed earnings, net of income taxes, of MVP in retained earnings$6,842,702 $3,267,176 
    
The change in the investment in unconsolidated affiliateaffiliates is provided below:
September 30
20202019
Cash investment$7,864,859 $20,965,907 
Change in accrued capital calls(2,512,387)(5,117,942)
Equity in earnings of unconsolidated affiliate4,814,874 3,020,348 
Change in investment in unconsolidated affiliates$10,167,346 $18,868,313 
 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 affiliates3,020,348
 938,531
 421,646
Change in investment in unconsolidated affiliates$18,868,313
 $21,062,040
 $3,948,702



Summary unaudited financial statements of Mountain Valley PipelineMVP are presented below. Southgate financial statements, which isare accounted for under the cost method, are not included:
Income Statements
Years Ended September 30,
20202019
AFUDC$479,586,911 $295,430,776 
Net Other Income714,128 5,655,644 
Net Income$480,301,039 $301,086,420 
Balance Sheets
September 30
20202019
Assets:
Current Assets$513,713,429 $485,323,892 
Construction Work in Progress5,536,248,668 4,675,267,389 
Other Assets4,597,441 13,190,816 
Total Assets$6,054,559,538 $5,173,782,097 
Liabilities and Equity:
Current Liabilities$187,581,804 $466,776,233 
Noncurrent Liabilities245,000 0 
Capital5,866,732,734 4,707,005,864 
Total Liabilities and Equity$6,054,559,538 $5,173,782,097 

6.    LINE-OF-CREDIT
 Income Statement
      
 Years Ended September 30,
 2019 2018 2017
AFUDC$295,430,776
 $90,096,350
 $41,848,389
Net Other Income5,655,644
 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 Progress4,675,267,389
 2,301,591,079
  
Other Assets13,190,816
 18,165,856
  
Total Assets$5,173,782,097
 $3,556,994,477
  
      
Liabilities and Equity:     
Current Liabilities$466,776,233
 $715,879,655
  
Capital4,707,005,864
 2,841,114,822
  
Total Liabilities and Equity$5,173,782,097
 $3,556,994,477
  

6.LINE-OF-CREDIT
    
OnIn March 26, 2019,2020, Roanoke Gas entered into a newrenewed its unsecured line-of-credit agreement. This agreement, replaced the prior line-of-credit agreementwhich was scheduled to expire March 31, 2020.2021. The new agreement is for a 2-yeartwo-year term expiring March 31, 20212022 with a maximum borrowing limit of $30,000,000.$28,000,000. 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 samehas a variable interest rate based on 30-day LIBOR plus 100 basis points, andan availability fee of 15 basis points and provides multi-tiered borrowing limits to accommodateassociated with the seasonal borrowing demands and minimize borrowing costs. of the Company.

54

The Company's total available borrowing limits under this agreement for the remaining term are as follows:
 
As ofAvailable
Line-of-Credit
September 30, 2020$19,000,000 
March 1, 202115,000,000 
July 20, 202120,000,000 
September 20, 202128,000,000 
As of
Available
Line-of-Credit
September 30, 2019$22,000,000
April 1, 202016,000,000
July 17, 202021,000,000
September 18, 202030,000,000


A summary of the line-of-credit follows:
 September 30
 20202019
Available line-of-credit at year-end$19,000,000 $22,000,000 
Outstanding balance at year-end9,143,606 8,172,473 
Highest month-end balance outstanding12,983,210 15,801,798 
Average daily balance3,286,033 6,049,527 
Average rate of interest during year on outstanding balances2.16 %3.40 %
Interest rate at year-end1.15 %3.02 %
Interest rate on unused line-of-credit0.15 %0.15 %
 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-end8,172,473
 7,361,017
 17,791,760
Highest month-end balance outstanding15,801,798
 17,054,377
 17,791,760
Average daily balance6,049,527
 6,730,334
 10,936,114
Average rate of interest during year on outstanding balances3.40% 2.53% 1.92%
Interest rate at year-end3.02% 3.26% 2.23%
Interest rate on unused line-of-credit0.15% 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

7.    LONG-TERM DEBT

In JuneDecember 2019, Midstream entered into two unsecured promissory notesthe Third Amendment to its Credit Agreement ("Amendment") and loan agreements. On June 12, 2019,amendments to the related Promissory Notes ("Notes") with the corresponding banks. The Amendment modified the original Credit Agreement and prior amendments between Midstream entered into a 7-year unsecured noteand the banks by increasing the total borrowing capacity to $41,000,000 from its previous limit of $26,000,000 and extending the maturity date to December 29, 2022. The Amendment retained all of the other provisions contained in the aggregate principal amount of $14,000,000 at anprevious credit agreements and amendments including the interest rate ofon the Notes based on 30-day LIBOR plus 115 basis points. Midstream also entered into an interest rate swap agreement that converts1.35%. The additional limits under the note's variable interest rate to a 3.24% fixed rate. On June 13, 2019, Midstream entered into a 5-year unsecured noteAmendment provide additional financing for the investment 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. MVP.

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,December 2019, Roanoke Gas entered into an agreement to issueunsecured 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 atwith a fixed interest rate of 3.60%. The proceedsProceeds from these notes will be used to finance a portion ofprovided funding for 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%.


