10-K 1 rgco-9302016x10kxq4.htm 10-K Document

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended September 30, 2016
Commission file number 000-26591
RGC RESOURCES, INC.
(Exact name of registrant as specified in its charter)
Virginia
 
54-1909697
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
519 Kimball Avenue, N.E., Roanoke, VA
 
24016
(Address of principal executive offices)
 
(Zip Code)
Registrant’s telephone number, including area code (540) 777-4427
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
Title of Each Class
 
Name of Each Exchange on
Which Registered
Common Stock, $5 Par Value
 
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  x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨  No  x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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
 
x
 
 
 
 
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  x
State the aggregate market value of the voting and non voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity as of the last business day of the registrant’s most recently completed second fiscal quarter: March 31, 2016. $95,954,187
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the last practicable date.
Class
 
Outstanding at November 30, 2016
COMMON STOCK, $5 PAR VALUE
 
4,798,466 SHARES
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the RGC Resources, Inc. Proxy Statement for the 2017 Annual Meeting of Shareholders are incorporated by reference into Part III hereof.



TABLE OF CONTENTS
 
 
 
 
 
 
 
 
Page Number
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 1.
 
 
 
 
 
 
 
Item 1A.
 
 
 
 
 
 
 
Item 1B.
 
 
 
 
 
 
 
Item 2.
 
 
 
 
 
 
 
Item 3.
 
 
 
 
 
 
 
Item 4.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 5.
 
 
 
 
 
 
 
Item 6.
 
 
 
 
 
 
 
Item 7.
 
 
 
 
 
 
 
Item 7A.
 
 
 
 
 
 
 
Item 8.
 
 
 
 
 
 
 
Item 9.
 
 
 
 
 
 
 
Item 9A.
 
 
 
 
 
 
 
Item 9B.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 10.
 
 
 
 
 
 
 
Item 11.
 
 
 
 
 
 
 
Item 12.
 
 
 
 
 
 
 
Item 13.
 
 
 
 
 
 
 
Item 14.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 15.
 
 
 
 
 
 
 
 




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.

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PART I
 
Item 1.
Business.

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

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

In July 2015, the Company formed RGC Midstream, LLC, a limited liability company established for the purpose of becoming a 1% investor in Mountain Valley Pipeline, LLC. Mountain Valley Pipeline, LLC was created for the purpose of constructing a natural gas pipeline in West Virginia and Virginia. Additional information regarding this investment is provided under Note 3 of the Company's annual consolidated financial statements and under the Equity Investment in Mountain Valley Pipeline section of Item 7.

In March 2016, Resources dissolved its subsidiary, RGC Ventures of Virginia, Inc. ("Ventures"). Ventures contained the operations of Application Resources, Inc., which provided information technology consulting services, and The Utility Consultants, which provided utility and regulatory consulting services to other utilities. Both of these operations were insignificant when compared to the overall activities of Resources and represented less than 0.2% of total revenues and less than 6% of other non-utility revenues.

Diversified Energy Company currently has no active operations.

Services
Roanoke Gas maintains an integrated natural gas distribution system to deliver natural gas purchased from suppliers to residential, commercial and industrial users in its service territory. The schedule below is a summary of customers, delivered volumes (expressed in decatherms), revenues and margin as a percentage of the total for each category: 
 
 
2016
 
 
Customers
 
Volume
 
Revenue
 
Margin
Residential
 
91.2
%
 
38
%
 
57
%
 
60
%
Commercial
 
8.7
%
 
31
%
 
33
%
 
25
%
Industrial
 
0.1
%
 
31
%
 
7
%
 
11
%
Other Utility
 
0.0
%
 
0
%
 
1
%
 
2
%
Other Non-Utility
 
0.0
%
 
0
%
 
2
%
 
2
%
Total Percent
 
100.0
%
 
100
%
 
100
%
 
100
%
Total Value
 
59,635

 
8,842,605

 
$
59,063,291

 
$
31,564,914

 
 
2015
 
 
Customers
 
Volume
 
Revenue
 
Margin
Residential
 
91.2
%
 
40
%
 
58
%
 
58
%
Commercial
 
8.7
%
 
30
%
 
33
%
 
26
%
Industrial
 
0.1
%
 
30
%
 
6
%
 
11
%
Other Utility
 
0.0
%
 
0
%
 
1
%
 
3
%
Other Non-Utility
 
0.0
%
 
0
%
 
2
%
 
2
%
Total Percent
 
100.0
%
 
100
%
 
100
%
 
100
%
Total Value
 
59,080

 
9,875,007

 
$
68,189,607

 
$
30,206,433


3


 
 
2014
 
 
Customers
 
Volume
 
Revenue
 
Margin
Residential
 
91.2
%
 
40
%
 
57
%
 
58
%
Commercial
 
8.7
%
 
29
%
 
34
%
 
25
%
Industrial
 
0.1
%
 
31
%
 
6
%
 
12
%
Other Utility
 
0.0
%
 
0
%
 
1
%
 
3
%
Other Non-Utility
 
0.0
%
 
0
%
 
2
%
 
2
%
Total Percent
 
100.0
%
 
100
%
 
100
%
 
100
%
Total Value
 
58,553

 
10,087,651

 
$
75,016,134

 
$
29,337,089


Roanoke Gas’ regulated natural gas distribution business accounted for approximately 98% of Resources total revenues for fiscal years ending September 30, 2016, 2015 and 2014. The tables above indicates that residential customers represent over 91% of the Company’s customer total; however, they represent less than 50% of the total gas volumes delivered and more than half of the Company’s consolidated revenues and margin. Industrial customers include primarily transportation customers that purchase their natural gas requirements directly from a supplier other than the Company and utilize Roanoke Gas’ natural gas distribution system for delivery to their operations. Most of the revenue billed for these customers relates only to transportation service, and not to the purchase of natural gas, causing total revenues generated by these deliveries to be approximately 7% of total revenues, even though they represent 31% of total natural gas deliveries for the year ended September 30, 2016 and approximately 11% to 12% of gross margin for each of the years presented.

The Company’s revenues are affected by changes in gas costs as well as by changes in consumption volume due to weather and economic conditions and changes in the non gas portion of customer billing rates. Increases or decreases in the cost of natural gas are passed on to customers through the purchased gas adjustment mechanism as explained in further detail in Note 1 of the Company’s annual consolidated financial statements. Significant increases in gas costs may cause customers to conserve or, in the case of industrial customers, to switch to alternative energy sources.

The Company’s residential and commercial sales are seasonal and temperature-sensitive as the majority of the gas sold by Roanoke Gas to these customers is used for heating. For the fiscal year ended September 30, 2016, approximately 64% of the Company’s total DTH of natural gas deliveries and 72% of the residential and commercial deliveries were made in the five-month period of November through March. These percentages are below the prior two fiscal years due to lower volumes attributable to a much warmer heating season. Total natural gas deliveries were 8.8 million DTH, 9.9 million DTH and 10.1 million DTH in fiscal 2016, 2015 and 2014, respectively.

Suppliers
Roanoke Gas relies on multiple interstate pipelines including those operated by Columbia Gas Transmission Corporation, LLC and Columbia Gulf Transmission Corporation, LLC (together “Columbia”), and East Tennessee Natural Gas, LLC (“East Tennessee”), Tennessee Gas Pipeline, Midwestern Gas Transmission Company and Saltville Gas Storage Company, LLC to transport natural gas from the production and storage fields to Roanoke Gas’ distribution system. Roanoke Gas is directly served by two pipelines, Columbia and East Tennessee. Columbia historically has delivered between 50% and 60% of the Company’s gas supply, while East Tennessee delivers the balance of the Company’s requirements. The rates paid for natural gas transportation and storage services purchased from the interstate pipeline companies are established by tariffs approved by the Federal Energy Regulatory Commission ("FERC"). These tariffs contain flexible pricing provisions, which, in some instances, authorize these transporters to reduce rates and charges to meet price competition. The current pipeline contracts expire at various times from 2017 to 2022. The Company anticipates being able to renew these contracts or enter into other contracts to meet customers’ continued demand for natural gas.

The Company manages its pipeline contracts and liquefied natural gas storage (“LNG”) facility in order to provide for sufficient capacity to meet the natural gas demands of its customers. The maximum daily winter capacity for delivery into Roanoke Gas’ distribution system under the interstate pipelines is 78,606 DTH per day. The LNG facility, which is capable of storing up to 200,000 DTH of natural gas in a liquid state for use during peak demand, has the capability of providing an additional 27,000 DTH per day. Combined, the pipelines and LNG facility can provide more than 105,000 DTH on a single winter day.


4


The Company uses multi-year contracts to meet its natural gas supply needs. The Company currently contracts with Sequent Energy Management, L.P. to manage its pipeline transportation, storage rights, gas supply inventories and deliveries and serve as the primary supplier of natural gas for Roanoke Gas. Natural gas purchased under the asset management agreement is priced at indexed-based market prices as reported in major industry pricing publications. The Company expects its firm supply agreements will be sufficient to meet customer demands for natural gas during the term of the agreement, which expires March 31, 2018.

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

Competition
The Company’s natural gas utility operates in a regulated, monopolistic environment. Roanoke Gas currently holds the only franchises and/or certificates of public convenience and necessity to distribute natural gas in its Virginia service areas. These franchises generally extend for multi-year periods and are renewable by the municipalities, including exclusive franchises in the cities of Roanoke and Salem and the Town of Vinton, Virginia. During fiscal 2016, all three franchise agreements were renewed for a term of 20 years with expiration dates of December 31, 2035.

Management anticipates that the Company will be able to renew all of its franchises when they expire. There can be no assurance, however, that a given jurisdiction will not refuse to renew a franchise or will not, in connection with the renewal of a franchise, attempt to impose restrictions or conditions that could adversely affect the Company’s business operations or financial condition. Certificates of public convenience and necessity, issued by the Virginia State Corporation Commission (the “SCC”), are of perpetual duration and subject to compliance with regulatory standards.

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

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

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

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

Employees
At September 30, 2016, Resources had 126 full-time employees and 132 total employees. As of that date, 34 employees, or 27% of the Company’s full-time employees, belonged to the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied-Industrial International Union, Local No. 515 and were represented under a collective

5


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

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

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

Availability of adequate and reliable pipeline capacity.

The Company is currently served directly by two interstate pipelines. These two pipelines carry 100% of the natural gas transported to the Company’s distribution system. Depending on weather conditions and the level of customer demand, failure of one or both of these interstate transmission pipelines could have a major impact on the Company’s ability to meet customer demand for natural gas and adversely affect the Company’s earnings as a result of lost revenue and the cost of service restoration.

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

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

Increased compliance and pipeline safety requirements and fines.

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

Investment in Mountain Valley Pipeline.

