2018 Annual Report
PRESIDENT’S LETTER
To Our Shareholders:
I am delighted to report that 2018 was an exceptional year for RGC Resources. Net income improved 17% from
2017 to $7.3 million, our fourth consecutive year of record earnings.
In March, Resources successfully raised
$15.1 million through its first public offering in over 20 years. In June, Resources was included in the Russell 2000
index for the second consecutive year. Our Board of Directors approved a 6.5% annualized dividend increase to
$0.66 per share, effective with the February 1, 2019 quarterly dividend payment. The February dividend will
reflect 75 years of continuous quarterly dividend payments and 15 years of consecutive annual dividend increases.
Roanoke Gas continues to experience consistent customer growth.
The number of residential and small
commercial customers increased approximately 1%. Commercial customer volumes increased 20%, industrial
customer volumes increased 4% and our top 10 customer usage increased 7% over 2017.
Looking forward, we
expect the trend of increasing commercial and industrial gas usage to continue as several new manufacturers
come on‐line, and the Virginia Tech Carilion Strategic Partnership expands its research institute and medical
school.
Construction on the Mountain Valley Pipeline (MVP) started in January 2018. Since then, MVP has encountered
legal challenges to various federal and state permits as well as anti‐pipeline protests. Both have led to periods of
work stoppages and schedule changes. Combined with unusually high rainfall, the projected in‐service date has
been moved to the end of calendar 2019. Roanoke Gas will have two interconnects with the MVP. The first
interconnect, located near the southern end of our system, will provide additional supply to address the growing
demand for natural gas in the Roanoke Valley. The second interconnect will be located in the new Summit View
business park in Franklin County, Virginia. This interconnect will provide Roanoke Gas the opportunity to build a
distribution system in Franklin County, which currently does not have access to natural gas, and extend gas service
to new industrial, commercial and residential customers.
The strategic investment in MVP continues to
complement our core business and enhance shareholder value.
In April 2018, MVP announced the MVP Southgate project, a proposed interstate natural gas pipeline anchored by
a firm capacity commitment from PSNC Energy. MVP Southgate will provide a much needed additional natural gas
supply source to southern Virginia and central North Carolina. RGC Midstream will have a small investment in this
project. MVP Southgate is scheduled to be completed and in‐service at the end of 2020.
In 2018, we invested a record $23.3 million in Roanoke Gas, focusing on the modernization of our distribution
system, new customer additions and system reinforcement projects that improved system safety and reliability.
This past year we replaced approximately 8.3 miles of first generation plastic mains and 496 services. Looking into
2019, in addition to the aforementioned MVP interconnects, we will continue our first generation plastic renewals
and undertake several large steel main reinforcement projects.
In closing, we are pleased to provide you with our 2018 annual report reflecting our long‐term commitment of
delivering shareholder value and providing safe and reliable natural gas service. On behalf of our Board of
Directors and dedicated employees, I thank you for your continued interest in our Company and for your ongoing
decision to invest in RGC Resources.
John S. D’Orazio
CEO & President
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
(State or other jurisdiction of
incorporation or organization)
519 Kimball Avenue, N.E., Roanoke, VA
(Address of principal executive offices)
54-1909697
(I.R.S. Employer
Identification No.)
24016
(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
Common Stock, $5 Par Value
Name of Each Exchange on
Which Registered
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
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
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
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
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.
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
Non-accelerated filer
(Do not check if smaller reporting company)
Smaller reporting company
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
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
COMMON STOCK, $5 PAR VALUE
Outstanding at November 23, 2018
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
Cautionary Note Regarding Forward Looking Statements
PART I
PART II
Item 1.
Business
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2.
Properties
Item 3.
Legal Proceedings
Item 4. Mine Safety Disclosures
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and
Issuer Purchases of Equity Securities
Item 6.
Selected Financial Data
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8.
Financial Statements and Supplementary Data
Item 9.
Changes in and Disagreements with Accountants on Accounting and
Financial Disclosures
Item 9A. Controls and Procedures
Item 9B. Other Information
Item 10. Directors, Executive Officers and Corporate Governance
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters
Item 13. Certain Relationships and Related Transactions, and Director
Independence
Item 14. Principal Accounting Fees and Services
Item 15. Exhibits and Financial Statement Schedules
Item 16. Form 10-K Summary
Signatures
PART III
PART IV
Page Number
2
3
6
10
10
11
11
12
14
14
30
31
68
68
70
71
71
71
71
71
72
72
73
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
Item 1.
Business.
General and Historical Development
PART I
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.
Residential
Commercial
Industrial
Other Utility
Other Non-Utility
Total Percent
Total Value
Residential
Commercial
Industrial
Other Utility
Other Non-Utility
Total Percent
Total Value
Customers
Volume
Revenue
Margin
2018
91.2%
8.7%
0.1%
0.0%
0.0%
100.0%
60,228
39%
32%
29%
0%
0%
100%
58%
33%
6%
1%
2%
100%
61%
25%
10%
2%
2%
100%
9,925,974
$
65,534,736
$
32,776,289
Customers
Volume
Revenue
Margin
2017
91.2%
8.7%
0.1%
0.0%
0.0%
100.0%
59,847
37%
31%
32%
0%
0%
100%
57%
33%
7%
1%
2%
100%
61%
25%
10%
2%
2%
100%
8,562,582
$
62,296,870
$
32,809,157
3
Residential
Commercial
Industrial
Other Utility
Other Non-Utility
Total Percent
Total Value
Customers
Volume
Revenue
Margin
2016
91.2%
8.7%
0.1%
0.0%
0.0%
100.0%
59,635
38%
31%
31%
0%
0%
100%
57%
33%
7%
1%
2%
100%
60%
25%
11%
2%
2%
100%
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
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities.
PART II
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.
Year Ending September 30, 2018
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
Year Ending September 30, 2017
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
$
$
Range of Bid Prices
Cash Dividends
High
Low
Declared
$
$
31.57
27.49
29.46
31.33
20.04
22.51
31.99
29.95
$
$
25.01
22.16
23.61
25.85
15.81
16.60
21.00
23.65
0.1550
0.1550
0.1550
0.1550
0.1450
0.1450
0.1450
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
A summary of the Company’s equity compensation plans follows as of September 30, 2018:
Plan category
Equity compensation plans approved by security holders
Equity compensation plans not approved by security holders
Total
(a)
(b)
(c)
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))
100,000
—
100,000
$14.34
—
$14.34
555,568
—
555,568
13
Item 6.
Selected Financial Data.
Year Ending September 30,
2018
2017
2016
2015
2014
Operating Revenues
Operating Income
Net Income
Basic Earnings Per Share (1)
Cash Dividends Declared Per Share (1)
Book Value Per Share (1)
Average Shares Outstanding (1)
Total Assets
$ 65,534,736
$ 62,296,870
$ 59,063,291
$ 68,189,607
$ 75,016,134
11,593,045
7,297,205
11,666,309
6,232,865
11,212,092
5,806,866
10,006,192
5,094,415
9,681,868
4,708,440
$
$
$
0.95
0.62
9.95
$
$
$
0.86
0.58
8.29
$
$
$
0.81
0.54
7.75
$
$
$
0.72
0.51
7.43
$
$
$
0.67
0.49
7.35
7,649,025
$219,560,106
7,218,686
$183,135,071
7,149,906
$165,552,849
7,092,315
$145,847,194
7,073,218
$137,423,321
Long-Term Debt (Less Unamortized
Debt Expense)
Stockholders' Equity
Shares Outstanding at Sept. 30(1)
$ 70,321,936
$ 61,312,011
$ 33,636,051
$ 30,316,573
$ 30,306,919
79,583,112
60,040,472
55,667,072
52,840,991
52,020,847
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,
Gas Utilities
Other
Total Operating Revenues
Delivered Volumes
Year Ended September 30,
Regulated Natural Gas (DTH)
Residential and Commercial
Transportation and Interruptible
Total Delivered Volumes
Heating Degree Days
(Unofficial)
2018
2017
Increase
Percentage
$
$
64,341,783
1,192,953
65,534,736
$
$
61,252,015
1,044,855
62,296,870
$
$
3,089,768
148,098
3,237,866
2018
2017
Increase
Percentage
7,103,825
2,822,149
9,925,974
5,840,883
2,721,699
8,562,582
1,262,942
100,450
1,363,392
3,954
3,250
704
5%
14%
5%
22%
4%
16%
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
Cost of gas
Gas Utility Margin
$
$
64,341,783
32,091,923
32,249,860
$
$
61,252,015
28,919,625
32,332,390
$
$
3,089,768
3,172,298
(82,530)
5%
11%
—%
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:
Customer Base Charge
SAVE Plan
Volumetric
WNA
Carrying Cost
Rate Refund
Other
Total
Twelve Months Ended September 30,
2018
2017
$
12,476,755
$
12,412,753
$
4,468,556
15,889,359
44,569
554,090
(1,320,167)
136,698
3,813,043
13,573,704
1,839,454
588,624
—
104,812
$
32,249,860
$
32,332,390
$
Increase /
(Decrease)
64,002
655,513
2,315,655
(1,794,885)
(34,534)
(1,320,167)
31,886
(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
Other
Total Operating Revenues
$
$
61,252,015
1,044,855
62,296,870
$
$
58,079,990
983,301
59,063,291
$
$
3,172,025
61,554
3,233,579
5%
6%
5%
Delivered Volumes
Year Ended September 30,
Regulated Natural Gas (DTH)
Residential and Commercial
Transportation and Interruptible
Total Delivered Volumes
Heating Degree Days
(Unofficial)
2017
2016
Decrease
Percentage
5,840,883
2,721,699
8,562,582
6,088,108
2,754,497
8,842,605
(247,225)
(32,798)
(280,023)
3,250
3,484
(234)
(4)%
(1)%
(3)%
(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
Cost of gas
Total Gross Margin
$
$
61,252,015
28,919,625
32,332,390
$
$
58,079,990
27,009,330
31,070,660
$
$
3,172,025
1,910,295
1,261,730
5%
7%
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:
Customer Base Charge
$
12,412,753
$
12,364,811
$
47,942
Twelve Months Ended September 30,
2017
2016
Increase /
(Decrease)
SAVE Plan
Volumetric
WNA
Carrying Cost
Other
Total
3,813,043
13,573,704
1,839,454
588,624
104,812
2,538,055
14,099,214
1,317,800
651,492
99,288
1,274,988
(525,510)
521,654
(62,868)
5,524
$
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,
Net cash provided by operating activities
Net cash used in investing activities
Net cash provided by financing activities
Increase (decrease) in cash and cash equivalents
Cash Flows Provided by Operating Activities:
2018
2017
2,016
$
$
$
13,503,795
(34,166,578)
20,840,554
177,771
$
$
12,980,978
(23,492,555)
9,937,965
(573,612) $
14,921,640
(20,996,501)
5,732,879
(341,982)
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.
Cash Flows From Operating Activities:
2018
2017
Increase (Decrease)
Twelve Months Ended September 30,
$
7,297,205
$
6,232,865
$
1,064,340
Net Income
Depreciation
Gas in storage
Prepaid income taxes
Change in over-collection of gas costs
Deferred taxes
Accounts payable and accrued expenses
Rate refund
Other
Net cash provided by operating activities
$
Cash Flows Used in Investing Activities:
7,090,169
74,698
959,142
(2,360,972)
755,994
191,054
1,320,167
(1,823,662)
13,503,795
$
6,378,368
(265,109)
(245,989)
528,387
3,325,379
(989,683)
—
(1,983,240)
12,980,978
$
711,801
339,807
1,205,131
(2,889,359)
(2,569,385)
1,180,737
1,320,167
159,578
522,817
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:
Long-Term Debt - Notes Payable (1)
Long-Term Debt - Line of Credit (2)
Total
Less than 1
year
1-3
Years
4-5
Years
After
5 Years
Total
$
$
— $ 17,743,200
$ 7,000,000
$ 38,500,000
$ 63,243,200
—
7,361,017
—
—
7,361,017
— $ 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)
Gas Supply (4)
Interest on Line-of-Credit (5)
Interest on Notes Payable (6)
Pension Plan Funding (7)
Investment in MVP (8)
Franchise Agreements (9)
Other Obligations (10)
$ 11,184,000
—
41,447
1,928,013
—
22,231,073
107,302
215,833
$ 15,360,868
—
18,571
3,721,105
—
6,295,212
224,357
424,281
$ 8,217,849
—
—
3,185,711
—
—
238,021
11,503
$ 1,950,134
—
—
15,396,752
—
—
1,942,731
138,379
$ 36,712,851
—
60,018
24,231,581
—
28,526,285
2,512,411
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
Benefit Obligation
Fair value of assets
Funded status
Funded status - September 30, 2017
Benefit Obligation
Fair value of assets
Funded status
Pension
Postretirement
Total
28,850,299
$
16,207,322
$
45,057,621
28,184,697
(665,602) $
12,924,957
(3,282,365) $
41,109,654
(3,947,967)
Pension
Postretirement
Total
29,657,347
$
17,666,812
$
47,324,159
26,418,671
(3,238,676) $
12,691,162
(4,975,650) $
39,109,833
(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
Discount rate
Rate of return on plan assets
Rate of increase in compensation
Change in
Assumption
Increase in Pension
Cost
Increase in
Projected Benefit
Obligation
-0.25% $
-0.25%
0.25%
112,000
$
1,125,000
70,000
43,000
N/A
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
Discount rate
Rate of return on plan assets
Medical claim cost increase
Change in
Assumption
-0.25% $
-0.25%
0.25%
Increase in
Postretirement
Benefit Cost
Increase in
Accumulated
Postretirement
Benefit Obligation
52,000
$
625,000
32,000
95,000
N/A
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
Report of Independent Registered Public Accounting Firm
Consolidated Financial Statements for the Years Ended September 30, 2018, 2017 and 2016:
Consolidated Balance Sheets
Consolidated Statements of Income
Consolidated Statements of Comprehensive Income
Consolidated Statements of Stockholders’ Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
Page
34
35
37
38
39
40
41
33
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.
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
ASSETS
CURRENT ASSETS:
Cash and cash equivalents
Accounts receivable, net
Materials and supplies
Gas in storage
Prepaid income taxes
Under-recovery of gas costs
Interest rate swap
Other
Total current assets
UTILITY PROPERTY:
In service
Accumulated depreciation and amortization
In service, net
Construction work in progress
Utility plant, net
OTHER ASSETS:
Regulatory assets
Investment in unconsolidated affiliate
Interest rate swap
Other
Total other assets
TOTAL ASSETS
2018
2017
$
247,411
$
3,913,830
913,889
7,627,196
837,683
922,898
100,723
980,972
15,544,602
224,854,320
(63,099,306)
161,755,014
4,208,614
165,963,628
8,862,147
28,507,146
209,840
472,743
69,640
3,492,703
1,021,191
7,701,894
1,796,825
—
26,777
1,576,574
15,685,604
204,223,714
(59,765,987)
144,457,727
3,470,244
147,927,971
11,796,260
7,445,106
90,066
190,064
38,051,876
19,521,496
$
219,560,106
$
183,135,071
(Continued)
35
RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AS OF SEPTEMBER 30, 2018 AND 2017
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Dividends payable
Accounts payable
Capital contributions payable
Customer credit balances
Customer deposits
Accrued expenses
Over-recovery of gas costs
Rate refund
Total current liabilities
LONG-TERM DEBT:
Notes payable
Line-of-credit
Less unamortized debt issuance costs
Long-term debt net of unamortized debt issuance costs
DEFERRED CREDITS AND OTHER LIABILITIES:
Asset retirement obligations
Regulatory cost of retirement obligations
Benefit plan liabilities
Deferred income taxes
Regulatory liability - deferred income taxes
Total deferred credits and other liabilities
COMMITMENTS AND CONTINGENCIES (Note 11)
CAPITALIZATION:
Stockholders’ Equity:
2018
2017
$
1,242,753
$
5,211,032
10,142,766
1,003,622
1,421,043
3,750,466
—
1,320,167
24,091,849
63,243,200
7,361,017
(282,281)
70,321,936
6,417,948
11,163,981
3,947,967
12,585,577
11,447,736
45,563,209
1,050,281
5,122,899
1,055,504
1,220,578
1,471,960
3,006,936
1,438,074
—
14,366,232
43,812,200
17,791,760
(291,949)
61,312,011
6,069,993
10,055,189
8,214,326
23,076,848
—
47,416,356
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
Preferred stock, no par; authorized 5,000,000 shares; no shares issued and
outstanding in 2018 and 2017
Capital in excess of par value
Retained earnings
Accumulated other comprehensive loss
Total stockholders’ equity
39,973,075
36,204,230
—
13,043,656
27,438,049
(871,668)
79,583,112
—
292,485
24,746,021
(1,202,264)
60,040,472
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
$
219,560,106
$
183,135,071
See notes to consolidated financial statements.
