Key Financial
Information
Year Ending September 30
2016
2015
2014
Net Income
$
5,806,866 $
5,094,415 $
4,708,440
Earnings Per Share
$
1.22 $
1.08 $
1.00
Natural Gas Customers
59,635
59,080
58,553
Additions to Plant
$
17,945,719 $
13,780,356 $
14,715,428
Natural Gas Deliveries (DTH’s)
8,842,605
9,875,007
10,087,651
Stock Price and Dividends
Dividends
$0.85
$0.80
$0.75
$0.70
$0.65
$0.60
$26.00
$24.00
$22.00
$20.00
$18.00
$16.00
$14.00
$12.00
Stock Price
2009
2010
2011
2012
2013
2014
2015
2016
DividendsPerShare
Share Price
Note: Dividends excludes
Dec 2012 $1.00 special
dividend
President’s
Letter
To Our Shareholders
report
We are pleased to provide you with our
2016 annual
reflecting strong
earnings, solid stock performance and
our long-term commitment of providing
safe and reliable natural gas service to
our customers. I am delighted to report
record earnings of $5.8 million or $1.22
per share outstanding, compared to
$1.08 per share last year, or a 13%
improvement.
strong
earnings and operational performance
have contributed to a 17% stock price
increase this past year. Combined with
dividends, our shareholders had a total
return of $4.29 per share in fiscal year
2016. Our Board of Directors approved
an annualized dividend increase from
$0.81 per share to $0.87 per share, effective with the February 1, 2017 quarterly
dividend payment. The February dividend will reflect 72 years of continuous
quarterly dividend payments and 20 annual dividend increases in the past 21 years.
Consistently
The economic outlook for the Roanoke region is positive. The past year has seen
several major economic announcements. Three major companies have
announced plans to invest $208 million in the next few years, creating over 525 new
jobs. In addition, Virginia Tech and Carilion Clinic announced a plan to build a $66
million facility to expand the Virginia Tech Carilion Health Sciences Campus in
Roanoke. Private sector employment in the Roanoke region reached its highest
levels since 2007, resulting in unemployment rates below 4%.
Our subsidiary, Roanoke Gas Company, experienced steady growth this year with
approximately 500 customer additions. Demand from existing industrial customers
was down slightly in 2016, however the first large compressed natural gas fueling
station was opened in the Roanoke Valley to fuel a large delivery vehicle fleet. The
station went into service in the first quarter of 2016 and has become one of our top
10 volumetric customers.
We continue to invest in capital improvements for Roanoke Gas Company. In fiscal
year 2016, we invested $17.9 million, with the primary focus on the modernization of
our distribution system. Approximately 15 miles of cast iron and bare steel pipe was
replaced with polyethylene pipe. I am excited to announce that in November
2016, the last segment of cast iron and bare steel main in our system was renewed.
This has been a 25-year effort and I wish to recognize our employees and
contractors who worked on this project that enhances the safety and reliability of
our natural gas distribution system.
President’s
Letter (continued)
Our focus will now turn to the renewal of approximately 45 miles of first
generation plastic mains and services that were installed before 1973. The first
generation plastic main renewal project is anticipated to take 3 to 4 years to
complete. We also completed the replacement and upgrade of two natural
gas transfer stations on the south side of our system, both of which connect with
the East Tennessee transmission line. Along with pipeline renewal and gate
station upgrades, the Company is implementing new technology to improve
the efficiency, safety and reliability of our distribution system. In the past year,
we invested in electronic tablet technology for field personnel and expanded
our GIS mapping system. Implementation of an automated meter reading
system is planned for fiscal year 2017. This will allow us to remotely access meter
readings and provide more comprehensive natural gas usage data.
Through our subsidiary, RGC Midstream, LLC, we are a 1% member of the
Mountain Valley Pipeline, LLC. The Mountain Valley Pipeline (MVP) will be an
approximately 300 mile, 42-inch diameter
interstate pipeline with an
approximate cost of $3.5 billion. The pipeline will transport natural gas from the
Marcellus and Utica production areas through West Virginia and Southwest
Virginia to the growing natural gas markets along the east coast. The MVP will
address the growing demand for natural gas in our region, add an additional
source of gas to the Roanoke Gas natural gas supply portfolio and provide the
Company with a more economically feasible opportunity to expand natural
gas service to previously unserved areas in southwest Virginia. The MVP project
is progressing through the Federal Energy Regulatory Commission (FERC)
approval process. On June 28, 2016, FERC issued the Notice of Schedule for
Environmental Review (NOS) and on September 16, 2016, FERC issued its draft
environmental impact statement regarding the MVP. Based on the schedule
provided in the NOS, the MVP expects to receive the FERC certificate in mid-
2017. The pipeline is targeted to be placed in-service during the fourth quarter
of 2018. Our total investment in this project is projected to be approximately $35
million. We believe this strategic investment will complement our core business
and continue to enhance shareholder value.
On behalf of our Board of Directors and
employees, thank you for your continued
interest in our Company and for your
ongoing decision
in RGC
Resources.
invest
to
John S. D’Orazio
President and Chief Executive Officer
(Left to Right) Chris Morrill, Roanoke City
Manager; Sherman P. Lea, Sr., Roanoke City
Mayor and John S. D’Orazio. Photograph
taken during 25 Year pipeline renewal
completion celebration.
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, 2016
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: None
Securities registered pursuant to Section 12(g) of the Act:
Title of Each Class
Common Stock, $5 Par Value
Name of Each Exchange on
Which Registered
NASDAQ Global Market
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, 2016. $95,954,187
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, 2016
4,798,466 SHARES
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the RGC Resources, Inc. Proxy Statement for the 2017 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
Signatures
PART III
PART IV
Page Number
2
3
6
10
10
10
10
11
13
13
28
29
63
63
65
66
66
66
66
66
67
68
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 most of the non-gas utility revenue of Resources.
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 3 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
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
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
3
Residential
Commercial
Industrial
Other Utility
Other Non-Utility
Total Percent
Total Value
Customers
Volume
Revenue
Margin
2014
91.2%
8.7%
0.1%
0.0%
0.0%
100.0%
58,553
40%
29%
31%
0%
0%
100%
57%
34%
6%
1%
2%
100%
58%
25%
12%
3%
2%
100%
10,087,651
$
75,016,134
$
29,337,089
Roanoke Gas’ regulated natural gas distribution business accounted for approximately 98% of Resources total revenues
for fiscal years ending September 30, 2016, 2015 and 2014. 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 31% of
total natural gas deliveries for the year ended September 30, 2016 and approximately 11% to 12% 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, 2016, approximately
64% of the Company’s total DTH of natural gas deliveries and 72% of the residential and commercial deliveries were
made in the five-month period of November through March. These percentages are below the prior two fiscal years due
to lower volumes attributable to a much warmer heating season. Total natural gas deliveries were 8.8 million DTH, 9.9
million DTH and 10.1 million DTH in fiscal 2016, 2015 and 2014, 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 between 50% and 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 2017 to
2022. 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 expects its firm supply agreements will be sufficient to meet customer demands for natural gas during the
term of the 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. During fiscal 2016, all three
franchise agreements were renewed for a term of 20 years with expiration dates of 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 and extends service to the new residential construction markets
located along or near gas distribution mains in its service area. Although new construction activity has been limited over
the last few years, the Company has been able to grow its customer base through customers converting from an
alternative energy source 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, 2016, Resources had 126 full-time employees and 132 total employees. As of that date, 34
employees, or 27% 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
5
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.
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 an investor could lose all or part of his, her or its investment.
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.
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, 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 a risk 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 impact on earnings.
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 laws and regulations at both the federal and state levels. The Company is subject to
ongoing inspections and reviews. Failure to comply with such requirements 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 operation.
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 approval
of the pipeline project by FERC and completing the construction of the pipeline within the targeted time frame and
6
budget. Any significant delay, cost over-run or the failure to receive the requisite approvals 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,
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 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 leading to higher prices or service disruptions. Disasters could also lead to additional
governmental regulations that limit production activity or increase production and transportation costs.
Security incident or cyber-attacks on the Company’s computer or information systems.
A security incident on the Company’s information systems from cyber-attacks or other sources could lead to
disruptions in natural gas deliveries or compromise the safety of the natural gas distribution system. Such attacks
could also result in corruption of the Company’s financial information or the unauthorized release of confidential
customer, employee or vendor information. The Company takes reasonable precautions to safeguard its computer
systems from attack; however, there is no guarantee 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.
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
7
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.
Environmental laws or regulations.
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 Mountain Valley Pipeline, LLC. Natural gas is a clean and efficient energy source; however, the
combustion of natural gas results in carbon related emissions. 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 could increase the demand for natural gas, potentially resulting in natural gas supply
concerns and higher cost 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.
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 stock issued
under the Dividend Reinvestment and Stock Purchase Plan 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 to provide more predictable financing 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 or deterioration in the financial condition of the
Company could increase the cost of borrowing or limit the Company’s ability to secure adequate funding.
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.
Regulatory actions or failure to obtain timely rate relief could decrease future profitability.
The Company’s natural gas operations are regulated by the SCC. The SCC approves the rates that the Company
charges its natural gas 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 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.
Insurance coverage may not be sufficient.
The Company currently has liability and property insurance in place to cover a variety of exposures and perils.
Although management considers the level of coverage to be appropriate considering the current environment, 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 it completely as an insured event. 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.
The cost of providing post-retirement benefits and related funding obligations may increase.
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
8
measure the required minimum funding levels of the plan, future government regulation, changes in life expectancy,
and required or voluntary contributions made to the plan. Changes in actuarial assumptions and differences between
the assumptions and actual results, as well as a significant decline in the value of investments that fund these plans, if
not offset or mitigated by a decline in plan liabilities, could increase the expense of these plans and require significant
additional funding. Both funding obligations and increased expense could have a material impact on the Company's
financial position, results of operation and cash flows.
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. However, if restrictions on drilling for natural gas in the shale rock
formations are imposed at either federal, state or local levels due to environmental or other concerns or other
exploration and development restrictions on conventional drilling are enacted, the price of natural gas could escalate.
The economic viability of the LLC could be significantly impacted by such restrictions. Furthermore, if demand for
natural gas increases at a rate in excess of current expectations, natural gas prices could also face upward pressure.
Increasing natural gas prices could result in declining sales as well as increases in bad debt expense.
Business activities are concentrated in a limited geographic region.
Changes in the Roanoke Valley’s economy, politics, regulations and weather patterns could negatively impact the
existing customer base, leading to declining usage patterns and financial condition of customers, both of which could
adversely affect earnings.
Weather conditions may cause revenues and earnings to vary from year to year.
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.
Failure to comply with debt covenant requirements could lead to adverse financial consequences that could affect the
Company's liquidity and ability to borrow funds.
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.
Inability to complete necessary or desirable pipeline expansion or infrastructure development projects may delay or
prevent the Company from adequately serving its customers or expanding its distribution system.
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,
9
and an inability to negotiate acceptable agreements relating to rights-of-way, construction or other material
development components. As a result, the Company may not be able to adequately serve existing customers or support
customer growth, which would negatively impact earnings.
