RGC Resources
Annual Report 2016

Plain-text annual report

Key Financial Information Year Ending September 30 2016 2015 2014 Net Income $ 5,806,866 $ 5,094,415 $ 4,708,440 Earnings Per Share $ 1.22 $ 1.08 $ 1.00 Natural Gas Customers 59,635 59,080 58,553 Additions to Plant $ 17,945,719 $ 13,780,356 $ 14,715,428 Natural Gas Deliveries (DTH’s) 8,842,605 9,875,007 10,087,651 Stock Price and Dividends Dividends $0.85 $0.80 $0.75 $0.70 $0.65 $0.60 $26.00 $24.00 $22.00 $20.00 $18.00 $16.00 $14.00 $12.00 Stock Price 2009 2010 2011 2012 2013 2014 2015 2016 DividendsPerShare Share Price Note: Dividends excludes Dec 2012 $1.00 special dividend President’s Letter To Our Shareholders report We are pleased to provide you with our 2016 annual reflecting strong earnings, solid stock performance and our long-term commitment of providing safe and reliable natural gas service to our customers. I am delighted to report record earnings of $5.8 million or $1.22 per share outstanding, compared to $1.08 per share last year, or a 13% improvement. strong earnings and operational performance have contributed to a 17% stock price increase this past year. Combined with dividends, our shareholders had a total return of $4.29 per share in fiscal year 2016. Our Board of Directors approved an annualized dividend increase from $0.81 per share to $0.87 per share, effective with the February 1, 2017 quarterly dividend payment. The February dividend will reflect 72 years of continuous quarterly dividend payments and 20 annual dividend increases in the past 21 years. Consistently The economic outlook for the Roanoke region is positive. The past year has seen several major economic announcements. Three major companies have announced plans to invest $208 million in the next few years, creating over 525 new jobs. In addition, Virginia Tech and Carilion Clinic announced a plan to build a $66 million facility to expand the Virginia Tech Carilion Health Sciences Campus in Roanoke. Private sector employment in the Roanoke region reached its highest levels since 2007, resulting in unemployment rates below 4%. Our subsidiary, Roanoke Gas Company, experienced steady growth this year with approximately 500 customer additions. Demand from existing industrial customers was down slightly in 2016, however the first large compressed natural gas fueling station was opened in the Roanoke Valley to fuel a large delivery vehicle fleet. The station went into service in the first quarter of 2016 and has become one of our top 10 volumetric customers. We continue to invest in capital improvements for Roanoke Gas Company. In fiscal year 2016, we invested $17.9 million, with the primary focus on the modernization of our distribution system. Approximately 15 miles of cast iron and bare steel pipe was replaced with polyethylene pipe. I am excited to announce that in November 2016, the last segment of cast iron and bare steel main in our system was renewed. This has been a 25-year effort and I wish to recognize our employees and contractors who worked on this project that enhances the safety and reliability of our natural gas distribution system. President’s Letter (continued) Our focus will now turn to the renewal of approximately 45 miles of first generation plastic mains and services that were installed before 1973. The first generation plastic main renewal project is anticipated to take 3 to 4 years to complete. We also completed the replacement and upgrade of two natural gas transfer stations on the south side of our system, both of which connect with the East Tennessee transmission line. Along with pipeline renewal and gate station upgrades, the Company is implementing new technology to improve the efficiency, safety and reliability of our distribution system. In the past year, we invested in electronic tablet technology for field personnel and expanded our GIS mapping system. Implementation of an automated meter reading system is planned for fiscal year 2017. This will allow us to remotely access meter readings and provide more comprehensive natural gas usage data. Through our subsidiary, RGC Midstream, LLC, we are a 1% member of the Mountain Valley Pipeline, LLC. The Mountain Valley Pipeline (MVP) will be an approximately 300 mile, 42-inch diameter interstate pipeline with an approximate cost of $3.5 billion. The pipeline will transport natural gas from the Marcellus and Utica production areas through West Virginia and Southwest Virginia to the growing natural gas markets along the east coast. The MVP will address the growing demand for natural gas in our region, add an additional source of gas to the Roanoke Gas natural gas supply portfolio and provide the Company with a more economically feasible opportunity to expand natural gas service to previously unserved areas in southwest Virginia. The MVP project is progressing through the Federal Energy Regulatory Commission (FERC) approval process. On June 28, 2016, FERC issued the Notice of Schedule for Environmental Review (NOS) and on September 16, 2016, FERC issued its draft environmental impact statement regarding the MVP. Based on the schedule provided in the NOS, the MVP expects to receive the FERC certificate in mid- 2017. The pipeline is targeted to be placed in-service