2015
ANNUAL REPORT
KEY FINANCIAL INFORMATION
Year Ending September 30
2015
2014
2013
Natural Gas Deliveries (DTH's)
9,875,007 10,087,651 9,408,894
Net Income
$ 5,094,415 $ 4,708,440 $ 4,262,052
Earnings Per Share
$ 1.08
$ 1.00
$ 0.91
Natural Gas Customers
59,080 58,553 58,238
Additions to Plan
$ 13,780,356 $ 14,715,428 $ 9,977,433
Regular Annualized
Dividends Per Share
Earnings Per Share
Stock Price, September 30
PRESIDENT’S LETTER
John S. D’Orazio,
President and Chief Executive Officer
To Our Shareholders
I am very pleased to report earnings of $5.1 million or $1.08 per share
outstanding compared to $1.00 per share
improvement. I am also pleased to report that our Board of Directors
approved an annualized dividend increase from $0.77 per share to
$0.81 per share, effective with the February 1, 2016, quarterly
dividend payments. The February dividend will reflect 71 years of
continuous quarterly dividend payments and 19 annual dividend
increases in the past 20 years.
last year or an 8%
We announced on October 1, 2015 that RGC Resources, through its
newly formed subsidiary RGC Midstream, LLC, acquired a 1% ownership interest in Mountain Valley
Pipeline LLC, which is a joint venture between EQT Midstream Partners LP, affiliates of NextEra Energy Inc.,
WGL Holdings Inc. and Vega Energy Partners Ltd. The Mountain Valley Pipeline (MVP) will be a 301 mile,
42-inch diameter pipeline with an approximate total cost of $3.5 billion. It will transport natural gas from
the Marcellus and Utica production areas through West Virginia and Southwest Virginia to the growing
natural gas markets in the Southeast and mid-Atlantic region. This pipeline is subject to approval and
regulation by the Federal Energy Regulatory Commission (FERC). The MVP is expected to be in service
during the fourth quarter of 2018. The MVP will address the growing demand for natural gas in our region
and enhance the reliability of the Roanoke Gas distribution system. It will also improve our ability to
expand our natural gas system into areas that currently do not have access and promote economic growth
and new investments in these areas. Our investment in this project is projected to be $35 million over the
next three years. We believe this strategic investment will complement our core business and enhance
shareholder value.
Continued
Special points of interest:
Earnings of $5.1 million or $1.08 per share
outstanding compared to $1.00 per share last
year or an 8% improvement.
Dividend increase from $0.77 per share to
$0.81 per share, effective February 1, 2016.
Mountain Valley Pipeline 1% ownership
interest.
1% increase in new customer additions.
PRESIDENT’S LETTER (continued)
The economy in the Roanoke area continues to grow at a steady pace and, as a result, Roanoke Gas
experienced a 1% increase in new customer additions. Approximately 71% of the new customer
additions were conversions, with the remainder from new construction. Conversions occur when
existing homes or businesses convert to natural gas from other fuel sources. Industrial demand was soft
in 2015. Future industrial demand will depend upon the state of the economy and market conditions.
During the past year, we provided gas service to a new manufacturing customer, who quickly became
one of our top customers based on gas usage. We are also excited to provide natural gas service to the
first compressed natural gas station in the Roanoke Valley. The station will be owned and operated by a
major fleet operator and is projected to be operational in the first quarter of fiscal 2016.
We experienced another strong year in the operations side of the business. Weather was 6% colder
than the 30-year average. In February, we experienced two days where natural gas deliveries ranked in
the top five days in the Company’s history. As a result of the efforts to modernize our system, the
distribution system operated as designed without any issues during those extremely cold periods.
We continue to invest in capital improvements for Roanoke Gas Company. In fiscal 2015, we invested
$13.8 million with the primary focus on the modernization of our distribution system. We replaced
approximately 10 miles of cast iron and bare steel pipe with polyethylene pipe. When we began our
renewal program in 1991, bare steel and cast iron mains represented 25% of our distribution system.
Cast iron and bare steel pipe now represent less than 2% of our distribution system. We anticipate
replacing the remaining bare steel and cast iron pipe by 2017. We will maintain our focus of further
enhancing the safety and reliability of our system with a fiscal 2016 capital budget of $15.2 million. This
will include the replacement and upgrade of two natural gas transfer stations.
On a national level, the natural gas industry continues to increase production in the various shale
formations through improved drilling and fracking technologies. There are numerous interstate pipeline
projects, either under construction or in the process of filing for FERC approval, to transport supply from
the shale formations to areas of the country where the demand for natural gas is increasing. Natural gas
prices are forecasted to remain low and stable on both a near and intermediate term basis due to
production and infrastructure improvements.
On behalf of our employees and Board of Directors, I thank you for your continuing decision to invest in
RGC Resources. We are pleased to be part of an exciting era for the natural gas industry and I look
forward to reporting to you at the end of 2016 on what I anticipate to be another year of solid
performance.
John S. D’Orazio
President and Chief Executive Officer
Visit us on the Web:
www.rgcresources.com
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, 2015
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, 2015. $89,254,811
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, 2015
4,750,645 SHARES
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the RGC Resources, Inc. Proxy Statement for the 2016 Annual Meeting of Shareholders are incorporated by
reference into Part III hereof.
TABLE OF CONTENTS
Cautionary Note Regarding Forward Looking Statements
PART I
Item 1.
Business
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2.
Properties
Item 3.
Legal Proceedings
Item 4. Mine Safety Disclosures
PART II
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
PART III
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
Part IV
Item 15. Exhibits and Financial Statement Schedules
Signatures
Page Number
2
3
6
10
10
10
10
11
12
13
27
28
60
60
63
64
64
64
64
64
65
66
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, RGC
Ventures of Virginia, Inc 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 2000, the information technology department of Resources formed Application Resources, Inc. under RGC Ventures
of Virginia, Inc. to provide information technology consulting services. In 2011, the Company also formed The Utility
Consultants under RGC Ventures of Virginia, Inc to provide utility and regulatory consulting services to other utilities.
The operations of RGC Ventures of Virginia, Inc. contributed less than 6% of other revenues and less than 1% of total
revenues of Resources during fiscal 2015. The Utility Consultants portion of RGC Ventures of Virginia, Inc. and
Diversified Energy Company currently have no active operations.
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 12 of the Company's annual consolidated financial statements and under the Equity Investment in
Mountain Valley Pipeline section of Item 7.
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
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
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
3
Residential
Commercial
Industrial
Other Utility
Other Non-Utility
Total Percent
Total Value
Customers
Volume
Revenue
Margin
2013
91.2%
8.7%
0.1%
0.0%
0.0%
100.0%
58,238
41%
28%
31%
0%
0%
100%
57%
33%
6%
2%
2%
100%
58%
25%
12%
3%
2%
100%
9,408,894
$
63,205,666
$
27,602,891
Roanoke Gas’ regulated natural gas distribution business accounted for approximately 98% of Resources total revenues
for fiscal years ending September 30, 2015, 2014 and 2013. The table 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 6% of total revenues even though they represent 30% of
total natural gas deliveries for the year ended September 30, 2015 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 Resources to these customers is used for heating. For the fiscal year ended September 30, 2015, approximately 68%
of the Company’s total DTH of natural gas deliveries and 77% of the residential and commercial deliveries were made
in the five-month period of November through March. These percentages are consistent with prior years. Total natural
gas deliveries were 9.9 million DTH, 10.1 million DTH and 9.4 million DTH in fiscal 2015, 2014 and 2013,
respectively.
Suppliers
Roanoke Gas relies on multiple interstate pipelines including those operated by Columbia Gas Transmission
Corporation and Columbia Gulf Transmission Corporation (together “Columbia”), and East Tennessee Natural Gas
Company (“East Tennessee”), Tennessee Gas Pipeline, Midwestern Gas Transmission 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 2020. 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 220,000 DTH of natural gas in a liquid state for use during peak demand, has the capability of
providing an additional 33,000 DTH per day. Combined, the pipelines and LNG facility can provide more than 111,000
DTH on a single winter day. In fiscal 2015, the Company realized a maximum one day-customer demand of 91,341
DTH which represented the highest single day volume delivery in the Company's history.
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 and storage rights and gas supply inventories
4
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, 2017.
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, which all expire
December 31, 2015.
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, 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 energy sources such as fuel oil, electricity, propane, coal and solar. Competition can be intense
among the other energy sources and can be based primarily on price. 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 new
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 customer conversions from an alternative energy
source to natural gas along its distribution lines.
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 charges at which natural
gas is 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. The SCC also grants certificates of public convenience and necessity to
distribute natural gas in Virginia.
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, 2015, Resources had 125 full-time employees and 133 total employees. As of that date, 33
employees, or 26% of the Company’s full-time employees, belonged to the United Steel, Paper and Forestry, Rubber,
Manufacturing, Energy, Allied-Industrial International Union, Local No. 515 and were represented under a collective
bargaining agreement. The union has been in place at the Company since 1952. The Company and the union
successfully negotiated a new collective bargaining agreement during 2015 that will expire on July 31, 2020.
Management maintains an amicable relationship with the union.
5
Website Access to Reports
The Company’s website address is www.rgcresources.com. Information appearing on this website is not incorporated
by reference in and is not a part of this annual report. The Company files reports with the Securities and Exchange
Commission ("SEC"). A copy of this annual report, as well as other recent annual and quarter 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 can obtain other Company filings with the SEC.
Item 1A.
Risk Factors
Please carefully consider the risks described below regarding the Company. The risks described below 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.
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. Recent enforcement actions by the Virginia Division of Utility and Railroad Safety have resulted in increased
fines for gas distribution companies across the state. 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.
Availability of adequate and reliable pipeline capacity.
The Company is 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, accidents, equipment breakdowns, 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, ultimately resulting in a longer-term negative impact on earnings.
6
Investment in Mountain Valley Pipeline.
The success or failure 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, completing the construction of the pipeline within the targeted time
frame and budget and fully subscribing the capacity of the pipeline once in service. 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 recoverable 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 damages under contracts, 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. project siting, financing, construction, permitting, governmental approvals and the negotiation of project
development agreements that may impede its development and operating activities. 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.
7
Security breach or cyber-attacks on the Company’s computer systems could corrupt financial information, expose
confidential personal information or compromise the safe and reliable delivery of natural gas.
A breach of the Company’s information systems from cyber-attacks or other sources could lead to disruptions in
natural gas deliveries or compromise the safety of our 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 as well as slow or declining growth in new
customer additions, both 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 result in increased 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. 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. New regulations could result
in a significant reduction in the use of coal as a fuel for electric power generation, 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.
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.
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 (“DRIP”) 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 investment in the LLC. 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.
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
8
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 make natural gas a less attractive energy source to the Company’s customers; thereby
potentially resulting 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.
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
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 of these plans. Such funding obligations could have a material impact on liquidity by reducing
cash flows and could negatively affect results of operations.
Weather conditions may cause revenues and earnings to vary from year to year.
The Company’s revenues and earnings are highly 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 with no benefit of additional revenues to offset
those costs as a result of the weather normalization adjustment.
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. A significant competitive factor is price. 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.
9
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,
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 1,125 miles of transmission and distribution pipeline with transmission and distribution plant
representing more than 85% 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 adequate, management continues to evaluate the adequacy of its
current facilities and intends to complete the replacement of its remaining cast iron and bare steel pipeline within the
next two years.
