10-K 1 rgco-9302019x10kxq4.htm 10-K Document
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended September 30, 2019
Commission file number 000-26591
RGC RESOURCES, INC.
(Exact name of registrant as specified in its charter)
Virginia
 
54-1909697
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
519 Kimball Avenue, N.E., Roanoke, VA
 
24016
(Address of principal executive offices)
 
(Zip Code)
Registrant’s telephone number, including area code (540) 777-4427
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Trading Symbol
Name of Each Exchange on
Which Registered
Common Stock, $5 Par Value
RGCO
NASDAQ Global Market

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

Indicate by check mark if the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act.        Yes  ¨  No  x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨  No  x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See definition of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
 
Large accelerated filer
 
¨
  
Accelerated filer
 
x
 
 
 
 
Non-accelerated filer
 
¨ (Do not check if smaller reporting company)
  
Smaller reporting company
 
x
 
 
 
 
Emerging growth company
 
¨
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨   No  x
State the aggregate market value of the voting and non voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity as of the last business day of the registrant’s most recently completed second fiscal quarter: March 31, 2019. $199,858,266
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the last practicable date.
Class
 
Outstanding at November 22, 2019
COMMON STOCK, $5 PAR VALUE
 
8,081,123 SHARES
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the RGC Resources, Inc. Proxy Statement for the 2020 Annual Meeting of Shareholders are incorporated by reference into Part III hereof.



TABLE OF CONTENTS
 
 
 
 
 
 
 
 
Page Number
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 1.
 
 
 
 
 
 
 
Item 1A.
 
 
 
 
 
 
 
Item 1B.
 
 
 
 
 
 
 
Item 2.
 
 
 
 
 
 
 
Item 3.
 
 
 
 
 
 
 
Item 4.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 5.
 
 
 
 
 
 
 
Item 6.
 
 
 
 
 
 
 
Item 7.
 
 
 
 
 
 
 
Item 7A.
 
 
 
 
 
 
 
Item 8.
 
 
 
 
 
 
 
Item 9.
 
 
 
 
 
 
 
Item 9A.
 
 
 
 
 
 
 
Item 9B.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 10.
 
 
 
 
 
 
 
Item 11.
 
 
 
 
 
 
 
Item 12.
 
 
 
 
 
 
 
Item 13.
 
 
 
 
 
 
 
Item 14.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 15.
 
 
 
 
 
 
 
Item 16.
 
 
 
 
 
 
 
 




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

2


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


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.

General and Historical Development
Resources was incorporated in the state of Virginia on July 31, 1998, for the primary purpose of becoming the holding company for Roanoke Gas and its subsidiaries. Effective July 1, 1999, Roanoke Gas and its subsidiaries were reorganized into the holding company structure. Resources is currently composed of the following subsidiaries: Roanoke Gas, Diversified Energy and Midstream.

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

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

Diversified Energy currently has no active operations.

Services
Roanoke Gas maintains an integrated natural gas distribution system to deliver natural gas purchased from suppliers to residential, commercial and industrial users in its service territory. The schedule below is a summary of customers, delivered volumes (expressed in DTH), revenues and margin as a percentage of the total for each category. For the purposes of this schedule, margin for the utility operations is defined as revenues less cost of gas. 
 
 
2019
 
 
Customers
 
Volume
 
Revenue
 
Margin
Residential
 
91.2
%
 
39
%
 
58
%
 
60
%
Commercial
 
8.7
%
 
31
%
 
33
%
 
26
%
Industrial
 
0.1
%
 
30
%
 
7
%
 
11
%
Other Utility
 
0.0
%
 
0
%
 
1
%
 
2
%
Other Non-Utility
 
0.0
%
 
0
%
 
1
%
 
1
%
Total Percent
 
100.0
%
 
100
%
 
100
%
 
100
%
Total Value
 
60,741

 
9,876,493

 
$
68,026,525

 
$
35,205,551

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

 
9,925,974

 
$
65,534,736

 
$
32,776,289


5


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

 
8,562,582

 
$
62,296,870

 
$
32,809,157


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

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

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

Suppliers
Roanoke Gas relies on multiple interstate pipelines including those operated by Columbia Gas Transmission Corporation, LLC and Columbia Gulf Transmission Corporation, LLC (together “Columbia”), and East Tennessee Natural Gas, LLC (“East Tennessee”), Tennessee Gas Pipeline, Midwestern Gas Transmission Company and Saltville Gas Storage Company, LLC ("Saltville") to transport natural gas from the production and storage fields to Roanoke Gas’ distribution system. Roanoke Gas is directly served by two pipelines, Columbia and East Tennessee. Columbia historically has delivered more than 60% of the Company’s gas supply, while East Tennessee delivers the balance of the Company’s requirements. The rates paid for natural gas transportation and storage services purchased from the interstate pipeline companies are established by tariffs approved by FERC. These tariffs contain flexible pricing provisions, which, in some instances, authorize these transporters to reduce rates and charges to meet price competition. The current pipeline contracts expire at various times from 2022 to 2027. The Company anticipates being able to renew these contracts or enter into other contracts to meet customers’ continued demand for natural gas.