The success of the Company's investment in Mountain Valley Pipeline, LLC (the "LLC") is predicated on several key factors including but not limited to the ability of all investors to meet their capital calls when due, the timely approval of the pipeline project by FERC and completing the construction of the pipeline within the targeted time frame and

6


budget. Any significant delay, cost over-run or the failure to receive the requisite approvals could have a significant effect on the Company's earnings and financial position.

In addition, there are also numerous risks facing the LLC over time, which in turn could adversely affect the Company's earnings and financial performance through its 1% investment. The LLC's ability to complete construction of, and capital improvement to, facilities on schedule and within budget may be adversely affected by escalating costs for materials and labor and regulatory compliance, inability to obtain or renew necessary licenses, rights-of-way, permits or other approvals on acceptable terms or on schedule, disputes involving contractors, labor organizations, land owners, governmental entities, environmental groups, Native American and aboriginal groups, and other third parties, negative publicity, transmission interconnection issues, and other factors. If any development project or construction or capital improvement project is not completed, is delayed or is subject to cost overruns, certain associated costs may not be approved for recovery or be recovered through regulatory mechanisms that may otherwise be available, and the LLC could become obligated to make delay or termination payments or become obligated for other contractual damages, could experience the loss of tax credits or tax incentives, or delayed or diminished returns, and could be required to write-off all or a portion of its investment in the project. Any of these events could have a material adverse effect on the LLC’s business, financial condition, results of operations and prospects. The LLC may face risks related to project siting, financing, construction, permitting, governmental approvals and the negotiation of project development agreements that may impede its development and operating activities. The LLC must periodically apply for licenses and permits from various local, state, federal and other regulatory authorities and abide by their respective conditions. Should the LLC be unsuccessful in obtaining necessary licenses or permits on acceptable terms, should there be a delay in obtaining or renewing necessary licenses or permits or should regulatory authorities initiate any associated investigations or enforcement actions or impose related penalties or disallowances on the LLC, the LLC’s business, financial condition, results of operations and prospects could be materially adversely affected. Any failure to negotiate successful project development agreements for new facilities with third parties could have similar results. The LLC’s gas infrastructure facilities and other facilities are subject to many operational risks. Operational risks could result in, among other things, lost revenues due to prolonged outages, increased expenses due to monetary penalties or fines for compliance failures, liability to third parties for property and personal injury damage, a failure to perform under applicable sales agreements and associated loss of revenues from terminated agreements or liability for liquidated damages under continuing agreements. The consequences of these risks could have a material adverse effect on the LLC’s business, financial condition, results of operations and prospects. Uncertainties and risks inherent in operating and maintaining the LLC's facilities include, but are not limited to, risks associated with facility start-up operations, such as whether the facility will achieve projected operating performance on schedule and otherwise as planned. The LLC’s business, financial condition, results of operations and prospects can be materially adversely affected by weather conditions, including, but not limited to, the impact of severe weather. Threats of terrorism and catastrophic events that could result from terrorism, cyber-attacks, or individuals and/or groups attempting to disrupt the LLC’s business, or the businesses of third parties, may materially adversely affect the LLC’s business, financial condition, results of operations and prospects.

Supply disruptions due to weather or other forces.

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

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

A security incident on the Company’s information systems from cyber-attacks or other sources could lead to disruptions in natural gas deliveries or compromise the safety of the natural gas distribution system. Such attacks could also result in corruption of the Company’s financial information or the unauthorized release of confidential customer, employee or vendor information. The Company takes reasonable precautions to safeguard its computer systems from attack; however, there is no guarantee that Company processes will adequately protect against unauthorized access to data. In the event of a successful attack, the Company could be exposed to material financial and reputational risks.

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

A weak or poorly performing economy can negatively affect the Company’s profitability. An economic downturn can result in loss of commercial and industrial customers due to plant closings, a loss of residential customers as well as

7


slow or declining growth in new customer additions, all of which would result in reduced sales volumes and lower revenues. An economic downturn could also result in rising unemployment and other factors that could lead to a loss of customers and an increase in customer delinquencies and bad debt expense.

Environmental laws or regulations.

Passage of new environmental legislation or implementation of regulations that mandate reductions in greenhouse gas emissions or other similar restrictions could have a negative effect on the Company’s core operations and its investment in the Mountain Valley Pipeline, LLC. Natural gas is a clean and efficient energy source; however, the combustion of natural gas results in carbon related emissions. Such legislation could impose limitations on greenhouse gas emissions, require funding of new energy efficiency objectives, impose new operational requirements or lead to other additional costs to the Company. Regulations restricting or prohibiting the use of coal as a fuel for electric power generation could increase the demand for natural gas, potentially resulting in natural gas supply concerns and higher cost for natural gas. Legislation or regulations could limit the exploration and development of natural gas reserves, making the price of natural gas less competitive and less attractive as a fuel source for consumers, resulting in reduced deliveries and earnings.

Access to capital to maintain liquidity.

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

Inability to attract and retain professional and technical employees..

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

Regulatory actions or failure to obtain timely rate relief could decrease future profitability.

The Company’s natural gas operations are regulated by the SCC. The SCC approves the rates that the Company charges its natural gas customers. If the SCC did not allow rates that provided for the timely recovery of costs or a reasonable rate of return on investment in natural gas distribution facilities, earnings could be negatively impacted. Issuance of debt and equity are also subject to SCC regulation and approval. Delays or lack of approvals could inhibit the ability to access capital markets and negatively impact liquidity or earnings.

Insurance coverage may not be sufficient.

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

The cost of providing post-retirement benefits and related funding obligations may increase.

The costs of providing defined benefit pension and retiree medical plans are dependent on a number of factors such as the rates of return on plan assets, discount rates used in determining plan liabilities, the level of interest rates used to

8


measure the required minimum funding levels of the plan, future government regulation, changes in life expectancy, and required or voluntary contributions made to the plan. Changes in actuarial assumptions and differences between the assumptions and actual results, as well as a significant decline in the value of investments that fund these plans, if not offset or mitigated by a decline in plan liabilities, could increase the expense of these plans and require significant additional funding. Both funding obligations and increased expense could have a material impact on the Company's financial position, results of operation and cash flows.

Volatility in the price and availability of natural gas.

Natural gas purchases represent the single largest expense of the Company. Even with increasing demand from other areas, including electric generation, natural gas prices are currently expected to remain stable in the near term, although there can be no guarantee to that effect. However, if restrictions on drilling for natural gas in the shale rock formations are imposed at either federal, state or local levels due to environmental or other concerns or other exploration and development restrictions on conventional drilling are enacted, the price of natural gas could escalate. The economic viability of the LLC could be significantly impacted by such restrictions. Furthermore, if demand for natural gas increases at a rate in excess of current expectations, natural gas prices could also face upward pressure. Increasing natural gas prices could result in declining sales as well as increases in bad debt expense.

Business activities are concentrated in a limited geographic region.

Changes in the Roanoke Valley’s economy, politics, regulations and weather patterns could negatively impact the existing customer base, leading to declining usage patterns and financial condition of customers, both of which could adversely affect earnings.

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

Competition from other energy providers.

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

Failure to comply with debt covenant requirements could lead to adverse financial consequences that could affect the Company's liquidity and ability to borrow funds.

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

Inability to complete necessary or desirable pipeline expansion or infrastructure development projects may delay or prevent the Company from adequately serving its customers or expanding its distribution system.

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

9


and an inability to negotiate acceptable agreements relating to rights-of-way, construction or other material development components. As a result, the Company may not be able to adequately serve existing customers or support customer growth, which would negatively impact earnings.

Item 1B.
Unresolved Staff Comments.

Not applicable.

Item 2.
Properties.

Included in “Utility Plant” on the Company’s consolidated balance sheet are storage plant, transmission plant, distribution plant and general plant of Roanoke Gas as categorized by natural gas utilities. The Company has approximately 1,132 miles of transmission and distribution pipeline with transmission and distribution plant representing more than 86% of the total investment in plant. The transmission and distribution pipelines are located on or under public roads and highways or private property for which the Company has obtained the legal authorization and rights to operate.
Roanoke Gas owns and operates eight metering stations through which it measures and regulates the gas being delivered by its suppliers. These stations are located at various points throughout the Company’s distribution system.
Roanoke Gas also owns a liquefied natural gas storage facility located in Botetourt County that has the capacity to store up to 220,000 DTH of natural gas.
The Company’s executive, accounting and business offices, along with its maintenance and service departments, are located on Kimball Avenue in Roanoke, Virginia.
Although the Company considers its present properties to be adequate, management continues to evaluate the adequacy of its current facilities as additional needs arise.
 
Item 3.
Legal Proceedings.

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

Not applicable.
 

10


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.
 
 
Range of Bid Prices
 
Cash Dividends
Year Ending September 30, 2016
 
High
 
Low
 
Declared
 First Quarter
 
$
23.94

 
$
20.05

 
$
0.2025

 Second Quarter
 
23.39

 
20.66

 
0.2025

 Third Quarter
 
26.00

 
21.45

 
0.2025

 Fourth Quarter
 
25.09

 
22.32

 
0.2025

 
 
 
 
 
 
 
Year Ending September 30, 2015
 
 
 
 
 
 
 First Quarter
 
$
22.45

 
$
19.28

 
$
0.1925

 Second Quarter
 
25.67

 
20.20

 
0.1925

 Third Quarter
 
22.99

 
19.78

 
0.1925

 Fourth Quarter
 
21.96

 
19.95

 
0.1925

As of November 25, 2016, there were 1,192 holders of record of the Company’s common stock. This number does not include all beneficial owners of common stock who hold their shares in “street name.”

Comparisons of Cumulative Total Shareholder Returns
The following performance graph compares the Company’s total shareholder return from September 30, 2011 through September 30, 2016 with the Dow Jones US Utility Index, a utility based index, and the Standard & Poor’s 500 Stock Index (S&P 500 Index), a broad market index.
The graph below reflects the value of a hypothetical investment of $100 made September 30, 2011 in the Company’s common stock and in each index as of September 30, 2016, assuming the reinvestment of all dividends. Historical stock price performance as reflected on the graph is not indicative of future price performance. The total value at the end of the five years was $163 for the Company’s common stock, $192 for the Dow Jones US Utilities Index and $213 for the S&P 500 Index.





11


rgco-9302_chartx53573.jpg
A summary of the Company’s equity compensation plans follows as of September 30, 2016:
 
 
(a)
 
(b)
 
(c)
Plan category
 
Number of securities
to be issued upon
exercise of
outstanding options,
warrants and rights
 
Weighted-average
exercise price of
outstanding
options, warrants
and rights
 
Number of securities
remaining available
for future issuance
under equity
compensation plans
(excluding securities
reflected in column
(a))
Equity compensation plans approved by security holders
 
58,200

 
$20.25
 
110,307

Equity compensation plans not approved by security holders
 

 

 

Total
 
58,200

 
$20.25
 
110,307

 

12



Item 6.
Selected Financial Data.