(Concluded)
36
RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
YEARS ENDED SEPTEMBER 30, 2018, 2017 AND 2016
OPERATING REVENUES:
Gas utilities
Other
Total operating revenues
OPERATING EXPENSES:
Cost of gas - utility
Cost of sales - non utility
Operations and maintenance
General taxes
Depreciation and amortization
Total operating expenses
OPERATING INCOME
Equity in earnings of unconsolidated affiliate
Other (income) expense, net
Interest expense
INCOME BEFORE INCOME TAXES
INCOME TAX EXPENSE
NET INCOME
EARNINGS PER COMMON SHARE:
Basic
Diluted
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic
Diluted
2018
2017
2016
$
64,341,783
$
61,252,015
$
58,079,990
1,192,953
65,534,736
1,044,855
62,296,870
983,301
59,063,291
32,091,923
28,919,625
666,524
12,348,890
1,878,010
6,956,344
53,941,691
11,593,045
938,531
(122,330)
2,461,565
10,192,341
2,895,136
7,297,205
0.95
0.95
$
$
$
568,088
13,100,041
1,786,070
6,256,737
50,630,561
11,666,309
421,646
132,446
1,917,254
10,038,255
3,805,390
6,232,865
0.86
0.86
$
$
$
27,009,330
489,047
13,098,086
1,663,126
5,591,610
47,851,199
11,212,092
152,864
255,585
1,636,321
9,473,050
3,666,184
5,806,866
0.81
0.81
7,649,025
7,695,712
7,218,686
7,256,046
7,149,906
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
NET INCOME
Other comprehensive income, net of tax:
Interest rate swaps
Defined benefit plans
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
2018
2017
2016
$
7,297,205
$
6,232,865
$
5,806,866
137,850
406,798
544,648
72,489
1,222,478
1,294,967
—
(210,686)
(210,686)
5,596,180
COMPREHENSIVE INCOME
$
7,841,853
$
7,527,832
$
See notes to consolidated financial statements.
38
RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
YEARS ENDED SEPTEMBER 30, 2018, 2017 AND 2016
Common
Stock
Capital in
Excess of
Par Value
Retained
Earnings
Balance - September 30, 2015
$ 23,707,490
$
8,647,669
$ 22,772,377
Net income
Other comprehensive loss
Exercise of stock options (3,300 shares)
Stock option grants
Cash dividends declared ($0.54 per share)
—
—
11,000
—
—
—
—
30,762
64,640
—
Issuance of common stock (66,887 shares)
222,955
766,477
5,806,866
—
—
—
(3,865,933)
—
Balance - September 30, 2016
Net income
$ 23,941,445
—
$
9,509,548
—
$ 24,713,310
6,232,865
Total
Stockholders’
Equity
Accumulated
Other
Comprehensive
Income (Loss)
$ (2,286,545) $ 52,840,991
5,806,866
(210,686)
41,762
—
(210,686)
—
—
—
64,640
(3,865,933)
989,432
$ (2,497,231) $ 55,667,072
6,232,865
—
—
—
—
1,294,967
—
1,294,967
142,241
—
(4,195,910)
(2,004,244)
—
—
7,297,205
—
—
—
73,780
(4,195,910)
—
(96,508)
921,965
$ (1,202,264) $ 60,040,472
7,297,205
—
—
—
—
544,648
544,648
—
—
—
—
19,945
(4,839,514)
(990,459)
17,490,530
(214,052)
20,285
(871,668) $ 79,583,112
Other comprehensive income
Exercise of stock options (11,225 shares)
Stock option grants
Cash dividends declared ($0.58 per share)
Stock split
Issuance costs
Issuance of common stock (47,187 shares)
—
50,250
—
—
12,029,790
—
182,745
—
91,991
73,780
—
(10,025,546)
(96,508)
739,220
Balance - September 30, 2017
$ 36,204,230
$
292,485
$ 24,746,021
Net income
Other comprehensive income
Exercise of stock options (1,575 shares)
Cash dividends declared ($0.62 per share)
Issuance costs
Issuance of common stock (752,194
shares)
Reclassification adjustment for effect of
change in tax law
—
—
7,875
—
—
—
—
12,070
—
(990,459)
—
(4,839,514)
—
3,760,970
13,729,560
—
—
—
234,337
Balance - September 30, 2018
$ 39,973,075
$ 13,043,656
$ 27,438,049
$
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
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income
Adjustments to reconcile net income to net cash provided by operations:
Depreciation and amortization
Cost of retirement of utility plant, net
Stock option grants
Equity in earnings of unconsolidated affiliate
Deferred income taxes
Other noncash items, net
Changes in assets and liabilities which provided (used) cash:
Accounts receivable and customer deposits, net
Inventories and gas in storage
Over/under recovery of gas costs
Other assets
Accounts payable, customer credit balances and accrued expenses, net
Rate refund
Total adjustments
Net cash provided by operating activities
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for utility property
Investment in unconsolidated affiliate
Proceeds from disposal of utility property
Net cash used in investing activities
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under line-of-credit
Repayments under line-of-credit
Proceeds from issuance of unsecured notes
Debt issuance expenses
Proceeds from issuance of stock
Cash dividends paid
Net cash provided by financing activities
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
CASH AND CASH EQUIVALENTS AT END OF YEAR
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid (refunded) during the year for:
Interest
Income taxes
2018
2017
2016
$ 7,297,205
$ 6,232,865
$ 5,806,866
7,090,169
(288,222)
—
(938,531)
755,994
163,482
(476,161)
182,000
(2,360,972)
784,566
(25,902)
1,320,167
6,206,590
13,503,795
6,378,368
(354,744)
73,780
(421,646)
3,325,379
203,743
(191,386)
(462,161)
528,387
(956,894)
(1,374,713)
—
6,748,113
12,980,978
5,709,525
(449,201)
64,640
(152,864)
4,466,954
197,298
(258,960)
867,682
(991,739)
(398,864)
60,303
—
9,114,774
14,921,640
(23,290,994)
(11,036,247)
160,663
(34,166,578)
(20,750,181)
(2,759,346)
16,972
(23,492,555)
(17,945,719)
(3,055,746)
4,964
(20,996,501)
29,814,468
(40,245,210)
19,431,000
(32,678)
16,520,016
(4,647,042)
20,840,554
177,771
69,640
247,411
$
42,569,303
(39,334,328)
9,916,000
(64,835)
967,698
(4,115,873)
9,937,965
(573,612)
643,252
69,640
$
38,310,326
(33,094,539)
3,396,200
(101,619)
1,031,194
(3,808,683)
5,732,879
(341,982)
985,234
643,252
$
$ 2,137,782
1,180,000
$ 1,734,178
726,000
$ 1,480,665
(907,000)
See notes to consolidated financial statements.
40
RGC RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2018, 2017 AND 2016
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation—RGC Resources, Inc. is an energy services company primarily engaged in the sale and
distribution of natural gas. The consolidated financial statements include the accounts of RGC Resources, Inc. and its
wholly owned subsidiaries (“Resources” or the “Company”): Roanoke Gas Company (“Roanoke Gas”), Diversified
Energy Company and RGC Midstream, LLC. Roanoke Gas is a natural gas utility, which distributes and sells natural
gas to approximately 60,200 residential, commercial and industrial customers within its service areas in Roanoke,
Virginia and the surrounding localities. The Company’s business is seasonal in nature as a majority of natural gas sales
are for space heating during the winter season. Roanoke Gas is regulated by the Virginia State Corporation
Commission (“SCC” or “Virginia Commission”). RGC Midstream, LLC is a wholly-owned subsidiary created
primarily to invest in the Mountain Valley Pipeline project. Diversified Energy Company is inactive.
The Company follows accounting and reporting standards established by the Financial Accounting Standards Board
(“FASB”) and the Securities and Exchange Commission (“SEC”).
Resources has only one reportable segment as defined under FASB ASC No. 280 – Segment Reporting. All
intercompany transactions have been eliminated in consolidation.
Certain reclassifications have been made to the prior year income statements to be consistent with the current year
presentation by moving cost of gas - utility and cost of sales - non utility under the operating expenses caption. This
presentation makes the Company's income statement presentation consistent with industry peers.
On June 28, 2018, the SEC adopted amendments to the definition of a "smaller reporting company' that became
effective on September 10, 2018. Under the rules for smaller reporting companies, certain disclosures required of
larger public business entities are reduced or eliminated. As it has met the qualifications under the definition of
smaller reporting company, the Company has used the smaller reporting company exception on a limited basis, but in
most instances, disclosures have been consistent with the prior year.
Rate Regulated Basis of Accounting—The Company’s regulated operations follow the accounting and reporting
requirements of FASB ASC No. 980, Regulated Operations. The economic effects of regulation can result in a
regulated company deferring costs that have been or are expected to be recovered from customers in a period different
from the period in which the costs would be charged to expense by an unregulated enterprise. When this situation
occurs, costs are deferred as assets in the consolidated balance sheet (regulatory assets) and recorded as expenses when
such amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for
amounts previously collected from customers and for current collection in rates of costs that are expected to be
incurred in the future (regulatory liabilities). In the event the provisions of FASB ASC No. 980 no longer apply to any
or all regulatory assets or liabilities, the Company would write off such amounts and include them in the consolidated
statements of income and comprehensive income in the period for which FASB ASC No. 980 no longer applied.
41
Regulatory assets and liabilities included in the Company’s consolidated balance sheets as of September 30, 2018 and
2017 are as follows:
Regulatory Assets:
Current Assets:
Accounts receivable:
Accrued WNA revenues
Under-recovery of gas costs
Other:
Accrued pension and postretirement medical
Utility Property:
In service:
Other
Other Assets:
Regulatory assets:
Premium on early retirement of debt
Accrued pension and postretirement medical
Other
Total regulatory assets
Regulatory Liabilities:
Current Liabilities:
Over-recovery of gas costs
Accrued expenses:
Over-recovery of SAVE Plan revenues
Rate refund
Deferred Credits and Other Liabilities:
Asset retirement obligations
Regulatory cost of retirement obligations
Regulatory liability - deferred income taxes
Total regulatory liabilities
September 30
2018
2017
169,602
922,898
$
248,840
—
293,000
658,786
11,945
11,945
1,826,995
5,704,718
1,330,434
10,259,592
$
1,941,182
8,643,524
1,211,554
12,715,831
— $
1,438,074
670,034
1,320,167
6,417,948
11,163,981
11,447,736
31,019,866
$
215,514
—
6,069,993
10,055,189
—
17,778,770
$
$
$
$
As of September 30, 2018, the Company had regulatory assets in the amount of $10,247,647 on which the Company
did not earn a return during the recovery period. These assets primarily pertain to the net funded position of the
Company’s benefit plans related to its regulated operations. As such, the amortization period is not specifically
defined.
Utility Plant and Depreciation—Utility plant is stated at original cost and includes direct labor and materials,
contractor costs, and all allocable overhead charges. The Company applies the group method of accounting, where the
costs of like assets are aggregated and depreciated by applying a rate based on the average expected useful life of the
assets. In accordance with Company policy, expenditures for depreciable assets with a life greater than one year are
capitalized, along with any upgrades or improvements to existing assets, when they significantly improve or extend
the original expected useful life of an asset. Expenditures for maintenance, repairs, and minor renewals and
betterments are expensed as incurred. The original cost of depreciable property retired is removed from utility plant
and charged to accumulated depreciation. The cost of asset removals, less salvage, is charged to “regulatory cost of
retirement obligations” or “asset retirement obligations” as explained under Asset Retirement Obligations below.
Utility plant is composed of the following major classes of assets:
42
Distribution and transmission
LNG storage
General and miscellaneous
Total utility plant in service
Years Ended September 30
2018
2017
$
196,778,546
$
177,845,619
13,413,175
14,662,599
13,299,288
13,078,807
$
224,854,320
$
204,223,714
Provisions for depreciation are computed principally at composite straight-line rates over periods ranging from 5 to 76
years. Rates are determined by depreciation studies which are required to be performed at least every 5 years on the
regulated utility assets of Roanoke Gas. The Company completed its last depreciation study in June 2014 and will be
required to complete a new depreciation study in fiscal 2019. The composite weighted-average depreciation rate
realized using the most recently completed depreciation study was 3.32%, 3.29% and 3.25% for fiscal years ended
September 30, 2018, 2017 and 2016.
The composite rates are composed of two components, one based on average service life and one based on cost of
retirement. As a result, the Company accrues the estimated cost of retirement of long-lived assets through depreciation
expense. Retirement costs are not a legal obligation but rather the result of cost-based regulation and are accounted for
under the provisions of FASB ASC No. 980. Such amounts are classified as a regulatory liability.
The Company reviews long-lived assets and certain identifiable intangibles for impairment whenever events or
changes in circumstances indicate that the carrying amount of an asset may not be recoverable. These reviews have not
identified any impairments which would have a material effect on the results of operations or financial condition.
Asset Retirement Obligations—FASB ASC No. 410, Asset Retirement and Environmental Obligations, requires
entities to record the fair value of a liability for an asset retirement obligation when there exists a legal obligation for
the retirement of the asset. When the liability is initially recorded, the entity capitalizes the cost, thereby increasing the
carrying amount of the underlying asset. In subsequent periods, the liability is accreted, and the capitalized cost is
depreciated over the useful life of the underlying asset. The Company has recorded asset retirement obligations for its
future legal obligations related to purging and capping its distribution mains and services upon retirement, although
the timing of such retirements is uncertain.
The Company’s composite depreciation rates include a component to provide for the cost of retirement of assets. As a
result, the Company accrues the estimated cost of retirement of its utility plant through depreciation expense and
creates a corresponding regulatory liability. The costs of retirement considered in the development of the depreciation
component include those costs associated with the legal liability. Therefore, the asset retirement obligation is
reclassified from the regulatory cost of retirement obligation. If the legal obligations were to exceed the regulatory
liability provided for in the depreciation rates, the Company would establish a regulatory asset for such difference with
the anticipation of future recovery through rates charged to customers. In 2017, the Company increased its asset
retirement obligation to reflect revisions to the estimated cash flows for asset retirements.
The following is a summary of the asset retirement obligation:
Beginning balance
Liabilities incurred
Liabilities settled
Accretion
Revisions to estimated cash flows
Ending balance
Years Ended September 30
2018
6,069,993
79,608
(126,907)
332,537
62,717
6,417,948
$
$
2017
5,682,556
65,556
(137,304)
312,503
146,682
6,069,993
$
$
Cash, Cash Equivalents and Short-Term Investments—From time to time, the Company will have balances on
deposit at banks in excess of the amount insured by the Federal Deposit Insurance Corporation (“FDIC”). The
Company has not experienced any losses on these accounts and does not consider these amounts to be at credit risk. As
of September 30, 2018, the Company did not have any bank deposits in excess of the FDIC insurance limits. For
purposes of the consolidated statements of cash flows, the Company considers all highly liquid debt instruments
purchased with an original maturity of three months or less to be cash equivalents.
43
Customer Receivables and Allowance for Doubtful Accounts—Accounts receivable include amounts billed to
customers for natural gas sales and related services and gas sales occurring subsequent to normal billing cycles but
before the end of the period. The Company provides an estimate for losses on these receivables by utilizing historical
information, current account balances, account aging and current economic conditions. Customer accounts are charged
off annually when deemed uncollectible or when turned over to a collection agency for action.
A reconciliation of changes in the allowance for doubtful accounts is as follows:
Beginning balance
Provision for doubtful accounts
Recoveries of accounts written off
Accounts written off
Ending balance
Years Ended September 30
2018
2017
2016
$
$
99,456
169,096
78,919
(243,898)
103,573
$
$
76,934
84,587
110,725
(172,790)
99,456
$
$
52,721
14,074
137,055
(126,916)
76,934
Financing Receivables—Financing receivables represent a contractual right to receive money either on demand, or on
fixed or determinable dates, and are recognized as assets on the entity’s balance sheet. Trade receivables, resulting
from the sale of natural gas and other services to customers, are the Company's primary type of financing receivables.
These receivables are short-term in nature with a provision for uncollectible balances included in the financial
statements.
Inventories—Natural gas in storage and materials and supplies inventories are recorded at average cost. Natural gas
storage injections are priced at the purchase cost at the time of injection and storage withdrawals are priced at the
weighted average cost of gas in storage. Materials and supplies are removed from inventory at average cost.
Unbilled Revenues—The Company bills its natural gas customers on a monthly cycle; however, the billing cycle
period for most customers does not coincide with the accounting periods used for financial reporting. As the Company
recognizes revenue when gas is delivered, an accrual is made to estimate revenues for natural gas delivered to
customers but not billed during the accounting period. The amounts of unbilled revenue receivable included in
accounts receivable on the consolidated balance sheets at September 30, 2018 and 2017 were $911,657 and $965,683,
respectively.