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 1,132 miles of transmission and distribution pipeline with transmission and distribution plant
representing more than 86% 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 will depend on, among other factors, earnings, capital
requirements, and the operating and financial condition of the Company.
Year Ending September 30, 2016
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
Year Ending September 30, 2015
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
$
$
Range of Bid Prices
Cash Dividends
High
Low
Declared
$
$
23.94
23.39
26.00
25.09
22.45
25.67
22.99
21.96
$
$
20.05
20.66
21.45
22.32
19.28
20.20
19.78
19.95
0.2025
0.2025
0.2025
0.2025
0.1925
0.1925
0.1925
0.1925
As of November 25, 2016, there were 1,192 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, 2011 through
September 30, 2016 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, 2011 in the Company’s
common stock and in each index as of September 30, 2016, 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 $163 for the Company’s common stock, $192 for the Dow Jones US Utilities Index and $213 for the
S&P 500 Index.
11
A summary of the Company’s equity compensation plans follows as of September 30, 2016:
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))
58,200
—
58,200
$20.25
—
$20.25
110,307
—
110,307
12
Item 6.
Selected Financial Data.
Year Ending September 30,
2016
2015
2014
2013
2012
Operating Revenues
Gross Margin
Operating Income
Net Income
$ 59,063,291
$ 68,189,607
$ 75,016,134
$ 63,205,666
$ 58,799,687
31,564,914
30,206,433
29,337,089
27,602,891
26,933,097
11,212,092
10,006,192
5,806,866
5,094,415
9,681,868
4,708,440
8,795,055
4,262,052
8,786,535
4,296,745
Basic Earnings Per Share
Cash Dividends Declared Per Share
Book Value Per Share
Average Shares Outstanding
Total Assets (1)
$
$
$
1.22
0.81
11.63
$
$
$
1.08
0.77
11.14
$
$
$
1.00
0.74
11.02
$
$
$
0.91
1.72
10.51
$
$
$
0.92
0.70
10.85
4,766,604
4,728,210
4,715,478
4,698,727
4,647,439
$165,552,849
$145,847,194
$137,423,321
$121,658,797
$127,363,410
Long-Term Debt (Less Unamortized
Debt Expense)
$ 33,636,051
$ 30,316,573
$ 30,306,919
$ 12,984,169
$ 12,978,681
Stockholders' Equity
55,667,072
52,840,991
52,020,847
49,502,422
50,682,930
Shares Outstanding at Sept. 30
4,788,289
4,741,498
4,720,378
4,709,326
4,670,567
(1)Total assets for the prior years were revised to reflect the reclassification of current deferred tax assets against
deferred tax liabilities as provided for in ASU 2015-17, Income Taxes: Balance Sheet Classification of Deferred Taxes.
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 59,600 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 also formed a wholly-owned subsidiary, RGC Midstream, LLC ("Midstream"), to
invest in the Mountain Valley Pipeline, LLC (the "LLC"). On October 1, 2015, Midstream executed agreements to
become 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. With recent regulatory actions placing a greater emphasis on
pipeline safety, the Company continues to focus its efforts on completing its renewal and replacement program. The
Company completed the replacement of all cast iron pipe in fiscal 2016 and replacement of all bare steel pipe in the
first quarter of fiscal 2017. The Company will continue its renewal program with plans to replace first generation,
pre-1973 plastic pipe over the next five 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.
Over 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 previous 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
increased 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
14
between actual costs incurred and costs recovered through the application of the PGA is recorded as a regulatory asset
or liability. At the end of the annual deferral period, the balance is amortized over an ensuing 12-month period as
amounts are reflected in customer billings.
The WNA reduces the volatility in earnings due to the variability in temperatures during the heating season. The WNA
is based on the most recent 30-year temperature average. The WNA 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 of each year. Any
billings or refunds related to the WNA are completed following the end of the WNA year. For the fiscal year ended
September 30, 2016, the Company recorded $1,318,000 in additional revenue from the WNA for weather that was
approximately 13% warmer than normal. During the fiscal year ended September 30, 2015, the Company had reduced
revenue by $609,000 due to the WNA for weather that was approximately 6.5% colder than normal. During the fiscal
year ended September 30, 2014, the Company recorded a reduction in revenue of $563,000 to reflect the WNA
adjustment for weather that was approximately 9% colder than normal. Prior to April 2014, the WNA provided for a
weather band of 3% above and below normal whereby no WNA would be calculated until weather was outside the 3%
band.
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. The decline in commodity
prices during the 2016 summer storage refill period continued the downward trend on the cost of gas in storage.
Although total average volumes in storage were higher during the current year, the lower commodity price of gas
resulted in a lower cost of gas in storage, which is the basis for calculating ICC revenues. Furthermore, the increase in
the utilization of the line-of-credit resulted in a greater allocation of the lower-rate debt in the overall weighted-average
cost of capital, thereby reducing the ICC factor. The combination of lower average storage gas inventories in terms of
cost and a lower ICC factor resulted in a $182,000 decline in ICC revenues in fiscal 2016. This decline follows a
reduction of $46,000 in ICC revenues during the prior fiscal year, resulting from the decline in price of gas delivered to
storage. Based on the current natural gas futures prices, the average dollar balance of gas in storage may decline next
year, but the decline is expected to be at a smaller level.
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 short-term
financing costs. Therefore, when inventory balances decline due to a reduction in commodity prices, net income will
decline as carrying cost revenues decrease by a greater amount than short-term financing 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 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 did not file for an
increase in the non-gas rates during the prior two years and the level of SAVE qualifying capital investment continues
to grow, SAVE Plan revenues have increased significantly. The Company recognized approximately $2,538,000,
$1,308,000 and $292,000 in SAVE Plan revenues for years ended September 30, 2016, 2015 and 2014, respectively.
15
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 has lost some key business activities over the last few years as some
companies have either shut down or relocated all or portions of their operations elsewhere. However, the Company
continues to experience some customer and sales growth including the addition of a large natural gas fleet refueling
station at a commercial customer. In addition, new business ventures have been announced in the Company's service
territory that should provide some additional natural gas load over the next few years. 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 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 weather, as reflected in the lower residential and
commercial volumes. Industrial consumption also declined, causing a reduction in transportation and interruptible
volumes. Residential and commercial deliveries tend to be more weather sensitive as reflected by a 12% decline in
volumes on 18% fewer heating degree days. Transportation and interruptible volumes, which are primarily driven by
production activities rather than weather, 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 the prior year and Application Resources during the current year.
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 %
16
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 as the Company continues to invest 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. As
discussed in more detail above, the WNA mechanism allowed the Company to recognize margin related to those natural
gas volumes not sold due to the warmer weather. ICC revenues continued to decline with a $182,000 reduction in fiscal
2016 compared to the prior year 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 last year, 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. In
addition, 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 by the customer
which could impact future revenues and margins.
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
last year due to much higher overhead capitalization and lower bad debt expenses more than offsetting higher benefit
and labor costs. Capitalized overheads, which include general and administrative costs, payroll overheads and
engineering costs, 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 and lower gas costs. 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.
Depreciation - Depreciation expense increased by $484,675, or more than 9%, corresponding to a similar increase in
utility plant investment.
17
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 composed of allowance for funds used during construction
("AFUDC"). 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, increased by $26,789, or 12%, primarily due to higher pipeline assessments.
Interest Expense - Total interest expense increased by $123,902, or 8%, due to a 15% increase in the average debt
outstanding. The combination of the investments in Mountain Valley Pipeline and the level of capital expenditures
during the year have required increased borrowing.
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 $1.22 in fiscal 2016 compared to $1.08 in fiscal 2015. Dividends declared
per share of common stock were $0.81 in fiscal 2016 compared to $0.77 in fiscal 2015.
Fiscal Year 2015 Compared with Fiscal Year 2014
The table below reflects operating revenues, volume activity and heating degree-days.
Operating Revenues
Year Ended September 30,
2015
2014
Gas Utilities
Other
Total Operating Revenues
$
$
67,094,290
1,095,317
68,189,607
$
$
73,865,487
1,150,647
75,016,134
$
$
Decrease
(6,771,197)
(55,330)
(6,826,527)
Percentage
(9)%
(5)%
(9)%
Delivered Volumes
Year Ended September 30,
Regulated Natural Gas (DTH)
Residential and Commercial
Transportation and Interruptible
Total Delivered Volumes
Heating Degree Days
(Unofficial)
2015
2014
Decrease
Percentage
6,955,594
2,919,413
9,875,007
7,005,920
3,081,731
10,087,651
(50,326)
(162,318)
(212,644)
4,253
4,351
(98)
(1)%
(5)%
(2)%
(2)%
Total gas utility operating revenues for the year ended September 30, 2015 decreased by 9% from the year ended
September 30, 2014 primarily due to lower gas costs and a reduction in natural gas deliveries. The average commodity
price of natural gas declined by 21% per decatherm sold. Delivered volumes declined due in part to weather, as
reflected in the decline in residential and commercial volumes, and a reduction in industrial consumption. Residential
and commercial deliveries tend to be more weather sensitive as reflected by a decline of 1% in volumes on 2% fewer
heating degree days. Transportation and interruptible volumes, which are primarily driven by production activities
rather than weather, decreased by 5%. Other revenues decreased by 5% as well.
18
Gross Margin
Year Ended September 30,
2015
2014
Increase /
(Decrease)
Percentage
Gas Utility
Other
Total Gross Margin
$
$
29,656,975
549,458
30,206,433
$
$
28,774,213
562,876
29,337,089
$
$
882,762
(13,418)
869,344
3 %
(2)%
3 %
Regulated natural gas margins from utility operations increased by 3% from fiscal 2014, primarily as a result of higher
SAVE Plan revenues and customer base charges more than offsetting lower volumetric margins and ICC revenues.
SAVE Plan revenues increased by $1,016,000. Customer base charges also increased due to modest customer growth.
Volumetric margin declined due to a reduction in total volumes delivered. Residential and commercial volumes
declined primarily due to slightly warmer weather. Interruptible and transportation volumes declined due to the loss of
a customer during fiscal 2015 and decreased usage at two of the Company's larger customers. The effect of the warmer
weather was mitigated in part by the WNA mechanism. In fiscal 2014, the WNA mechanism provided for a weather
band of 3% variance around normal during the winter heating season while the fiscal 2015 heating season had a 0%
weather band. Because the fiscal 2014 year had a 3% weather band in place for part of the year and weather was colder
than normal, the Company was able to retain approximately $251,000 in excess margin realized on the 3% weather
band, while the fiscal 2015 year WNA with a 0% weather band required the adjustment of margin back to the level
expected for normal weather.
Other margins, consisting of non-utility related services, decreased by $13,418 on comparable activity. The Utility
Consultants, which ceased activity during fiscal 2015, contributed $17,000 to the non-utility related margin. The
service contracts that comprise most of the non-utility related activities are subject to annual or semi-annual renewal
provisions and the potential exists that these contracts may not be renewed or extended by the customer. In addition,
the level of activity under these contracts will fluctuate based on customer requirements which may result in
fluctuations in revenues and margins.