Midstream has 2 other variable rate notes in the amounts of $14,000,000 and $10,000,000 that are hedged by swap agreements, which effectively convert the interest rates to 3.24% and 3.14%, respectively.
55

Long-term debt consists of the following:
 September 30
20202019
 PrincipalUnamortized Debt Issuance CostsPrincipalUnamortized Debt Issuance Costs
Roanoke Gas:
Unsecured senior notes payable, at 4.26%, due on September 18, 2034$30,500,000 $135,157 $30,500,000 $144,811 
Unsecured term note payable, at 30-day LIBOR plus 0.90%, November 1, 20217,000,000 3,613 7,000,000 6,948 
Unsecured term notes payable, at 3.58% due on October 2, 20278,000,000 33,712 8,000,000 38,528 
Unsecured term notes payable at 4.41%, due on March 28, 203110,000,000 32,892 10,000,000 36,272 
Unsecured term notes payable at 3.60%, due on December 6, 202910,000,000 32,585 0 0 
Midstream:
Unsecured term notes payable, at 30-day LIBOR plus 1.35% due December 29, 202225,475,200 38,728 16,012,200 59,504 
Unsecured term note payable, at 30-day LIBOR plus 1.15%, due June 12, 202614,000,000 13,844 14,000,000 16,252 
Unsecured term note payable, at 30-day LIBOR plus 1.20%, due June 1, 202410,000,000 8,644 10,000,000 11,000 
Total notes payable$114,975,200 $299,175 $95,512,200 $313,315 
Line-of-credit, at 30-day LIBOR plus 1.00%, due March 31, 20229,143,606 0 8,172,473 0 
Total long-term debt$124,118,806 $299,175 $103,684,673 $313,315 
 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, 20217,000,000
 6,948
 7,000,000
 10,283
Unsecured term notes payable, at 3.58% due on October 2, 20278,000,000
 38,528
 8,000,000
 43,343
Unsecured term notes payable at 4.41%, due on March 28, 203110,000,000
 36,272
 —
 —
Midstream:       
Unsecured term notes payable, at 30-day LIBOR plus 1.35% due December 29, 202016,012,200
 59,504
 17,743,200
 74,190
Unsecured term note payable, at 30-day LIBOR plus 1.15%, due June 12, 202614,000,000
 16,252
 —
 —
Unsecured term note payable, at 30-day LIBOR plus 1.20%, due June 1, 202410,000,000
 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, 20218,172,473
 —
 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, 20192020 and 2018,2019, the Company also had an unamortized loss on the early retirement of debt of $1,712,808$1,598,620 and $1,826,995,$1,712,808, 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 Company was in compliance with all debt covenants as of September 30, 2020 and September 30, 2019.
The aggregate annual maturities of long-term debt for the next five years ending after September 30, 20192020 are as follows:
Year Ending September 30Maturities
2021$0 
202216,268,606 
202325,975,200 
20249,375,000 
20250 
Thereafter72,500,000 
Total$124,118,806 

56
Year Ending September 30Maturities
2020$—
202124,184,673
20227,000,000
2023—
202410,000,000
Thereafter62,500,000
Total$103,684,673



8.8.    INCOME TAXES

On December 22, 2017, the President signed into law
As a result of 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,2018, the Company's statutory federal income tax rate transitioned from 34% in fiscal 2017 to 24.3% in fiscal 2018 andis 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%2020 and the number of days at 21%.2019, respectively.


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 excess deferred taxes related to the other regulatory basis differences are being collected from customers over a five year period.


The details of income tax expense are as follows:
 Years Ended September 30
 20202019
Current income taxes:
Federal$1,841,124 $1,698,215 
State342,233 268,488 
Total current income taxes2,183,357 1,966,703 
Deferred income taxes:
Federal644,682 272,079 
State477,621 411,949 
Total deferred income taxes1,122,303 684,028 
Total income tax expense$3,305,660 $2,650,731 
 Years Ended September 30
 2019 2018 2017
Current income taxes:     
Federal$1,698,215
 $1,831,085
 $72,368
State268,488
 308,057
 407,643
Total current income taxes1,966,703
 2,139,142
 480,011
Deferred income taxes:     
Federal272,079
 440,282
 3,129,925
State411,949
 315,712
 195,454
Total deferred income taxes684,028
 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, 20182020 and 20172019 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
 20202019
Income before income taxes$13,870,194 $11,349,143 
Corporate federal income tax rate21.0 %21.0 %
Income tax expense computed at the federal statutory rate$2,912,741 $2,383,320 
State income taxes, net of federal income tax benefit647,685 537,545 
Net amortization of excess deferred taxes on regulated operations(162,228)(212,896)
Tax benefit recognized on stock compensation(114,984)(96,499)
Other, net22,446 39,261 
Total income tax expense$3,305,660 $2,650,731 
57

 Years Ended September 30
 2019 2018 2017
Income before income taxes$11,349,143
 $10,192,341
 $10,038,255
Corporate federal income tax rate21.0% 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 benefit537,545
 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, net39,261
 22,230
 20,760
Total income tax expense$2,650,731
 $2,895,136
 $3,805,390


The tax effects of temporary differences that give rise to the deferred tax assets and deferred tax liabilities are as follows:
 September 30
 20202019
Deferred tax assets:
Allowance for uncollectibles$180,986 $28,503 
Accrued pension and postretirement medical benefits651,356 782,592 
Regulatory effect of change in federal income tax rate2,814,525 2,867,383 
Accrued vacation140,635 150,882 
Over-recovery of gas costs0 23,979 
Cost of gas held in storage604,962 590,495 
Deferred compensation992,605 803,979 
Interest rate swaps572,343 230,204 
Rate refund0 130,063 
Other97,564 261,125 
Total gross deferred tax assets6,054,976 5,869,205 
Deferred tax liabilities:
Utility plant18,310,474 18,132,022 
MVP investment1,693,075 705,193 
Other25,189 10,513 
Total gross deferred tax liabilities20,028,738 18,847,728 
Net deferred tax liability$13,973,762 $12,978,523 
 September 30
 2019 2018
Deferred tax assets:   
Allowance for uncollectibles$28,503
 $26,658
Accrued pension and postretirement medical benefits782,592
 897,834
Regulatory effect of change in federal income tax rate2,867,383
 2,946,649
Accrued vacation150,882
 160,001
Over-recovery of gas costs23,979
 —
Cost of gas held in storage590,495
 591,899
Deferred compensation803,979
 716,843
Interest rate swap230,204
 —
Rate refund130,063
 339,812
Other261,125
 298,129
Total gross deferred tax assets5,869,205
 5,977,825
Deferred tax liabilities:   
Utility plant18,132,022
 17,982,215
Under-recovery of gas costs—
 255,570
MVP investment705,193
 245,678
Other10,513
 79,939
Total gross deferred tax liabilities18,847,728
 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 undernetted against other expense.income.
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, 20162017 are no longer subject to examination.