Item 3.
Legal Proceedings.
The Company was a defendant in two civil lawsuits associated with a November 2009 explosion and fire at a West
Virginia residence. The first lawsuit was dismissed by order on March 31, 2015, and the second lawsuit was dismissed
by order on April 27, 2015. The final resolution was consistent with management's expectations as the settlement did
not materially affect the Company's financial position, results of operation, or liquidity.
The Company is not known to be a party to any other pending legal proceedings.
Item 4.
Mine Safety Disclosures.
Not applicable.
10
PART II
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities.
Market Information
Resources' common stock is listed on the NASDAQ Global Market under the trading symbol RGCO. Payment of
dividends is within the discretion of the Board of directors and will depend on, among other factors, earnings, capital
requirements, and the operating and financial condition of the Company.
Year Ending September 30, 2015
High
Low
Declared
Range of Bid Prices
Cash Dividends
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
Year Ending September 30, 2014
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
$
$
$
$
22.45
25.67
22.99
21.96
19.98
20.06
19.73
20.51
$
$
19.28
20.20
19.78
19.95
18.10
18.46
19.00
19.17
0.1925
0.1925
0.1925
0.1925
0.185
0.185
0.185
0.185
As of November 30, 2015, there were 1,209 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, 2010 through
September 30, 2015 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, 2010 in the Company’s
common stock and in each index as of September 30, 2015, 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 $172 for the Company’s common stock, $181 for the Dow Jones US Utilities Index and $187 for the
S&P 500 Index.
11
A summary of the Company’s equity compensation plans follows as of September 30, 2015:
(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))
52,400
—
52,400
$19.83
—
$19.83
128,134
—
128,134
Plan category
Equity compensation plans approved by security holders
Equity compensation plans not approved by security holders
Total
Item 6.
Selected Financial Data.
12
Year Ending September 30,
2015
2014
2013
2012
2011
Operating Revenues
Gross Margin
Operating Income
Net Income
$ 68,189,607
$ 75,016,134
$ 63,205,666
$ 58,799,687
$ 70,798,871
30,206,433
29,337,089
27,602,891
26,933,097
27,269,566
10,006,192
5,094,415
9,681,868
4,708,440
8,795,055
4,262,052
8,786,535
4,296,745
9,313,046
4,653,473
Basic Earnings Per Share
Cash Dividends Declared Per Share
Book Value Per Share
$
$
$
1.08
0.77
11.14
$
$
$
1.00
0.74
11.02
$
$
$
0.91
1.72
10.51
$
$
$
0.92
0.70
10.85
$
$
$
1.01
0.68
10.55
Average Shares Outstanding
4,728,210
4,715,478
4,698,727
4,647,439
4,592,713
Total Assets
$148,140,730
$139,127,641
$124,510,870
$129,735,019
$125,522,242
Long-Term Debt (Less Current
Portion)
$ 30,500,000
$ 30,500,000
$ 13,000,000
$ 13,000,000
$ 13,000,000
Stockholders' Equity
52,840,991
52,020,847
49,502,422
50,682,930
48,785,778
Shares Outstanding at Sept. 30
4,741,498
4,720,378
4,709,326
4,670,567
4,624,682
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Forward-Looking Statements
This report contains forward-looking statements that relate to future transactions, events or expectations. RGC
Resources, Inc. (“Resources” or the “Company”) may publish forward-looking statements relating to such matters as
anticipated financial performance, business prospects, technological developments, new products, research and
development activities and similar matters. These statements are based on management’s current expectations and
information available at the time of such statements and are believed to be reasonable and are made in good faith. The
Private Securities Litigation Reform Act of 1995 provides a safe harbor for forward-looking statements. In order to
comply with the terms of the safe harbor, the Company notes that a variety of factors could cause the Company’s actual
results and experience to differ materially from the anticipated results or expectations expressed in the Company’s
forward-looking statements. The risks and uncertainties that may affect the operations, performance, development and
results of the Company’s business include, but are not limited to, those set forth in the following discussion and within
Item 1A “Risk Factors” of this Annual Report on Form 10-K. All of these factors are difficult to predict and many are
beyond the Company’s control. Accordingly, while the Company believes its forward-looking statements to be
reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from
them will be realized. When used in the Company’s documents or news releases, the words “anticipate,” “believe,”
“intend,” “plan,” “estimate,” “expect,” “objective,” “projection,” “forecast,” “budget,” “assume,” “indicate” or similar
words or future or conditional verbs such as “will,” “would,” “should,” “can,” “could” or “may” are intended to
identify forward-looking statements.
Forward-looking statements reflect the Company’s current expectations only as of the date they are made. The
Company assumes no duty to update these statements should expectations change or actual results differ from current
expectations except as required by applicable laws and regulations.
Overview
Resources is an energy services company primarily engaged in the regulated sale and distribution of natural gas to
approximately 59,100 residential, commercial and industrial customers in Roanoke, Virginia and the surrounding
localities, through its Roanoke Gas Company (“Roanoke Gas”) subsidiary. Resources also provides certain unregulated
services through Roanoke Gas and utility information system services through RGC Ventures of Virginia, Inc., which
operates as The Utility Consultants and Application Resources. The Company also formed a new wholly-owned
13
subsidiary, RGC Midstream, LLC ("Midstream"), which was created to invest in the Mountain Valley Pipeline ("MVP")
project. On October 1, 2015, Midstream executed the agreements to become a 1% member in the MVP project. More
information is provided under the Equity Investment in Mountain Valley Pipeline section below. The unregulated
operations represent less than 3% 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.
Management anticipates replacing all remaining cast iron and bare steel pipe within the next two years and expects to
continue its renewal program with plans to replace first generation pre-1973 plastic pipe.
The Company is also dedicated to the safeguarding of its information technology systems. These systems contain
confidential customer, vendor and employee information as well as important financial data. There is risk associated
with the unauthorized access of this information with a malicious intent to corrupt data, cause operational disruptions,
or compromise information. Management believes it has taken reasonable security measures to protect these systems
from cyber security attacks and other types of breaches; however, there can be no guarantee that a breach will not
occur. In the event of a breach, 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
breach of confidential information.
Over 97% 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 and a Steps to Advance Virginia Energy
("SAVE") adjustment rider.
The Company's approved billing rates include a component designed to allow for the recovery of the cost of natural gas
used by its customers. The cost of natural gas is considered a pass-through cost and is independent of the non-gas rates
of the Company. This rate component, referred to as the PGA clause, allows the Company to pass along to its customers
increases and decreases in natural gas costs incurred by its regulated operations. On a quarterly basis, the Company
files a PGA rate adjustment request with the SCC to adjust the gas cost component of its rates up or down depending on
projected price and activity. Once administrative approval is received, the Company adjusts the gas cost component of
its rates to reflect the approved amount. As actual costs will differ from the projections used in establishing the PGA
rate, the Company will either over-recover or under-recover its actual gas costs during the period. The difference
between actual costs incurred and costs recovered through the application of the PGA is recorded as a regulatory asset
or liability. At the end of the annual deferral period, the balance is amortized over an ensuing 12-month period as
amounts are reflected in customer billings.
The WNA reduces the volatility in earnings due to the variability in temperatures during the heating season. The WNA
is based on a weather measurement band around 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
14
price protection when the weather is colder than normal. Prior to April 2014, the WNA provided a weather band of 3%
above and below normal, whereby the Company would bill its customers for the lost margin (excluding gas costs) for
the impact of weather that was more than 3% warmer than normal or refund customers the excess margin earned for
weather that was more than 3% colder than normal. Effective with the WNA year that began April 2014, the 3%
weather band was removed and the WNA is now based strictly on temperature variations from normal. For the fiscal
year ended September 30, 2015, the Company recorded a $609,000 reduction in revenue 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 8.8% colder than normal. If the
WNA weather band had been 0% for the entire fiscal 2014 instead of 3% for the period October 1, 2013 through March
31, 2014, revenue would have been adjusted down by $814,000. No revenue adjustment for WNA was made for fiscal
2013 as the number of heating degree days fell within the 3% band then in effect.
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 carrying cost revenue (“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 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. As the
commodity price for natural gas has declined by more than $1.00 a decatherm compared to the same period last year,
the price of gas delivered into storage during the current year has declined by a similar amount. The result was a
decline in the price of gas in storage to $3.38 per decatherm at September 30, 2015 compared to a price in storage of
$4.71 and $4.08 at September 30, 2014 and 2013, respectively. However, the average dollar balance of gas in storage
inventory actually increased over the prior fiscal year due to the higher-priced gas in storage at the beginning of fiscal
2015 combined with a greater level of withdrawals in fiscal 2014 due to the colder winter. Although the average
balance of gas in storage during the current year was higher than the prior fiscal year, ICC revenues during fiscal 2015
declined by approximately $46,000 due to a reduction in the weighted-average cost of capital. The weighted-average
cost of capital declined from last year due to the refinancing of the Company's long-term debt in September 2014
combined with an increasing allocation of low cost short-term debt in the determination of the ICC rate. Based on the
current prices of natural gas futures, the average dollar balance of gas in storage is expected to be much lower in the
next fiscal year, resulting in lower ICC revenues in fiscal 2016.
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 provide for the recovery of non-gas related expenses and 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 year and the level of capital investment continues to grow, SAVE Plan
revenues have increased significantly. The Company recognized approximately $1,308,000, $292,000 and $169,000 in
SAVE Plan revenues for years ended September 30, 2015, 2014 and 2013. SAVE revenues will be included as part of
the new 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 year as some companies
15
have either shut down or relocated all or portions of their operations elsewhere. In addition, a couple of the Company's
larger industrial customers have reduced natural gas consumption amid lower production activities. The impact of
these relocations or the duration of these curtailments is unknown at this time. However, despite these losses, the local
economy appears relatively stable and should continue to slowly improve absent a major economic setback, on either a
local or national level.
Results of Operations
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
Decrease
Percentage
Gas Utilities
Other
Total Operating Revenues
$
$
67,094,290
1,095,317
68,189,607
$
$
73,865,487
1,150,647
75,016,134
$
$
(6,771,197)
(55,330)
(6,826,527)
(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.
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. As the Company continues to invest in eligible SAVE Plan
infrastructure, the associated SAVE Plan revenues will continue to increase. Customer base charges also increased due
16
to modest customer growth. As discussed above, 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 and decreased usage at two of the Company's largest
customers. The effect of the warmer weather was mitigated in part by the WNA mechanism. The prior year WNA
mechanism provided for a weather band of 3% variance around normal during the winter heating season while the
current heating season had a 0% weather band. Because the prior 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 current 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 ("pension plan")
and postretirement medical plan ("postretirement plan") expense. 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. More information on these plans and the impact on the financial statements are provided under
the Pension and Postretirement Benefits section of the Critical Accounting Policies and Estimates below and in Note 6
of the consolidated financial statements. 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 MVP. Additional information on the investment in MVP is provided under the Equity
Investment in Mountain Valley Pipeline section below and in Note 12 of the consolidated financial statements. Total
capitalized overheads declined by $106,000 because of delays in the production of liquified natural gas due to
maintenance down time, lower capital expenditures and a reduction in the capitalization rate compared to the prior year.
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
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.
17
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.
Fiscal Year 2014 Compared with Fiscal Year 2013
The table below reflects operating revenues, volume activity and heating degree-days.