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

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

6



The Company uses summer storage programs to supplement gas supply requirements during the winter months. During the summer months, the Company injects gas into its LNG facility. In addition, the Company has contracted for storage capacity from Columbia, Tennessee Gas Pipeline and Saltville for a combined total of more than 2.4 million DTH of storage capacity. The balance of the Company’s annual natural gas requirements are met primarily through market purchases made by its asset manager.

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

Management anticipates that the Company will be able to renew all of its franchises when they expire. There can be no assurance, however, that a given jurisdiction will not refuse to renew a franchise or will not, in connection with the renewal of a franchise, attempt to impose restrictions or conditions that could adversely affect the Company’s business operations or financial condition. CPCNs, issued by the SCC, are generally of perpetual duration and subject to compliance with regulatory standards.

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

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

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

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

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

Employees
At September 30, 2019, Resources had 106 full-time employees and 107 total employees. As of that date, 26 employees, or 24%, belonged to the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied-Industrial International Union, Local No. 515 and were represented under a collective bargaining agreement. The union has been

7


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

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

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

OPERATIONAL RISKS

Availability of sufficient and reliable pipeline capacity.

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

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

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

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



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.

Inability to attract and retain professional and technical employees.

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

Geographic concentration of business activities.

The Company's business activities are concentrated in the Roanoke Valley. Changes in the local economy, politics, regulations and weather patterns could negatively impact the Company's existing customer base, leading to declining usage patterns and financial condition of customers, both of which could adversely affect earnings.
    
Impact of weather conditions and related regulatory mechanisms.
    
The Company’s revenues and earnings are dependent upon weather conditions. The Company’s rate structure currently has a WNA factor that results in either a recovery or refund of revenues due to any variation from the 30-year average for heating degree-days. If the provision for the WNA were removed from its rate structure, the Company would be exposed to a much greater risk related to weather variability resulting in earnings volatility. A colder than normal winter could cause the Company to incur higher than normal operating and maintenance costs.

Volatility in the price and availability of natural gas.

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

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

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

9


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

Competition from other energy providers.

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

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

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

REGULATORY RISKS

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

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

Increased compliance and pipeline safety requirements and fines.

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

Regulatory actions or failure to obtain timely rate relief.

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


10


Compliance with and Changes in Tax Laws.

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

FINANCIAL RISKS

Investment in Mountain Valley Pipeline, LLC.

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

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

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

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

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


11


Access to capital to maintain liquidity.

The Company relies on a variety of capital sources to operate its business and fund capital expenditures, including internally generated cash from operations, short-term borrowings under its line-of-credit, proceeds from the issuance of additional shares of its common stock and other sources. Access to a line-of-credit is essential to provide seasonal funding of natural gas operations and provide capital budget bridge financing. Access to capital markets and other long-term funding sources is important for capital outlays and funding of the LLC investment. The ability of the Company to maintain and renew its line-of-credit and to secure longer-term financing is critical to operations. Adverse market trends, market disruptions or deterioration in the financial condition of the Company could increase the cost of borrowing, restrict the Company's ability to issue additional shares of its common stock or otherwise limit the Company’s ability to secure adequate funding.
    
Insurance coverage may not be sufficient.

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

Post-retirement benefits and related funding of obligations.

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

Failure to comply with debt covenant requirements.

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

Exposure to Market Risks.

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

Item 1B.
Unresolved Staff Comments.

Not applicable.






12


Item 2.
Properties.

Included in “Utility Property” on the Company’s consolidated balance sheet are storage plant, transmission plant, distribution plant and general plant of Roanoke Gas as categorized by natural gas utilities. The Company has approximately 1,146 miles of transmission and distribution pipeline with transmission and distribution plant representing 88% of the total utility plant investment. The transmission and distribution pipelines are located on or under public roads and highways or private property for which the Company has obtained the legal authorization and rights to operate.
Roanoke Gas currently owns and operates nine metering stations through which it measures and regulates the gas being delivered by its suppliers. These stations are located at various points throughout the Company’s distribution system.
Roanoke Gas also owns a liquefied natural gas storage facility located in its service territory that has the capacity to store up to 200,000 DTH of natural gas.
The Company’s executive, accounting and business offices, along with its maintenance and service departments, are located on Kimball Avenue in Roanoke, Virginia.
Although the Company considers its present properties to be adequate, management continues to evaluate the adequacy of its current facilities as additional needs arise.
 
Item 3.
Legal Proceedings.

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

Not applicable.
 

13


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

Market Information
Resources' common stock is listed on the NASDAQ Global Market under the trading symbol RGCO. Payment of dividends is within the discretion of the Board of Directors and depends on, among other factors, earnings, capital requirements, and the operating and financial condition of the Company.
 