9.EMPLOYEE BENEFIT PLANS

9.    EMPLOYEE BENEFIT PLANS

The Company sponsors both a noncontributory pension plan and a postretirement plan. The pension plan covers substantially all employees hired prior to January 2017 and benefits fully vest after 5 years of credited service. Benefits paid to retirees are based on age at retirement, years of service and average compensation. 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 PlanPostretirement Plan
 2020201920202019
Accumulated benefit obligation$34,821,069 $30,927,973 $17,925,409 $18,030,399 
Change in benefit obligation:
Benefit obligation at beginning of year$35,550,987 $28,850,299 $18,030,399 $16,207,322 
Service cost691,602 537,268 167,879 132,882 
Interest cost1,062,227 1,166,728 531,480 648,944 
Actuarial loss (gain)3,620,400 5,901,915 (325,269)1,530,522 
Benefit payments, net of retiree contributions(927,214)(905,223)(479,080)(489,271)
Benefit obligation at end of year$39,998,002 $35,550,987 $17,925,409 $18,030,399 
Change in fair value of plan assets:
Fair value of plan assets at beginning of year$33,586,671 $28,184,697 $13,082,610 $12,924,957 
Actual return on plan assets, net of taxes4,198,174 3,907,197 1,112,723 346,924 
Employer contributions800,000 2,400,000 400,000 300,000 
Benefit payments, net of retiree contributions(927,214)(905,223)(479,080)(489,271)
Fair value of plan assets at end of year$37,657,631 $33,586,671 $14,116,253 $13,082,610 
Funded status$(2,340,371)$(1,964,316)$(3,809,156)$(4,947,789)
Amounts recognized in the consolidated balance sheet consist of:
Noncurrent liabilities$(2,340,371)$(1,964,316)$(3,809,156)$(4,947,789)
Amounts recognized in accumulated other comprehensive loss:
Net actuarial loss, net of tax$1,181,744 $1,047,063 $614,987 $777,717 
Total amounts included in other comprehensive loss, net of tax$1,181,744 $1,047,063 $614,987 $777,717 
Amounts deferred to a regulatory asset:
Net actuarial loss$6,977,944 $6,356,201 $2,755,333 $3,661,168 
Amounts recognized as regulatory assets$6,977,944 $6,356,201 $2,755,333 $3,661,168 
 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 cost537,268
 665,235
 132,882
 167,220
Interest cost1,166,728
 1,088,180
 648,944
 640,602
Actuarial (gain) loss5,901,915
 (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 taxes3,907,197
 1,798,722
 346,924
 426,787
Employer contributions2,400,000
 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$80,000 before tax, of AOCI will be recognized in net periodic benefit costs in fiscal 20202021 and approximately $603,000$577,000 of amounts deferred as regulatory assets will be amortized and recognized in net periodic benefit costs in fiscal 2020.2021.





59

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:plan:

 Pension PlanPostretirement Plan
 2020201920202019
Assumptions used to determine benefit obligations:
Discount rate2.47 %3.03 %2.44 %3.00 %
Expected rate of compensation increase4.00 %4.00 %N/AN/A
Assumptions used to determine benefit costs:
Discount rate3.03 %4.11 %3.00 %4.09 %
Expected long-term rate of return on plan assets5.50 %5.50 %4.26 %4.30 %
Expected rate of compensation increase4.00 %4.00 %N/AN/A
 Pension Plan Postretirement Plan
 2019 2018 2017 2019 2018 2017
Assumptions used to determine benefit obligations:           
Discount rate3.03% 4.11% 3.72% 3.00% 4.09% 3.69%
Expected rate of compensation increase4.00% 4.00% 4.00% N/A
 N/A
 N/A
Assumptions used to determine benefit costs:           
Discount rate4.11% 3.72% 3.42% 4.09% 3.69% 3.33%
Expected long-term rate of return on plan assets5.50% 7.00% 7.00% 4.30% 4.84% 4.84%
Expected rate of compensation increase4.00% 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 PlanPostretirement Plan
 2020201920202019
Service cost$691,602 $537,268 $167,879 $132,882 
Interest cost1,062,227 1,166,728 531,480 648,944 
Expected return on plan assets(1,836,623)(1,549,437)(550,394)(547,218)
Recognized loss455,744 158,599 237,371 123,805 
Net periodic benefit cost$372,950 $313,158 $386,336 $358,413 
 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 cost1,166,728
 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 loss158,599
 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 65Post 65
 2020201920202019
Health care cost trend rate assumed for next year7.00 %7.00 %5.20 %5.20 %
Rate to which the cost trend is assumed to decline (the ultimate trend rate)5.50 %5.50 %5.20 %5.20 %
Year that the rate reaches the ultimate trend rate2023202220202019
 Pre 65 Post 65
 2019 2018 2017 2019 2018 2017
Health care cost trend rate assumed for next year7.00% 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 rate2022
 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% Increase1% Decrease
Effect on total service and interest cost components$132,000 $(105,000)
Effect on accumulated postretirement benefit obligation3,042,000 (2,454,000)
 1% Increase 1% Decrease
Effect on total service and interest cost components$136,000
 $(109,000)
Effect on accumulated postretirement benefit obligation2,954,000
 (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 2018,2020, the Company revised its targeted pension plan investment allocation by rebalancing the assets from a 60%40% equity allocation to a 40%30% equity allocation. This change in investment allocation corresponds with the Company's strategy was in response to continue to match the duration of 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. Theassets with its liabilities. This change in investment allocation will allow the opportunitycontinue to reduce investment risk and volatility in asset performance while providing for some asset growth through the reduced equity exposure.growth. As a result, the Company's assumed long-termlong-
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term rate of return on pension and postretirement plan assets for fiscal 20192021 was adjusted down to 5.5%

