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EX-32.2 - EXHIBIT 32.2 - RGC RESOURCES INCrgco-ex322x9302018xq4.htm
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EX-31.2 - EXHIBIT 31.2 - RGC RESOURCES INCrgco-ex312x9302018xq4.htm
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EX-23 - EXHIBIT 23 - RGC RESOURCES INCrgco-ex23x9302018xq4.htm
EX-21 - EXHIBIT 21 - RGC RESOURCES INCrgco-ex21x9302018xq4.htm
EX-13 - EXHIBIT 13 - RGC RESOURCES INCex132018annualreportr719.htm
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended September 30, 2018
Commission file number 000-26591
RGC RESOURCES, INC.
(Exact name of registrant as specified in its charter)
Virginia
 
54-1909697
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
519 Kimball Avenue, N.E., Roanoke, VA
 
24016
(Address of principal executive offices)
 
(Zip Code)
Registrant’s telephone number, including area code (540) 777-4427
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
 
Name of Each Exchange on
Which Registered
Common Stock, $5 Par Value
 
NASDAQ Global Market

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

Indicate by check mark if the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act.        Yes  ¨  No  x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨  No  x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See definition of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
 
Large accelerated filer
 
¨
  
Accelerated filer
 
x
 
 
 
 
Non-accelerated filer
 
¨ (Do not check if smaller reporting company)
  
Smaller reporting company
 
x
 
 
 
 
Emerging growth company
 
¨
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨   No  x
State the aggregate market value of the voting and non voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity as of the last business day of the registrant’s most recently completed second fiscal quarter: March 31, 2018. $188,207,371
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the last practicable date.
Class
 
Outstanding at November 23, 2018
COMMON STOCK, $5 PAR VALUE
 
8,003,606 SHARES
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the RGC Resources, Inc. Proxy Statement for the 2019 Annual Meeting of Shareholders are incorporated by reference into Part III hereof.



TABLE OF CONTENTS
 
 
 
 
 
 
 
 
Page Number
 
 
 
 
 
 
 
 
 
 
 
 
 
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.
 
 
 
 
 
 
 
 




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

2


PART I
 
Item 1.
Business.

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

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

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

Diversified Energy Company currently has no active operations.

Services
Roanoke Gas maintains an integrated natural gas distribution system to deliver natural gas purchased from suppliers to residential, commercial and industrial users in its service territory. The schedule below is a summary of customers, delivered volumes (expressed in decatherms), revenues and margin as a percentage of the total for each category. For the purposes of this schedule, margin for the utility operations is defined as revenues less cost of gas. 
 
 
2018
 
 
Customers
 
Volume
 
Revenue
 
Margin
Residential
 
91.2
%
 
39
%
 
58
%
 
61
%
Commercial
 
8.7
%
 
32
%
 
33
%
 
25
%
Industrial
 
0.1
%
 
29
%
 
6
%
 
10
%
Other Utility
 
0.0
%
 
0
%
 
1
%
 
2
%
Other Non-Utility
 
0.0
%
 
0
%
 
2
%
 
2
%
Total Percent
 
100.0
%
 
100
%
 
100
%
 
100
%
Total Value
 
60,228

 
9,925,974

 
$
65,534,736

 
$
32,776,289

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

 
8,562,582

 
$
62,296,870

 
$
32,809,157


3


 
 
2016
 
 
Customers
 
Volume
 
Revenue
 
Margin
Residential
 
91.2
%
 
38
%
 
57
%
 
60
%
Commercial
 
8.7
%
 
31
%
 
33
%
 
25
%
Industrial
 
0.1
%
 
31
%
 
7
%
 
11
%
Other Utility
 
0.0
%
 
0
%
 
1
%
 
2
%
Other Non-Utility
 
0.0
%
 
0
%
 
2
%
 
2
%
Total Percent
 
100.0
%
 
100
%
 
100
%
 
100
%
Total Value
 
59,635

 
8,842,605

 
$
59,063,291

 
$
31,564,914


Roanoke Gas’ regulated natural gas distribution business accounted for approximately 98% of Resources total revenues for fiscal years ending September 30, 2018, 2017 and 2016. The tables above indicate that residential customers represent over 91% of the Company’s customer total; however, they represent less than 40% of the total gas volumes delivered and more than half of the Company’s consolidated revenues and margin. Industrial customers include primarily transportation customers that purchase their natural gas requirements directly from a supplier other than the Company and utilize Roanoke Gas’ natural gas distribution system for delivery to their operations. Most of the revenue billed for these customers relates only to transportation service, and not to the purchase of natural gas, causing total revenues generated by these deliveries to be approximately 6% of total revenues, even though they represent 29% of total natural gas deliveries for the year ended September 30, 2018 and approximately 10% to 11% of margin for each of the years presented.

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

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

Suppliers
Roanoke Gas relies on multiple interstate pipelines including those operated by Columbia Gas Transmission Corporation, LLC and Columbia Gulf Transmission Corporation, LLC (together “Columbia”), and East Tennessee Natural Gas, LLC (“East Tennessee”), Tennessee Gas Pipeline, Midwestern Gas Transmission Company and Saltville Gas Storage Company, LLC to transport natural gas from the production and storage fields to Roanoke Gas’ distribution system. Roanoke Gas is directly served by two pipelines, Columbia and East Tennessee. Columbia historically has delivered more than 60% of the Company’s gas supply, while East Tennessee delivers the balance of the Company’s requirements. The rates paid for natural gas transportation and storage services purchased from the interstate pipeline companies are established by tariffs approved by the Federal Energy Regulatory Commission ("FERC"). These tariffs contain flexible pricing provisions, which, in some instances, authorize these transporters to reduce rates and charges to meet price competition. The current pipeline contracts expire at various times from 2019 to 2027. The Company anticipates being able to renew these contracts or enter into other contracts to meet customers’ continued demand for natural gas.