The changes in the components of the gas utility margin are summarized below:
Customer Base Charge
$
12,240,580
$
12,064,764
$
175,816
Twelve Months Ended September 30,
2015
2014
Increase
(Decrease)
SAVE Plan
Volumetric
WNA
Carrying Cost
Other
Total
1,307,795
15,757,907
(608,560)
833,291
125,962
291,946
15,990,704
(563,187)
879,381
110,605
1,015,849
(232,797)
(45,373)
(46,090)
15,357
$
29,656,975
$
28,774,213
$
882,762
Operations and Maintenance Expense - Operations and maintenance expenses increased by $103,497, or 1%, in
fiscal 2015 compared with fiscal 2014 due to higher benefit costs and professional services and less overhead
capitalization more than offsetting reductions in the level of bad debt expense, labor and contracted labor. Employee
benefit expenses increased by $260,000 primarily due to higher medical, defined benefit pension plan and
postretirement medical plan. The actuarially determined expenses for the pension and postretirement plans increased
in fiscal 2015 due to a decline in the discount rate for valuing both plans' liabilities at September 30, 2014. Professional
services increased by $77,000 primarily due to legal expenses associated with the new union contract, the formation of
the Company's new subsidiary and the due diligence work related to the investment in the Mountain Valley Pipeline.
Total capitalized overheads declined by $106,000 because of delays in the production of liquefied natural gas due to
maintenance down time, lower capital expenditures and a reduction in the capitalization rate compared to fiscal 2014.
Bad debt expense decreased by $61,000 due to lower customer billings resulting from warmer weather and a lower
commodity price of gas. Labor and contracted services costs declined by $133,000 due to timing of pipeline right-of-
way clearing and prior year costs related to updating the Company's corrosion control processes. The remaining
19
decrease relates to a variety of areas including the level of facility and equipment maintenance, advertising and
administrative costs.
General Taxes - General taxes increased $46,035, or 3%, primarily due to higher property taxes associated with
increases in utility property.
Depreciation - Depreciation expense increased by $395,488, or 8%, corresponding to a similar increase in utility plant
investment.
Other Expense - Other expense, net, increased by $21,909, or 11%, primarily due to an increase in charitable requests
related to specific campaigns.
Interest Expense - Total interest expense decreased by $314,582, or 17%, due to a lower interest rate on long-term
debt. In September 2014, the Company refinanced its $28,000,000 in long-term debt, which had an average interest
rate of 6.30% with $30,500,000 in new debt having a rate of 4.26%.
Income Taxes - Income tax expense increased by $231,022 on higher pre-tax earnings. The effective tax rate was
38.4% for both fiscal 2015 and 2014.
Net Income and Dividends - Net income for fiscal 2015 was $5,094,415 compared to $4,708,440 for fiscal 2014.
Basic and diluted earnings per share were $1.08 in fiscal 2015 compared to $1.00 in fiscal 2014. Dividends declared
per share of common stock were $0.77 in fiscal 2015 compared to $0.74 in fiscal 2014.
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 to a lesser extent, capital raised through the
Company’s stock plans.
Cash and cash equivalents decreased by $341,982 in fiscal 2016 compared to an increase of $135,477 in fiscal 2015
and a decrease of $1,996,467 in fiscal 2014. The following table summarizes the categories of sources and uses of
cash:
Cash Flow Summary
Year Ended September 30,
Provided by operating activities
Used in investing activities
Provided by (used in) financing activities
Increase (decrease) in cash and cash equivalents
Cash Flows Provided by Operating Activities:
2016
2015
2014
$
14,921,640
(20,996,501)
5,732,879
$
16,760,827
(13,750,274)
(2,875,076)
6,839,738
(14,698,570)
5,862,365
(341,982) $
135,477
$
(1,996,467)
$
$
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 increases in natural gas storage levels and rising customer receivable
balances.
Cash provided by operating activities was $14,922,000 in fiscal 2016, $16,761,000 in fiscal 2015 and $6,840,000 in
fiscal 2014. Cash provided by operating activities decreased by more than $1,800,000 from last year primarily as a
result of a smaller decline in natural gas commodity prices and refunding part of last year's over-collection of gas costs,
20
offset by a greater increase in deferred tax liability due to the subsequent extension of 50% bonus tax depreciation
through 2017, higher net income and book depreciation. The average price of gas in storage declined by 13% during
fiscal 2016 as natural gas commodity prices continued their decline even though total volumes increased by nearly 5%,
resulting in an overall decrease in gas in storage of $724,000. During fiscal 2015, the average price of gas in storage
declined by 28% on nearly unchanged volumes resulting in a $3,242,000 decrease in gas in storage from fiscal 2014.
In addition, the significant drop in natural gas prices during the prior year resulted in an increase in over-collection of
gas costs as the adjustment to the PGA factor used to bill customers for the gas component of rates lagged behind the
declining price of gas. As a result, the Company collected $1,900,000 from customers in excess of actual gas costs in
fiscal 2015. During fiscal 2016, the Company reduced its over-collection by nearly $1,000,000 as the Company began
refunding the excess collections. Subsequent to the issuance of fiscal 2015 financial statements, Congress passed, and
the President signed into law, the Protecting Americans from Tax Hikes ("PATH" Act) which extended the 50% bonus
depreciation for calendar 2015 through December 31, 2017 and provided for 40% bonus depreciation for calendar 2018
and 30% bonus depreciation for calendar 2019. As a result of the passage of the PATH Act, the Company recorded an
adjustment to deferred taxes in the amount of $1,284,000 in the first quarter of fiscal 2016 to recognize the effect of
bonus depreciation on the balance of 2015 asset additions in addition to $3,065,000 in deferred tax liability recognized
for the effect of 50% bonus depreciation on fiscal 2016 capital additions. As a result of the bonus depreciation
extension for 2015, the Company requested and received a refund of $1,600,000 in federal taxes related to the
additional deduction claimed on the fiscal 2015 tax return. In comparison, total deferred taxes increased by $2,417,000
in fiscal 2015. A summary of the key components of the cash flows from operating activities is provided below:
Cash Flow Provided by Operating Activities:
2016
2015
Increase (Decrease)
Twelve Months Ended September 30,
Net income
Depreciation
Decrease in gas in storage
Increase / (decrease) in over-collection of gas costs
Increase in deferred taxes
Other
Net Cash Provided by Operations
$
Cash Flows Used in Investing Activities:
$
5,806,866
$
5,094,415
$
712,451
5,709,525
723,713
(991,739)
4,466,954
(793,679)
14,921,640
$
5,219,893
3,242,492
2,082,257
2,416,841
(1,295,071)
16,760,827
$
489,632
(2,518,779)
(3,073,996)
2,050,113
501,392
(1,839,187)
Investing activities primarily consist of expenditures under the Company’s construction program, which involves a
combination of replacing aging bare steel and cast iron pipe with new plastic or coated steel pipe, making
improvements to the LNG plant and expansion of its natural gas system to meet the demands of customer growth. The
Company’s expenditures related to its pipeline renewal program and other system and infrastructure improvements
increased to nearly $18,000,000 in fiscal 2016 from $13,800,000 in fiscal 2015 and $14,700,000 in fiscal 2014. The
Company renewed 14.9 miles of natural gas distribution main and replaced 684 services in fiscal 2016. This compares
to 10 miles of main and 594 services in fiscal 2015 and 13.6 miles of main and 942 services in fiscal 2014. The
Company completed the replacement of its cast iron pipe during fiscal 2016 and finished replacing the remainder of the
bare steel pipe in November 2016. The Company also completed the replacement of two natural gas custody transfer
stations connected to the East Tennessee transmission line. In addition, the Company’s capital expenditures included
costs to extend natural gas distribution mains and services to 495 new customers in fiscal 2016 compared to 609 new
customers in fiscal 2015 and 673 in fiscal 2014. Depreciation covered approximately 32% of the current year's capital
expenditures compared to 38% for 2015 and 33% for 2014, with the balance provided from other operating cash flows
and borrowings under the line-of-credit.
Capital expenditures are expected to remain at elevated levels over the next few years. With the replacement of cast
iron and bare steel mains completed, renewal efforts will now shift to replacing approximately 45 miles of pre-1973
first generation plastic pipe with current polyethylene pipe. This renewal project is expected to be completed by 2021.
The Company has also begun implementation of an automated meter reading system, expected to be completed in fiscal
2017, whereby all customer meters will be retrofitted with transmitters which will allow consumption data to be
collected remotely. The current capital budget for fiscal 2017 reflects an increase of more than $3,000,000 in
expenditures over fiscal 2016. The Company expects to increase its borrowing activity to meet the funding
requirements of these planned expenditures.
21
Investing cash flows also reflect the Company's $3,055,746 funding of its participation in the Mountain Valley Pipeline.
The Company expects to invest an additional $32 million over the remaining three-year project period, pending FERC
approval. 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. More information regarding the credit facility is provided in Note 5 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 long-term and short-term borrowings and repayments, issuance of stock and
the payment of dividends. As mentioned above, the Company uses its line-of-credit arrangement to fund seasonal
working capital and provide temporary financing for capital projects. Cash flows provided by financing activities were
$5,733,000 in fiscal 2016 compared to cash used in financing activities of $2,875,000 in fiscal 2015 and cash provided
by financing activities of $5,862,000 for fiscal 2014. The combination of greater capital investment related to the
pipeline renewal program and other projects, including the Mountain Valley Pipeline, required increased borrowing
activity. In fiscal 2015, net borrowing activity under the line-of-credit was nearly unchanged as the Company benefited
from higher operating cash flows resulting from declines in the price of natural gas and the extension of 50% bonus
depreciation for tax purposes. In 2014, the Company refinanced $28,000,000 of its debt, including $2,238,000 in early
termination fees on notes and interest rate swaps with $30,500,000 in unsecured 20-year term notes. The early
termination fees were deferred as a regulatory asset and are being amortized over the term of the new notes as a
component of interest expense. The $28,000,000 in retired debt had an average interest rate of 6.30% with an effective
rate of 6.43%. The new debt has a stated interest rate of 4.26% and an effective rate of 4.67%. The nearly $315,000
reduction in interest expense in fiscal 2015 is entirely due to the refinancing. The Company increased the utilization of
its line-of-credit to provide bridge financing for its capital budget for amounts in excess of those provided by
operations. Proceeds from the issuance of stock were $1,031,000 under the DRIP plan. Dividends increased as the
annualized dividend rate per share went from $0.74 in fiscal 2014 to $0.77 in fiscal 2015 and $0.81 if fiscal 2016. The
Company’s consolidated capitalization was 62.2% equity and 37.8% long-term debt at September 30, 2016. This
compares to 63.4% equity and 36.6% long-term debt at September 30, 2015.
Effective March 31, 2016, the Company entered into a new line-of-credit agreement. This new agreement maintains
the same terms and rates as provided for under the expired agreement. The interest rate is based on 30-day LIBOR plus
100 basis points and includes an availability fee of 15 basis points applied to the difference between the face amount of
the note and the average outstanding balance during the period. The Company maintained multi-tiered borrowing
limits to accommodate seasonal borrowing demands and minimize overall borrowing costs, with available limits
ranging from $10,000,000 to $24,000,000 during the term of the agreement. The line-of-credit agreement will expire
March 31, 2017. The Company anticipates being able to extend or replace the line-of-credit upon expiration; however,
there is no guarantee that the line-of-credit will be extended or replaced under the same or equivalent terms currently in
place.