and 4.3%, respectively.5.4%. 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, 2020 and 2019 and 2018 were:
 Pension PlanPostretirement Plan
 Target20202019Target20202019
Asset category:
Equity securities30 %30 %40 %50 %51 %49 %
Debt securities70 %69 %59 %50 %48 %50 %
Cash0 %1 %1 %0 %1 %1 %
Other0 %0 %0 %0 %0 %0 %
 Pension Plan Postretirement Plan
 Target 2019 2018 Target 2019 2018
Asset category:           
Equity securities40% 40% 40% 50% 49% 49%
Debt securities60% 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 21 in the fair value hierarchy as their fair values are determined based on individual prices for each security that comprises the mutual funds. Most of the individual investmentsThe common and collective trust funds 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.included under Level 2. The following tables contains the fair value classifications of the plans' assets:
  Pension Plan
Fair Value Measurements - September 30, 2020
 Fair ValueLevel 1Level 2Level 3
Asset Class:
Cash$339,287 $339,287 $0 $0 
Common and Collective Trust and Pooled Funds:
Bonds
Liability Driven Investment26,038,966 0 26,038,966 0 
Equities
Domestic Large Cap Growth3,462,841 0 3,462,841 0 
Domestic Large Cap Value3,351,694 0 3,351,694 0 
Domestic Small/Mid Cap Core1,665,005 0 1,665,005 0 
Foreign Large Cap Value1,473,427 0 1,473,427 0 
        Mutual Funds:
Equities
Foreign Large Cap Growth1,047,274 1,047,274 0 0 
Foreign Large Cap Value279,137 279,137 0 0 
Total$37,657,631 $1,665,698 $35,991,933 $0 
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  Pension Plan
Fair Value Measurements - September 30, 2019		  Pension Plan
Fair Value Measurements - September 30, 2019
Fair Value Level 1 Level 2 Level 3 Fair ValueLevel 1Level 2Level 3
Asset Class:       Asset Class:
Cash$371,780
 $371,780
 $—
 $—
Cash$371,780 $371,780 $0 $0 
Common and Collective Trust and Pooled Funds:       Common and Collective Trust and Pooled Funds:
Bonds       Bonds
Liability Driven Investment19,702,561
 —
 19,702,561
 —
Liability Driven Investment19,702,561 0 19,702,561 0 
Equities       Equities
Domestic Large Cap Growth4,069,197
 —
 4,069,197
 —
Domestic Large Cap Growth4,069,197 0 4,069,197 0 
Domestic Large Cap Value4,055,518
 —
 4,055,518
 —
Domestic Large Cap Value4,055,518 0 4,055,518 0 
Domestic Small/Mid Cap Core2,032,084
 —
 2,032,084
 —
Domestic Small/Mid Cap Core2,032,084 0 2,032,084 0 
Foreign Large Cap Value1,783,990
 —
 1,783,990
 —
Foreign Large Cap Value1,783,990 0 1,783,990 0 
Mutual Funds:       Mutual Funds:
Equities       Equities
Foreign Large Cap Growth1,227,981
 1,227,981
 —
 —
Foreign Large Cap Growth1,227,981 1,227,981 0 0 
Foreign Large Cap Value343,560
 343,560
 —
 —
Foreign Large Cap Value343,560 343,560 0 0 
Total$33,586,671
 $1,943,321
 $31,643,350
 $—
Total$33,586,671 $1,943,321 $31,643,350 $0 


  Postretirement Plan
Fair Value Measurements - September 30, 2020
 Fair ValueLevel 1Level 2Level 3
Asset Class:
Cash$73,908 $73,908 $0 $0 
Mutual Funds
Bonds
Domestic Fixed Income6,163,808 6,163,808 0 0 
Foreign Fixed Income638,709 638,709 0 0 
Equities
Domestic Large Cap Growth2,197,839 2,197,839 0 0 
Domestic Large Cap Value2,119,433 2,119,433 0 0 
Domestic Small/Mid Cap Growth262,726 262,726 0 0 
Domestic Small/Mid Cap Value235,216 235,216 0 0 
Domestic Small/Mid Cap Core552,607 552,607 0 0 
Foreign Large Cap Growth548,967 548,967 0 0 
Foreign Large Cap Value1,224,420 1,224,420 0 0 
Foreign Large Cap Core77,471 77,471 0 0 
Other21,149 0 21,149 0 
Total$14,116,253 $14,095,104 $21,149 $0 