Operating Revenues
Year Ended September 30,
2014
2013
Increase /
(Decrease)
Percentage
Gas Utilities
Other
Total Operating Revenues
$
73,865,487
$
62,024,174
$
1,150,647
75,016,134
1,181,492
63,205,666
11,841,313
(30,845)
11,810,468
19 %
(3)%
19 %
Delivered Volumes
Year Ended September 30,
Regulated Natural Gas (DTH)
Residential and Commercial
Transportation and Interruptible
Total Delivered Volumes
Heating Degree Days
(Unofficial)
2014
2013
Increase
Percentage
7,005,920
3,081,731
10,087,651
6,498,783
2,910,111
9,408,894
507,137
171,620
678,757
4,351
4,001
350
8%
6%
7%
9%
Total gas utility operating revenues for the year ended September 30, 2014 increased by 19% from the year ended
September 30, 2013. The increase in gas revenues was primarily attributable to a combination of a 7% increase in total
delivered natural gas volumes, a 30% per decatherm increase in the average commodity price of natural gas,
implementation of a non-gas rate increase and higher SAVE Plan revenues. The increase in delivered volumes was
driven by the colder winter heating season where total heating degree days increased by 9% over fiscal 2013 and were
above the 30-year average by the same percentage. Transportation and interruptible volumes, which are primarily
driven by production activities rather than weather, increased by 6%. Other revenues decreased by 3% due to the
completion of a one-time project during the prior year more than offsetting increases in the level of certain other
contract services during fiscal 2014.
18
Gross Margin
Year Ended September 30,
2014
2013
Increase
Percentage
Gas Utility
Other
Total Gross Margin
$
$
28,774,213
562,876
29,337,089
$
$
27,108,112
494,779
27,602,891
$
$
1,666,101
68,097
1,734,198
6%
14%
6%
Regulated natural gas margins from utility operations increased by 6% from fiscal 2013, primarily as a result of higher
residential and commercial sales volumes, the implementation of a non-gas rate increase and the addition of the SAVE
Plan rider. Residential and commercial volumes (which are strongly correlated to the weather) increased due to the
much colder winter season. The higher margins generated by the increased residential and commercial volume were
mostly offset by a net WNA refund of $563,000 recognized in fiscal 2014. The Company also implemented a non-gas
rate increase effective November 1, 2013 and an increased SAVE Plan Rider beginning January 1, 2014. The non-gas
rate increase was designed to provide approximately $887,000 in additional annual non-gas revenues. The
implementation of the increased non-gas rates in November 2013 accounted for approximately $422,000 of the increase
in customer base charges, a flat monthly fee billed to each natural gas customer, and $474,000 of the additional
volumetric revenue. The SAVE Plan Rider provided an additional $123,000 in margin. ICC revenues continued to
decline with a $58,000 reduction in fiscal 2014 compared to fiscal 2013 due to the larger storage withdrawals and lower
ICC factor.
Other margins, consisting of non-utility related services, increased by $68,097 due to an increased level of activity
under one of the contracted services. 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.
The changes in the components of the gas utility margin are summarized below:
Customer Base Charge
SAVE Plan
Volumetric
WNA
Carrying Cost
Other
Total
Twelve Months Ended September 30,
2014
2013
$
12,064,764
$
11,405,093
$
291,946
15,990,704
(563,187)
879,381
110,605
168,747
14,497,351
—
937,684
99,237
Increase
(Decrease)
659,671
123,199
1,493,353
(563,187)
(58,303)
11,368
$
28,774,213
$
27,108,112
$
1,666,101
Operations and Maintenance Expense - Operations and maintenance expenses increased by $529,789, or 4%, in
fiscal 2014 compared with fiscal 2013 primarily due to higher labor costs, contracted services, bad debt expense and
corporate insurance expense more than offsetting significant reductions in employee benefit costs and greater
capitalization of Company overheads on construction projects and LNG (liquefied natural gas) production. Labor costs
and contracted services increased by $1,128,000 primarily due to a full year of increased operations staffing, timing of
pipeline right-of-way clearing, a full year of costs related to an SCC mandated meter installation inspection and
remediation program, expenses related to updating the Company’s corrosion control processes, benefit consulting
services and network services support and training. Bad debt expense increased by approximately $64,000 related to
much higher customer billings due to a colder winter heating season. Corporate property and liability insurance
increased by $93,000 due to a combination of higher premiums and increased general liability coverage limits. These
higher costs were partially offset by a $605,000 reduction in employee benefit expenses, specifically in the pension
plan and postretirement plan. These actuarially determined expenses declined in fiscal 2014 due to a combination of a
higher discount rate for valuing both plans’ liabilities at September 30, 2013 and strong investment performance of both
plans’ assets. In addition, $339,000 of additional overheads was capitalized due to a significantly higher level of
19
construction expenditures related to the Company’s renewal program and other projects. Total capital expenditures rose
by more than $4.7 million over the prior year. The remaining increase of $188,000 relates to a variety of areas
including additional facility and equipment maintenance and support costs, higher utility expenses and increased
administrative costs related to the Company’s operations.
General Taxes - General taxes increased $79,640, or 5%, primarily due to higher property taxes associated with
increases in utility property and greater payroll taxes related to increased operations staffing.
Depreciation - Depreciation expense increased by $237,956, or 5%, corresponding to the increase in utility plant
investment partially offset by lower depreciation rates.
Other Expense - Other expense, net, increased by $146,770 primarily due to the absence of interest income related to
the ANGD note which was paid off in fiscal 2013 combined with a greater level of corporate charitable giving and
increased SCC pipeline assessments.
Interest Expense - Total interest expense remained virtually unchanged from fiscal 2013 as the Company benefited in
September from lower interest expense due to its debt refinancing which offset the increased interest incurred under the
line-of-credit.
Income Taxes - Income tax expense increased by $294,753 on higher pre-tax earnings. The effective tax rate for fiscal
2014 was 38.4% compared to 38.3% for 2013.
Net Income and Dividends - Net income for fiscal 2014 was $4,708,440 compared to $4,262,052 for fiscal 2013.
Basic and diluted earnings per share were $1.00 in fiscal 2014 compared to $0.91 in fiscal 2013. Dividends declared
per share of common stock were $0.74 in fiscal 2014 compared to $1.72 in fiscal 2013, which included the one-time
special dividend of $1.00.
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 increased by $135,477 in fiscal 2015 compared to decreases of $1,996,467 in fiscal 2014
and $6,063,647 in fiscal 2013. The following table summarizes the categories of sources and uses of cash:
Cash Flow Summary
Year Ended September 30,
2015
2014
2013
Provided by operating activities
Used in investing activities
Provided by (used in) financing activities
Increase (decrease) in cash and cash equivalents
$
$
$
16,760,827
(13,750,274)
(2,875,076)
$
6,839,738
(14,698,570)
5,862,365
10,037,070
(9,947,510)
(6,153,207)
135,477
$
(1,996,467) $
(6,063,647)
Cash Flows Provided by Operating Activities:
The seasonal nature of the natural gas business causes operating cash flows to fluctuate significantly during the year as
well as from year to year. Factors, including weather, energy prices, natural gas storage levels and customer
collections, all contribute to working capital levels and related cash flows. Generally, operating cash flows are positive
during the second and third quarters as a combination of earnings, declining storage gas levels and collections on
customer accounts all contribute to higher cash levels. During the first and fourth quarters, operating cash flows
20
generally decrease due to the combination of increases in natural gas storage levels and rising customer receivable
balances.
Cash provided by operating activities was $16,761,000 in fiscal 2015, $6,840,000 in fiscal 2014 and $10,037,000 in
fiscal 2013. Cash provided by operating activities increased by nearly $10,000,000 from last year primarily as a result
of lower natural gas commodity prices and the extension of 50% bonus depreciation for tax purposes for calendar 2014.
The gas cost component of the Company's natural gas billing rates for the high volume winter period from January
through March were derived based on natural gas futures pricing in early December 2014 when expectations were that
prices would rise slightly during the period. Instead, the commodity price of gas declined by nearly $1.50 per
decatherm from December 2014 until early February 2015, at which time the price leveled off. As a result, the
Company was over-recovered on gas costs for billings rendered during this time period. The Company also benefited
from the decline in natural gas prices as natural gas purchased for storage was at lower rates than in fiscal 2014. The
Company purchases natural gas for storage purposes during the spring and summer months for use during the fall and
winter heating season. As natural gas prices remained at lower levels during the spring and summer, the price of gas in
storage declined from $4.71 per decatherm at September 30, 2014 to $3.38 at September 30, 2015, which resulted in an
overall decline in storage inventory of $3,242,000. In addition, the extension of bonus depreciation to the end of
calendar 2014 accounted for most of the increase in the deferred tax liability. Operating cash flow also increased due to
higher net income and depreciation amounts. The cash windfall on the over-recovery of gas costs will be short-lived as
the excess collected will be refunded to customers in 2016. In addition, deferred tax liabilities related to accelerated
and bonus depreciation on the Company's utility plant at September 30, 2015 will begin to reverse in 2016 or later,
resulting in additional cash outflows for payment of the taxes. Conversely, during fiscal 2014 storage inventory
balances increased by more than $1,000,000 and the Company went from an over-collected position to an under-
collected position, resulting in a $1,208,000 use of operating cash.
Cash Flows Used in Investing Activities:
Investing activities primarily consist of expenditures under the Company’s construction program, which involves a
combination of replacing aging 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 and
expansion have continued at elevated levels with total expenditures of $13,800,000 in fiscal 2015, $14,700,000 in fiscal
2014 and approximately $10,000,000 in fiscal 2013. The Company renewed 10 miles of bare steel and cast iron natural
gas distribution main and replaced 594 services in fiscal 2015. This compares to 13.6 miles of main and 942 services in
fiscal 2014 and 13 miles of main and 1,064 services in fiscal 2013. Total costs related to the renewal program continue
to increase as the less complex and highly concentrated customer areas of the Company’s natural gas distribution
system have been completed, leaving the more difficult sections to be done. Completion of the remaining pipeline
replacement will more than likely be at a higher cost. The Company’s capital expenditures also included costs to
extend mains and services to 609 new customers in fiscal 2015 compared to 673 in fiscal 2014 and 468 in fiscal 2013.
In addition, the Company completed a significant main relocation and replacement of the compressor at the LNG plant
in fiscal 2015.
RGC Resources is committed to the safe and reliable delivery of natural gas to its customers and, as a result, plans to
commit the necessary resources to its pipeline renewal program with an expectation to replace all remaining cast iron
and bare steel pipe within the next two years. As a reflection of this commitment, the Company’s capital budget for
next year is currently estimated to be in excess of fiscal 2015 with the continuation of the pipeline replacement program
and the replacement of two additional transfer stations. Depreciation provided approximately 38% of the current year’s
capital expenditures compared to 33% for 2014 and 47% for 2013. Upon completion of the bare steel and cast iron
pipe replacement, the Company plans to direct its efforts to replacing all pre-1973 plastic mains with polyethylene pipe.
This project encompasses approximately 40 miles of natural gas main with a 2019 anticipated completion. The
Company expects to increase its borrowing activity to meet the funding requirements of these plans.
