2017 Annual Report
PRESIDENT’S LETTER
To Our Shareholders:
The past year has been exciting for our Company. We experienced our third consecutive year of record
In January, the Board of
earnings at $6.2 million, or $0.86 per share, an increase of 7% over 2016.
Directors approved a 3‐for‐2 stock dividend payable March 1, 2017, and in June, RGC Resources was
added to the Russell 2000 for the first time in our history. Our market capitalization also increased
from approximately $120 million to over $190 million in 2017. Building on this success, our Board
approved a 6.9% dividend increase to $0.62 per share. The February 2018 dividend will reflect 73
years of continuous quarterly dividend payments and 14 consecutive years of annual dividend
increases.
In late 2017, Roanoke Gas Company capped off a 25‐year project replacing the last of the bare steel
and cast iron mains in its natural gas distribution system. We also completed the largest single capital
project in the Company’s history, a $6 million automated meter reading (AMR) installation. This
modern technology platform will provide more real‐time data and reduce costs.
Roanoke Gas continues to experience consistent customer growth. Several large industrial customers
have either opened new facilities or expanded and modernized existing facilities. Looking forward, we
anticipate continued large commercial customer growth as economic development in the Roanoke
Valley is strong. We also added approximately 620 new residential and small commercial customers in
2017. We believe these trends will continue.
In 2017, we invested $20.7 million,
We continue to invest in capital improvements for Roanoke Gas.
the largest annual amount in Roanoke Gas history.
In addition to supporting customer growth and
implementing AMR, we replaced 9 miles of first generation plastic mains. We anticipate the first
generation plastic main replacement project to take approximately 3 to 4 years to complete.
In
addition to this project, our plans for 2018 include the renewal of one major gate station and several
large main extension projects.
The Mountain Valley Pipeline (MVP) project received its FERC certificate in October and is planning to
begin construction in early 2018. The MVP will address the growing demand for natural gas in our
region, add an additional source of gas to the Roanoke Gas supply portfolio and provide the Company
with the opportunity to expand natural gas service to Franklin County, Virginia, a previously unserved
area. This strategic investment complements our core business and continues to enhance shareholder
value.
Finally, Mr. George Logan is retiring after 15 years of service to our Board of Directors. A corporate
governance expert with vast business and academic experience, Mr. Logan made significant
contributions to the Company’s growth and success during his tenure.
On behalf of our Board of Directors and employees, thank you for your continued interest in our
Company and for your ongoing decision to invest in RGC Resources.
John S. D’Orazio
President & Chief Executive Officer
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, 2017
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, or a
smaller reporting company. See definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in
Rule 12b-2 of the Exchange Act. (Check one).
Large accelerated filer
Accelerated filer
Non-accelerated filer
(Do not check if smaller reporting company)
Smaller reporting company
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, 2017. $147,136,528
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 30, 2017
7,250,093 SHARES
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the RGC Resources, Inc. Proxy Statement for the 2018 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
10
10
11
13
13
29
29
64
64
66
67
67
67
67
67
68
68
69
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. Mountain Valley Pipeline, LLC was created for the purpose
of constructing a natural gas pipeline in West Virginia and Virginia. 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.
In March 2016, Resources dissolved its subsidiary, RGC Ventures of Virginia, Inc. ("Ventures"). Ventures contained the
operations of Application Resources, Inc., which provided information technology consulting services, and The Utility
Consultants, which provided utility and regulatory consulting services to other utilities. Both of these operations were
insignificant when compared to the overall activities of Resources and represented less than 0.2% of total revenues and
less than 6% of other non-utility revenues.
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:
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
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
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
3
Residential
Commercial
Industrial
Other Utility
Other Non-Utility
Total Percent
Total Value
Customers
Volume
Revenue
Margin
2015
91.2%
8.7%
0.1%
0.0%
0.0%
100.0%
59,080
40%
30%
30%
0%
0%
100%
58%
33%
6%
1%
2%
100%
58%
26%
11%
3%
2%
100%
9,875,007
$
68,189,607
$
30,206,433
Roanoke Gas’ regulated natural gas distribution business accounted for approximately 98% of Resources total revenues
for fiscal years ending September 30, 2017, 2016 and 2015. The tables above indicates that residential customers
represent over 91% of the Company’s customer total; however, they represent less than 50% of the total gas volumes
delivered and more than half of the Company’s consolidated revenues and margin. Industrial customers include
primarily transportation customers that purchase their natural gas requirements directly from a supplier other than the
Company and utilize Roanoke Gas’ natural gas distribution system for delivery to their operations. Most of the revenue
billed for these customers relates only to transportation service, and not to the purchase of natural gas, causing total
revenues generated by these deliveries to be approximately 7% of total revenues, even though they represent 32% of
total natural gas deliveries for the year ended September 30, 2017 and approximately 10% to 11% of gross 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
further detail in Note 1 of the Company’s annual consolidated financial statements. Significant increases in gas costs
may cause customers to conserve or, in the case of industrial customers, to switch to alternative energy sources.
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, 2017, approximately
65% of the Company’s total DTH of natural gas deliveries and 73% of the residential and commercial deliveries were
made in the five-month period of November through March. These percentages are comparable to the prior year but
lower than fiscal 2015 due to lower volumes attributable to a much warmer heating season in fiscal 2016 and 2017.
Total natural gas deliveries were 8.6 million DTH, 8.8 million DTH and 9.9 million DTH in fiscal 2017, 2016 and 2015,
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 approximately 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 2018 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 for delivery
into Roanoke Gas’ distribution system under the interstate pipelines is 78,606 DTH per day. The LNG facility, which is
capable of storing up to 200,000 DTH of natural gas in a liquid state for use during peak demand, has the capability of
providing an additional 27,000 DTH per day. Combined, the pipelines and LNG facility can provide more than 105,000
DTH on a single winter day.
4
The Company uses multi-year contracts to meet its natural gas supply needs. The Company currently contracts with
Sequent Energy Management, L.P. to manage its pipeline transportation, storage rights, gas supply inventories and
deliveries and serve as the primary supplier of natural gas for Roanoke Gas. Natural gas purchased under the asset
management agreement is priced at indexed-based market prices as reported in major industry pricing publications. The
Company is currently in the process of soliciting proposals for a new asset management agreement to replace the
current agreement which expires March 31, 2018.
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 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.
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. Certificates of public convenience and necessity, issued by the Virginia State
Corporation Commission (the “SCC”), are of perpetual duration and subject to compliance with regulatory standards.
Although Roanoke Gas has exclusive rights for the distribution of natural gas in its service area, the Company competes
with suppliers of other forms of energy such as fuel oil, electricity, propane, coal 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. New construction activity has remained steady over the last few
years and the Company continues to grow its customer base through a combination of extending service to 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, 2017, Resources had 106 full-time employees and 109 total employees. As of that date, 30
employees, or 28% of the Company’s full-time employees, belonged to the United Steel, Paper and Forestry, Rubber,
Manufacturing, Energy, Allied-Industrial International Union, Local No. 515 and were represented under a collective
bargaining agreement. The union has been in place at the Company since 1952. The current collective bargaining
agreement will expire on July 31, 2020. Management maintains an amicable relationship with the union.
5
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 and is 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 adequate 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 and, if sufficiently frequent or prolonged, could lead customers to turn to
alternative energy sources.
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 policies with financially sound carriers to protect against many of these risks. 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.
Investment in Mountain Valley Pipeline.
The success of the Company's investment in Mountain Valley Pipeline, LLC (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, the 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.
In addition, there are also numerous risks facing the LLC over time, which in turn could adversely affect the
Company's earnings and financial performance through its 1% investment. The LLC's ability to complete
construction of, and capital improvement to, facilities on schedule and within budget may be adversely affected by
escalating costs for materials and labor and regulatory compliance, inability to obtain or renew necessary licenses,
6
rights-of-way, permits or other approvals on acceptable terms or on schedule, disputes involving contractors, labor
organizations, land owners, governmental entities, environmental groups, Native American and aboriginal groups, and
other third parties, negative publicity, transmission interconnection issues, and other factors. If any development
project or construction or capital improvement project is not completed, is delayed or is subject to cost overruns,
certain associated costs may not be approved for recovery or be recovered through regulatory mechanisms that may
otherwise be available, and the LLC could become obligated to make delay or termination payments or become
obligated for other contractual damages, could 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. Any of these
events could have a material adverse effect on the LLC’s business, financial condition, results of operations and
prospects. The LLC may face risks related to project siting, financing, construction, permitting, governmental
approvals and the negotiation of project development agreements that may impede its development and operating
activities. The LLC must periodically apply for licenses and permits from various local, state, federal and other
regulatory authorities and abide by their respective conditions. Should the LLC be unsuccessful in obtaining necessary
licenses or permits on acceptable terms, should there be a delay in obtaining or renewing necessary licenses or permits
or should regulatory authorities initiate any associated investigations or enforcement actions or impose related
penalties or disallowances on the LLC, the LLC’s business, financial condition, results of operations and prospects
could be materially adversely affected. Any failure to negotiate successful project development agreements for new
facilities with third parties could have similar results.
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 that could result 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.
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 supplies of natural gas. Decreased supplies could result in an
inability to meet customer demand or lead to higher prices or service disruptions. Disasters could also lead to
additional governmental regulations that may limit production activity or increase production and transportation costs.
Security incident or cyber-attacks on the Company’s computer or information systems.
A cyber-security incident on the Company’s information systems could result in corruption of the Company’s financial
information or the unauthorized release of confidential customer, employee or vendor information or result in the
interruption of our ability to provide natural gas to our customer or compromise the safety of our distribution,
transmission and storage systems. The Company takes reasonable precautions to safeguard its computer systems from
attack; however, there are no guarantees that Company processes will adequately protect against unauthorized access
to data. 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 and the attack could also materially
increase the costs we incur 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.
7
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 electric 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 varying weather conditions.
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.
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 gas-fired 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 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 maintain, expand or
upgrade its distribution, transmission and/or storage infrastructure, including new pipeline installation. Various factors
may prevent or delay the completion of such projects or make them more costly, such as the inability to obtain
required approval from local, state and/or federal regulatory and governmental bodies, public opposition to the
projects, inability to obtain adequate financing, competition for labor and materials, construction delays, cost overruns,
and an inability to negotiate acceptable agreements relating to rights-of-way, construction or other material
development components. As a result, the Company may not be able to adequately serve existing customers or expand
its distribution system to support customer growth, including any potential customer growth as a result of the
construction of the MVP, which would negatively impact earnings.
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
8
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.
The combustion of natural gas results in carbon related emissions. 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.
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
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.
Insurance coverage may not be sufficient.
The Company currently has liability and property insurance to cover a variety of exposures and perils. Although
management considers the level of coverage to be appropriate, the insurance policies 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 significantly 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
9
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 Plant” 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 1,135 miles of transmission and distribution pipeline with transmission and distribution plant
representing more than 87% of the total investment in plant. The transmission and distribution pipelines are located on
or under public roads and highways or private property for which the Company has obtained the legal authorization and
rights to operate.
Roanoke Gas 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 Botetourt County that has the capacity to store
up to 220,000 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.
10
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, 2017
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
Year Ending September 30, 2016
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
$
$
Range of Bid Prices
Cash Dividends
High
Low
Declared
$
$
20.04
22.51
31.99
29.95
15.96
15.59
17.33
16.73
$
$
15.81
16.60
21.00
23.65
13.37
13.77
14.30
14.88
0.1450
0.1450
0.1450
0.1450
0.1350
0.1350
0.1350
0.1350
As of November 24, 2017, there were 1,159 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, 2012 through
September 30, 2017 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, 2012 in the Company’s
common stock and in each index as of September 30, 2017, 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 $300 for the Company’s common stock, $180 for the Dow Jones US Utilities Index and $194 for the
S&P 500 Index.
11
A summary of the Company’s equity compensation plans follows as of September 30, 2017:
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))
101,575
—
101,575
$14.31
—
$14.31
576,018
—
576,018
12
Item 6.
Selected Financial Data.
Operating Revenues
Gross Margin
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
Long-Term Debt (Less Unamortized
Debt Expense)
Stockholders' Equity
Shares Outstanding at Sept. 30(1)
Year Ending September 30,
2017
2016
2015
2014
2013
$ 62,296,870
$ 59,063,291
$ 68,189,607
$ 75,016,134
$ 63,205,666
32,809,157
31,564,914
30,206,433
29,337,089
27,602,891
11,666,309
11,212,092
10,006,192
6,232,865
5,806,866
5,094,415
9,681,868
4,708,440
8,795,055
4,262,052
$
$
$
0.86
0.58
8.29
$
$
$
0.81
0.54
7.75
$
$
$
0.72
0.51
7.43
$
$
$
0.67
0.49
7.35
$
$
$
0.60
1.15
7.01
7,218,686
7,149,906
7,092,315
7,073,218
7,048,091
$183,135,071
$165,552,849
$145,847,194
$137,423,321
$121,658,797
$ 61,312,011
$ 33,636,051
$ 30,316,573
$ 30,306,919
$ 12,984,169
60,040,472
55,667,072
52,840,991
52,020,847
49,502,422
7,240,846
7,182,434
7,112,247
7,080,567
7,063,989
(1)Total shares and per share amounts for the prior years were revised to reflect the three-for-two stock split.
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.
13
Overview
Resources is an energy services company primarily engaged in the regulated sale and distribution of natural gas to
approximately 59,800 residential, commercial and industrial customers in Roanoke, Virginia, and the surrounding
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. The Federal Energy Regulatory Commission ("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.
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 managing the
incident. The Company also maintains cyber-insurance coverage to mitigate financial implications resulting 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
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, 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.
14
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, 2017,
the Company recorded $1,839,000 in additional revenue from the WNA for weather that was approximately 18%
warmer than normal. During the fiscal year ended September 30, 2016, the Company recorded $1,318,000 in
additional revenue for the WNA for weather that was approximately 13% warmer than normal. During the fiscal year
ended September 30, 2015, the Company reduced revenue by $609,000 due to the WNA for weather that was
approximately 6.5% colder than normal. As normal weather is based on the most recent 30-year temperature average,
the heating degree days used to determine normal will change each year as a new year is added to the 30-year period
and the oldest year is removed. As a result of two consecutive years of significantly warmer winters, the number of
heating degree days that defines normal has declined from 4,000 in fiscal 2013 to 3,959 in fiscal 2017. 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 3,959 heating degree days, or about 1% less than for what the rates were designed
to recover. The 30-year normal will not be reset in base rates until the next time the Company files for a non-gas rate
increase, so until such time as normal is reset, the WNA may slightly under-recover for warmer weather.
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 cost balance of
storage gas at September 30, 2017 was higher than last year due to higher prices during the summer storage refill, the
average balance during the year, which is the base used to calculate ICC revenues, was lower by 5%. Furthermore,
increased borrowing levels in fiscal 2017 reduced the overall weighted average cost of capital, or ICC factor, as the
debt to equity ratio increased. The combination of lower average storage balances and a reduction in the ICC factor
resulted in a nearly $63,000 decline in ICC revenues. This trend in lower average storage balances and ICC factor in
fiscal 2016 resulted in a $182,000 decline in ICC revenues from fiscal 2015. Based on the current storage balances
and natural gas futures, the average dollar balance of gas in storage may increase next year; however, an expected
increase in debt will potentially reduce the ICC factor and corresponding 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 carrying cost revenues is based on the Company’s
weighted-average cost of capital, carrying cost 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 utilizing historical information including investment in natural gas facilities. 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 not recoverable until a formal
rate application is made 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 related to these 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. As the
Company has not filed for an increase in non-gas rates since 2013, SAVE Plan revenues have increased each year
corresponding to the level of SAVE qualifying capital investment. The Company recognized approximately $3,813,000,
15
$2,538,000 and $1,308,000 in SAVE Plan revenues for years ended September 30, 2017, 2016 and 2015, respectively.