 
 
Year Ending September 30,
 
 
2016
 
2015
 
2014
 
2013
 
2012
 
 
 
 
 
 
 
 
 
 
 
Operating Revenues
 
$
59,063,291

 
$
68,189,607

 
$
75,016,134

 
$
63,205,666

 
$
58,799,687

Gross Margin
 
31,564,914

 
30,206,433

 
29,337,089

 
27,602,891

 
26,933,097

Operating Income
 
11,212,092

 
10,006,192

 
9,681,868

 
8,795,055

 
8,786,535

Net Income
 
5,806,866

 
5,094,415

 
4,708,440

 
4,262,052

 
4,296,745

Basic Earnings Per Share
 
$
1.22

 
$
1.08

 
$
1.00

 
$
0.91

 
$
0.92

Cash Dividends Declared Per Share
 
$
0.81

 
$
0.77

 
$
0.74

 
$
1.72

 
$
0.70

Book Value Per Share
 
$
11.63

 
$
11.14

 
$
11.02

 
$
10.51

 
$
10.85

Average Shares Outstanding
 
4,766,604

 
4,728,210

 
4,715,478

 
4,698,727

 
4,647,439

Total Assets (1)
 
$
165,552,849

 
$
145,847,194

 
$
137,423,321

 
$
121,658,797

 
$
127,363,410

 
 
 
 
 
 
 
 
 
 
 
Long-Term Debt (Less Unamortized Debt Expense)
 
$
33,636,051

 
$
30,316,573

 
$
30,306,919

 
$
12,984,169

 
$
12,978,681

Stockholders' Equity
 
55,667,072

 
52,840,991

 
52,020,847

 
49,502,422

 
50,682,930

Shares Outstanding at Sept. 30
 
4,788,289

 
4,741,498

 
4,720,378

 
4,709,326

 
4,670,567


(1)Total assets for the prior years were revised to reflect the reclassification of current deferred tax assets against deferred tax liabilities as provided for in ASU 2015-17, Income Taxes: Balance Sheet Classification of Deferred Taxes.

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

Forward-Looking Statements

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

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




13



Overview

Resources is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately 59,600 residential, commercial and industrial customers in Roanoke, Virginia, and the surrounding localities, through its Roanoke Gas Company (“Roanoke Gas”) subsidiary. Roanoke Gas also provides certain unregulated services. Resources also formed a wholly-owned subsidiary, RGC Midstream, LLC ("Midstream"), to invest in the Mountain Valley Pipeline, LLC (the "LLC"). On October 1, 2015, Midstream executed agreements to become a 1% member in the LLC. More information is provided under the Equity Investment in Mountain Valley Pipeline section below. The unregulated operations represent less than 2% of revenues and margins of Resources.

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

The Company is committed to the safe and reliable delivery of natural gas to its customers. Since 1991, the Company has placed an emphasis on the modernization of its distribution system through the renewal and replacement of its cast iron and bare steel natural gas distribution pipelines. With recent regulatory actions placing a greater emphasis on pipeline safety, the Company continues to focus its efforts on completing its renewal and replacement program. The Company completed the replacement of all cast iron pipe in fiscal 2016 and replacement of all bare steel pipe in the first quarter of fiscal 2017. The Company will continue its renewal program with plans to replace first generation, pre-1973 plastic pipe over the next five years.

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

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

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

The Company's approved billing rates include a component designed to allow for the recovery of the cost of natural gas used by its customers. The cost of natural gas is considered a pass-through cost and is independent of the non-gas rates of the Company. This rate component, referred to as the PGA clause, allows the Company to pass along to its customers increases and decreases in natural gas costs incurred by its regulated operations. On a quarterly basis, the Company files a PGA rate adjustment request with the SCC to adjust the gas cost component of its rates up or down depending on projected price and activity. Once administrative approval is received, the Company adjusts the gas cost component of its rates to reflect the approved amount. As actual costs will differ from the projections used in establishing the PGA rate, the Company will either over-recover or under-recover its actual gas costs during the period. The difference

14


between actual costs incurred and costs recovered through the application of the PGA is recorded as a regulatory asset or liability. At the end of the annual deferral period, the balance is amortized over an ensuing 12-month period as amounts are reflected in customer billings.

The WNA reduces the volatility in earnings due to the variability in temperatures during the heating season. The WNA is based on the most recent 30-year temperature average. The WNA provides the Company with a level of earnings protection when weather is warmer than normal and provides its customers with price protection when the weather is colder than normal. The WNA allows the Company to recover from its customers the lost margin (excluding gas costs) from the impact of weather that is warmer than normal and correspondingly requires the Company to refund the excess margin earned for weather that is colder than normal. The WNA year runs from April through March of each year. Any billings or refunds related to the WNA are completed following the end of the WNA year. For the fiscal year ended September 30, 2016, the Company recorded $1,318,000 in additional revenue from the WNA for weather that was approximately 13% warmer than normal. During the fiscal year ended September 30, 2015, the Company had reduced revenue by $609,000 due to the WNA for weather that was approximately 6.5% colder than normal. During the fiscal year ended September 30, 2014, the Company recorded a reduction in revenue of $563,000 to reflect the WNA adjustment for weather that was approximately 9% colder than normal. Prior to April 2014, the WNA provided for a weather band of 3% above and below normal whereby no WNA would be calculated until weather was outside the 3% band.

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

During times of rising gas costs and rising inventory levels, the Company recognizes ICC revenues to offset higher financing costs associated with higher inventory balances. Conversely, during times of decreasing gas costs and declining inventory balances, the Company recognizes less carrying cost revenue as financing costs are lower. In addition, ICC revenues are impacted by changes in the weighted-average cost of capital. The decline in commodity prices during the 2016 summer storage refill period continued the downward trend on the cost of gas in storage. Although total average volumes in storage were higher during the current year, the lower commodity price of gas resulted in a lower cost of gas in storage, which is the basis for calculating ICC revenues. Furthermore, the increase in the utilization of the line-of-credit resulted in a greater allocation of the lower-rate debt in the overall weighted-average cost of capital, thereby reducing the ICC factor. The combination of lower average storage gas inventories in terms of cost and a lower ICC factor resulted in a $182,000 decline in ICC revenues in fiscal 2016. This decline follows a reduction of $46,000 in ICC revenues during the prior fiscal year, resulting from the decline in price of gas delivered to storage. Based on the current natural gas futures prices, the average dollar balance of gas in storage may decline next year, but the decline is expected to be at a smaller level.

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

The Company’s non-gas rates are designed to allow for the recovery of non-gas related expenses and provide a reasonable return to shareholders. These rates are determined based on the filing of a formal rate application with the SCC utilizing historical information including investment in natural gas facilities. Generally, investments related to extending service to new customers are recovered through the non-gas rates currently in place. The investment in replacing and upgrading existing infrastructure is not recoverable until a formal rate application is made to include the additional investment and new non-gas rates are approved. The SAVE Plan and Rider provides the Company with the ability to recover costs related to these investments on a prospective basis rather than on a historical basis. The SAVE Plan provides a mechanism to recover the related depreciation and expenses and provide a return on rate base of the additional capital investments related to improving the Company's infrastructure until such time a formal rate application is filed to incorporate this investment in the Company's non-gas rates. As the Company did not file for an increase in the non-gas rates during the prior two years and the level of SAVE qualifying capital investment continues to grow, SAVE Plan revenues have increased significantly. The Company recognized approximately $2,538,000, $1,308,000 and $292,000 in SAVE Plan revenues for years ended September 30, 2016, 2015 and 2014, respectively.

15


SAVE revenues will be included as part of the non-gas base rates the next time the Company files for a non-gas rate increase. Additional information regarding the SAVE Rider is provided under the Regulatory Affairs section.

The economic environment has a direct correlation with business and industrial production, customer growth and natural gas utilization. The local economy has lost some key business activities over the last few years as some companies have either shut down or relocated all or portions of their operations elsewhere. However, the Company continues to experience some customer and sales growth including the addition of a large natural gas fleet refueling station at a commercial customer. In addition, new business ventures have been announced in the Company's service territory that should provide some additional natural gas load over the next few years. The local economy appears relatively stable and should continue to improve absent a major economic setback on a local, regional or national level.

Results of Operations

Fiscal Year 2016 Compared with Fiscal Year 2015

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

Operating Revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended September 30,
2016
 
2015
 
Decrease
 
Percentage
Gas Utilities
$
58,079,990

 
$
67,094,290

 
$
(9,014,300
)
 
(13
)%
Other
983,301

 
1,095,317

 
(112,016
)
 
(10
)%
Total Operating Revenues
$
59,063,291

 
$
68,189,607

 
$
(9,126,316
)
 
(13
)%

Delivered Volumes
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended September 30,
2016
 
2015
 
Decrease
 
Percentage
Regulated Natural Gas (DTH)
 
 
 
 
 
 
 
 Residential and Commercial
6,088,108

 
6,955,594

 
(867,486
)
 
(12
)%
 Transportation and Interruptible
2,754,497

 
2,919,413

 
(164,916
)
 
(6
)%
 Total Delivered Volumes
8,842,605

 
9,875,007

 
(1,032,402
)
 
(10
)%
Heating Degree Days (Unofficial)
3,484

 
4,253

 
(769
)
 
(18
)%

Total gas utility operating revenues for the year ended September 30, 2016 declined by 13% from the year ended September 30, 2015 primarily due to a combination of lower gas costs and a reduction in natural gas deliveries more than offsetting revenues from the SAVE plan rider and WNA. The average commodity price of natural gas declined by 28% per decatherm sold. Delivered volumes declined primarily due to weather, as reflected in the lower residential and commercial volumes. Industrial consumption also declined, causing a reduction in transportation and interruptible volumes. Residential and commercial deliveries tend to be more weather sensitive as reflected by a 12% decline in volumes on 18% fewer heating degree days. Transportation and interruptible volumes, which are primarily driven by production activities rather than weather, decreased by 6%. Other revenues experienced a 10% decrease. Approximately half of the decrease in other revenues was attributable to the cessation of operations for Utility Consultants during the prior year and Application Resources during the current year.

Gross Margin
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended September 30,
2016
 
2015
 
Increase / (Decrease)
 
Percentage
Gas Utility
$
31,070,660

 
$
29,656,975

 
$
1,413,685

 
5
 %
Other
494,254

 
549,458

 
(55,204
)
 
(10
)%
Total Gross Margin
$
31,564,914

 
$
30,206,433

 
$
1,358,481

 
4
 %

16



Regulated natural gas margins from utility operations increased by 5% from fiscal 2015, primarily as a result of WNA revenues, increasing SAVE Plan revenues and customer base charges related to customer growth more than offsetting lower volumetric margins and ICC revenues. SAVE Plan revenues increased by $1,230,000 as the Company was in the third year of the current SAVE Plan. The growth in SAVE Plan revenues has been fueled by the Company's pipeline renewal program as the Company continues to invest in eligible SAVE Plan infrastructure projects. As noted above, volumetric margin declined due to a reduction in total volumes delivered. Residential and commercial volumes declined due to much warmer weather compared to the prior year. Interruptible and transportation volumes declined due to a combination of reduced activity at one large customer, the closing of another industrial customer's operations during the prior fiscal year and a significant decrease in usage by another industrial customer that uses natural gas as its back up fuel source. The impact of the warmer weather on volumetric margin was offset by the WNA mechanism. As discussed in more detail above, the WNA mechanism allowed the Company to recognize margin related to those natural gas volumes not sold due to the warmer weather. ICC revenues continued to decline with a $182,000 reduction in fiscal 2016 compared to the prior year due to lower commodity prices and a lower ICC factor.

