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EX-32.2 - EXHIBIT 32.2 - RGC RESOURCES INCrgco-ex322x9302017xq4.htm
EX-32.1 - EXHIBIT 32.1 - RGC RESOURCES INCrgco-ex321x9302017xq4.htm
EX-31.2 - EXHIBIT 31.2 - RGC RESOURCES INCrgco-ex312x9302017xq4.htm
EX-31.1 - EXHIBIT 31.1 - RGC RESOURCES INCrgco-ex311x9302017xq4.htm
EX-23 - EXHIBIT 23 - RGC RESOURCES INCrgco-ex23x9302017xq4.htm
EX-21 - EXHIBIT 21 - RGC RESOURCES INCrgco-ex21x9302017xq4.htm
EX-13 - EXHIBIT 13 - RGC RESOURCES INCex132017annualreportfina.htm
EX-10.O - EXHIBIT 10.O - RGC RESOURCES INCex10o-saltvillegasstoragec.htm
EX-10.II - EXHIBIT 10.II - RGC RESOURCES INCex10ii-amendedandrestatedr.htm
EX-10.F - EXHIBIT 10.F - RGC RESOURCES INCex10f-columbiagastransmiss.htm
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended September 30, 2017
Commission file number 000-26591
RGC RESOURCES, INC.
(Exact name of registrant as specified in its charter)
Virginia
 
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:
Title of Each Class
 
Name of Each Exchange on
Which Registered
Common Stock, $5 Par Value
 
NASDAQ Global Market

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act.        Yes  ¨  No  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, 2017. $147,136,528
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the last practicable date.
Class
 
Outstanding at November 30, 2017
COMMON STOCK, $5 PAR VALUE
 
7,250,093 SHARES
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the RGC Resources, Inc. Proxy Statement for the 2018 Annual Meeting of Shareholders are incorporated by reference into Part III hereof.



TABLE OF CONTENTS
 
 
 
 
 
 
 
 
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.
 
 
 
 
 
 
 
Item 16.
 
 
 
 
 
 
 
 




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

2


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 less than 2% of consolidated revenues.

In July 2015, the Company formed RGC Midstream, LLC, a limited liability company established for the purpose of becoming a 1% investor in Mountain Valley Pipeline, LLC. Mountain Valley Pipeline, LLC was created for the purpose of constructing a natural gas pipeline in West Virginia and Virginia. Additional information regarding this investment is provided under Note 4 of the Company's annual consolidated financial statements and under the Equity Investment in Mountain Valley Pipeline section of Item 7.

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

Diversified Energy Company currently has no active operations.

Services
Roanoke Gas maintains an integrated natural gas distribution system to deliver natural gas purchased from suppliers to residential, commercial and industrial users in its service territory. The schedule below is a summary of customers, delivered volumes (expressed in decatherms), revenues and margin as a percentage of the total for each category: 
 
 
2017
 
 
Customers
 
Volume
 
Revenue
 
Margin
Residential
 
91.2
%
 
37
%
 
57
%
 
61
%
Commercial
 
8.7
%
 
31
%
 
33
%
 
25
%
Industrial
 
0.1
%
 
32
%
 
7
%
 
10
%
Other Utility
 
0.0
%
 
0
%
 
1
%
 
2
%
Other Non-Utility
 
0.0
%
 
0
%
 
2
%
 
2
%
Total Percent
 
100.0
%
 
100
%
 
100
%
 
100
%
Total Value
 
59,847

 
8,562,582

 
$
62,296,870

 
$
32,809,157

 
 
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


3


 
 
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


Roanoke Gas’ regulated natural gas distribution business accounted for approximately 98% of Resources total revenues for fiscal years ending September 30, 2017, 2016 and 2015. The tables above indicates that residential customers represent over 91% of the Company’s customer total; however, they represent less than 50% of the total gas volumes delivered and more than half of the Company’s consolidated revenues and margin. Industrial customers include primarily transportation customers that purchase their natural gas requirements directly from a supplier other than the Company and utilize Roanoke Gas’ natural gas distribution system for delivery to their operations. Most of the revenue billed for these customers relates only to transportation service, and not to the purchase of natural gas, causing total revenues generated by these deliveries to be approximately 7% of total revenues, even though they represent 32% of total natural gas deliveries for the year ended September 30, 2017 and approximately 10% to 11% of gross margin for each of the years presented.

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

The Company’s residential and commercial sales are seasonal and temperature-sensitive as the majority of the gas sold by Roanoke Gas to these customers is used for heating. For the fiscal year ended September 30, 2017, approximately 65% of the Company’s total DTH of natural gas deliveries and 73% of the residential and commercial deliveries were made in the five-month period of November through March. These percentages are comparable to the prior year but lower than fiscal 2015 due to lower volumes attributable to a much warmer heating season in fiscal 2016 and 2017. Total natural gas deliveries were 8.6 million DTH, 8.8 million DTH and 9.9 million DTH in fiscal 2017, 2016 and 2015, respectively.

Suppliers
Roanoke Gas relies on multiple interstate pipelines including those operated by Columbia Gas Transmission Corporation, LLC and Columbia Gulf Transmission Corporation, LLC (together “Columbia”), and East Tennessee Natural Gas, LLC (“East Tennessee”), Tennessee Gas Pipeline, Midwestern Gas Transmission Company and Saltville Gas Storage Company, LLC to transport natural gas from the production and storage fields to Roanoke Gas’ distribution system. Roanoke Gas is directly served by two pipelines, Columbia and East Tennessee. Columbia historically has delivered approximately 60% of the Company’s gas supply, while East Tennessee delivers the balance of the Company’s requirements. The rates paid for natural gas transportation and storage services purchased from the interstate pipeline companies are established by tariffs approved by the Federal Energy Regulatory Commission ("FERC"). These tariffs contain flexible pricing provisions, which, in some instances, authorize these transporters to reduce rates and charges to meet price competition. The current pipeline contracts expire at various times from 2018 to 2027. The Company anticipates being able to renew these contracts or enter into other contracts to meet customers’ continued demand for natural gas.

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


4


The Company uses multi-year contracts to meet its natural gas supply needs. The Company currently contracts with Sequent Energy Management, L.P. to manage its pipeline transportation, storage rights, gas supply inventories and deliveries and serve as the primary supplier of natural gas for Roanoke Gas. Natural gas purchased under the asset management agreement is priced at indexed-based market prices as reported in major industry pricing publications. The Company is currently in the process of soliciting proposals for a new asset management agreement to replace the current agreement which expires March 31, 2018.

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

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

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

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

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

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

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

Employees
At September 30, 2017, Resources had 106 full-time employees and 109 total employees. As of that date, 30 employees, or 28% of the Company’s full-time employees, belonged to the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied-Industrial International Union, Local No. 515 and were represented under a collective bargaining agreement. The union has been in place at the Company since 1952. The current collective bargaining agreement will expire on July 31, 2020. Management maintains an amicable relationship with the union.

5



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

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

OPERATIONAL RISKS

Availability of adequate and reliable pipeline capacity.

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

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

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

Investment in Mountain Valley Pipeline.

The success of the Company's investment in Mountain Valley Pipeline, LLC (the "LLC") is predicated on several key factors including but not limited to the ability of all investors to meet their capital calls when due, the timely state and federal approvals and completing the construction of the pipeline within the targeted time frame and budget. Any significant delay, cost over-run or the failure to receive the requisite approvals on a timely basis, or at all, could have a significant effect on the Company's earnings and financial position.

In addition, there are also numerous risks facing the LLC over time, which in turn could adversely affect the Company's earnings and financial performance through its 1% investment. The LLC's ability to complete construction of, and capital improvement to, facilities on schedule and within budget may be adversely affected by escalating costs for materials and labor and regulatory compliance, inability to obtain or renew necessary licenses,

6


rights-of-way, permits or other approvals on acceptable terms or on schedule, disputes involving contractors, labor organizations, land owners, governmental entities, environmental groups, Native American and aboriginal groups, and other third parties, negative publicity, transmission interconnection issues, and other factors. If any development project or construction or capital improvement project is not completed, is delayed or is subject to cost overruns, certain associated costs may not be approved for recovery or be recovered through regulatory mechanisms that may otherwise be available, and the LLC could become obligated to make delay or termination payments or become obligated for other contractual damages, could experience the loss of tax credits or tax incentives, or delayed or diminished returns, and could be required to write-off all or a portion of its investment in the project. Any of these events could have a material adverse effect on the LLC’s business, financial condition, results of operations and prospects. The LLC may face risks related to project siting, financing, construction, permitting, governmental approvals and the negotiation of project development agreements that may impede its development and operating activities. The LLC must periodically apply for licenses and permits from various local, state, federal and other regulatory authorities and abide by their respective conditions. Should the LLC be unsuccessful in obtaining necessary licenses or permits on acceptable terms, should there be a delay in obtaining or renewing necessary licenses or permits or should regulatory authorities initiate any associated investigations or enforcement actions or impose related penalties or disallowances on the LLC, the LLC’s business, financial condition, results of operations and prospects could be materially adversely affected. Any failure to negotiate successful project development agreements for new facilities with third parties could have similar results.

The LLC’s gas infrastructure facilities and other facilities are subject to many operational risks. Operational risks could result in, among other things, lost revenues due to prolonged outages, increased expenses due to monetary penalties or fines for compliance failures, liability to third parties for property and personal injury damage, a failure to perform under applicable sales agreements and associated loss of revenues from terminated agreements or liability for liquidated damages under continuing agreements. The consequences of these risks could have a material adverse effect on the LLC’s business, financial condition, results of operations and prospects. Uncertainties and risks inherent in operating and maintaining the LLC's facilities include, but are not limited to, risks associated with facility start-up operations, such as whether the facility will achieve projected operating performance on schedule and otherwise as planned. The LLC’s business, financial condition, results of operations and prospects can be materially adversely affected by weather conditions, including, but not limited to, the impact of severe weather. Threats of terrorism and catastrophic events that could result from terrorism, cyber-attacks, or individuals and/or groups attempting to disrupt the LLC’s business, or the businesses of third parties, may materially adversely affect the LLC’s business, financial condition, results of operations and prospects.
    