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 used by financing activities were
$2,875,000 for fiscal 2015 compared to cash provided by financing activities of $5,862,000 for fiscal 2014 and cash
used in financing activities of $6,153,000 for fiscal 2013. After significant activity in the financing area in 2014,
21
financing cash flow returned to a more normal pattern in fiscal 2015. 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's utilization of its line-of-credit to fund both the Company’s seasonal working capital needs as well as bridge
financing for its capital budget increased but not nearly to the extent expected due to the higher cash flows from
operations. Dividends increased as the annualized dividend rate went from $0.74 per share to $0.77 per share in 2015.
Fiscal 2013 included a special one-time dividend of $1.00 per share in addition to the regular quarterly dividend. The
special dividend totaled $4,675,337, of which $425,630 was returned to the Company under the DRIP Plan. The
Company’s consolidated capitalization was 63.4% equity and 36.6% long-term debt at September 30, 2015. This
compares to 63.0% equity and 37.0% long-term debt at September 30, 2014
Effective March 31, 2015, 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 with an increase in the total borrowing limit. 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 $6,000,000 to $24,000,000 during the term of the agreement. The
upper limit of the line-of-credit increased over prior years due to expected capital expenditure funding needs. The line-
of-credit agreement will expire March 31, 2016. 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.
In addition to the Company's ongoing capital projects, Midstream has a commitment to invest approximately $35
million over the next three years under the agreement as a 1% member of Mountain Valley Pipeline, LLC. The
Company plans to use a combination of debt and equity financing to meet this commitment.
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, 2015, the estimated recorded and unrecorded obligations are as follows:
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
$
— $
9,340,997
$ 9,340,997
$
— $
—
— $
— $ 30,500,000
$ 30,500,000
—
—
9,340,997
— $ 30,500,000
$ 39,840,997
(1) See Note 4 to the consolidated financial statements.
(2) See Note 3 to the consolidated financial statements.
22
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)
$ 11,392,645
—
24,457
1,299,300
—
$ 17,787,400
—
—
2,598,600
—
$ 8,599,382
—
—
2,598,600
—
$
— $ 37,779,427
—
—
24,457
—
24,688,700
18,192,200
—
—
Investment in MVP (8)
Other Obligations (9)
5,300,000
114,501
25,000,000
34,598
4,700,000
2,340
—
27,380
35,000,000
178,819
Total
$ 18,130,903
$ 45,420,598
$ 15,900,322
$ 18,219,580
$ 97,671,403
(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 9 to the consolidated
financial statements.
(5) Accrued interest on line-of-credit balance at September 30, 2015, including minimum facility fee on unused line-of-
credit. See Note 3 to the consolidated financial statements.
(6) Semi-annual interest payment on 20-year $30.5 million note payable September 18, 2034. See Note 4 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 6 to the consolidated financial statements.
(8) Projected 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 Mountain Valley Pipeline, LLC (the "LLC"), an investment in the Mountain
Valley Pipeline project. The purpose of the LLC is to construct and operate a natural gas pipeline connecting an
existing 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 with an expected decision in late 2016.
Assuming a favorable response by FERC, the pipeline is expected to be in service by the end of calendar 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, the Company will benefit from access to
another source of natural gas to its distribution system. Currently, Roanoke Gas is served by two pipelines and a
liquefied natural gas storage facility. Damage to or interruption in supply from any of these sources, especially during
the winter heating season, could have a significant impact on the Company's ability to serve its customers. A third
pipeline would reduce the risk related to 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 for the acquisition of land and materials related to the construction of the pipeline and other
pre-construction costs. Once approved, more significant cash draws will be required.
Regulatory Affairs
On June 30, 2015, the Company filed an application for modification of the SAVE (Steps to Advance Virginia’s
Energy) 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
23
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 amendments in 2013 and 2014
included additional projects related to the replacement of bare steel and cast iron natural gas pipe in addition to two
other major projects and added the investment for the related meter and regulator installations located on customer
premises. On September 25, 2015, the Company received approval for its most recent amendment to the SAVE Plan
effective for calendar year 2016, which included an increase in the investment to complete replacement of the bare steel
and cast iron natural gas pipe in addition to the replacement of first generation plastic pipe. The SCC also approved the
inclusion of the replacement of two of the Company's natural gas transfer stations and an increase in the allowed
spending variance for projects under the SAVE Plan. The projects included under the SAVE Plan will enhance the
safety and reliability of the Company’s gas distribution system and reduce greenhouse emissions. In addition, the
recovery of the depreciation and related expenses on these projects through the SAVE Plan rider will allow the
Company to forego a formal non-gas rate increase at this time.
The Company currently holds the only franchises and certificates of public convenience and necessity to distribute
natural gas in its service area. Certificates of public convenience and necessity are issued by the SCC to provide
service in the cities and counties in the Company's service territory. These certificates are intended for perpetual
duration subject to compliance and regulatory standards. Franchises are granted by the local cities and towns served by
the Company and are generally granted for a defined period of time. The current franchises with the City of Roanoke,
the City of Salem and the Town of Vinton will expire January 1, 2016. The Company is currently in negotiations to
renew the franchises in each of these localities. Management anticipates that it will be able to renew all of its
franchises.
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 Mountain Valley Pipeline 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.
On June 4, 2014, the Company filed an application with the SCC requesting approval to extend its authority to incur
short-term indebtedness of up to $30,000,000 and to issue up to $60,000,000 in long-term debt securities as part of its
long-term financing plan, which included the refinancing of higher interest rate debt and funding for the Company’s
pipeline replacement program and other infrastructure projects. On June 25, 2014, the SCC issued an order granting
the approval of the Company’s request. The authority to issue long-term debt extends through September 30, 2019. In
September 2014, the Company retired $28,000,000 in outstanding debt and replaced it with $30,500,000 in lower
interest rate long-term debt. With significant capital expenditures planned over the next few years related to the SAVE
Plan and other projects, the Company will have the flexibility to seek and manage the timing of long-term financing.
The Company’s provision for depreciation is computed principally based on composite rates determined by
depreciation studies. These depreciation studies are required to be performed on the regulated utility assets of Roanoke
Gas Company at least every five years. In June 2014, the Company filed an updated depreciation study with the SCC
to update the previous study that was implemented in fiscal 2009. The SCC approved new rates in September 2014
which resulted in a small reduction in the overall composite depreciation rate from 3.35% in 2013 to 3.25% in fiscal
2014 and 2015. The new rates were implemented retroactive to October 1, 2013.
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.
24
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 $1,001,418 and $1,071,128 as of
September 30, 2015 and 2014, 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 6 to the consolidated financial statements, are based on
numerous assumptions and factors, including provisions of the plans, employee demographics, contributions made to
the plan, return on plan assets and various actuarial calculations, assumptions and accounting requirements. In regard
to the pension plan, specific factors include assumptions regarding the discount rate used in determining future benefit
obligations, expected long-term rate of return on plan assets, compensation increases and life expectancies. Similarly,
the postretirement medical plan also requires the estimation of many of the same factors as the pension plan in addition
to assumptions regarding the rate of medical inflation and Medicare availability. Actual results may differ materially
from the results expected from the actuarial assumptions due to changing economic conditions, differences in actual
returns on plan assets, different rates of medical inflation, volatility in interest rates and changes in life expectancy.
Such differences may result in a material impact on the amount of expense recorded in future periods or the value of the
obligations on the balance sheet.
In selecting the discount rate to be used in determining the benefit liability, the Company utilized the Citigroup yield
curves which incorporate the rates of return on high-quality, fixed-income investments that corresponded to the length
and timing of benefit streams expected under both the pension plan and postretirement plan. The Company used a
discount rate of 4.22% and 4.15% for valuing its pension plan liability and postretirement plan liability at September
30, 2015. This rate was unchanged for the pension plan and increased by only 0.05% from the prior year for the
postretirement plan. The ongoing low interest rate environment has kept the discount rate depressed thereby keeping
the liabilities at higher levels. Although the 30-year Treasury rate decreased from 3.21% to 2.87%, the Moody’s Aaa
was nearly unchanged decreasing by only 0.05% which corresponds to the minimal change in the discount rates used
by the benefit plans. As the discount rates remained at or near last year's levels, the increase in each plan's liability was
25
driven in part to an additional year of accreated service. However, the most significant impact to the liabilities is
attributed to the adoption of new mortality tables. On October 27, 2014, the Society of Actuaries released the final
reports of the pension plan RP-2014 Mortality Tables and the Mortality Improvement Scale MP-2014. The new
mortality tables, which were adopted by the Company for its current 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 by approximately 5% or nearly
$1.3 million and the postretirement liability by approximately 7% or about $1 million, thereby increasing future
expense.
Following better than expected returns in fiscal 2013 and 2014, the returns on the related pension and postretirement
assets for fiscal 2015 fell short of the corresponding long-term rate of return assumptions. During fiscal 2015 fourth
quarter, the equity markets experienced a greater than 10% market correction which was reflected in the plans' asset
balances at September 30, 2015. The Company took advantage of lower equity prices and contributed an additional
$900,000 during the quarter, over and above the previously projected $800,000 annual contribution to the pension plan.
The increased contributions served to mitigate the impact of the adoption of the RP-2014 Mortiality Tables and lower
investment returns. As a result of the increase in the funded deficit, pension and postretirement medical plan expense
will increase in fiscal 2016 due to an increase in the amortization of the actuarial loss. The following tables reflect the
funded status of both plans at the corresponding fiscal year ends.
Funded status - September 30, 2015
Pension
Postretirement
Total
Benefit obligation
Fair value of assets
Funded status
Funded status - September 30, 2014
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)
Pension
Postretirement
Total
24,636,695
$
14,983,169
$
39,619,864
20,514,179
(4,122,516) $
10,646,249
(4,336,920) $
31,160,428
(8,459,436)
The economic environment makes it difficult to project interest rates and future investment returns. Current indications
tend to support an increase in interest rates; however, any expectation or trend beyond an initial increase is
indeterminable. If the economy improves, 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 2016. These rates
are consistent with the expected long-term rates in place during fiscal 2015.
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
26
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 (Pension Benefit Guaranty Corporation) 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 the greater of
the minimum annual pension contribution requirement or its expense level for subsequent years. The Company
currently expects to contribute approximately $500,000 to its pension plan and $500,000 to its postretirement plan in
fiscal 2016. With pension expense expected to be approximately $837,000 in fiscal 2016, management is still
following the funding strategy when considering the $900,000 in additional funding made in the fiscal fourth quarter of
2015. 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%
114,000
$
1,132,000
53,000
55,000
N/A
306,000
The following schedule reflects the sensitivity of postretirement benefit costs from changes in certain actuarial
assumptions, while the other components of the calculation remain constant.
Actuarial Assumptions
Discount rate
Rate of return on plan assets
Medical claim cost increase
Change in
Assumption
Increase in
Postretirement
Benefit Cost
Increase in
Accumulated
Postretirement
Benefit
Obligation
-0.25% $
-0.25%
0.25%
35,000
$
569,000
26,000
78,000
N/A
596,000
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, 2015 and 2014.
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.
27
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, 2015, the Company has $9,340,997 outstanding under its variable rate line-of-credit. 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 $64,700. 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, 2015, the Company had no outstanding derivative instruments to hedge the price of natural gas. The
Company had approximately 2,418,000 decatherms of gas in storage, including LNG, at an average price of $3.38 per
decatherm compared to 2,424,000 decatherms at an average price of $4.71 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 the derivative contracts and other price hedging techniques are passed through to
customers when realized through the regulated natural gas PGA mechanism.