Other margins, consisting of non-utility related services, decreased by $55,204 on comparable activity. The Utility Consultants, which ceased activity last year, and Application Resources, which terminated in fiscal 2016, accounted for approximately $25,000 of the reduction in non-utility related margin. The remainder of the decrease in other margins is attributable to the level of activity under these contracts which fluctuates based on customer requirements. In addition, service contracts which generate the majority of the non-utility related revenues are subject to annual or semi-annual renewal provisions and the potential exists that these contracts may not be renewed or extended by the customer which could impact future revenues and margins.

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

 
Twelve Months Ended September 30,
 
 
 
2016
 
2015
 
Increase (Decrease)
Customer Base Charge
$
12,364,811

 
$
12,240,580

 
$
124,231

SAVE Plan
2,538,055

 
1,307,795

 
1,230,260

Volumetric
14,099,214

 
15,757,907

 
(1,658,693
)
WNA
1,317,800

 
(608,560
)
 
1,926,360

Carrying Cost
651,492

 
833,291

 
(181,799
)
Other
99,288

 
125,962

 
(26,674
)
Total
$
31,070,660

 
$
29,656,975

 
$
1,413,685


Operations and Maintenance Expense - Operations and maintenance expenses declined by $388,799, or 3%, from last year due to much higher overhead capitalization and lower bad debt expenses more than offsetting higher benefit and labor costs. Capitalized overheads, which include general and administrative costs, payroll overheads and engineering costs, increased by 30%, or nearly $873,000, over fiscal 2015 due to higher benefit costs, a 30% increase in capital expenditures and a 38% increase in the amount of LNG produced. In addition, bad debt expense declined by $77,000 due to the combination of reduced sales related to much warmer weather and lower gas costs. Total benefit costs increased by $456,000 due to increased pension and postretirement medical costs related to the amortization of higher actuarial losses attributable to the adoption of a new mortality table that reflects extended life expectancies. Operating and maintenance labor costs increased by $141,000, or 2%, due to normal wage adjustments. The remaining decrease relates to a variety of areas, including the level of contracted and professional services, as the prior year included expenses related to the union contract negotiations and due diligence work related to the investment in the LLC.

General Taxes - General taxes increased $56,705, or 4%, primarily due to higher property taxes associated with increases in utility property.
 
Depreciation - Depreciation expense increased by $484,675, or more than 9%, corresponding to a similar increase in utility plant investment.


17


Equity in Earnings of Unconsolidated Affiliate - The investment in Mountain Valley Pipeline began in fiscal 2016 and the $152,864 equity in earnings is primarily composed of allowance for funds used during construction ("AFUDC"). The investment in Mountain Valley Pipeline and the related AFUDC earnings are discussed further under the Equity Investment in Mountain Valley Pipeline section below.

Other Expense - Other expense, net, increased by $26,789, or 12%, primarily due to higher pipeline assessments.

Interest Expense - Total interest expense increased by $123,902, or 8%, due to a 15% increase in the average debt outstanding. The combination of the investments in Mountain Valley Pipeline and the level of capital expenditures during the year have required increased borrowing.

Income Taxes - Income tax expense increased by $495,622, or 16%, on higher pre-tax earnings. The effective tax rate was 38.7% for fiscal 2016 compared to 38.4% for fiscal 2015.

Net Income and Dividends - Net income for fiscal 2016 was $5,806,866 compared to $5,094,415 for fiscal 2015. Basic and diluted earnings per share were $1.22 in fiscal 2016 compared to $1.08 in fiscal 2015. Dividends declared per share of common stock were $0.81 in fiscal 2016 compared to $0.77 in fiscal 2015.
    
Fiscal Year 2015 Compared with Fiscal Year 2014

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

Operating Revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended September 30,
2015
 
2014
 
Decrease
 
Percentage
Gas Utilities
$
67,094,290

 
$
73,865,487

 
$
(6,771,197
)
 
(9
)%
Other
1,095,317

 
1,150,647

 
(55,330
)
 
(5
)%
Total Operating Revenues
$
68,189,607

 
$
75,016,134

 
$
(6,826,527
)
 
(9
)%

Delivered Volumes
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended September 30,
2015
 
2014
 
Decrease
 
Percentage
Regulated Natural Gas (DTH)
 
 
 
 
 
 
 
 Residential and Commercial
6,955,594

 
7,005,920

 
(50,326
)
 
(1
)%
 Transportation and Interruptible
2,919,413

 
3,081,731

 
(162,318
)
 
(5
)%
 Total Delivered Volumes
9,875,007

 
10,087,651

 
(212,644
)
 
(2
)%
Heating Degree Days (Unofficial)
4,253

 
4,351

 
(98
)
 
(2
)%

Total gas utility operating revenues for the year ended September 30, 2015 decreased by 9% from the year ended September 30, 2014 primarily due to lower gas costs and a reduction in natural gas deliveries. The average commodity price of natural gas declined by 21% per decatherm sold. Delivered volumes declined due in part to weather, as reflected in the decline in residential and commercial volumes, and a reduction in industrial consumption. Residential and commercial deliveries tend to be more weather sensitive as reflected by a decline of 1% in volumes on 2% fewer heating degree days. Transportation and interruptible volumes, which are primarily driven by production activities rather than weather, decreased by 5%. Other revenues decreased by 5% as well.


18


Gross Margin
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended September 30,
2015
 
2014
 
Increase / (Decrease)
 
Percentage
Gas Utility
$
29,656,975

 
$
28,774,213

 
$
882,762

 
3
 %
Other
549,458

 
562,876

 
(13,418
)
 
(2
)%
Total Gross Margin
$
30,206,433

 
$
29,337,089

 
$
869,344

 
3
 %

Regulated natural gas margins from utility operations increased by 3% from fiscal 2014, primarily as a result of higher SAVE Plan revenues and customer base charges more than offsetting lower volumetric margins and ICC revenues. SAVE Plan revenues increased by $1,016,000. Customer base charges also increased due to modest customer growth. Volumetric margin declined due to a reduction in total volumes delivered. Residential and commercial volumes declined primarily due to slightly warmer weather. Interruptible and transportation volumes declined due to the loss of a customer during fiscal 2015 and decreased usage at two of the Company's larger customers. The effect of the warmer weather was mitigated in part by the WNA mechanism. In fiscal 2014, the WNA mechanism provided for a weather band of 3% variance around normal during the winter heating season while the fiscal 2015 heating season had a 0% weather band. Because the fiscal 2014 year had a 3% weather band in place for part of the year and weather was colder than normal, the Company was able to retain approximately $251,000 in excess margin realized on the 3% weather band, while the fiscal 2015 year WNA with a 0% weather band required the adjustment of margin back to the level expected for normal weather.

Other margins, consisting of non-utility related services, decreased by $13,418 on comparable activity. The Utility Consultants, which ceased activity during fiscal 2015, contributed $17,000 to the non-utility related margin. The service contracts that comprise most of the non-utility related activities are subject to annual or semi-annual renewal provisions and the potential exists that these contracts may not be renewed or extended by the customer. In addition, the level of activity under these contracts will fluctuate based on customer requirements which may result in fluctuations in revenues and margins.

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

 
Twelve Months Ended September 30,
 
 
 
2015
 
2014
 
Increase (Decrease)
Customer Base Charge
$
12,240,580

 
$
12,064,764

 
$
175,816

SAVE Plan
1,307,795

 
291,946

 
1,015,849

Volumetric
15,757,907

 
15,990,704

 
(232,797
)
WNA
(608,560
)
 
(563,187
)
 
(45,373
)
Carrying Cost
833,291

 
879,381

 
(46,090
)
Other
125,962

 
110,605

 
15,357

Total
$
29,656,975

 
$
28,774,213

 
$
882,762


Operations and Maintenance Expense - Operations and maintenance expenses increased by $103,497, or 1%, in fiscal 2015 compared with fiscal 2014 due to higher benefit costs and professional services and less overhead capitalization more than offsetting reductions in the level of bad debt expense, labor and contracted labor. Employee benefit expenses increased by $260,000 primarily due to higher medical, defined benefit pension plan and postretirement medical plan. The actuarially determined expenses for the pension and postretirement plans increased in fiscal 2015 due to a decline in the discount rate for valuing both plans' liabilities at September 30, 2014. Professional services increased by $77,000 primarily due to legal expenses associated with the new union contract, the formation of the Company's new subsidiary and the due diligence work related to the investment in the Mountain Valley Pipeline. Total capitalized overheads declined by $106,000 because of delays in the production of liquefied natural gas due to maintenance down time, lower capital expenditures and a reduction in the capitalization rate compared to fiscal 2014. Bad debt expense decreased by $61,000 due to lower customer billings resulting from warmer weather and a lower commodity price of gas. Labor and contracted services costs declined by $133,000 due to timing of pipeline right-of-way clearing and prior year costs related to updating the Company's corrosion control processes. The remaining

19


decrease relates to a variety of areas including the level of facility and equipment maintenance, advertising and administrative costs.

General Taxes - General taxes increased $46,035, or 3%, primarily due to higher property taxes associated with increases in utility property.
 
Depreciation - Depreciation expense increased by $395,488, or 8%, corresponding to a similar increase in utility plant investment.

Other Expense - Other expense, net, increased by $21,909, or 11%, primarily due to an increase in charitable requests related to specific campaigns.

Interest Expense - Total interest expense decreased by $314,582, or 17%, due to a lower interest rate on long-term debt. In September 2014, the Company refinanced its $28,000,000 in long-term debt, which had an average interest rate of 6.30% with $30,500,000 in new debt having a rate of 4.26%.

Income Taxes - Income tax expense increased by $231,022 on higher pre-tax earnings. The effective tax rate was 38.4% for both fiscal 2015 and 2014.

Net Income and Dividends - Net income for fiscal 2015 was $5,094,415 compared to $4,708,440 for fiscal 2014. Basic and diluted earnings per share were $1.08 in fiscal 2015 compared to $1.00 in fiscal 2014. Dividends declared per share of common stock were $0.77 in fiscal 2015 compared to $0.74 in fiscal 2014.
    