62

  Pension Plan
Fair Value Measurements - September 30, 2018		  Postretirement Plan
Fair Value Measurements - September 30, 2019
Fair Value Level 1 Level 2 Level 3 Fair ValueLevel 1Level 2Level 3
Asset Class:       Asset Class:
Cash$282,478
 $282,478
 $—
 $—
Cash$66,860 $66,860 $0 $0 
Common and Collective Trust and Pooled Funds:       
Mutual FundsMutual Funds
Bonds       Bonds
Liability Driven Investment16,504,956
 —
 16,504,956
 —
Domestic Fixed IncomeDomestic Fixed Income5,987,248 5,987,248 0 0 
Foreign Fixed IncomeForeign Fixed Income611,196 611,196 0 0 
Equities       Equities
Domestic Large Cap Growth3,449,486
 —
 3,449,486
 —
Domestic Large Cap Growth1,909,836 1,909,836 0 0 
Domestic Large Cap Value3,381,285
 —
 3,381,285
 —
Domestic Large Cap Value1,931,615 1,931,615 0 0 
Domestic Small/Mid Cap GrowthDomestic Small/Mid Cap Growth210,251 210,251 0 0 
Domestic Small/Mid Cap ValueDomestic Small/Mid Cap Value214,034 214,034 0 0 
Domestic Small/Mid Cap Core1,685,352
 —
 1,685,352
 —
Domestic Small/Mid Cap Core464,526 464,526 0 0 
Foreign Large Cap Value1,527,796
 —
 1,527,796
 —
Mutual Funds:       
Equities       
Foreign Large Cap Growth1,060,383
 1,060,383
 —
 —
Foreign Large Cap Growth489,286 489,286 0 0 
Foreign Large Cap Value292,961
 292,961
 —
 —
Foreign Large Cap Value1,098,992 1,098,992 0 0 
Foreign Large Cap CoreForeign Large Cap Core70,782 70,782 0 0 
OtherOther27,984 0 27,984 0 
Total$28,184,697
 $1,635,822
 $26,548,875
 $—
Total$13,082,610 $13,054,626 $27,984 $0 

   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 Income5,987,248
 5,987,248
 —
 —
Foreign Fixed Income611,196
 611,196
 —
 —
Equities       
Domestic Large Cap Growth1,909,836
 1,909,836
 —
 —
Domestic Large Cap Value1,931,615
 1,931,615
 —
 —
Domestic Small/Mid Cap Growth210,251
 210,251
 —
 —
Domestic Small/Mid Cap Value214,034
 214,034
 —
 —
Domestic Small/Mid Cap Core464,526
 464,526
 —
 —
Foreign Large Cap Growth489,286
 489,286
 —
 —
Foreign Large Cap Value1,098,992
 1,098,992
��—
 —
Foreign Large Cap Core70,782
 70,782
 —
 —
Other27,984
 —
 27,984
 —
Total$13,082,610
 $13,054,626
 $27,984
 $—

   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 Income5,859,588
 5,859,588
 —
 —
Foreign Fixed Income609,722
 609,722
 —
 —
Equities       
Domestic Large Cap Growth1,926,076
 1,926,076
 —
 —
Domestic Large Cap Value1,874,643
 1,874,643
 —
 —
Domestic Small/Mid Cap Growth214,180
 214,180
 —
 —
Domestic Small/Mid Cap Value210,891
 210,891
 —
 —
Domestic Small/Mid Cap Core459,363
 459,363
 —
 —
Foreign Large Cap Growth525,720
 525,720
 —
 —
Foreign Large Cap Value1,090,851
 1,090,851
 —
 —
Foreign Large Cap Core28,786
 28,786
 —
 —
Other29,020
 —
 29,020
 —
Total$12,924,957
 $12,895,937
 $29,020
 $—


Each mutual fund or common collective trust 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$500,000 to its pension plan and $400,000 to its postretirement plan in fiscal 2020.2021.
The following table reflects expected future benefit payments:
Fiscal year ending September 30Pension
Plan		Postretirement
Plan
2021$1,043,787 $568,170 
20221,133,470 605,966 
20231,221,341 666,049 
20241,320,157 678,659 
20251,416,485 684,989 
2026-20308,355,472 3,637,984 
Fiscal year ending September 30Pension
Plan		 Postretirement
Plan
2020$995,393
 $633,473
20211,050,564
 685,678
20221,134,262
 732,085
20231,222,806
 790,242
20241,316,860
 794,515
2025-20297,825,994
 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. The following table reflects the Company's contributions:

Years Ended September 30,
20202019
Matching contribution$364,773 $348,369 
Discretionary contribution18,313 21,829 






10.COMMON STOCK OPTIONS

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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, 2019,2020, the number of shares available for future grants was 36,000.23,000.
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 2017,2020, 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,
20202019
Expected volatility31.53%N/A
Expected dividends2.74%N/A
Expected exercise term (years)7.00N/A
Risk-free interest rate0.51%N/A
 Years Ended September 30,
 2019 2018 2017
Expected volatilityN/A N/A 26.09%
Expected dividendsN/A N/A 3.81%
Expected exercise term (years)N/A N/A 7.00
Risk-free interest rateN/A N/A 2.20%

The underlying methods regarding each assumption are as follows:
Expected volatility is based on the historical volatilitiesvolatility 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 SharesWeighted- Average Exercise PriceWeighted- Average Remaining Contractual Terms (years)
Aggregate Intrinsic Value1
 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 outstanding, September 30, 2018100,000 14.34 6.61,237,286 
Options granted —
 —
   Options granted0 0 
Options exercised (31,508) 13.08
   Options exercised(31,508)13.08 
Options expired —
 —
   Options expired0 0 
Options forfeited —
 —
   Options forfeited0 0 
Options outstanding, September 30, 2019 68,492
 $14.91
 6.2 $981,170
Options outstanding, September 30, 201968,492 14.91 6.2981,170 
Options granted Options granted13,000 27.87 
Options exercised Options exercised(29,992)14.65 
Options expired Options expired0 0 
Options forfeited Options forfeited0 0 
Options outstanding, September 30, 2020Options outstanding, September 30, 202051,500 $18.34 6.4$320,797 
      
Vested and exercisable at September 30, 2019 68,492
 $14.91
 6.2 $981,170
Vested and exercisable at September 30, 2020Vested and exercisable at September 30, 202051,500 $18.34 6.4$320,797 
1Aggregate intrinsic value includes only those options where the exercise price is below the market price.
Years Ended September 30,
20202019
Weighted-average grant date option fair value$6.26 $0 
Stock option expense81,380 0 
Intrinsic value of options exercised411,638 456,002 
Proceeds from exercise of stock options439,509 412,179 