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

The Company uses multi-year contracts to meet its natural gas supply needs. The Company currently contracts with Sequent Energy Management, L.P. to manage its pipeline transportation, storage rights, gas supply inventories and deliveries and serve as the primary supplier of natural gas for Roanoke Gas. Natural gas purchased under the asset

4


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

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

Competition
The Company’s natural gas utility operates in a regulated, monopolistic environment. Roanoke Gas currently holds the only franchises and/or certificates of public convenience and necessity ("CPCN") to distribute natural gas in its Virginia service areas. These franchises generally extend for multi-year periods and are renewable by the municipalities, including exclusive franchises in the cities of Roanoke and Salem and the Town of Vinton, Virginia. All three franchise agreements were recently renewed for a term of 20 years and will expire December 31, 2035. The Company has filed an application with the Virginia State Corporation Commission ("SCC") to obtain a CPCN for portions of Franklin County that are not currently certificated. A final decision is pending on this request. Roanoke Gas plans to tap into the Mountain Valley Pipeline and provide natural gas service to portions of Franklin County.

Management anticipates that the Company will be able to renew all of its franchises when they expire. There can be no assurance, however, that a given jurisdiction will not refuse to renew a franchise or will not, in connection with the renewal of a franchise, attempt to impose restrictions or conditions that could adversely affect the Company’s business operations or financial condition. CPCN, issued by the SCC, are generally of perpetual duration and subject to compliance with regulatory standards. If the SCC issues a CPCN for the currently uncertified sections of Franklin County, the CPCN would have a 5-year term if natural gas service was not extended into those areas.

Although Roanoke Gas has exclusive rights for the distribution of natural gas in its service area, the Company competes with suppliers of other forms of energy such as fuel oil, electricity, propane, coal and solar. Competition can be intense among the other energy sources with the primary driver being price in most instances. This is particularly true for those industrial applications that have the ability to switch to alternative fuels. The relationship between supply and demand has the greatest impact on the price of natural gas. Greater demand for natural gas for electric generation and other uses can provide upward pressure on the price of natural gas. Currently, a plentiful supply of natural gas, mostly due to improved drilling and extraction processes in shale formations, has served to maintain prices at lower levels. The Company continues to see a demand for its product. Construction activity for new business has improved over this past year and growth in residential service has remained steady over the last few years as the Company continues to grow its customer base through a combination of extending service by new construction and converting existing alternative energy source users to natural gas.

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

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

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

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

5


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

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

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

OPERATIONAL RISKS

Availability of sufficient and reliable pipeline capacity.

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

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

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

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


6


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

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

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

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

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

Geographic concentration of business activities.

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

Volatility in the price and availability of natural gas.

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

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

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

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

7


projects, inability to obtain adequate financing, competition for labor and materials, construction delays, cost overruns, and an inability to negotiate acceptable agreements relating to rights-of-way, construction or other material development components. As a result, the Company may not be able to adequately serve existing customers or expand its distribution system to support customer growth. This could include any potential customer growth or system reliability enhancement resulting from connection to the Mountain Valley Pipeline ("MVP"). Any of these factors could negatively impact earnings.

Competition from other energy providers.

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

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

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


REGULATORY RISKS

Increased compliance and pipeline safety requirements and fines.

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

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

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

Regulatory actions or failure to obtain timely rate relief.

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

8


reasonable rate of return on investment in natural gas distribution facilities, earnings could be negatively impacted. Issuance of debt and equity by our subsidiaries are also subject to SCC regulation and approval. Delays or lack of approvals could inhibit the ability to access capital markets and negatively impact liquidity or earnings.


FINANCIAL RISKS

Access to capital to maintain liquidity.

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

Investment in Mountain Valley Pipeline.

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

Although the LLC initially received the necessary federal and state permits to begin construction on the pipeline, progress on the MVP has been hindered by several legal and regulatory obstacles as both the U.S, Fourth Circuit Court of Appeals (“Fourth Circuit”) and FERC have issued stays or stop orders affecting portions or all of the project pending resolution of issues or concerns raised as the project has progressed. For example, in July 2018, the Fourth Circuit challenged the adequacy of alternative route evaluations for the permits issued by the US Forest Service and the Bureau of Land Management for the right-of-way granted for the 3.5 mile section of the 303 mile pipeline through the Jefferson National Forest. In August 2018, FERC issued a project wide stop work order related to the Fourth Circuit’s stay issued for the right-of-way in the National Forest. At the end of August, FERC issued a Modified Stop Work Order that allowed construction activities to restart in all locations except for the Jefferson National Forest and a section in West Virginia. The Fourth Circuit also lifted a stay order which had stopped construction through streams and wetland crossings in West Virginia thereby allowing construction to proceed in these areas. In October, the Fourth Circuit issued an order to vacate the stream and wetland crossing permit issued by the US. Army Corps of Engineers, which impacts approximately 160 miles of the project in West Virginia.

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

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

9



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

Insurance coverage may not be sufficient.

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

Post-retirement benefits and related funding of obligations.

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

Failure to comply with debt covenant requirements.

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

Item 1B.
Unresolved Staff Comments.

Not applicable.

Item 2.
Properties.

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

10


Roanoke Gas currently owns and operates eight metering stations through which it measures and regulates the gas being delivered by its suppliers. These stations are located at various points throughout the Company’s distribution system.
Roanoke Gas also owns a liquefied natural gas storage facility located in its service territory that has the capacity to store up to 200,000 DTH of natural gas.
The Company’s executive, accounting and business offices, along with its maintenance and service departments, are located on Kimball Avenue in Roanoke, Virginia.
Although the Company considers its present properties to be adequate, management continues to evaluate the adequacy of its current facilities as additional needs arise.
 
Item 3.
Legal Proceedings.

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

Not applicable.
 

11


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

Market Information
Resources' common stock is listed on the NASDAQ Global Market under the trading symbol RGCO. Payment of dividends is within the discretion of the Board of Directors and depends on, among other factors, earnings, capital requirements, and the operating and financial condition of the Company.
 