Capital Resources and Liquidity

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

Cash and cash equivalents decreased by $341,982 in fiscal 2016 compared to an increase of $135,477 in fiscal 2015 and a decrease of $1,996,467 in fiscal 2014. The following table summarizes the categories of sources and uses of cash:

Cash Flow Summary
Year Ended September 30,
 
2016
 
2015
 
2014
Provided by operating activities
$
14,921,640

 
$
16,760,827

 
$
6,839,738

Used in investing activities
(20,996,501
)
 
(13,750,274
)
 
(14,698,570
)
Provided by (used in) financing activities
5,732,879

 
(2,875,076
)
 
5,862,365

Increase (decrease) in cash and cash equivalents
$
(341,982
)
 
$
135,477

 
$
(1,996,467
)

Cash Flows Provided by Operating Activities:

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

Cash provided by operating activities was $14,922,000 in fiscal 2016, $16,761,000 in fiscal 2015 and $6,840,000 in fiscal 2014. Cash provided by operating activities decreased by more than $1,800,000 from last year primarily as a result of a smaller decline in natural gas commodity prices and refunding part of last year's over-collection of gas costs,

20


offset by a greater increase in deferred tax liability due to the subsequent extension of 50% bonus tax depreciation through 2017, higher net income and book depreciation. The average price of gas in storage declined by 13% during fiscal 2016 as natural gas commodity prices continued their decline even though total volumes increased by nearly 5%, resulting in an overall decrease in gas in storage of $724,000. During fiscal 2015, the average price of gas in storage declined by 28% on nearly unchanged volumes resulting in a $3,242,000 decrease in gas in storage from fiscal 2014. In addition, the significant drop in natural gas prices during the prior year resulted in an increase in over-collection of gas costs as the adjustment to the PGA factor used to bill customers for the gas component of rates lagged behind the declining price of gas. As a result, the Company collected $1,900,000 from customers in excess of actual gas costs in fiscal 2015. During fiscal 2016, the Company reduced its over-collection by nearly $1,000,000 as the Company began refunding the excess collections. Subsequent to the issuance of fiscal 2015 financial statements, Congress passed, and the President signed into law, the Protecting Americans from Tax Hikes ("PATH" Act) which extended the 50% bonus depreciation for calendar 2015 through December 31, 2017 and provided for 40% bonus depreciation for calendar 2018 and 30% bonus depreciation for calendar 2019. As a result of the passage of the PATH Act, the Company recorded an adjustment to deferred taxes in the amount of $1,284,000 in the first quarter of fiscal 2016 to recognize the effect of bonus depreciation on the balance of 2015 asset additions in addition to $3,065,000 in deferred tax liability recognized for the effect of 50% bonus depreciation on fiscal 2016 capital additions. As a result of the bonus depreciation extension for 2015, the Company requested and received a refund of $1,600,000 in federal taxes related to the additional deduction claimed on the fiscal 2015 tax return. In comparison, total deferred taxes increased by $2,417,000 in fiscal 2015. A summary of the key components of the cash flows from operating activities is provided below:

 
Twelve Months Ended September 30,
 
 
Cash Flow Provided by Operating Activities:
2016
 
2015
 
Increase (Decrease)
  Net income
$
5,806,866

 
$
5,094,415

 
$
712,451

  Depreciation
5,709,525

 
5,219,893

 
489,632

  Decrease in gas in storage
723,713

 
3,242,492

 
(2,518,779
)
  Increase / (decrease) in over-collection of gas costs
(991,739
)
 
2,082,257

 
(3,073,996
)
  Increase in deferred taxes
4,466,954

 
2,416,841

 
2,050,113

  Other
(793,679
)
 
(1,295,071
)
 
501,392

Net Cash Provided by Operations
$
14,921,640

 
$
16,760,827

 
$
(1,839,187
)

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 increased to nearly $18,000,000 in fiscal 2016 from $13,800,000 in fiscal 2015 and $14,700,000 in fiscal 2014. The Company renewed 14.9 miles of natural gas distribution main and replaced 684 services in fiscal 2016. This compares to 10 miles of main and 594 services in fiscal 2015 and 13.6 miles of main and 942 services in fiscal 2014. The Company completed the replacement of its cast iron pipe during fiscal 2016 and finished replacing the remainder of the bare steel pipe in November 2016. The Company also completed the replacement of two natural gas custody transfer stations connected to the East Tennessee transmission line. In addition, the Company’s capital expenditures included costs to extend natural gas distribution mains and services to 495 new customers in fiscal 2016 compared to 609 new customers in fiscal 2015 and 673 in fiscal 2014. Depreciation covered approximately 32% of the current year's capital expenditures compared to 38% for 2015 and 33% for 2014, with the balance provided from other operating cash flows and borrowings under the line-of-credit.

Capital expenditures are expected to remain at elevated levels over the next few years. With the replacement of cast iron and bare steel mains completed, renewal efforts will now shift to replacing approximately 45 miles of pre-1973 first generation plastic pipe with current polyethylene pipe. This renewal project is expected to be completed by 2021. The Company has also begun implementation of an automated meter reading system, expected to be completed in fiscal 2017, whereby all customer meters will be retrofitted with transmitters which will allow consumption data to be collected remotely. The current capital budget for fiscal 2017 reflects an increase of more than $3,000,000 in expenditures over fiscal 2016. The Company expects to increase its borrowing activity to meet the funding requirements of these planned expenditures.


21


Investing cash flows also reflect the Company's $3,055,746 funding of its participation in the Mountain Valley Pipeline. The Company expects to invest an additional $32 million over the remaining three-year project period, pending FERC approval. Funding for the investment in the LLC is provided through a combination of a $25 million credit facility, which matures in 2020, and equity capital. More information regarding the credit facility is provided in Note 5 of the Consolidated Financial Statements and under the Equity Investment in Mountain Valley Pipeline section below.

Cash Flows Provided by (Used in) Financing Activities:

Financing activities generally consist of long-term and short-term borrowings and repayments, issuance of stock and the payment of dividends. As mentioned above, the Company uses its line-of-credit arrangement to fund seasonal working capital and provide temporary financing for capital projects. Cash flows provided by financing activities were $5,733,000 in fiscal 2016 compared to cash used in financing activities of $2,875,000 in fiscal 2015 and cash provided by financing activities of $5,862,000 for fiscal 2014. The combination of greater capital investment related to the pipeline renewal program and other projects, including the Mountain Valley Pipeline, required increased borrowing activity. In fiscal 2015, net borrowing activity under the line-of-credit was nearly unchanged as the Company benefited from higher operating cash flows resulting from declines in the price of natural gas and the extension of 50% bonus depreciation for tax purposes. In 2014, the Company refinanced $28,000,000 of its debt, including $2,238,000 in early termination fees on notes and interest rate swaps with $30,500,000 in unsecured 20-year term notes. The early termination fees were deferred as a regulatory asset and are being amortized over the term of the new notes as a component of interest expense. The $28,000,000 in retired debt had an average interest rate of 6.30% with an effective rate of 6.43%. The new debt has a stated interest rate of 4.26% and an effective rate of 4.67%. The nearly $315,000 reduction in interest expense in fiscal 2015 is entirely due to the refinancing. The Company increased the utilization of its line-of-credit to provide bridge financing for its capital budget for amounts in excess of those provided by operations. Proceeds from the issuance of stock were $1,031,000 under the DRIP plan. Dividends increased as the annualized dividend rate per share went from $0.74 in fiscal 2014 to $0.77 in fiscal 2015 and $0.81 if fiscal 2016. The Company’s consolidated capitalization was 62.2% equity and 37.8% long-term debt at September 30, 2016. This compares to 63.4% equity and 36.6% long-term debt at September 30, 2015.

Effective March 31, 2016, the Company entered into a new line-of-credit agreement. This new agreement maintains the same terms and rates as provided for under the expired agreement. The interest rate is based on 30-day LIBOR plus 100 basis points and includes an availability fee of 15 basis points applied to the difference between the face amount of the note and the average outstanding balance during the period. The Company maintained multi-tiered borrowing limits to accommodate seasonal borrowing demands and minimize overall borrowing costs, with available limits ranging from $10,000,000 to $24,000,000 during the term of the agreement. The line-of-credit agreement will expire March 31, 2017. The Company anticipates being able to extend or replace the line-of-credit upon expiration; however, there is no guarantee that the line-of-credit will be extended or replaced under the same or equivalent terms currently in place.

On December 29, 2015, Midstream entered into a Credit Agreement (the "Credit Agreement") and related Promissory Notes (the "Notes"), under which Midstream may borrow up to a total of $25 million, over a period of 5 years, with an interest rate of 30-day LIBOR plus 160 basis points. In accordance with the terms of the Credit Agreement, at such time as Midstream has borrowed $17.5 million under the Notes, Midstream is required to provide the next $5 million in equity towards its capital contributions to the LLC. Once Midstream has completed its $5 million in contributions, it may resume borrowing up to the $25 million limit. Currently, management is considering the possibility of an equity issue by Resources to provide Midstream with the $5 million in equity capital required under the Notes. Following the end of the 5-year term on the Notes, Midstream anticipates refinancing the $25 million Notes with a longer-term amortizing debt instrument.

Off-Balance Sheet Arrangements

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

Contractual Obligations and Commitments

The Company has incurred various contractual obligations and commitments in the normal course of business. As of September 30, 2016, the estimated recorded and unrecorded obligations are as follows:


22


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

 
$

 
$
3,396,200

 
$
30,500,000

 
$
33,896,200

Short-Term Debt (2)
14,556,785

 

 

 

 
14,556,785

Total
$
14,556,785

 
$

 
$
3,396,200

 
$
30,500,000

 
$
48,452,985

 
 
 
 
 
 
 
 
 
 
(1) See Note 5 to the consolidated financial statements.
(2) See Note 4 to the consolidated financial statements.

Unrecorded contractual obligations, not reflected in consolidated balance sheets in accordance with US GAAP:
Less than 1 year
 
1-3 Years
 
4-5 Years
 
After 5 Years
 
Total
Pipeline and Storage Capacity (3)
$
10,474,339

 
$
15,999,239

 
$
7,276,676

 
$
2,682,848

 
$
36,433,102

Gas Supply (4)

 

 

 

 

Interest on Short-Term Debt (5)
32,824

 

 

 

 
32,824

Interest on Long-Term Debt (6)
1,371,200

 
2,742,400

 
2,688,200

 
17,277,081

 
24,078,881

Pension Plan Funding (7)

 

 

 

 

Investment in MVP (8)
3,500,000

 
28,444,254

 

 

 
31,944,254

Other Obligations (9)
117,780

 
24,502

 
4,661

 
25,540

 
172,483

Total
$
15,496,143

 
$
47,210,395

 
$
9,969,537

 
$
19,985,469

 
$
92,661,544

 
 
 
 
 
 
 
 
 
 
(3) Recoverable through the PGA process.
(4) Volumetric obligation is for the purchase of contracted decatherms of natural gas at market prices in effect at the time of purchase. Unable to estimate related payment obligation until time of purchase. See Note 10 to the consolidated financial statements.
(5) Accrued interest on line-of-credit balance at September 30, 2016, including minimum facility fee on unused line-of-credit. See Note 4 to the consolidated financial statements.
(6) Calculated interest payments on 20-year $30.5 million Roanoke Gas Co. note payable due September 18, 2034 and on 09/30/2016 balance on Midstream notes due December 29, 2020. See Note 5 to the consolidated financial statements.
(7) Estimated minimum funding assuming application of credit balances in plan to offset funding. Minimum funding requirements beyond five years is not available. See Note 7 to the consolidated financial statements.
(8) Projected remaining funding of the Company's 1% interest in MVP as entered into on October 1, 2015.
(9) Various lease, maintenance, equipment and service contracts.
              