11.    OTHER STOCK PLANS
 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 exercised456,002
 15,256
 99,929
Proceeds from exercise of stock options412,179
 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$100,000 per year in additional shares of common stock of the Company. Under the DRIP, the Company issued 26,716, 31,74428,191 and 36,44626,716 shares in 2019, 20182020 and 2017,2019, respectively. As of September 30, 2019,2020, the Company had 390,513362,322 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

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.
65

The following table reflects the director compensation activity pursuant to the Plan:
20202019
SharesWeighted-Average Fair Value on Date of GrantSharesWeighted-Average Fair Value on Date of Grant
Beginning of year balance104,680 $12.51 98,302 $11.51 
  Granted9,193 26.28 6,378 27.93 
  Vested(14,803)10.68 0 0 
  Forfeited0 0 0 0 
End of year balance99,070 $14.06 104,680 $12.51 
 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 balance98,302
 $11.51
 111,893
 $10.56
 107,023
 $10.11
  Granted6,378
 27.93
 6,692
 26.57
 4,870
 16.77
  Vested—
 —
 (20,283) 11.20
 —
 —
  Forfeited—
 —
 —
 —
 —
 —
End of year balance104,680
 $12.51
 98,302
 $11.51
 111,893
 $10.56

The fair market value of the Director Restricted Stock included in compensation during fiscal 2020 and 2019 2018was $241,617 and 2017 was $178,100, $177,800 and $99,400. Norespectively. NaN Director Restricted Stock was forfeited during fiscal 2019, 20182020 or 2017.2019.
As of September 30, 2019,2020, the Company had 65,20852,029 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 onin 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 201820202019
Shares Weighted-Average Fair Value on Date of Grant Shares Weighted-Average Fair Value on Date of GrantSharesWeighted-Average Fair Value on Date of GrantSharesWeighted-Average Fair Value on Date of Grant
Beginning of year balance6,734
 $26.33
 —
 $—
Beginning of year balance10,185 $28.65 6,734 $26.33 
Granted10,227
 29.80
 10,101
 26.33
 Granted14,951 28.17 10,227 29.80 
Vested(6,776) 28.08
 (3,367) 26.33
 Vested(18,321)28.30 (6,776)28.08 
Forfeited—
 —
 —
 —
 Forfeited0 0 0 0 
End of year balance10,185
 $28.65
 6,734
 $26.33
End of year balance6,815 $28.55 10,185 $28.65 
The fair market value of the Officer Restricted Stock included as compensation during fiscal 2020 and 2019 was $450,677 and 2018 was $282,365, and $188,388.respectively. As of September 30, 2019,2020, the Company had 429,151413,718 shares available for issuance under the RSPO.


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 no0 shares in 20192020 and 2018 and 1,628 shares valued at $30,154 in 2017.2019. As of September 30, 20192020 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.inactive.


12.COMMITMENTS AND CONTINGENCIES




66

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, 20192020 for the remainder of the contract period. The current asset management contract was renewed in April 2018July 2020 for a threeone year period which will expire in March 2021.2022. The new contract was renewed at essentially the same terms and conditions as the prior agreement.
agreement, except the utilization fee retained by Roanoke Gas was reduced.
YearNatural Gas Contracts

(In DTHs)
2019-20202020-20212,071,0612,090,972 
2020-20212021-2022295,866
Total2,366,927
Total
2,386,838 

In addition to the volumetric commitment above, the Company also has a fixed price agreement to purchase approximately 1.3 million dth, from October 2020 to March 2021, at prices ranging from $2.17 to $2.62 per dth.
Roanoke Gas also has contracts for pipeline and storage capacity which extend for various periods. These capacity costs and related fees are valued at tariff rates in place as of September 30, 2019.2020. 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$21,881,000 and $28,496,000$30,317,000 under the asset management, pipeline and storage contracts in fiscal years 2019, 20182020 and 2017,2019, respectively. The table below details the pipeline and storage capacity obligationscommitments as of September 30, 20192020 for the remainder of the contract period.
YearPipeline and
Storage Capacity
2019-2020$11,532,130
2020-202111,532,130
2021-202210,858,922
2022-20237,351,348
2023-20245,593,093
Thereafter3,916,965
Total$50,784,588

YearPipeline and
Storage Capacity
2020-2021$11,048,798 
2021-202210,284,092 
2022-20237,403,271 
2023-20245,743,826 
2024-20253,167,937 
Thereafter888,426 
Total$38,536,350 
Roanoke Gas maintains franchise agreements granted by the local cities and towns served by the Company. Roanoke Gas renewed it'sits 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, $2,405,1092020, $2,294,588 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.

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


13.FAIR VALUE MEASUREMENTS

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, 20192020 and 2018,2019, respectively:
 
 Fair Value Measurements - September 30, 2020
Fair ValueQuoted Prices in
Active Markets
Level 1		Significant  Other
Observable
Inputs
Level 2		Significant
Unobservable
Inputs
Level 3
  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:       Liabilities:
Natural gas purchases$397,757
 $—
 $397,757
 $—
Natural gas purchases$470,755 $0 $470,755 $0 
Interest rate swaps894,341
 —
 894,341
 —
Interest rate swaps2,223,556 0 2,223,556 0 
Total$1,292,098
 $—
 $1,292,098
 $—
Total$2,694,311 $0 $2,694,311 $0 