Supply disruptions due to weather or other forces.

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

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

A cyber-security incident on the Company’s information systems could result in corruption of the Company’s financial information or the unauthorized release of confidential customer, employee or vendor information or result in the interruption of our ability to provide natural gas to our customer or compromise the safety of our distribution, transmission and storage systems. The Company takes reasonable precautions to safeguard its computer systems from attack; however, there are no guarantees that Company processes will adequately protect against unauthorized access to data. In the event of a successful attack, the Company could be exposed to material financial and reputational risks, possible disruptions in natural gas deliveries or a compromise of the safety of the natural gas distribution system, as well as be exposed to claims by persons harmed by such an attack and the attack could also materially increase the costs we incur to protect against such risks.

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

A weak or poorly performing economy can negatively affect the Company’s profitability. An economic downturn can result in loss of commercial and industrial customers due to plant closings, a loss of residential customers as well as slow or declining growth in new customer additions, all of which would result in reduced sales volumes and lower revenues. An economic downturn could also result in rising unemployment and other factors that could lead to a loss of customers and an increase in customer delinquencies and bad debt expense.

7


Inability to attract and retain professional and technical employees.

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

Geographic concentration of business activities.

The Company's business activities are concentrated in the Roanoke Valley. Changes in the local economy, politics, regulations and weather patterns could negatively impact the Company's existing customer base, leading to declining usage patterns and financial condition of customers, both of which could adversely affect earnings.

Volatility in the price and availability of natural gas.

Natural gas purchases represent the single largest expense of the Company. Even with increasing demand from other areas, including electric generation, natural gas prices are currently expected to remain stable in the near term, although there can be no guarantee to that effect. If demand for natural gas increases at a rate in excess of current expectations, natural gas prices could face upward pressure. Increasing natural gas prices could result in declining sales as well as increases in bad debt expense.

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

Competition from other energy providers.

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

Inability to complete necessary or desirable pipeline expansion or infrastructure development projects.

In order to serve new customers or expand service to existing customers, the Company needs to maintain, expand or upgrade its distribution, transmission and/or storage infrastructure, including new pipeline installation. Various factors may prevent or delay the completion of such projects or make them more costly, such as the inability to obtain required approval from local, state and/or federal regulatory and governmental bodies, public opposition to the projects, inability to obtain adequate financing, competition for labor and materials, construction delays, cost overruns, and an inability to negotiate acceptable agreements relating to rights-of-way, construction or other material development components. As a result, the Company may not be able to adequately serve existing customers or expand its distribution system to support customer growth, including any potential customer growth as a result of the construction of the MVP, which would negatively impact earnings.


REGULATORY RISKS

Increased compliance and pipeline safety requirements and fines.

The Company is committed to the safe and reliable delivery of natural gas to its customers. Working in concert with this commitment are numerous federal and state laws and regulations. Failure to comply with these laws and

8


regulations could result in the levy of significant fines. There are inherent risks that may be beyond the Company’s control, including third party actions, which could result in damage to pipeline facilities, injury and even death. Such incidents could subject the Company to lawsuits, large fines, increased scrutiny and loss of customers, all of which could have a significant effect on the Company’s financial position and results of operations.

Environmental laws or regulations.

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

Regulatory actions or failure to obtain timely rate relief.

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


FINANCIAL RISKS

Access to capital to maintain liquidity.

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

Insurance coverage may not be sufficient.

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

Post-retirement benefits and related funding of obligations.

The costs of providing defined benefit pension and retiree medical plans are dependent on a number of factors such as the rates of return on plan assets, discount rates used in determining plan liabilities, the level of interest rates used to measure the required minimum funding levels of the plan, future government regulation, changes in life expectancy, and required or voluntary contributions made to the plan. Changes in actuarial assumptions and differences between the assumptions and actual results, as well as a significant decline in the value of investments that fund these plans, if not offset or mitigated by a decline in plan liabilities, could increase the expense of these plans and require significant

9


additional funding. Both funding obligations and increased expense could have a material impact on the Company's financial position, results of operation and cash flows.

Failure to comply with debt covenant requirements.

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

Item 1B.
Unresolved Staff Comments.

Not applicable.

Item 2.
Properties.

Included in “Utility Plant” on the Company’s consolidated balance sheet are storage plant, transmission plant, distribution plant and general plant of Roanoke Gas as categorized by natural gas utilities. The Company has approximately 1,135 miles of transmission and distribution pipeline with transmission and distribution plant representing more than 87% of the total investment in plant. The transmission and distribution pipelines are located on or under public roads and highways or private property for which the Company has obtained the legal authorization and rights to operate.
Roanoke Gas owns and operates eight metering stations through which it measures and regulates the gas being delivered by its suppliers. These stations are located at various points throughout the Company’s distribution system.
Roanoke Gas also owns a liquefied natural gas storage facility located in Botetourt County that has the capacity to store up to 220,000 DTH of natural gas.
The Company’s executive, accounting and business offices, along with its maintenance and service departments, are located on Kimball Avenue in Roanoke, Virginia.
Although the Company considers its present properties to be adequate, management continues to evaluate the adequacy of its current facilities as additional needs arise.
 
Item 3.
Legal Proceedings.

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

Not applicable.
 

10


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 depends 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, 2017
 
High
 
Low
 
Declared
 First Quarter
 
$
20.04

 
$
15.81

 
$
0.1450

 Second Quarter
 
22.51

 
16.60

 
0.1450

 Third Quarter
 
31.99

 
21.00

 
0.1450

 Fourth Quarter
 
29.95

 
23.65

 
0.1450

 
 
 
 
 
 
 
Year Ending September 30, 2016
 
 
 
 
 
 
 First Quarter
 
$
15.96

 
$
13.37

 
$
0.1350

 Second Quarter
 
15.59

 
13.77

 
0.1350

 Third Quarter
 
17.33

 
14.30

 
0.1350

 Fourth Quarter
 
16.73

 
14.88

 
0.1350

As of November 24, 2017, there were 1,159 holders of record of the Company’s common stock. This number does not include all beneficial owners of common stock who hold their shares in “street name.”

Comparisons of Cumulative Total Shareholder Returns
The following performance graph compares the Company’s total shareholder return from September 30, 2012 through September 30, 2017 with the Dow Jones US Utility Index, a utility based index, and the Standard & Poor’s 500 Stock Index (S&P 500 Index), a broad market index.
The graph below reflects the value of a hypothetical investment of $100 made September 30, 2012 in the Company’s common stock and in each index as of September 30, 2017, assuming the reinvestment of all dividends. Historical stock price performance as reflected on the graph is not indicative of future price performance. The total value at the end of the five years was $300 for the Company’s common stock, $180 for the Dow Jones US Utilities Index and $194 for the S&P 500 Index.





11


rgco-9302_chartx25348.jpg
A summary of the Company’s equity compensation plans follows as of September 30, 2017:
 
 
(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
 
101,575

 
$14.31
 
576,018

Equity compensation plans not approved by security holders
 

 

 

Total
 
101,575

 
$14.31
 
576,018

 

12



Item 6.
Selected Financial Data.

 
 
Year Ending September 30,
 
 
2017
 
2016
 
2015
 
2014
 
2013
 
 
 
 
 
 
 
 
 
 
 
Operating Revenues
 
$
62,296,870

 
$
59,063,291

 
$
68,189,607

 
$
75,016,134

 
$
63,205,666

Gross Margin
 
32,809,157

 
31,564,914

 
30,206,433

 
29,337,089

 
27,602,891

Operating Income
 
11,666,309

 
11,212,092

 
10,006,192

 
9,681,868

 
8,795,055

Net Income
 
6,232,865

 
5,806,866

 
5,094,415

 
4,708,440

 
4,262,052

Basic Earnings Per Share (1)
 
$
0.86

 
$
0.81

 
$
0.72

 
$
0.67

 
$
0.60

Cash Dividends Declared Per Share (1)
 
$
0.58

 
$
0.54

 
$
0.51

 
$
0.49

 
$
1.15

Book Value Per Share (1)
 
$
8.29

 
$
7.75

 
$
7.43

 
$
7.35

 
$
7.01

Average Shares Outstanding (1)
 
7,218,686

 
7,149,906

 
7,092,315

 
7,073,218

 
7,048,091

Total Assets
 
$
183,135,071

 
$
165,552,849

 
$
145,847,194

 
$
137,423,321

 
$
121,658,797

 
 
 
 
 
 
 
 
 
 
 
Long-Term Debt (Less Unamortized Debt Expense)
 
$
61,312,011

 
$
33,636,051

 
$
30,316,573

 
$
30,306,919

 
$
12,984,169

Stockholders' Equity
 
60,040,472

 
55,667,072

 
52,840,991

 
52,020,847

 
49,502,422

Shares Outstanding at Sept. 30(1)
 
7,240,846

 
7,182,434

 
7,112,247

 
7,080,567

 
7,063,989


(1)Total shares and per share amounts for the prior years were revised to reflect the three-for-two stock split.