Equity Investment in Mountain Valley Pipeline

On October 1, 2015, the Company, through its newly formed wholly-owned subsidiary, Midstream, entered into an agreement to become a 1% member in the LLC. The purpose of the LLC is to construct and operate the Mountain Valley Pipeline ("MVP"), a natural gas pipeline connecting an existing gathering and transmission system in northern West Virginia to another interstate pipeline in south central Virginia. This project falls under the jurisdiction of FERC and is subject to its approval prior to beginning construction. In October 2015, the LLC filed the application with FERC to construct the pipeline. On June 28, 2016, FERC issued the Notice of Schedule for Environmental Review (NOS) and on September 16, 2016, FERC issued its draft environmental impact statement ("EIS") regarding the MVP. In the draft EIS, FERC staff concluded that approval of the MVP would result in some adverse environmental impacts; however, they acknowledged that such impacts would be reduced to less than significant levels with the implementation of the LLC's proposed mitigation plans in addition to measures recommended in the EIS. Comments regarding the draft EIS must be filed on or before December 22, 2016. Based on the schedule provided in the NOS, the MVP expects to receive the FERC certificate in mid-2017. The pipeline is targeted to be placed in-service during the fourth quarter of 2018.

Management believes the investment in the LLC will be beneficial for the Company, its shareholders and southwest Virginia. In addition to the potential returns from the investment in the LLC, Roanoke Gas will benefit from access to another source of natural gas to its distribution system. Currently, Roanoke Gas is served by two pipelines and a

23


liquefied natural gas storage facility. Damage to or interruption in supply from any of these sources, especially during the winter heating season, could have a significant impact on the Company's ability to serve its customers. A third pipeline would reduce the impact from such an event. In addition, the proposed pipeline path would provide the Company with a more economically feasible opportunity to provide natural gas service to previously unserved areas in southwest Virginia.

The total project cost is anticipated to be $3.5 billion. As a 1% member in the LLC, Midstream's contribution is expected to be approximately $35 million. The agreement provides for a schedule of cash draws to fund the project. The initial payments are related to pre-construction activities including the acquisition of land, easements and materials. Once approved and construction begins, more significant cash draws will be required. Initial funding for the investment in the LLC is provided through the Midstream credit facility under which Midstream may borrow up to a total of $25 million, over a period of 5 years with the balance coming from equity capital.

A majority of the earnings from the investment in MVP relates to the allowance for funds used during construction ("AFUDC") income generated by the deployment of capital in the design, engineering, materials procurement, project management and ultimately construction phases of the pipeline. AFUDC is an accounting method whereby the costs of debt and equity funds used to finance facility infrastructure are credited to income and charged to the cost of the project. The level of investment in MVP will continue to grow at a steady pace until such time FERC issues their decision on the project. If approved by FERC, construction on the pipeline should begin in earnest and both the investment in MVP and the AFUDC will increase at a much greater rate until the pipeline is placed in service. Earnings after the pipeline is operational would be derived from the fees charged for transporting natural gas through the pipeline.

Regulatory Affairs

The Company continues to recover the costs of its infrastructure replacement program through its SAVE Plan. On June 30, 2016, the Company filed an application with the SCC for modification to its SAVE Plan and Rider. The original SAVE Plan and Rider were approved by the SCC through an order issued on August 29, 2012 and has been modified or amended each year since. The original SAVE Plan was designed to facilitate the accelerated replacement of the remaining bare steel and cast iron natural gas pipe by providing a mechanism for the Company to recover the related depreciation and expenses and return on rate base of the additional capital investment without the filing of a formal application for an increase in non-gas base rates. The projects included under the SAVE Plan will enhance the safety and reliability of the Company’s gas distribution system and reduce greenhouse emissions. The amendments in 2013 and 2014 added projects related to the replacement of bare steel and cast iron natural gas pipe in addition to two other major projects and the investment for related meter and regulator installations located on customer premises. In 2015, the SCC approved the Company's request to expand the authorized annual spending variance from 10% to 20% and set a 5% cumulative SAVE spending variance. This allows the Company to recover it's investment up to the new variance limits. The 2016 application included provisions to continue the ongoing pipeline renewal project with a focus on pre-1973 plastic pipe, the replacement of three natural gas custody transfer stations, the replacement of coated steel tubing services and related meter installations. The 2017 SAVE revenue requirement is approximately $4,000,000, representing an increase of almost $1,000,000 over the estimated 2016 SAVE Plan year. The additional SAVE Plan revenue as approved by the SCC will allow the Company to forgo a formal non-gas rate increase application at this time.

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

On March 25, 2015, the Company filed an application for approval of a Certificate of Public Convenience and Necessity with the SCC to include the remaining uncertificated portions of Franklin County into its authorized natural gas service territory. On July 30, 2015, the Company filed a Motion to Stay Proceeding requesting the SCC stay the application request pending further progress in the review of the MVP project by FERC and reconsider the application at a later date. The SCC granted the stay on July 31, 2015, which permitted the Company to continue its application request at a later date. The Company intends to pursue the application assuming FERC approval of the MVP project.


24


Critical Accounting Policies and Estimates

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

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

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

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

Revenue recognition - Regulated utility sales and transportation revenues are based upon rates approved by the SCC. The non-gas cost component of rates may not be changed without a formal rate application and corresponding authorization by the SCC in the form of a Commission order; however, the gas cost component of rates may be adjusted quarterly through the PGA mechanism. When the Company files a request for a non-gas rate increase, the SCC may allow the Company to place such rates into effect subject to refund pending a final order. Under these circumstances, the Company estimates the amount of increase it anticipates will be approved based on the best available information. The Company also bills customers through a SAVE Rider that provides a mechanism to recover on a prospective basis the costs associated with the Company’s expected investment related to the replacement of natural gas distribution pipe and other qualifying projects. As required under the provisions of FASB ASC No. 980, Regulated Operations, the Company recognizes billed revenue related to the SAVE projects to the extent such revenues have been earned under the provisions of the SAVE Plan.

The Company bills its regulated natural gas customers on a monthly cycle. The billing cycle for most customers does not coincide with the accounting periods used for financial reporting. The Company accrues estimated revenue for natural gas delivered to customers but not yet billed during the accounting period based on weather during the period and current and historical data. The financial statements include unbilled revenue of $1,004,061 and $1,001,418 as of September 30, 2016 and 2015, respectively.

Allowance for Doubtful Accounts - The Company evaluates the collectability of its accounts receivable balances based upon a variety of factors including loss history, level of delinquent account balances, collections on previously written off accounts and general economic conditions.

Pension and Postretirement Benefits - The Company offers a defined benefit pension plan (“pension plan”) and a postretirement medical and life insurance plan (“postretirement plan”) to eligible employees. The expenses and liabilities associated with these plans, as disclosed in Note 7 to the consolidated financial statements, are based on numerous assumptions and factors, including provisions of the plans, employee demographics, contributions made to the plan, return on plan assets and various actuarial calculations, assumptions and accounting requirements. In regard to the pension plan, specific factors include assumptions regarding the discount rate used in determining future benefit obligations, expected long-term rate of return on plan assets, compensation increases and life expectancies. Similarly, the postretirement medical plan also requires the estimation of many of the same factors as the pension plan in addition to assumptions regarding the rate of medical inflation and Medicare availability. Actual results may differ materially from the results expected from the actuarial assumptions due to changing economic conditions, differences in actual

25


returns on plan assets, different rates of medical inflation, volatility in interest rates and changes in life expectancy. Such differences may result in a material impact on the amount of expense recorded in future periods or the value of the obligations on the balance sheet.

In selecting the discount rate to be used in determining the benefit liability, the Company utilized the Citigroup yield curves which incorporate the rates of return on high-quality, fixed-income investments that corresponded to the length and timing of benefit streams expected under both the pension plan and postretirement plan. The Company used a discount rate of 3.42% and 3.33%, respectively, for valuing its pension plan liability and postretirement plan liability at September 30, 2016. These rates decreased significantly from the prior year with a decline of 0.80% and 0.82%, respectively. Interest rates moved even lower in 2016 keeping the discount rate depressed, thereby elevating the plan liabilities. The downward movement of the discount rate is evidenced by the 30-year Treasury rate, which decreased from 2.87% to 2.32% and the Moody's Aaa rate, which declined by a corresponding 0.56%. This reduction in discount rate, combined with other factors, increased the pension liability by more than $2,300,000 and the postretirement medical liability by approximately $3,150,000. In fiscal 2015, the most significant impact to the liabilities was attributed to the adoption of new mortality tables. On October 27, 2014, the Society of Actuaries released the final reports of the RP-2014 Mortality Tables and the Mortality Improvement Scale MP-2015. The new mortality tables, which were adopted by the Company for its September 30, 2015 defined benefit plan valuations, extend the assumed life expectancy of participants in the plans and provide a better measure of defined benefit plan liabilities. The impact of the change in assumed mortality increased the Company’s pension liability for the prior year by approximately 5% or nearly $1.3 million and the postretirement liability by approximately 7% or about $1 million. The Company used the RP-2014 Mortality Tables under the Projection Scale MP-2015 for the current year valuation.
 
Due to a variety of factors including volatility in the pension expense and corresponding liabilities, continued depressed interest rates and increasing life expectancies, the Company is implementing a risk reduction strategy for its pension plan. This risk reduction strategy included two components. The first offered a one-time lump sum pay out of the pension benefit to vested terminated employees who were not currently receiving payments under the pension plan. Approximately 63% of those vested, terminated employees elected to receive their pension in a lump sum resulting in a payout of $1,242,000 from plan assets in September 2016. These lump sum payments removed approximately $1,500,000 in pension plan liabilities and reduced the number of participants on which the Pension Benefit Guaranty Corporation ("PBGC") premiums are determined. The second was to take action on the pension plan similar to what was done with the postretirement plan back in 2000 by closing the pension plan to new employees effective January 1, 2017. Employees hired prior to that date will continue to accrue benefits. This "soft freeze" of the pension plan will not provide immediate relief to the Plan; but, pension liability growth will slow and eventually decline as no new participants will enter the pension plan. Likewise, pension expense will begin to decline in the future as less service cost is accrued due to fewer active employees in the pension plan. As more of the pension liability becomes fixed through retirements, management will begin to align the duration of the plan's liabilities with its assets in an effort to further reduce market volatility.