SAVE revenues will be included as part of the non-gas base rates the next time the Company files for a non-gas rate
increase. 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. The local economy appears relatively stable and should continue to improve absent a major
economic setback on a local, regional or national level.
Results of Operations
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
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 Margin
Year Ended September 30,
2017
2016
Increase /
(Decrease)
Percentage
Gas Utility
Other
Total Gross Margin
$
$
32,332,390
476,767
32,809,157
$
$
31,070,660
494,254
31,564,914
$
$
1,261,730
(17,487)
1,244,243
4 %
(4)%
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 as the Company continues to
invest in qualified infrastructure projects. Since January 2014, the Company has invested more than $32,000,000 in
qualified SAVE projects with fiscal 2018 projected to add an additional $8,000,000 in SAVE investment. Volumetric
16
margin declined by nearly $526,000 due to a reduction in total volumes delivered. Residential and commercial
volumes declined due to warmer weather compared to the prior year. 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.
Other margins, consisting of non-utility related services, decreased by $17,487 despite higher revenues. Higher
operating costs made margin tighter in the non-utility services part of operations. The service contracts which generate
the majority of the non-utility related revenues are subject to annual or semi-annual renewal provisions and the
potential exists that these contracts may not be renewed or extended, which could negatively impact future revenues
and margins.
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 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.
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 ("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 Expense - Other expense, net, decreased by $123,139, or 48%, primarily due to lower pipeline assessments and
charitable commitments.
17
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 as described in Note 2 to the Consolidated Financial
Statements.
Fiscal Year 2016 Compared with Fiscal Year 2015
The table below reflects operating revenues, volume activity and heating degree-days.
Operating Revenues
Year Ended September 30,
2016
2015
Gas Utilities
Other
Total Operating Revenues
$
$
58,079,990
983,301
59,063,291
$
$
67,094,290
1,095,317
68,189,607
$
$
Decrease
(9,014,300)
(112,016)
(9,126,316)
Percentage
(13)%
(10)%
(13)%
Delivered Volumes
Year Ended September 30,
Regulated Natural Gas (DTH)
Residential and Commercial
Transportation and Interruptible
Total Delivered Volumes
Heating Degree Days
(Unofficial)
2016
2015
Decrease
Percentage
6,088,108
2,754,497
8,842,605
6,955,594
2,919,413
9,875,007
(867,486)
(164,916)
(1,032,402)
3,484
4,253
(769)
(12)%
(6)%
(10)%
(18)%
Total gas utility operating revenues for the year ended September 30, 2016 declined by 13% from the year ended
September 30, 2015 primarily due to a combination of lower gas costs and a reduction in natural gas deliveries more
than offsetting revenues from the SAVE plan rider and WNA. The average commodity price of natural gas declined by
28% per decatherm sold. Delivered volumes declined primarily due to warmer weather, as reflected in the lower
residential and commercial volumes. Industrial consumption also declined, causing a reduction in transportation and
interruptible volumes. The more weather sensative residential and commercial deliveries declined by 12% on 18%
fewer heating degree days. Transportation and interruptible volumes decreased by 6%. Other revenues experienced a
10% decrease. Approximately half of the decrease in other revenues was attributable to the cessation of operations for
Utility Consultants during fiscal 2015 and Application Resources during fiscal 2016.
18
Gross Margin
Year Ended September 30,
2016
2015
Increase /
(Decrease)
Percentage
Gas Utility
Other
Total Gross Margin
$
$
31,070,660
494,254
31,564,914
$
$
29,656,975
549,458
30,206,433
$
$
1,413,685
(55,204)
1,358,481
5 %
(10)%
4 %
Regulated natural gas margins from utility operations increased by 5% from fiscal 2015, primarily as a result of WNA
revenues, increasing SAVE Plan revenues and customer base charges related to customer growth more than offsetting
lower volumetric margins and ICC revenues. SAVE Plan revenues increased by $1,230,000 as the Company was in the
third year of the current SAVE Plan. The growth in SAVE Plan revenues has been fueled by the Company's pipeline
renewal program and investment in eligible SAVE Plan infrastructure projects. As noted above, volumetric margin
declined due to a reduction in total volumes delivered. Residential and commercial volumes declined due to much
warmer weather compared to the prior year. Interruptible and transportation volumes declined due to a combination of
reduced activity at one large customer, the closing of another industrial customer's operations during the prior fiscal
year and a significant decrease in usage by another industrial customer that uses natural gas as its back up fuel source.
The impact of the warmer weather on volumetric margin was offset by the WNA mechanism. ICC revenues continued
to decline with a $182,000 reduction in fiscal 2016 compared to fiscal 2015 due to lower commodity prices and a lower
ICC factor.
Other margins, consisting of non-utility related services, decreased by $55,204 on comparable activity. The Utility
Consultants, which ceased activity in fiscal 2015, and Application Resources, which terminated in fiscal 2016,
accounted for approximately $25,000 of the reduction in non-utility related margin. The remainder of the decrease in
other margins is attributable to the level of activity under these contracts which fluctuates based on customer
requirements.
The changes in the components of the gas utility margin are summarized below:
Customer Base Charge
$
12,364,811
$
12,240,580
$
124,231
Twelve Months Ended September 30,
2016
2015
Increase /
(Decrease)
SAVE Plan
Volumetric
WNA
Carrying Cost
Other
Total
2,538,055
14,099,214
1,317,800
651,492
99,288
1,307,795
15,757,907
(608,560)
833,291
125,962
$
31,070,660
$
29,656,975
$
1,230,260
(1,658,693)
1,926,360
(181,799)
(26,674)
1,413,685
Operations and Maintenance Expense - Operations and maintenance expenses declined by $388,799, or 3%, from
fiscal 2015 due to much higher overhead capitalization and lower bad debt expenses more than offsetting higher benefit
and labor costs. Capitalized overheads increased by 30%, or nearly $873,000, over fiscal 2015 due to higher benefit
costs, a 30% increase in capital expenditures and a 38% increase in the amount of LNG produced. In addition, bad debt
expense declined by $77,000 due to the combination of reduced sales related to much warmer weather, lower gas costs
and level of collections on previously written off accounts. Total benefit costs increased by $456,000 due to increased
pension and postretirement medical costs related to the amortization of higher actuarial losses attributable to the
adoption of a new mortality table that reflects extended life expectancies. Operating and maintenance labor costs
increased by $141,000, or 2%, due to normal wage adjustments. The remaining decrease relates to a variety of areas,
including the level of contracted and professional services, as the prior year included expenses related to the union
contract negotiations and due diligence work related to the investment in the LLC.
General Taxes - General taxes increased $56,705, or 4%, primarily due to higher property taxes associated with
increases in utility property.
19
Depreciation - Depreciation expense increased by $484,675, or more than 9%, corresponding to a similar increase in
utility plant investment.
Equity in Earnings of Unconsolidated Affiliate - The investment in Mountain Valley Pipeline began in fiscal 2016
and the $152,864 equity in earnings is primarily attributed to AFUDC income. More information regarding the
investment in Mountain Valley Pipeline is located under the Equity Investment in Mountain Valley Pipeline section
below.
Other Expense - Other expense, net, increased by $26,789, or 12%, primarily due to higher pipeline assessments and
multi-year charitable commitments.
Interest Expense - Total interest expense increased by $123,902, or 8%, due to a 15% increase in the average debt
outstanding. The increase in average debt levels was attributable to financing the investments in Mountain Valley
Pipeline and SAVE related projects and other capital improvements.
Income Taxes - Income tax expense increased by $495,622, or 16%, on higher pre-tax earnings. The effective tax rate
was 38.7% for fiscal 2016 compared to 38.4% for fiscal 2015.
Net Income and Dividends - Net income for fiscal 2016 was $5,806,866 compared to $5,094,415 for fiscal 2015.
Basic and diluted earnings per share were $0.81 in fiscal 2016 compared to $0.72 in fiscal 2015. Dividends declared
per share of common stock were $0.54 in fiscal 2016 compared to $0.51 in fiscal 2015. 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 Company’s stock plans.
Cash and cash equivalents decreased by $573,612 in fiscal 2017 and $341,982 in fiscal 2016 compared to an increase
of $135,477 in fiscal 2015. 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 (used in) financing activities
Increase (decrease) in cash and cash equivalents
Cash Flows Provided by Operating Activities:
2017
2016
2,015
$
$
$
12,980,978
(23,492,555)
9,937,965
(573,612) $
$
14,921,640
(20,996,501)
5,732,879
(341,982) $
16,760,827
(13,750,274)
(2,875,076)
135,477
The seasonal nature of the natural gas business causes operating cash flows to fluctuate significantly during the year as
well as from year to year. Factors, including weather, energy prices, natural gas storage levels and customer
collections, all contribute to working capital levels and related cash flows. Generally, operating cash flows are positive
during the second and third quarters as a combination of earnings, declining storage gas levels and collections on
customer accounts all contribute to higher cash levels. During the first and fourth quarters, operating cash flows
generally decrease due to the combination of increasing natural gas storage levels and rising customer receivable
balances.
Cash provided by operating activities was $12,981,000 in fiscal 2017, $14,922,000 in fiscal 2016 and $16,761,000 in
fiscal 2015. Cash provided by operating activities decreased by more than $1,900,000 from last year primarily as a
result of natural gas commodity prices ending their steady price decline and a smaller increase in deferred tax liabilities
associated with the continuation of bonus depreciation. Commodity prices had been declining since 2014, resulting in
lower natural gas storage costs. During fiscal 2017, natural gas prices reversed this trend and increased, resulting in
higher cost of gas in storage. The Company continues to benefit from the application of bonus depreciation for federal
20
income tax purposes with much higher first year tax deductions on assets placed in service; however, the growth in the
tax benefit has been at a smaller rate. The Company has been claiming an initial tax deduction each year on 50% of the
cost of most of the utility assets placed in service since 2008 with 100% bonus depreciation in effect during 2011. As a
result of the bonus depreciation claimed during this time, the federal tax depreciation base is considerably smaller on
these assets for all years following the year in which bonus depreciation deduction was claimed. Deferred tax has
continued to increase due to the growth in capital expenditures by the Company. However, 50% bonus depreciation
declines to 40% in 2018 and 30% in 2019. Absent any changes to current tax law, bonus depreciation will end after
2019. With projected capital expenditures expected to remain near fiscal 2017 levels and the scheduled phase out of
bonus depreciation, deferred taxes are expected to reverse in the near future resulting in cash outflows as these taxes are
paid. A summary of the key components of the cash flows from operating activities is provided below:
Cash Flows From Operating Activities:
2017
2016
Increase (Decrease)
Twelve Months Ended September 30,
Net income
Depreciation
Decrease in gas in storage
Increase in deferred taxes
Accounts payable and accrued expenses
Other
Net cash provided by operating activities
$
Cash Flows Used in Investing Activities:
$
6,232,865
$
5,806,866
$
425,999
6,378,368
(265,109)
3,325,379
(989,683)
(1,700,842)
12,980,978
$
5,709,525
723,713
4,466,954
15,046
(1,800,464)
14,921,640
$
668,843
(988,822)
(1,141,575)
(1,004,729)
99,622
(1,940,662)
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, expanding its natural gas system to meet the demands of customer growth, as
well as the continued investment in the MVP. The Company’s expenditures related to its pipeline renewal program and
other system and infrastructure improvements increased to more than $20,700,000 in fiscal 2017 from $18,000,000 in
fiscal 2016 and $13,800,000 in fiscal 2015. The Company renewed 9 miles of natural gas distribution main and
replaced 459 services in fiscal 2017. This compares to 14.9 miles of main and 684 services in fiscal 2016 and 10 miles
of main and 594 services in fiscal 2015. 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 499 new customers in fiscal 2017 compared to 495 new customers in fiscal 2016 and 609 in fiscal 2015.
Although the level of expenditures under the pipeline renewal program declined in fiscal 2017 as the Company
transitioned from cast iron and bare steel to first generation plastic pipe replacement, the Company exceeded last year's
capital spending with the completion of the automated meter reading ("AMR") project. The AMR project involved the
retrofitting of all customer meters with transmitters to allow consumption data to be collected remotely. The AMR
system provides the Company with an efficient data collection process for more reliable and accurate measure of
natural gas usage by its customers. Depreciation covered approximately 31% of the current year's capital expenditures
compared to 32% for 2016 and 38% for 2015, 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 now focused
on replacing the remaining pre-1973 first generation plastic pipe with polyethylene pipe. This renewal project is
expected to be completed by 2021. The current capital budget for fiscal 2018 is projected at more than $20,000,000,
consistent with fiscal 2017 levels. In addition to the replacement of pre-1973 plastic pipe, the Company plans to invest
approximately $3,000,000 for customer growth, replace a natural gas transfer station and reinforce sections of the
distribution system to meet increasing demand and ensure 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 $2,759,346 funding of its participation in the LLC. The Company
expects to invest a total of $35 million in the project. Funding for the investment in the LLC is provided through a
combination of a $25 million credit facility, which matures in 2020, and equity capital. The Company may consider
issuing additional common stock in 2018 to supplement the debt financing. When the $25 million credit facility
matures, the Company will consider its financing options, which may included longer-term debt financing. More
21
information regarding the credit facility is provided in Note 6 of the Consolidated Financial Statements 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. 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.
Cash flows provided by financing activities were $9,938,000 in fiscal 2017 and $5,733,000 in fiscal 2016 compared to
cash used in financing activities of $2,875,000 in fiscal 2015. The combination of greater capital investment related to
the pipeline renewal program and other projects, including the Mountain Valley Pipeline, and lower cash flows from
operating activities increased net borrowing. As noted above, the Company's operating cash flows have declined since
2015 as the benefits from declining natural gas prices and bonus depreciation have lessened. The Company increased
the net utilization of its line-of-credit by $3,235,000 to provide bridge financing for its capital budget. The Company
also entered into a 5-year unsecured note in the principal amount of $7,000,000 on November 1, 2016. The proceeds
from this note were used to convert a portion of the line-of-credit balance supporting Roanoke Gas' capital expenditures
into a longer-term financing instrument. The remaining $2,916,000 increase in unsecured notes payable is attributable
to the borrowing under Midstream's credit facility to finance the investment in MVP. Proceeds from the issuance of
stock were $968,000 under the Company's stock plans. Dividends increased as the annualized dividend rate per share
went from $0.51 in fiscal 2015 to $0.54 in fiscal 2016 and $0.58 in fiscal 2017. The Company’s consolidated
capitalization was 49.4% equity and 50.6% long-term debt at September 30, 2017. This compares to 62.2% equity and
37.8% long-term debt at September 30, 2016. The long-term debt as a percent of long-term capitalization increased
significantly over last year due to the extension of the line-of-credit term to more than one year resulting in its transition
to a non-current debt as noted below.
On March 27, 2017, Roanoke Gas entered into a new revolving line-of-credit note agreement. The new line-of-credit
agreement is for a two-year term expiring March 31, 2019, replacing the one-year agreement that expired on March 31,
2017. As the new agreement is for a two-year term, amounts drawn against the new agreement are considered to be
non-current as the balance outstanding under the line-of-credit will not be subject to repayment within the next 12-
month period. Therefore, the balance sheet at September 30, 2017 reflects the line-of-credit balance as part of long-
term debt while the prior year's balance is classified as a current liability. 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 the 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 $10,000,000 to $30,000,000. 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 outstanding at September 30, 2017 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, 2017, the estimated recorded and unrecorded obligations are as follows:
22
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
$
$
— $
— $ 13,312,200
$ 30,500,000
$ 43,812,200
—
17,791,760
—
—
17,791,760
— $ 17,791,760
$ 13,312,200
$ 30,500,000
$ 61,603,960
(1) See Note 6 to the consolidated financial statements. Does not include scheduled debt payments for the unsecured
notes issued on October 2, 2017.