Income Taxes—Income taxes are accounted for using the asset and liability method. Under the asset and liability
method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to
differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax
bases. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the years in which those
temporary differences are expected to be recovered or settled. A valuation allowance against deferred tax assets is
provided if it is more likely than not the deferred tax asset will not be realized. The Company and its subsidiaries file
state and federal consolidated income tax returns.
Debt Expenses—Debt issuance expenses are deferred and amortized over the lives of the debt instruments. The
unamortized balances are offset against the carrying value of long-term debt.
Over/Under-Recovery of Natural Gas Costs—Pursuant to the provisions of the Company’s Purchased Gas
Adjustment (“PGA”) clause, the SCC provides the Company with a method of passing along to its customers increases
or decreases in natural gas costs incurred by its regulated operations, including gains and losses on natural gas
derivative hedging instruments. On a quarterly basis, the Company files a PGA rate adjustment request with the SCC
to increase or decrease the gas cost component of its rates, based on projected price and activity. Once administrative
approval is received, the Company adjusts the gas cost component of its rates to reflect the approved amount. As
actual costs will differ from the projections used in establishing the PGA rate, the Company may either over-recover or
under-recover its actual gas costs during the period. Any difference between actual costs incurred and costs recovered
through the application of the PGA is recorded as a regulatory asset or liability. At the end of the deferral period, the
balance of the net deferred charge or credit is amortized over an ensuing 12-month period as amounts are reflected in
customer billings.
Fair Value—Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an
orderly transaction between market participants at the measurement date. The Company determines fair value based on
the following fair value hierarchy which prioritizes each input to the valuation methods into one of the following three
broad levels:
44
•
•
•
Level 1 – Unadjusted quoted prices in active markets for identical assets or liabilities that
the Company has the ability to access at the measurement date.
Level 2 – Inputs other than quoted prices in Level 1 that are either for similar assets or
liabilities in active markets, quoted prices for identical or similar assets or liabilities in
markets that are not active, inputs other than quoted prices that are observable for the asset
or liability, or inputs that are derived principally from or corroborated by observable
market data by correlation or other means.
Level 3 – Unobservable inputs for the asset or liability where there is little, if any, market
activity which require the Company to develop its own assumptions.
The fair value hierarchy gives the highest priority to unadjusted quoted prices in active markets (Level 1) and the
lowest priority to unobservable inputs (Level 3). All fair value disclosures are categorized within one of the three
categories in the hierarchy. See fair value disclosures below and in Notes 8 and 12.
Use of Estimates—The preparation of financial statements in conformity with Generally Accepted Accounting
Principles in the United States of America requires management to make estimates and assumptions that affect the
reported amounts of assets and liabilities, disclosure of contingent liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those
estimates.
Excise and Sales Taxes—Certain excise and sales taxes imposed by the state and local governments in the Company’s
service territory are collected by the Company from its customers. These taxes are accounted for on a net basis and
therefore are not included as revenues in the Company’s Consolidated Statements of Income.
Earnings Per Share—Basic earnings per share and diluted earnings per share are calculated by dividing net income
by the weighted-average common shares outstanding during the period and the weighted-average common shares
outstanding during the period plus dilutive potential common shares, respectively. Dilutive potential common shares
are calculated in accordance with the treasury stock method, which assumes that proceeds from the exercise of all
options are used to repurchase common stock at market value. The amount of shares remaining after the proceeds are
exhausted represents the potentially dilutive effect of the securities. A reconciliation of basic and diluted earnings per
share is presented below:
Net Income
Weighted-average common shares
Effect of dilutive securities:
Options to purchase common stock
Diluted average common shares
Earnings Per Share of Common Stock:
Basic
Diluted
Years Ended September 30
2018
7,297,205
7,649,025
$
2017
6,232,865
7,218,686
$
2016
5,806,866
7,149,906
46,687
7,695,712
37,360
7,256,046
9,857
7,159,763
0.95
0.95
$
$
0.86
0.86
$
$
0.81
0.81
$
$
$
Business and Credit Concentrations—The primary business of the Company is the distribution of natural gas to
residential, commercial and industrial customers in its service territories.
No sales to individual customers accounted for more than 5% of total revenue in any period or amounted to more than
5% of total accounts receivable.
Roanoke Gas currently holds the only franchises and certificates of public convenience and necessity to distribute
natural gas in its service area. These franchises are effective through January 1, 2036. The Company's current
certificates of public convenience and necessity in Virginia are exclusive and are intended for perpetual duration.
Roanoke Gas is served directly by two primary pipelines that provide all of the natural gas supplied to the Company’s
customers. Depending upon weather conditions and the level of customer demand, failure of one or both of these
transmission pipelines could have a major adverse impact on the Company.
45
Derivative and Hedging Activities—FASB ASC No. 815, Derivatives and Hedging, requires the recognition of all
derivative instruments as assets or liabilities in the Company’s balance sheet and measurement of those instruments at
fair value.
The Company’s hedging and derivatives policy allows management to enter into derivatives for the purpose of
managing the commodity and financial market risks of its business operations. The Company’s hedging and
derivatives policy specifically prohibits the use of derivatives for speculative purposes. The key market risks that RGC
Resources, Inc. may hedge against include the price of natural gas and the cost of borrowed funds.
The Company historically has entered into collars, swaps and caps for the purpose of hedging the price of natural gas
in order to provide price stability during the winter months. The fair value of these instruments is recorded in the
balance sheet with the offsetting entry to either under-recovery of gas costs or over-recovery of gas costs. Net income
and other comprehensive income are not affected by the change in market value as any cost incurred or benefit
received from these instruments is recoverable or refunded through the PGA as the SCC allows for full recovery of
prudent costs associated with natural gas purchases. At September 30, 2018 and 2017, the Company had no
outstanding derivative instruments for the purchase of natural gas.
The Company has one interest rate swap associated with its $7,000,000 term note as discussed in Note 6. Effective
November 1, 2017, the swap agreement converted the floating rate note based on LIBOR into a fixed rate debt with a
2.30% effective interest rate. The swap qualifies as a cash flow hedge with changes in fair value reported in other
comprehensive income. No portion of the swap was deemed ineffective during the period.
The table below reflects the fair value of the derivative instrument and its corresponding classification in the
consolidated balance sheets.
Derivatives designated as hedging instruments:
Current assets:
Interest rate swap
Other assets:
Interest rate swap
Total derivatives designated as hedging instruments
September 30
2018
2017
$
$
$
100,723
$
26,777
209,840
310,563
$
$
90,066
116,843
The fair value of the interest rate swap is determined by using the counter party's proprietary models and certain
assumptions regarding past, present and future market conditions. See Note 12 for additional information on fair value.
Non-Cash Activity — A non-cash increase in investment in unconsolidated affiliate and corresponding increase in
capital contributions payable of $9,087,262 and $767,710 occurred for the fiscal years ended September 30, 2018 and
2017, respectively.
46
Other Comprehensive Income (Loss)—A summary of other comprehensive income is provided below:
Year Ended September 30, 2018:
Interest rate swap:
Unrealized gains
Transfer of realized gains to interest expense
Net interest rate swap
Defined benefit plans:
Net gain arising during period
Amortization of actuarial gains
Net defined benefit plans
Other comprehensive income
Year Ended September 30, 2017:
Interest rate swap:
Unrealized gains
Net interest rate swap
Defined benefit plans:
Net gain arising during period
Amortization of actuarial losses
Net defined benefit plans
Other comprehensive income
Year Ended September 30, 2016:
Defined benefit plans:
Net loss arising during period
Amortization of actuarial losses
Net defined benefit plans
Other comprehensive loss
Before Tax
Amount
Tax
(Expense)
or Benefit
Net of Tax
Amount
$
$
$
$
$
$
$
$
$
217,773
(24,053)
193,720
595,570
(23,887)
571,683
765,403
$
(62,807) $
6,937
(55,870)
(171,775) $
6,890
(164,885)
(220,755) $
154,966
(17,116)
137,850
423,795
(16,997)
406,798
544,648
116,843
$
116,843
(44,354) $
(44,354)
72,489
72,489
1,715,505
$
256,234
1,971,739
2,088,582
$
(651,892) $
(97,369)
(749,261)
(793,615) $
1,063,613
158,865
1,222,478
1,294,967
(560,887)
221,070
(339,817)
(339,817) $
213,137
(84,006)
129,131
129,131
$
(347,750)
137,064
(210,686)
(210,686)
The amortization of actuarial gains or losses are included as a component of net periodic pension and postretirement
benefit costs in operations and maintenance expense.
Composition of Accumulated Other Comprehensive Income (Loss):
Balance September 30, 2015
Other comprehensive income (loss)
Balance September 30, 2016
Other comprehensive income (loss)
Balance September 30, 2017
Other comprehensive income (loss)
Reclassification adjustment for the effect of change in tax
law
Balance September 30, 2018
$
$
Interest Rate
Swaps
— $
—
—
72,489
72,489
137,850
Defined Benefit
Plans
(2,286,545) $
(210,686)
(2,497,231)
1,222,478
(1,274,753)
406,798
Accumulated
Other
Comprehensive
Income (Loss)
(2,286,545)
(210,686)
(2,497,231)
1,294,967
(1,202,264)
544,648
20,285
230,624
$
(234,337)
(1,102,292) $
(214,052)
(871,668)
47
The reclassification related to the interest rate swap was charged to regulatory liability - deferred taxes to offset the
adjustment made when revaluing the deferred tax liability of the interest rate swap for the reduction in corporate
income tax rates. See recently adopted accounting standards for more information on the reclassification from
accumulated other comprehensive income.
Recently Adopted Accounting Standards
In March 2016, the FASB issued ASU 2016-09, Compensation - Stock Compensation: Improvements to Employee
Share-Based Payment Accounting. The guidance simplifies several aspects of the accounting for share-based payment
award transactions, including income tax consequences, classification of awards as either equity or liabilities and
classification on the statement of cash flows. The new guidance is effective for the Company for the annual reporting
period ending September 30, 2018 and interim periods within that annual period. Early adoption is permitted. The
Company adopted this ASU for the quarter ended September 30, 2016. Under the prior guidance, excess tax benefits
were to be tracked in an APIC pool and not recognized in the income statement. Tax deficiencies were netted against
the accumulated APIC pool and only recognized in the income statement starting at the time tax deficiencies exceeded
the pool. Under ASU 2016-09, the APIC pool is eliminated with all excess tax benefits and deficiencies recognized in
income tax expense on the income statement. Prior to the adoption of this ASU, stock option activity did not result in
the accumulation of an APIC pool; therefore, adopting the ASU had minimal impact on the Company’s current
financial position, results of operations or cash flows and no impact on prior results.
In January 2017, the FASB issued ASU 2017-03, Accounting Changes and Error Corrections and Investments - Equity
Method and Joint Ventures. This update adds the text of the SEC Staff Announcement, Disclosure of the Impact That
Recently Issued Accounting Standards Will Have on the Financial Statements of a Registrant When Such Standards
Are Adopted in a Future Period (in accordance with Staff Accounting Bulletin Topic 11.M) as paragraph 250-10-S99-6.
Related specifically to ASU 2014-09, ASU 2016-02 and ASU 2016-13, an SEC registrant should evaluate ASUs that
have not yet been adopted to determine and include appropriate financial disclosures and MD&A discussions,
including consideration of additional qualitative disclosures, to assist financial statement readers in assessing the
significance of impact on adoption. The new guidance is effective immediately. The nature of this guidance relates to
the effectiveness and quality of disclosures related to ASUs not yet adopted; however, there is no effect on the
Company's financial position, results of operations or cash flows.
In February 2018, the FASB issued ASU 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220) -
Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. The ASU provides the option
to reclassify stranded tax effects within Accumulated Other Comprehensive Income ("AOCI") to retained earnings in
each period in which the effects of the change in the U.S. federal corporate income tax rate, per the Tax Cuts and Jobs
Act, is recorded. The new guidance is effective for the Company for the annual reporting period ending September 30,
2020 and interim periods within that annual period. Early adoption is permitted. Management completed its evaluation
and adopted the new guidance in the fourth quarter of fiscal 2018. As a result, the Company reclassified $234,337 in
stranded tax expense out of AOCI to retained earnings related to pension and postretirement plans for the unregulated
operations of Resources. In addition, the Company also reclassified $20,285 out of AOCI to the regulatory liability for
the stranded tax expense related to the interest rate swap. See the Other Comprehensive Income section above and
Note 3 below for more information.
Recently Issued Accounting Standards
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) that affects any
entity that enters into contracts with customers for the transfer of goods or services or transfer of non-financial assets.
This guidance supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most
industry-specific guidance. The core principle of the new guidance is that an entity should recognize revenue to depict
the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity
expects to be entitled in exchange for those goods or services. To achieve that core principle, an entity should apply
the following steps: (1) identify the contract with the customer, (2) identify the performance obligations in the
contract, (3) determine the transaction price, (4) allocate the transaction price to the performance obligations in the
contract, and (5) recognize revenue when, or as, the entity satisfies the performance obligation. In August 2015, the
FASB issued ASU 2015-14 that deferred the effective date of this guidance by one year making the standard effective
for the Company's annual reporting period ending September 30, 2019 and interim periods within that annual period.
Subsequent ASUs have been issued, which provide additional guidance to assist in the implementation of the new
revenue standard. Based on the evaluation of the ASU, management has determined that the adoption of the new
standard will not have a material impact on the Company's financial position, results of operations or cash flows.
However, significant new disclosures will be required as a result of the guidance. The Company is completing the
48
review and updating of its disclosures and will reflect the changes with the adoption of the standard in the first quarter
of fiscal 2019 using the modified retrospective approach.
In January 2016, the FASB issued ASU 2016-01, Financial Instruments - Overall: Recognition and Measurement of
Financial Assets and Financial Liabilities. The ASU enhances the reporting model for financial instruments to provide
users of the financial statements with more useful information through several provisions, including the following: (1)
requires equity investments, excluding investments accounted for under the equity method, be measured at fair value
with changes in fair value recognized in net income, (2) simplifies the impairment assessment of equity investments
without readily determinable fair values, (3) eliminates the requirement to disclose the method(s) and significant
assumptions used to estimate the fair value that is required to be disclosed for financial instruments measured at
amortized cost on the balance sheet, (4) requires entities to use the exit price notion when measuring the fair value of
financial instruments for disclosure purposes, and (5) requires separate presentation of financial assets and financial
liabilities by measurement category and form of financial asset on the balance sheet or the accompanying notes to the
financial statements. The new guidance is effective for the Company for the annual reporting period ending September
30, 2019 and interim periods within that annual period. Management is in the process of completing its evaluation of
the standard, but does not anticipate the new guidance to have a material effect on its financial position, results of
operations or cash flows.
In February 2016, the FASB issued ASU 2016-02, Leases. The ASU leaves the accounting for leases mostly
unchanged for lessors, with the exception of targeted improvements for consistency; however, the new guidance
requires lessees to recognize assets and liabilities for leases with terms of more than 12 months. The ASU also revises
the definition of a lease as a contract, or part of a contract, that conveys the right to control the use of identified
property, plant or equipment for a period of time in exchange for consideration. Consistent with current GAAP, the
presentation and cash flows arising from a lease by a lessee will primarily depend on its classification as a finance or
operating lease. In contrast, the new ASU requires both types of leases to be recognized on the balance sheet. In
addition, the new guidance includes quantitative and qualitative disclosure requirements to aid financial statement
users in better understanding the amount, timing and uncertainty of cash flows arising from leases. The new guidance
is effective for the Company for the annual reporting period ending September 30, 2020 and interim periods within
that annual period. Early adoption is permitted. The Company has completed its inventory of leases and does not
currently expect the new guidance to have a material effect on its financial position, results of operations or cash
flows.
In March 2017, the FASB issued ASU 2017-07, Compensation - Retirement Benefits. The primary objective of this
guidance is to improve the financial statement presentation of net periodic pension and postretirement benefit costs;
however, it also changes which cost components are eligible for capitalization. The amendments in the ASU require
that an employer report the service cost component in the same line item or items as other compensation costs arising
from services rendered by the employees during the period. The other components of net benefit cost are required to
be presented in the income statement separately from the service cost component and, if a subtotal for income from
operations is presented, outside of income from operations. In addition, the ASU allows only the service cost
component of periodic benefit cost to be eligible for capitalization when applicable. This change to capitalization
eligibility differs from the treatment currently applied by the Company and from allowed regulatory accounting. The
new guidance is effective for the Company for the annual reporting period ending September 30, 2019 and interim
periods within that annual period. Early adoption is permitted. Management has had discussions with its state
regulators regarding the adoption of this ASU for regulatory purposes. The regulatory body has not taken a position
on the change in capitalization requirements for these benefit costs and will evaluate the impact of this ASU on a case
by case basis. The Company intends to adopt this ASU effective October 1, 2018 with the change in expense
classification on a retrospective basis and the change in capitalization of costs on a prospective basis. If the regulatory
body ultimately determines that changes to the capitalization of these retirement benefits is not appropriate for
regulatory purposes, the Company may have to establish regulatory assets or liabilities for those costs or benefits
excluded from capitalization under this ASU. Management does not expect the new guidance to have a material effect
on the Company's consolidated financial statements.