 
Range of Bid Prices
 
Cash Dividends
Year Ending September 30, 2018
 
High
 
Low
 
Declared
 First Quarter
 
$
31.57

 
$
25.01

 
$
0.1550

 Second Quarter
 
27.49

 
22.16

 
0.1550

 Third Quarter
 
29.46

 
23.61

 
0.1550

 Fourth Quarter
 
31.33

 
25.85

 
0.1550

 
 
 
 
 
 
 
Year Ending September 30, 2017
 
 
 
 
 
 
 First Quarter
 
$
20.04

 
$
15.81

 
$
0.1450

 Second Quarter
 
22.51

 
16.60

 
0.1450

 Third Quarter
 
31.99

 
21.00

 
0.1450

 Fourth Quarter
 
29.95

 
23.65

 
0.1450

As of November 24, 2018, there were 1,140 holders of record of the Company’s common stock. This number does not include all beneficial owners of common stock who hold their shares in “street name.”

Comparisons of Cumulative Total Shareholder Returns
The following performance graph compares the Company’s total shareholder return from September 30, 2013 through September 30, 2018 with the Dow Jones US Utility Index, a utility based index, and the Standard & Poor’s 500 Stock Index (S&P 500 Index), a broad market index.
The graph below reflects the value of a hypothetical investment of $100 made September 30, 2013 in the Company’s common stock and in each index as of September 30, 2018, assuming the reinvestment of all dividends. Historical stock price performance as reflected on the graph is not indicative of future price performance. The total value at the end of the five years was $245 for the Company’s common stock, $172 for the Dow Jones US Utilities Index and $192 for the S&P 500 Index.





12


chart-a996de24f3a15868bcaa09.jpg
A summary of the Company’s equity compensation plans follows as of September 30, 2018:
 
 
(a)
 
(b)
 
(c)
Plan category
 
Number of securities
to be issued upon
exercise of
outstanding options,
warrants and rights
 
Weighted-average
exercise price of
outstanding
options, warrants
and rights
 
Number of securities
remaining available
for future issuance
under equity
compensation plans
(excluding securities
reflected in column
(a))
Equity compensation plans approved by security holders
 
100,000

 
$14.34
 
555,568

Equity compensation plans not approved by security holders
 

 

 

Total
 
100,000

 
$14.34
 
555,568

 

13



Item 6.
Selected Financial Data.

 
 
Year Ending September 30,
 
 
2018
 
2017
 
2016
 
2015
 
2014
 
 
 
 
 
 
 
 
 
 
 
Operating Revenues
 
$
65,534,736

 
$
62,296,870

 
$
59,063,291

 
$
68,189,607

 
$
75,016,134

Operating Income
 
11,593,045

 
11,666,309

 
11,212,092

 
10,006,192

 
9,681,868

Net Income
 
7,297,205

 
6,232,865

 
5,806,866

 
5,094,415

 
4,708,440

Basic Earnings Per Share (1)
 
$
0.95

 
$
0.86

 
$
0.81

 
$
0.72

 
$
0.67

Cash Dividends Declared Per Share (1)
 
$
0.62

 
$
0.58

 
$
0.54

 
$
0.51

 
$
0.49

Book Value Per Share (1)
 
$
9.95

 
$
8.29

 
$
7.75

 
$
7.43

 
$
7.35

Average Shares Outstanding (1)
 
7,649,025

 
7,218,686

 
7,149,906

 
7,092,315

 
7,073,218

Total Assets
 
$
219,560,106

 
$
183,135,071

 
$
165,552,849

 
$
145,847,194

 
$
137,423,321

 
 
 
 
 
 
 
 
 
 
 
Long-Term Debt (Less Unamortized Debt Expense)
 
$
70,321,936

 
$
61,312,011

 
$
33,636,051

 
$
30,316,573

 
$
30,306,919

Stockholders' Equity
 
79,583,112

 
60,040,472

 
55,667,072

 
52,840,991

 
52,020,847

Shares Outstanding at Sept. 30(1)
 
7,994,615

 
7,240,846

 
7,182,434

 
7,112,247

 
7,080,567


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

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

Forward-Looking Statements

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

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

Overview

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

14


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

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

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

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

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

More than 98% of the Company’s revenues are derived from the sale and delivery of natural gas to Roanoke Gas customers. The SCC authorizes the rates and fees the Company charges its customers for these services. These rates are designed to provide the Company with the opportunity to recover its gas and non-gas expenses and to earn a reasonable rate of return for shareholders based on normal weather. Normal weather refers to the average number of heating degree days (an industry measure by which the average daily temperature falls below 65 degrees Fahrenheit) over the most recent 30-year period.

As the Company’s business is seasonal in nature, volatility in winter weather and the commodity price of natural gas, can impact the effectiveness of the Company’s rates in recovering its costs and providing a reasonable return for its shareholders. In order to mitigate the effect of weather variations, the Company has certain approved rate mechanisms in place that help provide stability in earnings, adjust for volatility in the price of natural gas and provide a return on qualified infrastructure investment. These mechanisms include a purchased gas adjustment factor ("PGA"), weather normalization adjustment factor ("WNA"), inventory carrying cost revenue ("ICC") and a Steps to Advance Virginia Energy ("SAVE") adjustment rider.

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

15


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

The WNA reduces the volatility in earnings due to the variability in temperatures during the heating season. The WNA is based on the most recent 30-year temperature average and provides the Company with a level of earnings protection when weather is warmer than normal and provides its customers with price protection when the weather is colder than normal. The WNA allows the Company to recover from its customers the lost margin (excluding gas costs) from the impact of weather that is warmer than normal and correspondingly requires the Company to refund the excess margin earned for weather that is colder than normal. The WNA year runs from April through March. Any billings or refunds related to the WNA are completed following the end of the WNA year. For the fiscal year ended September 30, 2018, the Company recorded approximately $45,000 in additional revenue from the WNA for weather that was less than 1% warmer than normal. For the fiscal years ended September 30, 2017 and 2016, the Company recorded $1,839,000 and $1,318,000 in additional revenue from the WNA for weather that was approximately 18% and 13% warmer than normal for the respective years. As normal weather is based on the most recent 30-year temperature average, the heating degree days used to determine normal will change annually as a new year is added to the 30-year period and the oldest year is removed. As a result of adding recent warmer than normal winters and dropping off colder than normal years from the beginning of the 30-year period, the number of heating degree days that defines normal has declined from 3,998 in fiscal 2013 to 3,944 in fiscal 2018. The Company's rates are designed on 4,000 heating degree days from its last non-gas rate filing; however, the WNA model is recovering on the current normal of 3,944 heating degree days, or about 1% less than for what the rates were designed to recover. The 30-year normal will be reset in base rates when the Company implements new non-gas rates associated with its recently filed rate application with the SCC.