(2) See Note 5 to the consolidated financial statements. New line-of-credit agreement executed for a 2-year term,
expiring March 31, 2019. 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)
Other Obligations (9)
$ 11,232,436
—
58,338
1,641,613
—
25,560,133
146,787
$ 17,746,270
—
25,800
3,283,226
—
4,741,780
10,087
$ 9,787,494
—
—
2,819,856
—
—
4,661
$ 3,067,053
—
—
15,541,764
—
—
25,540
$ 41,833,253
—
84,138
23,286,459
—
30,301,913
187,075
Total
$ 38,639,307
$ 25,807,163
$ 12,612,011
$ 18,634,357
$ 95,692,838
(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, 2017, 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 and on the 09/30/2017 balance on
Midstream notes due December 29, 2020. See Note 6 to the consolidated financial statements. Does not include
scheduled interest payments on the unsecured notes issued on October 2, 2017.
(7) Estimated minimum funding 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 2018.
(8) Projected remaining funding of the Company's 1% interest in MVP as entered into on October 1, 2015.
(9) 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. This project falls under the jurisdiction of FERC and is
subject to its approval prior to beginning construction. On October 13, 2017, FERC issued the MVP Certificate of
Public Convenience and Necessity ("CPCN"). Pending Virginia and West Virginia state environmental agency permits
and other federal agency permits, it is expected that FERC will issue a construction Notice-to-Proceed ("NTP") in late
2017 or early 2018. If the NTP is received on this schedule, the MVP targeted in-service date is late fourth quarter of
2018.
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
23
the winter heating season, could have a significant impact on the Company's ability to serve its customers. A third
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.
The total project cost is anticipated to be $3.5 billion. As a 1% member in the LLC, Midstream's cash contribution is
expected to be approximately $35 million. The agreement provides for a schedule of cash draws to fund the project.
The initial payments are related to pre-construction activities including the acquisition of land, easements and materials.
Once the NTP is received and construction begins, more significant cash draws will be required. Initial funding for the
investment in the LLC is provided through the Midstream credit facility under which Midstream may borrow up to a
total of $25 million, through 2020 with the balance coming from equity capital. The Company regularly assesses its
overall capital needs and capital structure. Based on these assessments and market conditions during 2018, the
Company may fund the LLC investment with proceeds from an equity offering of the Company's common stock.
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 will continue to grow at a steady pace until such time FERC issues their decision on the project. When the
NTP is received, construction on the pipeline should begin in earnest and both the investment in MVP and the AFUDC
will increase at a much greater rate until the pipeline is placed in service. Earnings after the pipeline is operational
would be derived from the fees charged for transporting natural gas through the pipeline.
Regulatory Affairs
The Company continues to recover the costs of its infrastructure replacement program through its SAVE Plan. On June
30, 2017, the Company filed its 2018 SAVE Plan application with the SCC. The original SAVE Plan and Rider were
approved by the SCC through an order issued on August 29, 2012 and has been modified, amended or updated each
year since. The original SAVE Plan was designed to facilitate the accelerated replacement of the remaining bare steel
and cast iron 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. The projects included under the SAVE Plan will enhance the safety and reliability of the
Company’s gas distribution system and reduce greenhouse emissions. The amendments in 2013 and 2014 added
projects related to the replacement of bare steel and cast iron natural gas pipe in addition to two other major projects
and the investment for related meter and regulator installations located on customer premises. In 2015, the SCC
approved the Company's request to expand the authorized annual spending variance from 10% to 20% and set a 5%
cumulative SAVE spending variance. This allows the Company to recover it's investment up to the new variance limits.
The 2016 and 2017 applications included provisions to continue the ongoing pipeline renewal project with a focus on
pre-1973 plastic pipe, replacement of natural gas custody transfer stations and the replacement of coated steel tubing
services and related meter installations. The 2018 SAVE Plan continues the focus on the replacement of the pre-1973
plastic pipe and the replacement of one custody transfer station. On September 28, 2017, the Company received SCC
approval to implement the new 2018 SAVE rates related to the proposed qualifying SAVE investments in calendar
2018. The new rates are designed to provide approximately $5,000,000 in revenue, representing an increase of
$1,000,000 over the estimated 2017 SAVE Plan year. The additional SAVE Plan revenue as approved by the SCC will
allow the Company to forgo a formal non-gas rate increase application at this time.
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 March 25, 2015, the Company filed an application for approval of a Certificate of Public Convenience and
Necessity with the SCC to include the remaining uncertificated portions of Franklin County into its authorized natural
gas service territory. On July 30, 2015, the Company filed a Motion to Stay Proceeding requesting the SCC stay the
application request pending further progress in the review of the MVP project by FERC and reconsider the application
at a later date. The SCC granted the stay on July 31, 2015, which permitted the Company to continue its application
24
request at a later date. As FERC has issued the CPCN on the MVP project, the Company intends to request removal of
the stay and complete the Franklin County application in fiscal 2018.
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 $965,683 and $1,004,061 as of
September 30, 2017 and 2016, respectively.
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
25
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 3.72% and 3.69%, respectively, for valuing its pension plan liability and postretirement plan liability at
September 30, 2017. These rates increased over the prior year by 0.30% and 0.36%, respectively. The rise in the
discount rate is evidenced by the 30-year Treasury rate, which increased from 2.32% to 2.86%. However, corporate
bond rates increased but to a lesser degree indicating that credit spreads among high quality investments narrowed
resulting in a smaller 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 under Projection Scale MP-2016
for the current year valuation.
The benefit plans' assets benefited from strong market returns and Company funding. Following lower than expected
returns in fiscal 2015, the returns on the related pension and postretirement assets for fiscal 2016 and 2017 exceeded the
corresponding long-term rate of return assumptions for both plans. Furthermore, in fiscal 2017, the Company
contributed $1,000,000 to each of the plans, which well exceeded the cash outflows for benefit payments. The
combination of better than expected returns, higher funding levels and increase in the discount rate improved the
funded status of the pension and postretirement plans by $3,143,000 and $2,406,000, respectively. The combination of
higher asset totals and higher discount rate also served to reduce pension and postretirement expense in fiscal 2018.
Funded status - September 30, 2017
Benefit Obligation
Fair value of assets
Funded status
Funded status - September 30, 2016
Benefit Obligation
Fair value of assets
Funded status
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)
Pension
Postretirement
Total
29,494,950
$
18,504,710
$
47,999,660
23,113,057
(6,381,893) $
11,122,783
(7,381,927) $
34,235,840
(13,763,820)
$
$
$
$
Accurately forecasting future interest rates and investment returns is nearly impossible. Interest rates have been low for
several years and just recently began to move higher. Investment returns from the equity market have been strong the
last two years; however, concern exists that current market valuations may be too high, which could be a prelude to a
market correction. The variability in interest rates and investment returns create the potential for volatility in the
Company's benefit plan liabilities, asset values, funded status and expense. Increasing interest rates would serve to
reduce the benefit liabilities but may negatively impact returns on fixed income investments in the short-term, while a
decline in interest rates would increase benefit liabilities and provide a short-term boost to fixed income returns. Equity
26
markets could experience a decline in the next year, which would reduce plan assets and negatively affect the funded
status of the plans, or equities could continue their strong performance and improve the funded status of the plans. The
Company cannot control the direction of interest rates or asset returns. However the Company annually evaluates the
returns on its targeted investment allocation model as well as the overall asset allocation of its benefit plans. The
investment policy as of the measurement date in September reflected a targeted allocation of 60% equity and 40% fixed
income on the pension plan and a targeted allocation of 50% equity and 50% fixed income for the postretirement plan.
Understanding the volatility in the markets, the Company reviews both plans potential long-term rate of return with
their investment advisors in determining the rates used in assumptions. As a result of this evaluation, the Company set
its expected long-term annual return on pension assets at 7.00% and postretirement assets at 4.84% (net of income
taxes) for fiscal 2018. These rates are consistent with the expected long-term rates used in fiscal 2017 and appear
reasonable based on a long-term investment horizon. Management will continue to re-evaluate the return assumptions
and asset allocation and adjust both as market conditions warrant.
With the inherent volatility associated with defined benefit plans, the Company continues to seek opportunities to
reduce risk and variability related to these plans. The Company implemented a freeze on the postretirement plan
effective January 1, 2000, whereby no employees hired on or after that date would participate. Employees and retirees
that were eligible at the time of the freeze continued to participate and accrue benefits. With regard to the pension plan,
the Company implemented a two-part risk reduction strategy. The first part included a one-time, lump sum pension
benefit pay out in fiscal 2016 to vested, terminated employees who were not receiving payments under the pension plan
at the time. Approximately 63% of those vested, terminated employees elected to receive their lump sum payment,
resulting in a payout of $1,242,000 from plan assets in September 2016. These lump sum payments removed
approximately $1,500,000 in pension plan liabilities and reduced the number of participants on which the Pension
Benefit Guaranty Corporation ("PBGC") premiums are determined. The second part was to take action on the pension
plan similar to what was done with the postretirement plan back in 2000 by closing the pension plan to new employees
effective January 1, 2017. Employees hired prior to that date will continue to accrue benefits. This "soft freeze" of the
pension plan will not provide immediate relief to the Plan in the form of reduced liabilities and lower expenses; but,
absent changes in other variables, pension liability growth will slow and eventually decline as no new participants will
enter the pension plan. Likewise, pension expense will reflect this change in the future as less service cost is accrued
due to fewer active employees in the pension plan. Furthermore, as the funded status of the plans improve, the
Company will evaluate the possibility of revising its asset allocation targets to more closely correlate to the
corresponding plan liabilities. Essentially, the goal would be to match investment maturities to the timing of payment
of benefits under the plans. During the current fiscal year, the Company transitioned the fixed income portion of its
pension assets into liability driven investing ("LDI"). Under the LDI approach, the fixed income portion of the
investments are allocated to one of three separate fixed income investments that corresponded to the duration of the
liabilities of the pension plan; a short duration investment, a middle duration investment and a longer-term duration
investment. No fundamental change has been made to the overall asset allocation between fixed income and equity
other than adjusting the duration of the fixed income portion. The matching of the asset and liability durations should
ultimately reduce some of the volatility in these plans.
In August 2014, the Highway and Transportation Funding Act of 2014 (“HATFA”) was signed into law, which included
a provision to extend the interest rate corridors introduced in 2012 under the Moving Ahead for Progress in the 21st
Century Act (“MAP-21”). MAP-21 provided temporary funding relief for defined benefit pension plans. The
requirements of the Employee Retirement Income Security Act of 1974 (ERISA) and the Pension Protection Act of
2006 (PPA) subject defined benefit plans to minimum funding rules. As a result, when interest rates are low, pension
plan liabilities increase thereby resulting in higher mandatory contributions to meet minimum funding obligations.
MAP-21 provided funding relief by allowing pension plans to adjust the interest rates used in determining funding
requirements so that they are within 10% of the average of interest rates for the 25-year period preceding the current
year for funding calculations for 2013 to within 30% for funding periods beginning in 2016. HATFA extended the
period of time that the 10% corridor instituted by MAP-21 may be used for funding calculations. Under HATFA, the
10% corridor extends through plan years that begin in 2017 and phases out to a 30% corridor in 2021 and later. HATFA
significantly increases the effective interest rates used in determining funding requirements and could result in a
deterioration of the pension plan funded status resulting in much greater funding requirements in the future as well as
higher PBGC premiums paid by sponsors of pension plans to protect participants in the event of default by the
employer. Management estimates that, under the provisions of HATFA, the Company will have no minimum funding
requirements next year. Although HATFA and MAP-21 allow the Company some funding relief, management expects
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 $1,600,000 to its
pension plan and $600,000 to its postretirement plan in fiscal 2018 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
27
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%
123,000
$
1,225,000
66,000
53,000
N/A
292,000
The following schedule reflects the sensitivity of postretirement benefit costs from changes in certain actuarial
assumptions, while the other components of the calculation remain constant.
Actuarial Assumptions - Postretirement Plan
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
1,000
$
747,000
29,000
45,000
N/A
723,000
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, 2017 related to the 5-year $7,000,000 variable-rate note. This swap agreement, which
was entered into on November 1, 2016, becomes effective November 1, 2017.
Tax Reform
Federal corporate tax reform is currently a major legislative agenda item. There continues to be discussion regarding
tax legislation and improving the corporate tax environment in the United States in an effort to encourage domestic
business development. The key proposal is a reduction in corporate income tax rates. In general, a change in corporate
income tax rates would not only reduce current income tax expense but also result in an adjustment to the value of
deferred income tax balances. According to ASC 740-10, deferred tax assets and liabilities shall be adjusted for the
effect of a change in tax laws and rates and the effect of such change shall be included in income from continuing
operations for the period that includes the date of enactment. If lower federal corporate tax rates are passed, deferred
income taxes at the date of enactment would be reduced and the net benefit or expense would flow through income tax
expense. However, for Roanoke Gas, any adjustment to deferred taxes would not be reflected in the income statement.
Instead, under the requirements of regulatory accounting, those excess deferred taxes would be reclassified to a
regulatory liability to be refunded to the utility's customers, as the Company's non gas rates provided for the recovery of
income taxes at a federal tax rate of 34%. As of September 30, 2017, the Company has a net deferred tax liability of
approximately $23,100,000 of which Roanoke Gas represented approximately $23,900,000 of that balance while the
unregulated operations of Resources had a net deferred tax asset of $800,000. If a corporate tax rate decrease becomes
law, then for every one percent decrease in the federal corporate tax rate, approximately $600,000 would be transferred
to a regulatory liability and $20,000 would be reflected as additional income tax expense in comprehensive income.
Other proposed tax law changes may have impacts, both favorable or unfavorable, to the Company's tax expense and
deferred tax balances. No adjustment will be made to deferred taxes or income tax expense until such time as any
proposed tax legislation is signed into law.
28
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, 2017, the Company has $17,791,760 outstanding under its variable-rate line-of-credit with an average
balance outstanding during the year of $10,936,114. The Company also had $6,312,200 outstanding under a 5-year
variable rate term loan and $7,000,000 outstanding on a 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 $223,000. 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, 2017, the Company had no outstanding derivative instruments to hedge the price of natural gas. The
Company had approximately 2,388,000 decatherms of gas in storage, including LNG, at an average price of $3.23 per
decatherm compared to 2,537,000 decatherms at an average price of $2.93 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.
Item 8.
Financial Statements and Supplementary Data.
29
RGC Resources, Inc.
and Subsidiaries
Consolidated Financial Statements
for the Years Ended September 30, 2017, 2016
and 2015, and Report of Independent
Registered Public Accounting Firm
30
RGC RESOURCES, INC. AND SUBSIDIARIES
TABLE OF CONTENTS
Report of Independent Registered Public Accounting Firm
Consolidated Financial Statements for the Years Ended September 30, 2017, 2016 and 2015:
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
32
33
35
36
37
38
39
31
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
RGC Resources, Inc.
Roanoke, Virginia
We have audited the accompanying consolidated balance sheets of RGC Resources, Inc. and Subsidiaries (“the Company”)
as of September 30, 2017 and 2016, 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, 2017. RGC Resources, Inc.’s
management is responsible for these financial statements. Our responsibility is to express an opinion on these consolidated
financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United
States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts
and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial
position of RGC Resources, Inc. and Subsidiaries as of September 30, 2017 and 2016, and the consolidated results of its
operations and its cash flows for each of the years in the three-year period ended September 30, 2017, in conformity with
accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States),
RGC Resources, Inc. and Subsidiaries’ internal control over financial reporting as of September 30, 2017, 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 8, 2017 expressed an unqualified opinion.