 Fair Value Measurements - September 30, 2019
  Fair Value Measurements - September 30, 2018 Fair ValueQuoted Prices in
Active Markets
Level 1		Significant Other
Observable
Inputs
Level  2		Significant
Unobservable
Inputs
Level 3
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:       Liabilities:
Natural gas purchases$693,495
 $—
 $693,495
 $—
Natural gas purchases$397,757 $0 $397,757 $0 
Interest rate swapsInterest rate swaps894,341 0 894,341 0 
Total$693,495
 $—
 $693,495
 $—
Total$1,292,098 $0 $1,292,098 $0 



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, 20192020 and 2018,2019, 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 consolidated financial statements as of September 30, 20192020 and 2018.2019.
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  Fair Value Measurements - September 30, 2019  Fair Value Measurements - September 30, 2020
Carrying
Amount		 Quoted Prices in
Active Markets
Level 1		 Significant Other
Observable  Inputs
Level 2		 Significant
Unobservable
Inputs
Level 3		 Carrying
Amount		Quoted Prices in
Active Markets
Level 1		Significant Other
Observable  Inputs
Level 2		Significant
Unobservable
Inputs
Level 3
Liabilities:       Liabilities:
Notes payable$95,512,200
 $—
 $—
 $100,900,952
Notes payable$114,975,200 $0 $0 $124,740,970 
Total$95,512,200
 $—
 $—
 $100,900,952
Total$114,975,200 $0 $0 $124,740,970 

  Fair Value Measurements - September 30, 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		 Carrying
Amount		Quoted Prices in
Active  Markets
Level 1		Significant Other
Observable  Inputs
Level 2		Significant
Unobservable
Inputs
Level 3
Liabilities:       Liabilities:
Notes payable$63,243,200
 $—
 $—
 $62,435,237
Notes payable$95,512,200 $0 $0 $100,900,952 
Total$63,243,200
 $—
 $—
 $62,435,237
Total$95,512,200 $0 $0 $100,900,952 


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.


14.QUARTERLY FINANCIAL INFORMATION (UNAUDITED)


14.    QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Quarterly financial data for the years ended September 30, 20192020 and 20182019 is summarized as follows:
2020First
Quarter		Second
Quarter		Third
Quarter		Fourth
Quarter
Operating revenues$19,785,453 $22,437,731 $11,071,918 $9,780,289 
Operating income (loss)$5,081,979 $6,999,616 $1,335,663 $(899,076)
Net income (loss)$4,006,936 $5,680,316 $1,206,578 $(329,296)
Earnings (loss) per share of common stock:
Basic$0.50 $0.70 $0.15 $(0.04)
Diluted$0.49 $0.70 $0.15 $(0.04)
2019First
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 

2018First
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

15.15.    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.
* * * * * *
69




Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
 
Item 9A.
Controls and Procedures.
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, 2019,2020, 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, 2019.2020.


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,GAAP, and that receipts and expenditures are being made only in accordance with authorizations of the management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the financial statements.


Because of the inherent limitations, any system of internal control over financial reporting, no matter how well designed, may not prevent or detect misstatements due to the possibility that a control can be circumvented or overridden or that misstatements due to error or fraud may occur that are not detected. Projections of the effectiveness to future periods are subject to the risk that the internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures included in such controls may deteriorate. The Company’s internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP.


The Company has conducted an evaluation of the design and effectiveness of the Company’s system of internal control over financial reporting as of September 30, 2019,2020, 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, 2019,2020, 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.



brownedwardsa07.jpg


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.
70
brownedwardssignaturea07.jpg

              CERTIFIED PUBLIC ACCOUNTANTS
Blacksburg, Virginia
December 3, 2019


Item 9B.Other Information.
Item 9B.Other Information.
None

71




PART III
 
Item 10.
Directors, Executive Officers and Corporate Governance.
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 20202021 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 20202021 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.Jacqueline L. Archer 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 20202021 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""Delinquent Section 16(a) Reports" in the Proxy Statement for the 20202021 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.
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 20202021 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.
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 20202021 Annual Meeting of Shareholders of Resources, is incorporated herein by reference.


Item 13.
Certain Relationships and Related Transactions, and Director Independence.
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 20202021 Annual Meeting of Shareholders of Resources, which information is incorporated herein by reference.
 
Item 14.
Principal Accounting Fees and Services.
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 20202021 Annual Meeting of Shareholders of Resources is incorporated herein by reference.

72

PART IV
 
Item 15.
Exhibits and Financial Statement Schedules.
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:
(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:
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.Exhibits.
1 (a)
3 (a)
3 (a)
3 (b)
4 (a)
4 (b)
4 (c)
10 (a)PFirm Transportation Agreement between East Tennessee Natural Gas Company and Roanoke Gas Company dated November 1, 1993 (incorporated herein by reference to Exhibit 10(a) of the Annual Report on Form 10-K for the fiscal year ended September 30, 1994 (SEC file number reference 0-367))
10 (b)
10 (c)
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)(c)
10 (e)(d)
10 (f)(e)
10 (g)(f)
10 (h)(g)PGas 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))

73

10 (i)(h)PGas 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)(i)PGas 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)(j)
10 (l)(k)
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)(l)
10(o)10 (m)
10 (p)(n)
10 (q)10(o)
10 (r)(p)
10 (q)
10 (s)(r)
10 (t)(s)
10 (u)(t)
10 (v)(u)

10 (w)(v)PCertificate 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)
74

10 (x)(w)PCertificate 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)1990 (SEC file number reference 0-367))
10 (y)(x)PCertificate 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)1990 (SEC file number reference 0-367))
10 (z)(y)PCertificate 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)1990 (SEC file number reference 0-367))
10 (a)(a)(z)PCertificate 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)1990 (SEC file number reference 0-367))
10 (b)(b)(a)(a)PResolution 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)1987 (SEC file number reference 0-367))
10 (c)(c)(b)(b)PResolution 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)1987 (SEC file number reference 0-367))
10 (d)(d)(c)(c)
10 (e)(e)(d)(d)
10 (f)(f)(e)(e)
10 (g)(g)(f)(f)
10 (h)(h)(g)(g)
10 (i)(i)(h)(h)
10 (j)(j)(i)(i)
10 (k)(k)(j)(j)
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)