In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging: Targeted Improvements to Accounting For
Hedging Activities. The ASU is meant to simplify recognition and presentation guidance in an effort to improve
financial reporting of cash flow and fair value hedging relationships to better portray the economic results of an
entity's risk management activities. This is achieved through changes to both the designation and measurement
guidance for qualifying hedging relationships, as well as changes to the presentation of hedge results. The new
guidance is effective for the Company for the annual reporting period ending September 30, 2020 and interim periods
within that annual period. Early adoption is permitted. Management has not completed its evaluation of the new
49
guidance; however, it does not currently expect the new guidance to have a material effect on its financial position,
results of operations or cash flows.
In August 2018, the FASB issued ASU 2018-14, Compensation - Retirement Benefits - Defined Benefit Plans -
General (Subtopic 715-20) - Disclosure Framework - Changes to the Disclosure Requirements for Defined Benefit
Plans. This ASU modifies disclosure requirements for employers that sponsor defined benefit pension or other
postretirement plans. The new guidance is effective for the Company for the annual reporting period ending September
30, 2021. Early adoption is permitted. Management has not completed its evaluation of the new guidance; however,
the ASU only modifies disclosure requirements and will not effect financial position, results of operations or cash
flows.
In August 2018, the FASB issued ASU 2018-15, Intangibles - Goodwill and Other - Internal-Use Software (Subtopic
350-40): Customer's Accounting for Implementation Costs incurred in a Cloud Computing Arrangement that is a
Service Contract. This ASU reduces the complexity of accounting for costs of implementing a cloud computing
service arrangement and aligns the following requirements to capitalize implementation costs: 1) those incurred in a
hosting arrangement that is a service contract, and 2) those incurred to develop or obtain internal-use software,
including hosting arrangements that include an internal software license. The new guidance is effective for the
Company for the annual reporting period beginning October 1, 2020. Management has not completed its evaluation of
the new guidance; however, it believes the new guidance will change the future treatment of certain contracts by
allowing related implementation costs to be capitalized and amortized over time, rather than directly expensed.
Management does not currently expect the new guidance to have a material effect on its financial position, results of
operations or cash flows.
Other accounting standards that have been issued or proposed by the FASB or other standard–setting bodies are not
currently applicable to the Company or are not expected to have a significant impact on the Company’s financial
position, results of operations and cash flows.
2.
STOCK ISSUE
In March 2018, the Company issued 700,000 shares of common stock resulting in proceeds of $15,109,541 net of
underwriting and other expenses. The Company issued the common shares to strengthen its balance sheet by
increasing the equity component of its total capitalization ratio. The net proceeds were invested in Roanoke Gas to
supplement the funding of its infrastructure improvement and replacement programs.
3.
REGULATORY MATTERS
The SCC exercises regulatory authority over the natural gas operations of Roanoke Gas. Such regulation encompasses
terms, conditions and rates to be charged to customers for natural gas service, safety standards, service extension,
accounting and depreciation.
On October 10, 2018, Roanoke Gas filed a general rate case application requesting an increase in annual customer
non-gas rates of $10.5 million. This increase incorporates into the non-gas rate the impact of recent tax reform, non-
SAVE utility plant investment, increased operating costs and approximately $4.7 million in SAVE plan ("Steps to
Advance Virginia's Energy") revenues that are currently being billed through the SAVE 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 by the
SCC. The last non-gas rate increase was filed in 2013 with rates effective November 1, 2013.
On June 29, 2018, the Company filed with the SCC its most recent SAVE Plan and Rider. The SAVE Plan provides a
mechanism for the Company to recover the related depreciation and expenses and return on rate base of the additional
capital investment on a prospective basis without the filing of a formal application for an increase in non-gas base
rates. Under the current application, the Company submitted its report for refunding the over-collection of revenues
under the 2017 SAVE Plan and proposed new 2019 SAVE rates to be implemented for the investment in 2019 SAVE
Plan projects. With the filing of the application for the general rate case, all SAVE Plan revenues related to SAVE
projects completed or in process through December 2018 will be incorporated into the new non-gas rates effective
January 1, 2019. Accordingly, the SAVE Plan rider will reset beginning January 1, 2019 and will relate only to SAVE
projects and expenditures incurred on and after this date. On September 27, 2018, the SCC issued their order
approving the new 2019 SAVE rider, which is expected to provide approximately $362,000 in revenue. The SCC also
approved the True-up factor to provide for the refund of approximately $163,000 in over-collected balance from the
2017 SAVE Plan.
50
As discussed in Note 7, the Tax Cut and Jobs Act ("TCJA") provided for a reduction in the federal corporate income
tax rate to 21%. The Company revalued its deferred tax assets and liabilities to reflect the new federal tax rate. Under
the provisions of ASC 740, the corresponding adjustment to deferred income taxes generally flows through to income
tax expense. For rate regulated entities such as Roanoke Gas, these excess deferred income taxes were originally
recovered from its customers based on billing rates derived using a federal income tax rate of 34%. Therefore, the
adjustment to the net deferred tax liability of Roanoke Gas, to the extent such net deferred tax liabilities are
attributable to rate base or cost of service for customers, are refundable to or collectible from customers. As of
September 30, 2018, Roanoke Gas has a net deferred tax regulatory liability in the amount of approximately $11.4
million composed of $12.7 million related to excess tax depreciation that will be refunded back to customers over 28
years 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.
With the implementation of the TCJA, the change in federal income tax rates occurred during the Company's fiscal
year resulting in the use of a 24.3% blended rate for fiscal 2018 and a conversion to the 21% in fiscal 2019. On
January 8, 2018, the SCC issued a directive requiring the accrual of a regulatory liability for excess revenues collected
from customers attributable to the higher federal income tax rate, currently included as a component of customer
billing rates, until such time as the SCC approves revised billing rates incorporating the lower tax rate. For the year
ended September 30, 2018, Roanoke Gas has recorded a reduction to revenue and established a regulatory liability in
the amount of $1,320,167 related to the excess revenues collected from customers during the year. The reduction in
excess revenues corresponds with a similar reduction in corporate income tax expense for the regulated operations of
Roanoke Gas. The excess revenues related to the SAVE Plan and inventory carrying cost have already been reflected
separately from the refund liability. The actual refund will not be finalized until the SCC completes their review and
makes any adjustments to the Company's calculations.
4.
OTHER INVESTMENTS
In October 2015, the Company, through its wholly-owned subsidiary, RGC Midstream, LLC ("Midstream"), acquired
a 1% equity interest in the Mountain Valley Pipeline, LLC (the “LLC”). The LLC was established to construct and
operate a natural gas pipeline originating in northern West Virginia and extending through south central Virginia. The
proposed pipeline will have the capacity to transport approximately 2 million decatherms of natural gas per day.
The estimated total project cost has increased from $3.7 billion to $4.6 billion, thereby increasing Midstream's
estimated total contributions to approximately $46 million. This increase is due to delays in construction resulting
from judicial and regulatory actions. Primarily, these actions relate to the adequacy of reviews performed by various
permit-granting agencies related to the construction of the pipeline under waterways and through the Jefferson
National Forest. The pipeline is under construction as it had received Federal Energy Regulatory Commission
("FERC") approval as well as the necessary federal and state permits; however, several recent FERC and Fourth
Circuit Court rulings have led to work stoppages and imposed construction limitations. As a result, construction
progress has slowed significantly and delayed the projected in-service date to the end of calendar 2019.
In April 2018, the LLC announced the MVP Southgate project ("Southgate"), which is a planned 70 mile pipeline
extending from the Mountain Valley Pipeline mainline in Virginia to delivery points in North Carolina. Midstream is a
less than 1% investor in this project, which will be accounted for under the cost method. Total estimated project cost
is between $350 and $500 million of which Midstream's portion will be approximately $1.8 to $2.5 million. The
Southgate in-service date is currently targeted for the end of calendar 2020.
Midstream held an approximate $28.5 million investment in the LLC and Southgate project at September 30, 2018.
Initial funding for Midstream's investment is provided through two unsecured Promissory Notes, each with a 5-year
term, as further described in Note 6 below.
The Company will participate in the earnings generated from the transportation of natural gas through both pipelines
proportionate to its level of investment once the pipelines are placed in service.
The financial statement locations of the investments by Midstream are as follows:
51
Balance Sheet Location of Other Investments:
Other Assets:
September 30
2018
2017
Investment in unconsolidated affiliate
$ 28,507,146
$
7,445,106
Current Liabilities:
Capital contributions payable
Income Statement Location of Other Investments:
Equity in earnings of unconsolidated affiliate
$ 10,142,766
$
1,055,504
For the Years ended September 30
2018
938,531
$
2017
421,646
$
2016
$
152,864
The change in the investment in unconsolidated affiliate are provided below:
Cash investment
Change in accrued capital calls
Equity in earnings of unconsolidated affiliate
For the Years ended September 30,
2018
$ 11,036,247
9,087,262
$
938,531
2017
2,759,346
767,710
421,646
$
2016
3,055,746
287,794
152,864
Change in investment in unconsolidated affiliate
$ 21,062,040
$
3,948,702
$
3,496,404
5.
LINE-OF-CREDIT
On March 26, 2018, Roanoke Gas entered into a new unsecured line-of-credit agreement. This line-of-credit
agreement replaced the agreement scheduled to expire on March 31, 2019. The new agreement is for a 2-year term
expiring March 31, 2020 with a maximum borrowing limit of $25,000,000. Amounts drawn against the new
agreement are considered to be non-current, as the balance under the line-of-credit is not subject to repayment within
the next 12-month period.
The new agreement maintains the same variable interest rate based on 30-day LIBOR plus 100 basis points and
availability fee of 15 basis points as the previous agreement. The new agreement also maintains the multi-tiered
borrowing limits to accommodate seasonal borrowing demands and minimize borrowing costs. Available limits under
this agreement for the remaining term are as follows:
As of
September 30, 2018
November 21, 2018
March 1, 2019
July 22, 2019
September 22, 2019
March 1, 2020
$
Available
Line-of-Credit
20,000,000
21,000,000
17,000,000
22,000,000
25,000,000
22,000,000
52
A summary of the line-of-credit follows:
Available line-of-credit at year-end
Outstanding balance at year-end
Highest month-end balance outstanding
Average daily balance
Average rate of interest during year on outstanding balances
Interest rate at year-end
Interest rate on unused line-of-credit
2018
$ 20,000,000
7,361,017
17,054,377
6,730,334
September 30
2017
$ 21,000,000
17,791,760
17,791,760
10,936,114
2016
$ 24,000,000
14,556,785
15,246,089
9,620,914
2.53%
3.26%
0.15%
1.92%
2.23%
0.15%
1.40%
1.53%
0.15%
Associated with the line-of-credit is a credit agreement that contains various representations, warranties and covenants
including a requirement that the Company maintain an interest coverage ratio of not less than 1.5 to 1 and a long-term
debt to long-term capitalization ratio of less than 65%.
6.
LONG-TERM DEBT
On October 2, 2017, the Company issued 10-year unsecured notes in the principal amount of $8,000,000 with a fixed
interest rate of 3.58% per annum. The proceeds from the notes were used to refinance a portion of the Company's
line-of-credit balance into longer-term financing.
Roanoke Gas has a 5-year unsecured variable rate note in the principal amount of $7,000,000 and an interest rate swap
agreement, which converts the variable rate debt into a fixed-rate instrument with an annual interest rate of 2.30%.
The swap agreement became effective on November 1, 2017 and will continue through the duration of the note.
Midstream has two 5-year unsecured Promissory Notes ("Notes") which provide financing for capital investment in
its 1% interest in the LLC. In April 2018, the Notes and corresponding credit agreement were amended to increase the
total borrowing limits to $38 million and reduce the variable interest rate to 30-day LIBOR plus 135 basis points.
Furthermore, the amended credit agreement removed the requirement for Midstream to provide $5 million in funding
outside of the Notes.
Long-term debt consists of the following:
September 30
2018
2017
Principal
Unamortized
Debt Issuance
Costs
Principal
Unamortized
Debt Issuance
Costs
Roanoke Gas Company:
Unsecured senior notes payable, at 4.26%, due
on September 18, 2034
Unsecured term note payable, at 30-day
LIBOR plus 0.90%, November 1, 2021
Unsecured term notes payable, at 3.58% due
on October 2, 2027
RGC Midstream, LLC:
Unsecured term notes payable, at 30-day
LIBOR plus 1.35% due December 29, 2020
Total notes payable
Line-of-credit, at 30-day LIBOR plus 1.00%,
due March 31, 2020
Total long-term debt
$ 30,500,000
$
154,465
$ 30,500,000
$
164,119
7,000,000
10,283
7,000,000
8,000,000
43,343
—
13,618
48,160
$ 17,743,200
$ 63,243,200
$
$
74,190
$
6,312,200
282,281
$ 43,812,200
$
$
66,052
291,949
7,361,017
—
17,791,760
—
$ 70,604,217
$
282,281
$ 61,603,960
$
291,949
Debt issuance costs are amortized over the life of the related debt. As of September 30, 2018 and 2017, the Company
also had an unamortized loss on the early retirement of debt of $1,826,995 and $1,941,182, respectively, which has
been deferred as a regulatory asset and is being amortized over a 20 year period.
53
All of the debt agreements set forth certain representations, warranties and covenants to which the Company is
subject, including financial covenants that requires the ratio of long-term debt to long-term capitalization to not exceed
65%. All of the debt agreements except for the line-of-credit provide for priority indebtedness to not exceed 15% of
consolidated total assets.
The aggregate annual maturities of long-term debt for the next five years ending after September 30, 2018 are as
follows:
Year Ending September 30
2019
2020
2021
2022
2023
Thereafter
Total
7.
INCOME TAXES
Maturities
—
7,361,017
17,743,200
7,000,000
—
38,500,000
70,604,217
$
$
On December 22, 2017, the President signed into law the TCJA, which enacted significant changes to the Internal
Revenue Code, including the reduction in the maximum federal corporate income tax rate from 35% to 21% effective
January 1, 2018. As the Company is a fiscal year taxpayer, the Company applied a blended federal tax rate of 24.3%
for the fiscal year ended September 30, 2018 as determined on the number of days of the Company's fiscal year at
34% and the number of days at 21%.
Under the provisions of ASC 740 - Income Taxes, the deferred tax assets and liabilities of the Company must be
revalued to reflect the reduction in the corporate federal income tax rate. The result of this revaluation was a reduction
in the net deferred tax liability of approximately $9 million, including approximately $11.8 million reclassified to
regulatory liability, a $3 million gross up to reflect pre-tax basis, and $0.26 million increase in income tax expense
related to unregulated operations. The excess deferred income taxes are reflected on a pretax basis to appropriately
contemplate future tax consequences in the periods when the regulatory liability is settled. Approximately $13.1
million of the excess deferred taxes related to certain depreciable property that must be returned to customers subject
to normalization requirements. The excess deferred taxes related to the depreciable property will be returned to
customers over the remaining weighted average useful life of the property using the Reverse South Georgia method
beginning January 2018. The remaining balance in the regulatory liability relates to approximately $1.3 million in
deferred tax assets that will be collected from customers over a yet to be determined period.