Blacksburg, Virginia
December 8, 2017
CERTIFIED PUBLIC ACCOUNTANTS
32
RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AS OF SEPTEMBER 30, 2017 AND 2016
ASSETS
CURRENT ASSETS:
Cash and cash equivalents
Accounts receivable, net
Materials and supplies
Gas in storage
Prepaid income taxes
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
2017
2016
$
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
19,521,496
643,252
3,478,983
824,139
7,436,785
1,550,836
—
1,548,329
15,482,324
185,577,286
(56,156,287)
129,420,999
2,707,139
132,128,138
14,332,451
3,496,404
—
113,532
17,942,387
$
183,135,071
$
165,552,849
(Continued)
33
RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AS OF SEPTEMBER 30, 2017 AND 2016
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Line-of-credit
Dividends payable
Accounts payable
Capital contributions payable
Customer credit balances
Customer deposits
Accrued expenses
Over-recovery of gas costs
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
Total deferred credits and other liabilities
COMMITMENTS AND CONTINGENCIES (Note 11)
CAPITALIZATION:
Stockholders’ Equity:
Common Stock, $5 par value; authorized 10,000,000 shares; issued and
outstanding 7,240,846 and 7,182,434 shares in 2017 and 2016, respectively
Preferred stock, no par; authorized 5,000,000 shares; no shares issued and
outstanding in 2017 and 2016
Capital in excess of par value
Retained earnings
Accumulated other comprehensive loss
Total stockholders’ equity
2017
2016
$
— $
14,556,785
1,050,281
5,122,899
1,055,504
1,220,578
1,471,960
3,006,936
1,438,074
970,244
5,345,575
287,794
1,605,608
1,627,105
3,194,255
909,687
14,366,232
28,497,053
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
33,896,200
—
(260,149)
33,636,051
5,682,556
9,348,443
13,763,820
18,957,854
47,752,673
36,204,230
23,941,445
—
292,485
24,746,021
(1,202,264)
60,040,472
—
9,509,548
24,713,310
(2,497,231)
55,667,072
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
$
183,135,071
$
165,552,849
See notes to consolidated financial statements.
(Concluded)
34
RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
YEARS ENDED SEPTEMBER 30, 2017, 2016 AND 2015
OPERATING REVENUES:
Gas utilities
Other
Total operating revenues
COST OF SALES:
Gas utilities
Other
Total cost of sales
GROSS MARGIN
OTHER OPERATING EXPENSES:
Operations and maintenance
General taxes
Depreciation and amortization
Total other operating expenses
OPERATING INCOME
Equity in earnings of unconsolidated affiliate
Other 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
2017
2016
2015
$
61,252,015
$
58,079,990
$
67,094,290
1,044,855
62,296,870
983,301
59,063,291
1,095,317
68,189,607
28,919,625
27,009,330
568,088
29,487,713
32,809,157
489,047
27,498,377
31,564,914
13,100,041
13,098,086
1,786,070
6,256,737
21,142,848
11,666,309
421,646
132,446
1,917,254
10,038,255
3,805,390
6,232,865
0.86
0.86
$
$
$
1,663,126
5,591,610
20,352,822
11,212,092
152,864
255,585
1,636,321
9,473,050
3,666,184
5,806,866
0.81
0.81
$
$
$
37,437,315
545,859
37,983,174
30,206,433
13,486,885
1,606,421
5,106,935
20,200,241
10,006,192
—
228,796
1,512,419
8,264,977
3,170,562
5,094,415
0.72
0.72
7,218,686
7,256,046
7,149,906
7,159,763
7,092,315
7,097,514
$
$
$
See notes to consolidated financial statements.
35
RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
YEARS ENDED SEPTEMBER 30, 2017, 2016 AND 2015
2017
2016
2015
$
6,232,865
$
5,806,866
$
5,094,415
72,489
1,222,478
1,294,967
—
(210,686)
(210,686)
5,596,180
$
—
(1,147,219)
(1,147,219)
3,947,196
NET INCOME
Other comprehensive income, net of tax:
Interest rate swaps
Defined benefit plans
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
COMPREHENSIVE INCOME
$
7,527,832
$
See notes to consolidated financial statements.
36
Total
Stockholders’
Equity
Accumulated
Other
Comprehensive
Income (Loss)
$ (1,139,326) $ 52,020,847
5,094,415
(1,147,219)
49,366
—
(1,147,219)
—
—
—
—
83,640
(3,643,093)
383,035
$ (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)
—
—
—
—
73,780
(4,195,910)
—
(96,508)
921,965
$ (1,202,264) $ 60,040,472
—
—
—
RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
YEARS ENDED SEPTEMBER 30, 2017, 2016 AND 2015
Common
Stock
Capital in
Excess of
Par Value
Retained
Earnings
Balance - September 30, 2014
$ 23,601,890
$
8,237,228
$ 21,321,055
Net income
Other comprehensive loss
Exercise of stock options (3,900 shares)
Stock option grants
Cash dividends declared ($0.51 per share)
—
—
13,000
—
—
—
—
36,366
83,640
—
Issuance of common stock (27,780 shares)
92,600
290,435
5,094,415
—
—
—
(3,643,093)
—
Balance - September 30, 2015
Net income
Other comprehensive loss
Exercise of stock options (3,300 shares)
Stock option grants
Cash dividends declared ($0.54 per share)
$ 23,707,490
—
$
8,647,669
—
$ 22,772,377
5,806,866
—
11,000
—
—
—
30,762
64,640
—
Issuance of common stock (66,887 shares)
222,955
766,477
Balance - September 30, 2016
$ 23,941,445
$
9,509,548
$ 24,713,310
—
—
—
(3,865,933)
—
6,232,865
Net income
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
See notes to consolidated financial statements.
37
RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED SEPTEMBER 30, 2017, 2016 AND 2015
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
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 (used in) 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
2017
2016
2015
$ 6,232,865
$ 5,806,866
$ 5,094,415
6,378,368
(354,744)
73,780
(421,646)
3,325,379
203,743
5,709,525
(449,201)
64,640
(152,864)
4,466,954
197,298
5,219,893
(406,731)
83,640
—
2,416,841
105,815
(191,386)
(462,161)
528,387
(956,894)
(1,374,713)
6,748,113
12,980,978
(258,960)
867,682
(991,739)
(398,864)
60,303
9,114,774
14,921,640
638,917
3,168,056
2,082,257
(768,922)
(873,354)
11,666,412
16,760,827
(20,750,181)
(2,759,346)
16,972
(23,492,555)
(17,945,719)
(3,055,746)
4,964
(20,996,501)
(13,780,356)
—
30,082
(13,750,274)
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
$
34,698,924
(34,402,977)
—
—
432,401
(3,603,424)
(2,875,076)
135,477
849,757
985,234
$
$ 1,734,178
726,000
$ 1,480,665
(907,000)
$ 1,002,462
1,266,573
See notes to consolidated financial statements.
38
RGC RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2017, 2016 AND 2015
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; RGC Ventures of Virginia, Inc., operating as Application Resources and The Utility Consultants;
and RGC Midstream, LLC. Roanoke Gas is a natural gas utility, which distributes and sells natural gas to
approximately 59,800 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 Ventures of Virginia, Inc. was dissolved in 2016 after Application
Resources, which provided information system services to software providers in the utility industry, ceased operations
in 2016, and The Utility Consultants, which provided regulatory consulting services to other utilities, ceased
operations in 2015. RGC Midstream, LLC is a wholly-owned subsidiary created in 2015 to invest in the Mountain
Valley pipeline project. Diversified Energy Company is currently 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.
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.
39
Regulatory assets and liabilities included in the Company’s consolidated balance sheets as of September 30, 2017 and
2016 are as follows:
Regulatory Assets:
Current Assets:
Accounts receivable:
Accrued WNA revenues
Other:
September 30
2017
2016
$
248,840
$
148,663
Accrued pension and postretirement medical
658,786
835,704
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
Deferred Credits and Other Liabilities:
Asset retirement obligations
Regulatory cost of retirement obligations
Total regulatory liabilities
11,945
11,945
1,941,182
8,643,524
1,211,554
12,715,831
$
2,055,369
11,460,738
816,344
15,328,763
1,438,074
$
909,687
215,514
238,694
6,069,993
10,055,189
17,778,770
$
5,682,556
9,348,443
16,179,380
$
$
$
As of September 30, 2017, the Company had regulatory assets in the amount of $12,703,886 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:
Distribution and transmission
LNG storage
General and miscellaneous
Total utility plant in service
40
Years Ended September 30
2017
2016
$
177,845,619
$
160,354,300
13,299,288
13,078,807
204,223,714
$
12,594,294
12,628,692
185,577,286
$
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. The
composite weighted-average depreciation rate realized using the most recently completed depreciation study was
3.29% for the fiscal year ended September 30, 2017 and 3.25% for the fiscal years ended September 30, 2016 and
2015.
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
2017
5,682,556
65,556
(137,304)
312,503
146,682
6,069,993
$
$
2016
5,295,868
85,263
(176,090)
310,568
166,947
5,682,556
$
$
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, 2017, the Company did not have any bank deposits in excess of the FDIC insurance limits. For
purposes of the consolidated statements of cash flows, the Company considers all highly liquid debt instruments
purchased with an original maturity of three months or less to be cash equivalents.
Customer Receivables and Allowance for Doubtful Accounts—Accounts receivable include amounts billed to
customers for natural gas sales and related services and gas sales occurring subsequent to normal billing cycles but
before the end of the period. The Company provides an estimate for losses on these receivables by utilizing historical
information, current account balances, account aging and current economic conditions. Customer accounts are charged
off annually when deemed uncollectible or when turned over to a collection agency for action.
41
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
2017
2016
2015
$
$
76,934
84,587
110,725
(172,790)
99,456
$
$
52,721
14,074
137,055
(126,916)
76,934
$
$
70,747
87,908
139,282
(245,216)
52,721
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 are the
Company's one primary type of financing receivables, resulting from the sale of natural gas and other services to its
customers. These receivables are short-term in nature with a provision for uncollectible balances included in the
financial statements.
Inventories—Inventories, consisting of natural gas in storage and materials and supplies, are recorded at average cost.
Injections into storage are priced at the purchase cost at the time of injection and withdrawals from storage are priced
at the weighted average price 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, 2017 and 2016 were $965,683 and
$1,004,061, 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 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 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:
•
•
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
42
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
2017
6,232,865
7,218,686
$
2016
5,806,866
7,149,906
$
2015
5,094,415
7,092,315
37,360
7,256,046
9,857
7,159,763
5,199
7,097,514
0.86
0.86
$
$
0.81
0.81
$
$
0.72
0.72
$
$
$
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.
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.
43
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. hedges 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, 2017 and 2016, the Company had no
outstanding derivative instruments for the purchase of natural gas.
The Company had one interest rate swap associated with its $7,000,000 term note with Branch Banking & Trust as
discussed in Note 6. Effective November 1, 2017, the swap agreement converts 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
2017
2016
$
$
$
26,777
$
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 $767,710 and $287,794 occurred for the fiscal years ended September 30, 2017 and
2016, respectively.
44
Other Comprehensive Income (Loss)—A summary of other comprehensive income is provided below:
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
Year Ended September 30, 2015:
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
$
$
$
$
$
$
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)
(1,910,573)
60,221
(1,850,352)
(1,850,352) $
726,017
(22,884)
703,133
703,133
$
(1,184,556)
37,337
(1,147,219)
(1,147,219)
The amortization of actuarial losses is 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, 2014
Other comprehensive income (loss)
Balance September 30, 2015
Other comprehensive income (loss)
Balance September 30, 2016
Other comprehensive income (loss)
Balance September 30, 2017
Interest Rate
Swaps
$
$
— $
—
—
—
—
72,489
72,489
$
Defined Benefit
Plans
(1,139,326) $
(1,147,219)
(2,286,545)
(210,686)
(2,497,231)
1,222,478
(1,274,753) $
Accumulated
Other
Comprehensive
Income (Loss)
(1,139,326)
(1,147,219)
(2,286,545)
(210,686)
(2,497,231)
1,294,967
(1,202,264)
45
Recently Adopted Accounting Standards—In November 2015, the FASB issued ASU 2015-17, Income Taxes:
Balance Sheet Classification of Deferred Taxes. The ASU requires that all deferred tax assets and liabilities be
presented as noncurrent and eliminates prior guidance to classify and present deferred tax assets and liabilities as
current and noncurrent. This ASU is effective for the Company for the annual reporting period ended September 30,
2018 and interim periods within that annual period. Early application is permitted. The Company adopted this ASU for
the quarter ended December 31, 2015.
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.
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.
The FASB continues to issue subsequent guidance under ASC No. 606 to provide further clarification of the original
ASU. In addition, the Company is also monitoring the activity of the Power and Utilities Task Force. The Task Force
was formed by the American Institute of Certified Public Accountants ("AICPA") in an effort to provide industry-
specific guidance. Implementation issues identified by the Task Force include accounting for contributions in aid of
construction and assessing collectability of customer accounts when regulated mechanisms exist to allow recovery of
uncollected accounts from ratepayers.
As of September 30, 2017, the Company continues identifying sources of revenue and evaluating the effect that the
revenue guidance will have on financial results and disclosures. Though the evaluation is ongoing, based on the
review of customer contracts to date, the Company is not anticipating a material impact to its financial position, results
of operations or cash flows upon adoption; however, the Company does anticipate the potential for significant new
disclosures as a result of the guidance. Because of ongoing internal analysis and the continued activities of the FASB
and other related implementation efforts regarding the rate-regulated natural gas industry, early adoption is not
expected. The Company will consider all current and future guidance, including the conclusions of the Task Force,
before determining how best to implement the new revenue recognition standard.
46
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 has not completed its evaluation of the new
guidance. However, the Company does not currently expect 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. Management has not completed its evaluation of the new guidance.
However, 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 is in the process of evaluating the new
guidance from this ASU. The regulatory body in the Company's service jurisdiction requires the capitalization of all
cost components included in net benefit costs. As a result, the Company may have to establish regulatory assets for
those costs now excluded from capitalization under this ASU. The Company has begun discussions with its regulatory
body, the State Corporation Commission of Virginia, regarding the expected treatment of those costs. Although the
ultimate disposition of these other components of net periodic benefit costs has not been determined, management
expects the new guidance may have a material effect on the Company's consolidated financial statements when
adopted.
In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging: Targeted Improvements to Accounting For
Hedging Activities. The ASU is meant to simplify recognition and presentation guidance in an effort to improve
financial reporting of cash flow and fair value hedging relationships to better portray the economic results of an
entity's risk management activities. This is achieved through changes to both the designation and measurement
guidance for qualifying hedging relationships, as well as changes to the presentation of hedge results. The new
guidance is effective for the Company for the annual reporting period ending September 30, 2020 and interim periods
within that annual period. Early adoption is permitted. Management has not completed its evaluation of the new
guidance; however, it does not currently expect the new guidance to have a material effect on its financial position,
results of operations or cash flows.
47
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 SPLIT
On January 17, 2017, Resources Board of Directors approved a three-for-two stock split of the Company's issued and
outstanding common stock. The stock split was effected in the form of a 50% stock dividend entitling each
shareholder to receive one additional share of common stock for every two shares owned. The stock dividend was
payable March 1, 2017 to shareholders of record on February 15, 2017. As the par value of the common stock
remained at $5 per share, the Company reclassified $10,025,546 from "Capital in excess of par value" and $2,004,244
from "Retained earnings" to "Common stock" associated with the issuance of 2,405,958 shares. Corresponding prior
year amounts of share and per share data have been restated retrospectively to reflect the 50% stock dividend.