Item 8.
Financial Statements and Supplementary Data.
28
RGC Resources, Inc.
and Subsidiaries
Consolidated Financial Statements
for the Years Ended September 30, 2015, 2014
and 2013, and Report of Independent
Registered Public Accounting Firm
29
RGC RESOURCES, INC. AND SUBSIDIARIES
TABLE OF CONTENTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED SEPTEMBER 30, 2015,
2014 and 2013:
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
31
32
34
35
36
37
38
30
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, 2015 and 2014, 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,
2015. 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, 2015 and 2014, and the consolidated
results of its operations and its cash flows for each of the years in the three-year period ended September 30,
2015, 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, 2015, based on criteria established in Internal Control-Integrated Framework - 1992 issued by the Committee
of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated December 4, 2015
expressed an unqualified opinion.
CERTIFIED PUBLIC ACCOUNTANTS
1715 Pratt Drive, Suite 2700
Blacksburg, Virginia
December 4, 2015
31
RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AS OF SEPTEMBER 30, 2015 AND 2014
ASSETS
CURRENT ASSETS:
Cash and cash equivalents
Accounts receivable, net
Materials and supplies
Gas in storage
Prepaid income taxes
Deferred income taxes
Under-recovery of gas costs
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
Other
Total other assets
TOTAL ASSETS
2015
2014
$
985,234
$
3,196,573
968,108
8,160,498
1,657,066
2,293,536
—
1,182,343
18,443,358
168,033,032
(53,307,079)
114,725,953
3,903,599
118,629,552
10,923,243
144,577
11,067,820
849,757
3,730,173
893,672
11,402,990
1,144,214
1,704,320
180,831
1,104,660
21,010,617
155,360,200
(50,645,642)
104,714,558
4,029,019
108,743,577
9,273,389
100,058
9,373,447
$
148,140,730
$
139,127,641
(Continued)
32
RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AS OF SEPTEMBER 30, 2015 AND 2014
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Borrowings under line-of-credit
Dividends payable
Accounts 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 9)
CAPITALIZATION:
Stockholders’ Equity:
2015
2014
$
9,340,997
$
912,995
5,141,677
1,560,351
1,579,441
2,766,097
1,901,426
9,045,050
873,326
5,367,299
1,373,927
1,492,150
2,200,882
—
23,202,984
20,352,634
30,500,000
(183,427)
30,316,573
5,295,868
8,885,486
10,685,261
16,913,567
41,780,182
30,500,000
(193,081)
30,306,919
4,802,015
8,575,147
8,459,436
14,610,643
36,447,241
Common stock, $5 par value; authorized 10,000,000 shares; issued and
outstanding 4,741,498 and 4,720,378 shares in 2015 and 2014, respectively
Preferred stock, no par; authorized 5,000,000 shares; no shares issued and
outstanding in 2015 and 2014
Capital in excess of par value
Retained earnings
Accumulated other comprehensive loss
Total stockholders’ equity
23,707,490
23,601,890
—
8,647,669
22,772,377
(2,286,545)
52,840,991
—
8,237,228
21,321,055
(1,139,326)
52,020,847
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
$
148,140,730
$
139,127,641
See notes to consolidated financial statements.
(Concluded)
33
RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
YEARS ENDED SEPTEMBER 30, 2015, 2014 AND 2013
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
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
2015
2014
2013
$
67,094,290
$
73,865,487
$
62,024,174
1,095,317
68,189,607
1,150,647
75,016,134
1,181,492
63,205,666
37,437,315
45,091,274
545,859
37,983,174
30,206,433
13,486,885
1,606,421
5,106,935
20,200,241
10,006,192
228,796
1,512,419
8,264,977
3,170,562
5,094,415
1.08
1.08
$
$
$
587,771
45,679,045
29,337,089
13,383,388
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
$
$
$
34,916,062
686,713
35,602,775
27,602,891
12,853,599
1,480,746
4,473,491
18,807,836
8,795,055
60,117
1,828,099
6,906,839
2,644,787
4,262,052
0.91
0.91
4,728,210
4,731,676
4,715,478
4,716,282
4,698,727
4,698,766
$
$
$
See notes to consolidated financial statements.
34
RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
YEARS ENDED SEPTEMBER 30, 2015, 2014 AND 2013
NET INCOME
Other comprehensive income, net of tax:
Interest rate swaps
Defined benefit plans
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
COMPREHENSIVE INCOME
2015
2014
2013
$
5,094,415
$
4,708,440
$
4,262,052
—
(1,147,219)
(1,147,219)
3,947,196
$
1,232,546
(220,638)
1,011,908
$
5,720,348
$
576,985
1,221,866
1,798,851
6,060,903
See notes to consolidated financial statements.
35
RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
YEARS ENDED SEPTEMBER 30, 2015, 2014 AND 2013
Common
Stock
Capital in
Excess of
Par Value
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Total
Stockholders’
Equity
(3,950,085) $ 50,682,930
4,262,052
—
1,798,851
1,798,851
—
—
84,840
(8,063,327)
—
737,076
(2,151,234) $ 49,502,422
4,708,440
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
Balance - September 30, 2012
$ 23,352,835
$
7,375,666
$ 23,904,514
$
Net income
Other comprehensive income
Stock option grants
Cash dividends declared ($1.72 per
share)
Issuance of common stock (38,759
shares)
Balance - September 30, 2013
Net income
Other comprehensive income
Stock option grants
Cash dividends declared ($0.74 per
share)
Issuance of common stock (11,052
shares)
—
—
—
—
—
—
84,840
4,262,052
—
—
—
(8,063,327)
193,795
543,281
—
$ 23,546,630
$
8,003,787
$ 20,103,239
$
—
—
—
—
—
—
75,310
4,708,440
—
—
—
(3,490,624)
55,260
158,131
—
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)
Issuance of common stock (18,520
shares)
—
—
13,000
—
—
—
—
36,366
83,640
5,094,415
—
—
—
—
(3,643,093)
92,600
290,435
—
Balance - September 30, 2015
$ 23,707,490
$
8,647,669
$ 22,772,377
$
See notes to consolidated financial statements.
36
RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED SEPTEMBER 30, 2015, 2014 AND 2013
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
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
Proceeds from disposal of utility property
Net cash used in investing activities
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds on collection of notes
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 during the year for:
$
2015
2014
2013
$ 5,094,415
$ 4,708,440
$ 4,262,052
5,219,893
(406,731)
83,640
2,416,841
105,815
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
4,656,716
(502,587)
84,840
786,990
39,186
(374,682)
(997,378)
1,714,497
1,106,590
(739,154)
5,775,018
10,037,070
(13,780,356)
30,082
(13,750,274)
(14,715,428)
16,858
(14,698,570)
(9,977,433)
29,923
(9,947,510)
—
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)
—
432,401
213,391
(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
$
1,142,770
4,354,402
(4,354,402)
—
—
—
—
—
737,076
(8,033,053)
(6,153,207)
(6,063,647)
8,909,871
$ 2,846,224
Interest
Income taxes
$ 1,002,462
1,266,573
$ 1,966,263
2,387,000
$ 1,803,528
622,076
See notes to consolidated financial statements.
37
RGC RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2015, 2014 AND 2013
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation—RGC Resources, Inc. is an energy services company 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 59,100 residential, commercial and industrial customers within its service areas in Roanoke, Virginia
and the surrounding localities. The Company’s business is seasonal in nature and weather dependent 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”). Application Resources provides information system
services to software providers in the utility industry. The Utility Consultants, which provided regulatory consulting
services to other utilities, ceased operations in 2015. RGC Midstream, LLC is a new wholly-owned subsidiary created
in 2015 to invest in a pipeline project. More information is provided in Note 12. Diversified Energy Company is
currently inactive.
The Company follows accounting and reporting standards set 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.
38
Regulatory assets and liabilities included in the Company’s consolidated balance sheets as of September 30, 2015 and
2014 are as follows:
Regulatory Assets:
Current Assets:
Accounts receivable:
Accrued WNA revenues
Under-recovery of gas costs
Other:
Accrued pension and postretirement medical
Utility Property:
In service:
Other
Other Assets:
Regulatory assets:
Premium on early retirement of debt
Accrued pension and postretirement medical
Other
Total regulatory assets
Regulatory Liabilities:
Current Liabilities:
Over-recovery of gas costs
Accrued expenses:
Over-recovery of SAVE Plan revenues
Deferred Credits and Other Liabilities:
Asset retirement obligations
Regulatory cost of retirement obligations
Total regulatory liabilities
September 30
2015
2014
229,281
—
$
143,753
180,831
530,781
394,215
11,945
11,945
2,169,556
8,378,419
375,268
11,695,250
$
2,283,744
6,884,812
104,833
10,004,133
1,901,426
$
—
153,365
187,203
5,295,868
8,885,486
16,236,145
$
4,802,015
8,575,147
13,564,365
$
$
$
$
As of September 30, 2015, the Company had regulatory assets in the amount of $9,513,749 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. The cost of additions to utility plant includes
direct charges and overhead. The cost of depreciable property retired is 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. Maintenance, repairs, and minor renewals and
betterments of property are charged to operations and maintenance.
Utility plant is comprised of the following major classes of assets:
Distribution and transmission
LNG storage
General and miscellaneous
Total utility plant in service
Years Ended September 30
2015
2014
$
143,172,628
$
134,439,225
12,501,179
12,359,225
9,163,158
11,757,817
$
168,033,032
$
155,360,200
Provisions for depreciation are computed principally at composite straight-line rates as determined by depreciation
studies required to be performed on the regulated utility assets of Roanoke Gas Company at least every five years. The
39
Company completed its most recent depreciation study in June 2014. The composite weighted-average depreciation
rates provided for under the new depreciation study were 3.25% for the fiscal years ended September 30, 2015 and
2014 compared to 3.35% for the fiscal year ended September 30, 2013 under the prior rates. For the year ended
September 30, 2014, the implementation of the new depreciation rates reduced depreciation expense by $126,875 and
increased net income by $78,713 and earnings per share by $0.02.
The composite rates are comprised 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 evacuating 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 2015, 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
2015
4,802,015
62,890
(162,072)
281,762
311,273
5,295,868
$
$
2014
4,525,355
74,276
(165,845)
258,763
109,466
4,802,015
$
$
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, 2015, 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.
40
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
2015
2014
2013
$
$
70,747
87,908
139,282
(245,216)
52,721
$
$
68,539
148,881
136,369
(283,042)
70,747
$
$
65,219
85,033
122,432
(204,145)
68,539
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, 2015 and 2014 were $1,001,418 and
$1,071,128, 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 amortized over the lives of the debt instruments.
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
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.
41
•
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 6 and 10.
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
2015
5,094,415
4,728,210
$
2014
4,708,440
4,715,478
$
2013
4,262,052
4,698,727
3,466
4,731,676
804
4,716,282
39
4,698,766
1.08
1.08
$
$
1.00
1.00
$
$
0.91
0.91
$
$
$
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, 2016. 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.
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
42
prudent costs associated with natural gas purchases. At September 30, 2015 and 2014, 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.