On December 29, 2015, Midstream entered into a Credit Agreement (the "Credit Agreement") and related Promissory
Notes (the "Notes"), under which Midstream may borrow up to a total of $25 million, over a period of 5 years, with an
interest rate of 30-day LIBOR plus 160 basis points. In accordance with the terms of the Credit Agreement, at such
time as Midstream has borrowed $17.5 million under the Notes, Midstream is required to provide the next $5 million in
equity towards its capital contributions to the LLC. Once Midstream has completed its $5 million in contributions, it
may resume borrowing up to the $25 million limit. Currently, management is considering the possibility of an equity
issue by Resources to provide Midstream with the $5 million in equity capital required under the Notes. Following the
end of the 5-year term on the Notes, Midstream anticipates refinancing the $25 million Notes with a longer-term
amortizing debt instrument.
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, 2016, the estimated recorded and unrecorded obligations are as follows:
22
Recorded contractual obligations:
Less than 1
year
1-3
Years
4-5
Years
After
5 Years
Total
Long-Term Debt (1)
Short-Term Debt (2)
Total
$
— $
— $ 3,396,200
$ 30,500,000
$ 33,896,200
14,556,785
—
—
—
14,556,785
$ 14,556,785
$
— $ 3,396,200
$ 30,500,000
$ 48,452,985
(1) See Note 5 to the consolidated financial statements.
(2) See Note 4 to the consolidated financial statements.
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 Short-Term Debt (5)
Interest on Long-Term Debt (6)
Pension Plan Funding (7)
$ 10,474,339
—
32,824
1,371,200
—
$ 15,999,239
—
—
2,742,400
—
$ 7,276,676
—
—
2,688,200
—
$ 2,682,848
—
—
17,277,081
—
$ 36,433,102
—
32,824
24,078,881
—
Investment in MVP (8)
Other Obligations (9)
3,500,000
117,780
28,444,254
24,502
—
4,661
—
25,540
31,944,254
172,483
Total
$ 15,496,143
$ 47,210,395
$ 9,969,537
$ 19,985,469
$ 92,661,544
(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 10 to the consolidated
financial statements.
(5) Accrued interest on line-of-credit balance at September 30, 2016, including minimum facility fee on unused line-of-
credit. See Note 4 to the consolidated financial statements.
(6) Calculated interest payments on 20-year $30.5 million Roanoke Gas Co. note payable due September 18, 2034 and on
09/30/2016 balance on Midstream notes due December 29, 2020. See Note 5 to the consolidated financial statements.
(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 7 to the consolidated financial statements.
(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 newly formed 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 an existing gathering and transmission system in northern
West Virginia to another interstate pipeline in south central Virginia. This project falls under the jurisdiction of FERC
and is subject to its approval prior to beginning construction. In October 2015, the LLC filed the application with
FERC to construct the pipeline. On June 28, 2016, FERC issued the Notice of Schedule for Environmental Review
(NOS) and on September 16, 2016, FERC issued its draft environmental impact statement ("EIS") regarding the MVP.
In the draft EIS, FERC staff concluded that approval of the MVP would result in some adverse environmental impacts;
however, they acknowledged that such impacts would be reduced to less than significant levels with the implementation
of the LLC's proposed mitigation plans in addition to measures recommended in the EIS. Comments regarding the
draft EIS must be filed on or before December 22, 2016. Based on the schedule provided in the NOS, the MVP expects
to receive the FERC certificate in mid-2017. The pipeline is targeted to be placed in-service during the 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
23
liquefied natural gas storage facility. Damage to or interruption in supply from any of these sources, especially during
the winter heating season, could have a significant impact on the Company's ability to serve its customers. A third
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 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 approved 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, over a period of 5 years with the balance coming from equity capital.
A majority of the earnings from the investment in MVP relates to the allowance for funds used during construction
("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. If approved by FERC, 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, 2016, the Company filed an application with the SCC for modification to its SAVE Plan and Rider. The original
SAVE Plan and Rider were approved by the SCC through an order issued on August 29, 2012 and has been modified or
amended 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 application included provisions to continue the ongoing pipeline renewal project with a focus on
pre-1973 plastic pipe, the replacement of three natural gas custody transfer stations, the replacement of coated steel
tubing services and related meter installations. The 2017 SAVE revenue requirement is approximately $4,000,000,
representing an increase of almost $1,000,000 over the estimated 2016 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 Company renewed the expiring franchise
agreements with the City of Roanoke, the City of Salem and the Town of Vinton under terms and conditions similar to
the expiring agreements. The new agreements have twenty-year terms and 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
request at a later date. The Company intends to pursue the application assuming FERC approval of the MVP project.
24
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 required under the provisions of FASB ASC No. 980, Regulated Operations, the
Company recognizes billed revenue related to the SAVE projects to the extent such revenues have been earned under
the provisions of the SAVE Plan.
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 $1,004,061 and $1,001,418 as of
September 30, 2016 and 2015, 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.
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 7 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
25
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 3.42% and 3.33%, respectively, for valuing its pension plan liability and postretirement plan liability at
September 30, 2016. These rates decreased significantly from the prior year with a decline of 0.80% and 0.82%,
respectively. Interest rates moved even lower in 2016 keeping the discount rate depressed, thereby elevating the plan
liabilities. The downward movement of the discount rate is evidenced by the 30-year Treasury rate, which decreased
from 2.87% to 2.32% and the Moody's Aaa rate, which declined by a corresponding 0.56%. This reduction in discount
rate, combined with other factors, increased the pension liability by more than $2,300,000 and the postretirement
medical liability by approximately $3,150,000. In fiscal 2015, the most significant impact to the liabilities was
attributed to the adoption of new mortality tables. On October 27, 2014, the Society of Actuaries released the final
reports of the RP-2014 Mortality Tables and the Mortality Improvement Scale MP-2015. The new mortality tables,
which were adopted by the Company for its September 30, 2015 defined benefit plan valuations, extend the assumed
life expectancy of participants in the plans and provide a better measure of defined benefit plan liabilities. The impact
of the change in assumed mortality increased the Company’s pension liability for the prior year by approximately 5% or
nearly $1.3 million and the postretirement liability by approximately 7% or about $1 million. The Company used the
RP-2014 Mortality Tables under the Projection Scale MP-2015 for the current year valuation.
Due to a variety of factors including volatility in the pension expense and corresponding liabilities, continued depressed
interest rates and increasing life expectancies, the Company is implementing a risk reduction strategy for its pension
plan. This risk reduction strategy included two components. The first offered a one-time lump sum pay out of the
pension benefit to vested terminated employees who were not currently receiving payments under the pension plan.
Approximately 63% of those vested, terminated employees elected to receive their pension in a lump sum 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 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; but, pension liability growth will slow and eventually decline as no new
participants will enter the pension plan. Likewise, pension expense will begin to decline in the future as less service
cost is accrued due to fewer active employees in the pension plan. As more of the pension liability becomes fixed
through retirements, management will begin to align the duration of the plan's liabilities with its assets in an effort to
further reduce market volatility.
Following lower than expected returns in fiscal 2015, the returns on the related pension and postretirement assets for
fiscal 2016 exceeded the corresponding long-term rate of return assumptions. Furthermore, the Company contributed
an additional $1,000,000 over and above the previously projected $500,000 annual contribution to the pension plan.
The combination of better than expected returns and higher funding levels were not enough to offset the increase in the
pension benefit obligation associated with the reduction in the discount rate and the accretion of service and interest
costs. As a result, the funded deficit for both the pension and postretirement plans increased during the period.
Generally, the reduction in the discount rate would result in an increase in benefit plan expense for the following year;
however, the combination of higher investment returns and contributions combined with the removal of the liabilities
related to the lump sum payments will result in a small decrease in pension expense in fiscal 2017. The postretirement
medical plan expense will increase as the plan experienced no beneficial offsets to reduce the impact of the lower
discount rate.
Funded status - September 30, 2016
Pension
Postretirement
Total
Benefit obligation
Fair value of assets
Funded status
$
$
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)
26
Funded status - September 30, 2015
Pension
Postretirement
Total
Benefit obligation
Fair value of assets
Funded status
$
$
27,167,621
$
15,355,668
$
42,523,289
21,394,399
(5,773,222) $
10,443,629
(4,912,039) $
31,838,028
(10,685,261)
The economic environment makes it difficult to project interest rates and future investment returns. During the prior
year, management believed that market conditions supported an increase in interest rates during fiscal 2016. Twelve
months later, interest rates have declined and the discount rate is nearly 1% lower than the same time last year. A
similar scenario exists this year as current indications tend to support an increase in interest rates. However, any
expectation or trend is purely speculation. If the economy shows indications of stronger growth, long-term interest
rates could increase, thereby reducing the benefit liabilities. However, increasing interest rates could have a negative
effect on investment returns, especially in the fixed income allocation, and any benefit obtained from reduced benefit
liabilities could be mitigated by less than expected returns on assets. Conversely, if the economy stagnates or declines,
interest rates could remain at lower levels or even drop, leading to an increase in the benefit liabilities. The Company
annually evaluates the returns on its targeted investment allocation model. 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. 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 4.89% (net of income taxes) for fiscal 2017. These rates are consistent with the expected long-term rates in
experienced during fiscal 2016. Management will continue to re-evaluate the return assumptions and adjust them as
market conditions warrant.
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 short-term 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 $750,000 to its pension plan and $1,000,000 to its postretirement plan in fiscal 2017. The Company will
continue to evaluate its benefit plan funding levels in light of funding requirements and ongoing investment returns and
make adjustments, as necessary, to avoid benefit restrictions.
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
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%
125,000
$
1,233,000
57,000
56,000
N/A
314,000
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.
27
Actuarial Assumptions
Discount rate
Rate of return on plan assets
Medical claim cost increase
Change in
Assumption
Increase (Decrease)
in Postretirement
Benefit Cost
Increase in
Accumulated
Postretirement
Benefit Obligation
-0.25% $
-0.25%
0.25%
(19,000) $
35,000
22,000
787,000
N/A
756,000
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 no commodity or interest rate
derivatives outstanding at September 30, 2016 and 2015.
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, 2016, the Company has $14,556,785 outstanding under its variable rate line-of-credit with an average
balance outstanding during the year of $9,991,078. The Company also had $3,396,200 outstanding under a 5-year
variable rate term loan. 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 $120,000. 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, 2016, the Company had no outstanding derivative instruments to hedge the price of natural gas. The
Company had approximately 2,537,000 decatherms of gas in storage, including LNG, at an average price of $2.93 per
decatherm compared to 2,418,000 decatherms at an average price of $3.38 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.
28
Item 8.
Financial Statements and Supplementary Data.
29
RGC Resources, Inc.
and Subsidiaries
Consolidated Financial Statements
for the Years Ended September 30, 2016, 2015
and 2014, 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, 2016, 2015 and 2014:
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, 2016 and 2015, 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, 2016. 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, 2016 and 2015, and the consolidated results of its
operations and its cash flows for each of the years in the three-year period ended September 30, 2016, 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, 2016, 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, 2016 expressed an unqualified opinion.