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

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

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

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

16


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

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

Results of Operations

Fiscal Year 2018 Compared with Fiscal Year 2017

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

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

 
$
61,252,015

 
$
3,089,768

 
5
%
Other
1,192,953

 
1,044,855

 
148,098

 
14
%
Total Operating Revenues
$
65,534,736

 
$
62,296,870

 
$
3,237,866

 
5
%

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

 
5,840,883

 
1,262,942

 
22
%
 Transportation and Interruptible
2,822,149

 
2,721,699

 
100,450

 
4
%
 Total Delivered Volumes
9,925,974

 
8,562,582

 
1,363,392

 
16
%
Heating Degree Days (Unofficial)
3,954

 
3,250

 
704

 
22
%

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


17


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

 
$
61,252,015

 
$
3,089,768

 
5
%
Cost of gas
32,091,923

 
28,919,625

 
3,172,298

 
11
%
Gas Utility Margin
$
32,249,860

 
$
32,332,390

 
$
(82,530
)
 
%

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

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

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

 
$
12,412,753

 
$
64,002

SAVE Plan
4,468,556

 
3,813,043

 
655,513

Volumetric
15,889,359

 
13,573,704

 
2,315,655

WNA
44,569

 
1,839,454

 
(1,794,885
)
Carrying Cost
554,090

 
588,624

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

 
(1,320,167
)
Other
136,698

 
104,812

 
31,886

Total
$
32,249,860

 
$
32,332,390

 
$
(82,530
)

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

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


18


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

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

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

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

Net Income and Dividends - Net income for fiscal 2018 was $7,297,205 compared to $6,232,865 for fiscal 2017. Basic and diluted earnings per share were $0.95 in fiscal 2018 compared to $0.86 in fiscal 2017. Dividends declared per share of common stock were $0.62 in fiscal 2018 compared to $0.58 in fiscal 2017.
    
Fiscal Year 2017 Compared with Fiscal Year 2016

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

Operating Revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended September 30,
2017
 
2016
 
Increase
 
Percentage
Gas Utilities
$
61,252,015

 
$
58,079,990

 
$
3,172,025

 
5
%
Other
1,044,855

 
983,301

 
61,554

 
6
%
Total Operating Revenues
$
62,296,870

 
$
59,063,291

 
$
3,233,579

 
5
%

Delivered Volumes
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended September 30,
2017
 
2016
 
Decrease
 
Percentage
Regulated Natural Gas (DTH)
 
 
 
 
 
 
 
 Residential and Commercial
5,840,883

 
6,088,108

 
(247,225
)
 
(4
)%
 Transportation and Interruptible
2,721,699

 
2,754,497

 
(32,798
)
 
(1
)%
 Total Delivered Volumes
8,562,582

 
8,842,605

 
(280,023
)
 
(3
)%
Heating Degree Days (Unofficial)
3,250

 
3,484

 
(234
)
 
(7
)%

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

19


residential and commercial volumes. Industrial consumption was nearly unchanged. Residential and commercial deliveries tend to be more weather sensitive as reflected by a 4% decline in volumes on 7% fewer heating degree days. Transportation and interruptible volumes, which are primarily driven by production activities rather than weather, decreased by 1%. Other revenues experienced a 6% increase.

Gross Utility Margin
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended September 30,
2017
 
2016
 
Increase
 
Percentage
Utility revenues
$
61,252,015

 
$
58,079,990

 
$
3,172,025

 
5
%
Cost of gas
28,919,625

 
27,009,330

 
1,910,295

 
7
%
Total Gross Margin
$
32,332,390

 
$
31,070,660

 
$
1,261,730

 
4
%

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

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

 
Twelve Months Ended September 30,
 
 
 
2017
 
2016
 
Increase / (Decrease)
Customer Base Charge
$
12,412,753

 
$
12,364,811

 
$
47,942

SAVE Plan
3,813,043

 
2,538,055

 
1,274,988

Volumetric
13,573,704

 
14,099,214

 
(525,510
)
WNA
1,839,454

 
1,317,800

 
521,654

Carrying Cost
588,624

 
651,492

 
(62,868
)
Other
104,812

 
99,288

 
5,524

Total
$
32,332,390

 
$
31,070,660

 
$
1,261,730


Operations and Maintenance Expense - Operations and maintenance expenses, in total, were nearly unchanged reflecting a net increase of $1,955 for the year. Expense declines in certain areas were offset by higher expenses in other categories. The most significant offsets pertain to labor, contracted services, employee benefit costs, corporate insurance, capitalized overheads and bad debt expense. Total operation and maintenance labor declined by $158,000 primarily as a result of the outsourcing of the Company's customer service, billing and credit and collection functions. Management made a strategic decision to transfer these operations to a provider that has significant experience in serving utility clients. In July 2017, the Company transitioned to the service provider, resulting in a reduction of 18 employees. The personnel savings from this work force reduction was partially offset by the fees paid to the service provider. Employee benefit costs increased by $195,000 due to higher health insurance premiums and higher actuarial determined costs on the post-retirement medical plan. The Company realized a $251,000 reduction in corporate property and liability insurance premiums due to favorable insurance renewals. Capitalized overheads, which include general and administrative, payroll and engineering costs, decreased by $179,000 from fiscal 2016 primarily due to a reduction in the general and administrative overhead rate and less LNG overheads due to a 46% reduction in the amount of LNG produced. The reduction in the LNG production was timing related as the facility was at near full capacity at September 30, 2016, while the balance at September 30, 2017 was at 79% capacity. Legal and other professional expenses were also lower due to reduced activity in those areas.