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 June 30, 2017, the Company filed with the SCC its most recent SAVE (Steps to Advance Virginia's Energy) 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 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 collecting the shortfall in
SAVE revenues collected under the 2016 SAVE Plan and proposed new 2018 SAVE rates to be implemented for the
ongoing investment in SAVE Plan projects. On September 28, 2017, the Company received approval of its application
to implement the new 2018 SAVE rates related to proposed qualifying SAVE investments in calendar 2018. The SCC
also approved the True-Up factor to provide collection on the remaining under-collected 2016 SAVE Plan for a
modification to the SAVE Plan and Rider.
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. On October 13, 2017, the Federal Energy Regulatory Commission issued
the Certificate of Public Convenience and Necessity subject to certain conditions and requirements. With FERC
approval, the LLC will continue the process of obtaining the necessary approvals and permits from other federal and
state government agencies. Assuming no significant delays in the permitting process, the pipeline is expected to be in
service by late 2018.
The total project cost is estimated to be approximately $3.5 billion. The Company's 1% equity interest in the LLC will
require a total estimated cash investment of approximately $35 million, provided by periodic capital contributions
throughout the design and construction phases of the project. Midstream held an approximate $7.4 million equity
method investment in the LLC at September 30, 2017. Initial funding for Midstream's investment in the LLC 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 the pipeline in
proportion to its level of investment.
The financial statement locations of the investment in the LLC are as follows:
48
Balance Sheet Location of Other Investments:
Other Assets:
September 30
2017
2016
Investment in unconsolidated affiliate
$
7,445,106
$
3,496,404
Current Liabilities:
Capital contributions payable
Income Statement Location of Other Investments:
Equity in earnings of unconsolidated affiliate
5.
LINE-OF-CREDIT
$
1,055,504
$
287,794
For the Years ended September 30
2017
421,646
$
2016
152,864
$
$
2015
—
On March 27, 2017, Roanoke Gas entered into a new unsecured line-of-credit agreement. This line-of-credit
agreement replaced the agreement which expired on March 31, 2017. The expired agreement was for a term of one
year and all amounts drawn against that agreement were considered to be current liabilities. The new line-of-credit
agreement is for a two-year term expiring March 31, 2019. 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.
Except for the two-year term, 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 expired 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, 2017
March 1, 2018
July 22, 2018
September 22, 2018
A summary of the line-of-credit follows:
$
Available
Line-of-Credit
21,000,000
17,000,000
22,000,000
30,000,000
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
2017
$ 21,000,000
17,791,760
17,791,760
10,936,114
September 30
2016
$ 24,000,000
14,556,785
15,246,089
9,620,914
2015
$ 24,000,000
9,340,997
17,366,052
6,377,040
1.92%
2.23%
0.15%
1.40%
1.53%
0.15%
1.17%
1.20%
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%.
49
6.
LONG-TERM DEBT
On November 1, 2016, Roanoke Gas entered into a 5-year unsecured note with Branch Banking & Trust in the
principal amount of $7,000,000. The note is variable rate with interest based on 30-day LIBOR plus 90 basis points.
In addition, Roanoke Gas also entered into a swap agreement with Branch Banking & Trust to convert the variable rate
debt into a fixed-rate instrument with an annual interest rate of 2.30%. The swap agreement is not effective until
November 1, 2017, with the monthly interest rate on the note floating until the swap period begins. The proceeds
from the note were used to convert a portion of the Company's line-of-credit balance into longer-term financing.
Midstream has two unsecured Promissory Notes ("Notes") which provide up to a total of $25 million in borrowing
limits over a period of 5 years, with an interest rate of 30-day LIBOR plus 160 basis points. Midstream issued the
Notes in December 2015 to provide financing for capital investment in respect of its 1% interest in the LLC. In
accordance with the terms of the debt, at such point in time as Midstream has borrowed $17.5 million under the Notes,
Midstream is required to provide the next $5 million towards its capital contributions to the LLC. Once Midstream has
completed its $5 million in contributions, it may resume borrowing under the Notes up to the $25 million limit.
Long-term debt consists of the following:
September 30
2017
2016
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
Pending unsecured note
RGC Midstream, LLC:
Unsecured term notes payable, at 30-day
LIBOR plus 1.60% due December 29, 2020
Total notes payable
Line-of-credit, at 30-day LIBOR plus 1.00%,
due March 31, 2019
Total long-term debt
$ 30,500,000
$
164,119
$ 30,500,000
$
173,773
7,000,000
—
13,618
48,160
—
—
—
—
$
6,312,200
$ 43,812,200
$
$
66,052
$
3,396,200
291,949
$ 33,896,200
$
$
86,376
260,149
17,791,760
—
—
—
$ 61,603,960
$
291,949
$ 33,896,200
$
260,149
Debt issuance costs are amortized over the life of the related debt. As of September 30, 2017 and 2016, the Company
also had an unamortized loss on the early retirement of debt of $1,941,182 and $2,055,369, respectively, which has
been deferred as a regulatory asset and is being amortized over a 20 year period.
All of the debt agreements set forth certain representations, warranties and covenants to which the Company is
subject, including financial covenants that limit Consolidated Long-Term Indebtedness to not more than 65% of total
capitalization. All of the debt agreements except for the line-of-credit provide for priority indebtedness to not exceed
15% of consolidated total assets.
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 note were used to convert a portion of the Company's line-
of-credit balance into longer-term financing.
50
The aggregate annual maturities of long-term debt for the next five years ending after September 30, 2017 are as
follows:
Year Ending September 30
2018
2019
2020
2021
2022
Thereafter
Total
7.
INCOME TAXES
The details of income tax expense are as follows:
Maturities
—
17,791,760
—
6,312,200
7,000,000
30,500,000
61,603,960
$
$
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
2017
2016
2015
$
72,368
$
407,643
480,011
3,129,925
195,454
3,325,379
(1,216,745) $
415,975
(800,770)
4,302,906
164,048
4,466,954
$
3,805,390
$
3,666,184
$
379,180
374,541
753,721
2,289,729
127,112
2,416,841
3,170,562
Income tax expense for the years ended September 30, 2017, 2016 and 2015 differed from amounts computed by
applying the U.S. Federal income tax rate of 34% to earnings before income taxes due to the following:
Income before income taxes
Income tax expense computed at the federal statutory
rate
State income taxes, net of federal income tax benefit
Other, net
Total income tax expense
Years Ended September 30
2017
10,038,255
3,413,007
398,044
(5,661)
3,805,390
$
$
$
$
$
$
2016
9,473,050
3,220,837
382,815
62,532
$
$
2015
8,264,977
2,810,092
331,091
29,379
3,666,184
$
3,170,562
51
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
Accrued vacation
Over-recovery of gas costs
Costs of gas held in storage
Deferred compensation
Other
Total gross deferred tax assets
Deferred tax liabilities:
Utility plant
MVP investment
Other
Total gross deferred tax liabilities
Net deferred tax liability
September 30
2017
2016
$
37,752
$
1,747,429
239,414
545,894
1,009,206
824,281
348,833
4,752,809
29,203
2,532,672
262,273
345,318
1,077,849
770,868
340,121
5,358,304
27,630,486
24,264,165
154,817
44,354
27,829,657
$
23,076,848
$
40,776
11,217
24,316,158
18,957,854
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 same situation occurred in fiscal 2014 when the
extension of 50% bonus depreciation was not signed into law until December 19, 2014, following the issuance of the
Company's financial statements for the year ended September 30, 2014. Correspondingly, fiscal 2015 income tax
expense included the tax effect of the 50% bonus depreciation for fixed asset additions during the last nine months of
fiscal 2014, which resulted in $1,442,211 in deferred tax expense related to fiscal 2014 being included in fiscal 2015.
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 extends through December 31, 2017, 40% for calendar 2018 and 30%
for calendar 2019 with no provision for bonus depreciation after 2019. Virginia tax law does not recognize bonus
depreciation; therefore, state income taxes were not impacted by the delayed bonus depreciation extensions.
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, 2014 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. In November 2016, the Board of Directors approved a "soft freeze" to the pension plan, whereby no
employees hired on or after January 1, 2017 will be eligible to participate. Employees hired prior to January 1, 2017
52
will continue to participate in the plan and accrue benefits. The Board of Directors also approved an amendment to
the 401(k) Plan which would allow for management to authorize a discretionary contribution to the 401(k) Plan for
employees hired on or after January 1, 2017. This discretionary contribution would be determined each year, and if
approved, 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.
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
2017
2016
2017
2016
$ 25,481,993
$ 25,090,968
$ 17,666,812
$ 18,504,710
Benefit obligation at beginning of year
$ 29,494,950
$ 27,167,621
$ 18,504,710
$ 15,355,668
Service cost
Interest cost
Actuarial (gain) loss
Benefit payments, net of retiree contributions
Benefit obligation at end of year
Change in fair value of plan assets:
706,677
995,598
(824,361)
(715,517)
$ 29,657,347
694,375
1,132,776
2,440,957
(1,940,779)
$ 29,494,950
183,267
626,822
(1,199,722)
(448,265)
$ 17,666,812
148,018
624,579
2,812,516
(436,071)
$ 18,504,710
Fair value of plan assets at beginning of year
$ 23,113,057
$ 21,394,399
$ 11,122,783
$ 10,443,629
Actual return on plan assets, net of taxes
3,021,131
2,159,437
1,016,644
615,225
Employer contributions
Benefit payments, net of retiree contributions
Fair value of plan assets at end of year
Funded status
Amounts recognized in the balance sheets
consist of:
500,000
1,000,000
(436,071)
(715,517)
$ 26,418,671
$ 11,122,783
$ (3,238,676) $ (6,381,893) $ (4,975,650) $ (7,381,927)
1,500,000
(1,940,779)
$ 23,113,057
1,000,000
(448,265)
$ 12,691,162
Noncurrent liabilities
$ (3,238,676) $ (6,381,893) $ (4,975,650) $ (7,381,927)
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
$
$
$
$
572,740
572,740
5,471,547
5,471,547
$
$
$
$
1,583,345
1,583,345
6,732,800
6,732,800
$
$
$
$
702,013
702,013
3,830,763
3,830,763
$
$
$
$
913,886
913,886
5,563,642
5,563,642
53
During 2016, the Company offered a one-time, lump sum pay out option for vested, terminated employees not
currently receiving payments under the pension plan. The lump sum offer was accepted by 40 of the 63 eligible
participants. In September 2016, the pension plan distributed $1,241,529 to the participants electing to receive the
lump sum payments, which resulted in a corresponding reduction of approximately $1,500,000 in the projected
pension obligation.
The Company expects that approximately $24,000 before tax, of accumulated other comprehensive income will be
recognized as a reduction in net periodic benefit costs in fiscal 2018 and approximately $659,000 of amounts deferred
as regulatory assets will be amortized and recognized in net periodic benefit costs in fiscal 2018.
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
2017, 2016 and 2015.
Pension Plan
Postretirement Plan
2017
2016
2015
2017
2016
2015
Assumptions used to determine benefit
obligations:
Discount rate
Expected rate of compensation increase
3.72%
4.00%
3.42%
4.00%
4.22%
4.00%
3.69%
N/A
3.33%
N/A
4.15%
N/A
Assumptions used to determine benefit
costs:
Discount rate
Expected long-term rate of return on plan
assets
Expected rate of compensation increase
3.42%
4.22%
4.22%
3.33%
4.15%
4.10%
7.00%
4.00%
7.00%
4.00%
7.00%
4.00%
4.84%
N/A
4.89%
N/A
4.90%
N/A
To develop the expected long-term rate of return on assets assumption, the Company, with input from the plans'
actuaries and investment advisors, considered the historical returns and the future expectations for returns for each
asset class, as well as the target asset allocation of each plan’s portfolio.
Components of net periodic benefit cost are as follows:
Pension Plan
Postretirement Plan
2017
2016
2015
2017
2016
2015
$ 706,677
$
694,375
$
654,782
$ 183,267
$ 148,018
$ 167,580
Service cost
Interest cost
Expected return on plan assets
(1,616,412)
Recognized loss
662,180
995,598
1,132,776
(1,492,241)
501,678
1,025,908
(1,440,846)
257,378
626,822
(571,513)
429,758
624,579
(507,858)
250,173
600,096
(516,656)
197,058
Net periodic benefit cost
$ 748,043
$
836,588
$
497,222
$ 668,334
$ 514,912
$ 448,078
The assumed health care cost trend rates used in measuring the accumulated benefit obligation for the postretirement
medical plan as of September 30, 2017, 2016 and 2015 are presented below:
2017
Pre 65
2016
2015
2017
Post 65
2016
2015
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%
7.50%
8.00%
5.00%
5.00%
5.00%
5.00%
2021
5.00%
2021
5.00%
2021
5.00%
2017
5.00%
2016
5.00%
2015
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
54
1% Increase
1% Decrease
$
153,000
2,961,000
$
(121,000)
(2,385,000)
The primary objectives of the Plan’s investment policy 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. The investment policy provides for a range of
investment allocations to allow for flexibility in responding to market conditions. The investment policy is
periodically reviewed by the Company and a third-party investment advisor.
The Company’s target and actual asset allocation in the pension and postretirement benefit plans as of September 30,
2017 and 2016 were:
Asset category:
Equity securities
Debt securities
Cash
Other
Pension Plan
Postretirement
Plan
Target
2017
2016
Target
2017
2016
60%
40%
—%
—%
63%
36%
1%
—%
63%
36%
1%
—%
50%
50%
—%
—%
51%
48%
1%
—%
52%
47%
—%
1%
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, 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
5,068,282
5,046,530
2,393,221
2,139,733
—
—
—
—
—
9,635,998
5,068,282
5,046,530
2,393,221
2,139,733
Mutual Funds:
Bonds
Equities
Foreign Large Cap Growth
Foreign Large Cap Value
Foreign Large Cap Core
399,909
398,995
1,070,903
26,418,671
$
$
—
—
—
265,100
$
399,909
398,995
1,070,903
26,153,571
$
Total
—
—
—
—
—
—
—
—
—
—
55
Defined Benefit Pension Plan
Fair Value Measurements - September 30, 2016
Fair Value
Level 1
Level 2
Level 3
$
117,265
$
117,265
$
— $
Asset Class:
Cash
Common and Collective Trust and
Pooled Funds:
Bonds
Domestic Fixed Income
4,497,373
Equities
Domestic Large Cap Growth
Domestic Large Cap Value
Domestic Small/Mid Cap
Core
Foreign Large Cap Value
Mutual Funds:
Bonds
Domestic Fixed Income
Foreign Fixed Income
Equities
3,426,041
4,543,385
2,149,566
1,795,897
3,615,209
234,622
Domestic Large Cap Growth
1,043,395
Foreign Large Cap Growth
Foreign Large Cap Value
Foreign Large Cap Core
366,420
373,480
950,404
—
—
—
—
—
—
—
—
—
—
—
4,497,373
3,426,041
4,543,385
2,149,566
1,795,897
3,615,209
234,622
1,043,395
366,420
373,480
950,404
Total
$
23,113,057
$
117,265
$
22,995,792
$
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
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
$
56
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Postretirement Benefit Plan
Fair Value Measurements - September 30, 2016
Fair Value
Level 1
Level 2
Level 3
$
43,455
$
43,455
$
— $
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 Value
Foreign Large Cap Core
Other
Total
5,109,834
87,821
1,824,796
1,770,664
195,319
198,884
427,409
964,827
456,100
43,674
—
—
—
—
—
—
—
—
—
—
5,109,834
87,821
1,824,796
1,770,664
195,319
198,884
427,409
964,827
456,100
43,674
$
11,122,783
$
43,455
$
11,079,328
$
—
—
—
—
—
—
—
—
—
—
—
—
Each mutual fund has been categorized based on its primary investment strategy.