1715 Pratt Drive, Suite 2700
Blacksburg, Virginia
December 8, 2016
CERTIFIED PUBLIC ACCOUNTANTS
32
RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AS OF SEPTEMBER 30, 2016 AND 2015
ASSETS
CURRENT ASSETS:
Cash and cash equivalents
Accounts receivable, net
Materials and supplies
Gas in storage
Prepaid income taxes
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
Other
Total other assets
TOTAL ASSETS
2016
2015
$
643,252
$
3,478,983
824,139
7,436,785
1,550,836
1,548,329
985,234
3,196,573
968,108
8,160,498
1,657,066
1,182,343
15,482,324
16,149,822
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
168,033,032
(53,307,079)
114,725,953
3,903,599
118,629,552
10,923,243
—
144,577
11,067,820
$
165,552,849
$
145,847,194
(Continued)
33
RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AS OF SEPTEMBER 30, 2016 AND 2015
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Borrowings under 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:
Principal amount
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 10)
CAPITALIZATION:
Stockholders’ Equity:
2016
2015
$
14,556,785
$
970,244
5,345,575
287,794
1,605,608
1,627,105
3,194,255
909,687
9,340,997
912,995
5,141,677
—
1,560,351
1,579,441
2,766,097
1,901,426
28,497,053
23,202,984
33,896,200
(260,149)
33,636,051
5,682,556
9,348,443
13,763,820
18,957,854
47,752,673
30,500,000
(183,427)
30,316,573
5,295,868
8,885,486
10,685,261
14,620,031
39,486,646
Common Stock, $5 par value; authorized 10,000,000 shares; issued and
outstanding 4,788,289 and 4,741,498 shares in 2016 and 2015, respectively
Preferred stock, no par; authorized 5,000,000 shares; no shares issued and
outstanding in 2016 and 2015
Capital in excess of par value
Retained earnings
Accumulated other comprehensive loss
Total stockholders’ equity
23,941,445
23,707,490
—
9,509,548
24,713,310
(2,497,231)
55,667,072
—
8,647,669
22,772,377
(2,286,545)
52,840,991
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
$
165,552,849
$
145,847,194
See notes to consolidated financial statements.
(Concluded)
34
RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
YEARS ENDED SEPTEMBER 30, 2016, 2015 AND 2014
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
2016
2015
2014
$
58,079,990
$
67,094,290
$
73,865,487
983,301
59,063,291
1,095,317
68,189,607
1,150,647
75,016,134
27,009,330
37,437,315
489,047
27,498,377
31,564,914
545,859
37,983,174
30,206,433
45,091,274
587,771
45,679,045
29,337,089
13,098,086
13,486,885
13,383,388
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
1.22
1.22
$
$
$
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
1.08
1.08
$
$
$
1,560,386
4,711,447
19,655,221
9,681,868
—
206,887
1,827,001
7,647,980
2,939,540
4,708,440
1.00
1.00
4,766,604
4,773,175
4,728,210
4,731,676
4,715,478
4,716,282
$
$
$
See notes to consolidated financial statements.
35
RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
YEARS ENDED SEPTEMBER 30, 2016, 2015 AND 2014
NET INCOME
Other comprehensive income, net of tax:
Interest rate swaps
Defined benefit plans
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
COMPREHENSIVE INCOME
2016
2015
2014
$
5,806,866
$
5,094,415
$
4,708,440
—
(210,686)
(210,686)
5,596,180
$
—
(1,147,219)
(1,147,219)
3,947,196
$
1,232,546
(220,638)
1,011,908
$
5,720,348
See notes to consolidated financial statements.
36
Accumulated
Other
Comprehensive
Income (Loss)
$ (2,151,234) $ 49,502,422
4,708,440
Total
Stockholders’
Equity
—
—
1,011,908
1,011,908
—
—
—
75,310
(3,490,624)
213,391
$ (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
—
—
RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
YEARS ENDED SEPTEMBER 30, 2016, 2015 AND 2014
Balance - September 30, 2013
$ 23,546,630
$
8,003,787
$ 20,103,239
Common
Stock
Capital in
Excess of
Par Value
Retained
Earnings
Net income
Other comprehensive income
Stock option grants
Cash dividends declared ($0.74 per share)
—
—
—
—
Issuance of common stock (11,052 shares)
55,260
—
—
75,310
—
158,131
4,708,440
—
(3,490,624)
—
Balance - September 30, 2014
$ 23,601,890
$
8,237,228
$ 21,321,055
Net income
Other comprehensive loss
Exercise of stock options (2,600 shares)
Stock option grants
Cash dividends declared ($0.77 per share)
—
—
13,000
—
—
—
—
36,366
83,640
—
Issuance of common stock (18,520 shares)
92,600
290,435
5,094,415
—
—
—
(3,643,093)
—
Balance - September 30, 2015
$ 23,707,490
$
8,647,669
$ 22,772,377
Net income
Other comprehensive loss
Exercise of stock options (2,200 shares)
Stock option grants
Cash dividends declared ($0.81 per share)
—
—
11,000
—
—
—
—
30,762
64,640
—
Issuance of common stock (44,591 shares)
222,955
766,477
5,806,866
—
—
—
(3,865,933)
—
Balance - September 30, 2016
$ 23,941,445
$
9,509,548
$ 24,713,310
See notes to consolidated financial statements.
37
RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED SEPTEMBER 30, 2016, 2015 AND 2014
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 taxes and investment tax credits
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
Retirement of note payable
Retirement of long-term debt
Early termination fees
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:
2016
2015
2014
$ 5,806,866
$ 5,094,415
$ 4,708,440
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
(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
4,838,062
(452,834)
75,310
—
859,788
38,073
12,424
(1,219,641)
(1,208,134)
(306,744)
(505,006)
2,131,298
6,839,738
(17,945,719)
(3,055,746)
4,964
(20,996,501)
(13,780,356)
—
30,082
(13,750,274)
(14,715,428)
—
16,858
(14,698,570)
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)
25,363,774
(16,318,724)
— 30,500,000
— (15,000,000)
— (13,000,000)
— (2,237,961)
(193,081)
—
213,391
432,401
(3,465,034)
(3,603,424)
(2,875,076)
5,862,365
(1,996,467)
135,477
2,846,224
849,757
849,757
985,234
$
$
Interest
Income taxes
$ 1,480,665
(907,000)
$ 1,002,462
1,266,573
$ 1,966,263
2,387,000
See notes to consolidated financial statements.
38
RGC RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2016, 2015 AND 2014
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 59,600 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, 2016 and
2015 are as follows:
Regulatory Assets:
Current Assets:
Accounts receivable:
Accrued WNA revenues
Other:
September 30
2016
2015
$
148,663
$
229,281
Accrued pension and postretirement medical
835,704
530,781
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
2,055,369
11,460,738
816,344
15,328,763
$
2,169,556
8,378,419
375,268
11,695,250
909,687
$
1,901,426
238,694
153,365
5,682,556
9,348,443
16,179,380
$
5,295,868
8,885,486
16,236,145
$
$
$
As of September 30, 2016, the Company had regulatory assets in the amount of $13,261,449 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
2016
2015
$
160,354,300
$
143,172,628
12,594,294
12,628,692
185,577,286
$
12,501,179
12,359,225
168,033,032
$
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
3.25% for each of the fiscal years ended September 30, 2016, 2015 and 2014.
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 2016, 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
2016
5,295,868
85,263
(176,090)
310,568
166,947
5,682,556
$
$
2015
4,802,015
62,890
(162,072)
281,762
311,273
5,295,868
$
$
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, 2016, 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
2016
2015
2014
$
$
52,721
14,074
137,055
(126,916)
76,934
$
$
70,747
87,908
139,282
(245,216)
52,721
$
$
68,539
148,881
136,369
(283,042)
70,747
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 receivable 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, 2016 and 2015 were $1,004,061 and
$1,001,418, 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 7 and 11.
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
2016
5,806,866
4,766,604
$
2015
5,094,415
4,728,210
$
2014
4,708,440
4,715,478
6,571
4,773,175
3,466
4,731,676
804
4,716,282
1.22
1.22
$
$
1.08
1.08
$
$
1.00
1.00
$
$
$
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 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, 2016 and 2015, the Company had no
outstanding derivative instruments for the purchase of natural gas.
The Company also had two interest rate swaps that essentially converted its variable interest rate notes to fixed rate
debt instruments. Both swaps were terminated in September 2014 as part of the Company's debt refinancing. These
swaps qualified as cash flow hedges with changes in fair value reported in other comprehensive income.
No derivative instruments were deemed to be ineffective for any period presented.
Non-Cash Activity — Non-cash increase in investment in unconsolidated affiliate and corresponding increase in
capital contributions payable of $287,794.
Other Comprehensive Income(Loss)—A summary of other comprehensive income is provided below:
Year Ended September 30, 2016:
Defined benefit plans:
Net loss arising during period
Amortization of actuarial losses
Other comprehensive loss
Year Ended September 30, 2015:
Defined benefit plans:
Net loss arising during period
Amortization of actuarial losses
Other comprehensive loss
Year Ended September 30, 2014:
Interest rate swaps:
Unrealized losses
Transfer of realized losses to interest expense
Transfer of realized losses to regulatory asset
Net interest rate swaps
Defined benefit plans:
Net loss arising during period
Amortization of actuarial losses
Net defined benefit plans
Other comprehensive income
Before Tax
Amount
Tax
(Expense)
or Benefit
Net of Tax
Amount
$
$
$
$
$
$
(560,887) $
221,070
(339,817) $
(1,910,573) $
60,221
(1,850,352) $
(58,800) $
926,262
1,119,233
1,986,695
(397,714)
41,846
(355,868)
1,630,827
$
$
$
$
$
$
213,137
(84,006)
129,131
726,017
(22,884)
703,133
22,321
(351,609)
(424,861)
(754,149)
151,131
(15,901)
135,230
(618,919) $
(347,750)
137,064
(210,686)
(1,184,556)
37,337
(1,147,219)
(36,479)
574,653
694,372
1,232,546
(246,583)
25,945
(220,638)
1,011,908
The amortization of actuarial losses and transition obligation is included as components of net periodic pension and
postretirement benefit costs and is included in operations and maintenance expense.
44
Composition of Accumulated Other Comprehensive Income (Loss):
Balance September 30, 2013
Other comprehensive income (loss)
Balance September 30, 2014
Other comprehensive income (loss)
Balance September 30, 2015
Other comprehensive income (loss)
Balance September 30, 2016
Interest Rate
Swaps
(1,232,546) $
1,232,546
—
—
—
—
— $
$
$
Defined Benefit
Plans
Accumulated
Other
Comprehensive
Income (Loss)
(918,688) $
(220,638)
(1,139,326)
(1,147,219)
(2,286,545)
(210,686)
(2,497,231) $
(2,151,234)
1,011,908
(1,139,326)
(1,147,219)
(2,286,545)
(210,686)
(2,497,231)
Recently Adopted Accounting Standards—In April 2015, the FASB issued ASU 2015-03, Interest-Imputation of
Interest: Simplifying the Presentation of Debt Issuance Costs. This ASU requires that debt issuance costs related to a
recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt
liability. The Company previously recognized debt issuance costs in assets and amortized those costs over the term of
the debt. This guidance is effective for the Company for the annual reporting period ending September 30, 2017 and
interim periods within that annual period. Early application is permitted. The Company adopted the ASU in the period
ended September 30, 2015. The adoption of this ASU did not have any effect on the Company's results of operations
or cash flows; however, the unamortized balance of debt issuance costs were reclassified from assets to an offset
against long-term debt. Certain deferred costs related to the early retirement of debt in 2014 are classified as
regulatory assets and are not offset against debt.