Other Comprehensive Income(Loss)—A summary of other comprehensive income is provided below:
Before Tax
Amount
Tax
(Expense)
or Benefit
Net-of Tax
Amount
$
$
$
$
$
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
Year Ended September 30, 2013:
Interest rate swaps:
Unrealized losses
Transfer of realized losses to interest expense
Net interest rate swaps
Defined benefit plans:
Net gain arising during period
Amortization of actuarial losses
Amortization of transition obligation
Net defined benefit plans
Other comprehensive income
(1,910,573) $
60,221
(1,850,352) $
726,017
(22,884)
703,133
$
$
$
22,321
(351,609)
(424,861)
(754,149)
151,131
(15,901)
135,230
(618,919) $
(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
(58,800) $
926,262
1,119,233
1,986,695
(397,714)
41,846
(355,868)
1,630,827
$
(20,479) $
950,501
930,022
$
7,774
(360,811)
(353,037)
(12,705)
589,690
576,985
1,714,890
219,890
35,972
1,970,752
$
2,900,774
$
(651,659)
(83,558)
(13,669)
(748,886)
(1,101,923) $
1,063,231
136,332
22,303
1,221,866
1,798,851
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.
43
Composition of Accumulated Other Comprehensive Income (Loss)
Balance September 30, 2012
Other comprehensive income (loss)
Balance September 30, 2013
Other comprehensive income (loss)
Balance September 30, 2014
Other comprehensive income (loss)
Balance September 30, 2015
Interest Rate
Swaps
(1,809,531) $
576,985
(1,232,546)
1,232,546
—
—
— $
Defined Benefit
Plans
(2,140,554) $
1,221,866
(918,688)
(220,638)
(1,139,326)
(1,147,219)
(2,286,545) $
$
$
Accumulated
Other
Comprehensive
Income (Loss)
(3,950,085)
1,798,851
(2,151,234)
1,011,908
(1,139,326)
(1,147,219)
(2,286,545)
Change in Method of Accounting for Long-term Debt—During the fiscal year ended September 30, 2015, the
Company adopted the provisions of ASU 2015-03 as described further under the Recently Adopted Accounting
Standards section below. Under ASU 2015-03, the unamortized balance of debt issuance costs are reclassified from
assets to liabilities and netted against the carrying value of long-term debt. The change had no impact on net income.
Management retrospectively applied the change. The carrying value of long-term debt and the reclassified debt
issuance costs are presented separately on the Company’s Consolidated Balance Sheets and in Note 4 for the periods
ended September 30, 2015 and 2014.
Recently Adopted Accounting Standards—In June 2011, the FASB issued guidance under FASB ASC No. 220 -
Comprehensive Income that defines the presentation of Comprehensive Income in the financial statements. According
to the guidance, an entity may present a single continuous statement of comprehensive income or two separate
statements - a statement of income and a statement of other comprehensive income that immediately follows the
statement of income. In either presentation, the entity is required to present on the face of the financial statement the
components of other comprehensive income including the reclassification adjustment for items that are reclassified
from other comprehensive income to net income. In December 2011, the FASB issued additional guidance under
FASB ASC No. 220 that deferred the effective date of earlier guidance with regard to the presentation of
reclassifications of items out of accumulated other comprehensive income. All other provisions of the original
guidance remain in effect. In February 2013, the FASB issued additional guidance regarding the reporting of amounts
reclassified out of accumulated other comprehensive income. Under the new provisions, an entity must present the
effects on the line items of net income of significant amounts reclassified out of accumulated other comprehensive
income. The disclosures required under this guidance are provided above.
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 during the current reporting period. The
adoption of this ASU did not have an 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. The changes required under this guidance are presented in Note 1, Note 4 and the Consolidated Balance
Sheets.
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 these steps: (1) identify the contract with the customer,
(2) identify the performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction
price to the performance obligations in the contract, and (5) recognize revenue when, or as, the entity satisfies the
performance obligation. In August 2015, the FASB issued Accounting Standards Update (ASU) 2015-14 that deferred
the effective date of this guidance by one year. Therefore, the new guidance is effective for the Company for the
44
annual reporting period ended September 30, 2019 and interim periods within that annual period. Early application is
not permitted. Management has not completed its evaluation of the new guidance; however, the Company does not
currently expect it 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 Company. Such regulation
encompasses terms, conditions and rates to be charged to customers for natural gas service, safety standards, service
extension, accounting and depreciation.
On September 25, 2015, the Company received approval of its application for a modification to the SAVE (Steps to
Advance Virginia's Energy) Plan and Rider. The original SAVE Plan filed in 2012 has been modified each year to
incorporate certain changes and to include new projects that qualify for recovery under the Plan. The SAVE Rider
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 June 25, 2014, the SCC approved the Company's application requesting approval to extend its authority to incur
short-term indebtedness of up to $30,000,000 and to issue up to $60,000,000 in long-term securities. The short-term
indebtedness authority allows the Company to continue to access its line-of-credit to provide seasonal funding of its
working capital needs as well as provide temporary bridge financing for its capital expenditures. The authority to
issue long-term securities allowed the Company to refinance its higher interest debt in September 2014 and provides
the Company with the approval to secure longer term funding for its capital expenditures.
3.
SHORT-TERM DEBT
The Company has available an unsecured line-of-credit with a bank which will expire March 31, 2016. 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, 2015
March 1, 2016
A summary of the line-of-credit follows:
Available
Line-of-Credit
$
24,000,000
17,000,000
Line-of-credit at year-end
Outstanding balance at year-end
Highest month-end balance outstanding
Average daily balance
Average rate of interest during year on outstanding balances
Interest rate at year-end
Interest rate on unused line-of-credit
2015
$ 24,000,000
9,340,997
17,366,052
6,377,040
September 30
2014
$ 15,000,000
9,045,050
9,045,050
1,340,833
$
2013
5,000,000
—
1,414,955
80,593
1.17%
1.20%
0.15%
1.16%
1.16%
0.15%
1.21%
1.18%
0.15%
Associated with the line-of-credit is a credit agreement that contains various provisions including a financial ratio that
requires the Company to maintain an interest coverage ratio of not less than 1.5 to 1.
45
4.
LONG-TERM DEBT
Long-term debt consists of the following:
September 30
2015
2014
Principal
Unamortized
Debt Issuance
Costs
Principal
Unamortized
Debt Issuance
Costs
Unsecured senior notes payable, at 4.26%, due
on September 18, 2034
Total
$ 30,500,000
$ 30,500,000
$
$
183,427
$ 30,500,000
183,427
$ 30,500,000
$
$
193,081
193,081
Debt issuance costs are amortized over the life of the related debt. As of September 30, 2015 and 2014, the Company
also had an unamortized loss on the early retirement of debt of $2,169,556 and $2,283,744, 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.
The aggregate annual maturities of long-term debt for the next five years ending after September 30, 2015 are as
follows:
Year Ending September 30
2016
2017
2018
2019
2020
Thereafter
Total
Maturities
—
—
—
—
—
30,500,000
30,500,000
$
$
5.
INCOME TAXES
The details of income tax expense are as follows:
Current income taxes:
Federal
State
Total current income taxes
Deferred income taxes:
Federal
State
Total deferred income taxes
Amortization of investment tax credits
Total income tax expense
Years Ended September 30
2015
2014
2013
$
379,180
$
1,789,294
$
1,404,450
374,541
753,721
2,289,729
127,112
2,416,841
—
$
3,170,562
$
290,458
2,079,752
687,417
175,464
862,881
(3,093)
2,939,540
$
453,347
1,857,797
829,080
(33,051)
796,029
(9,039)
2,644,787
46
Income tax expense for the years ended September 30, 2015, 2014 and 2013 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
$
$
2015
8,264,977
2,810,092
331,091
—
29,379
$
$
2014
7,647,980
2,600,313
307,509
(3,093)
34,811
2013
6,906,839
2,348,325
277,395
(9,039)
28,106
3,170,562
$
2,939,540
$
2,644,787
$
$
$
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
Accrued gas costs
Deferred compensation
Other
Total gross deferred tax assets
Deferred tax liabilities:
Utility plant
Under-recovery of gas costs
Accrued gas costs
Total gross deferred tax liabilities
Net deferred tax liability
Deferred Income Tax - Balance Sheet
Deferred income taxes (net current assets)
Deferred income taxes (net non-current liabilities)
Net deferred tax liability
September 30
2015
2014
$
20,012
$
2,502,774
249,837
721,782
930,524
—
651,336
265,951
5,342,216
26,855
2,077,409
230,842
—
973,651
36,305
579,451
295,654
4,220,167
19,804,862
17,057,847
—
157,385
19,962,247
$
14,620,031
$
68,643
—
17,126,490
12,906,323
September 30
2015
2,293,536
16,913,567
14,620,031
$
$
2014
1,704,320
14,610,643
12,906,323
$
$
Current federal tax expense for fiscal 2015 reflected the effect of 50% bonus depreciation for the entire calendar year
of 2014, which included nine months of the prior fiscal year. The extension of bonus depreciation for 2014 was signed
into law subsequent to the issuance of the Company's financial statements for the year ended September 30, 2014. As
a result, $1,442,211 of deferred taxes that related to the prior year were reflected in the current year tax provision,
thereby reducing the current tax expense by the same amount. Total income tax expense was not impacted by the
classification change between current and deferred income taxes.
47
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, 2012 are no longer subject to examination.
6.
EMPLOYEE BENEFIT PLANS
The Company sponsors both a noncontributory defined benefit pension plan and a postretirement benefit plan
(“Plans”). The defined benefit 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.
The postretirement benefit plan provides certain healthcare, 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.
48
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
2015
2014
2015
2014
$ 22,853,206
$ 20,697,734
$ 15,355,668
$ 14,983,169
Benefit obligation at beginning of year
$ 24,636,695
$ 21,468,769
$ 14,983,169
$ 13,028,628
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:
654,782
553,291
1,025,908
1,020,302
167,580
600,096
168,634
602,684
1,487,278
(637,042)
$ 27,167,621
2,199,697
(605,364)
$ 24,636,695
70,196
(465,373)
$ 15,355,668
1,673,552
(490,329)
$ 14,983,169
1,750,033
$ 10,114,062
$ 18,801,262
$ 20,514,179
(182,738)
500,000
1,700,000
(490,329)
(637,042)
$ 21,394,399
$ 10,646,249
$ (5,773,222) $ (4,122,516) $ (4,912,039) $ (4,336,920)
$ 10,646,249
(237,247)
500,000
(465,373)
$ 10,443,629
568,248
(605,364)
$ 20,514,179
522,516
Noncurrent liabilities
$ (5,773,222) $ (4,122,516) $ (4,912,039) $ (4,336,920)
Amounts recognized in accumulated other
comprehensive loss:
Transition obligation, net of tax
Net actuarial loss, net of tax
Total amounts included in other
comprehensive loss, net of tax
Amounts deferred to a regulatory asset:
Transition obligation
Net actuarial loss
Amounts recognized as regulatory assets
$
$
$
$
— $
— $
— $
—
1,694,924
616,352
591,621
522,974
1,694,924
$
616,352
$
591,621
$
522,974
— $
— $
— $
—
5,280,756
4,166,900
3,628,448
3,112,127
5,280,756
$
4,166,900
$
3,628,448
$
3,112,127
Effective with the valuation of the September 30, 2015 defined benefit obligations, the Company adopted the new
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.