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

Forward-Looking Statements

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

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





13


Overview

Resources is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately 59,800 residential, commercial and industrial customers in Roanoke, Virginia, and the surrounding localities, through its Roanoke Gas Company (“Roanoke Gas”) subsidiary. Roanoke Gas also provides certain unregulated services. Resources formed a wholly-owned subsidiary, RGC Midstream, LLC ("Midstream"), to invest in the Mountain Valley Pipeline, LLC (the "LLC"). Midstream is a 1% member in the LLC. More information is provided under the Equity Investment in Mountain Valley Pipeline section below. The unregulated operations represent less than 2% of revenues and margins of Resources.

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

The Company is committed to the safe and reliable delivery of natural gas to its customers. Since 1991, the Company has placed an emphasis on the modernization of its distribution system through the renewal and replacement of its cast iron and bare steel natural gas distribution pipelines and other system improvements. The Company completed the replacement of all cast iron and bare steel pipe in the first quarter of fiscal 2017 and is continuing its renewal program with the replacement of first generation, pre-1973 plastic pipe to be completed over the next few years.

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

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

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

The Company's approved billing rates include a component designed to allow for the recovery of the cost of natural gas used by its customers. The cost of natural gas is considered a pass-through cost and is independent of the non-gas rates of the Company. This rate component, referred to as the PGA clause, allows the Company to pass along to its customers increases and decreases in natural gas costs incurred by its regulated operations. On a quarterly basis, the Company files a PGA rate adjustment request with the SCC to adjust the gas cost component of its rates up or down depending on projected price and activity. Once administrative approval is received, the Company adjusts the gas cost component of its rates to reflect the approved amount. As actual costs will differ from the projections used in establishing the PGA rate, the Company will either over-recover or under-recover its actual gas costs during the period. The difference between actual costs incurred and costs recovered through the application of the PGA is recorded as a regulatory asset or liability. At the end of the annual deferral period, the balance is amortized over an ensuing 12-month period as amounts are reflected in customer billings.

14



The WNA reduces the volatility in earnings due to the variability in temperatures during the heating season. The WNA is based on the most recent 30-year temperature average and provides the Company with a level of earnings protection when weather is warmer than normal and provides its customers with price protection when the weather is colder than normal. The WNA allows the Company to recover from its customers the lost margin (excluding gas costs) from the impact of weather that is warmer than normal and correspondingly requires the Company to refund the excess margin earned for weather that is colder than normal. The WNA year runs from April through March. Any billings or refunds related to the WNA are completed following the end of the WNA year. For the fiscal year ended September 30, 2017, the Company recorded $1,839,000 in additional revenue from the WNA for weather that was approximately 18% warmer than normal. During the fiscal year ended September 30, 2016, the Company recorded $1,318,000 in additional revenue for the WNA for weather that was approximately 13% warmer than normal. During the fiscal year ended September 30, 2015, the Company reduced revenue by $609,000 due to the WNA for weather that was approximately 6.5% colder than normal. As normal weather is based on the most recent 30-year temperature average, the heating degree days used to determine normal will change each year as a new year is added to the 30-year period and the oldest year is removed. As a result of two consecutive years of significantly warmer winters, the number of heating degree days that defines normal has declined from 4,000 in fiscal 2013 to 3,959 in fiscal 2017. The Company's rates are designed on 4,000 heating degree days from its last non-gas rate filing; however, the WNA model is recovering on the current normal of 3,959 heating degree days, or about 1% less than for what the rates were designed to recover. The 30-year normal will not be reset in base rates until the next time the Company files for a non-gas rate increase, so until such time as normal is reset, the WNA may slightly under-recover for warmer weather.

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

During times of rising gas costs and rising inventory levels, the Company recognizes ICC revenues to offset higher financing costs associated with higher inventory balances. Conversely, during times of decreasing gas costs and declining inventory balances, the Company recognizes less carrying cost revenue as financing costs are lower. In addition, ICC revenues are impacted by changes in the weighted-average cost of capital. Although, the cost balance of storage gas at September 30, 2017 was higher than last year due to higher prices during the summer storage refill, the average balance during the year, which is the base used to calculate ICC revenues, was lower by 5%. Furthermore, increased borrowing levels in fiscal 2017 reduced the overall weighted average cost of capital, or ICC factor, as the debt to equity ratio increased. The combination of lower average storage balances and a reduction in the ICC factor resulted in a nearly $63,000 decline in ICC revenues. This trend in lower average storage balances and ICC factor in fiscal 2016 resulted in a $182,000 decline in ICC revenues from fiscal 2015. Based on the current storage balances and natural gas futures, the average dollar balance of gas in storage may increase next year; however, an expected increase in debt will potentially reduce the ICC factor and corresponding ICC revenues.

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

The Company’s non-gas rates are designed to allow for the recovery of non-gas related expenses and provide a reasonable return to shareholders. These rates are determined based on the filing of a formal rate application with the SCC utilizing historical information including investment in natural gas facilities. Generally, investments related to extending service to new customers are recovered through the additional revenues generated by the non-gas rates currently in place. The investment in replacing and upgrading existing infrastructure is not recoverable until a formal rate application is made to include the additional investment, and new non-gas rates are approved. The SAVE Plan and Rider provides the Company with the ability to recover costs related to these investments on a prospective basis rather than on a historical basis. The SAVE Plan provides a mechanism to recover the related depreciation and expenses and provide a return on rate base of the additional capital investments related to improving the Company's infrastructure until such time a formal rate application is filed to incorporate this investment in the Company's non-gas rates. As the Company has not filed for an increase in non-gas rates since 2013, SAVE Plan revenues have increased each year corresponding to the level of SAVE qualifying capital investment. The Company recognized approximately $3,813,000,

15


$2,538,000 and $1,308,000 in SAVE Plan revenues for years ended September 30, 2017, 2016 and 2015, respectively. SAVE revenues will be included as part of the non-gas base rates the next time the Company files for a non-gas rate increase. Additional information regarding the SAVE Rider is provided under the Regulatory Affairs section.

The economic environment has a direct correlation with business and industrial production, customer growth and natural gas utilization. The local economy appears relatively stable and should continue to improve absent a major economic setback on a local, regional or national level.

Results of Operations

Fiscal Year 2017 Compared with Fiscal Year 2016

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

Operating Revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended September 30,
2017
 
2016
 
Increase
 
Percentage
Gas Utilities
$
61,252,015

 
$
58,079,990

 
$
3,172,025

 
5
%
Other
1,044,855

 
983,301

 
61,554

 
6
%
Total Operating Revenues
$
62,296,870

 
$
59,063,291

 
$
3,233,579

 
5
%

Delivered Volumes
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended September 30,
2017
 
2016
 
Decrease
 
Percentage
Regulated Natural Gas (DTH)
 
 
 
 
 
 
 
 Residential and Commercial
5,840,883

 
6,088,108

 
(247,225
)
 
(4
)%
 Transportation and Interruptible
2,721,699

 
2,754,497

 
(32,798
)
 
(1
)%
 Total Delivered Volumes
8,562,582

 
8,842,605

 
(280,023
)
 
(3
)%
Heating Degree Days (Unofficial)
3,250

 
3,484

 
(234
)
 
(7
)%

Total gas utility operating revenues for the year ended September 30, 2017 increased by 5% from the year ended September 30, 2016 primarily due to higher gas costs and increased SAVE Plan revenues more than offsetting a reduction in natural gas deliveries. The average commodity price of natural gas increased by 11% per decatherm sold due to higher commodity prices. Delivered volumes declined primarily due to weather, as reflected in the lower residential and commercial volumes. Industrial consumption was nearly unchanged. Residential and commercial deliveries tend to be more weather sensitive as reflected by a 4% decline in volumes on 7% fewer heating degree days. Transportation and interruptible volumes, which are primarily driven by production activities rather than weather, decreased by 1%. Other revenues experienced a 6% increase.

Gross Margin
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended September 30,
2017
 
2016
 
Increase / (Decrease)
 
Percentage
Gas Utility
$
32,332,390

 
$
31,070,660

 
$
1,261,730

 
4
 %
Other
476,767

 
494,254

 
(17,487
)
 
(4
)%
Total Gross Margin
$
32,809,157

 
$
31,564,914

 
$
1,244,243

 
4
 %

Regulated natural gas margins from utility operations increased by 4% from fiscal 2016, primarily as a result of increasing SAVE Plan revenues. Total SAVE Plan revenues increased by $1,275,000 as the Company continues to invest in qualified infrastructure projects. Since January 2014, the Company has invested more than $32,000,000 in qualified SAVE projects with fiscal 2018 projected to add an additional $8,000,000 in SAVE investment. Volumetric

16


margin declined by nearly $526,000 due to a reduction in total volumes delivered. Residential and commercial volumes declined due to warmer weather compared to the prior year. Interruptible and transportation volumes were nearly unchanged reflecting only a small decline. The impact of the warmer weather on volumetric margin was offset by the WNA, which provided approximately $522,000 in revenues. As discussed in more detail above, the WNA allowed the Company to recognize margin related to those natural gas volumes not delivered due to the warmer weather. ICC revenues declined by $63,000 due to lower average gas storage balance and a lower ICC factor.

Other margins, consisting of non-utility related services, decreased by $17,487 despite higher revenues. Higher operating costs made margin tighter in the non-utility services part of operations. The service contracts which generate the majority of the non-utility related revenues are subject to annual or semi-annual renewal provisions and the potential exists that these contracts may not be renewed or extended, which could negatively impact future revenues and margins.