10 (m)(m)(k)(k)
10 (l)(l)
10 (n)(n)(m)(m)
75

10 (o)(o)(n)(n)
10 (o)(o)
10 (p)(p)
10 (q)(q)
10 (r)(r)
10 (s)(s)
10 (t)(t)
10 (u)(u)
10 (v)(v)
10 (v)(v)(w)(w)
10 (w)(w)(x)(x)
10 (x)(x)(y)(y)
10 (y)(y)(z)(z)
10 (z)(z)(a)(a)(a)
10 (a)(a)(a)(b)(b)(b)
10 (b)(b)(b)(c)(c)(c)
10 (c)(c)(c)(d)(d)(d)

76

10 (d)(d)(d)(e)(e)(e)
10 (e)(e)(e)(f)(f)(f)
10 (f)(f)(f)(g)(g)(g)
10 (h)(h)(h)
10 (g)(g)(g)(i)(i)(i)
10 (h)(h)(h)(j)(j)(j)
10 (i)(i)(i)(k)(k)(k)
10 (j)(j)(j)(l)(l)(l)
10 (k)(k)(k)(m)(m)(m)
10 (l)(l)(l)(n)(n)(n)
10 (m)(m)(m)(o)(o)(o)
10 (n)(n)(n)(p)(p)(p)
10(q)(q)(q)
10 (o)(o)(o)10(r)(r)(r)
10 (p)(p)(p)10(s)(s)(s)
10(q)(q)(q)10(t)(t)(t)
77

10(r)(r)(r)10(u)(u)(u)
10(s)(s)(s)10(v)(v)(v)

10(t)(t)(t)10(w)(w)(w)
10(u)(u)(u)10(x)(x)(x)
10(v)(v)(v)10(y)(y)(y)
10(w)(w)(w)10(z)(z)(z)
10(x)(x)(x)10(a)(a)(a)(a)
10(y)(y)(y)10(b)(b)(b)(b)
10(z)(z)(z)10(c)(c)(c)(c)
10(a)(a)(a)(a)10(d)(d)(d)(d)
10(b)(b)(b)(b)10(e)(e)(e)(e)
10(c)(c)(c)(c)10(f)(f)(f)(f)**
10(d)(d)(d)(d)10(g)(g)(g)(g)
10(e)(e)(e)(e)10(h)(h)(h)(h)
1310(i)(i)(i)(i)
10(j)(j)(j)(j)
10(k)(k)(k)(k)
10(l)(l)(l)(l)
78

13
2114
21
23
31.1
31.2
32.1*
32.2*
101The following documents from the Registrant’s Annual Report on Form 10-K for the years ended September 30, 2019, 20182020 and 2017,2019, formatted in XBRL (eXtensible Business Reporting Language); Consolidated Balance Sheets at September 30, 20192020 and 2018,2019, (ii) Consolidated Statements of Income for the years ended September 30, 2019, 20182020 and 2017,2019, (iii) Consolidated Statements of Comprehensive Income for the years ended September 30, 2019, 20182020 and 2017,2019, (iv) Consolidated Statements of Stockholders’ Equity for the years ended September 30, 2019, 20182020 and 2017,2019, (v) Consolidated Statements of Cash Flows for the years ended September 30, 2019, 20182020 and 2017,2019, and (vi) Notes to Consolidated Financial Statements.

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

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

PThese original exhibits were filed with the SEC in paper form and therefore are not hyper-linked to the original 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.
Item 16.
Form 10-K Summary.


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.



79

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        RANDALL P. BURTON, II
December 3, 20192020
Paul W. NesterRandall P. Burton, IIDate
Vice President, Secretary, Treasurer and CFO
(principal accounting and financial officer)Principal Financial Officer)

80

Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report on Form 10-K has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
 
/S/    PAUL W. NESTER        
December 3, 2020President and Chief Executive Officer, Director
Paul W. NesterDate(Principal Executive Officer)
/S/    RANDALL P. BURTON, II
December 3, 2020Vice President, Secretary, Treasurer and CFO
Randall P. Burton, IIDate(Principal Financial Officer)
/S/    JOHN B. WILLIAMSON, III        
December 3, 2020Chairman of the Board and Director
John B. Williamson, IIIDate
/S/    JOHN S. D'ORAZIO        /    NANCY H. AGEE        
December 3, 20192020President and Chief Executive Officer, Director
John S. D'OrazioNancy H. AgeeDate
/S/    PAUL W. NESTER        JACQUELINE L. ARCHER
December 3, 20192020
Vice President, Treasurer and CFO
(principal accounting and financial officer)
Director
Paul W. NesterJacqueline L. ArcherDate
/S/    JOHN B. WILLIAMSONABNEY S. BOXLEY, III        
December 3, 20192020Chairman of the Board and Director
John B. Williamson, IIIDate
/S/    NANCY H. AGEE        
December 3, 2019Director
Nancy H. AgeeDate
/S/    ABNEY S. BOXLEY, III        
December 3, 2019Director
Abney S. Boxley, IIIDate
/S/  T. JOE CRAWFORD
December 3, 20192020Director
T. Joe CrawfordDate
/S/    MARYELLEN F. GOODLATTE        
December 3, 20192020Director
Maryellen F. GoodlatteDate
/S/    J. ALLEN LAYMAN        
December 3, 20192020Director
J. Allen LaymanDate
/S/    S. FRANK SMITH        
December 3, 20192020Director
S. Frank SmithDate
/S/    RAYMOND D. SMOOT, JR.        
December 3, 2019Director
Raymond D. Smoot, Jr.Date

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