during the fourth quarter of 2018. Our total investment in this project is projected to be approximately $35 million. We believe this strategic investment will complement our core business and continue to enhance shareholder value. On behalf of our Board of Directors and employees, thank you for your continued interest in our Company and for your ongoing decision in RGC Resources. invest to John S. D’Orazio President and Chief Executive Officer (Left to Right) Chris Morrill, Roanoke City Manager; Sherman P. Lea, Sr., Roanoke City Mayor and John S. D’Orazio. Photograph taken during 25 Year pipeline renewal completion celebration. UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended September 30, 2016 Commission file number 000-26591 RGC RESOURCES, INC. (Exact name of registrant as specified in its charter) Virginia (State or other jurisdiction of incorporation or organization) 519 Kimball Avenue, N.E., Roanoke, VA (Address of principal executive offices) 54-1909697 (I.R.S. Employer Identification No.) 24016 (Zip Code) Registrant’s telephone number, including area code (540) 777-4427 Securities registered pursuant to Section 12(b) of the Act: None Securities registered pursuant to Section 12(g) of the Act: Title of Each Class Common Stock, $5 Par Value Name of Each Exchange on Which Registered NASDAQ Global Market Indicate by check mark if the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act. Yes No Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes No Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes No Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes No Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one). Large accelerated filer Accelerated filer Non-accelerated filer (Do not check if smaller reporting company) Smaller reporting company Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes No State the aggregate market value of the voting and non voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity as of the last business day of the registrant’s most recently completed second fiscal quarter: March 31, 2016. $95,954,187 Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the last practicable date. Class COMMON STOCK, $5 PAR VALUE Outstanding at November 30, 2016 4,798,466 SHARES DOCUMENTS INCORPORATED BY REFERENCE: Portions of the RGC Resources, Inc. Proxy Statement for the 2017 Annual Meeting of Shareholders are incorporated by reference into Part III hereof. TABLE OF CONTENTS Cautionary Note Regarding Forward Looking Statements PART I PART II Item 1. Business Item 1A. Risk Factors Item 1B. Unresolved Staff Comments Item 2. Properties Item 3. Legal Proceedings Item 4. Mine Safety Disclosures Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Item 6. Selected Financial Data Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations Item 7A. Quantitative and Qualitative Disclosures About Market Risk Item 8. Financial Statements and Supplementary Data Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosures Item 9A. Controls and Procedures Item 9B. Other Information Item 10. Directors, Executive Officers and Corporate Governance Item 11. Executive Compensation Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters Item 13. Certain Relationships and Related Transactions, and Director Independence Item 14. Principal Accounting Fees and Services Item 15. Exhibits and Financial Statement Schedules Signatures PART III PART IV Page Number 2 3 6 10 10 10 10 11 13 13 28 29 63 63 65 66 66 66 66 66 67 68 Cautionary Note Regarding Forward Looking Statements This report contains forward-looking statements that relate to future transactions, events or expectations. In addition, RGC Resources, Inc. (“Resources” or the “Company”) may announce or publish forward-looking statements relating to such matters as anticipated financial performance, business prospects, technological developments, new products, research and development activities and similar matters. These statements are based on management’s current expectations and information available at the time of such statements and are believed to be reasonable and are made in good faith. The Private Securities Litigation Reform Act of 1995 provides a safe harbor for forward-looking statements. In order to comply with the terms of the safe harbor, the Company notes that a variety of factors could cause the Company’s actual results and experience to differ materially from the anticipated results or expectations expressed in the Company’s forward-looking statements. The risks and uncertainties that may affect the operations, performance, development and results of the Company’s business include, but are not limited to those set forth in the following discussion and within Item 1A “Risk Factors” of this Annual Report on Form 10- K. All of these factors are difficult to predict and many are beyond the Company’s control. Accordingly, while the Company believes its forward-looking statements to be reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from them will be realized. When used in the Company’s documents or news releases, the words “anticipate,” “believe,” “intend,” “plan,” “estimate,” “expect,” “objective,” “projection,” “forecast,” “budget,” “assume,” “indicate” or similar words or future or conditional verbs such as “will,” “would,” “should,” “can,” “could” or “may” are intended to identify forward-looking statements. Forward-looking statements reflect the Company’s current expectations only as of the date they are made. The Company assumes no duty to update these statements should expectations change or actual results differ from current expectations except as required by applicable laws and regulations. 