The details of income tax expense are as follows:
Current income taxes:
Federal
State
Total current income taxes
Deferred income taxes:
Federal
State
Total deferred income taxes
Total income tax expense
Years Ended September 30
2018
2017
2016
$
1,831,085
$
72,368
$
308,057
2,139,142
440,282
315,712
755,994
407,643
480,011
3,129,925
195,454
3,325,379
$
2,895,136
$
3,805,390
$
(1,216,745)
415,975
(800,770)
4,302,906
164,048
4,466,954
3,666,184
54
Income tax expense for the years ended September 30, 2018, 2017 and 2016 differed from amounts computed by
applying the U.S. federal income tax rate to earnings before income taxes due to the following:
Income before income taxes
Corporate federal income tax rate
Income tax expense computed at the federal statutory
rate
State income taxes, net of federal income tax benefit
Revaluation of unregulated deferred taxes to 21%
Net amortization of excess deferred taxes on regulated
operations
Other, net
Total income tax expense
Years Ended September 30
2018
10,192,341
24.3%
2,476,739
472,193
256,444
(264,106)
(46,134)
2,895,136
$
$
$
$
$
2017
10,038,255
34.0%
3,413,007
398,044
—
—
2016
9,473,050
34.0%
3,220,837
382,815
—
—
(5,661)
3,805,390
62,532
$
3,666,184
$
$
$
The tax effects of temporary differences that give rise to the deferred tax assets and deferred tax liabilities are as
follows:
Deferred tax assets:
Allowance for uncollectibles
Accrued pension and postretirement medical benefits
Regulatory effect of change in federal income tax rate
Accrued vacation
Over-recovery of gas costs
Costs of gas held in storage
Deferred compensation
Rate refund
Other
Total gross deferred tax assets
Deferred tax liabilities:
Utility plant
Under-recovery of gas costs
MVP investment
Other
Total gross deferred tax liabilities
Net deferred tax liability
September 30
2018
2017
$
26,658
$
897,834
2,946,649
160,001
—
591,899
716,843
339,812
298,129
5,977,825
37,752
1,747,429
—
239,414
545,894
1,009,206
824,281
—
348,833
4,752,809
17,982,215
27,630,486
255,570
245,678
79,939
18,563,402
$
12,585,577
$
—
154,817
44,354
27,829,657
23,076,848
The current federal tax expense for fiscal 2016 reflected the effect of 50% bonus depreciation for the entire fiscal year
2016 as well as for nine months of fiscal 2015. The Protecting Americans from Tax Hikes ("PATH" Act), which
extended 50% bonus depreciation for calendar 2015, was signed into law on December 18, 2015, subsequent to the
issuance of the Company's September 30, 2015 annual report. As a result, $1,283,925 of deferred taxes that related to
fiscal 2015 bonus depreciation were reflected in the fiscal 2016 tax provision, thereby reducing the current tax expense
and increasing deferred tax expense by the same amount. The recording of the effect of the adjustments for bonus
depreciation had no effect on total income tax expense, net income or earnings per share. Only the current and
deferred components of income tax expense and their corresponding assets and liabilities were affected.
Under the PATH Act, 50% bonus depreciation extended through December 31, 2017, with 40% for calendar 2018 and
30% for calendar 2019 with no provision for bonus depreciation after 2019. Effective with the TCJA, utilities are no
longer eligible to take bonus depreciation.
55
FASB ASC No. 740 - Income Taxes provides for the determination of whether tax benefits claimed or expected to be
claimed on a tax return should be recognized in the financial statements. The Company has evaluated its tax positions
and accordingly has not identified any significant uncertain tax positions. The Company’s policy is to classify interest
associated with uncertain tax positions as interest expense in the financial statements. Penalties are classified under
other expense.
The Company files a consolidated federal income tax return and state income tax returns in Virginia and West
Virginia. The federal returns and the state returns for both Virginia and West Virginia for the tax years ended prior to
September 30, 2015 are no longer subject to examination.
8.
EMPLOYEE BENEFIT PLANS
The Company sponsors both a noncontributory defined benefit pension plan ("pension plan") and a postretirement
benefit plan ("postretirement plan"). The pension plan covers substantially all employees and benefits fully vest after
5 years of credited service. Benefits paid to retirees are based on age at retirement, years of service and average
compensation. Effective January 1, 2017, a "soft freeze" to the pension plan was implemented, and employees hired
on or after that date are no longer eligible to participate. Employees hired prior to January 1, 2017 will continue to
participate in the plan and accrue benefits. Commensurate with the "soft freeze" in the pension plan, the Company
amended its 401(k) Plan, allowing management to authorize a discretionary contribution to the 401(k) account for
those employees hired on or after January 1, 2017. The amount, if any, of this discretionary contribution would be
determined each year and would be applied to the eligible employees at the end of the calendar year. This Company
contribution would be in addition to any employee elected deferrals and employer match as provided for under the
401(k) Plan.
The postretirement benefit plan provides certain health care, supplemental retirement and life insurance benefits to
retired employees who meet specific age and service requirements. Employees hired prior to January 1, 2000 are
eligible to participate in the postretirement benefit plan. Employees must have a minimum of 10 years of service and
retire after attaining the age of 55 in order to vest in the postretirement plan. Retiree contributions to the plan are based
on the number of years of service to the Company as determined under the defined benefit plan.
Employers who sponsor defined benefit plans must recognize the funded status of defined benefit pension and other
postretirement plans as an asset or liability in their statements of financial position and recognize changes in that
funded status in the year in which the changes occur through comprehensive income. For pension plans, the benefit
obligation is the projected benefit obligation, and for other postretirement plans, the benefit obligation is the
accumulated benefit obligation. The Company established a regulatory asset for the portion of the obligation expected
to be recovered in rates in future periods. The regulatory asset is adjusted for the amortization of the transition
obligation and recognition of actuarial gains and losses. The portion of the obligation attributable to the unregulated
operations of the holding company is recognized in other comprehensive income.
56
The following tables set forth the benefit obligation, fair value of plan assets, the funded status of the benefit plans,
amounts recognized in the Company’s financial statements and the assumptions used.
Accumulated benefit obligation
Change in benefit obligation:
Pension Plan
Postretirement Plan
2018
2017
2018
2017
$ 25,199,762
$ 25,481,993
$ 16,207,322
$ 17,666,812
Benefit obligation at beginning of year
$ 29,657,347
$ 29,494,950
$ 17,666,812
$ 18,504,710
Service cost
Interest cost
Actuarial gain
Benefit payments, net of retiree contributions
Benefit obligation at end of year
Change in fair value of plan assets:
665,235
706,677
167,220
183,267
1,088,180
(1,727,767)
(832,696)
$ 28,850,299
995,598
(824,361)
(715,517)
$ 29,657,347
640,602
(1,774,320)
(492,992)
$ 16,207,322
626,822
(1,199,722)
(448,265)
$ 17,666,812
Fair value of plan assets at beginning of year
$ 26,418,671
$ 23,113,057
$ 12,691,162
$ 11,122,783
Actual return on plan assets, net of taxes
1,798,722
3,021,131
426,787
1,016,644
Employer contributions
Benefit payments, net of retiree contributions
Fair value of plan assets at end of year
Funded status
Amounts recognized in the balance sheet
consist of:
Noncurrent liabilities
Amounts recognized in accumulated other
comprehensive loss:
Net actuarial loss, net of tax
Total amounts included in other
comprehensive loss, net of tax
Amounts deferred to a regulatory asset:
Net actuarial loss
Amounts recognized as regulatory assets
$
$
$
$
$
$
800,000
(832,696)
$ 28,184,697
1,000,000
(448,265)
$ 12,691,162
(665,602) $ (3,238,676) $ (3,282,365) $ (4,975,650)
1,000,000
(715,517)
$ 26,418,671
300,000
(492,992)
$ 12,924,957
(665,602) $ (3,238,676) $ (3,282,365) $ (4,975,650)
361,215
361,215
3,894,221
3,894,221
$
$
$
$
572,740
572,740
5,471,547
5,471,547
$
$
$
$
741,077
741,077
2,103,497
2,103,497
$
$
$
$
702,013
702,013
3,830,763
3,830,763
The Company expects that approximately $10,000 before tax, of accumulated other comprehensive income will be
recognized as a reduction in net periodic benefit costs in fiscal 2019 and approximately $293,000 of amounts deferred
as regulatory assets will be amortized and recognized in net periodic benefit costs in fiscal 2019.
The following table details the actuarial assumptions used in determining the projected benefit obligations and net
benefit cost of the pension and the accumulated benefit obligations and net benefit cost of the postretirement plan for
2018, 2017 and 2016.
Pension Plan
Postretirement Plan
2018
2017
2016
2018
2017
2016
Assumptions used to determine benefit
obligations:
Discount rate
Expected rate of compensation increase
4.11%
4.00%
3.72%
4.00%
3.42%
4.00%
4.09%
N/A
3.69%
N/A
3.33%
N/A
Assumptions used to determine benefit
costs:
Discount rate
Expected long-term rate of return on plan
assets
Expected rate of compensation increase
3.72%
3.42%
4.22%
3.69%
3.33%
4.15%
7.00%
4.00%
7.00%
4.00%
7.00%
4.00%
4.84%
N/A
4.84%
N/A
4.89%
N/A
57
To develop the expected long-term rate of return on assets assumption, the Company, with input from the plans'
actuaries and investment advisors, considered the historical returns and the future expectations for returns for each
asset class, as well as the target asset allocation of each plan’s portfolio.
Components of net periodic benefit cost are as follows:
Service cost
Interest cost
Expected return on plan assets
Recognized loss
Pension Plan
Postretirement Plan
2018
2017
2016
2018
2017
2016
$ 665,235
$
706,677
$
694,375
$ 167,220
$ 183,267
$ 148,018
1,088,180
(1,862,838)
351,030
995,598
(1,616,412)
662,180
1,132,776
(1,492,241)
501,678
640,602
(623,381)
283,868
626,822
(571,513)
429,758
624,579
(507,858)
250,173
Net periodic benefit cost
$ 241,607
$
748,043
$
836,588
$ 468,309
$ 668,334
$ 514,912
The assumed health care cost trend rates used in measuring the accumulated benefit obligation for the postretirement
medical plan as of September 30, 2018, 2017 and 2016 are presented below:
2018
Pre 65
2017
2016
2018
Post 65
2017
2016
Health care cost trend rate assumed for next
year
Rate to which the cost trend is assumed to
decline (the ultimate trend rate)
Year that the rate reaches the ultimate trend rate
7.00%
7.00%
7.50%
5.00%
5.00%
5.00%
5.00%
2026
5.00%
2021
5.00%
2021
5.00%
2018
5.00%
2017
5.00%
2016
The health care cost trend rate assumptions could have a significant effect on the amounts reported. A change of 1%
would have the following effects:
Effect on total service and interest cost components
Effect on accumulated postretirement benefit obligation
1% Increase
1% Decrease
$
155,000
2,487,000
$
(123,000)
(2,025,000)
The primary objectives of the Plans' investment policies are to maintain investment portfolios that diversify risk
through prudent asset allocation parameters, achieve asset returns that meet or exceed the plans’ actuarial assumptions,
achieve asset returns that are competitive with like institutions employing similar investment strategies and meet
expected future benefits in both the short-term and long-term. In 2018, the Company revised its targeted pension plan
investment allocation by rebalancing the assets from a 60% equity allocation to a 40% equity allocation. This change
in investment strategy was in response to the pension plan approaching a fully funded position, thereby allowing the
opportunity to reduce investment risk and volatility in asset performance while providing for asset growth through the
remaining equity investments. As a result, the Company updated its long-term rate of return on pension and
postretirement plan assets for fiscal 2019 to 5.5% and 4.3%, respectively. The investment policy continues to provide
for a range of investment allocations to allow for continued flexibility in responding to market conditions.
The Company’s target and actual asset allocation in the pension and postretirement benefit plans as of September 30,
2018 and 2017 were:
Asset category:
Equity securities
Debt securities
Cash
Other
Pension Plan
Postretirement
Plan
Target
2018
2017
Target
2018
2017
40%
60%
—%
—%
40%
59%
1%
—%
63%
36%
1%
—%
50%
50%
—%
—%
49%
50%
1%
—%
51%
48%
1%
—%
58
The assets of the plans are invested in mutual funds. The Company uses the fair value hierarchy described in Note 1 to
classify these assets. The mutual funds are included under Level 2 in the fair value hierarchy as their fair values are
determined based on individual prices for each security that comprises the mutual funds. Most of the individual
investments are determined based on quoted market prices for each security; however, certain fixed income securities
and other investments are not actively traded and are valued based on similar investments. The following table
contains the fair value classifications of the benefit plan assets:
Defined Benefit Pension Plan
Fair Value Measurements - September 30, 2018
Fair Value
Level 1
Level 2
Level 3
$
282,478
$
282,478
$
— $
Asset Class:
Cash
Common and Collective Trust and
Pooled Funds:
Bonds
Liability Driven Investment
16,504,956
Equities
Domestic Large Cap Growth
Domestic Large Cap Value
Domestic Small/Mid Cap
Core
Foreign Large Cap Value
3,449,486
3,381,285
1,685,352
1,527,796
—
—
—
—
—
16,504,956
3,449,486
3,381,285
1,685,352
1,527,796
Mutual Funds:
Equities
Foreign Large Cap Growth
Foreign Large Cap Value
1,060,383
292,961
28,184,697
$
$
—
—
282,478
$
1,060,383
292,961
27,902,219
$
Total
Defined Benefit Pension Plan
Fair Value Measurements - September 30, 2017
Fair Value
Level 1
Level 2
Level 3
$
265,100
$
265,100
$
— $
Asset Class:
Cash
Common and Collective Trust and
Pooled Funds:
Bonds
Liability Driven Investment
9,635,998
Equities
Domestic Large Cap Growth
Domestic Large Cap Value
Domestic Small/Mid Cap
Core
Foreign Large Cap Value
Mutual Funds:
Equities
Foreign Large Cap Growth
Foreign Large Cap Value
Foreign Large Cap Core
5,068,282
5,046,530
2,393,221
2,139,733
399,909
398,995
1,070,903
—
—
—
—
—
—
—
—
9,635,998
5,068,282
5,046,530
2,393,221
2,139,733
399,909
398,995
1,070,903
Total
$
26,418,671
$
265,100
$
26,153,571
$
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
59
Postretirement Benefit Plan
Fair Value Measurements - September 30, 2018
Fair Value
Level 1
Level 2
Level 3
$
96,117
$
96,117
$
— $
5,859,588
609,722
1,926,076
1,874,643
214,180
210,891
459,363
525,720
1,090,851
28,786
29,020
—
—
—
—
—
—
—
—
—
—
—
5,859,588
609,722
1,926,076
1,874,643
214,180
210,891
459,363
525,720
1,090,851
28,786
29,020
$
12,924,957
$
96,117
$
12,828,840
$
Postretirement Benefit Plan
Fair Value Measurements - September 30, 2017
Fair Value
Level 1
Level 2
Level 3
$
64,616
$
64,616
$
— $
Asset Class:
Cash
Mutual Funds
Bonds
Domestic Fixed Income
Foreign Fixed Income
Equities
Domestic Large Cap Growth
Domestic Large Cap Value
Domestic Small/Mid Cap
Growth
Domestic Small/Mid Cap
Value
Domestic Small/Mid Cap
Core
Foreign Large Cap Growth
Foreign Large Cap Value
Foreign Large Cap Core
Other
Total
Asset Class:
Cash
Mutual Funds
Bonds
Domestic Fixed Income
Foreign Fixed Income
Equities
Domestic Large Cap Growth
Domestic Large Cap Value
Domestic Small/Mid Cap
Growth
Domestic Small/Mid Cap
Value
Domestic Small/Mid Cap
Core
Foreign Large Cap Growth
Foreign Large Cap Value
Foreign Large Cap Core
Other
Total
5,727,258
359,460
1,998,971
1,998,714
209,332
209,630
455,867
39,107
1,079,766
511,298
37,143
—
—
—
—
—
—
—
—
—
—
—
5,727,258
359,460
1,998,971
1,998,714
209,332
209,630
455,867
39,107
1,079,766
511,298
37,143
$
12,691,162
$
64,616
$
12,626,546
$
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Each mutual fund has been categorized based on its primary investment strategy.
60
The Company expects to contribute $800,000 to its pension plan and $300,000 to its postretirement benefit plan in
fiscal 2019.
The following table reflects expected future benefit payments:
Fiscal year ending September 30
2019
2020
2021
2022
2023
2024-2028
$
Pension
Plan
Postretirement
Plan
$
934,935
983,862
1,042,332
1,124,774
1,220,246
7,346,304
688,340
685,088
725,587
778,814
834,042
4,230,466
The Company sponsors a defined contribution plan (the “401k Plan”) covering all employees who elect to participate.
Employees may contribute from 1% to 50% of their annual compensation to the 401k Plan, limited to a maximum
annual amount as set periodically by the Internal Revenue Service. The Company matches 100% of the participant’s
first 4% of contributions and 50% on the next 2% of contributions. Company matching contributions were $338,066,
$361,702 and $353,793 for 2018, 2017 and 2016, respectively. The Company also provided for $9,637 in
discretionary contributions in 2018 for those employees hired on or after January 1, 2017.
9.
COMMON STOCK OPTIONS
The Company’s stockholders approved the RGC Resources, Inc. Key Employee Stock Option Plan (“KESOP”). The
KESOP provides for the issuance of common stock options to officers and certain other full-time salaried employees
to acquire shares of the Company’s common stock. As of September 30, 2018, the number of shares available for
future grants was 36,000.
FASB ASC No. 718 - Compensation-Stock Compensation requires that compensation expense be recognized for the
issuance of equity instruments to employees. During the fiscal years ended 2017 and 2016, the Board approved stock
option grants to certain officers. As required by the KESOP, each option's exercise price per share equaled the fair
value of the Company's common stock on the grant date. Pursuant to the Plan, the options vest over a six-month
period and are exercisable over a ten-year period from the date of issuance. No options were granted in fiscal 2018.