20


General Taxes - General taxes increased $122,944, or 7%, primarily due to higher property taxes associated with increases in utility property.
 
Depreciation - Depreciation expense increased by $665,127, or 12%, corresponding to 10% increase in utility plant investment.

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

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

Interest Expense - Total interest expense increased by $280,933, or 17%, due to a 24% increase in the average total debt outstanding. The combination of Mountain Valley Pipeline investments and the level of capital expenditures during fiscal 2017 generated the higher debt balances. The average interest rate declined during the current year from 3.76% to 3.56%. The $7,000,000 unsecured note issued on November 1, 2016 had a variable rate that ranged from 1.43% to 2.14% during the year, which was lower than the average rate on the outstanding debt during fiscal 2016.

Income Taxes - Income tax expense increased by $139,206, or 4%, on higher pre-tax earnings. The effective tax rate was 37.9% for fiscal 2017 compared to 38.7% for fiscal 2016. The lower effective tax rate was attributable to the exercise of stock options during the year, which resulted in additional tax deductions above the amount recorded at grant date due to the significant appreciation in stock price over the grant price.

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

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

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

Cash Flow Summary
Year Ended September 30,
 
2018
 
2017
 
2,016
Net cash provided by operating activities
$
13,503,795

 
$
12,980,978

 
$
14,921,640

Net cash used in investing activities
(34,166,578
)
 
(23,492,555
)
 
(20,996,501
)
Net cash provided by financing activities
20,840,554

 
9,937,965

 
5,732,879

Increase (decrease) in cash and cash equivalents
$
177,771

 
$
(573,612
)
 
$
(341,982
)

Cash Flows Provided by Operating Activities:

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


21


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

 
Twelve Months Ended September 30,
 
 
Cash Flows From Operating Activities:
2018
 
2017
 
Increase (Decrease)
Net Income
$
7,297,205

 
$
6,232,865

 
$
1,064,340

Depreciation
7,090,169

 
6,378,368

 
711,801

Gas in storage
74,698

 
(265,109
)
 
339,807

Prepaid income taxes
959,142

 
(245,989
)
 
1,205,131

Change in over-collection of gas costs
(2,360,972
)
 
528,387

 
(2,889,359
)
Deferred taxes
755,994

 
3,325,379

 
(2,569,385
)
Accounts payable and accrued expenses
191,054

 
(989,683
)
 
1,180,737

Rate refund
1,320,167

 

 
1,320,167

Other
(1,823,662
)
 
(1,983,240
)
 
159,578

Net cash provided by operating activities
$
13,503,795

 
$
12,980,978

 
$
522,817


Cash Flows Used in Investing Activities:

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

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

22


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

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

Cash Flows Provided by (Used in) Financing Activities:

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

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

On March 26, 2018, Roanoke Gas entered into a new unsecured revolving line-of-credit note agreement. The new line-of-credit agreement is for a two-year term expiring March 31, 2020, replacing the two-year agreement that expired on March 31, 2019. The new agreement maintains the same variable interest rate based on 30-day LIBOR plus 100 basis points and availability fee of 15 basis points applied to the unused balance. The new agreement also maintains multi-tiered borrowing limits to accommodate seasonal borrowing demands and minimize borrowing costs. The total available borrowing limits during the term of the new agreement range from $2,000,000 to $25,000,000. As the agreement is for a two-year term, amounts drawn against the new agreement are generally considered to be non-current. The Company intends to request an extension of the agreement by one year prior to next March when the outstanding debt would become a current liability; however, there is no guarantee that the line-of-credit agreement will be extended or replaced on terms comparable to those currently in place.

On October 2, 2017, the Company issued two 10-year unsecured notes in the aggregate principal amount of $8,000,000 with a fixed interest rate of 3.58% per annum. Interest is paid semi-annually on these notes in April and October of each year until the notes mature. The proceeds from these notes were used to refinance a portion of the line-of-credit balance into longer-term financing.

Off-Balance Sheet Arrangements

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

Contractual Obligations and Commitments

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

23



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

 
$
17,743,200

 
$
7,000,000

 
$
38,500,000

 
$
63,243,200

Long-Term Debt - Line of Credit (2)

 
7,361,017

 

 

 
7,361,017

Total
$

 
$
25,104,217

 
$
7,000,000

 
$
38,500,000

 
$
70,604,217

 
 
 
 
 
 
 
 
 
 
(1) See Note 6 to the consolidated financial statements.
(2) See Notes 5 and 6 to the consolidated financial statements. New line-of-credit agreement executed for a 2-year term, expiring March 31, 2020. Amounts drawn against agreement are considered non-current as they are not subject to repayment within 12-months.

Unrecorded contractual obligations, not reflected in consolidated balance sheets in accordance with US GAAP:
Less than 1 year
 
1-3 Years
 
4-5 Years
 
After 5 Years
 
Total
Pipeline and Storage Capacity (3)
$
11,184,000

 
$
15,360,868

 
$
8,217,849

 
$
1,950,134

 
$
36,712,851

Gas Supply (4)

 

 

 

 

Interest on Line-of-Credit (5)
41,447

 
18,571

 

 

 
60,018

Interest on Notes Payable (6)
1,928,013

 
3,721,105

 
3,185,711

 
15,396,752

 
24,231,581

Pension Plan Funding (7)

 

 

 

 

Investment in MVP (8)
22,231,073

 
6,295,212

 

 

 
28,526,285

Franchise Agreements (9)
107,302

 
224,357

 
238,021

 
1,942,731

 
2,512,411

Other Obligations (10)
215,833

 
424,281

 
11,503

 
138,379

 
789,996

Total
$
35,707,668

 
$
26,044,394

 
$
11,653,084

 
$
19,427,996

 
$
92,833,142

 
 