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

 
Twelve Months Ended September 30,
 
 
 
2017
 
2016
 
Increase / (Decrease)
Customer Base Charge
$
12,412,753

 
$
12,364,811

 
$
47,942

SAVE Plan
3,813,043

 
2,538,055

 
1,274,988

Volumetric
13,573,704

 
14,099,214

 
(525,510
)
WNA
1,839,454

 
1,317,800

 
521,654

Carrying Cost
588,624

 
651,492

 
(62,868
)
Other
104,812

 
99,288

 
5,524

Total
$
32,332,390

 
$
31,070,660

 
$
1,261,730


Operations and Maintenance Expense - Operations and maintenance expenses, in total, were nearly unchanged reflecting a net increase of $1,955 for the year. Expense declines in certain areas were offset by higher expenses in other categories. The most significant offsets pertain to labor, contracted services, employee benefit costs, corporate insurance, capitalized overheads and bad debt expense. Total operation and maintenance labor declined by $158,000 primarily as a result of the outsourcing of the Company's customer service, billing and credit and collection functions. Management made a strategic decision to transfer these operations to a provider that has significant experience in serving utility clients. In July 2017, the Company transitioned to the service provider, resulting in a reduction of 18 employees. The personnel savings from this work force reduction was offset by the fees paid to the service provider. Employee benefit costs increased by $195,000 due to higher health insurance premiums and higher actuarial determined costs on the post-retirement medical plan. The Company realized a $251,000 reduction in corporate property and liability insurance premiums due to favorable insurance renewals. Capitalized overheads, which include general and administrative, payroll and engineering costs, decreased by $179,000 from fiscal 2016 primarily due to a reduction in the general and administrative overhead rate and less LNG overheads due to a 46% reduction in the amount of LNG produced. The reduction in the LNG production was timing related as the facility was at near full capacity at September 30, 2016, while the balance at September 30, 2017 was at 79% capacity. Legal and other professional expenses were also lower due to reduced activity in those areas.

General Taxes - General taxes increased $122,944, or 7%, primarily due to higher property taxes associated with increases in utility property.
 
Depreciation - Depreciation expense increased by $665,127, or 12%, corresponding to 10% increase in utility plant investment.

Equity in Earnings of Unconsolidated Affiliate - The equity in earnings of the Mountain Valley Pipeline investment increased by $268,782 primarily consisting of the allowance for funds used during construction ("AFUDC") related to the increasing investment in the project. The investment in Mountain Valley Pipeline and the related AFUDC earnings are discussed further under the Equity Investment in Mountain Valley Pipeline section below.

Other Expense - Other expense, net, decreased by $123,139, or 48%, primarily due to lower pipeline assessments and charitable commitments.

17



Interest Expense - Total interest expense increased by $280,933, or 17%, due to a 24% increase in the average total debt outstanding. The combination of Mountain Valley Pipeline investments and the level of capital expenditures during fiscal 2017 generated the higher debt balances. The average interest rate declined during the current year from 3.76% to 3.56%. The $7,000,000 unsecured note issued on November 1, 2016 had a variable rate that ranged from 1.43% to 2.14% during the year, which was lower than the average rate on the outstanding debt during fiscal 2016.

Income Taxes - Income tax expense increased by $139,206, or 4%, on higher pre-tax earnings. The effective tax rate was 37.9% for fiscal 2017 compared to 38.7% for fiscal 2016. The lower effective tax rate was attributable to the exercise of stock options during the year, which resulted in additional tax deductions above the amount recorded at grant date due to the significant appreciation in stock price over the grant price.

Net Income and Dividends - Net income for fiscal 2017 was $6,232,865 compared to $5,806,866 for fiscal 2016. Basic and diluted earnings per share were $0.86 in fiscal 2017 compared to $0.81 in fiscal 2016. Dividends declared per share of common stock were $0.58 in fiscal 2017 compared to $0.54 in fiscal 2016. All per share amounts were restated for the three-for-two stock split effective March 1, 2017 as described in Note 2 to the Consolidated Financial Statements.
    
Fiscal Year 2016 Compared with Fiscal Year 2015

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

Operating Revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended September 30,
2016
 
2015
 
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 warmer weather, as reflected in the lower residential and commercial volumes. Industrial consumption also declined, causing a reduction in transportation and interruptible volumes. The more weather sensative residential and commercial deliveries declined by 12% on 18% fewer heating degree days. Transportation and interruptible volumes decreased by 6%. Other revenues experienced a 10% decrease. Approximately half of the decrease in other revenues was attributable to the cessation of operations for Utility Consultants during fiscal 2015 and Application Resources during fiscal 2016.


18


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

Regulated natural gas margins from utility operations increased by 5% from fiscal 2015, primarily as a result of WNA revenues, increasing SAVE Plan revenues and customer base charges related to customer growth more than offsetting lower volumetric margins and ICC revenues. SAVE Plan revenues increased by $1,230,000 as the Company was in the third year of the current SAVE Plan. The growth in SAVE Plan revenues has been fueled by the Company's pipeline renewal program and investment in eligible SAVE Plan infrastructure projects. As noted above, volumetric margin declined due to a reduction in total volumes delivered. Residential and commercial volumes declined due to much warmer weather compared to the prior year. Interruptible and transportation volumes declined due to a combination of reduced activity at one large customer, the closing of another industrial customer's operations during the prior fiscal year and a significant decrease in usage by another industrial customer that uses natural gas as its back up fuel source. The impact of the warmer weather on volumetric margin was offset by the WNA mechanism. ICC revenues continued to decline with a $182,000 reduction in fiscal 2016 compared to fiscal 2015 due to lower commodity prices and a lower ICC factor.

Other margins, consisting of non-utility related services, decreased by $55,204 on comparable activity. The Utility Consultants, which ceased activity in fiscal 2015, and Application Resources, which terminated in fiscal 2016, accounted for approximately $25,000 of the reduction in non-utility related margin. The remainder of the decrease in other margins is attributable to the level of activity under these contracts which fluctuates based on customer requirements.

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

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

General Taxes - General taxes increased $56,705, or 4%, primarily due to higher property taxes associated with increases in utility property.
 

19


Depreciation - Depreciation expense increased by $484,675, or more than 9%, corresponding to a similar increase in utility plant investment.

Equity in Earnings of Unconsolidated Affiliate - The investment in Mountain Valley Pipeline began in fiscal 2016 and the $152,864 equity in earnings is primarily attributed to AFUDC income. More information regarding the investment in Mountain Valley Pipeline is located under the Equity Investment in Mountain Valley Pipeline section below.

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

Interest Expense - Total interest expense increased by $123,902, or 8%, due to a 15% increase in the average debt outstanding. The increase in average debt levels was attributable to financing the investments in Mountain Valley Pipeline and SAVE related projects and other capital improvements.

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

Net Income and Dividends - Net income for fiscal 2016 was $5,806,866 compared to $5,094,415 for fiscal 2015. Basic and diluted earnings per share were $0.81 in fiscal 2016 compared to $0.72 in fiscal 2015. Dividends declared per share of common stock were $0.54 in fiscal 2016 compared to $0.51 in fiscal 2015. All per share amounts were restated for the three-for-two stock split effective March 1, 2017.
    
Capital Resources and Liquidity

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

Cash and cash equivalents decreased by $573,612 in fiscal 2017 and $341,982 in fiscal 2016 compared to an increase of $135,477 in fiscal 2015. The following table summarizes the categories of sources and uses of cash:

Cash Flow Summary
Year Ended September 30,
 
2017
 
2016
 
2,015
Net cash provided by operating activities
$
12,980,978

 
$
14,921,640

 
$
16,760,827

Net cash used in investing activities
(23,492,555
)
 
(20,996,501
)
 
(13,750,274
)
Net cash provided by (used in) financing activities
9,937,965

 
5,732,879

 
(2,875,076
)
Increase (decrease) in cash and cash equivalents
$
(573,612
)
 
$
(341,982
)
 
$
135,477


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 increasing natural gas storage levels and rising customer receivable balances.

Cash provided by operating activities was $12,981,000 in fiscal 2017, $14,922,000 in fiscal 2016 and $16,761,000 in fiscal 2015. Cash provided by operating activities decreased by more than $1,900,000 from last year primarily as a result of natural gas commodity prices ending their steady price decline and a smaller increase in deferred tax liabilities associated with the continuation of bonus depreciation. Commodity prices had been declining since 2014, resulting in lower natural gas storage costs. During fiscal 2017, natural gas prices reversed this trend and increased, resulting in higher cost of gas in storage. The Company continues to benefit from the application of bonus depreciation for federal

20


income tax purposes with much higher first year tax deductions on assets placed in service; however, the growth in the tax benefit has been at a smaller rate. The Company has been claiming an initial tax deduction each year on 50% of the cost of most of the utility assets placed in service since 2008 with 100% bonus depreciation in effect during 2011. As a result of the bonus depreciation claimed during this time, the federal tax depreciation base is considerably smaller on these assets for all years following the year in which bonus depreciation deduction was claimed. Deferred tax has continued to increase due to the growth in capital expenditures by the Company. However, 50% bonus depreciation declines to 40% in 2018 and 30% in 2019. Absent any changes to current tax law, bonus depreciation will end after 2019. With projected capital expenditures expected to remain near fiscal 2017 levels and the scheduled phase out of bonus depreciation, deferred taxes are expected to reverse in the near future resulting in cash outflows as these taxes are paid. A summary of the key components of the cash flows from operating activities is provided below:

 
Twelve Months Ended September 30,
 
 
Cash Flows From Operating Activities:
2017
 
2016
 
Increase (Decrease)
  Net income
$
6,232,865

 
$
5,806,866

 
$
425,999

  Depreciation
6,378,368

 
5,709,525

 
668,843

  Decrease in gas in storage
(265,109
)
 
723,713

 
(988,822
)
  Increase in deferred taxes
3,325,379

 
4,466,954

 
(1,141,575
)
  Accounts payable and accrued expenses
(989,683
)
 
15,046

 
(1,004,729
)
  Other
(1,700,842
)
 
(1,800,464
)
 
99,622

Net cash provided by operating activities
$
12,980,978

 
$
14,921,640

 
$
(1,940,662
)