As the Company's stock options are not traded on the open market, the fair value of each grant is estimated on the date
of grant using the Black-Scholes option pricing model including the following assumptions:
Expected volatility
Expected dividends
Expected exercise term (years)
Risk-free interest rate
2018
N/A
N/A
N/A
N/A
Years Ended September 30,
2017
26.09%
3.81%
7.00
2.20%
2016
28.78%
3.99%
7.00
2.10%
The underlying methods regarding each assumption are as follows:
Expected volatility is based on the historical volatilities of the daily closing price of the Company's common
stock.
Expected dividend rate is based on historical dividend payout trends.
Expected exercise term is based on the average time historical option grants were outstanding before being
exercised.
Risk-free interest rate is based on the 7-year Treasury rate on the date of option grant.
Forfeitures are recognized when they occur.
Stock option transactions under the Company's plans for the years ended September 30, 2018, 2017 and 2016 are
summarized below. The information contained in the tables below have been restated to reflect the effect of the stock
split:
61
Number of
Shares
Weighted-
Average Exercise
Price
Options outstanding, September 30, 2015
Options granted
Options exercised
Options expired
Options forfeited
Options outstanding, September 30, 2016
Options granted
Options exercised
Options expired
Options forfeited
$
78,600
24,000
(3,300)
—
(12,000)
87,300
25,500
(11,225)
—
—
Options outstanding, September 30, 2017
101,575
Options granted
Options exercised
Options expired
Options forfeited
—
(1,575)
—
—
Options outstanding, September 30, 2018
100,000
$
13.22
14.15
12.65
—
13.20
13.50
16.37
12.67
—
—
14.31
—
12.66
—
—
14.34
Vested and exercisable at September 30,
2018
100,000
$
14.34
1
Aggregate intrinsic value includes only those options where the exercise price is below the market price.
Weighted-
Average
Remaining
Contractual
Terms (years)
8.3
Aggregate
Intrinsic Value 1
$
43,086
7.8
200,211
7.6
1,448,338
6.6
6.6
$
1,237,286
$
1,237,286
2018
Years Ended September 30,
2017
2016
Weighted-average grant date option fair value
$
— $
2.89
$
Stock option expense
Intrinsic value of options exercised
Proceeds from exercise of stock options
—
15,256
19,945
73,780
99,929
142,241
2.69
64,640
8,418
41,762
10.
OTHER STOCK PLANS
Dividend Reinvestment and Stock Purchase Plan
The Company offers a Dividend Reinvestment and Stock Purchase Plan (the “DRIP”) to shareholders of record for the
reinvestment of dividends and the purchase of up to $40,000 per year in additional shares of common stock of the
Company. Under the DRIP, the Company issued 31,744, 36,446 and 52,146 shares in 2018, 2017 and 2016,
respectively. As of September 30, 2018, the Company had 417,229 shares of stock available for issuance under the
DRIP.
Restricted Stock Plan for Outside Directors
The Board of Directors of the Company implemented the Restricted Stock Plan for Outside Directors (the “Plan”)
effective January 27, 1997. Under the Plan, each director may elect annually to have up to 100% of his or her fees paid
in shares of common stock ("Director Restricted Stock"); however, a minimum of 40% of the monthly retainer fee
must be paid to each non-employee director of Resources in shares of Director Restricted Stock until such time as the
director has accumulated at least 10,000 shares. The number of shares of Restricted Stock awarded each month is
determined based on the closing sales price of Resources' common stock on the NASDAQ Global Market on the first
62
business day of the month. The Director Restricted Stock issued under the Plan vests only in the case of a participant's
death, disability, retirement, or in the event of a change in control of Resources. The Director Restricted Stock may
not be sold, transferred, assigned or pledged by the participant until the shares have vested under the terms of the Plan.
The shares of Director Restricted Stock will be forfeited to Resources by a participant's voluntary resignation during
his or her term on the Board or removal for cause as a director.
The Company assumes all directors will complete their term and there will be no forfeiture of the Restricted Stock.
Since the inception of the Plan, no director has forfeited any shares of Restricted Stock. The Company recognizes as
compensation the market value of the Restricted Stock in the period it is issued.
The following table reflects the director compensation activity pursuant to the Plan:
2018
2017
2016
Weighted-
Average Fair
Value on Date
of Grant
Shares
Weighted-
Average Fair
Value on Date
of Grant
Shares
Weighted-
Average Fair
Value on Date
of Grant
Shares
111,893
$
6,692
(20,283)
—
10.56
26.57
11.20
—
107,023
$
4,870
—
—
10.11
16.77
—
—
100,373
$
6,650
—
—
9.80
14.79
—
—
Beginning of year
balance
Granted
Vested
Forfeited
End of year balance
98,302
$
11.51
111,893
$
10.56
107,023
$
10.11
The fair market value of the Director Restricted Stock included in compensation during fiscal 2018, 2017 and 2016
was $177,800, $99,400 and $98,334. No Director Restricted Stock vested or was forfeited during fiscal 2017 and
2016.
As of September 30, 2018, the Company had 75,049 shares available for issuance under the Plan.
RGC Resources, Inc. Restricted Stock Plan
The Board of Directors of the Company implemented the RGC Resources, Inc. Restricted Stock Plan (the “Restricted
Stock Plan”) in 2017 following approval by the shareholders at the Company's annual meeting held on February 6,
2017. Under the Restricted Stock Plan, the Compensation Committee of the Board of Directors may grant shares of
restricted stock ("Officer Restricted Stock") that vest over time to key employees and officers for the purpose of
attracting and retaining those individuals essential to the operation and growth of the Company. The Restricted Stock
Plan provides for certain restrictions and non-transferability requirements until minimum levels of ownership are
obtained. Such restrictions may continue beyond the vesting period.
The Company assumes all officers will complete their requirements and there will be no forfeiture of the Officer
Restricted Stock.
The following table reflects the officer compensation activity pursuant to the Restricted Stock Plan:
Beginning of year balance
Granted
Vested
Forfeited
End of year balance
2018
Shares
Weighted-Average Fair
Value on Date of Grant
— $
10,101
(3,367)
—
6,734
$
—
26.33
26.33
—
26.33
The fair market value of the Officer Restricted Stock included as compensation during fiscal 2018 was $188,388. As
of September 30, 2018, the Company had 439,734 shares available for issuance under the Plan.
63
Stock Bonus Plan
Shares from the Stock Bonus Plan may be issued to certain employees and management personnel in recognition of
their performance and service. Under the Stock Bonus Plan, the Company issued 1,628 and 2,813 shares valued at
$30,154 and $39,819, respectively, in 2017 and 2016. No shares were issued in 2018. As of September 30, 2018 the
Company had 4,785 shares of stock available for issuance under the Stock Bonus Plan. This Plan is currently inactive
and has been replaced by the Restricted Stock Plan.
11.
COMMITMENTS AND CONTINGENCIES
Long-Term Contracts
Due to the nature of the natural gas distribution business, Roanoke Gas enters into agreements with both suppliers and
pipelines to contract for natural gas commodity purchases, storage capacity and pipeline delivery capacity. Roanoke
Gas obtains most of its regulated natural gas supply through an asset management contract with a third party asset
manager. Roanoke Gas utilizes an asset manager to optimize the use of its transportation, storage rights, and gas
supply inventories which helps to ensure a secure and reliable source of natural gas. Under the current asset
management contract, Roanoke Gas has designated the asset manager to act as agent for its storage capacity and all
gas balances in storage. Roanoke Gas retains ownership of gas in storage. Under provisions of this contract, Roanoke
Gas is obligated to purchase its winter storage requirements from the asset manager during the spring and summer
injection periods at market price. The table below details the volumetric obligations as of September 30, 2018 for the
remainder of the contract period. The asset management contract was renewed for another three year period at
essentially the same terms and conditions as the prior agreement. The current asset management agreement will expire
in March 2021.
Year
2018-2019
2019-2020
2020-2021
Total
Natural Gas Contracts
(In Decatherms)
2,089,578
2,071,061
295,866
4,456,505
Roanoke Gas also has contracts for pipeline and storage capacity which extend for various periods. These capacity
costs and related fees are valued at tariff rates in place as of September 30, 2018. These rates may increase or decrease
in the future based upon rate filings and rate orders granting a rate change to the pipeline or storage operator. Roanoke
Gas expended approximately $31,137,000, $28,496,000 and $24,852,000 under the asset management, pipeline and
storage contracts in fiscal years 2018, 2017 and 2016, respectively. The table below details the pipeline and storage
capacity obligations as of September 30, 2018 for the remainder of the contract period.
Year
2018-2019
2019-2020
2020-2021
2021-2022
2022-2023
Thereafter
Total
Pipeline and
Storage Capacity
$
11,184,000
8,856,915
6,503,953
5,847,945
2,369,904
1,950,134
$
36,712,851
64
Roanoke Gas maintains franchise agreements granted by the local cities and towns served by the Company. Roanoke
Gas recently renewed it's franchise agreements with the City of Roanoke, the City of Salem and the Town of Vinton
for 20-year terms expiring in December 2035. Per the agreements, franchise fees will increase 3% per year through the
term of the agreements for a total cost of $2,512,411.
Other Contracts
The Company maintains other agreements in the ordinary course of business covering various lease, maintenance,
equipment and service contracts. These agreements currently extend through December 2031 and are not material to
the Company.
Legal
From time to time, the Company may become involved in litigation or claims arising out of its operations in the
normal course of business. At the current time, the Company is not known to be a party to any legal proceedings that
would be expected to have a materially adverse impact on its financial position, results of operations or cash flows.
Environmental Matters
Both Roanoke Gas and a previously owned gas subsidiary operated manufactured gas plants (MGPs) as a source of
fuel for lighting and heating until the early 1950’s. A by-product of operating MGPs was coal tar, and the potential
exists for tar waste contaminants at the former plant sites. While the Company does not currently recognize any
commitments or contingencies related to environmental costs at either site, should the Company ever be required to
remediate either site, it will pursue all prudent and reasonable means to recover any related costs, including the use of
insurance claims and regulatory approval for rate case recognition of expenses associated with any work required.
12.
FAIR VALUE MEASUREMENTS
The following table summarizes the Company’s financial assets and liabilities that are measured at fair value on a
recurring basis and the fair value measurements by level within the fair value hierarchy as defined in Note 1 as of
September 30, 2018 and 2017, respectively:
Assets:
Interest rate swaps
Total
Liabilities:
Natural gas purchases
Total
Assets:
Interest rate swaps
Total
Liabilities:
Natural gas purchases
Total
Fair Value Measurements - September 30, 2018
Quoted Prices in
Active Markets
Level 1
Significant Other
Observable
Inputs
Level 2
Significant
Unobservable
Inputs
Level 3
$
$
$
$
$
$
$
$
— $
— $
310,563
310,563
— $
— $
693,495
693,495
$
$
$
$
—
—
—
—
Fair Value Measurements - September 30, 2017
Quoted Prices in
Active Markets
Level 1
Significant Other
Observable
Inputs
Level 2
Significant
Unobservable
Inputs
Level 3
— $
— $
116,843
116,843
— $
— $
805,159
805,159
$
$
$
$
—
—
—
—
$
$
$
$
$
$
$
$
Fair Value
310,563
310,563
693,495
693,495
Fair Value
116,843
116,843
805,159
805,159
65
Under the asset management contract, a timing difference can exist between the payment for natural gas purchases and
the actual receipt of such purchases. Payments are made based on a predetermined monthly volume with the price
based on the weighted average first of the month index prices corresponding to the month of the scheduled payment.
At September 30, 2018 and 2017, the Company had recorded in accounts payable the estimated fair value of the
liability determined on the corresponding first of month index prices for which the liability was expected to be settled.
The Company’s nonfinancial assets and liabilities that are measured at fair value on a nonrecurring basis consist of its
asset retirement obligations. The asset retirement obligations are measured at fair value at initial recognition based on
expected future cash flows to settle the obligation.
The carrying value of cash and cash equivalents, accounts receivable, borrowings under line-of-credit, accounts
payable (with the exception of the timing difference under the asset management contract), customer credit balances
and customer deposits is a reasonable estimate of fair value due to the shorter-term nature of these financial
instruments. The following table summarizes the fair value of the Company’s financial assets and liabilities that are
not adjusted to fair value in the financial statements as of September 30, 2018 and 2017.
Liabilities:
Notes payable
Total
Liabilities:
Notes payable
Total
Fair Value Measurements - September 30, 2018
Carrying
Amount
Quoted Prices in
Active Markets
Level 1
Significant Other
Observable
Inputs
Level 2
Significant
Unobservable
Inputs
Level 3
$
$
63,243,200
63,243,200
$
$
— $
— $
— $
— $
62,435,237
62,435,237
Fair Value Measurements - September 30, 2017
Carrying
Amount
Quoted Prices in
Active Markets
Level 1
Significant Other
Observable
Inputs
Level 2
Significant
Unobservable
Inputs
Level 3
$
$
43,812,200
43,812,200
$
$
— $
— $
— $
— $
45,689,238
45,689,238
The fair value of long-term debt for Roanoke Gas is estimated by discounting the future cash flows of the fixed rate
debt based on the underlying 20-year Treasury rate or other Treasury instrument with a corresponding maturity period
and estimated credit spread extrapolated based on market conditions since the issuance of the debt. Increasing interest
rates during 2018 resulted in the reduction in the fair value of the Company's outstanding debt. The fair value for the
RGC Midstream debt is estimated by discounting the estimated credit spread extrapolated based on market conditions.
FASB ASC 825 – Financial Instruments requires disclosures regarding concentrations of credit risk from financial
instruments. Cash equivalents are investments in high-grade, short-term securities (original maturity less than three
months), placed with financially sound institutions. Accounts receivable are from a diverse group of customers
including individuals and small and large companies in various industries. The Company maintains certain credit
standards with its customers and requires a customer deposit if such evaluation warrants.
66
13.
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Quarterly financial data for the years ended September 30, 2018 and 2017 is summarized as follows:
2018
Operating revenues
Operating income
Net income
Earnings per share of common stock:
Basic
Diluted
2017
Operating revenues
Operating income
Net income
Earnings per share of common stock:
Basic
Diluted
14.
SUBSEQUENT EVENTS
First
Quarter
18,756,051
3,675,124
2,059,462
0.28
0.28
First
Quarter
18,788,585
3,982,275
2,232,218
0.31
0.31
$
$
$
$
$
$
$
$
$
$
Second
Quarter
24,917,973
5,306,718
3,465,929
0.47
0.47
Second
Quarter
21,900,013
5,589,207
3,225,199
0.45
0.45
$
$
$
$
$
$
$
$
$
$
Third
Quarter
11,889,570
1,866,223
1,087,355
0.14
0.14
Third
Quarter
11,435,824
1,328,207
615,562
0.09
0.08
$
$
$
$
$
$
$
$
$
$
Fourth
Quarter
9,971,142
744,980
684,459
0.09
0.09
Fourth
Quarter
10,172,448
766,620
159,886
0.02
0.02
$
$
$
$
$
$
$
$
$
$
The Company has evaluated subsequent events through the date the financial statements were issued. There were no
other items not otherwise disclosed which would have materially impacted the Company’s consolidated financial
statements.
* * * * * *
67
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A.
Controls and Procedures.
The Company maintains disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the
Securities Exchange Act of 1934, as amended (the “Exchange Act”)) that are designed to be effective in providing
reasonable assurance that information required to be disclosed in reports under the Exchange Act are recorded,
processed, summarized and reported within the time periods specified in the rules and forms of the Securities and
Exchange Commission (the “SEC”), and that such information is accumulated and communicated to management to
allow for timely decisions regarding required disclosure.
As of September 30, 2018, the Company completed an evaluation, under the supervision and with the participation of
management, including the chief executive officer and the chief financial officer, of the effectiveness of the design and
operation of the Company’s disclosure controls and procedures. Based upon that evaluation, the chief executive officer
and chief financial officer concluded that the Company’s disclosure controls and procedures were effective at the
reasonable assurance level as of September 30, 2018.
Management routinely reviews the Company’s internal control over financial reporting and makes changes, as
necessary, to enhance the effectiveness of the internal controls over financial reporting. There were no changes in the
internal controls over financial reporting during the fourth quarter of the fiscal year covered by this report that have
materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial
reporting.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The Company’s management is responsible for establishing and maintaining adequate internal control over financial
reporting (as defined in Rules 13a-15(f) under the Securities and Exchange Act of 1934). Internal control over financial
reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the
preparation and fair presentation of financial statements for external purposes in accordance with accounting principles
generally accepted in the United States of America and include those policies and procedures that: (i) pertain to the
maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the
assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures are being made only in accordance with authorizations of the management and directors of the Company;
and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the Company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations, any system of internal control over financial reporting, no matter how well
designed, may not prevent or detect misstatements due to the possibility that a control can be circumvented or
overridden or that misstatements due to error or fraud may occur that are not detected. Projections of the effectiveness
to future periods are subject to the risk that the internal controls may become inadequate because of changes in
conditions, or that the degree of compliance with the policies and procedures included in such controls may deteriorate.