2 Item 1. Business. General and Historical Development PART I RGC Resources, Inc. ("Resources" or the "Company") was incorporated in the state of Virginia on July 31, 1998, for the primary purpose of becoming the holding company for Roanoke Gas Company (“Roanoke Gas”) and its subsidiaries. Effective July 1, 1999, Roanoke Gas and its subsidiaries were reorganized into the holding company structure. Resources is currently composed of the following subsidiaries: Roanoke Gas, Diversified Energy Company and RGC Midstream, LLC. Roanoke Gas was organized as a public service corporation under the laws of the Commonwealth of Virginia in 1912. The principal service of Roanoke Gas is the distribution and sale of natural gas to residential, commercial and industrial customers within its service territory in Roanoke, Virginia and the surrounding localities. Roanoke Gas also provides certain non-regulated services which account for most of the non-gas utility revenue of Resources. In July 2015, the Company formed RGC Midstream, LLC, a limited liability company established for the purpose of becoming a 1% investor in Mountain Valley Pipeline, LLC. Mountain Valley Pipeline, LLC was created for the purpose of constructing a natural gas pipeline in West Virginia and Virginia. Additional information regarding this investment is provided under Note 3 of the Company's annual consolidated financial statements and under the Equity Investment in Mountain Valley Pipeline section of Item 7. In March 2016, Resources dissolved its subsidiary, RGC Ventures of Virginia, Inc. ("Ventures"). Ventures contained the operations of Application Resources, Inc., which provided information technology consulting services, and The Utility Consultants, which provided utility and regulatory consulting services to other utilities. Both of these operations were insignificant when compared to the overall activities of Resources and represented less than 0.2% of total revenues and less than 6% of other non-utility revenues. Diversified Energy Company currently has no active operations. Services Roanoke Gas maintains an integrated natural gas distribution system to deliver natural gas purchased from suppliers to residential, commercial and industrial users in its service territory. The schedule below is a summary of customers, delivered volumes (expressed in decatherms), revenues and margin as a percentage of the total for each category: Residential Commercial Industrial Other Utility Other Non-Utility Total Percent Total Value Residential Commercial Industrial Other Utility Other Non-Utility Total Percent Total Value Customers Volume Revenue Margin 2016 91.2% 8.7% 0.1% 0.0% 0.0% 100.0% 59,635 38% 31% 31% 0% 0% 100% 57% 33% 7% 1% 2% 100% 60% 25% 11% 2% 2% 100% 8,842,605 $ 59,063,291 $ 31,564,914 Customers Volume Revenue Margin 2015 91.2% 8.7% 0.1% 0.0% 0.0% 100.0% 59,080 40% 30% 30% 0% 0% 100% 58% 33% 6% 1% 2% 100% 58% 26% 11% 3% 2% 100% 9,875,007 $ 68,189,607 $ 30,206,433 3 Residential Commercial Industrial Other Utility Other Non-Utility Total Percent Total Value Customers Volume Revenue Margin 2014 91.2% 8.7% 0.1% 0.0% 0.0% 100.0% 58,553 40% 29% 31% 0% 0% 100% 57% 34% 6% 1% 2% 100% 58% 25% 12% 3% 2% 100% 10,087,651 $ 75,016,134 $ 29,337,089 Roanoke Gas’ regulated natural gas distribution business accounted for approximately 98% of Resources total revenues for fiscal years ending September 30, 2016, 2015 and 2014. The tables above indicates that residential customers represent over 91% of the Company’s customer total; however, they represent less than 50% of the total gas volumes delivered and more than half of the Company’s consolidated revenues and margin. Industrial customers include primarily transportation customers that purchase their natural gas requirements directly from a supplier other than the Company and utilize Roanoke Gas’ natural gas distribution system for delivery to their operations. Most of the revenue billed for these customers relates only to transportation service, and not to the purchase of natural gas, causing total revenues generated by these deliveries to be approximately 7% of total revenues, even though they represent 31% of total natural gas deliveries for the year ended September 30, 2016 and approximately 11% to 12% of gross margin for each of the years presented. The Company’s revenues are affected by changes in gas costs as well as by changes in consumption volume due to weather and economic conditions and changes in the non gas portion of customer billing rates. Increases or decreases in the cost of natural gas are passed on to customers through the purchased gas adjustment mechanism as explained in further detail in Note 1 of the Company’s annual consolidated financial statements. Significant increases in gas costs may cause customers to conserve or, in