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. The
Company applied the retrospective approach in adopting this ASU and reclassified $2,293,536 previously reflected as
a current deferred income tax asset against the balance of the non-current deferred tax liability in the September 30,
2015 consolidated balance sheet. There was no other impact to the Company’s financial position, results of operations
or cash flows.
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.
Recently Issued Accounting Standards—In May 2014, the FASB issued guidance under FASB ASC No. 606 -
Revenue from Contracts with Customers 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
45
satisfies the performance obligation. 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 application was not permitted. In
August 2015, the FASB issued ASU 2015-14 that deferred the effective date of this guidance by one year to
September 30, 2019. The FASB has issued subsequent guidance under ASC No. 606 to provide clarification of certain
aspects of the original ASU. All additional guidance is being considered as part of the Company's evaluation of the
revenue recognition standard. Although Management has not completed its evaluation of all the issued guidance under
ASC No. 606, the Company does not currently expect the guidance to have a material effect on its financial position,
results of operations or cash flows.
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 does not currently expect the new guidance to have a material effect on its financial position,
results of operations or cash flows.
Other accounting standards that have been issued or proposed by the FASB or other standard–setting bodies are not
currently applicable to the Company or are not expected to have a significant impact on the Company’s financial
position, results of operations and cash flows.
2.
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, 2016, the Company filed with the SCC an application for a modification to the SAVE (Steps to Advance
Virginia's Energy) Plan and Rider. The original SAVE Plan has been modified each year to incorporate certain
changes and to include new projects that qualify for rate recovery under the the Plan. 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. On October 18,
2016, the Company received approval of its application for a modification to the SAVE Plan and Rider. Under the
order, the SCC approved the extension of the SAVE Plan for an additional three years through 2021, the replacement
of three gas custody transfer stations and the replacement of coated steel tubing services in addition to the existing
plan to replace pre-1973 plastic pipe.
46
3.
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. If approved by the Federal Energy Regulatory Commission, 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 investment of approximately $35 million, by periodic capital contributions throughout the
design and construction phases of the project. Midstream held an approximate $3.5 million equity method investment
in the LLC at September 30, 2016. 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 5 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:
Balance Sheet Location of Other Investments:
Other Assets:
September 30
2016
2015
Investment in unconsolidated affiliate
$
3,496,404
$
Current Liabilities:
Capital contributions payable
$
287,794
$
—
—
Income Statement Location of Other Investments:
Equity in earnings of unconsolidated affiliate
For the Years ended September 30
2016
152,864
$
$
2015
2014
— $
—
4.
SHORT-TERM DEBT
The Company has available an unsecured line-of-credit with a bank which will expire March 31, 2017. The Company
anticipates being able to extend or replace this line-of-credit upon expiration. The Company’s available unsecured
line-of-credit varies during the year to accommodate its seasonal borrowing demands. Available limits under this
agreement for the remaining term are as follows:
Effective
September 30, 2016
March 1, 2017
Available
Line-of-Credit
$
24,000,000
17,000,000
47
A summary of the line-of-credit follows:
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
2016
$ 24,000,000
14,556,785
15,246,089
9,620,914
September 30
2015
$ 24,000,000
9,340,997
17,366,052
6,377,040
2014
$ 15,000,000
9,045,050
9,045,050
1,340,833
1.40%
1.53%
0.15%
1.17%
1.20%
0.15%
1.16%
1.16%
0.15%
Associated with the line-of-credit is a credit agreement that contains various provisions including a requirement that
the Company maintain an interest coverage ratio of not less than 1.5 to 1.
5.
LONG-TERM DEBT
On December 29, 2015, Midstream, a wholly-owned subsidiary of Resources, entered into a Credit Agreement (the
“Agreement”) and related Promissory Notes (the “Notes”) with Union Bank & Trust and Branch Banking & Trust
(collectively, the “Banks”), under which Midstream may borrow up to a total of $25 million, over a period of 5 years,
with an interest rate of 30-day LIBOR plus 160 basis points. Midstream issued the Notes to provide financing for
capital contributions in respect of its 1% interest in the LLC. Coinciding with Midstream's entry into the Agreement
and Notes, Resources entered into a Guaranty in favor of the Banks by which it guarantees Midstream's payment and
performance on the Notes.
Interest on the Notes is due monthly with the outstanding balance on the Notes due in full on December 29, 2020. The
Notes are unsecured. In accordance with the terms of the Agreement, 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
2016
2015
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
RGC Midstream, LLC:
Unsecured term notes payable, at 30-day
LIBOR plus 1.60% due December 29, 2020
Total
$ 30,500,000
$
173,773
$ 30,500,000
$
183,427
3,396,200
86,376
—
—
$ 33,896,200
$
260,149
$ 30,500,000
$
183,427
Debt issuance costs are amortized over the life of the related debt. As of September 30, 2016 and 2015, the Company
also had an unamortized loss on the early retirement of debt of $2,055,369 and $2,169,556, respectively, which has
been deferred as a regulatory asset and is being amortized over a 20 year period.
The unsecured notes payable contain various provisions, including two financial covenants. First, total long-term
debt, including current maturities, shall not exceed 65% of total capitalization. Second, the Company shall not allow
priority indebtedness to exceed 15% of total assets.
48
The aggregate annual maturities of long-term debt for the next five years ending after September 30, 2016 are as
follows:
Year Ending September 30
2017
2018
2019
2020
2021
Thereafter
Total
Maturities
—
—
—
—
3,396,200
30,500,000
33,896,200
$
$
6.
INCOME TAXES
The details of income tax expense are as follows:
Years Ended September 30
2016
2015
2014
Current income taxes:
Federal
State
Total current income taxes
Deferred income taxes:
Federal
State
Total deferred income taxes
Amortization of investment tax credits
Total income tax expense
379,180
$
1,789,294
$
(1,216,745) $
415,975
(800,770)
4,302,906
164,048
4,466,954
—
374,541
753,721
2,289,729
127,112
2,416,841
—
$
3,666,184
$
3,170,562
$
290,458
2,079,752
687,417
175,464
862,881
(3,093)
2,939,540
Income tax expense for the years ended September 30, 2016, 2015 and 2014 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
Amortization of investment tax credits
Other, net
Total income tax expense
Years Ended September 30
$
$
2016
9,473,050
3,220,837
382,815
—
62,532
$
$
2015
8,264,977
2,810,092
331,091
—
29,379
2014
7,647,980
2,600,313
307,509
(3,093)
34,811
3,666,184
$
3,170,562
$
2,939,540
$
$
$
49
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
Accrued gas costs
Total gross deferred tax liabilities
Net deferred tax liability
September 30
2016
2015
$
29,203
$
2,532,672
262,273
345,318
1,077,849
770,868
340,121
5,358,304
20,012
2,502,774
249,837
721,782
930,524
651,336
265,951
5,342,216
24,264,165
19,804,862
40,776
11,217
24,316,158
$
18,957,854
$
—
157,385
19,962,247
14,620,031
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 current year's 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.
The passage of the PATH Act provides for 50% bonus depreciation through December 31, 2017, 40% in calendar
2018 and 30% in 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, 2013 are no longer subject to examination.
7.
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
50
employees hired on or after January 1, 2017 will be eligible to participate in the pension plan. Employees hired prior
to January 1, 2017 will continue to participate in the plan and accrue benefits. The Board of Directors is also
considering the implementation of a contribution to the 401(k) Plan for employees hired on or after January 1, 2017.
The Company paid contribution would be equal to 3% of the employees' annual compensation. 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 its statement 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
2016
2015
2016
2015
$ 25,090,968
$ 22,853,206
$ 18,504,710
$ 15,355,668
Benefit obligation at beginning of year
$ 27,167,621
$ 24,636,695
$ 15,355,668
$ 14,983,169
Service cost
Interest cost
Actuarial loss
Benefit payments, net of retiree contributions
Benefit obligation at end of year
Change in fair value of plan assets:
Fair value of plan assets at beginning of year
Actual return on plan assets, net of taxes
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:
694,375
654,782
1,132,776
1,025,908
148,018
624,579
167,580
600,096
2,440,957
(1,940,779)
$ 29,494,950
1,487,278
(637,042)
$ 27,167,621
2,812,516
(436,071)
$ 18,504,710
70,196
(465,373)
$ 15,355,668
2,159,437
$ 21,394,399
$ 10,443,629
$ 10,646,249
(237,247)
500,000
1,500,000
(465,373)
(1,940,779)
$ 23,113,057
$ 10,443,629
$ (6,381,893) $ (5,773,222) $ (7,381,927) $ (4,912,039)
$ 20,514,179
(182,738)
1,700,000
(637,042)
$ 21,394,399
500,000
(436,071)
$ 11,122,783
615,225
Noncurrent liabilities
$ (6,381,893) $ (5,773,222) $ (7,381,927) $ (4,912,039)
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
1,583,345
1,694,924
913,886
591,621
$
1,583,345
$
1,694,924
$
913,886
$
591,621
6,732,800
5,280,756
5,563,642
3,628,448
Amounts recognized as regulatory assets
$
6,732,800
$
5,280,756
$
5,563,642
$
3,628,448
51
Effective with the valuation of the September 30, 2015 defined benefit obligations, the Company adopted the RP-2014
Mortality Tables as issued by the Society of Actuaries in late 2014. The adoption of the new tables, which reflected an
increase in assumed life expectancy, increased the September 30, 2015 pension liability by an estimated $1,300,000
and the postretirement liability by an estimated $1,000,000.
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, 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 $256,000 before tax, of accumulated other comprehensive loss will be
recognized as a portion of net periodic benefit costs in fiscal 2017 and approximately $836,000 of amounts deferred as
regulatory assets will be amortized and recognized in net periodic benefit costs in fiscal 2017.
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
2016, 2015 and 2014.