 
Range of Bid Prices
 
Cash Dividends
Year Ending September 30, 2019
 
High
 
Low
 
Declared
 First Quarter
 
$
30.71

 
$
24.16

 
$
0.1650

 Second Quarter
 
30.51

 
26.50

 
0.1650

 Third Quarter
 
30.52

 
25.63

 
0.1650

 Fourth Quarter
 
31.00

 
26.46

 
0.1650

 
 
 
 
 
 
 
Year Ending September 30, 2018
 
 
 
 
 
 
 First Quarter
 
$
31.57

 
$
25.01

 
$
0.1550

 Second Quarter
 
27.49

 
22.16

 
0.1550

 Third Quarter
 
29.46

 
23.61

 
0.1550

 Fourth Quarter
 
31.33

 
25.85

 
0.1550

As of November 22, 2019, there were 1,106 holders of record of the Company’s common stock. This number does not include all beneficial owners of common stock who hold their shares in “street name.”

Comparisons of Cumulative Total Shareholder Returns
The following performance graph compares the Company’s total shareholder return from September 30, 2014 through September 30, 2019 with the Dow Jones US Utility Index, a utility based index, and the S&P 500 Index, a broad market index.
The graph below reflects the value of a hypothetical investment of $100 made September 30, 2014 in the Company’s common stock and in each index as of September 30, 2019, assuming the reinvestment of all dividends. Historical stock price performance as reflected on the graph is not indicative of future price performance. The total value at the end of the five years was $250 for the Company’s common stock, $185 for the Dow Jones US Utilities Index and $167 for the S&P 500 Index.





14


chart-a07a7d952c695f03bd6a06.jpg
A summary of the Company’s equity compensation plans follows as of September 30, 2019:
 
 
(a)
 
(b)
 
(c)
Plan category
 
Number of securities
to be issued upon
exercise of
outstanding options,
warrants and rights
 
Weighted-average
exercise price of
outstanding
options, warrants
and rights
 
Number of securities
remaining available
for future issuance
under equity
compensation plans
(excluding securities
reflected in column
(a))
Equity compensation plans approved by security holders
 
68,492

 
$14.91
 
535,144

Equity compensation plans not approved by security holders
 

 

 

Total
 
68,492

 
$14.91
 
535,144

 

15



Item 6.
Selected Financial Data.

 
 
Year Ending September 30,
 
 
2019
 
2018
 
2017
 
2016
 
2015
 
 
 
 
 
 
 
 
 
 
 
Operating Revenues
 
$
68,026,525

 
$
65,534,736

 
$
62,296,870

 
$
59,063,291

 
$
68,189,607

Operating Income (1)
 
11,595,464

 
11,470,507

 
12,192,742

 
11,644,839

 
10,129,130

Net Income
 
8,698,412

 
7,297,205

 
6,232,865

 
5,806,866

 
5,094,415

Basic Earnings Per Share
 
$
1.08

 
$
0.95

 
$
0.86

 
$
0.81

 
$
0.72

Cash Dividends Declared Per Share
 
$
0.66

 
$
0.62

 
$
0.58

 
$
0.54

 
$
0.51

Book Value Per Share
 
$
10.29

 
$
9.95

 
$
8.29

 
$
7.75

 
$
7.43

Average Shares Outstanding
 
8,039,484

 
7,649,025

 
7,218,686

 
7,149,906

 
7,092,315

Total Assets
 
$
258,353,696

 
$
219,560,106

 
$
183,135,071

 
$
165,552,849

 
$
145,847,194

 
 
 
 
 
 
 
 
 
 
 
Long-Term Debt (Less Unamortized Debt Expense)
 
$
103,371,358

 
$
70,321,936

 
$
61,312,011

 
$
33,636,051

 
$
30,316,573

Stockholders' Equity
 
83,096,392

 
79,583,112

 
60,040,472

 
55,667,072

 
52,840,991

Shares Outstanding at Sept. 30
 
8,073,264

 
7,994,615

 
7,240,846

 
7,182,434

 
7,112,247

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

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

Overview

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

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

More than 98% of the Company’s revenues, excluding equity in earnings of MVP, are derived from the sale and delivery of natural gas to Roanoke Gas customers. The SCC authorizes the rates and fees the Company charges its customers for these services. These rates are designed to provide the Company with the opportunity to recover its gas and non-gas expenses and to earn a reasonable rate of return for shareholders based on normal weather.

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

16


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

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

The Company is committed to the safe and reliable delivery of natural gas to its customers. Since 1991, the Company has placed an emphasis on the modernization of its distribution system through the renewal and replacement of its cast iron and bare steel natural gas distribution pipelines and other system improvements. In 2017, the Company completed the replacement of all cast iron and bare steel pipe and is continuing its renewal program with other qualified infrastructure replacement programs including the renewal of first generation, pre-1973 plastic pipe.

The Company is also dedicated to the safeguarding of its information technology systems.  These systems contain confidential customer, vendor and employee information as well as important financial data.  There is risk associated with the unauthorized access of this information with a malicious intent to corrupt data, cause operational disruptions, or compromise information.  Management believes it has taken reasonable security measures to protect these systems from cyber attacks and other types of incidents; however, there can be no guarantee that an incident will not occur.  In the event of a cyber incident, the Company will execute its Security Incident Response Plan.  The Company maintains cyber-insurance coverage to mitigate financial expense that may result from a cyber incident.