 
 
 
 
 
 
 
 
(3) Recoverable through the PGA process.
(4) Volumetric obligation is for the purchase of contracted decatherms of natural gas at market prices in effect at the time of purchase. Unable to estimate related payment obligation until time of purchase. See Note 11 to the consolidated financial statements.
(5) Accrued interest on line-of-credit balance at September 30, 2018, including minimum facility fee on unused line-of-credit. See Note 5 to the consolidated financial statements.
(6) Calculated interest payments on 20-year $30.5 million Roanoke Gas Co. Prudential note payable due September 18, 2034, 5-year $7 million Roanoke Gas Co. BB&T note payable due November 01, 2021, 10-year $8 million Roanoke Gas Co. Prudential note payable due October 02, 2027, and on the September 30, 2018 balance on Midstream notes due December 29, 2020. See Note 6 to the consolidated financial statements.
(7) Estimated minimum funding requirement assuming application of credit balances in plan to offset funding. Minimum funding requirements beyond five years is not available. See Note 8 to the consolidated financial statements for the planned funding in fiscal 2019.
(8) Projected remaining funding of the Company's 1% interest in the LLC as entered into on October 1, 2015.
(9) Franchise tax obligations due Roanoke City, Salem City and Town of Vinton per 20-year term agreements. See Note 11 to the consolidated financial statements.
(10) Various lease, maintenance, equipment and service contracts.
              
Equity Investment in Mountain Valley Pipeline

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

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

24


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

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

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

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

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

Regulatory and Tax Reform

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

The Company continues to recover the costs of its infrastructure replacement program through its SAVE Plan. The original SAVE Plan was designed to facilitate the accelerated replacement of aging natural gas pipe by providing a mechanism for the Company to recover the related depreciation and expenses and return on rate base of the additional capital investment without the filing of a formal application for an increase in non-gas base rates. Since the implementation and approval of the original SAVE Plan in 2012, the Company has modified, amended and updated it each year to incorporate various qualifying projects. On September 28, 2018, the SCC issued their order approving the 2019 SAVE Plan and SAVE rider effective January 1, 2019 with a continued focus on the ongoing replacement of the pre-1973 plastic pipe. As all previous SAVE investment has been incorporated into the general rate application, the new SAVE Plan Rider will reflect only the recovery of qualifying SAVE Plan investments beginning in January 2019.

25


The 2019 SAVE Plan Rider is expected to provide approximately $362,000 in revenue. In addition, the SCC also approved the true-up factor for the 2017 SAVE Plan, which will refund approximately $163,000 in excess SAVE Plan revenues to customers.
 
As disclosed in Notes 3 and 7, the TCJA was signed into law on December 22, 2017 and provided sweeping changes to the federal income tax code. The most significant change included the reduction of the maximum corporate federal income tax rate from 35% to 21%. Another significant change included the elimination of bonus depreciation for utilities in exchange for retaining the full deductibility of utility related interest expense. There were several other changes to the tax code that will have lesser impact on the Company.

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

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

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

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

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

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

26


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

Critical Accounting Policies and Estimates

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

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

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

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

Revenue recognition - Regulated utility sales and transportation revenues are based upon rates approved by the SCC. The non-gas cost component of rates may not be changed without a formal rate application and corresponding authorization by the SCC in the form of a Commission order; however, the gas cost component of rates may be adjusted quarterly through the PGA mechanism. When the Company files a request for a non-gas rate increase, the SCC may allow the Company to place such rates into effect subject to refund pending a final order. Under these circumstances, the Company estimates the amount of increase it anticipates will be approved based on the best available information. The Company also bills customers through a SAVE Rider that provides a mechanism to recover on a prospective basis the costs associated with the Company’s expected investment related to the replacement of natural gas distribution pipe and other qualifying projects. As authorized by the SCC, the Company adjusts billed revenues monthly through the application of the WNA model. As the Company's non-gas rates are established based on the 30-year temperature average, monthly fluctuations in temperature from the 30-year average could result in the recognition of more or less revenue than for what the non-gas rates were designed. The WNA authorizes the Company to adjust monthly revenues for the effects of variation in weather from the 30-year average with a corresponding entry to a WNA receivable or WNA payable. At the end of each WNA year, the Company will refund excess revenue collected for weather that was colder than the 30-year average or bill the customer for revenue short-fall for weather that was warmer than normal. As required under the provisions of FASB ASC No. 980, Regulated Operations, the Company recognizes billed revenue related to the SAVE projects and from the WNA to the extent such revenues have been earned under the provisions approved by the SCC.

The Company bills its regulated natural gas customers on a monthly cycle. The billing cycle for most customers does not coincide with the accounting periods used for financial reporting. The Company accrues estimated revenue for natural gas delivered to customers but not yet billed during the accounting period based on weather during the period and current and historical data. The financial statements include unbilled revenue of $911,657 and $965,683 as of September 30, 2018 and 2017, respectively.

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

27


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

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

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

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

Over the last few years, management has focused on reducing risk in the Company's defined benefit plans with a greater emphasis on pension plan risk. In 2016, the Company offered a one-time, lump-sum payout of the pension benefit to vested employees who were not receiving payments under the plan. Approximately 63%, or 40 former employees, elected to receive their pension benefit in a lump sum, which resulted in a payout of $1,242,000 from plan assets while reducing plan liabilities by nearly $1,500,000 at the time and also reduced the number of participants on which the Pension Benefit Guaranty Corporation ("PBGC") premiums are determined. In 2017, the Company implemented its next de-risking strategy by implementing a "soft freeze" to the pension plan whereby new employees hired on or after January 1, 2017 would not be eligible to participate in the pension plan. Employees hired prior to that date continue to accrue benefits based on compensation and years of service. This soft freeze mirrored the strategy in 2000 when the Company implemented a similar freeze in its postretirement medical plan. These strategies have reduced liability growth by not allowing new participants into the plans and reducing the number of participants entitled to future benefits.