Pension Plan
Postretirement Plan
2016
2015
2014
2016
2015
2014
Assumptions used to determine benefit
obligations:
Discount rate
Expected rate of compensation increase
3.42%
4.00%
4.22%
4.00%
4.22%
4.00%
3.33%
N/A
4.15%
N/A
4.10%
N/A
Assumptions used to determine benefit
costs:
Discount rate
Expected long-term rate of return on plan
assets
Expected rate of compensation increase
4.22%
4.22%
4.82%
4.15%
4.10%
4.73%
7.00%
4.00%
7.00%
4.00%
7.00%
4.00%
4.89%
N/A
4.90%
N/A
4.92%
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:
Service cost
Interest cost
Expected return on plan assets
Recognized loss
Pension Plan
Postretirement Plan
2016
2015
2014
2016
2015
2014
$ 694,375
$
654,782
$
553,291
$ 148,018
$ 167,580
$ 168,634
1,132,776
(1,492,241)
501,678
1,025,908
(1,440,846)
257,378
1,020,302
(1,312,354)
136,394
624,579
(507,858)
250,173
600,096
(516,656)
197,058
602,684
(496,476)
89,515
Net periodic benefit cost
$ 836,588
$
497,222
$
397,633
$ 514,912
$ 448,078
$ 364,357
The assumed health care cost trend rates used in measuring the accumulated benefit obligation for the postretirement
medical plan as of September 30, 2016, 2015 and 2014 are presented below:
2016
Pre 65
2015
2014
2016
Post 65
2015
2014
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
7.50%
8.00%
8.50%
5.00%
5.00%
5.00%
5.00%
2021
5.00%
2021
5.00%
2021
5.00%
2016
5.00%
2015
5.00%
2014
52
The health care cost trend rate assumptions could have a significant effect on the amounts reported. A change of 1%
would have the following effects:
Effect on total service and interest cost components
Effect on accumulated postretirement benefit obligation
1% Increase
1% Decrease
$
137,000
3,083,000
$
(109,000)
(2,491,000)
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,
2016 and 2015 were:
Asset category:
Equity securities
Debt securities
Cash
Other
Pension Plan
Postretirement
Plan
Target
2016
2015
Target
2016
2015
60%
40%
—%
—%
63%
36%
1%
—%
64%
35%
1%
—%
50%
50%
—%
—%
52%
47%
—%
1%
52%
47%
1%
—%
53
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, 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
3,426,041
4,543,385
2,149,566
1,795,897
Mutual Funds:
Bonds
Domestic Fixed Income
Foreign Fixed Income
Equities
Domestic Large Cap Growth
Foreign Large Cap Growth
Foreign Large Cap Value
Foreign Large Cap Core
Total
$
3,615,209
234,622
1,043,395
366,420
373,480
950,404
23,113,057
$
—
—
—
—
—
—
—
—
—
—
—
117,265
$
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
22,995,792
$
—
—
—
—
—
—
—
—
—
—
—
—
—
54
Defined Benefit Pension Plan
Fair Value Measurements - September 30, 2015
Fair Value
Level 1
Level 2
Level 3
$
106,502
$
106,502
$
— $
Asset Class:
Cash
Common and Collective Trust and
Pooled Funds:
Bonds
Domestic Fixed Income
3,996,246
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
Domestic Large Cap Growth
Foreign Large Cap Value
Foreign Large Cap Core
3,150,561
4,183,172
1,937,613
1,873,313
3,313,331
213,118
1,030,957
653,276
936,310
—
—
—
—
—
—
—
—
—
—
3,996,246
3,150,561
4,183,172
1,937,613
1,873,313
3,313,331
213,118
1,030,957
653,276
936,310
Total
$
21,394,399
$
106,502
$
21,287,897
$
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
$
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
55
Postretirement Benefit Plan
Fair Value Measurements - September 30, 2015
Fair Value
Level 1
Level 2
Level 3
$
58,749
$
58,749
$
— $
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
4,845,174
38,654
1,746,621
1,638,695
194,260
186,344
417,980
893,115
378,596
45,441
—
—
—
—
—
—
—
—
—
—
4,845,174
38,654
1,746,621
1,638,695
194,260
186,344
417,980
893,115
378,596
45,441
$
10,443,629
$
58,749
$
10,384,880
$
—
—
—
—
—
—
—
—
—
—
—
—
Each mutual fund has been categorized based on its primary investment strategy.
The Company expects to contribute $750,000 to its pension plan and $1,000,000 to its postretirement benefit plan in
fiscal 2017.
The following table reflects expected future benefit payments:
Fiscal year ending September 30
2017
2018
2019
2020
2021
2022-2026
$
Pension
Plan
Postretirement
Plan
$
774,312
836,309
910,261
983,917
1,048,990
6,613,848
642,842
656,790
679,876
705,769
747,426
4,226,050
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 $353,793, $338,896 and $330,241 for 2016, 2015 and 2014, respectively.
8.
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, 2016, the number of shares available for
future grants was 41,000.
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 2016, 2015 and 2014, the Board approved
stock option grants to certain officers. As required by the KESOP, each option's exercise price per share equaled the
56
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,
2016
28.78%
3.99%
7.00
2.10%
2015
34.34%
4.11%
7.00
1.98%
2014
35.01%
4.21%
7.00
2.23%
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, 2016, 2015 and 2014 are
summarized below:
Number of
Shares
Weighted-
Average Exercise
Price
Options outstanding, September 30, 2013
Options granted
Options exercised
Options expired
Options forfeited
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
$
21,000
17,000
—
—
—
38,000
17,000
(2,600)
—
—
52,400
16,000
(2,200)
—
(8,000)
Options outstanding, September 30, 2016
58,200
$
19.01
18.95
—
—
—
18.98
21.60
18.99
—
—
19.83
21.22
18.98
—
19.80
20.25
Vested and exercisable at September 30,
2016
58,200
$
20.25
1
Aggregate intrinsic value includes only those options where the exercise price is below the market price.
57
Weighted-
Average
Remaining
Contractual
Terms (years)
9.5
Aggregate
Intrinsic Value 1
$
5,229
8.8
34,840
8.3
43,086
7.8
7.8
$
$
200,211
200,211
The weighted-average grant-date fair value of options granted during the years ended September 30, 2016, 2015 and
2014 was $4.04, $4.92 and $4.43, respectively. The intrinsic value of the options exercised during fiscal 2016 and
2015 was $8,418 and $5,624, respectively. The Company recognized $64,640, $83,640 and $75,310 in stock option
expense in fiscal 2016, 2015 and 2014, respectively.
The Company received $41,762 and $49,366 from the exercise of options in 2016 and 2015. No options were
exercised in 2014.
9.
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 34,764, 8,431 and 7 shares in 2016, 2015 and 2014, respectively. As
of September 30, 2016, the Company had 323,613 shares of stock available for issuance under the DRIP.
Restricted Stock Plan
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 Restricted Stock Plan:
2016
2015
2014
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
66,915
$
Granted
Vested
Forfeited
4,433
—
—
14.70
22.18
—
—
62,844
$
4,071
—
—
14.29
20.88
—
—
59,064
$
3,780
—
—
13.97
19.37
—
—
End of year balance
71,348
$
15.16
66,915
$
14.70
62,844
$
14.29
The fair market value of the Restricted Stock issued as compensation during fiscal 2016, 2015 and 2014 was $98,334,
$85,000 and $73,200. No Restricted Stock vested or was forfeited during fiscal 2016, 2015 and 2014.
As of September 30, 2016, the Company had 63,008 shares available for issuance 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
58
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 1,875, 2,731 and 4,098 shares valued at $39,819, $59,332 and $78,841,
respectively, in 2016, 2015 and 2014. As of September 30, 2016 the Company had 6,299 shares of stock available for
issuance under the Stock Bonus Plan.
10.
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, 2016 for the remainder of the contract period. The current asset management contract will expire in
March 2018.
Year
2016-2017
2017-2018
Total
Natural Gas Contracts
(In Decatherms)
2,071,061
295,866
2,366,927
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, 2016. 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 $24,852,000, $33,405,000 and $44,884,000 under the asset management, pipeline and
storage contracts in fiscal years 2016, 2015 and 2014, respectively. The table below details the pipeline and storage
capacity obligations as of September 30, 2016 for the remainder of the contract period.
Year
2016-2017
2017-2018
2018-2019
2019-2020
2020-2021
Thereafter
Total
Other Contracts
Pipeline and
Storage Capacity
$
10,474,339
8,784,004
7,215,235
4,800,201
2,476,475
2,682,848
$
36,433,102
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.
59
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.
11.
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, 2016 and 2015, respectively:
Liabilities:
Natural gas purchases
Total
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
$
$
—
—
Fair Value Measurements - September 30, 2015
Quoted Prices in
Active Markets
Level 1
Significant Other
Observable
Inputs
Level 2
Significant
Unobservable
Inputs
Level 3
Fair Value
712,710
712,710
$
$
— $
— $
712,710
712,710
$
$
—
—
$
$
$
$
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, 2016 and 2015, 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 short-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, 2016 and 2015.
Liabilities:
Long-term debt
Total
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
60
Liabilities:
Long-term debt
Total
Fair Value Measurements - September 30, 2015
Carrying
Amount
Quoted Prices in
Active Markets
Level 1
Significant Other
Observable
Inputs
Level 2
Significant
Unobservable
Inputs
Level 3
$
$
30,500,000
30,500,000
$
$
— $
— $
— $
— $
28,570,585
28,570,585
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 52 basis point drop in the 20-year Treasury combined with a reduction in
the assumed credit spreads accounted for the increase in the fair value of the fixed rate debt. The fair value for the
RGC Midstream debt is estimated by discounting the estimated credit spread extrapolated based on market conditions.
FASB ASC 825 – Financial Instruments requires disclosures regarding concentrations of credit risk from financial
instruments. Cash equivalents are investments in high-grade, short-term securities (original maturity less than three
months), placed with financially sound institutions. Accounts receivable are from a diverse group of customers
including individuals and small and large companies in various industries. The Company maintains certain credit
standards with its customers and requires a customer deposit if such evaluation warrants.
12.
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Quarterly financial data for the years ended September 30, 2016 and 2015 is summarized as follows:
2016
Operating revenues
Gross margin
Operating income
Net income
Earnings per share of common stock:
Basic
Diluted
2015
Operating revenues
Gross margin
Operating income
Net income
Earnings per share of common stock:
Basic
Diluted
13.
SUBSEQUENT EVENTS
First
Quarter
16,010,056
8,738,116
3,498,052
1,922,790
0.40
0.40
First
Quarter
21,250,065
8,622,143
3,514,352
1,924,376
0.41
0.41
$
$
$
$
$
$
$
$
$
$
$
$
Second
Quarter
21,777,773
10,649,269
5,444,314
3,111,447
0.65
0.65
Second
Quarter
26,431,729
10,213,770
4,879,469
2,779,344
0.59
0.59
$
$
$
$
$
$
$
$
$
$
$
$
Third
Quarter
11,295,197
6,312,340
1,453,350
627,068
0.13
0.13
Third
Quarter
10,774,409
5,961,828
956,219
354,940
0.08
0.07
$
$
$
$
$
$
$
$
$
$
$
$
Fourth
Quarter
9,980,265
5,865,189
816,376
145,561
0.03
0.03
Fourth
Quarter
9,733,404
5,408,692
656,152
35,755
0.01
0.01
$
$
$
$
$
$
$
$
$
$
$
$
On November 1, 2016, Roanoke Gas entered into a 5-year unsecured note with Branch Banking and 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 to convert the variable rate debt into a fixed-rate
instrument with an annual interest rate of 2.30%. The swap agreement is effective November 1, 2017, with the
monthly interest rate floating until the swap period begins. The proceeds from the note will be used to convert a
portion of the Company's line-of-credit balance into longer-term financing.
61
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.
* * * * * *
62
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, 2016, 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, 2016.