Following lower than expected returns in fiscal 2015, the returns on the related pension and postretirement assets for fiscal 2016 exceeded the corresponding long-term rate of return assumptions. Furthermore, the Company contributed an additional $1,000,000 over and above the previously projected $500,000 annual contribution to the pension plan. The combination of better than expected returns and higher funding levels were not enough to offset the increase in the pension benefit obligation associated with the reduction in the discount rate and the accretion of service and interest costs. As a result, the funded deficit for both the pension and postretirement plans increased during the period. Generally, the reduction in the discount rate would result in an increase in benefit plan expense for the following year; however, the combination of higher investment returns and contributions combined with the removal of the liabilities related to the lump sum payments will result in a small decrease in pension expense in fiscal 2017. The postretirement medical plan expense will increase as the plan experienced no beneficial offsets to reduce the impact of the lower discount rate.

Funded status - September 30, 2016
Pension
 
Postretirement
 
Total
  Benefit obligation
$
29,494,950

 
$
18,504,710

 
$
47,999,660

  Fair value of assets
23,113,057

 
11,122,783

 
34,235,840

  Funded status
$
(6,381,893
)
 
$
(7,381,927
)
 
$
(13,763,820
)

26


Funded status - September 30, 2015
Pension
 
Postretirement
 
Total
  Benefit obligation
$
27,167,621

 
$
15,355,668

 
$
42,523,289

  Fair value of assets
21,394,399

 
10,443,629

 
31,838,028

  Funded status
$
(5,773,222
)
 
$
(4,912,039
)
 
$
(10,685,261
)

The economic environment makes it difficult to project interest rates and future investment returns. During the prior year, management believed that market conditions supported an increase in interest rates during fiscal 2016. Twelve months later, interest rates have declined and the discount rate is nearly 1% lower than the same time last year. A similar scenario exists this year as current indications tend to support an increase in interest rates. However, any expectation or trend is purely speculation. If the economy shows indications of stronger growth, long-term interest rates could increase, thereby reducing the benefit liabilities. However, increasing interest rates could have a negative effect on investment returns, especially in the fixed income allocation, and any benefit obtained from reduced benefit liabilities could be mitigated by less than expected returns on assets. Conversely, if the economy stagnates or declines, interest rates could remain at lower levels or even drop, leading to an increase in the benefit liabilities. The Company annually evaluates the returns on its targeted investment allocation model. The investment policy as of the measurement date in September reflected a targeted allocation of 60% equity and 40% fixed income on the pension plan and a targeted allocation of 50% equity and 50% fixed income for the postretirement plan. As a result of this evaluation, the Company set its expected long-term annual return on pension assets at 7.00% and postretirement assets at 4.89% (net of income taxes) for fiscal 2017. These rates are consistent with the expected long-term rates in experienced during fiscal 2016. Management will continue to re-evaluate the return assumptions and adjust them as market conditions warrant.

In August 2014, the Highway and Transportation Funding Act of 2014 (“HATFA”) was signed into law, which included a provision to extend the interest rate corridors introduced in 2012 under the Moving Ahead for Progress in the 21st Century Act (“MAP-21”). MAP-21 provided temporary funding relief for defined benefit pension plans. The requirements of the Employee Retirement Income Security Act of 1974 (ERISA) and the Pension Protection Act of 2006 (PPA) subject defined benefit plans to minimum funding rules. As a result, when interest rates are low, pension plan liabilities increase thereby resulting in higher mandatory contributions to meet minimum funding obligations. MAP-21 provided funding relief by allowing pension plans to adjust the interest rates used in determining funding requirements so that they are within 10% of the average of interest rates for the 25-year period preceding the current year for funding calculations for 2013 to within 30% for funding periods beginning in 2016. HATFA extended the period of time that the 10% corridor instituted by MAP-21 may be used for funding calculations. Under HATFA, the 10% corridor extends through plan years that begin in 2017 and phases out to a 30% corridor in 2021 and later. HATFA significantly increases the effective interest rates used in determining funding requirements and could result in a deterioration of the pension plan funded status resulting in much greater funding requirements in the future as well as higher PBGC premiums paid by sponsors of pension plans to protect participants in the event of default by the employer. Management estimates that, under the provisions of HATFA, the Company will have no minimum funding requirements next year. Although HATFA and MAP-21 allow the Company some short-term funding relief, management expects to continue its pension funding plan by contributing at least the minimum annual pension contribution requirement or its expense level for subsequent years. The Company currently expects to contribute approximately $750,000 to its pension plan and $1,000,000 to its postretirement plan in fiscal 2017. The Company will continue to evaluate its benefit plan funding levels in light of funding requirements and ongoing investment returns and make adjustments, as necessary, to avoid benefit restrictions.

The following schedule reflects the sensitivity of pension costs to changes in certain actuarial assumptions, assuming that the other components of the calculation remain constant.
Actuarial Assumptions
Change in Assumption
 
Increase in Pension Cost
 
Increase in Projected Benefit Obligation
Discount rate
-0.25
 %
 
$
125,000

 
$
1,233,000

Rate of return on plan assets
-0.25
 %
 
57,000

 
N/A

Rate of increase in compensation
0.25
 %
 
56,000

 
314,000


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

27



Actuarial Assumptions
Change in Assumption
 
Increase (Decrease) in Postretirement Benefit Cost
 
Increase in Accumulated Postretirement Benefit Obligation
Discount rate
-0.25
 %
 
$
(19,000
)
 
$
787,000

Rate of return on plan assets
-0.25
 %
 
35,000

 
N/A

Medical claim cost increase
0.25
 %
 
22,000

 
756,000


Derivatives - The Company may hedge certain risks incurred in its operation through the use of derivative instruments. The Company applies the requirements of FASB ASC No. 815, Derivatives and Hedging, which requires the recognition of derivative instruments as assets or liabilities in the Company’s balance sheet at fair value. In most instances, fair value is based upon quoted futures prices for natural gas commodities and interest rate futures for interest rate swaps. Changes in the commodity and futures markets will impact the estimates of fair value in the future. Furthermore, the actual market value at the point of realization of the derivative may be significantly different from the values used in determining fair value in prior financial statements. The Company had no commodity or interest rate derivatives outstanding at September 30, 2016 and 2015.

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

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

Interest Rate Risk
The Company is exposed to market risk related to changes in interest rates associated with its borrowing activities. As of September 30, 2016, the Company has $14,556,785 outstanding under its variable rate line-of-credit with an average balance outstanding during the year of $9,991,078. The Company also had $3,396,200 outstanding under a 5-year variable rate term loan. A hypothetical 100 basis point increase in market interest rates applicable to the Company’s variable rate debt outstanding during the year would have resulted in an increase in interest expense for the current year of approximately $120,000. The Company’s remaining debt is at a fixed rate.

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

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

At September 30, 2016, the Company had no outstanding derivative instruments to hedge the price of natural gas. The Company had approximately 2,537,000 decatherms of gas in storage, including LNG, at an average price of $2.93 per decatherm compared to 2,418,000 decatherms at an average price of $3.38 per decatherm last year. The SCC currently allows for full recovery of prudent costs associated with natural gas purchases, and any additional costs or benefits associated with the settlement of derivative contracts and other price hedging techniques are passed through to customers when realized through the regulated natural gas PGA mechanism.
 

28



Item 8.
Financial Statements and Supplementary Data.

29



RGC Resources, Inc.
and Subsidiaries

Consolidated Financial Statements
for the Years Ended September 30, 2016, 2015
and 2014, and Report of Independent
Registered Public Accounting Firm

30



RGC RESOURCES, INC. AND SUBSIDIARIES
TABLE OF CONTENTS
 


31



brownedwardsa03.jpg




REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders
RGC Resources, Inc.
Roanoke, Virginia

We have audited the accompanying consolidated balance sheets of RGC Resources, Inc. and Subsidiaries (“the Company”) as of September 30, 2016 and 2015, and the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows for each of the years in the three-year period ended September 30, 2016. RGC Resources, Inc.’s management is responsible for these financial statements. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of RGC Resources, Inc. and Subsidiaries as of September 30, 2016 and 2015, and the consolidated results of its operations and its cash flows for each of the years in the three-year period ended September 30, 2016, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), RGC Resources, Inc. and Subsidiaries’ internal control over financial reporting as of September 30, 2016, based on criteria established in Internal Control-Integrated Framework - 2013 issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated December 8, 2016 expressed an unqualified opinion.
 
brownedwardssignaturea03.jpg
              CERTIFIED PUBLIC ACCOUNTANTS
1715 Pratt Drive, Suite 2700
Blacksburg, Virginia
December 8, 2016


32



RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AS OF SEPTEMBER 30, 2016 AND 2015
 
 
 
2016
 
2015
ASSETS
 
 
 
CURRENT ASSETS:
 
 
 
Cash and cash equivalents
$
643,252

 
$
985,234

Accounts receivable, net
3,478,983

 
3,196,573

Materials and supplies
824,139

 
968,108

Gas in storage
7,436,785

 
8,160,498

Prepaid income taxes
1,550,836

 
1,657,066

Other
1,548,329

 
1,182,343

Total current assets
15,482,324

 
16,149,822

UTILITY PROPERTY:
 
 
 
In service
185,577,286

 
168,033,032

Accumulated depreciation and amortization
(56,156,287
)
 
(53,307,079
)
In service, net
129,420,999

 
114,725,953

Construction work in progress
2,707,139

 
3,903,599

Utility plant, net
132,128,138

 
118,629,552

OTHER ASSETS:
 
 
 
Regulatory assets
14,332,451

 
10,923,243

Investment in unconsolidated affiliate
3,496,404

 

Other
113,532

 
144,577

Total other assets
17,942,387

 
11,067,820

TOTAL ASSETS
$
165,552,849

 
$
145,847,194


(Continued)

33


RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AS OF SEPTEMBER 30, 2016 AND 2015
 
 
 
2016
 
2015
LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
CURRENT LIABILITIES:
 
 
 
Borrowings under line-of-credit
$
14,556,785

 
$
9,340,997

Dividends payable
970,244

 
912,995

Accounts payable
5,345,575

 
5,141,677

Capital contributions payable
287,794

 

Customer credit balances
1,605,608

 
1,560,351

Customer deposits
1,627,105

 
1,579,441

Accrued expenses
3,194,255

 
2,766,097

Over-recovery of gas costs
909,687

 
1,901,426

Total current liabilities
28,497,053

 
23,202,984

LONG-TERM DEBT:
 
 
 
       Principal amount
33,896,200

 
30,500,000

       Less unamortized debt issuance costs
(260,149
)
 
(183,427
)
       Long-term debt net of unamortized debt issuance costs
33,636,051

 
30,316,573

DEFERRED CREDITS AND OTHER LIABILITIES:
 
 
 
Asset retirement obligations
5,682,556

 
5,295,868

Regulatory cost of retirement obligations
9,348,443

 
8,885,486

Benefit plan liabilities
13,763,820

 
10,685,261

Deferred income taxes
18,957,854

 
14,620,031

Total deferred credits and other liabilities
47,752,673

 
39,486,646

COMMITMENTS AND CONTINGENCIES (Note 10)

 

CAPITALIZATION:
 
 
 
Stockholders’ Equity:
 
 
 
Common Stock, $5 par value; authorized 10,000,000 shares; issued and outstanding 4,788,289 and 4,741,498 shares in 2016 and 2015, respectively
23,941,445

 
23,707,490

Preferred stock, no par; authorized 5,000,000 shares; no shares issued and outstanding in 2016 and 2015

 

Capital in excess of par value
9,509,548

 
8,647,669

Retained earnings
24,713,310

 
22,772,377

Accumulated other comprehensive loss
(2,497,231
)
 
(2,286,545
)
Total stockholders’ equity
55,667,072

 
52,840,991

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
$
165,552,849

 
$
145,847,194

(Concluded)
See notes to consolidated financial statements.