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

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

17



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

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

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

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

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

Results of Operations

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


18



Fiscal Year 2019 Compared with Fiscal Year 2018

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

Operating Revenues
 
 
 
 
 
 
 
Year Ended September 30,
2019
 
2018
 
Increase / (Decrease)
 
Percentage
Gas Utilities
$
67,306,260

 
$
64,341,783

 
$
2,964,477

 
5
 %
Other
720,265

 
1,192,953

 
(472,688
)
 
(40
)%
Total Operating Revenues
$
68,026,525

 
$
65,534,736

 
$
2,491,789

 
4
 %

Delivered Volumes
 
 
 
 
 
 
 
Year Ended September 30,
2019
 
2018
 
Increase / (Decrease)
 
Percentage
Regulated Natural Gas (DTH)
 
 
 
 
 
 
 
 Residential and Commercial
6,901,181

 
7,103,825

 
(202,644
)
 
(3
)%
 Transportation and Interruptible
2,975,312

 
2,822,149

 
153,163

 
5
 %
 Total Delivered Volumes
9,876,493

 
9,925,974

 
(49,481
)
 
 %
Heating Degree Days (Unofficial)
3,791

 
3,954

 
(163
)
 
(4
)%

Total gas utility operating revenues for the year ended September 30, 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 operating income, the most comparable GAAP financial measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. Therefore, the following discussion of financial performance will reference gross utility margin as part of the analysis of the results of operations.


19


Gross Utility Margin
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended September 30,
2019
 
2018
 
Increase
 
Percentage
Utility revenues
$
67,306,260

 
$
64,341,783

 
$
2,964,477

 
5
%
Cost of gas
32,401,123

 
32,091,923

 
309,200

 
1
%
Gross Utility Margin
$
34,905,137

 
$
32,249,860

 
$
2,655,277

 
8
%

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

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

 
Years Ended September 30,
 
 
 
2019
 
2018
 
Increase / (Decrease)
Customer Base Charge
$
13,486,234

 
$
12,476,755

 
$
1,009,479

SAVE Plan
1,599,281

 
4,468,556

 
(2,869,275
)
Volumetric
19,298,454

 
15,889,359

 
3,409,095

WNA
452,892

 
44,569

 
408,323

Carrying Cost
462,260

 
554,090

 
(91,830
)
Excess Revenues - Tax Reform
(523,881
)
 
(1,320,167
)
 
796,286

Other Revenues
129,897

 
136,698

 
(6,801
)
Total
$
34,905,137

 
$
32,249,860

 
$
2,655,277


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

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

20


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

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

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

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

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

Net Income and Dividends - Net income for fiscal 2019 was $8,698,412 compared to $7,297,205 for fiscal 2018. Basic and diluted earnings per share were $1.08 in fiscal 2019 compared to $0.95 in fiscal 2018. Dividends declared per share of common stock were $0.66 in fiscal 2019 compared to $0.62 in fiscal 2018.
    
Fiscal Year 2018 Compared with Fiscal Year 2017

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

Operating Revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended September 30,
2018
 
2017
 
Increase
 
Percentage
Gas Utilities
$
64,341,783

 
$
61,252,015

 
$
3,089,768

 
5
%
Other
1,192,953

 
1,044,855

 
148,098

 
14
%
Total Operating Revenues
$
65,534,736

 
$
62,296,870

 
$
3,237,866

 
5
%


21


Delivered Volumes
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended September 30,
2018
 
2017
 
Increase
 
Percentage
Regulated Natural Gas (DTH)
 
 
 
 
 
 
 
 Residential and Commercial
7,103,825

 
5,840,883

 
1,262,942

 
22
%
 Transportation and Interruptible
2,822,149

 
2,721,699

 
100,450

 
4
%
 Total Delivered Volumes
9,925,974

 
8,562,582

 
1,363,392

 
16
%
Heating Degree Days (Unofficial)
3,954

 
3,250

 
704

 
22
%

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

Gross Utility Margin
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended September 30,
2018
 
2017
 
Increase / (Decrease)
 
Percentage
Utility revenues
$
64,341,783

 
$
61,252,015

 
$
3,089,768

 
5
%
Cost of gas
32,091,923

 
28,919,625

 
3,172,298

 
11
%
Gross Utility Margin
$
32,249,860

 
$
32,332,390

 
$
(82,530
)
 
%

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

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



22


 
Years Ended September 30,
 
 
 
2018
 
2017
 
Increase / (Decrease)
Customer Base Charge
$
12,476,755

 
$
12,412,753

 
$
64,002

SAVE Plan
4,468,556

 
3,813,043

 
655,513

Volumetric
15,889,359

 
13,573,704

 
2,315,655

WNA
44,569

 
1,839,454

 
(1,794,885
)
Carrying Cost
554,090

 
588,624

 
(34,534
)
Rate Refund
(1,320,167
)
 

 
(1,320,167
)
Other Revenues
136,698

 
104,812

 
31,886

Total
$
32,249,860

 
$
32,332,390

 
$
(82,530
)

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

General Taxes - General taxes increased $91,940, or 5%, primarily due to higher property taxes associated with increases in utility property offset by lower payroll taxes.
 