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

28


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

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

Funded status - September 30, 2018
Pension
 
Postretirement
 
Total
Benefit Obligation
$
28,850,299

 
$
16,207,322

 
$
45,057,621

Fair value of assets
28,184,697

 
12,924,957

 
41,109,654

Funded status
$
(665,602
)
 
$
(3,282,365
)
 
$
(3,947,967
)
Funded status - September 30, 2017
Pension
 
Postretirement
 
Total
Benefit Obligation
$
29,657,347

 
$
17,666,812

 
$
47,324,159

Fair value of assets
26,418,671

 
12,691,162

 
39,109,833

Funded status
$
(3,238,676
)
 
$
(4,975,650
)
 
$
(8,214,326
)

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

Management estimates that, under the current provisions regarding defined benefit pension plans, the Company will have no minimum funding requirements next year. However, management plans to continue its pension funding plan by contributing at least the minimum annual pension contribution requirement or its expense level for subsequent years. The Company currently expects to contribute approximately $800,000 to its pension plan and $300,000 to its postretirement plan in fiscal 2019 with a continuing goal to improve both plans' funded status. The Company will continue to evaluate its benefit plan funding levels in light of funding requirements and ongoing investment returns and make adjustments, as necessary, to avoid benefit restrictions and minimize PBGC premiums.

The following schedule reflects the sensitivity of pension costs to changes in certain actuarial assumptions, assuming that the other components of the calculation remain constant.
Actuarial Assumptions - Pension Plan
Change in Assumption
 
Increase in Pension Cost
 
Increase in Projected Benefit Obligation
Discount rate
-0.25
 %
 
$
112,000

 
$
1,125,000

Rate of return on plan assets
-0.25
 %
 
70,000

 
N/A

Rate of increase in compensation
0.25
 %
 
43,000

 
221,000


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

29


Actuarial Assumptions - Postretirement Plan
Change in Assumption
 
Increase in Postretirement Benefit Cost
 
Increase in Accumulated Postretirement Benefit Obligation
Discount rate
-0.25
 %
 
$
52,000

 
$
625,000

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

 
N/A

Medical claim cost increase
0.25
 %
 
95,000

 
607,000


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

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

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

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

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

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

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


30


Item 8.
Financial Statements and Supplementary Data.

31



RGC Resources, Inc.
and Subsidiaries

Consolidated Financial Statements
for the Years Ended September 30, 2018, 2017
and 2016, and Report of Independent
Registered Public Accounting Firm

32



RGC RESOURCES, INC. AND SUBSIDIARIES
TABLE OF CONTENTS
 


33



brownedwardsa05.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, 2018 and 2017, and the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows for each of the years in the three-year period ended September 30, 2018, and the related notes (collectively referred to as the financial statements). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of September 30, 2018 and 2017, and the results of its operations and its cash flows for each of the years in the three-year period ended September 30, 2018, in conformity with accounting principles generally accepted in the United States of America.

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

Basis for Opinion

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

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
 
brownedwardssignaturea05.jpg
              CERTIFIED PUBLIC ACCOUNTANTS

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

Blacksburg, Virginia
December 3, 2018

34


RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AS OF SEPTEMBER 30, 2018 AND 2017
 
 
 
2018
 
2017
ASSETS
 
 
 
CURRENT ASSETS:
 
 
 
Cash and cash equivalents
$
247,411

 
$
69,640

Accounts receivable, net
3,913,830

 
3,492,703

Materials and supplies
913,889

 
1,021,191

Gas in storage
7,627,196

 
7,701,894

Prepaid income taxes
837,683

 
1,796,825

Under-recovery of gas costs
922,898

 

Interest rate swap
100,723

 
26,777

Other
980,972

 
1,576,574

Total current assets
15,544,602

 
15,685,604

UTILITY PROPERTY:
 
 
 
In service
224,854,320

 
204,223,714

Accumulated depreciation and amortization
(63,099,306
)
 
(59,765,987
)
In service, net
161,755,014

 
144,457,727

Construction work in progress
4,208,614

 
3,470,244

Utility plant, net
165,963,628

 
147,927,971

OTHER ASSETS:
 
 
 
Regulatory assets
8,862,147

 
11,796,260

Investment in unconsolidated affiliate
28,507,146

 
7,445,106

Interest rate swap
209,840

 
90,066

Other
472,743

 
190,064

Total other assets
38,051,876

 
19,521,496

TOTAL ASSETS
$
219,560,106

 
$
183,135,071


(Continued)

35


RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AS OF SEPTEMBER 30, 2018 AND 2017
 
 
 
2018
 
2017
LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
CURRENT LIABILITIES:
 
 
 
Dividends payable
$
1,242,753

 
$
1,050,281

Accounts payable
5,211,032

 
5,122,899

Capital contributions payable
10,142,766

 
1,055,504

Customer credit balances
1,003,622

 
1,220,578

Customer deposits
1,421,043

 
1,471,960

Accrued expenses
3,750,466

 
3,006,936

Over-recovery of gas costs

 
1,438,074

Rate refund
1,320,167

 

Total current liabilities
24,091,849

 
14,366,232

LONG-TERM DEBT:
 
 
 
Notes payable
63,243,200

 
43,812,200

Line-of-credit
7,361,017

 
17,791,760

       Less unamortized debt issuance costs
(282,281
)
 
(291,949
)
       Long-term debt net of unamortized debt issuance costs
70,321,936

 
61,312,011

DEFERRED CREDITS AND OTHER LIABILITIES:
 
 
 
Asset retirement obligations
6,417,948

 
6,069,993

Regulatory cost of retirement obligations
11,163,981

 
10,055,189

Benefit plan liabilities
3,947,967

 
8,214,326

Deferred income taxes
12,585,577

 
23,076,848

Regulatory liability - deferred income taxes
11,447,736

 

Total deferred credits and other liabilities
45,563,209

 
47,416,356

COMMITMENTS AND CONTINGENCIES (Note 11)

 

CAPITALIZATION:
 
 
 
Stockholders’ Equity:
 
 
 
Common Stock, $5 par value; authorized 10,000,000 shares; issued and outstanding 7,994,615 and 7,240,846 shares in 2018 and 2017, respectively
39,973,075

 
36,204,230

Preferred stock, no par; authorized 5,000,000 shares; no shares issued and outstanding in 2018 and 2017

 

Capital in excess of par value
13,043,656

 
292,485

Retained earnings
27,438,049

 
24,746,021

Accumulated other comprehensive loss
(871,668
)
 
(1,202,264
)
Total stockholders’ equity
79,583,112

 
60,040,472

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
$
219,560,106

 
$
183,135,071

(Concluded)
See notes to consolidated financial statements.