The Company expects to contribute $1,600,000 to its pension plan and $600,000 to its postretirement benefit plan in
fiscal 2018.
The following table reflects expected future benefit payments:
Fiscal year ending September 30
2018
2019
2020
2021
2022
2023-2027
$
Pension
Plan
Postretirement
Plan
$
817,861
879,779
966,930
1,041,200
1,139,637
6,981,849
618,241
644,666
671,228
710,495
749,674
4,148,403
The Company also 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 $361,702, $353,793 and $338,896 for 2017, 2016 and 2015, respectively.
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, 2017, 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, 2016 and 2015, the Board approved
stock option grants to certain officers. As required by the KESOP, each option's exercise price per share equaled the
57
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.
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
Years Ended September 30,
2017
26.09%
3.81%
7.00
2.20%
2016
28.78%
3.99%
7.00
2.10%
2015
34.34%
4.11%
7.00
1.98%
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, 2017, 2016 and 2015 are
summarized below. The information contained in the tables below have been restated to reflect the effect of the stock
split:
Options outstanding, September 30, 2014
Options granted
Options exercised
Options expired
Options forfeited
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
Number of
Shares
Weighted-
Average Exercise
Price
$
57,000
25,500
(3,900)
—
—
78,600
24,000
(3,300)
—
(12,000)
87,300
25,500
(11,225)
—
—
12.65
14.40
12.66
—
—
13.22
14.15
12.65
—
13.20
13.50
16.37
12.67
—
—
Weighted-
Average
Remaining
Contractual
Terms (years)
8.8
Aggregate
Intrinsic Value 1
$
34,840
8.3
43,086
7.8
200,211
Options outstanding, September 30, 2017
101,575
$
14.31
Vested and exercisable at September 30,
2017
101,575
$
14.31
1
Aggregate intrinsic value includes only those options where the exercise price is below the market price.
58
7.6
7.6
$
1,448,338
$
1,448,338
2017
Years Ended September 30,
2016
2015
Weighted-average grant date option fair value
$
2.89
$
2.69
$
Stock option expense
Intrinsic value of options exercised
Proceeds from exercise of stock options
73,780
99,929
142,241
64,640
8,418
41,762
3.28
83,640
5,624
49,366
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 36,446, 52,146 and 12,647 shares in 2017, 2016 and 2015,
respectively. As of September 30, 2017, the Company had 448,973 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, a minimum of 40% of the monthly retainer fee paid to each non-employee
director of Resources was paid in shares of common stock (“Restricted Stock”). 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 business day of the month. The 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
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 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. Effective October 1, 2016, the
Board of Directors amended the Plan to remove the requirement that directors take a minimum 40% of their retainer in
Restricted Stock for those directors who owned at least 10,000 shares of Resources stock.
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:
2017
2016
2015
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
Beginning of year
balance
107,023
$
Granted
Vested
Forfeited
4,870
—
—
10.11
16.77
—
—
100,373
$
6,650
—
—
9.80
14.79
—
—
94,267
$
6,106
—
—
9.53
13.92
—
—
End of year balance
111,893
$
10.56
107,023
$
10.11
100,373
$
9.80
The fair market value of the Restricted Stock issued as compensation during fiscal 2017, 2016 and 2015 was $99,400,
$98,334 and $85,000. No Restricted Stock vested or was forfeited during fiscal 2017, 2016 and 2015.
As of September 30, 2017, the Company had 85,233 shares available for issuance under the Plan.
59
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 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 Restricted Stock Plan originally authorized 300,000 shares to be available for issuance; however, following the
three-for-two stock split on March 1, 2017, the total authorized shares increased to 450,000. As of September 30,
2017, no shares have been granted under the Restricted Stock Plan.
Stock Bonus Plan
Under the Stock Bonus Plan, executive officers are encouraged to own a position in the Company’s common stock of
at least 50% of the value of their annual salary. To promote this policy, the Plan provides that all officers with stock
ownership positions below 50% of the value of their annual salaries must, unless approved by the Committee, use no
less than 50% of any performance bonus to purchase Company common stock. Shares from the Stock Bonus Plan may
also 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, 2,813 and 4,097 shares valued at $30,154, $39,819 and $59,332,
respectively, in 2017, 2016 and 2015. As of September 30, 2017 the Company had 4,785 shares of stock available for
issuance under the Stock Bonus Plan.
11.
COMMITMENTS AND CONTINGENCIES
Long-Term Contracts
Due to the nature of the natural gas distribution business, the Company enters into agreements with both suppliers and
pipelines to contract for natural gas commodity purchases, storage capacity and pipeline delivery capacity. The
Company obtains most of its regulated natural gas supply through an asset management contract between Roanoke
Gas and a third party asset manager. The Company 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, the Company has designated the asset manager to act as agent for the Company's
storage capacity and all gas balances in storage. The Company retains ownership of gas in storage. Under provisions
of this contract, the Company 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, 2017 for the remainder of the contract period. The current asset management contract will expire in
March 2018.
Year
2017-2018
Total
Natural Gas Contracts
(In Decatherms)
369,828
369,828
60
The Company 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, 2017. 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 $28,496,000, $24,852,000 and $33,405,000 under the asset management, pipeline and
storage contracts in fiscal years 2017, 2016 and 2015, respectively. The table below details the pipeline and storage
capacity obligations as of September 30, 2017 for the remainder of the contract period.
Year
2017-2018
2018-2019
2019-2020
2020-2021
2021-2022
Thereafter
Total
Other Contracts
$
Pipeline and
Storage Capacity
11,232,436
10,113,115
7,633,155
5,221,751
4,565,743
3,067,053
$
41,833,253
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, 2017 and 2016, respectively:
Assets:
Interest rate swaps
Total
Liabilities:
Natural gas purchases
Total
Fair Value Measurements - September 30, 2017
Quoted Prices in
Active Markets
Level 1
Significant Other
Observable
Inputs
Level 2
Significant
Unobservable
Inputs
Level 3
Fair Value
$
$
$
$
$
$
$
$
116,843
116,843
805,159
805,159
61
— $
— $
116,843
116,843
— $
— $
805,159
805,159
$
$
$
$
—
—
—
—
Liabilities:
Natural gas purchases
Total
Fair Value Measurements - September 30, 2016
Quoted Prices in
Active Markets
Level 1
Significant Other
Observable
Inputs
Level 2
Significant
Unobservable
Inputs
Level 3
Fair Value
$
$
1,052,930
1,052,930
$
$
— $
— $
1,052,930
1,052,930
$
$
—
—
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, 2017 and 2016, 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, 2017 and 2016.
Liabilities:
Long-term debt
Total
Liabilities:
Long-term debt
Total
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
Fair Value Measurements - September 30, 2016
Carrying
Amount
Quoted Prices in
Active Markets
Level 1
Significant Other
Observable
Inputs
Level 2
Significant
Unobservable
Inputs
Level 3
$
$
33,896,200
33,896,200
$
$
— $
— $
— $
— $
36,163,523
36,163,523
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 and estimated credit spread extrapolated based on market
conditions since the issuance of the debt. A 64 basis point increase in the 20-year Treasury in fiscal 2017 partially
offset by a reduction in the assumed credit spreads accounted for the smaller differential between the fair value and
the carrying amount of the notes payable at the end of the year. 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.
62
13.
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Quarterly financial data for the years ended September 30, 2017 and 2016 is summarized as follows:
2017
Operating revenues
Gross margin
Operating income
Net income
Earnings per share of common stock:
Basic
Diluted
2016
Operating revenues
Gross margin
Operating income
Net income
Earnings per share of common stock:
Basic
Diluted
14.
SUBSEQUENT EVENTS
First
Quarter
18,788,585
9,390,905
3,982,275
2,232,218
0.31
0.31
First
Quarter
16,010,056
8,738,116
3,498,052
1,922,790
0.27
0.27
$
$
$
$
$
$
$
$
$
$
$
$
Second
Quarter
21,900,013
10,829,730
5,589,207
3,225,199
0.45
0.45
Second
Quarter
21,777,773
10,649,269
5,444,314
3,111,447
0.44
0.44
$
$
$
$
$
$
$
$
$
$
$
$
Third
Quarter
11,435,824
6,634,402
1,328,207
615,562
0.09
0.08
Third
Quarter
11,295,197
6,312,340
1,453,350
627,068
0.09
0.09
$
$
$
$
$
$
$
$
$
$
$
$
Fourth
Quarter
10,172,448
5,954,120
766,620
159,886
0.02
0.02
Fourth
Quarter
9,980,265
5,865,189
816,376
145,561
0.02
0.02
$
$
$
$
$
$
$
$
$
$
$
$
On October 2, 2017, Roanoke Gas entered into two 10-year unsecured notes with Prudential Investment Management
in the total principal amount of $8,000,000. The notes have an annual interest rate of 3.58%. The proceeds from the
note will be used to convert a portion of the Company's line-of-credit balance into longer-term financing.
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.
* * * * * *
63
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, 2017, 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, 2017.
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, 2017, 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, 2017, 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, 2017.
64
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
RGC Resources, Inc.
Roanoke, Virginia
We have audited RGC Resources, Inc. and Subsidiaries (“the Company”)’s internal control over financial reporting as of September 30,
2017, based on criteria established in Internal Control-Integrated Framework - 2013 issued by the Committee of Sponsoring Organizations
of the Treadway Commission (COSO). RGC Resources, Inc. and Subsidiaries’ 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 conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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.
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.
In our opinion, RGC Resources, Inc. and Subsidiaries (“the Company”) maintained, in all material respects, effective internal control
over financial reporting as of September 30, 2017, based on criteria established in Internal Control-Integrated Framework - 2013 issued
by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the
consolidated balance sheets as of September 30, 2017 and 2016 and the related consolidated statements of income, comprehensive income,
stockholders’ equity, and cash flows of RGC Resources, Inc. and Subsidiaries for each of the years in the three year period ended September
30, 2017, and our report dated December 8, 2017 expressed an unqualified opinion.
CERTIFIED PUBLIC ACCOUNTANTS
Blacksburg, Virginia
December 8, 2017
65
Item 9B.
Other Information.
None
66
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 2018 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 2018
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, George W. Logan 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 2018 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 2018 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 2018 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 2018 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 2018 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 2018
Annual Meeting of Shareholders of Resources is incorporated herein by reference.
67
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:
10 (f)
10 (o)
FTS Service Agreement effective April 1, 2017 between Columbia Gas Transmission LLC and Roanoke Gas
Company
FSS Service Agreement between Saltville Gas Storage Company L.L.C. and Roanoke Gas Company dated
November 21, 2012
10 (i)(i)
RGC Resources, Inc. Amended and Restated Restricted Stock Plan for Outside Directors
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, 2017, 2016 and 2015, formatted in XBRL (eXtensible Business Reporting Language);
Consolidated Balance Sheets at September 30, 2017 and 2016, (ii) Consolidated Statements of Income for
the years ended September 30, 2017, 2016 and 2015, (iii) Consolidated Statements of Comprehensive
Income for the years ended September 30, 2017, 2016 and 2015, (iv) Consolidated Statements of
Stockholders’ Equity for the years ended September 30, 2017, 2016 and 2015, (v) Consolidated Statements
of Cash Flows for the years ended September 30, 2017, 2016 and 2015, 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.
68
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 8, 2017
Date
69
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 8, 2017
John S. D'Orazio
Date
President and Chief Executive
Officer, Director
/S/ PAUL W. NESTER
December 8, 2017
Paul W. Nester
Date
Vice President, Treasurer and CFO
(principal accounting and financial
officer)
/S/ JOHN B. WILLIAMSON, III
December 8, 2017
Chairman of the Board and Director
John B. Williamson, III
Date
/S/ NANCY H. AGEE
December 8, 2017
Director
Nancy H. Agee
Date
/S/ ABNEY S. BOXLEY, III
December 8, 2017
Director
Abney S. Boxley, III
Date
/S/ MARYELLEN F. GOODLATTE
December 8, 2017
Director
Maryellen F. Goodlatte
Date
/S/ J. ALLEN LAYMAN
J. Allen Layman
December 8, 2017
Director
Date
/S/ GEORGE W. LOGAN
George W. Logan
December 8, 2017
Director
Date
/S/ S. FRANK SMITH
S. Frank Smith
December 8, 2017
Director
Date
/S/ RAYMOND D. SMOOT, JR.
December 8, 2017
Director
Raymond D. Smoot, Jr.
Date
70
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
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)
10 (y)
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
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 as of November 1, 2013 (incorporated herein by reference to
Exhibit 10.1 on Form 8-K as filed October 9, 2013 (SEC file number reference 0-367))
Notice of Renewal of Natural Gas Asset Management Agreement originally dated November 1,
2013 between Sequent Energy Management and Roanoke Gas Company with an effective date of
March 31, 2017 (incorporated by reference to Exhibit 10.4 of Form 10-Q as filed August 4, 2016)
Guaranty Agreement between RGC Resources, Inc. and Sequent Energy Management effective June
7, 2016. (incorporated herein by reference to Exhibit 10.5 on Form 10-Q as filed August 4, 2016)
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 (z)
10 (a)(a)
10 (b)(b)
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 (c)(c)
P Resolution of the Council for the Town of Troutville, Virginia dated November 4, 1968
(incorporated herein by reference to Exhibit 10(g) of Registration Statement No. 33-11383, on Form
S-4, filed with the Commission on January 16, 1987)
10 (d)(d)
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)
10 (p)(p)
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
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 Paul W. Nester effective May 1,
2015 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed May 5, 2015)
Change in Control Agreement by and between RGC Resources, Inc. and Robert L. Wells, II
effective May 1, 2015 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed May
5, 2015)
Change in Control Agreement between RGC Resources, Inc. and Mr. Carl J. Shockley effective
May 1, 2015 (incorporated herein by reference to Exhibit 10.3 on Form 8-K as filed May 5, 2015)
Change in Control Agreement between RGC Resources, Inc. and John S. D'Orazio effective April 1,
2016 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed April 4, 2016)
Revolving Line of Credit Note in the original principal amount of $30,000,000 by Roanoke Gas
Company in favor of Wells Fargo Bank, N.A. dated March 27, 2017 (incorporated herein by
reference to Exhibit 10.1 on Form 8-K as filed March 29, 2017)
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 (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)
10 (f)(f)(f)
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)
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))
Unconditional guaranty by and between RGC Resources, Inc. and Wachovia Bank, National
Association, dated March 23, 2009 for the benefit of Roanoke Gas Company (incorporated by
reference to Exhibit 10.2 on Form 8-K as filed March 26, 2009 (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)
Promissory Note dated December 29, 2015 by RGC Midstream, LLC in the principal amount of
$15,000,000 in favor of Union Bank &Trust due December 29, 2020 (incorporated by reference to
Exhibit 10.2 on Form 8-K as filed December 31, 2015)
Promissory Note dated December 29, 2015 by RGC Midstream, LLC in the principle amount of
$10,000,000 in favor of Branch Banking and Trust Company due December 29, 2020 (incorporated
by reference to Exhibit 10.3 on Form 8-K as filed December 31, 2015)
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)
Promissory Note dated November 1, 2016 in the principle amount of $7,000,000 in favor of Branch
Banking and Trust Company due November 1, 2021 (incorporated by reference to Exhibit 10.2 on
Form 8-K as filed November 7, 2016)
10 (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) **
10 (o)(o)(o) **
10 (p)(p)(p)
13
21
23
31.1
31.2
32.1*
32.2*
101
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)
Second Amended and Restated Limited Liability Company Agreement of Mountain Valley Pipeline,
LLC dated March 10, 2015 (incorporated by reference to Exhibit 10.1 on Form 10-Q as filed
February 5, 2016)
First Amendment to Second Amended and Restated Limited Liability Agreement of Mountain
Valley Pipeline, LLC (incorporated by reference to Exhibit 10.1 on Form 10-Q as filed May 6,
2016)
Second Amendment to Second Amended and Restated Limited Liability Company Agreement of
Mountain Valley Pipeline, LLC dated October 24, 2016 (incorporated by reference to Exhibit 10.1
on the Quarterly Report on Form 10-Q as filed February 8, 2017)
Guaranty Agreement by RGC Resources, Inc. in favor of Mountain Valley Pipeline, LLC dated
October 1, 2015 (incorporated herein by reference to Exhibit 10.2 on Form 10-Q as filed February
5, 2016)
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, 2017, 2016 and 2015, formatted in XBRL (eXtensible Business Reporting
Language); Consolidated Balance Sheets at September 30, 2017 and 2016, (ii) Consolidated
Statements of Income for the years ended September 30, 2017, 2016 and 2015, (iii) Consolidated
Statements of Comprehensive Income for the years ended September 30, 2017. 2016 and 2015, (iv)
Consolidated Statements of Stockholders’ Equity for the years ended September 30, 2017, 2016 and
2015, (v) Consolidated Statements of Cash Flows for the years ended September 30, 2017, 2016
and 2015, 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.