Depreciation - Depreciation expense increased by $699,607 or 11%, corresponding to 10% increase in utility plant investment.

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

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

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

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

23


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

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

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

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

Cash Flow Summary
Year Ended September 30,
 
2019
 
2018
 
2017
Net cash provided by operating activities
$
14,697,704

 
$
13,503,795

 
$
12,980,978

Net cash used in investing activities
(42,830,005
)
 
(34,166,578
)
 
(23,492,555
)
Net cash provided by financing activities
29,516,238

 
20,840,554

 
9,937,965

Increase (decrease) in cash and cash equivalents
$
1,383,937

 
$
177,771

 
$
(573,612
)

Cash Flows Provided by Operating Activities:

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

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

24


 
Years Ended September 30,
 
 
Cash Flows From Operating Activities:
2019
 
2018
 
Increase (Decrease)
Net Income
$
8,698,412

 
$
7,297,205

 
$
1,401,207

Depreciation
7,600,852

 
7,090,169

 
510,683

Equity in earnings
(3,020,348
)
 
(938,531
)
 
(2,081,817
)
Gas in storage
1,178,889

 
74,698

 
1,104,191

Prepaid income taxes
(320,297
)
 
959,142

 
(1,279,439
)
Change in over-collection of gas costs
1,084,735

 
(2,360,972
)
 
3,445,707

Deferred taxes
684,028

 
755,994

 
(71,966
)
Accounts payable and accrued expenses
(2,745,377
)
 
191,054

 
(2,936,431
)
Rate refund
2,507,422

 
1,320,167

 
1,187,255

Other
(970,612
)
 
(885,131
)
 
(85,481
)
Net cash provided by operating activities
$
14,697,704

 
$
13,503,795

 
$
1,193,909


Cash Flows Used in Investing Activities:

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

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

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



25


Cash Flows Provided by Financing Activities:

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

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

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

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

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

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

Off-Balance Sheet Arrangements

The Company has no off-balance sheet arrangements as defined in Regulation S-K, Item 303(a)(4)(ii).

Contractual Obligations and Commitments

The Company has incurred various contractual obligations and commitments in the normal course of business. As of September 30, 2019, the estimated recorded and unrecorded obligations are as follows:

26


Recorded contractual obligations:
Less than 1 year
 
1-3 Years
 
4-5 Years
 
After 5 Years
 
Total
Long-Term Debt - Notes Payable (1)
$

 
$
23,012,200

 
$
10,000,000

 
$
62,500,000

 
$
95,512,200

Long-Term Debt - Line of Credit (2)

 
8,172,473

 

 

 
8,172,473

Total
$

 
$
31,184,673

 
$
10,000,000

 
$
62,500,000

 
$
103,684,673

 
 
 
 
 
 
 
 
 
 
(1) See Note 7 to the consolidated financial statements.
(2) See Notes 6 and 7 to the consolidated financial statements. New line-of-credit agreement executed for a 2-year term, expiring March 31, 2021. Amounts drawn against agreement are considered non-current as they are not subject to repayment within 12-months.
Unrecorded contractual obligations, not reflected in consolidated balance sheets in accordance with US GAAP:
Less than 1 year
 
1-3 Years
 
4-5 Years
 
After 5 Years
 
Total
Pipeline and Storage Capacity (3)
$
11,532,130

 
$
22,391,052

 
$
12,944,441

 
$
1,950,134

 
$
48,817,757

Gas Supply (4)

 

 

 

 

Interest on Line-of-Credit (5)
40,806

 
22,750

 

 

 
63,556

Interest on Notes Payable (6)
3,509,997

 
5,902,370

 
3,185,711

 
15,396,752

 
27,994,830

Pension Plan Funding (7)

 

 

 

 

Investment in MVP (8)
14,917,024

 
1,354,456

 

 

 
16,271,480

Franchise Agreements (9)
110,521

 
231,088

 
245,161

 
1,818,339

 
2,405,109

Other Obligations (10)
207,085

 
228,116

 
3,596

 
12,105

 
450,902

Total
$
30,317,563

 
$
30,129,832

 
$
16,378,909

 
$
19,177,330

 
$
96,003,634

 
 
 
 
 
 
 
 
 
 
(3) Recoverable through the PGA process.
(4) Volumetric obligation is for the purchase of contracted decatherms of natural gas at market prices in effect at the time of purchase. Unable to estimate related payment obligation until time of purchase. See Note 12 to the consolidated financial statements.
(5) Accrued interest on line-of-credit balance at September 30, 2019, including minimum facility fee on unused line-of-credit. See Note 6 to the consolidated financial statements.
(6) Calculated interest payments notes payable included in Note 7 to the consolidated financial statements.
(7) Estimated minimum funding requirement assuming application of credit balances in plan to offset funding. Minimum funding requirements beyond five years is not available. See Note 9 to the consolidated financial statements for the planned funding in fiscal 2019.
(8) Projected remaining funding of the Company's 1% interest in the LLC as entered into on October 1, 2015.
(9) Franchise tax obligations due Roanoke City, Salem City and Town of Vinton per 20-year term agreements. See Note 12 to the consolidated financial statements.
(10) Various lease, maintenance, equipment and service contracts.
              