The Company’s internal control system was designed to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external purposes in accordance with GAAP.
The Company has conducted an evaluation of the design and effectiveness of the Company’s system of internal control
over financial reporting as of September 30, 2018, based on the framework set forth in ”Internal Control - Integrated
Framework (2013)” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based upon
such evaluation, the Company concluded that, as of September 30, 2018, the Company’s internal control over financial
reporting was effective.
The Company’s independent registered public accounting firm, Brown, Edwards & Company, LLP, has issued its report
on the effectiveness of the Company’s internal control over financial reporting as of September 30, 2018.
68
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
RGC Resources, Inc.
Roanoke, Virginia
Opinion on Internal Control over Financial Reporting
We have audited RGC Resources, Inc. and Subsidiaries (“the Company's”)’internal control over financial reporting as of September 30,
2018, based on criteria established in Internal Control-Integrated Framework - 2013 issued by the Committee of Sponsoring Organizations
of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over
financial reporting as of September 30, 2018, based on criteria established in Internal Control-Integrated Framework - 2013 issued by
COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB),
the consolidated balance sheets and the related consolidated statements of income, comprehensive income, stockholders' equity, and cash
flows of the Company, and our report dated December 3, 2018, expressed an unqualified opinion.
Basis for Opinion
The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of
the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control
over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based
on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company
in accordance with the U.S. federal securities laws and applicable rules and regulations of the Securities and Exchange Commission and
the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our
audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing
the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on
the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.
Definition and Limitation of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting
principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide
reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally
accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations
of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections
of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in
conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Blacksburg, Virginia
December 3, 2018
CERTIFIED PUBLIC ACCOUNTANTS
69
Item 9B.
Other Information.
None
70
Item 10.
Directors, Executive Officers and Corporate Governance.
PART III
For information with respect to the executive officers of the registrant, see “Executive Officers" section in the Proxy
Statement for the 2019 Annual Meeting of Shareholders of Resources incorporated herein by reference. For information
with respect to the Company’s directors and nominees and the Company’s Audit Committee, see Proposal 1 “Election
of Directors of Resources” and “Report of the Audit Committee”, respectively, in the Proxy Statement for the 2019
Annual Meeting of Shareholders of Resources, which information is incorporated herein by reference. In addition, the
Board of Directors has determined that Abney S. Boxley, III and Raymond D. Smoot, Jr. are audit committee financial
experts under applicable SEC rules.
For information regarding the process for identifying and evaluating candidates to be nominated as directors, see
"Director Nominations" in the Proxy Statement for the 2019 Annual Meeting of Shareholders of Resources, which is
incorporated herein by reference.
Information with respect to compliance with Section 16(a) of the Exchange Act, which is set forth under the caption
"Section 16 (a) Beneficial Ownership Reporting Compliance" in the Proxy Statement for the 2019 Annual Meeting of
Shareholders of Resources, is incorporated herein by reference.
The Company has adopted a Code of Ethics applicable to all of its officers, directors and employees. The Company has
posted the text of its Code of Ethics on its website at www.rgcresources.com. The Board of Directors has adopted
charters for the Audit, Compensation, and Corporate Governance and Nominating Committees of the Board of
Directors. These documents may also be found on the Company’s website at www.rgcresources.com.
Item 11.
Executive Compensation.
The information set forth under "Compensation of Directors", "Compensation Discussion and Analysis" and "Report of
the Compensation Committee" in the Proxy Statement for the 2019 Annual Meeting of Shareholders of Resources is
incorporated herein by reference.
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
For information pertaining to securities authorized for issuance under equity compensation plans, see Part II, Item 5
above.
The information pertaining to shareholders beneficially owning more than five percent of the registrant’s common stock
and the security ownership of management, which is set forth under the caption “Security Ownership of Certain
Beneficial Owners and Management" in the Proxy Statement for the 2019 Annual Meeting of Shareholders of
Resources, is incorporated herein by reference.
Item 13.
Certain Relationships and Related Transactions, and Director Independence.
The information pertaining to director independence is set forth under the caption “Board of Directors and Committees
of the Board of Directors” and pertaining to transactions with related persons is set forth under the caption
"Transactions with Related Persons" in the Proxy Statement for the 2019 Annual Meeting of Shareholders of
Resources, which information is incorporated herein by reference.
Item 14.
Principal Accounting Fees and Services.
The information set forth under the caption "Report of the Audit Committee" in the Proxy Statement for the 2019
Annual Meeting of Shareholders of Resources is incorporated herein by reference.
71
Item 15.
Exhibits and Financial Statement Schedules.
(a)
List of documents filed as part of this report:
PART IV
1.
2.
Financial statements filed as part of this report:
All financial statements of the registrant as set forth under Item 8 of this Report on Form 10-K.
Financial statement schedules filed as part of this report:
All information is inapplicable or presented in the consolidated financial statements or related notes
thereto.
3.
Exhibits to this Form 10-K filed as part of this report:
13
21
23
31.1
31.2
32.1*
32.2*
101
Annual Report
Subsidiaries of the Company
Consent of Brown, Edwards & Company, LLP
Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer
Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer
Section 1350 Certification of Principal Executive Officer
Section 1350 Certification of Principal Financial Officer
The following documents from the Registrant’s Annual Report on Form 10-K for the years ended
September 30, 2018, 2017 and 2016, formatted in XBRL (eXtensible Business Reporting Language);
Consolidated Balance Sheets at September 30, 2018 and 2017, (ii) Consolidated Statements of Income for
the years ended September 30, 2018, 2017 and 2016, (iii) Consolidated Statements of Comprehensive
Income for the years ended September 30, 2018, 2017 and 2016, (iv) Consolidated Statements of
Stockholders’ Equity for the years ended September 30, 2018, 2017 and 2016, (v) Consolidated Statements
of Cash Flows for the years ended September 30, 2018, 2017 and 2016, and (vi) Notes to Consolidated
Financial Statements.
*
These certifications are being furnished solely to accompany this annual report pursuant to 18 U.S.C. Section 1350, and
are not being filed for purposes of Section 18 of the Securities Exchange Act of 1934 and are not to be incorporated by
reference into any filing of the registrant, whether made before or after the date hereof, regardless of any general
incorporation language in such filing.
Item 16.
Form 10-K Summary.
Not applicable.
72
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this
Annual Report on Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized.
SIGNATURES
RGC RESOURCES, INC.
By:
/S/ PAUL W. NESTER
Paul W. Nester
Vice President, Secretary, Treasurer and CFO
(principal accounting and financial officer)
December 3, 2018
Date
73
Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report on Form 10-K has been signed below
by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
/S/ JOHN S. D'ORAZIO
December 3, 2018
John S. D'Orazio
Date
President and Chief Executive
Officer, Director
/S/ PAUL W. NESTER
December 3, 2018
Paul W. Nester
Date
Vice President, Treasurer and CFO
(principal accounting and financial
officer)
/S/ JOHN B. WILLIAMSON, III
December 3, 2018
Chairman of the Board and Director
John B. Williamson, III
Date
/S/ NANCY H. AGEE
December 3, 2018
Director
Nancy H. Agee
Date
/S/ ABNEY S. BOXLEY, III
December 3, 2018
Director
Abney S. Boxley, III
Date
/S/ T. JOE CRAWFORD
T. Joe Crawford
December 3, 2018
Director
Date
/S/ MARYELLEN F. GOODLATTE
December 3, 2018
Director
Maryellen F. Goodlatte
Date
/S/ J. ALLEN LAYMAN
J. Allen Layman
December 3, 2018
Director
Date
/S/ S. FRANK SMITH
S. Frank Smith
December 3, 2018
Director
Date
/S/ RAYMOND D. SMOOT, JR.
December 3, 2018
Director
Raymond D. Smoot, Jr.
Date
74
Exhibit No.
3 (a)
3 (b)
4 (a)
4 (b)
4 (c)
10 (a)
10 (b)
10 (c)
10 (d)
10 (e)
10 (f)
10 (g)
10 (h)
10 (i)
10 (j)
EXHIBIT INDEX
Description
Articles of Incorporation of RGC Resources, Inc. (incorporated herein by reference to Exhibit 3(a)
of Registration Statement No. 33-67311, on Form S-4, filed with the Commission on November 13,
1998, and amended by Amendment No. 5, filed with the Commission on January 28, 1999)
Amended and Restated Bylaws of RGC Resources, Inc. (incorporated herein by reference to Exhibit
3(b) on the Form 8-K filed on February 7, 2014)
Specimen copy of certificate for RGC Resources, Inc. common stock, $5.00 par value (incorporated
herein by reference to Exhibit 3(b) of Registration Statement No. 33-67311, on Form S-4, filed with
the Commission on November 13, 1998, and amended by Amendment No. 5, filed with the
Commission on January 28, 1999)
RGC Resources, Inc., Amended and Restated Dividend Reinvestment and Stock Purchase Plan
(incorporated by reference to Exhibit 4(b) of the Form 10-K for the year ended September 30, 2014)
Description of RGC Resources, Inc. Common Stock (incorporated by reference to Exhibit 99.1 on
Form 8-K as filed on August 10, 2017)
P Firm Transportation Agreement between East Tennessee Natural Gas Company and Roanoke Gas
Company dated November 1, 1993 (incorporated herein by reference to Exhibit 10(a) of the Annual
Report on Form 10-K for the fiscal year ended September 30, 1994 (SEC file number reference
0-367))
NTS Service Agreement between Columbia Gas Transmission Corporation and Roanoke Gas
Company dated September 3, 2004 (incorporated herein by reference to Exhibit 10(g)(g)(g) of the
Quarterly Report on Form 10-Q for the period ended December 31, 2004)
FSS Service Agreement between Columbia Gas Transmission Corporation and Roanoke Gas
Company dated September 3, 2004 (incorporated herein by reference to Exhibit 10(h)(h)(h) of the
Quarterly Report Form 10-Q for the period ended December 31, 2004)
FTS Service Agreement between Columbia Gas Transmission Corporation and Roanoke Gas
Company dated September 3, 2004 (incorporated herein by reference to Exhibit 10(i)(i)(i) of the
Quarterly Report on Form 10-Q for the period ended December 31, 2004)
SST Service Agreement between Columbia Gas Transmission Corporation and Roanoke Gas
Company dated September 3, 2004 (incorporated herein by reference to Exhibit 10(j)(j)(j) of the
Quarterly Report on Form 10-Q for the period ended December 31, 2004)
FTS Service Agreement effective April 1, 2017 between Columbia Gas Transmission LLC and
Roanoke Gas Company (incorporated herein by reference to Exhibit 10(f) of the Annual Report on
Form 10-K as filed December 8, 2017)
FTS-1 Service Agreement between Columbia Gulf Transmission Corporation and Roanoke Gas
Company dated September 3, 2004 (incorporated herein by reference to Exhibit 10(k)(k)(k) of the
Quarterly Report on Form 10-Q for period ended December 31, 2004)
P Gas Transportation Agreement, for use under FT-A rate schedule, between Tennessee Gas Pipeline
Company and Roanoke Gas Company dated November 1, 1993 (incorporated herein by reference to
Exhibit 10(k) of the Annual Report on Form 10-K for the fiscal year ended September 30, 1994
(SEC file number reference 0-367))
P Gas Transportation Agreement, for use under IT rate schedule, between Tennessee Gas Pipeline
Company and Roanoke Gas Company dated September 1, 1993 (incorporated herein by reference to
Exhibit 10(l) of the Annual Report on Form 10-K for the fiscal year ended September 30, 1994
(SEC file number reference 0-367))
P Gas Storage Contract under rate schedule FS (Market Area) Portland between Tennessee Gas
Pipeline Company and Roanoke Gas Company dated November 1, 1993 (incorporated herein by
reference to Exhibit 10(k)(k) of the Annual Report on Form 10-K for the fiscal year ended
September 30, 1994 (SEC file number reference 0-367))
10 (k)
10 (l)
10 (m)
10 (n)
10(o)
10 (p)
10 (q)
10 (r)
10 (s)
10 (t)
10 (u)
10 (v)
10 (w)
10 (x)
FTA Gas Transportation Agreement effective November 1, 1998, between East Tennessee Natural
Gas Company and Roanoke Gas Company (incorporated herein by reference to Exhibit 10(s)(s) of
Annual Report on Form 10-K for the fiscal year ended September 30, 1998 (SEC file reference
number 0-367))
FTS Service Agreement effective November 1, 1999, between Columbia Gas Transmission
Corporation and Roanoke Gas Company (incorporated herein by reference to Exhibit 10(p)(p) of
Annual Report on Form 10-K for the fiscal year ended September 30, 2001 (SEC file reference
number 0-367))
Firm Storage Service Agreement effective March 19, 1997, between Virginia Gas Storage Company
and Roanoke Gas Company (incorporated herein by reference to Exhibit 10(w)(w) of Annual
Report on Form 10-K for the fiscal year ended September 30, 1998 (SEC file reference number
0-367))
Firm Storage Service Agreement by and between Roanoke Gas Company and Virginia Gas Pipeline
Company, dated June 1, 2001 (incorporated herein by reference to Exhibit 10(b)(b)(b) of Annual
Report on Form 10-K for the fiscal year ended September 30, 2001 (SEC file number reference
0-367))
FSS Service Agreement between Saltville Gas Storage Company L.L.C. and Roanoke Gas
Company dated November 21, 2012 (incorporated herein by reference to Exhibit 10(o) of the
Annual Report on Form 10-K as filed December 8, 2017)
Firm Pipeline Service Agreement by and between Roanoke Gas Company and Virginia Gas Pipeline
Company, dated June 1, 2001 (incorporated herein by reference to Exhibit 10(c)(c)(c) of Annual
Report on Form 10-K for the fiscal year ended September 30, 2001 (SEC file number reference
0-367))
Natural Gas Asset Management Agreement by and between Roanoke Gas Company and Sequent
Energy Management LP effective April 1, 2018 (incorporated herein by reference to Exhibit 10.1 on
Form 8-K as filed on March 27, 2018)
Parental Guaranty by RGC Resources, Inc. in favor of Sequent Energy Management LP effective
April 1, 2018 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed on March 27,
2018)
Gas Transportation Agreement between Tennessee Gas Pipeline Company and Roanoke Gas
Company originally dated November 1, 1999 as amended May 17, 2016 (incorporated herein by
reference to Exhibit 10.3 of Form 10-Q as filed August 4, 2016)
Amendment dated May 17, 2016 to Gas Transportation Agreement originally dated December 1,
1993 between Tennessee Gas Pipeline Company and Roanoke Gas Company (incorporated herein
by reference to Exhibit 10.1 of Form 10-Q as filed August 4, 2016)
Amendment dated May 17, 2016 to Gas Transportation Agreement originally dated November 1,
1993 between Tennessee Gas Pipeline Company and Roanoke Gas Company (incorporated herein
by reference to Exhibit 10.2 of Form 10-Q as filed August 4, 2016)
P Certificate of Public Convenience and Necessity for Bedford County dated February 21, 1966
(incorporated herein by reference to Exhibit 10(o) of Registration Statement No. 33-36605, on Form
S-2, filed with the Commission on August 29, 1990, and amended by Amendment No. 1, filed with
the Commission on September 19, 1990)
P Certificate of Public Convenience and Necessity for Roanoke County dated October 19, 1965
(incorporated herein by reference to Exhibit 10(p) of Registration Statement No. 33-36605, on Form
S-2, filed with the Commission on August 29, 1990, and amended by Amendment No. 1, filed with
the Commission on September 19, 1990)
P Certificate of Public Convenience and Necessity for Botetourt County dated August 30, 1966
(incorporated herein by reference to Exhibit 10(q) of Registration Statement No. 33-36605, on Form
S-2, filed with the Commission on August 29, 1990, and amended by Amendment No. 1, filed with
the Commission on September 19, 1990)
10 (y)
10 (z)
10 (a)(a)
P Certificate of Public Convenience and Necessity for Montgomery County dated July 8, 1985
(incorporated herein by reference to Exhibit 10(r) of Registration Statement No. 33-36605, on Form
S-2, filed with the Commission on August 29, 1990, and amended by Amendment No. 1, filed with
the Commission on September 19, 1990)
P Certificate of Public Convenience and Necessity for Franklin County dated September 8, 1964
(incorporated herein by reference to Exhibit 10(t) of Registration Statement No. 33-36605, on Form
S-2, filed with the Commission on August 29, 1990, and amended by Amendment No. 1, filed with
the Commission on September 19, 1990)
P Resolution of the Council for the Town of Fincastle, Virginia dated June 8, 1970 (incorporated