34



RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
YEARS ENDED SEPTEMBER 30, 2016, 2015 AND 2014
 
 
 
2016
 
2015
 
2014
OPERATING REVENUES:
 
 
 
 
 
Gas utilities
$
58,079,990

 
$
67,094,290

 
$
73,865,487

Other
983,301

 
1,095,317

 
1,150,647

Total operating revenues
59,063,291

 
68,189,607

 
75,016,134

COST OF SALES:
 
 
 
 
 
Gas utilities
27,009,330

 
37,437,315

 
45,091,274

Other
489,047

 
545,859

 
587,771

Total cost of sales
27,498,377

 
37,983,174

 
45,679,045

GROSS MARGIN
31,564,914

 
30,206,433

 
29,337,089

OTHER OPERATING EXPENSES:
 
 
 
 
 
Operations and maintenance
13,098,086

 
13,486,885

 
13,383,388

General taxes
1,663,126

 
1,606,421

 
1,560,386

Depreciation and amortization
5,591,610

 
5,106,935

 
4,711,447

Total other operating expenses
20,352,822

 
20,200,241

 
19,655,221

OPERATING INCOME
11,212,092

 
10,006,192

 
9,681,868

Equity in earnings of unconsolidated affiliate
152,864

 

 

Other expense, net
255,585

 
228,796

 
206,887

Interest expense
1,636,321

 
1,512,419

 
1,827,001

INCOME BEFORE INCOME TAXES
9,473,050

 
8,264,977

 
7,647,980

INCOME TAX EXPENSE
3,666,184

 
3,170,562

 
2,939,540

NET INCOME
$
5,806,866

 
$
5,094,415

 
$
4,708,440

EARNINGS PER COMMON SHARE:
 
 
 
 
 
Basic
$
1.22

 
$
1.08

 
$
1.00

Diluted
$
1.22

 
$
1.08

 
$
1.00

WEIGHTED AVERAGE SHARES OUTSTANDING:
 
 
 
 
 
Basic
4,766,604

 
4,728,210

 
4,715,478

Diluted
4,773,175

 
4,731,676

 
4,716,282

See notes to consolidated financial statements.

35



RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
YEARS ENDED SEPTEMBER 30, 2016, 2015 AND 2014
 
 
 
2016
 
2015
 
2014
NET INCOME
$
5,806,866

 
$
5,094,415

 
$
4,708,440

Other comprehensive income, net of tax:
 
 
 
 
 
Interest rate swaps

 

 
1,232,546

Defined benefit plans
(210,686
)
 
(1,147,219
)
 
(220,638
)
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
(210,686
)
 
(1,147,219
)
 
1,011,908

COMPREHENSIVE INCOME
$
5,596,180

 
$
3,947,196

 
$
5,720,348

See notes to consolidated financial statements.


36



RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
YEARS ENDED SEPTEMBER 30, 2016, 2015 AND 2014
 
 
 
Common
Stock
 
Capital in
Excess of
Par Value
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Total
Stockholders’
Equity
Balance - September 30, 2013
$
23,546,630

 
$
8,003,787

 
$
20,103,239

 
$
(2,151,234
)
 
$
49,502,422

Net income

 

 
4,708,440

 

 
4,708,440

Other comprehensive income

 

 

 
1,011,908

 
1,011,908

Stock option grants

 
75,310

 

 

 
75,310

Cash dividends declared ($0.74 per share)

 

 
(3,490,624
)
 

 
(3,490,624
)
Issuance of common stock (11,052 shares)
55,260

 
158,131

 

 

 
213,391

Balance - September 30, 2014
$
23,601,890

 
$
8,237,228

 
$
21,321,055

 
$
(1,139,326
)
 
$
52,020,847

Net income

 

 
5,094,415

 

 
5,094,415

Other comprehensive loss

 

 

 
(1,147,219
)
 
(1,147,219
)
Exercise of stock options (2,600 shares)
13,000

 
36,366

 

 

 
49,366

Stock option grants

 
83,640

 

 

 
83,640

Cash dividends declared ($0.77 per share)

 

 
(3,643,093
)
 

 
(3,643,093
)
Issuance of common stock (18,520 shares)
92,600

 
290,435

 

 

 
383,035

Balance - September 30, 2015
$
23,707,490

 
$
8,647,669

 
$
22,772,377

 
$
(2,286,545
)
 
$
52,840,991

Net income

 

 
5,806,866

 

 
5,806,866

Other comprehensive loss

 

 

 
(210,686
)
 
(210,686
)
Exercise of stock options (2,200 shares)
11,000

 
30,762

 

 

 
41,762

Stock option grants

 
64,640

 

 

 
64,640

Cash dividends declared ($0.81 per share)

 

 
(3,865,933
)
 

 
(3,865,933
)
Issuance of common stock (44,591 shares)
222,955

 
766,477

 

 

 
989,432

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

 
$
9,509,548

 
$
24,713,310

 
$
(2,497,231
)
 
$
55,667,072

See notes to consolidated financial statements.


37



RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED SEPTEMBER 30, 2016, 2015 AND 2014

 
 
2016
 
2015
 
2014
CASH FLOWS FROM OPERATING ACTIVITIES:
 
 
 
 
 
Net income
$
5,806,866

 
$
5,094,415

 
$
4,708,440

Adjustments to reconcile net income to net cash provided by operations:
 
 
 
 
 
Depreciation and amortization
5,709,525

 
5,219,893

 
4,838,062

Cost of retirement of utility plant, net
(449,201
)
 
(406,731
)
 
(452,834
)
Stock option grants
64,640

 
83,640

 
75,310

Equity in earnings of unconsolidated affiliate
(152,864
)
 

 

Deferred taxes and investment tax credits
4,466,954

 
2,416,841

 
859,788

Other noncash items, net
197,298

 
105,815

 
38,073

Changes in assets and liabilities which provided (used) cash:
 
 
 
 
 
Accounts receivable and customer deposits, net
(258,960
)
 
638,917

 
12,424

Inventories and gas in storage
867,682

 
3,168,056

 
(1,219,641
)
Over/under recovery of gas costs
(991,739
)
 
2,082,257

 
(1,208,134
)
Other assets
(398,864
)
 
(768,922
)
 
(306,744
)
Accounts payable, customer credit balances and accrued expenses, net
60,303

 
(873,354
)
 
(505,006
)
Total adjustments
9,114,774

 
11,666,412

 
2,131,298

Net cash provided by operating activities
14,921,640

 
16,760,827

 
6,839,738

CASH FLOWS FROM INVESTING ACTIVITIES:
 
 
 
 
 
Expenditures for utility property
(17,945,719
)
 
(13,780,356
)
 
(14,715,428
)
Investment in unconsolidated affiliate
(3,055,746
)
 

 

Proceeds from disposal of utility property
4,964

 
30,082

 
16,858

Net cash used in investing activities
(20,996,501
)
 
(13,750,274
)
 
(14,698,570
)
CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
 
 
Borrowings under line-of-credit
38,310,326

 
34,698,924

 
25,363,774

Repayments under line-of-credit
(33,094,539
)
 
(34,402,977
)
 
(16,318,724
)
Proceeds from issuance of unsecured notes
3,396,200

 

 
30,500,000

Retirement of note payable

 

 
(15,000,000
)
Retirement of long-term debt

 

 
(13,000,000
)
Early termination fees

 

 
(2,237,961
)
Debt issuance expenses
(101,619
)
 

 
(193,081
)
Proceeds from issuance of stock
1,031,194

 
432,401

 
213,391

Cash dividends paid
(3,808,683
)
 
(3,603,424
)
 
(3,465,034
)
Net cash provided by (used in) financing activities
5,732,879

 
(2,875,076
)
 
5,862,365

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
(341,982
)
 
135,477

 
(1,996,467
)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
985,234

 
849,757

 
2,846,224

CASH AND CASH EQUIVALENTS AT END OF YEAR
$
643,252

 
$
985,234

 
$
849,757

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
 
 
 
 
 
Cash paid (refunded) during the year for:
 
 
 
 
 
Interest
$
1,480,665

 
$
1,002,462

 
$
1,966,263

Income taxes
(907,000
)
 
1,266,573

 
2,387,000


See notes to consolidated financial statements.

38



RGC RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2016, 2015 AND 2014

1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation—RGC Resources, Inc. is an energy services company primarily engaged in the sale and distribution of natural gas. The consolidated financial statements include the accounts of RGC Resources, Inc. and its wholly owned subsidiaries (“Resources” or the “Company”): Roanoke Gas Company (“Roanoke Gas”); Diversified Energy Company; RGC Ventures of Virginia, Inc., operating as Application Resources and The Utility Consultants; and RGC Midstream, LLC. Roanoke Gas is a natural gas utility, which distributes and sells natural gas to approximately 59,600 residential, commercial and industrial customers within its service areas in Roanoke, Virginia and the surrounding localities. The Company’s business is seasonal in nature as a majority of natural gas sales are for space heating during the winter season. Roanoke Gas is regulated by the Virginia State Corporation Commission (“SCC” or “Virginia Commission”). RGC Ventures of Virginia, Inc. was dissolved in 2016 after Application Resources, which provided information system services to software providers in the utility industry, ceased operations in 2016, and The Utility Consultants, which provided regulatory consulting services to other utilities, ceased operations in 2015. RGC Midstream, LLC is a wholly-owned subsidiary created in 2015 to invest in the Mountain Valley pipeline project. Diversified Energy Company is currently inactive.
The Company follows accounting and reporting standards established by the Financial Accounting Standards Board (“FASB”) and the Secu