Equity Investment in Mountain Valley Pipeline

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

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


27


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

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

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

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

Regulatory and Tax Reform

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

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

28


SCC staff report and the rebuttal testimony and evidence presented at the hearing, management has established a provision for a refund of revenues collected in excess of management's expectations regarding the final rate award. On November 19, 2019, the hearing examiner issued his report, which was subsequently revised on November 26, 2019. Although the revised report indicated a more favorable result than reflected in management's estimates, no adjustment was made to the rate refund estimate included in the September 30, 2019 financial statements, as recent rate orders from the SCC Commissioners have differed from the findings included in the hearing examiners' reports. The Company will continue to monitor information and refine its assumptions regarding its refund estimates until such time as the SCC issues its final order and new billing rates are finalized.
 
Since its prior rate case in 2013, Roanoke Gas has deferred costs attributable to compliance and safety related expenses. These ESAC expenses were above and beyond a base line for those costs previously provided for in non-gas base rates and have been included in the current rate application for recovery over a five-year period. As noted above, the SCC staff report recommended excluding a portion of these costs from rate recovery. The Company has evaluated the situation and adjusted the valuation based on its assessment of the resolution. If the ultimate result is different from management's assessment, any difference would be further adjusted following a final order from the SCC.

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

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

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

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

29


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

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

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

Roanoke Gas' provision for depreciation is computed principally based on composite rates determined by depreciation studies. These depreciation studies are required to be performed on the regulated utility assets of Roanoke Gas at least every five years. The previous depreciation study was completed and implemented in fiscal 2014. On June 11, 2019, Roanoke Gas submitted its current depreciation study, which incorporates all of the new and replacement infrastructure and equipment placed in service since the last study. In September 2019, the SCC administratively approved the depreciation study and directed the Company to implement the new rates retroactive to October 1, 2018. The new depreciation rates resulted in a reduction of total depreciation expense of $32,570 for fiscal 2019.

Critical Accounting Policies and Estimates

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

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

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

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

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

30


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

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

The Company bills its regulated natural gas customers on a monthly cycle. The billing cycle for most customers does not coincide with the accounting periods used for financial reporting. The Company accrues estimated revenue for natural gas delivered to customers but not yet billed during the accounting period based on weather during the period and current and historical data. The consolidated financial statements include unbilled revenue of $1,236,384 and $911,657 as of September 30, 2019 and 2018, respectively.

The Company adopted ASU 2014-09, Revenue from Contracts with Customers, and subsequent guidance and amendments effective October 1, 2018. The adoption of the ASU did not have a significant effect on the Company's results of operations, financial position or cash flows as the new guidance resulted in essentially no change in the manner and timing in which the Company recognizes revenues. The primary operation of the Company is the sale and/or delivery of natural gas to customers (the performance obligation) based on SCC approved tariff rates (the transaction price). The Company recognizes revenue through billed and unbilled customer usage as natural gas is delivered. The Company also recognizes revenue through ARPs, including the WNA.
Allowance for Doubtful Accounts - The Company evaluates the collectability of its accounts receivable balances based upon a variety of factors including loss history, level of delinquent account balances, collections on previously written off accounts and general economic conditions. The Company outsourced its credit and collections function in 2017 as part of its strategic decision to move the call center, billing and other customer service functions to a third-party provider with significant utility experience. These changes have been incorporated into the current valuation model for accounts receivable, which used historical information based on collection functions previously handled in-house.

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


31


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

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

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

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

Funded status - September 30, 2019
Pension
 
Postretirement
 
Total
Benefit Obligation
$
35,550,987

 
$
18,030,399

 
$
53,581,386

Fair value of assets
33,586,671

 
13,082,610

 
46,669,281

Funded status
$
(1,964,316
)
 
$
(4,947,789
)
 
$
(6,912,105
)
Funded status - September 30, 2018
Pension
 
Postretirement
 
Total
Benefit Obligation
$
28,850,299

 
$
16,207,322

 
$
45,057,621

Fair value of assets
28,184,697

 
12,924,957

 
41,109,654

Funded status
$
(665,602
)
 
$
(3,282,365
)
 
$
(3,947,967
)

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

32


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

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

The following schedule reflects the sensitivity of pension costs to changes in certain actuarial assumptions, assuming that the other components of the calculation remain constant.
Actuarial Assumptions - Pension Plan
Change in Assumption
 
Increase in Pension Cost
 
Increase in Projected Benefit Obligation
Discount rate
-0.25
 %
 
$
145,000

 
$
1,497,000

Rate of return on plan assets
-0.25
 %
 
83,000

 
N/A

Rate of increase in compensation
0.25
 %
 
53,000

 
280,000


The following schedule reflects the sensitivity of postretirement benefit costs from changes in certain actuarial assumptions, while the other components of the calculation remain constant.
Actuarial Assumptions - Postretirement Plan
Change in Assumption
 