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 natural gas pipe with new plastic or coated steel pipe, making improvements to the LNG plant and distribution facilities, expanding its natural gas system to meet the demands of customer growth, as well as the continued investment in the MVP. The Company’s expenditures related to its pipeline renewal program and other system and infrastructure improvements increased to more than $20,700,000 in fiscal 2017 from $18,000,000 in fiscal 2016 and $13,800,000 in fiscal 2015. The Company renewed 9 miles of natural gas distribution main and replaced 459 services in fiscal 2017. This compares to 14.9 miles of main and 684 services in fiscal 2016 and 10 miles of main and 594 services in fiscal 2015. The Company completed the replacement of its cast iron and bare steel pipe in late 2016. In addition, the Company’s capital expenditures included costs to extend natural gas distribution mains and services to 499 new customers in fiscal 2017 compared to 495 new customers in fiscal 2016 and 609 in fiscal 2015. Although the level of expenditures under the pipeline renewal program declined in fiscal 2017 as the Company transitioned from cast iron and bare steel to first generation plastic pipe replacement, the Company exceeded last year's capital spending with the completion of the automated meter reading ("AMR") project. The AMR project involved the retrofitting of all customer meters with transmitters to allow consumption data to be collected remotely. The AMR system provides the Company with an efficient data collection process for more reliable and accurate measure of natural gas usage by its customers. Depreciation covered approximately 31% of the current year's capital expenditures compared to 32% for 2016 and 38% for 2015, with the balance provided from other operating cash flows and borrowings.

Capital expenditures are expected to remain at elevated levels over the next few years. The Company is now focused on replacing the remaining pre-1973 first generation plastic pipe with polyethylene pipe. This renewal project is expected to be completed by 2021. The current capital budget for fiscal 2018 is projected at more than $20,000,000, consistent with fiscal 2017 levels. In addition to the replacement of pre-1973 plastic pipe, the Company plans to invest approximately $3,000,000 for customer growth, replace a natural gas transfer station and reinforce sections of the distribution system to meet increasing demand and ensure reliability of gas service. The Company expects to increase its borrowing activity to meet the funding requirements of these planned expenditures.

Investing cash flows also reflect the Company's $2,759,346 funding of its participation in the LLC. The Company expects to invest a total of $35 million in the project. Funding for the investment in the LLC is provided through a combination of a $25 million credit facility, which matures in 2020, and equity capital. The Company may consider issuing additional common stock in 2018 to supplement the debt financing. When the $25 million credit facility matures, the Company will consider its financing options, which may included longer-term debt financing. More

21


information regarding the credit facility is provided in Note 6 of the Consolidated Financial Statements and under the Equity Investment in Mountain Valley Pipeline section below.

Cash Flows Provided by (Used in) Financing Activities:

Financing activities generally consist of borrowings and repayments under debt agreements, issuance of stock and the payment of dividends. As mentioned above, the Company uses its line-of-credit to fund seasonal working capital and provide temporary financing for capital projects, which is then converted into longer-term debt or equity financing. Cash flows provided by financing activities were $9,938,000 in fiscal 2017 and $5,733,000 in fiscal 2016 compared to cash used in financing activities of $2,875,000 in fiscal 2015. The combination of greater capital investment related to the pipeline renewal program and other projects, including the Mountain Valley Pipeline, and lower cash flows from operating activities increased net borrowing. As noted above, the Company's operating cash flows have declined since 2015 as the benefits from declining natural gas prices and bonus depreciation have lessened. The Company increased the net utilization of its line-of-credit by $3,235,000 to provide bridge financing for its capital budget. The Company also entered into a 5-year unsecured note in the principal amount of $7,000,000 on November 1, 2016. The proceeds from this note were used to convert a portion of the line-of-credit balance supporting Roanoke Gas' capital expenditures into a longer-term financing instrument. The remaining $2,916,000 increase in unsecured notes payable is attributable to the borrowing under Midstream's credit facility to finance the investment in MVP. Proceeds from the issuance of stock were $968,000 under the Company's stock plans. Dividends increased as the annualized dividend rate per share went from $0.51 in fiscal 2015 to $0.54 in fiscal 2016 and $0.58 in fiscal 2017. The Company’s consolidated capitalization was 49.4% equity and 50.6% long-term debt at September 30, 2017. This compares to 62.2% equity and 37.8% long-term debt at September 30, 2016. The long-term debt as a percent of long-term capitalization increased significantly over last year due to the extension of the line-of-credit term to more than one year resulting in its transition to a non-current debt as noted below.

On March 27, 2017, Roanoke Gas entered into a new revolving line-of-credit note agreement. The new line-of-credit agreement is for a two-year term expiring March 31, 2019, replacing the one-year agreement that expired on March 31, 2017. As the new agreement is for a two-year term, amounts drawn against the new agreement are considered to be non-current as the balance outstanding under the line-of-credit will not be subject to repayment within the next 12-month period. Therefore, the balance sheet at September 30, 2017 reflects the line-of-credit balance as part of long-term debt while the prior year's balance is classified as a current liability. The new agreement maintains the same variable interest rate based on 30-day LIBOR plus 100 basis points and availability fee of 15 basis points applied to the unused balance. The new agreement also maintains the multi-tiered borrowing limits to accommodate seasonal borrowing demands and minimize borrowing costs. The total available borrowing limits during the term of the new agreement range from $10,000,000 to $30,000,000. The Company intends to request an extension of the agreement by one year prior to next March when the outstanding debt would become a current liability; however, there is no guarantee that the line-of-credit agreement will be extended or replaced on terms comparable to those currently in place.

On October 2, 2017, the Company issued two 10-year unsecured notes in the aggregate principal amount of $8,000,000 with a fixed interest rate of 3.58% per annum. Interest is paid semi-annually on these notes in April and October of each year until the notes mature. The proceeds from these notes were used to refinance a portion of the line-of-credit balance outstanding at September 30, 2017 into longer-term financing.

Off-Balance Sheet Arrangements

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

Contractual Obligations and Commitments

The Company has incurred various contractual obligations and commitments in the normal course of business. As of September 30, 2017, the estimated recorded and unrecorded obligations are as follows:


22


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

 
$

 
$
13,312,200

 
$
30,500,000

 
$
43,812,200

Long-Term Debt - Line of Credit (2)

 
17,791,760

 

 

 
17,791,760

Total
$

 
$
17,791,760

 
$
13,312,200

 
$
30,500,000

 
$
61,603,960

 
 
 
 
 
 
 
 
 
 
(1) See Note 6 to the consolidated financial statements. Does not include scheduled debt payments for the unsecured notes issued on October 2, 2017.
(2) See Note 5 to the consolidated financial statements. New line-of-credit agreement executed for a 2-year term, expiring March 31, 2019. Amounts drawn against agreement are considered non-current as they are not subject to repayment within 12-months.

Unrecorded contractual obligations, not reflected in consolidated balance sheets in accordance with US GAAP:
Less than 1 year
 
1-3 Years
 
4-5 Years
 
After 5 Years
 
Total
Pipeline and Storage Capacity (3)
$
11,232,436

 
$
17,746,270

 
$
9,787,494

 
$
3,067,053

 
$
41,833,253

Gas Supply (4)

 

 

 

 

Interest on Line-of-Credit (5)
58,338

 
25,800

 

 

 
84,138

Interest on Notes Payable (6)
1,641,613

 
3,283,226

 
2,819,856

 
15,541,764

 
23,286,459

Pension Plan Funding (7)

 

 

 

 

Investment in MVP (8)
25,560,133

 
4,741,780

 

 

 
30,301,913

Other Obligations (9)
146,787

 
10,087

 
4,661

 
25,540

 
187,075

Total
$
38,639,307

 
$
25,807,163

 
$
12,612,011

 
$
18,634,357

 
$
95,692,838

 
 
 
 
 
 
 
 
 
 
(3) Recoverable through the PGA process.
(4) Volumetric obligation is for the purchase of contracted decatherms of natural gas at market prices in effect at the time of purchase. Unable to estimate related payment obligation until time of purchase. See Note 11 to the consolidated financial statements.
(5) Accrued interest on line-of-credit balance at September 30, 2017, including minimum facility fee on unused line-of-credit. See Note 5 to the consolidated financial statements.
(6) Calculated interest payments on 20-year $30.5 million Roanoke Gas Co. Prudential note payable due September 18, 2034, 5-year $7 million Roanoke Gas Co. BB&T note payable due November 01, 2021 and on the 09/30/2017 balance on Midstream notes due December 29, 2020. See Note 6 to the consolidated financial statements. Does not include scheduled interest payments on the unsecured notes issued on October 2, 2017.
(7) Estimated minimum funding assuming application of credit balances in plan to offset funding. Minimum funding requirements beyond five years is not available. See Note 8 to the consolidated financial statements for the planned funding in fiscal 2018.
(8) Projected remaining funding of the Company's 1% interest in MVP as entered into on October 1, 2015.
(9) Various lease, maintenance, equipment and service contracts.
              
Equity Investment in Mountain Valley Pipeline

On October 1, 2015, the Company, through its wholly-owned subsidiary Midstream, entered into an agreement to become a 1% member in the LLC. The purpose of the LLC is to construct and operate the Mountain Valley Pipeline ("MVP"), a natural gas pipeline connecting the Equitrans gathering and transmission system in northern West Virginia to the Transco interstate pipeline in south central Virginia. This project falls under the jurisdiction of FERC and is subject to its approval prior to beginning construction. On October 13, 2017, FERC issued the MVP Certificate of Public Convenience and Necessity ("CPCN"). Pending Virginia and West Virginia state environmental agency permits and other federal agency permits, it is expected that FERC will issue a construction Notice-to-Proceed ("NTP") in late 2017 or early 2018. If the NTP is received on this schedule, the MVP targeted in-service date is late fourth quarter of 2018.