Exhibit 10(f)
Service Agreement No. 181709
Revision No. 0
FTS SERVICE AGREEMENT
THIS AGREEMENT is made and entered into this 21 day of October, 2016, by and between COLUMBIA
GAS TRANSMISSION, LLC ("Transporter") and ROANOKE GAS COMPANY ("Shipper").
WITNESSETH: That in consideration of the mutual covenants herein contained, the parties hereto agree
as follows:
Section 1. Service to be Rendered. Transporter shall perform and Shipper shall receive service in
accordance with the provisions of the effective FTS Rate Schedule and applicable General Terms and
Conditions of Transporter's FERC Gas Tariff, Fourth Revised Volume No. 1 ("Tariff"), on file with the Federal
Energy Regulatory Commission ("Commission"), as the same may be amended or superseded in accordance
with the rules and regulations of the Commission. The maximum obligation of Transporter to deliver gas
hereunder to or for Shipper, the designation of the points of delivery at which Transporter shall deliver or
cause gas to be delivered to or for Shipper, and the points of receipt at which Shipper shall deliver or cause
gas to be delivered, are specified in Appendix A, as the same may be amended from time to time by
agreement between Shipper and Transporter, or in accordance with the rules and regulations of the
Commission.
Section 2. Term. Service under this Agreement shall commence as of April 1, 2017, and shall continue in
full force and effect until March 31, 2027. Pre-granted abandonment shall apply upon termination of this
Agreement, subject to any right of first refusal Shipper may have under the Commission's regulations and
Transporter's Tariff.
Section 3. Rates. Shipper shall pay Transporter the charges and furnish Retainage as described in the
above-referenced Rate Schedule, unless otherwise agreed to by the parties in writing and specified as an
amendment to this Service Agreement. Transporter may agree to discount its rate to Shipper below
Transporter's maximum rate, but not less than Transporter's minimum rate. Such discounted rate may apply to:
(a) specified quantities (contract demand or commodity quantities); (b) specified quantities above or below a
certain level or all quantities if quantities exceed a certain level; (c) quantities during specified time periods; (d)
quantities at specified points, locations, or other defined geographical areas; (e) that a specified discounted
rate will apply in a specified relationship to the quantities actually transported (i.e., that the reservation charge
will be adjusted in a specified relationship to quantities actually transported); (f) production and/or reserves
committed by the Shipper; and (g) based on a formula including, but not limited to, published index prices for
specific receipt and/or delivery points or other agreed-upon pricing points, provided that the resulting rate shall
be no lower than the minimum nor higher than the maximum applicable rate set forth in the Tariff. In addition,
the discount agreement may include a provision that if one rate component which was at or below the
applicable maximum rate at the time the discount agreement was executed subsequently exceeds the
applicable maximum rate due to a change in Transporter's maximum rate so that such rate component must be
adjusted downward to equal the new applicable maximum rate, then other rate components may be adjusted
upward to achieve the agreed overall rate, so long as none of the resulting rate components exceed the
maximum rate applicable to that rate component. Such changes to rate components shall be applied
prospectively, commencing with the date a Commission order accepts revised tariff sections. However, nothing
contained herein shall be construed to alter a refund obligation under applicable law for any period during
which rates, which had been charged under a discount agreement, exceeded rates which ultimately are found
to be just and reasonable.
Section 4. Notices. Notices to Transporter under this Agreement shall be addressed to it at 5151 San
Felipe, Suite 2500, Houston, Texas 77056, Attention: Customer Services and notices to Shipper shall be
addressed to it at Roanoke Gas Company, President, P.O. Box 13007, Roanoke, VA 24030, Attention:
Roanoke Gas Company, until changed by either party by written notice.
Section 5. Superseded Agreements. This Service Agreement supersedes and cancels, as of the effective
date hereof, the following Service Agreement(s): N/A.
ROANOKE GAS COMPANY
COLUMBIA GAS TRANSMISSION, LLC
By
Title
Date
/s/ Michael Gagnet
October 21, 2016
By
Title
Date
/s/ Millie Moran
VP, Cust Svcs & Bus Int
October 19, 2016
Revision No. 0
Appendix A to Service Agreement No. 181709
Under Rate Schedule FTS
between Columbia Gas Transmission, LLC ("Transporter")
and Roanoke Gas Company ("Shipper").
Transportation Demand
Begin Date
End Date
Recurrence Interval
Transportation Demand Dth/day
04/01/2017
03/31/2027
7,000
1/1 - 12/31
Primary Receipt Points
Begin Date
04/01/2017
End Date
03/31/2017
Scheduling
Point No.
801
Scheduling Point Name
TCO-LEACH
Measuring
Point No.
801
Measuring Point Name
TCO-LEACH
Maximum
Daily
Quantity
(Dth/day)
7,000
Minimum
Receipt
Pressure
Obligation
(psig) 1/
Recurrence
Interval
1/1 - 12/31
Primary Delivery Points
Maximum
Daily
Delivery
Design Daily
Minimum
Delivery
Pressure
Begin Date
End Date
Scheduling
Point No.
04/01/2017
03/31/2027
62
Scheduling Point Name
ROANOKE GAS
COMPANY
Measuring
Point No.
62
Measuring Point Name
ROANOKE GAS
COMPANY
Obligation
(Dth/day) 1/
Quantity
(Dth/day) 1/
Obligation
(psig) 1/
Recurrence
Interval
7,000
1/1-12/31
1/
Application of MDDOs, DDQs and ADQs, minimum pressure and/or hourly flowrate shall be as follows:
The Master List of Interconnects ("MLI") as defined in Section 1 of the General Terms and Conditions of Transporter's Tariff is incorporated herein by reference
for purposes of listing valid secondary interruptible receipt points and delivery points.
Yes X No (Check applicable blank) Transporter and Shipper have mutually agreed to a Regulatory Restructuring Reduction Option pursuant to Section
42 of the General Terms and Conditions of Transporter's FERC Gas Tariff.
Yes X No (Check applicable blank) Shipper has a contractual right of first refusal equivalent to the right of first refusal set forth from time to time in
Section 4 of the General Terms and Conditions of Transporter's FERC Gas Tariff.
X Yes
applicable, set forth in Transporter's currently effective Rate Schedule SST Service Agreement No. 79864 Appendix A with Shipper, which are incorporated herein
by reference.
No (Check applicable blank) All gas shall be delivered at existing points of interconnection within the MDDOs, ADQs and/or DDQs, as
Yes X No (Check applicable blank) This Service Agreement covers interim capacity sold pursuant to the provisions of General Terms and Conditions
Section 4. Right of first refusal rights, if any, applicable to this interim capacity are limited as provided for in General Terms and Conditions Section 4.
Yes X No (Check applicable blank) This Service Agreement covers offsystem capacity sold pursuant to Section 47 of the General Terms and
Conditions. Right of first refusal rights, if any, applicable to this offsystem capacity are limited as provided for in General Terms and Conditions Section 47.
ROANOKE GAS COMPANY
COLUMBIA GAS TRANSMISSION, LLC
By
Title
Date
Michael Gagnet
October 21, 2016
By
Title
Date
Millie Moran
VP, Cust Svcs & Bus Int
October 19, 2016
SERVICE AGREEMENT
FOR RATE SCHEDULE FSS
Exhibit 10(o)
Date: Nov 21, 2013
Contract No. 420074-R1
This AGREEMENT is entered into by and between SALTVILLE GAS STORAGE COMPANY L.L.C.,
(“Saltville”) and ROANOKE GAS COMPANY (“Customer”).
WHEREAS, Saltville and Customer desire to enter into the Service Agreement for storage service under Rate Schedule FSS>
NO THEREFORE, in consideration of the premises and of the mutual covenants herein contained,
The parties do agree as follows:
1.) Saltville agrees to provide and Customer agrees to take and pay for service under this Agreement pursuant to Saltville’s Rate
Schedule FSS and the General Terms and Conditions of Saltville’s Tariff, which are incorporated herein by reference and made
a part hereof.
2.) The Maximum Storage Quantity (“MSQ”), Maximum Daily Withdrawal Quantity, (“MDWQ”) and Maximum Daily Injection Quantity
(“MDIQ”) and the Primary Point(s) of Receipt and Delivery applicable to service under this Agreement are listed on Exhibit A
attached hereto. Exhibit A constitutes a part of this agreement and is incorporated herein.
3.) This Agreement shall be effective on April 1, 2013 and shall continue until March 31, 2018 (“Primary Term”);provided, however,
that if the Primary Term is of a duration of more than one year, then the contract shall remain in force and effect and the contract
term will automatically roll-over for additional five year increments (“Secondary Term”) unless Customer, one year prior to the
expiration of the Primary Term or a Secondary Term, provides written notice to Saltville of either (1) exercise its right-of-first-
refusal in accord with Section 8 of Rate Schedule FSS. Provided further, if the Commission or other governmental body having
jurisdiction over the service rendered pursuant to this Agreement authorizes abandonment of such service, this Agreement
shall terminate on the abandonment date permitted by the Commission or such other governmental body. Any portions of this
Agreement necessary to correct or cash-out imbalances under this Agreement as required by the General Terms and
Conditions of Saltville’s FERC Gas Tariff shall survive the other parts of this Agreement until such time as such balancing has
been accomplished.
4.) Maximum rates, charges, and fees shall be applicable to service pursuant to this Agreement except during the specified term
of a discounted or negotiated rate to which Customer and Saltville have agreed. Provisions governing such discounted rate
shall be as specified in the Discount Confirmation provided to Customer by Saltville. Provisions governing such negotiated rate
and term shall be as specified on an appropriate Statement of Negotiated Rates filed, with the consent of Customer, as part
of Saltville’s Tariff. It is further agreed that Saltville may seek authorization from the Commission and/or other appropriate body
at any time and from time to time to change any rates, charges or other provisions in the applicable Rate Schedule and General
Terms and Conditions of Saltville’s Tariff and Saltville shall have the right to place such changes in effect in accordance with
the Natural Gas Act. Nothing contained herein shall be construed to deny Customer any rights it may have under the Natural
Gas Act, including the right to participate fully in rate or other proceedings by intervention or otherwise to contest increased
rates in whole or in part.
5.) Unless otherwise required in the Tariff, all notices shall be in writing and mailed to the applicable address below or transmitted
via facsimile. Customer or Saltville may change the addresses or other information below by written notice to the other without
the necessity of amending this Agreement:
SALTVILLE:
Customer:
SALTVILLE GAS STORAGE COMPANY L.L.C.
5400 WESTHEIMER COURT
ROUTE CODE: GTMKTSERV
HOUSTON, TX 77056
ROANOKE GAS COMPANY
PO BOX 13007
ROANOKE, VA 24030-3007
6.) The interpretation and performance of this Agreement shall be in accordance with the laws of the Commonwealth of Virginia
without recourse to the law regarding the conflict of laws. This Agreement and the obligations of the parties are subject to all
present and future valid laws with respect to the subject matter, State and Federal, and to all valid present and future orders,
rules and regulations of duly constituted authorities having jurisdiction.
7.) This Agreement supersedes and cancels, as of the effective date of this Agreement, the contract(s) between the parties hereto
as described below if applicable:
[None or an appropriate description]
Page 1 of 2
Contract No.: 420074-R1
IN WITNESS WHEREOF, the parties hereto have caused this agreement to be signed by their Respective Officers and/or
Representatives thereunto duly authorized to be effective as of the date stated above.
ROANOKE GAS COMPANY
SALTVILLE GAS STORAGE COMPANY L.L.C.
By: /s/ John S. D'Orazio
Title: President & CEO
Date: Nov 21, 2012
By: /s/ Patti Fitzgerald
Title: VP, Marketing
Date: 12/6/12
Page 2 of 2
Exhibit A dated November 21, 2012
To the Firm Storage Service Agreement date November 21, 2012
Between
Saltville Gas Storage Company L.L.C. (Saltville)
and
ROANOKE GAS COMPANY (Customer)
Exhibit A Effective Date: 04/04/2013
I.
II.
Primary Point(S) of Receipt:
Meter
Number
44009
MDRO
1,500
Description
EARLY GROVE REC/INJ (59147)
Primary Point(S) of Delivery:
Meter
Number
44147
MDDO
2,500
Description
EARLY GROVE DEL/WD (59009)
County
WASHINGTON
State
VA
County
WASHINGTON VA
State
III.
Service Levels:
1.) Quantities:
Maximum Storage Quantity (MSQ):
Maximum Daily Injection Quantity (MDIQ):
Maximum Daily Withdrawal Quantity (MDWQ):
250,000 Dth
1,500 Dth/Day
2,500 Dth/Day
SIGNED FOR IDENTIFICATION:
SALTVILLE: /s/ Patti Fitzgerald
CUSTOMER: /s/ John S. D’Orazio
SUPERSEDES EXHIBIT A DATED N/A
Legal Approved by CMP, Capacity Approved by WW, Credit Approved by GW
Page 1 of 1
Contract No: 420074-R1A1
AMENDED AND RESTATED
RESTRICTED STOCK PLAN FOR
OUTSIDE DIRECTORS OF RGC RESOURCES, INC.
Exhibit 10(i)(i)
1.
Assumption of Plan by RGC Resources, Inc.; Purpose
This Amended and Restated Restricted Stock Plan for Outside Directors of RGC Resources,
Inc. (as successor to Roanoke Gas Company) (the "Plan") amends and restates the Roanoke Gas
Company Restricted Stock Plan for Outside Directors (the "Original Plan"), which was adopted by the
Board of Directors of Roanoke Gas Company ("Roanoke Gas") on September 23, 1996, and became
effective as of such date upon approval of the Original Plan by the shareholders of Roanoke Gas company
on January 27, 1997. The amendment and restatement of the Original Plan and the assumption of
liabilities hereunder are undertaken by RGC Resources, Inc., (the “Company”), as successor to Roanoke
Gas, in connection with the reorganization of Roanoke Gas into a holding company structure (the
“Reorganization”) as part of which Roanoke Gas became a wholly-owned subsidiary of RGC Resources
as of July 1, 1999. The Reorganization is being effected pursuant to an Agreement and Plan of Merger
dated as of September 28, 1998 (the “Merger Agreement”), which is approved by the stockholders of
Roanoke Gas on March 31, 1999, and pursuant to which Roanoke Gas and RGC Resources agreed that
from and after the effective date of the Merger provided for therein, this Plan would utilize RGC
Resources common stock instead of Roanoke Gas common stock. Accordingly, as of the effective date
hereof, RGC Resources assumes the obligations of Roanoke Gas under the Original Plan and undertakes
to carry out all responsibilities of the Company specified herein. Roanoke Gas consents and agrees to
the assumption by RGC Resources of the Roanoke Gas’ responsibilities under this Plan.