herein by reference to Exhibit 10(f) of Registration Statement No. 33-11383, on Form S-4, filed
with the Commission on January 16, 1987)
10 (b)(b)
P Resolution of the Council for the Town of Troutville, Virginia dated November 4, 1968
(incorporated herein by reference to Exhibit 10(g) of Registration Statement No. 33-11383, on Form
S-4, filed with the Commission on January 16, 1987)
10 (c)(c)
10 (d)(d)
10 (e)(e)
10 (f)(f)
10 (g)(g)
10 (h)(h)
10 (i)(i)
10 (j)(j)
10 (k)(k)
10 (l)(l)
10 (m)(m)
10 (n)(n)
10 (o)(o)
Gas Franchise Agreement between the City of Roanoke, Virginia, and Roanoke Gas Company dated
December 14, 2015 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed
December 16, 2015)
Gas Franchise Agreement between the City of Salem, Virginia, and Roanoke Gas Company dated
December 14, 2015 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed
December 16, 2015)
Gas Franchise Agreement between the Town of Vinton, Virginia, and Roanoke Gas Company dated
November 17, 2015 (incorporated herein by reference to Exhibit 10.3 on Form 8-K as filed
December 16, 2015)
RGC Resources Amended and Restated Key Employee Stock Option Plan (incorporated herein by
reference to Exhibit 4(c) of Registration Statement No. 333-02455, Post Effective Amendment on
Form S-8, filed with the Commission on July 2, 1999)
RGC Resources, Inc. Amended and Restated Stock Bonus Plan (incorporated herein by reference to
Exhibit 10 on Form 8-K filed on January 27, 2005 (SEC file reference number 0-367))
RGC Resources, Inc. Amended And Restated Restricted Stock Plan for Outside Directors
(incorporated herein by reference to Exhibit 10(i)(i) to the Annual Report on Form 10-K as filed
December 8, 2017)
RGC Resources, Inc. Restricted Stock Plan (incorporated herein by reference to Exhibit 10.1 of
Form 8-K as filed February 9, 2017)
Change in Control Agreement between RGC Resources, Inc. and Mr. John S. D'Orazio effective
May 1, 2018 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed May 1, 2018)
Change in Control Agreement between RGC Resources, Inc. and Mr. Paul W. Nester effective May
1, 2018 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed May 1, 2018)
Change in Control Agreement between RGC Resources, Inc. and Mr. Robert L. Wells, II effective
May 1, 2018 (incorporated herein by reference to Exhibit 10.3 on Form 8-K as filed May 1, 2018)
Change in Control Agreement between RGC Resources, Inc. and Mr. Carl J. Shockley effective
May 1, 2018 (incorporated herein by reference to Exhibit 10.4 on Form 8-K as filed May 1, 2018)
Revolving Line of Credit Note in the original principal amount of $25,000,000 by Roanoke Gas
Company in favor of Wells Fargo Bank, N.A. dated as of March 26, 2018 (incorporated herein by
reference to Exhibit 10.1 on Form 8-K as filed March 27, 2018)
Credit Agreement by and between Roanoke Gas Company and Wells Fargo Bank, N.A. dated
March 31, 2016 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed April 4,
2016)
10 (p)(p)
10 (q)(q)
10 (r)(r)
10 (s)(s)
10 (t)(t)
10 (u)(u)
10 (v)(v)
10 (w)(w)
10 (x)(x)
10 (y)(y)
10 (z)(z)
10 (a)(a)(a)
10 (b)(b)(b)
10 (c)(c)(c)
10 (d)(d)(d)
10 (e)(e)(e)
First Amendment to Credit Agreement by and between Roanoke Gas Company and Wells Fargo
Bank, N.A. dated March 27, 2017 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as
filed March 29, 2017)
Second Amendment to Credit Agreement by and between Roanoke Gas Company and Wells Fargo
Bank, N.A. dated as of March 26, 2018 (incorporated herein by reference to Exhibit 10.2 on Form
8-K as filed March 27, 2018)
Continuing Guaranty by RGC Resources, Inc. in favor of Wells Fargo Bank, N.A. dated March 31,
2016 (incorporated by reference to Exhibit 10.3 on Form 8-K as filed April 4, 2016)
Indemnification and Cost Sharing Agreement by and between RGC Resources, Inc., Bluefield Gas
Company and ANGD, LLC (incorporated herein by reference to Exhibit 10.2 on Form 10-K as filed
December 21, 2007 (SEC file number reference 0-367))
Note Purchase Agreement for 4.26% Senior Guaranteed Notes due September 18, 2034 in the
original principal amount of $30,500,000 in favor of The Prudential Insurance Company of
America, PAR U Hartford Life & Annuity Comfort Trust and PRUCO Life Insurance Company of
New Jersey (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed August 4, 2014)
Unconditional Parent Guaranty by RGC Resources, Inc. in favor of each of the olders of the notes:
The Prudential Life Insurance Company of America, PAR U Hartford Life & Annuity Comfort
Trust and PRUCO Life Insurance Company of New Jersey (incorporated herein by reference to
Exhibit 10.2 on Form 8-K as filed August 4, 2014)
4.26% Senior Guaranteed Notes due September 18, 2034 in the original principal amount of
$15,250,000 in favor of The Prudential Insurance Company of America (incorporated herein by
reference to Exhibit 10.1 on Form 8-K as filed September 23, 2014)
4.26% Senior Guaranteed Notes due September 18, 2034 in the original principal amount of
$9,700,000 in favor of PAR U Hartford Life & Annuity Comfort Trust (incorporated herein by
reference to Exhibit 10.2 on Form 8-K as filed September 23, 2014)
4.26% Senior Guaranteed Notes due September 18, 2034 in the original principal amount of
$5,550,000 in favor of PRUCO Life Insurance Company of New Jersey (incorporated herein by
reference to Exhibit 10.3 on Form 8-K as filed September 23, 2014)
ISDA Master Agreement by and between Roanoke Gas Company and Branch Bank and Trust dated
as of October 27, 2008 (incorporated herein by reference to Exhibit 10.3 on Form 8-K as filed
November 5, 2008 (SEC file number reference 0-367))
Credit Agreement between RGC Midstream, LLC, Union Bank & Trust and Branch Banking and
Trust Company dated December 29, 2015 (incorporated by reference to Exhibit 10.1 on Form 8-K
as filed December 31, 2015)
First Amendment to Credit Agreement between RGC Midstream, LLC and the lenders Union Bank
& Trust and Branch Banking and Trust dated April 11, 2018 (incorporated herein by reference to
Exhibit 10.1 on Form 8-K as filed April 12, 2018)
Amended and Restated Note in the principal amount of $22,800,000 in favor of Union Bank &
Trust due December 29, 2020 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as
filed April 12, 2018)
Amended and Restated Note in the principal amount of $15,200,000 in favor of Branch Banking
and Trust due December 29, 2020 (incorporated herein by reference to Exhibit 10.3 on Form 8-K as
filed April 12, 2018)
Guaranty by RGC Resources, Inc. in favor of Union Bank & Trust and Branch Banking and Trust
Company dated December 29, 2015 (incorporated herein by reference to Exhibit 10.4 on Form 8-K
as filed December 31, 2015)
Term Loan Agreement dated November 1, 2016 in favor of Branch Banking and Trust Company
dated November 1, 2016 (incorporated by reference to Exhibit 10.1 on Form 8-K as filed November
7, 2016)
10 (f)(f)(f)
10 (g)(g)(g)
10 (h)(h)(h)
10 (i)(i)(i)
10 (j)(j)(j)
10 (k)(k)(k)
10 (l)(l)(l)
10 (m)(m)
(m)
**
10 (n)(n)(n)
13
21
23
31.1
31.2
32.1*
32.2*
101
Promissory Note dated November 1, 2016 in the principle amount of $7,000,000 in favor of Branch
Banking and Trust Company due November 1, 2021 (incorporated by reference to Exhibit 10.2 on
Form 8-K as filed November 7, 2016)
Guaranty Agreement between RGC Resources, Inc. and Branch Banking and Trust Company on
behalf of Roanoke Gas Company dated November 1, 2016 (incorporated herein by reference to
Exhibit 10.3 on Form 8-K as filed November 7, 2016)
Swap Agreement by and between Roanoke Gas Company and Branch Banking and Trust Company
dated November 1, 2016 (incorporated herein by reference to Exhibit 10.4 on Form 8-K as filed
November 7, 2016)
Private Shelf Agreement by and between Roanoke Gas Company and Prudential Investment
Management, Inc. for the pre-authorization to issue notes up to $29,500,000 in total during the term
of the agreement (incorporated herein by reference to Exhibit 10.4 on Form 8-K as filed October 4,
2017)
Unsecured Note in the original principal amount of $4,000,000 by and between Roanoke Gas
Company and PRUCO Life Insurance Company of New Jersey, dated October 2, 2017
(incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed October 4, 2017)
Unsecured Note in the original principal amount of $4,000,000 by and between Roanoke Gas
Company and Prudential Arizona Reinsurance Captive Company, dated October 2, 2017
(incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed October 4, 2017)
Unconditional Parent Guaranty by RGC Resources, Inc. in favor of each of the olders of the notes:
The PRUCO Life Insurance Company of New Jersey and the Prudential Arizona Reinsurance
Captive Company (incorporated herein by reference to Exhibit 10.3 on Form 8-K as filed October 4,
2017)
Third Amended and Restated Limited Liability Company Agreement of Mountain Valley Pipeline,
LLC dated April 6, 2018 (incorporated by reference to Exhibit 10.1 on the Quarterly Report on
Form 10-Q as filed May 7, 2018)
Guaranty Agreement by RGC Resources, Inc. in favor of Mountain Valley Pipeline, LLC
(incorporated herein by reference to Exhibit 10.2 on Form 10-Q as filed May 7, 2018)
Annual Report
Subsidiaries of the Company
Consent of Brown, Edwards & Company, LLP
Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer
Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer
Section 1350 Certification of Principal Executive Officer
Section 1350 Certification of Principal Financial Officer
The following documents from the Registrant’s Annual Report on Form 10-K for the years ended
September 30, 2018, 2017 and 2016, formatted in XBRL (eXtensible Business Reporting
Language); Consolidated Balance Sheets at September 30, 2018 and 2017, (ii) Consolidated
Statements of Income for the years ended September 30, 2018, 2017 and 2016, (iii) Consolidated
Statements of Comprehensive Income for the years ended September 30, 2018. 2017 and 2016, (iv)
Consolidated Statements of Stockholders’ Equity for the years ended September 30, 2018, 2017 and
2016, (v) Consolidated Statements of Cash Flows for the years ended September 30, 2018, 2017
and 2016, and (vi) Notes to Consolidated Financial Statements.
*
These certifications are being furnished solely to accompany this annual report pursuant to 18 U.S.C. Section 1350, and
are not being filed for purposes of Section 18 of the Securities Exchange Act of 1934 and are not to be incorporated by
reference into any filing of the registrant, whether made before or after the date hereof, regardless of any general
incorporation language in such filing.
**
Confidential treatment has been granted with respect to portions of this exhibit, indicated by asterisks, which has been
filed separately with the Securities and Exchange Commission.
P
These original exhibits were filed with the SEC in paper form and therefore are not hyper-linked to the original filing.
RGC Resources, Inc.
Subsidiaries of Registrant
Exhibit 21
Roanoke Gas Company
Diversified Energy Company
RGC Midstream, LLC
Exhibit 23
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in Registration Statement No. 333-218966 on Form S-8, Registration
Statement No. 333-187529 on Form S-8, Registration Statement No. 333-178136 on Form S-8, Registration Statement
No. 333-122746 on Form S-8, Registration Statement No. 333-219876 on Form S-3, Registration Statement
No. 333-122742 on Form S-3 of RGC Resources, Inc. of our report dated December 3, 2018 appearing in this Annual
Report on Form 10-K of RGC Resources, Inc. for the year ended September 30, 2018.
Blacksburg, Virginia
December 3, 2018
CERTIFIED PUBLIC ACCOUNTANTS
Exhibit 31.1
I, John S. D'Orazio, certify that:
CERTIFICATION
1.
2.
3.
4.
I have reviewed this annual report on Form 10-K of RGC Resources, Inc.;
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and
for, the periods presented in this report;
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting
(as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a)
(b)
(c)
(d)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period
in which this report is being prepared;
Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external purposes in accordance with
generally accepted accounting principles;
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report
our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation; and
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred
during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual
report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control
over financial reporting; and
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control
over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or
persons performing the equivalent functions):
(a)
(b)
All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process,
summarize and report financial information; and
Any fraud, whether or not material, that involves management or other employees who have a significant role
in the registrant’s internal control over financial reporting.
Date: December 3, 2018
/s/ John S. D'Orazio
President and Chief Executive Officer
Exhibit 31.2
I, Paul W. Nester, certify that:
CERTIFICATION
1.
2.
3.
4.
I have reviewed this annual report on Form 10-K of RGC Resources, Inc.;
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and
for, the periods presented in this report;
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting
(as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a)
(b)
(c)
(d)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period
in which this report is being prepared;
Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external purposes in accordance with
generally accepted accounting principles;
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report
our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation; and
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred
during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual
report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control
over financial reporting; and
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control
over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or
persons performing the equivalent functions):
(a)
(b)
All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process,
summarize and report financial information; and
Any fraud, whether or not material, that involves management or other employees who have a significant role
in the registrant’s internal control over financial reporting.
Date: December 3, 2018
/s/ Paul W. Nester
Vice-President, Secretary,Treasurer and
CFO
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
Exhibit 32.1
In connection with the Annual Report of RGC Resources, Inc. (the “Company”) on Form 10-K for the period ended
September 30, 2018 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John S.
D'Orazio, President and Chief Executive Officer of the Company, certify to my knowledge, pursuant to 18 U.S.C. § 1350, as
adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:
(1)
(2)
The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of
1934; and
The information contained in the Report fairly presents, in all material respects, the financial condition and
result of operations of the Company.
/s/ John S. D'Orazio
John S. D'Orazio
President and Chief Executive Officer
December 3, 2018
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
Exhibit 32.2
In connection with the Annual Report of RGC Resources, Inc. (the “Company”) on Form 10-K for the period ended
September 30, 2018 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Paul W. Nester,
Vice-President, Secretary, Treasurer and CFO of the Company, certify to my knowledge, pursuant to 18 U.S.C. § 1350, as
adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:
(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of
operations of the Company.
/s/ Paul W. Nester
Paul W. Nester
Vice-President, Secretary,
Treasurer and CFO
December 3, 2018
CORPORATE INFORMATION
Board of
Directors
Nancy Howell Agee
President & CEO, Carilion Clinic
Abney S. Boxley, III
President – East Region, Summit Materials
T. Joe Crawford
Vice President & General Manager, Steel Dynamics Roanoke Bar Division
John S. D’Orazio
President & CEO, RGC Resources, Inc.
Maryellen F. Goodlatte
Attorney & Principal, Glenn, Feldmann, Darby & Goodlatte
J. Allen Layman
Private Investor & Retired Utility Executive
S. Frank Smith
Private Investor & Retired Energy Industry Executive
Raymond D. Smoot, Jr.
Chairman, Union Bankshares Corporation
John B. Williamson, III
Chairman of the Board
DIVIDEND REINVESTMENT AND STOCK
PURCHASE PLAN INQUIRIES
Through the Company’s Dividend Reinvestment
and Stock Purchase Plan, shareholders of record
are offered a convenient way to acquire and
reinvest cash dividends in additional shares of the
Company’s common stock and avoid commissions
or other charges. Additionally, shareholders are
given on‐line access to make transfers, consolidate
accounts, replace stock certificates and dividend
payments, set‐up direct deposit, update personal
information and much more. Broadridge Corporate
Issuer Solutions administers the plan and is the
agent
for participants. For more information,
inquiries may be directed to RGC Resources, Inc.,
Shareholder Information Services, P.O. Box 13007,
Roanoke, VA 24030, (540) 777‐3853.
ANNUAL REPORT AND 10‐K
This annual report, 10‐K and the financial
statements contained herein are submitted
to the shareholders of the Company for their
general information and not in connection
with any sale or offer to sell, or solicitation
of any offer to buy, any securities.
ANNUAL MEETING
The annual meeting of shareholders of the
Company will be held at The Hotel Roanoke
and Conference Center, 110 Shenandoah
Avenue, Roanoke, Virginia,
on
Monday, February 4, 2019, at 9:00 a.m.
Proxies for
the annual meeting will be
requested from shareholders when notice of
meeting, proxy statement and form of proxy
are mailed on or about December 14, 2018.
24016
519 Kimball Avenue, NE
P.O. Box 13007
Roanoke, Virginia 24030‐3007
www.rgcresources.com
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Trading on NASDAQ as RGCO