Management believes the investment in the LLC will be beneficial for the Company, its shareholders and southwest Virginia. In addition to the potential returns from the investment in the LLC, Roanoke Gas will benefit from access to another source of natural gas to its distribution system. Currently, Roanoke Gas is served by two pipelines and a liquefied natural gas storage facility. Damage to or interruption in supply from any of these sources, especially during

23


the winter heating season, could have a significant impact on the Company's ability to serve its customers. A third pipeline would reduce the impact from such an event. In addition, the proposed pipeline path would provide the Company with a more economically feasible opportunity to provide natural gas service to previously unserved areas in southwest Virginia.

The total project cost is anticipated to be $3.5 billion. As a 1% member in the LLC, Midstream's cash contribution is expected to be approximately $35 million. The agreement provides for a schedule of cash draws to fund the project. The initial payments are related to pre-construction activities including the acquisition of land, easements and materials. Once the NTP is received and construction begins, more significant cash draws will be required. Initial funding for the investment in the LLC is provided through the Midstream credit facility under which Midstream may borrow up to a total of $25 million, through 2020 with the balance coming from equity capital. The Company regularly assesses its overall capital needs and capital structure. Based on these assessments and market conditions during 2018, the Company may fund the LLC investment with proceeds from an equity offering of the Company's common stock.

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

Regulatory Affairs

The Company continues to recover the costs of its infrastructure replacement program through its SAVE Plan. On June 30, 2017, the Company filed its 2018 SAVE Plan application with the SCC. The original SAVE Plan and Rider were approved by the SCC through an order issued on August 29, 2012 and has been modified, amended or updated each year since. The original SAVE Plan was designed to facilitate the accelerated replacement of the remaining bare steel and cast iron natural gas pipe by providing a mechanism for the Company to recover the related depreciation and expenses and return on rate base of the additional capital investment without the filing of a formal application for an increase in non-gas base rates. The projects included under the SAVE Plan will enhance the safety and reliability of the Company’s gas distribution system and reduce greenhouse emissions. The amendments in 2013 and 2014 added projects related to the replacement of bare steel and cast iron natural gas pipe in addition to two other major projects and the investment for related meter and regulator installations located on customer premises. In 2015, the SCC approved the Company's request to expand the authorized annual spending variance from 10% to 20% and set a 5% cumulative SAVE spending variance. This allows the Company to recover it's investment up to the new variance limits. The 2016 and 2017 applications included provisions to continue the ongoing pipeline renewal project with a focus on pre-1973 plastic pipe, replacement of natural gas custody transfer stations and the replacement of coated steel tubing services and related meter installations. The 2018 SAVE Plan continues the focus on the replacement of the pre-1973 plastic pipe and the replacement of one custody transfer station. On September 28, 2017, the Company received SCC approval to implement the new 2018 SAVE rates related to the proposed qualifying SAVE investments in calendar 2018. The new rates are designed to provide approximately $5,000,000 in revenue, representing an increase of $1,000,000 over the estimated 2017 SAVE Plan year. The additional SAVE Plan revenue as approved by the SCC will allow the Company to forgo a formal non-gas rate increase application at this time.

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

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

24


request at a later date. As FERC has issued the CPCN on the MVP project, the Company intends to request removal of the stay and complete the Franklin County application in fiscal 2018.

Critical Accounting Policies and Estimates

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

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

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

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

Revenue recognition - Regulated utility sales and transportation revenues are based upon rates approved by the SCC. The non-gas cost component of rates may not be changed without a formal rate application and corresponding authorization by the SCC in the form of a Commission order; however, the gas cost component of rates may be adjusted quarterly through the PGA mechanism. When the Company files a request for a non-gas rate increase, the SCC may allow the Company to place such rates into effect subject to refund pending a final order. Under these circumstances, the Company estimates the amount of increase it anticipates will be approved based on the best available information. The Company also bills customers through a SAVE Rider that provides a mechanism to recover on a prospective basis the costs associated with the Company’s expected investment related to the replacement of natural gas distribution pipe and other qualifying projects. As authorized by the SCC, the Company adjusts billed revenues monthly through the application of the WNA model. As the Company's non-gas rates are established based on the 30-year temperature average, monthly fluctuations in temperature from the 30-year average could result in the recognition of more or less revenue than for what the non-gas rates were designed. The WNA authorizes the Company to adjust monthly revenues for the effects of variation in weather from the 30-year average with a corresponding entry to a WNA receivable or WNA payable. At the end of each WNA year, the Company will refund excess revenue collected for weather that was colder than the 30-year average or bill the customer for revenue short-fall for weather that was warmer than normal. As required under the provisions of FASB ASC No. 980, Regulated Operations, the Company recognizes billed revenue related to the SAVE projects and from the WNA to the extent such revenues have been earned under the provisions approved by the SCC.

The Company bills its regulated natural gas customers on a monthly cycle. The billing cycle for most customers does not coincide with the accounting periods used for financial reporting. The Company accrues estimated revenue for natural gas delivered to customers but not yet billed during the accounting period based on weather during the period and current and historical data. The financial statements include unbilled revenue of $965,683 and $1,004,061 as of September 30, 2017 and 2016, respectively.

Allowance for Doubtful Accounts - The Company evaluates the collectability of its accounts receivable balances based upon a variety of factors including loss history, level of delinquent account balances, collections on previously written off accounts and general economic conditions. The Company recently outsourced its credit and collections function as part of its strategic decision to move the call center, billing and other customer service functions to a third

25


party provider with significant utility experience. These changes will impact the current valuation model for accounts receivable, which used historical information based on collection functions previously handled by Company personnel.

Pension and Postretirement Benefits - The Company offers a defined benefit pension plan (“pension plan”) and a postretirement medical and life insurance plan (“postretirement plan”) to eligible employees. The expenses and liabilities associated with these plans, as disclosed in Note 8 to the consolidated financial statements, are based on numerous assumptions and factors, including provisions of the plans, employee demographics, contributions made to the plan, return on plan assets and various actuarial calculations, assumptions and accounting requirements. In regard to the pension plan, specific factors include assumptions regarding the discount rate used in determining future benefit obligations, expected long-term rate of return on plan assets, compensation increases and life expectancies. Similarly, the postretirement medical plan also requires the estimation of many of the same factors as the pension plan in addition to assumptions regarding the rate of medical inflation and Medicare availability. Actual results may differ materially from the results expected from the actuarial assumptions due to changing economic conditions, differences in actual returns on plan assets, different rates of medical inflation, volatility in interest rates and changes in life expectancy. Such differences may result in a material impact on the amount of expense recorded in future periods or the value of the obligations on the balance sheet.

In selecting the discount rate to be used in determining the benefit liability, the Company utilized the Citigroup yield curves which incorporate the rates of return on high-quality, fixed-income investments that corresponded to the length and timing of benefit streams expected under both the pension plan and postretirement plan. The Company used a discount rate of 3.72% and 3.69%, respectively, for valuing its pension plan liability and postretirement plan liability at September 30, 2017. These rates increased over the prior year by 0.30% and 0.36%, respectively. The rise in the discount rate is evidenced by the 30-year Treasury rate, which increased from 2.32% to 2.86%. However, corporate bond rates increased but to a lesser degree indicating that credit spreads among high quality investments narrowed resulting in a smaller discount rate increase. This increase in the discount rates was the primary driver in the reduction of the accumulated benefit obligation on the postretirement plan. The rise in the discount rate for the pension plan nearly offset the increase in liabilities associated with additional credited service and salary increases resulting in small increases in both the accumulated benefit obligation and the projected benefit obligation. The Company used the RP-2014 Mortality Table, adjusted to 2006, with generational mortality improvements under Projection Scale MP-2016 for the current year valuation.

The benefit plans' assets benefited from strong market returns and Company funding. Following lower than expected returns in fiscal 2015, the returns on the related pension and postretirement assets for fiscal 2016 and 2017 exceeded the corresponding long-term rate of return assumptions for both plans. Furthermore, in fiscal 2017, the Company contributed $1,000,000 to each of the plans, which well exceeded the cash outflows for benefit payments. The combination of better than expected returns, higher funding levels and increase in the discount rate improved the funded status of the pension and postretirement plans by $3,143,000 and $2,406,000, respectively. The combination of higher asset totals and higher discount rate also served to reduce pension and postretirement expense in fiscal 2018.

Funded status - September 30, 2017
Pension
 
Postretirement
 
Total
Benefit Obligation
$
29,657,347

 
$
17,666,812

 
$
47,324,159

Fair value of assets
26,418,671

 
12,691,162

 
39,109,833

Funded status
$
(3,238,676
)
 
$
(4,975,650
)
 
$
(8,214,326
)
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
)

Accurately forecasting future interest rates and investment returns is nearly impossible. Interest rates have been low for several years and just recently began to move higher. Investment returns from the equity market have been strong the last two years; however, concern exists that current market valuations may be too high, which could be a prelude to a market correction. The variability in interest rates and investment returns create the potential for volatility in the Company's benefit plan liabilities, asset values, funded status and expense. Increasing interest rates would serve to reduce the benefit liabilities but may negatively impact returns on fixed income investments in the short-term, while a decline in interest rates would increase benefit liabilities and provide a short-term boost to fixed income returns. Equity

26


markets could experience a decline in the next year, which would reduce plan assets and negatively affect the funded status of the plans, or equities could continue their strong performance and improve the funded status of the plans. The Company cannot control the direction of interest rates or asset returns. However the Company annually evaluates the returns on its targeted investment allocation model as well as the overall asset allocation of its benefit plans. The investment policy as of the measurement date in September reflected a targeted allocation of 60% equity and 40% fixed income on the pension plan and a targeted allocation of 50% equity and 50% fixed income for the postretirement plan. Understanding the volatility in the markets, the Company reviews both plans potential long-term rate of return with their investment advisors in determining the rates used in assumptions. As a result of this evaluation, the Company set its expected long-term annual return on pension assets at 7.00% and postretirement assets at 4.84% (net of income taxes) for fiscal 2018. These rates are consistent with the expected long-term rates used in fiscal 2017 and appear reasonable based on a long-term investment horizon. Management will continue to re-evaluate the return assumptions and asset allocation and adjust both as market conditions warrant.