Increase in Postretirement Benefit Cost
 
Increase in Accumulated Postretirement Benefit Obligation
Discount rate
-0.25
 %
 
$
39,000

 
$
753,000

Rate of return on plan assets
-0.25
 %
 
32,000

 
N/A

Medical claim cost increase
0.25
 %
 
78,000

 
722,000


Derivatives - The Company may hedge certain risks incurred in its operation through the use of derivative instruments. The Company applies the requirements of FASB ASC No. 815, Derivatives and Hedging, which requires the recognition of derivative instruments as assets or liabilities in the Company’s consolidated balance sheet at fair value. In most instances, fair value is based upon quoted futures prices for natural gas commodities and interest rate futures for interest rate swaps. Changes in the commodity and futures markets will impact the estimates of fair value in the future. Furthermore, the actual market value at the point of realization of the derivative may be significantly different from the values used in determining fair value in prior financial statements. The Company had three interest-rate swaps outstanding at September 30, 2019 related to the three variable rate notes held by the Company. See Note 7 for additional information regarding the swaps.
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk.

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




33


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.

34



RGC Resources, Inc.
and Subsidiaries

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

35



RGC RESOURCES, INC. AND SUBSIDIARIES
TABLE OF CONTENTS
 


36



brownedwardsa07.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, 2019 and 2018, and the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows for each of the years in the three-year period ended September 30, 2019, and the related notes (collectively referred to as the financial statements). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of September 30, 2019 and 2018, and the results of its operations and its cash flows for each of the years in the three-year period ended September 30, 2019, in conformity with accounting principles generally accepted in the United States of America.

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

Basis for Opinion

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

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
 
brownedwardssignaturea07.jpg
              CERTIFIED PUBLIC ACCOUNTANTS

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

Blacksburg, Virginia
December 3, 2019

37



RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AS OF SEPTEMBER 30, 2019 AND 2018
 
 
 
2019
 
2018
ASSETS
 
 
 
CURRENT ASSETS:
 
 
 
Cash and cash equivalents
$
1,631,348

 
$
247,411

Accounts receivable, net
3,870,211

 
3,744,228

Materials and supplies
1,021,882

 
913,889

Gas in storage
6,448,307

 
7,627,196

Prepaid income taxes
1,157,980

 
837,683

Regulatory assets
1,521,939

 
1,385,500

Interest rate swap

 
100,723

Other
733,525

 
687,972

Total current assets
16,385,192

 
15,544,602

UTILITY PROPERTY:
 
 
 
In service
237,786,964

 
224,854,320

Accumulated depreciation and amortization
(67,207,334
)
 
(63,099,306
)
In service, net
170,579,630

 
161,755,014

Construction work in progress
11,423,326

 
4,208,614

Utility plant, net
182,002,956

 
165,963,628

OTHER ASSETS:
 
 
 
Regulatory assets
12,178,853

 
8,862,147

Investment in unconsolidated affiliate
47,375,459

 
28,507,146

Interest rate swap

 
209,840

Other
411,236

 
472,743

Total other assets
59,965,548

 
38,051,876

TOTAL ASSETS
$
258,353,696

 
$
219,560,106


(Continued)

38


RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AS OF SEPTEMBER 30, 2019 AND 2018
 
 
 
2019
 
2018
LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
CURRENT LIABILITIES:
 
 
 
Dividends payable
$
1,339,522

 
$
1,242,753

Accounts payable
4,483,233

 
5,211,032

Capital contributions payable
5,024,824

 
10,142,766

Customer credit balances
880,295

 
1,003,622

Customer deposits
1,432,031

 
1,421,043

Accrued expenses
3,448,000

 
3,080,432

Interest rate swap
147,556

 

Regulatory liabilities
4,877,603

 
1,990,201

Total current liabilities
21,633,064

 
24,091,849

LONG-TERM DEBT:
 
 
 
Notes payable
95,512,200

 
63,243,200

Line-of-credit
8,172,473

 
7,361,017

Less unamortized debt issuance costs
(313,315
)
 
(282,281
)
Long-term debt net of unamortized debt issuance costs
103,371,358

 
70,321,936

DEFERRED CREDITS AND OTHER LIABILITIES:
 
 
 
Interest rate swap
746,785

 

Asset retirement obligations
6,788,683

 
6,417,948

Regulatory cost of retirement obligations
11,892,352

 
11,163,981

Benefit plan liabilities
6,912,105

 
3,947,967

Deferred income taxes
12,978,523

 
12,585,577

Regulatory liabilities
10,934,434

 
11,447,736

Total deferred credits and other liabilities
50,252,882

 
45,563,209

COMMITMENTS AND CONTINGENCIES (Note 12)

 

CAPITALIZATION:
 
 
 
Stockholders’ Equity:
 
 
 
Common Stock, $5 par value; authorized 10,000,000 shares; issued and outstanding 8,073,264 and 7,994,615 shares in 2019 and 2018, respectively
40,366,320

 
39,973,075

Preferred stock, no par; authorized 5,000,000 shares; no shares issued and outstanding in 2019 and 2018

 

Capital in excess of par value
14,397,072

 
13,043,656

Retained earnings
30,821,917

 
27,438,049

Accumulated other comprehensive loss
(2,488,917
)
 
(871,668
)
Total stockholders’ equity
83,096,392

 
79,583,112

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
$
258,353,696

 
$
219,560,106

(Concluded)
See notes to consolidated financial statements.