The Company expects that approximately $221,000 before tax, of accumulated other comprehensive loss will be
recognized as a portion of net periodic benefit costs in fiscal 2016 and approximately $531,000 of amounts deferred as
regulatory assets will be amortized and recognized in net periodic benefit costs in fiscal 2016.
The Company amortized the unrecognized transition obligation over 20 years ending in June 2013.
49
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
2015, 2014 and 2013.
Pension Plan
Postretirement Plan
2015
2014
2013
2015
2014
2013
Assumptions used to determine benefit
obligations:
Discount rate
Expected rate of compensation increase
4.22%
4.00%
4.22%
4.00%
4.82%
4.00%
4.15%
N/A
4.10%
N/A
4.73%
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%
4.82%
4.06%
4.10%
4.73%
3.95%
7.00%
4.00%
7.00%
4.00%
7.25%
4.00%
4.90%
N/A
4.92%
N/A
5.11%
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
Amortization of unrecognized
transition obligation
Recognized loss
Pension Plan
Postretirement Plan
2015
2014
2013
2015
2014
2013
$ 654,782
$
553,291
$
634,892
$ 167,580
$ 168,634
$ 213,131
1,025,908
(1,440,846)
1,020,302
(1,312,354)
946,247
(1,184,787)
600,096
(516,656)
602,684
(496,476)
531,845
(452,383)
—
—
—
—
—
257,378
136,394
578,263
197,058
89,515
141,671
241,747
Net periodic benefit cost
$ 497,222
$
397,633
$
974,615
$ 448,078
$ 364,357
$ 676,011
The assumed health care cost trend rates used in measuring the accumulated benefit obligation for the postretirement
medical plan as of September 30, 2015, 2014 and 2013 are presented below:
2015
Pre 65
2014
2013
2015
Post 65
2014
2013
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
8.00%
8.50%
9.00%
5.00%
5.00%
5.00%
5.00%
2021
5.00%
2021
5.00%
2021
5.00%
2015
5.00%
2014
5.00%
2013
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
2,383,000
$
(109,000)
(1,938,000)
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 fiduciary for investment matters.
50
The Company’s target and actual asset allocation in the pension and postretirement benefit plans as of September 30,
2015 and 2014 were:
Asset category:
Equity securities
Debt securities
Cash
Other
Pension Plan
Postretirement
Plan
Target
2015
2014
Target
2015
2014
60%
40%
—%
—%
64%
35%
1%
—%
60%
39%
1%
—%
50%
50%
—%
—%
52%
47%
1%
—%
55%
44%
1%
—%
The assets of the plans are invested in mutual funds. The Company uses the fair value hierarchy described in Note 1 to
classify these assets. The mutual funds are included under Level 2 in the fair value hierarchy as their fair values are
determined based on individual prices for each security that comprises the mutual funds. Most all 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, 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
3,150,561
4,183,172
1,937,613
1,873,313
Mutual Funds:
Bonds
Domestic Fixed Income
Foreign Fixed Income
3,313,331
213,118
Equities
—
—
—
—
—
—
—
3,996,246
3,150,561
4,183,172
1,937,613
1,873,313
3,313,331
213,118
Domestic Large Cap Growth
Foreign Large Cap Value
Foreign Large Cap Core
1,030,957
653,276
936,310
21,394,399
$
$
—
—
—
106,502
$
1,030,957
653,276
936,310
21,287,897
$
Total
—
—
—
—
—
—
—
—
—
—
—
—
51
Defined Benefit Pension Plan
Fair Value Measurements - September 30, 2014
Fair Value
Level 1
Level 2
Level 3
$
182,644
$
182,644
$
— $
Asset Class:
Cash
Common and Collective Trust and
Pooled Funds:
Bonds
Domestic Fixed Income
1,455,153
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
2,079,566
3,295,144
1,850,340
1,641,619
6,289,437
204,747
2,088,528
608,787
818,214
—
—
—
—
—
—
—
—
—
—
1,455,153
2,079,566
3,295,144
1,850,340
1,641,619
6,289,437
204,747
2,088,528
608,787
818,214
Total
$
20,514,179
$
182,644
$
20,331,535
$
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
$
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
52
Postretirement Benefit Plan
Fair Value Measurements - September 30, 2014
Fair Value
Level 1
Level 2
Level 3
$
116,173
$
116,173
$
— $
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
4,658,299
101,904
1,789,381
1,759,740
400,898
396,537
37,741
941,153
394,769
49,654
—
—
—
—
—
—
—
—
—
—
4,658,299
101,904
1,789,381
1,759,740
400,898
396,537
37,741
941,153
394,769
49,654
$
10,646,249
$
116,173
$
10,530,076
$
—
—
—
—
—
—
—
—
—
—
—
—
Each mutual fund has been categorized based on its primary investment strategy.
The Company expects to contribute $500,000 to its pension plan and $500,000 to its postretirement benefit plan in
fiscal 2016.
The following table reflects expected future benefit payments:
Fiscal year ending September 30
2016
2017
2018
2019
2020
2021-2025
$
Pension
Plan
Postretirement
Plan
$
655,968
698,403
773,580
818,585
944,944
6,531,464
617,386
625,167
634,509
655,095
695,924
4,012,407
The Company also sponsors a defined contribution plan (“401k Plan”) covering all employees who elect to participate.
Employees may contribute from 1% to 50% of their annual compensation to the 401k Plan, limited to a maximum
annual amount as set periodically by the Internal Revenue Service. The Company matches 100% of the participant’s
first 4% of contributions and 50% on the next 2% of contributions. Company matching contributions were $338,896,
$330,241 and $306,382 for 2015, 2014 and 2013, respectively.
7.
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, 2015, the number of shares available for
future grants was 49,000.
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 2015, 2014 and 2013, the Board approved
stock option grants to certain officers. As required by the KESOP, each option's exercise price per share equaled the
53
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,
2015
34.34%
4.11%
7.00
1.98%
2014
35.01%
4.21%
7.00
2.23%
2013
34.75%
4.32%
7.00
1.23%
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.
No forfeitures are assumed to occur.
54
Stock option transactions under the Company's plans for the years ended September 30, 2015, 2014 and 2013 are
summarized below:
Options outstanding, September 30, 2012
Options granted
Options exercised
Options expired
Options forfeited
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
Number of
Shares
Weighted-
Average Exercise
Price
— $
21,000
—
—
—
21,000
17,000
—
—
—
38,000
17,000
(2,600)
—
—
—
19.01
—
—
—
19.01
18.95
—
—
—
18.98
21.60
18.99
—
—
Weighted-
Average
Remaining
Contractual
Terms (years)
Aggregate
Intrinsic Value 1
0.0
$
—
9.5
5,229
8.8
34,840
Options outstanding, September 30, 2015
52,400
$
19.83
Vested and exercisable at September 30,
2015
52,400
$
19.83
1
Aggregate intrinsic value includes only those options where the exercise price is below the market price.
8.3
8.3
$
$
43,086
43,086
The weighted-average grant-date fair value of options granted during the years ended September 30, 2015, 2014 and
2013 was $4.92, $4.43 and $4.04, respectively. The intrinsic value of the options exercised during fiscal 2015 was
$5,624. The Company recognized $83,640, $75,310 and $84,840 in stock option expense in fiscal 2015, 2014 and
2013, respectively.
The Company received $49,366 from the exercise of options in 2015. No options were exercised in 2013 or 2014.
55
8.
OTHER STOCK PLANS
Dividend Reinvestment and Stock Purchase Plan
The Company offers a Dividend Reinvestment and Stock Purchase Plan (“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 plan, the Company issued 8,431, 7 and 24,905 shares in 2015, 2014 and 2013, respectively.
As of September 30, 2015, the Company had 358,377 shares of stock available for issuance under the DRIP Plan.
Restricted Stock Plan
The Board of Directors of the Company implemented the Restricted Stock Plan for Outside Directors (“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 is paid in shares of common stock (“Restricted Stock”). The number of shares of Restricted
Stock is calculated each month 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 this 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 this
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.
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:
2015
2014
2013
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
62,844
$
Granted
Vested
Forfeited
4,071
—
—
14.29
20.88
—
—
59,064
$
3,780
—
—
13.97
19.37
—
—
54,011
$
5,053
—
—
13.51
18.93
—
—
End of year balance
66,915
$
14.70
62,844
$
14.29
59,064
$
13.97
The fair market value of the Restricted Stock issued as compensation during fiscal 2015, 2014 and 2013 was $85,000,
$73,200 and $95,667. No Restricted Stock vested or was forfeited during fiscal 2015, 2014 and 2013.
As of September 30, 2015, the Company had 70,960 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, receive
no less than 50% of any performance bonus in the form of 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 2,731, 4,098 and 4,022 shares valued at $59,332, $78,841
and $72,580, respectively, in 2015, 2014 and 2013. As of September 30, 2015 the Company had 8,174 shares of stock
available for issuance under the Stock Bonus Plan.
56
9.
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, 2015 for the remainder of the contract period.
Year
2015-2016
2016-2017
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, 2015. 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. The
Company expended approximately $33,405,000, $44,884,000 and $35,348,000 under the asset management, pipeline
and storage contracts for Roanoke Gas in fiscal years 2015, 2014 and 2013, respectively. The table below details the
pipeline and storage capacity obligations as of September 30, 2015 for the remainder of the contract period.
Year
2015-2016
2016-2017
2017-2018
2018-2019
2019-2020
Thereafter
Total
Other Contracts
Pipeline and
Storage Capacity
$
11,392,645
9,999,402
7,787,998
6,171,421
2,427,961
—
$
37,779,427
The Company maintains other agreements in the ordinary course of business covering various lease, maintenance,
equipment and service contracts. These agreements currently extend through December 2031 and are not material to
the Company.
Legal
From time to time, the Company may become involved in litigation or claims arising out of its operations in the
normal course of business. At the current time, the Company is not known to be a party to any legal proceedings that
would be expected to have a materially adverse impact on its financial position, results of operations or cash flows.
Environmental Matters
Both Roanoke Gas Company 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 on-site 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.
57
10.
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, 2015 and 2014, respectively:
Liabilities:
Natural gas purchases
Total
Liabilities:
Natural gas purchases
Total
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
$
$
—
—
Fair Value Measurements - September 30, 2014
Quoted Prices in
Active Markets
Level 1
Significant Other
Observable
Inputs
Level 2
Significant
Unobservable
Inputs
Level 3
Fair Value
795,019
795,019
$
$
— $
— $
795,019
795,019
$
$
—
—
$
$
$
$
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, 2015 and 2014, 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, 2015 and 2014.
Fair Value Measurements - September 30, 2015
Significant Other
Observable
Inputs
Level 2
Significant
Unobservable
Inputs
Level 3
Quoted Prices in
Active Markets
Level 1
Carrying
Amount
Liabilities:
Long-term debt
Total
Liabilities:
Long-term debt
Total
$
$
30,500,000
30,500,000
$
$
— $
— $
— $
— $
28,570,585
28,570,585
Fair Value Measurements - September 30, 2014
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
$
$
— $
— $
— $
— $
30,622,664
30,622,664
58
The fair value of long-term debt 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.
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.
11.
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Quarterly financial data for the years ended September 30, 2015 and 2014 is summarized as follows:
2015
Operating revenues
Gross margin
Operating income
Net income
Earnings per share of common stock:
Basic
Diluted
2014
Operating revenues
Gross margin
Operating income
Net income (loss)
Earnings per share of common stock:
Basic
Diluted
12.