With the inherent volatility associated with defined benefit plans, the Company continues to seek opportunities to reduce risk and variability related to these plans. The Company implemented a freeze on the postretirement plan effective January 1, 2000, whereby no employees hired on or after that date would participate. Employees and retirees that were eligible at the time of the freeze continued to participate and accrue benefits. With regard to the pension plan, the Company implemented a two-part risk reduction strategy. The first part included a one-time, lump sum pension benefit pay out in fiscal 2016 to vested, terminated employees who were not receiving payments under the pension plan at the time. Approximately 63% of those vested, terminated employees elected to receive their lump sum payment, resulting in a payout of $1,242,000 from plan assets in September 2016. These lump sum payments removed approximately $1,500,000 in pension plan liabilities and reduced the number of participants on which the Pension Benefit Guaranty Corporation ("PBGC") premiums are determined. The second part was to take action on the pension plan similar to what was done with the postretirement plan back in 2000 by closing the pension plan to new employees effective January 1, 2017. Employees hired prior to that date will continue to accrue benefits. This "soft freeze" of the pension plan will not provide immediate relief to the Plan in the form of reduced liabilities and lower expenses; but, absent changes in other variables, pension liability growth will slow and eventually decline as no new participants will enter the pension plan. Likewise, pension expense will reflect this change in the future as less service cost is accrued due to fewer active employees in the pension plan. Furthermore, as the funded status of the plans improve, the Company will evaluate the possibility of revising its asset allocation targets to more closely correlate to the corresponding plan liabilities. Essentially, the goal would be to match investment maturities to the timing of payment of benefits under the plans. During the current fiscal year, the Company transitioned the fixed income portion of its pension assets into liability driven investing ("LDI"). Under the LDI approach, the fixed income portion of the investments are allocated to one of three separate fixed income investments that corresponded to the duration of the liabilities of the pension plan; a short duration investment, a middle duration investment and a longer-term duration investment. No fundamental change has been made to the overall asset allocation between fixed income and equity other than adjusting the duration of the fixed income portion. The matching of the asset and liability durations should ultimately reduce some of the volatility in these plans.

In August 2014, the Highway and Transportation Funding Act of 2014 (“HATFA”) was signed into law, which included a provision to extend the interest rate corridors introduced in 2012 under the Moving Ahead for Progress in the 21st Century Act (“MAP-21”). MAP-21 provided temporary funding relief for defined benefit pension plans. The requirements of the Employee Retirement Income Security Act of 1974 (ERISA) and the Pension Protection Act of 2006 (PPA) subject defined benefit plans to minimum funding rules. As a result, when interest rates are low, pension plan liabilities increase thereby resulting in higher mandatory contributions to meet minimum funding obligations. MAP-21 provided funding relief by allowing pension plans to adjust the interest rates used in determining funding requirements so that they are within 10% of the average of interest rates for the 25-year period preceding the current year for funding calculations for 2013 to within 30% for funding periods beginning in 2016. HATFA extended the period of time that the 10% corridor instituted by MAP-21 may be used for funding calculations. Under HATFA, the 10% corridor extends through plan years that begin in 2017 and phases out to a 30% corridor in 2021 and later. HATFA significantly increases the effective interest rates used in determining funding requirements and could result in a deterioration of the pension plan funded status resulting in much greater funding requirements in the future as well as higher PBGC premiums paid by sponsors of pension plans to protect participants in the event of default by the employer. Management estimates that, under the provisions of HATFA, the Company will have no minimum funding requirements next year. Although HATFA and MAP-21 allow the Company some funding relief, management expects to continue its pension funding plan by contributing at least the minimum annual pension contribution requirement or its expense level for subsequent years. The Company currently expects to contribute approximately $1,600,000 to its pension plan and $600,000 to its postretirement plan in fiscal 2018 with a continuing goal to improve both plans' funded status. The Company will continue to evaluate its benefit plan funding levels in light of funding requirements

27


and ongoing investment returns and make adjustments, as necessary, to avoid benefit restrictions and minimize PBGC premiums.

The following schedule reflects the sensitivity of pension costs to changes in certain actuarial assumptions, assuming that the other components of the calculation remain constant.
Actuarial Assumptions - Pension Plan
Change in Assumption
 
Increase in Pension Cost
 
Increase in Projected Benefit Obligation
Discount rate
-0.25
 %
 
$
123,000

 
$
1,225,000

Rate of return on plan assets
-0.25
 %
 
66,000

 
N/A

Rate of increase in compensation
0.25
 %
 
53,000

 
292,000


The following schedule reflects the sensitivity of postretirement benefit costs from changes in certain actuarial assumptions, while the other components of the calculation remain constant.
Actuarial Assumptions - Postretirement Plan
Change in Assumption
 
Increase in Postretirement Benefit Cost
 
Increase in Accumulated Postretirement Benefit Obligation
Discount rate
-0.25
 %
 
$
1,000

 
$
747,000

Rate of return on plan assets
-0.25
 %
 
29,000

 
N/A

Medical claim cost increase
0.25
 %
 
45,000

 
723,000


Derivatives - The Company may hedge certain risks incurred in its operation through the use of derivative instruments. The Company applies the requirements of FASB ASC No. 815, Derivatives and Hedging, which requires the recognition of derivative instruments as assets or liabilities in the Company’s balance sheet at fair value. In most instances, fair value is based upon quoted futures prices for natural gas commodities and interest rate futures for interest rate swaps. Changes in the commodity and futures markets will impact the estimates of fair value in the future. Furthermore, the actual market value at the point of realization of the derivative may be significantly different from the values used in determining fair value in prior financial statements. The Company had one interest-rate swap outstanding at September 30, 2017 related to the 5-year $7,000,000 variable-rate note. This swap agreement, which was entered into on November 1, 2016, becomes effective November 1, 2017.

Tax Reform

Federal corporate tax reform is currently a major legislative agenda item. There continues to be discussion regarding tax legislation and improving the corporate tax environment in the United States in an effort to encourage domestic business development. The key proposal is a reduction in corporate income tax rates. In general, a change in corporate income tax rates would not only reduce current income tax expense but also result in an adjustment to the value of deferred income tax balances. According to ASC 740-10, deferred tax assets and liabilities shall be adjusted for the effect of a change in tax laws and rates and the effect of such change shall be included in income from continuing operations for the period that includes the date of enactment. If lower federal corporate tax rates are passed, deferred income taxes at the date of enactment would be reduced and the net benefit or expense would flow through income tax expense. However, for Roanoke Gas, any adjustment to deferred taxes would not be reflected in the income statement. Instead, under the requirements of regulatory accounting, those excess deferred taxes would be reclassified to a regulatory liability to be refunded to the utility's customers, as the Company's non gas rates provided for the recovery of income taxes at a federal tax rate of 34%. As of September 30, 2017, the Company has a net deferred tax liability of approximately $23,100,000 of which Roanoke Gas represented approximately $23,900,000 of that balance while the unregulated operations of Resources had a net deferred tax asset of $800,000. If a corporate tax rate decrease becomes law, then for every one percent decrease in the federal corporate tax rate, approximately $600,000 would be transferred to a regulatory liability and $20,000 would be reflected as additional income tax expense in comprehensive income. Other proposed tax law changes may have impacts, both favorable or unfavorable, to the Company's tax expense and deferred tax balances. No adjustment will be made to deferred taxes or income tax expense until such time as any proposed tax legislation is signed into law.

28


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

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

Interest Rate Risk
The Company is exposed to market risk related to changes in interest rates associated with its borrowing activities. As of September 30, 2017, the Company has $17,791,760 outstanding under its variable-rate line-of-credit with an average balance outstanding during the year of $10,936,114. The Company also had $6,312,200 outstanding under a 5-year variable rate term loan and $7,000,000 outstanding on a another 5-year variable-rate which has a fixed rate swap effective November 1, 2017. A hypothetical 100 basis point increase in market interest rates applicable to the Company’s variable-rate debt outstanding during the year would have resulted in an increase in interest expense for the current year of approximately $223,000. The Company’s remaining debt is at a fixed rate.

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

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

At September 30, 2017, the Company had no outstanding derivative instruments to hedge the price of natural gas. The Company had approximately 2,388,000 decatherms of gas in storage, including LNG, at an average price of $3.23 per decatherm compared to 2,537,000 decatherms at an average price of $2.93 per decatherm last year. The SCC currently allows for full recovery of prudent costs associated with natural gas purchases, and any additional costs or benefits associated with the settlement of derivative contracts and other price hedging techniques are passed through to customers when realized through the regulated natural gas PGA mechanism.

Item 8.
Financial Statements and Supplementary Data.