39



RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
YEARS ENDED SEPTEMBER 30, 2019, 2018 AND 2017
 
 
 
2019
 
2018
 
2017
OPERATING REVENUES:
 
 
 
 
 
Gas utilities
$
67,306,260

 
$
64,341,783

 
$
61,252,015

Other
720,265

 
1,192,953

 
1,044,855

Total operating revenues
68,026,525

 
65,534,736

 
62,296,870

OPERATING EXPENSES:
 
 
 
 
 
Cost of gas - utility
32,401,123

 
32,091,923

 
28,919,625

Cost of sales - non utility
419,851

 
666,524

 
568,088

Operations and maintenance
14,089,019

 
12,471,428

 
12,573,608

General taxes
2,066,794

 
1,878,010

 
1,786,070

Depreciation and amortization
7,454,274

 
6,956,344

 
6,256,737

Total operating expenses
56,431,061

 
54,064,229

 
50,104,128

OPERATING INCOME
11,595,464

 
11,470,507

 
12,192,742

Equity in earnings of unconsolidated affiliate
3,020,348

 
938,531

 
421,646

Other income (expense), net
351,882

 
244,868

 
(658,879
)
Interest expense
3,618,551

 
2,461,565

 
1,917,254

INCOME BEFORE INCOME TAXES
11,349,143

 
10,192,341

 
10,038,255

INCOME TAX EXPENSE
2,650,731

 
2,895,136

 
3,805,390

NET INCOME
$
8,698,412

 
$
7,297,205

 
$
6,232,865

EARNINGS PER COMMON SHARE:
 
 
 
 
 
Basic
$
1.08

 
$
0.95

 
$
0.86

Diluted
$
1.08

 
$
0.95

 
$
0.86

WEIGHTED AVERAGE SHARES OUTSTANDING:
 
 
 
 
 
Basic
8,039,484

 
7,649,025

 
7,218,686

Diluted
8,078,950

 
7,695,712

 
7,256,046

See notes to consolidated financial statements.

40



RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
YEARS ENDED SEPTEMBER 30, 2019, 2018 AND 2017
 
 
 
2019
 
2018
 
2017
NET INCOME
$
8,698,412

 
$
7,297,205

 
$
6,232,865

Other comprehensive income, net of tax:
 
 
 
 
 
Interest rate swaps
(894,761
)
 
137,850

 
72,489

Defined benefit plans
(722,488
)
 
406,798

 
1,222,478

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
(1,617,249
)
 
544,648

 
1,294,967

COMPREHENSIVE INCOME
$
7,081,163

 
$
7,841,853

 
$
7,527,832

See notes to consolidated financial statements.

41



RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
YEARS ENDED SEPTEMBER 30, 2019, 2018 AND 2017
 
 
 
Common
Stock
 
Capital in
Excess of
Par Value
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Total
Stockholders’
Equity
Balance - September 30, 2016
$
23,941,445

 
$
9,509,548

 
$
24,713,310

 
$
(2,497,231
)
 
$
55,667,072

Net income

 

 
6,232,865

 

 
6,232,865

Other comprehensive income

 

 

 
1,294,967

 
1,294,967

Exercise of stock options (11,225 shares)
50,250

 
91,991

 

 

 
142,241

Stock option grants

 
73,780

 

 

 
73,780

Cash dividends declared ($0.58 per share)

 

 
(4,195,910
)
 

 
(4,195,910
)
Stock split
12,029,790

 
(10,025,546
)
 
(2,004,244
)
 

 

Issuance costs

 
(96,508
)
 

 

 
(96,508
)
Issuance of common stock (47,187 shares)
182,745

 
739,220

 

 

 
921,965

Balance - September 30, 2017
$
36,204,230

 
$
292,485

 
$
24,746,021

 
$
(1,202,264
)
 
$
60,040,472

Net income

 

 
7,297,205

 

 
7,297,205

Other comprehensive income

 

 

 
544,648

 
544,648

Exercise of stock options (1,575 shares)
7,875

 
12,070

 

 

 
19,945

Cash dividends declared ($0.62 per share)

 

 
(4,839,514
)
 

 
(4,839,514
)
Issuance costs

 
(990,459
)
 

 

 
(990,459
)
Issuance of common stock (752,194 shares)
3,760,970

 
13,729,560

 

 

 
17,490,530

Reclassification adjustment for effect of change in tax law

 

 
234,337

 
(214,052
)
 
20,285

Balance - September 30, 2018
$
39,973,075

 
$
13,043,656

 
$
27,438,049

 
$
(871,668
)