36



RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
YEARS ENDED SEPTEMBER 30, 2018, 2017 AND 2016
 
 
 
2018
 
2017
 
2016
OPERATING REVENUES:
 
 
 
 
 
Gas utilities
$
64,341,783

 
$
61,252,015

 
$
58,079,990

Other
1,192,953

 
1,044,855

 
983,301

Total operating revenues
65,534,736

 
62,296,870

 
59,063,291

OPERATING EXPENSES:
 
 
 
 
 
Cost of gas - utility
32,091,923

 
28,919,625

 
27,009,330

Cost of sales - non utility
666,524

 
568,088

 
489,047

Operations and maintenance
12,348,890

 
13,100,041

 
13,098,086

General taxes
1,878,010

 
1,786,070

 
1,663,126

Depreciation and amortization
6,956,344

 
6,256,737

 
5,591,610

Total operating expenses
53,941,691

 
50,630,561

 
47,851,199

OPERATING INCOME
11,593,045

 
11,666,309

 
11,212,092

Equity in earnings of unconsolidated affiliate
938,531

 
421,646

 
152,864

Other (income) expense, net
(122,330
)
 
132,446

 
255,585

Interest expense
2,461,565

 
1,917,254

 
1,636,321

INCOME BEFORE INCOME TAXES
10,192,341

 
10,038,255

 
9,473,050

INCOME TAX EXPENSE
2,895,136

 
3,805,390

 
3,666,184

NET INCOME
$
7,297,205

 
$
6,232,865

 
$
5,806,866

EARNINGS PER COMMON SHARE:
 
 
 
 
 
Basic
$
0.95

 
$
0.86

 
$
0.81

Diluted
$
0.95

 
$
0.86

 
$
0.81

WEIGHTED AVERAGE SHARES OUTSTANDING:
 
 
 
 
 
Basic
7,649,025

 
7,218,686

 
7,149,906

Diluted
7,695,712

 
7,256,046

 
7,159,763

See notes to consolidated financial statements.

37



RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
YEARS ENDED SEPTEMBER 30, 2018, 2017 AND 2016
 
 
 
2018
 
2017
 
2016
NET INCOME
$
7,297,205

 
$
6,232,865

 
$
5,806,866

Other comprehensive income, net of tax:
 
 
 
 
 
Interest rate swaps
137,850

 
72,489

 

Defined benefit plans
406,798

 
1,222,478

 
(210,686
)
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
544,648

 
1,294,967

 
(210,686
)
COMPREHENSIVE INCOME
$
7,841,853

 
$
7,527,832

 
$
5,596,180

See notes to consolidated financial statements.

38



RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
YEARS ENDED SEPTEMBER 30, 2018, 2017 AND 2016
 
 
 
Common
Stock
 
Capital in
Excess of
Par Value
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Total
Stockholders’
Equity
Balance - September 30, 2015
$
23,707,490

 
$
8,647,669

 
$
22,772,377

 
$
(2,286,545
)
 
$
52,840,991

Net income

 

 
5,806,866

 

 
5,806,866

Other comprehensive loss

 

 

 
(210,686
)
 
(210,686
)
Exercise of stock options (3,300 shares)
11,000

 
30,762

 

 

 
41,762

Stock option grants

 
64,640

 

 

 
64,640

Cash dividends declared ($0.54 per share)

 

 
(3,865,933
)
 

 
(3,865,933
)
Issuance of common stock (66,887 shares)
222,955

 
766,477

 

 

 
989,432

Balance - September 30, 2016
$
23,941,445

 
$
9,509,548

 
$
24,713,310

 
$
(2,497,231
)
 
$
55,667,072

Net income

 

 
6,232,865

 

 
6,232,865

Other comprehensive income

 

 

 
1,294,967

 
1,294,967

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

 
91,991

 

 

 
142,241

Stock option grants

 
73,780

 

 

 
73,780

Cash dividends declared ($0.58 per share)

 

 
(4,195,910
)
 

 
(4,195,910
)
Stock split
12,029,790

 
(10,025,546
)
 
(2,004,244
)
 

 

Issuance costs

 
(96,508
)
 

 

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

 
739,220

 

 

 
921,965

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

 
$
292,485

 
$
24,746,021

 
$
(1,202,264
)
 
$
60,040,472

Net income

 

 
7,297,205

 

 
7,297,205

Other comprehensive income

 

 

 
544,648

 
544,648

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

 
12,070

 

 

 
19,945

Cash dividends declared ($0.62 per share)

 

 
(4,839,514
)
 

 
(4,839,514
)
Issuance costs

 
(990,459
)
 

 

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

 
13,729,560

 

 

 
17,490,530

Reclassification adjustment for effect of change in tax law

 

 
234,337

 
(214,052
)
 
20,285

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

 
$
13,043,656

 
$
27,438,049

 
$
(871,668
)
 
$
79,583,112

See notes to consolidated financial statements.


39



RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED SEPTEMBER 30, 2018, 2017 AND 2016

 
 
2018
 
2017
 
2016
CASH FLOWS FROM OPERATING ACTIVITIES:
 
 
 
 
 
Net income
$
7,297,205

 
$
6,232,865

 
$
5,806,866

Adjustments to reconcile net income to net cash provided by operations:
 
 
 
 
 
Depreciation and amortization
7,090,169

 
6,378,368

 
5,709,525