29



RGC Resources, Inc.
and Subsidiaries

Consolidated Financial Statements
for the Years Ended September 30, 2017, 2016
and 2015, and Report of Independent
Registered Public Accounting Firm

30



RGC RESOURCES, INC. AND SUBSIDIARIES
TABLE OF CONTENTS
 


31



brownedwardsa04.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, 2017 and 2016, and the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows for each of the years in the three-year period ended September 30, 2017. RGC Resources, Inc.’s management is responsible for these financial statements. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of RGC Resources, Inc. and Subsidiaries as of September 30, 2017 and 2016, and the consolidated results of its operations and its cash flows for each of the years in the three-year period ended September 30, 2017, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), RGC Resources, Inc. and Subsidiaries’ internal control over financial reporting as of September 30, 2017, based on criteria established in Internal Control-Integrated Framework - 2013 issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated December 8, 2017 expressed an unqualified opinion.
 
brownedwardssignaturea04.jpg
              CERTIFIED PUBLIC ACCOUNTANTS

Blacksburg, Virginia
December 8, 2017


32



RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AS OF SEPTEMBER 30, 2017 AND 2016
 
 
 
2017
 
2016
ASSETS
 
 
 
CURRENT ASSETS:
 
 
 
Cash and cash equivalents
$
69,640

 
$
643,252

Accounts receivable, net
3,492,703

 
3,478,983

Materials and supplies
1,021,191

 
824,139

Gas in storage
7,701,894

 
7,436,785

Prepaid income taxes
1,796,825

 
1,550,836

Interest rate swap
26,777

 

Other
1,576,574

 
1,548,329

Total current assets
15,685,604

 
15,482,324

UTILITY PROPERTY:
 
 
 
In service
204,223,714

 
185,577,286

Accumulated depreciation and amortization
(59,765,987
)
 
(56,156,287
)
In service, net
144,457,727

 
129,420,999

Construction work in progress
3,470,244

 
2,707,139

Utility plant, net
147,927,971

 
132,128,138

OTHER ASSETS:
 
 
 
Regulatory assets
11,796,260

 
14,332,451

Investment in unconsolidated affiliate
7,445,106

 
3,496,404

Interest rate swap
90,066

 

Other
190,064

 
113,532

Total other assets
19,521,496

 
17,942,387

TOTAL ASSETS
$
183,135,071

 
$
165,552,849


(Continued)

33


RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AS OF SEPTEMBER 30, 2017 AND 2016
 
 
 
2017
 
2016
LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
CURRENT LIABILITIES:
 
 
 
Line-of-credit
$

 
$
14,556,785

Dividends payable
1,050,281

 
970,244

Accounts payable
5,122,899

 
5,345,575

Capital contributions payable
1,055,504

 
287,794

Customer credit balances
1,220,578

 
1,605,608

Customer deposits
1,471,960

 
1,627,105

Accrued expenses
3,006,936

 
3,194,255

Over-recovery of gas costs
1,438,074

 
909,687

Total current liabilities
14,366,232

 
28,497,053

LONG-TERM DEBT:
 
 
 
Notes payable
43,812,200

 
33,896,200

Line-of-credit
17,791,760

 

       Less unamortized debt issuance costs
(291,949
)
 
(260,149
)
       Long-term debt net of unamortized debt issuance costs
61,312,011

 
33,636,051

DEFERRED CREDITS AND OTHER LIABILITIES:
 
 
 
Asset retirement obligations
6,069,993

 
5,682,556

Regulatory cost of retirement obligations
10,055,189

 
9,348,443

Benefit plan liabilities
8,214,326

 
13,763,820

Deferred income taxes
23,076,848

 
18,957,854

Total deferred credits and other liabilities
47,416,356

 
47,752,673

COMMITMENTS AND CONTINGENCIES (Note 11)

 

CAPITALIZATION:
 
 
 
Stockholders’ Equity:
 
 
 
Common Stock, $5 par value; authorized 10,000,000 shares; issued and outstanding 7,240,846 and 7,182,434 shares in 2017 and 2016, respectively
36,204,230

 
23,941,445

Preferred stock, no par; authorized 5,000,000 shares; no shares issued and outstanding in 2017 and 2016

 

Capital in excess of par value
292,485

 
9,509,548

Retained earnings
24,746,021

 
24,713,310

Accumulated other comprehensive loss
(1,202,264
)
 
(2,497,231
)
Total stockholders’ equity
60,040,472

 
55,667,072

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
$
183,135,071

 
$
165,552,849

(Concluded)
See notes to consolidated financial statements.

34



RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
YEARS ENDED SEPTEMBER 30, 2017, 2016 AND 2015
 
 
 
2017
 
2016
 
2015
OPERATING REVENUES:
 
 
 
 
 
Gas utilities
$
61,252,015

 
$
58,079,990

 
$
67,094,290

Other
1,044,855

 
983,301

 
1,095,317

Total operating revenues
62,296,870

 
59,063,291

 
68,189,607

COST OF SALES:
 
 
 
 
 
Gas utilities
28,919,625

 
27,009,330

 
37,437,315

Other
568,088

 
489,047

 
545,859

Total cost of sales
29,487,713

 
27,498,377

 
37,983,174

GROSS MARGIN
32,809,157

 
31,564,914

 
30,206,433

OTHER OPERATING EXPENSES:
 
 
 
 
 
Operations and maintenance
13,100,041

 
13,098,086

 
13,486,885

General taxes
1,786,070

 
1,663,126

 
1,606,421

Depreciation and amortization
6,256,737

 
5,591,610

 
5,106,935

Total other operating expenses
21,142,848

 
20,352,822

 
20,200,241

OPERATING INCOME
11,666,309

 
11,212,092

 
10,006,192

Equity in earnings of unconsolidated affiliate
421,646

 
152,864

 

Other expense, net
132,446

 
255,585

 
228,796

Interest expense
1,917,254

 
1,636,321

 
1,512,419

INCOME BEFORE INCOME TAXES
10,038,255

 
9,473,050

 
8,264,977

INCOME TAX EXPENSE
3,805,390

 
3,666,184

 
3,170,562

NET INCOME
$
6,232,865

 
$
5,806,866

 
$
5,094,415

EARNINGS PER COMMON SHARE:
 
 
 
 
 
Basic
$
0.86

 
$
0.81

 
$
0.72

Diluted
$
0.86

 
$
0.81

 
$
0.72

WEIGHTED AVERAGE SHARES OUTSTANDING:
 
 
 
 
 
Basic
7,218,686

 
7,149,906

 
7,092,315

Diluted
7,256,046

 
7,159,763

 
7,097,514

See notes to consolidated financial statements.

35



RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
YEARS ENDED SEPTEMBER 30, 2017, 2016 AND 2015
 
 
 
2017
 
2016
 
2015
NET INCOME
$
6,232,865

 
$
5,806,866

 
$
5,094,415

Other comprehensive income, net of tax:
 
 
 
 
 
Interest rate swaps
72,489

 

 

Defined benefit plans
1,222,478

 
(210,686
)
 
(1,147,219
)
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
1,294,967

 
(210,686
)
 
(1,147,219
)
COMPREHENSIVE INCOME
$
7,527,832

 
$
5,596,180

 
$
3,947,196

See notes to consolidated financial statements.

36



RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
YEARS ENDED SEPTEMBER 30, 2017, 2016 AND 2015
 
 
 
Common
Stock
 
Capital in
Excess of
Par Value
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Total
Stockholders’
Equity
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 (3,900 shares)
13,000

 
36,366

 

 

 
49,366

Stock option grants

 
83,640

 

 

 
83,640

Cash dividends declared ($0.51 per share)

 

 
(3,643,093
)
 

 
(3,643,093
)
Issuance of common stock (27,780 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 (3,300 shares)
11,000

 
30,762

 

 

 
41,762

Stock option grants

 
64,640

 

 

 
64,640

Cash dividends declared ($0.54 per share)

 

 
(3,865,933
)
 

 
(3,865,933
)
Issuance of common stock (66,887 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

Net income

 

 
6,232,865

 

 
6,232,865

Other comprehensive income

 

 

 
1,294,967

 
1,294,967

Exercise of stock options (11,225 shares)
50,250

 
91,991

 

 

 
142,241

Stock option grants

 
73,780

 

 

 
73,780

Cash dividends declared ($0.58 per share)

 

 
(4,195,910
)
 

 
(4,195,910
)
Stock split
12,029,790

 
(10,025,546
)
 
(2,004,244
)
 

 

Issuance costs

 
(96,508
)
 

 

 
(96,508
)
Issuance of common stock (47,187 shares)
182,745

 
739,220

 

 

 
921,965

Balance - September 30, 2017
$
36,204,230

 
$
292,485

 
$
24,746,021

 
$
(1,202,264
)
 
$
60,040,472

See notes to consolidated financial statements.


37



RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED SEPTEMBER 30, 2017, 2016 AND 2015

 
 
2017
 
2016
 
2015
CASH FLOWS FROM OPERATING ACTIVITIES:
 
 
 
 
 
Net income
$
6,232,865

 
$
5,806,866

 
$
5,094,415

Adjustments to reconcile net income to net cash provided by operations:
 
 
 
 
 
Depreciation and amortization
6,378,368

 
5,709,525

 
5,219,893

Cost of retirement of utility plant, net
(354,744
)
 
(449,201
)
 
(406,731
)
Stock option grants
73,780

 
64,640

 
83,640

Equity in earnings of unconsolidated affiliate
(421,646
)
 
(152,864
)
 

Deferred income taxes
3,325,379

 
4,466,954

 
2,416,841

Other noncash items, net
203,743

 
197,298

 
105,815

Changes in assets and liabilities which provided (used) cash:
 
 
 
 
 
Accounts receivable and customer deposits, net
(191,386
)
 
(258,960
)
 
638,917

Inventories and gas in storage
(462,161
)
 
867,682

 
3,168,056

Over/under recovery of gas costs
528,387

 
(991,739
)
 
2,082,257

Other assets
(956,894
)
 
(398,864
)
 
(768,922
)
Accounts payable, customer credit balances and accrued expenses, net
(1,374,713