The Amended and Restated Restricted Stock Plan for Outside Directors of RGC Resources, Inc.
is intended to advance the interests of RGC Resources, Inc., its shareholders, and its affiliates by
encouraging and enabling outside directors upon whose judgment, initiative and effort the Company
relies for the successful conduct of its business, to acquire and retain a proprietary interest in the Company
by ownership of its stock.
2.
Definitions
The following definitions apply to this Plan and to the Election Forms:
(a)
Beneficiary or Beneficiaries means a person or persons or other entity designated on
a Beneficiary Designation Form by a Participant to receive Company Stock under this
Plan if the Participant dies. If there is no valid designation by the Participant, or if
the designated Beneficiary or Beneficiaries fail to survive the Participant, the
Participant's Beneficiary is the first of the following who survives the Participant: the
Participant's spouse (the person legally married to the Participant when the Participant
dies); the Participant's children in equal shares; the Participant's other surviving issue,
per stirpes; the Participant's parents; and the Participant's estate.
1
(b)
Beneficiary Designation Form means a form acceptable to the Chairman of the
Committee or his designee used by a Participant according to this Plan to name the
Beneficiary or Beneficiaries who will receive all the Company Stock under this Plan
if the Participant dies.
(c)
Board means the Board of Directors of the Company.
(d)
Change in Control means a change in control of a nature that would be required to
be reported (assuming such event has not been "previously reported") in response to
Item l (a) of the Current Report on Form 8-K, as in effect on the date hereof, pursuant
to Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended ("Exchange
Act"); provided that, notwithstanding the foregoing and without limitation, such a
change in control shall be deemed to have occurred at such time as (i) any Person is
or becomes the "beneficial owner" (as defined in Rule 13d-3 or Rule 13d-5 under the
Exchange Act as in effect on the date hereof), directly or indirectly, of 20% or more
of the combined voting power of the Company's voting securities; (ii) the incumbent
Board ceases for any reason to constitute at least the majority of the Board, provided
that any person becoming a director subsequent to the date hereof whose election, or
nomination for election by the Company's shareholders, was approved by a vote of at
least 75% of the directors comprising the incumbent Board (either by a specific vote
or by approval of the proxy statement of the Company in which such person is named
as a nominee for director, without objection to such nomination) shall be, for purposes
of this clause (ii), considered as though such person were a member of the incumbent
Board; (iii) all or substantially all of the assets of the Company are sold, transferred
or conveyed by any means, including, but not limited to, direct purchase or merger, if
the transferee is not controlled by the Company, control meaning the ownership of
more than 50% of the combined voting power of such entity's voting securities; or (iv)
the Company is merged or consolidated with another corporation or entity and as a
result of such merger or consolidation less than 75% of the outstanding voting securities
of the surviving or resulting corporation or entity shall be owned in the aggregate by
the former shareholders of the Company. Notwithstanding anything in the foregoing
to the contrary, no Change in Control shall be deemed to have occurred for purposes
of the Plan by virtue of any transaction (i) which results in a Participant or a group of
Persons which includes the Participant, acquiring, directly or indirectly, 20% or more
of the combined voting power of the Company's voting securities; or (ii) which results
in the Company, any affiliate of the Company or any profit-sharing plan, employee
stock ownership plan or employee benefit plan of the Company or any of its affiliates
(or any trustee of or fiduciary with respect to any such plan acting in such capacity)
acquiring, directly or indirectly, 20% or more of the combined voting power of the
Company's voting securities.
(e)
Committee means the Compensation Committee of the Board.
(f)
Company means RGC Resources, Inc.
(g)
Company Stock means the common stock, $5 par value of the Company.
2
(h)
Compensation means a Member's Retainer Fee for the Deferral Year.
(i)
Election Form means a document governed by the provisions of Section 4 of this Plan,
including the portion that is the related Beneficiary Designation Form, that applies to
all of that Participant's shares of Restricted Stock under the Plan.
(j)
Directors means those duly named members of the Board.
(k)
(1)
Election Date means the date established by this Plan as the date before which a Member
must submit a valid Election Form to the Committee. For each Plan Year, the Election
Date is July 31. However, for an individual who becomes a Member during a Plan
Year, the Election Date is the thirtieth day following the date that he becomes a Member.
Despite the two preceding sentences, the Committee may set an earlier date as the
Election Date for any Plan Year.
Employee means an individual with whom either the Company or its affiliates has an
employer-employee relationship as determined for Federal Insurance Contribution Act
purposes and Federal Unemployment Tax Act purposes, including subsection 3401(c)
of the Internal Revenue Code and regulations promulgated under that subsection.
(m)
Family Trust means a trust for which the applicable Participant serves as a trustee and
which is for the benefit of family members of the Participant.
(n) Members means Directors who are not simultaneously Employees.
(o)
Participant means a Member during the Plan Year (including any Family Trust to
which Restricted Stock is transferred by him or her in accordance with Section 6 of
this Plan).
(p)
Plan means the Company's Restricted Stock Plan for Outside Directors.
(q)
(r)
(s)
(t)
Plan Year means a fiscal year ending September 30 during which the Plan is in
effect and during which a Member receives a portion or all of his Compensation in
Restricted Stock hereunder.
Person means person within the meaning of Sections 3(a)(9) and 13(d)(3) of the
Securities Exchange Act of 1934.
Restricted Stock means Company Stock issued to Participants under the Plan and
subject to the vesting and non-transferability provision of the Plan.
Retainer Fee means that portion of a Director's Compensation that is fixed and paid
without regard to his attendance at meetings.
3
3.
Restricted Stock Payments
Unless a Participant owns at least 10,000 shares of Company Stock, on the first day of each
month during each Plan Year, forty percent (40%) of a Participant’s Compensation for the month shall
be paid in shares of Restricted Stock of the Company. In determining the number of shares to be issued
pursuant to the preceding sentence, the Fair Market Value of the Restricted Stock under the Plan shall,
for each calendar month, be calculated based on the closing sales price of the Company's common
stock on the Nasdaq Global Market on the first day of the month, if the first day of the month is a
trading day, or if not, the first trading day prior to the first day of the month.
4.
Additional Restricted Stock Election
(a)
(b)
(c)
Before each Plan Year's Election Date, each Member will be provided with an Election
Form and a Beneficiary Designation Form. Subject to approval of the Board or the
Committee, a Member may elect to receive up to 100% of his Compensation for the
Plan Year in Restricted Stock.
An additional Restricted Stock election is valid when an Election Form is completed,
signed by the electing Member, received by the Committee Chairman and approved
by the Board or the Committee on or before the Election Date.
A Member may not revoke or amend an Election Form after the Election Date for the
Plan Year. Any revocation before an Election Date is the same as a failure to submit
an Election Form. Any writing signed by a Member expressing an intention to revoke
his Election Form and delivered to a member of the Committee before the close of
business on the relevant Election Date is a revocation.
5.
Vesting
The shares of Restricted Stock of the Company issued under Section 3 and Section 4 of this
Plan shall vest only in the case of a Participant's death, disability, retirement (including not standing
for reelection to the Board), or in the event of a Change in Control of the Company. There shall be no
option to take cash in lieu of stock upon vesting of shares under this Plan.
6.
Nontransferability
No share of Restricted Stock issued hereunder may be sold, transferred, assigned, or pledged
by the Participant until such share has vested in accordance of the terms of this Plan. At the time
the Restricted Stock vests, and, if the Participant has been issued legended certificates of Restricted
Stock, upon the return of such certificates to the Company, a certificate for such vested shares shall
be delivered to the Participant (or the Beneficiary designated by the Participant in the event of death),
free of restrictive legend (other than any required by applicable securities laws). Notwithstanding
the foregoing, no vested shares may be sold, transferred, assigned or pledged by the Participant (or
4
the Beneficiary) unless six months have elapsed between the date of grant of the shares of Restricted
Stock which have vested and the date of the sale, transfer, assignment or pledge of such vested shares.
Notwithstanding the foregoing, a Participant may transfer Restricted Stock to a Family Trust.
7.
Forfeiture
The shares of Restricted Stock issued under Section 3 and Section 4 of this Plan shall
be forfeited to the Company upon a Member's voluntary resignation during his term on the
Board, or removal for cause as a Director.
8.
Stock Certificates
Stock certificates representing the Restricted Stock, together with stock powers or
other instruments of assignment, each endorsed in blank, which will permit transfer to the
Company of all or any portion of the Restricted Stock evidenced by such certificate in the
event it is forfeited, shall be deposited by the recipient with the Company.
9.
Rights as Shareholder
Subject to the terms of this Plan, the Participant, as the owner of the Restricted Stock,
shall have all rights of a shareholder including, but not limited to, voting rights, the right to
receive cash or stock dividends thereon, and the right to participate in any capital adjustment
of the Company. Any distribution with the respect to shares of Restricted Stock other than in
the form of cash shall be held by the Company, and shall be subject to the same restrictions as
the shares with respect to which such distributions were made. The Committee may require
that any or all dividends or other distributions paid on shares of Restricted Stock shall be
automatically sequestered and may be reinvested on an immediate or deferred basis in additional
shares of Company stock, which may be subject to the same restrictions as the Restricted Stock
or such other restrictions as the Committee may determine.
10.
Claims against Participant's Restricted Stock
The shares of Restricted Stock issued pursuant to this Plan are not subject in any manner
to anticipation, alienation, sale, transfer, assignment, pledge, encumbrance, or charge, and any
attempt to do so is void. Moreover, the shares are not subject to attachment or legal process for
a Participant's debts or other obligations. Nothing contained in this Plan gives any Participant
any interest, lien, or claim against any specific asset of the Company.
11.
Amendment or Termination
The Board may at any time suspend or terminate the Plan or may amend it from time
to time in such respects as the Board may deem advisable in order that the Restricted Stock
issued hereunder may conform to any changes in the law or any other respect with which the
Board may deem to be in the best interests of the Company. No such suspension, termination
or amendment of the Plan shall require approval of the shareholders unless shareholder approval
is required by applicable law or stock exchange requirements.
5
12.
Notices
Notices and elections under this Plan must be in writing. A notice or election is deemed
delivered if it is delivered personally or if it is mailed by registered or certified mail to the person
at his last known business address.
13. Waiver
The waiver of a breach of any provision in this Plan does not operate as and may not
be construed as a waiver of any later breach.
14.
Construction
This Plan is created, adopted, and maintained according to the laws of the
Commonwealth of Virginia (except its choice-of-law rules). It is governed by those laws in all
respects. Headings and captions are only for convenience; they do not have substantive meaning.
If a provision of this Plan is not valid or not enforceable, that fact in no way affects the validity
or enforceability of any other provision. Use of the one gender includes all, and the singular
and plural include each other.
15.
Adjustments For Changes in Capitalization
In the event of a reorganization, recapitalization, stock split, stock dividend,
combination of shares, rights offer, liquidation, dissolution, merger, consolidation, spin off, sale
of assets, payment of an extraordinary cash dividend, or any other change in or affecting the
corporate structure or capitalization of the Company, the Committee shall make appropriate
adjustments in the number, price or kind of shares of Restricted Stock authorized to be issued
under this Plan, and in any outstanding shares of Restricted Stock issued hereunder.
16. Withholding Taxes
Whenever the Company is required to issue or transfer shares of Restricted Stock under
this Plan, the Company shall have the right to require the recipient of such Restricted Stock to
remit to the Company an amount sufficient to satisfy any federal, state or local withholding tax
liability prior to the delivery of any certificate for such shares. Whenever under the Plan payments
are to be made in cash, such payments shall be net of an amount sufficient to satisfy any federal,
state or local withholding tax liability.
17.
Indemnification
The Company shall indemnify and hold harmless each person who is or has been a
member of the Committee, or of the Board of Directors, against and from any and all loss,
expense, liability, or costs (including reasonable attorneys' fees) that may be imposed upon or
reasonably incurred by him in connection with or resulting from any claim, action, suit or
6
proceedings to which he may be a party or in which he may be involved by reason of any action
taken or failure to act under the Plan, and against and from any and all amounts paid by him in
settlement thereof with the Company's approval or paid by him in satisfaction of a final judgment
against him in such action, suit, or proceedings, provided he shall give the Company an
opportunity, at its own expense to handle and defend the same before he undertakes to handle
defense on his own behalf. The right of indemnification herein set forth shall not be exclusive
of any other rights of indemnification to which such person may be entitled under the Company's
Articles of Incorporation, or code or regulations, as a matter of law, or otherwise, or any power
that the Company may have to indemnify him or to hold him harmless. It is the Company's
intention that all expenses incurred in connection with the administration of the Plan shall be
borne by the Company rather than by any member of the Committee or the Board of Directors.
18.
Effective Date of the Plan
The Plan is subject to approval by the shareholders of the Company. The Plan will
become effective on the date so approved.
19.
Shares Subject to the Plan
The aggregate number of shares of Company Stock which may be issued in respect to
Restricted Stock shall not exceed 50,000 shares. All shares distributed pursuant to the Plan shall
consist of authorized but unissued shares of the Company.
20.
Power of the Committee
The Committee shall have authority to interpret conclusively the provisions of the Plan,
to adopt such rules and regulations for carrying out the Plan as it may deem advisable, to decide
conclusively all questions of fact arising in the application of the Plan, and to make all other
determinations necessary or advisable for the administration of the Plan. All decisions and acts
of the Committee shall be final and binding upon all affected Plan Participants.
21. Miscellaneous
Transactions under this Plan are intended to comply with Rule 16b-3 (or its successor),
as amended from time to time, promulgated pursuant to the Securities Exchange Act of 1934.
Therefore, to the extent any provision of the Plan or action by a person administering the Plan
fails to so comply, it shall be deemed null and void ab initio to the extent permitted by law and
deemed advisable by the Committee.
As evidence of its adoption and approval of this Plan and approval of the terms and
conditions of each Participant transaction hereunder, the Board has caused this document to be
executed on its behalf, and on behalf of the Company, this 25th day of July, 2016.
By /s/ John S. D'Orazio
John S. D’Orazio
President and CEO, RGC Resources, Inc.
7
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 8, 2017 appearing in this Annual
Report on Form 10-K of RGC Resources, Inc. for the year ended September 30, 2017.
Blacksburg, Virginia
December 8, 2017
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 8, 2017
/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 8, 2017
/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, 2017 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 8, 2017
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, 2017 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 8, 2017
CORPORATE INFORMATION
Nancy Howell Agee
President & CEO, Carilion Clinic
Abney S. Boxley, III
President & CEO, Boxley Materials Company
John S. D’Orazio
President & CEO, RGC Resources, Inc.
Maryellen F. Goodlatte
Attorney & Principal, Glenn Feldmann, Darby & Goodlatte
J. Allen Layman
Private Investor
George W. Logan
Principal, Pine Street Partners, LLC
S. Frank Smith
Consultant, Alpha Coal Sales Company, LLC
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
for participants. For more information,
agent
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
on
Avenue, Roanoke, Virginia,
Monday, February 5, 2018, 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 15, 2017.
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