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, 2016, 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, 2016, 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, 2016.
63
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,
2016, 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, 2016, 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, 2016 and 2015 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, 2016, and our report dated December 8, 2016 expressed an unqualified opinion.
CERTIFIED PUBLIC ACCOUNTANTS
1715 Pratt Drive, Suite 2700
Blacksburg, Virginia
December 8, 2016
64
Item 9B.
Other Information
None
65
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 2017 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 2017
Annual Meeting of Shareholders of Resources, which information is incorporated herein by reference. In addition, the
Board of Directors has determined that 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 2017 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 Compliance" in the Proxy Statement for the 2017 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 2017 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 2017 Annual Meeting of Shareholders of
Resources, is incorporated herein by reference.
Item 13.
Certain Relationships and Related Transactions, and Director Independence.
For information with respect to certain relationships and related transactions, see "Transactions with Related Persons"
section in the Proxy Statement for the 2017 Annual Meeting of Shareholders of Resources, which is incorporated herein
by reference.
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 2017 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 2017
Annual Meeting of Shareholders of Resources is incorporated herein by reference.
66
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 (l)(l)
Second Amendment to RGC Resources, Inc. Restricted Stock Plan for Outside Directors
21
23
31.1
31.2
32.1*
32.2*
101
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, 2016, 2015 and 2014, formatted in XBRL (eXtensible Business Reporting Language);
Consolidated Balance Sheets at September 30, 2016 and 2015, (ii) Consolidated Statements of Income for
the years ended September 30, 2016, 2015 and 2014, (iii) Consolidated Statements of Comprehensive
Income for the years ended September 30, 2016, 2015 and 2014, (iv) Consolidated Statements of
Stockholders’ Equity for the years ended September 30, 2016, 2015 and 2014, (v) Consolidated Statements
of Cash Flows for the years ended September 30, 2016, 2015 and 2014, 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.
67
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, 2016
Date
68
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, 2016
John S. D'Orazio
Date
President and Chief Executive
Officer, Director
/S/ PAUL W. NESTER
December 8, 2016
Paul W. Nester
Date
Vice President, Treasurer and CFO
(principal accounting and financial
officer)
/S/ JOHN B. WILLIAMSON, III
December 8, 2016
Chairman of the Board and Director
John B. Williamson, III
Date
/S/ NANCY H. AGEE
December 8, 2016
Director
Nancy H. Agee
Date
/S/ ABNEY S. BOXLEY, III
December 8, 2016
Director
Abney S. Boxley, III
Date
/S/ MARYELLEN F. GOODLATTE
December 8, 2016
Director
Maryellen F. Goodlatte
Date
/S/ J. ALLEN LAYMAN
J. Allen Layman
December 8, 2016
Director
Date
/S/ GEORGE W. LOGAN
George W. Logan
December 8, 2016
Director
Date
/S/ S. FRANK SMITH
S. Frank Smith
December 8, 2016
Director
Date
/S/ RAYMOND D. SMOOT, JR.
December 8, 2016
Director
Raymond D. Smoot, Jr.
Date
69
Exhibit No.
3 (a)
3 (b)
4 (a)
4 (b)
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 10-K for the year ended September 30, 2011)
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)
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-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)
ITS-1 Service Agreement between Columbia Gulf Transmission Company and Roanoke Gas
Company dated November 1, 1993 (incorporated herein by reference to Exhibit 10(j) of the Annual
Report on Form 10-K for the fiscal year ended September 30, 1994 (SEC file number reference
0-367))
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))
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))
Gas Storage Contract under rate schedule FS (Production Area) Bear Creek II between Tennessee
Gas Pipeline Company and Roanoke Gas Company dated November 1, 1993 (incorporated herein
by reference to Exhibit 10(m) 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)
Gas Storage Contract under rate schedule FS (Production Area) Bear Creek I between Tennessee
Gas Pipeline Company and Roanoke Gas Company dated September 1, 1993 (incorporated herein
by reference to Exhibit 10(n) of the Annual Report on Form 10-K for the fiscal year ended
September 30, 1994 (SEC file number reference 0-367))
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))
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))
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)
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)
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)
10 (z)
10 (a)(a)
10 (b)(b)
10 (c)(c)
10 (d)(d)
10 (e)(e)
10 (f)(f)
10 (g)(g)
10 (h)(h)
10 (i)(i)
10 (j)(j)
10 (k)(k)
10 (l)(l)
10 (m)(m)
10 (n)(n)
10 (o)(o)
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)
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)
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)
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)
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)
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. Restricted Stock Plan for Outside Directors (incorporated herein by reference
to Exhibit 10(r)(r) of Annual Report on Form 10-K for the fiscal year ended September 30, 1999
SEC file reference number 0-367)
Amendment to RGC Resources, Inc. Restricted Stock Plan for Outside Directors (incorporated
herein by reference to Exhibit 10.2 on Form 10-Q as filed May 6, 2016)
Second Amendment to RGC Resources, Inc. Restricted Stock Plan for Outside Directors
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)
10 (p)(p)
10 (q)(q)
10 (r)(r)
10 (s)(s)
10 (t)(t)
10 (u)(u)
10 (v)(v)
10 (w)(w)
10 (x)(x)
10 (y)(y)
10 (z)(z)
10 (a)(a)(a)
10 (b)(b)(b)
10 (c)(c)(c)
10 (d)(d)(d)
10 (e)(e)(e)
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 $24,000,000 by Roanoke Gas
Company in favor of Wells Fargo Bank, N.A. dated March 31, 2016 (incorporated herein by
reference to Exhibit 10.1 on Form 8-K as filed April 4, 2016)
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)
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(x)(x) 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)
10 (f)(f)(f)
**
10 (g)(g)(g) **
10 (h)(h)(h)
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)
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)
21
23
31.1
31.2
32.1*
32.2*
101
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, 2016, 2015 and 2014, formatted in XBRL (eXtensible Business Reporting
Language); Consolidated Balance Sheets at September 30, 2016 and 2015, (ii) Consolidated
Statements of Income for the years ended September 30, 2016, 2015 and 2014, (iii) Consolidated
Statements of Comprehensive Income for the years ended September 30, 2016. 2015 and 2014, (iv)
Consolidated Statements of Stockholders’ Equity for the years ended September 30, 2016, 2015 and
2014, (v) Consolidated Statements of Cash Flows for the years ended September 30, 2016, 2015
and 2014, 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.
Exhibit 10 (l)(l)
Second Amendment to the Restricted Stock Plan for Outside Directors
The Amended and Restated Restricted Stock Plan for Outside Directors of RGC Resources, Inc. (the "Plan"),
is amended effective October 1, 2016, to change the first sentence of Section 3 of the Plan so that it reads as follows:
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.
This Amendment was adopted by the Board of Directors on July 25, 2016.
/s/ Paul W. Nester_____________
Paul W. Nester
Secretary
RGC Resources, Inc.
Subsidiaries of Registrant
Exhibit 21
Roanoke Gas Company
Diversified Energy Company
RGC Ventures of Virginia, Inc.
RGC Midstream, LLC
Exhibit 23
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in 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. 333-122742 on Form S-3 of RGC Resources, Inc. of our report dated December 8, 2016 appearing in this Annual
Report on Form 10-K of RGC Resources, Inc. for the year ended September 30, 2016.
CERTIFIED PUBLIC ACCOUNTANTS
1715 Pratt Drive, Suite 2700
Blacksburg, Virginia
December 8, 2016
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, 2016
/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, 2016
/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, 2016 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, 2016
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, 2016 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, 2016
25-Year Gas Pipeline
Modernization Program
Completion
Roanoke Gas Company announced the completion of a quarter
century modernization project to improve the safety and reliability of
natural gas service throughout the City of Roanoke and surrounding area.
Prior to the 1960’s, the nation’s natural gas suppliers installed cast iron or
bare steel pipelines to deliver natural gas to customers. In Roanoke, some
of these underground lines dated back to the 19th century. Starting in
1991, the project was intentionally spaced over 25 years to limit service
interruptions. With the completion of the project, 200 miles of bare steel
and cast iron pipelines have been replaced with modern polyethylene
plastic pipe.
Captured in the photograph below, Company personnel and city
officials commemorated the replacement of the final section with the
ceremonial installation of the last section of upgraded pipeline.
Board of
Directors
Nancy Howell Agee
President and CEO
Carilion Clinic
Abney S. Boxley, III
President and CEO
Boxley Materials Company
John S. D’Orazio
President and CEO
RGC Resources, Inc.
Maryellen F. Goodlatte
Attorney and Principal
Glenn Feldmann
J. Allen Layman
Private Investor
George W. Logan
Principal, Pine Street Partners, LLC;
Faculty, UVA Darden Graduate
School of Business
S. Frank Smith
Consultant
Alpha Coal Sales Co., LLC
Raymond D. Smoot, Jr.
Senior Fellow
Virginia Tech Foundation, Inc.
John B. Williamson, III
Chairman of the Board
Corporate
Information
ANNUAL REPORT AND 10-K
submitted
This annual report, 10-K and the
statements contained
financial
the
herein are
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.
to
ANNUAL MEETING
The annual meeting of shareholders
of the Company will be held at The
Hotel Roanoke and Conference
Center, 110 Shenandoah Avenue,
on
Roanoke, Virginia,
Monday, February 6, 2017, 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,
2016.
24016
FINANCIAL INQUIRIES
All financial analysts and professional
investment managers should direct
their requests for information to:
RGC Resources, Inc.
Vice President and CFO
P.O. Box 13007, Roanoke, VA 24030
(540) 777-3853
Access up-to-date information on
RGC Resources, Inc. and its
subsidiaries at
www.rgcresources.com.
DIVIDEND REINVESTMENT AND STOCK
PURCHASE PLAN INQUIRIES
the Company’s Dividend
and
other
stock
or
shareholders of
Through
Reinvestment and Stock Purchase
Plan,
record are
offered a convenient way to
acquire and reinvest cash dividends
in additional shares of the Company’s
avoid
common
commissions
charges.
Additionally, shareholders are given
on-line access
transfers,
consolidate accounts, replace stock
certificates and dividend payments,
set-up
update
information and much
personal
more. Broadridge Corporate
Issuer
Solutions administers the plan and is
the agent for participants. For more
information, inquiries may be directed
to RGC Resources, Inc., Shareholder
Services, P.O. Box 13007, Roanoke, VA
24030, (540) 777-3853.
to make
deposit,
direct
STOCK PLAN ADMINISTRATOR
Broadridge Corporate Issuer Solutions
1155 Long Island Avenue
Edgewood, NY 11717
(855) 449-0975
Email: shareholder@broadridge.com
Shareholder Portal:
https://investor.broadridge.com/rgco
EGISTERED ACCOUNTING FIRM
INDEPENDENT REGISTERED PUBLIC
ACCOUNTING FIRM
Brown Edwards & Company, L.L.P.
1715 Pratt Drive, Suite 2700
Blacksburg, VA 24060
Photography by Amy Nance-Pearman at
boydphotography.com
519 Kimball Avenue, N.E.
P.O. Box 13007
Roanoke, Virginia 24030
www.rgcresources.com
NASDAQ: RGCO