SUBSEQUENT EVENTS
First
Quarter
21,250,065
8,622,143
3,514,352
1,924,376
0.41
0.41
First
Quarter
20,011,194
8,202,992
3,272,646
1,722,788
0.37
0.37
$
$
$
$
$
$
$
$
$
$
$
$
Second
Quarter
26,431,729
10,213,770
4,879,469
2,779,344
0.59
0.59
Second
Quarter
32,699,965
10,161,125
5,121,022
2,846,795
0.60
0.60
$
$
$
$
$
$
$
$
$
$
$
$
Third
Quarter
10,774,409
5,961,828
956,219
354,940
0.08
0.07
Third
Quarter
12,024,817
5,721,551
940,691
283,194
0.06
0.06
$
$
$
$
$
$
$
$
$
$
$
$
Fourth
Quarter
9,733,404
5,408,692
656,152
35,755
0.01
0.01
Fourth
Quarter
10,280,158
5,251,421
347,509
(144,337)
(0.03)
(0.03)
$
$
$
$
$
$
$
$
$
$
$
$
On October 1, 2015, the Company, through its newly formed wholly-owned subsidiary, RGC Midstream, LLC,
entered into an agreement to become a 1% member 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. This project, if approved by the Federal Energy Regulatory Commission, will require an
estimated $35 million investment by the Company to support the construction of the pipeline over the next 3 years.
The projected in service date of the pipeline is late 2018. The Company will participate in the earnings generated
from the transportation of natural gas on the pipeline in proportion to its level of investment. The Company will apply
the equity method to account for the transactions and activity of the investment.
On October 1, 2015, RGC Midstream borrowed $1,500,000 under a temporary line-of-credit agreement to make its
initial investment in the LLC.
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.
* * * * * *
59
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, 2015, 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, 2015.
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.
60
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, 2015, based on the framework set forth in ”Internal Control - Integrated
Framework (1992)” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based upon
such evaluation, the Company concluded that, as of September 30, 2015, 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, 2015.
61
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,
2015, based on criteria established in Internal Control-Integrated Framework - 1992 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, 2015, based on criteria established in Internal Control-Integrated Framework - 1992 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, 2015 and 2014 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, 2015, and our report dated December 4, 2015 expressed an unqualified opinion.
CERTIFIED PUBLIC ACCOUNTANTS
1715 Pratt Drive, Suite 2700
Blacksburg, Virginia
December 4, 2015
62
Item 9B.
Other Information
None
63
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 2016 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 2016
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 2016 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 2016 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 2016 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 2016 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 2016 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 2016 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 2016
Annual Meeting of Shareholders of Resources is incorporated herein by reference.
64
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:
2015 Annual Report to Shareholders (such report, except to the extent incorporated herein by reference, is
being furnished for the information of the Commission only and is not to be deemed filed as part of this
Annual Report on Form 10-K)
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, 2015, 2014 and 2013, formatted in XBRL (eXtensible Business Reporting Language);
Consolidated Balance Sheets at September 30, 2015 and 2014, (ii) Consolidated Statements of Income for the
years ended September 30, 2015, 2014 and 2013, (iii) Consolidated Statements of Comprehensive Income for
the years ended September 30, 2015, 2014 and 2013, (iv) Consolidated Statements of Stockholders’ Equity for
the years ended September 30, 2015, 2014 and 2013, (v) Consolidated Statements of Cash Flows for the years
ended September 30, 2015, 2014 and 2013, and (vi) Notes to Consolidated Financial Statements.
13
21
23
31.1
31.2
32.1*
32.2*
101
*
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.
65
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 10, 2015
Date
66
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 10, 2015
John S. D'Orazio
Date
President and Chief Executive
Officer, Director
/S/ PAUL W. NESTER
December 10, 2015
Paul W. Nester
Date
Vice President, Treasurer and CFO
(principal accounting and financial
officer)
/S/ JOHN B. WILLIAMSON, III
December 10, 2015
Chairman of the Board and Director
John B. Williamson, III
Date
/S/ NANCY H. AGEE
December 10, 2015
Director
Nancy H. Agee
Date
/S/ ABNEY S. BOXLEY, III
December 10, 2015
Director
Abney S. Boxley, III
Date
/S/ MARYELLEN F. GOODLATTE
December 10, 2015
Director
Maryellen F. Goodlatte
Date
/S/ J. ALLEN LAYMAN
J. Allen Layman
December 10, 2015
Director
Date
/S/ GEORGE W. LOGAN
George W. Logan
December 10, 2015
Director
Date
/S/ S. FRANK SMITH
S. Frank Smith
December 10, 2015
Director
Date
/S/ RAYMOND D. SMOOT, JR.
December 10, 2015
Director
Raymond D. Smoot, Jr.
Date
67
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)
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))
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)
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)
10 (x)
10 (y)
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)
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 Town of Vinton, Virginia, and Roanoke Gas Company dated
July 2, 1996 (incorporated herein by reference to Exhibit 10(n)(n) of Annual Report on Form 10-K
for the fiscal year ended September 30, 1996 (SEC file number reference 0-367))
Gas Franchise Agreement between the City of Salem, Virginia, and Roanoke Gas Company dated
July 9, 1996 (incorporated herein by reference to Exhibit 10(o)(o) of Annual Report on Form 10-K
for the fiscal year ended September 30, 1996 (SEC file number reference 0-367))
Gas Franchise Agreement between the City of Roanoke, Virginia, and Roanoke Gas Company dated
July 12, 1996 (incorporated herein by reference to Exhibit 10(p)(p) of Annual Report on Form 10-K
for the fiscal year ended September 30, 1996 (SEC file number reference 0-367))
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)
Change in Control Agreement between RGC Resources, Inc. and Paul W. Nester effective May 1,
2015 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed May 5, 2015)
Change in Control Agreement by and between RGC Resources, Inc. and Robert L. Wells, II
effective May 1, 2015 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed May
5, 2015)
Change in Control Agreement between RGC Resources, Inc. and Mr. Carl J. Shockley effective
May 1, 2015 (incorporated herein by reference to Exhibit 10.3 on Form 8-K as filed May 5, 2015)
Change in Control Agreement between John S. D’Orazio and RGC Resources, Inc. effective April
1, 2011 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed April 4, 2011 (SEC
file number reference 0-367))
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, 2015 (incorporated herein by
reference to Exhibit 10.1 on Form 8-K as filed April 3, 2015)
Credit Agreement by and between Roanoke Gas Company and Wells Fargo Bank, N.A. dated
March 31, 2015 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed April 3,
2015)
Continuing guaranty by RGC Resources, Inc. and Wells Fargo Bank, N. A. dated March 31, 2015
(incorporated by reference to Exhibit 10.3 on Form 8-K as filed April 3, 2015)
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))
10 (n)(n)
10 (o)(o)
10 (p)(p)
10 (q)(q)
10 (r)(r)
10 (s)(s)
10 (t)(t)
13
21
23
31.1
31.2
32.1*
32.2*
101
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))
2015 Annual Report to Shareholders (such report, except to the extent incorporated herein by
reference, is being furnished for the information of the Commission only and is not to be deemed
filed as part of this Annual Report on Form 10-K)
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, 2015, 2014 and 2013, formatted in XBRL (eXtensible Business Reporting
Language); Consolidated Balance Sheets at September 30, 2015 and 2014, (ii) Consolidated
Statements of Income for the years ended September 30, 2015, 2014 and 2013, (iii) Consolidated
Statements of Comprehensive Income for the years ended September 30, 2015. 2014 and 2013, (iv)
Consolidated Statements of Stockholders’ Equity for the years ended September 30, 2015, 2014 and
2013, (v) Consolidated Statements of Cash Flows for the years ended September 30, 2015, 2014
and 2013, 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.
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 4, 2015 appearing in this Annual
Report on Form 10-K of RGC Resources, Inc. for the year ended September 30, 2015.
CERTIFIED PUBLIC ACCOUNTANTS
1715 Pratt Drive, Suite 2700
Blacksburg, Virginia
December 9, 2015
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 10, 2015
/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 10, 2015
/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, 2015 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 10, 2015
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, 2015 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Paul W. Nester,
Vice-President, 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 10, 2015
BOARD OF DIRECTORS
Nancy Howell Agee
President and Chief
Executive Officer
Carilion Clinic
Abney S. Boxley, III
President and Chief
Executive Officer
Boxley Materials Company
John S. D’Orazio
President and Chief
Executive Officer
RGC Resources, Inc.
Maryellen F. Goodlatte
Attorney and Principal
Glenn Feldmann Darby &
Goodlatte
J. Allen Layman
Private Investor
George Logan
Principal
Pine Street Partners, LLC
Faculty, University of VA
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
OFFICERS
John S. D’Orazio
President and
Paul W. Nester
Vice President, Secretary,
Carl J. Shockley, Jr.
Vice President,
Chief Executive Officer
Treasurer and Chief Financial Officer
Operations—Roanoke Gas Company
Howard T. Lyon
Robert L. Wells, II
Assistant Secretary and
Vice President,
Assistant Treasurer
Information Technology
INFRASTRUCTURE RENEWALS
“In fiscal 2015…We replaced approximately 10 miles of cast iron and bare steel
pipe...we anticipate replacing the remaining bare steel and cast iron pipe by 2017.”
CORPORATE INFORMATION
DIVIDEND REINVESTMENT AND STOCK
PURCHASE PLAN SHAREHOLDER INQUIRIES
ANNUAL REPORT AND 10-K
transfers,
Through the Dividend Reinvestment and
Stock Purchase Plan, shareholders of record
are offered a convenient way to acquire and
reinvest cash dividends in additional shares
of the Company’s common stock and avoid
commissions or other charges. Additionally,
shareholders are given on-line access to
make
replace stock certificates or dividend checks,
establish direct deposit, update personal
information and much more. American
Stock Transfer and Trust Company, LLC
administers the plan and is the agent for
participants. For more information, inquiries
may be directed to RGC Resources, Inc.,
Shareholder Information Services, P.O. Box
13007, Roanoke, VA 24030, (540) 777-3853.
consolidate accounts,
This annual report, 10-K and the financial
statements contained herein are submitted
to the shareholders of the Company for their
general information and not in connection
with any sale or offer to sell, or solicitation
of any offer to buy, any securities.
ANNUAL MEETING
The annual meeting of shareholders of the
Company will be held at The Hotel Roanoke
and Conference Center, 110 Shenandoah
Avenue, Roanoke, Virginia, 24016 on
Monday, February 1, 2016, 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 16, 2015.
STOCK PLAN ADMINISTRATOR AND AGENT
FINANCIAL INQUIRIES
American Stock Transfer & Trust
Company, LLC
6201 15th Avenue
Brooklyn, NY 11219
(800) 937-5449
INREGISTERED ACCOUNTING FIRM
INDEPENDENT REGISTERED PUBLIC
ACCOUNTING FIRM
Brown Edwards & Company, L.L.P.
1715 Pratt Drive, Suite 2700
Blacksburg, VA 24060
All financial analysts and professional
investment managers should direct their
questions and requests for information to:
RGC Resources, Inc.
VP, Treasurer, Secretary & 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.
519 Kimball Avenue, N.E.
P.O. Box 13007
Roanoke, Virginia, 24030
www.rgcresources.com