the case of industrial customers, to switch to alternative energy sources. The Company’s residential and commercial sales are seasonal and temperature-sensitive as the majority of the gas sold by Roanoke Gas to these customers is used for heating. For the fiscal year ended September 30, 2016, approximately 64% of the Company’s total DTH of natural gas deliveries and 72% of the residential and commercial deliveries were made in the five-month period of November through March. These percentages are below the prior two fiscal years due to lower volumes attributable to a much warmer heating season. Total natural gas deliveries were 8.8 million DTH, 9.9 million DTH and 10.1 million DTH in fiscal 2016, 2015 and 2014, respectively. Suppliers Roanoke Gas relies on multiple interstate pipelines including those operated by Columbia Gas Transmission Corporation, LLC and Columbia Gulf Transmission Corporation, LLC (together “Columbia”), and East Tennessee Natural Gas, LLC (“East Tennessee”), Tennessee Gas Pipeline, Midwestern Gas Transmission Company and Saltville Gas Storage Company, LLC to transport natural gas from the production and storage fields to Roanoke Gas’ distribution system. Roanoke Gas is directly served by two pipelines, Columbia and East Tennessee. Columbia historically has delivered between 50% and 60% of the Company’s gas supply, while East Tennessee delivers the balance of the Company’s requirements. The rates paid for natural gas transportation and storage services purchased from the interstate pipeline companies are established by tariffs approved by the Federal Energy Regulatory Commission ("FERC"). These tariffs contain flexible pricing provisions, which, in some instances, authorize these transporters to reduce rates and charges to meet price competition. The current pipeline contracts expire at various times from 2017 to 2022. The Company anticipates being able to renew these contracts or enter into other contracts to meet customers’ continued demand for natural gas. The Company manages its pipeline contracts and liquefied natural gas storage (“LNG”) facility in order to provide for sufficient capacity to meet the natural gas demands of its customers. The maximum daily winter capacity for delivery into Roanoke Gas’ distribution system under the interstate pipelines is 78,606 DTH per day. The LNG facility, which is capable of storing up to 200,000 DTH of natural gas in a liquid state for use during peak demand, has the capability of providing an additional 27,000 DTH per day. Combined, the pipelines and LNG facility can provide more than 105,000 DTH on a single winter day. 4 The Company uses multi-year contracts to meet its natural gas supply needs. The Company currently contracts with Sequent Energy Management, L.P. to manage its pipeline transportation, storage rights, gas supply inventories and deliveries and serve as the primary supplier of natural gas for Roanoke Gas. Natural gas purchased under the asset management agreement is priced at indexed-based market prices as reported in major industry pricing publications. The Company expects its firm supply agreements will be sufficient to meet customer demands for natural gas during the term of the agreement, which expires March 31, 2018. The Company uses summer storage programs to supplement gas supply requirements during the winter months. During the summer months, the Company injects gas into its LNG facility. In addition, the Company has contracted for storage capacity from Columbia, Tennessee Gas Pipeline and Saltville Gas Storage Company, LLC for a combined total of more than 2.4 million DTH of storage capacity. The balance of the Company’s annual natural gas requirements are met primarily through market purchases made by its asset manager. Competition The Company’s natural gas utility operates in a regulated, monopolistic environment. Roanoke Gas currently holds the only franchises and/or certificates of public convenience and necessity to distribute natural gas in its Virginia service areas. These franchises generally extend for multi-year periods and are renewable by the municipalities, including exclusive franchises in the cities of Roanoke and Salem and the Town of Vinton, Virginia. During fiscal 2016, all three franchise agreements were renewed for a term of 20 years with expiration dates of December 31, 2035. Management anticipates that the Company will be able to renew all of its franchises when they expire. There can be no assurance, however, that a given jurisdiction will not refuse to renew a franchise or will not, in connection with the renewal of a franchise, attempt to impose restrictions or conditions that could adversely affect the Company’s business operations or financial condition. Certificates of public convenience and necessity, issued by the Virginia State Corporation Commission (the “SCC”), are of perpetual duration and subject to compliance with regulatory standards. Although Roanoke Gas has exclusive rights for the distribution of natural gas in its service area, the Company competes with suppliers of other forms of energy such as fuel oil, electricity, propane, coal and solar. Competition can be intense among the other energy sources with the primary driver being price in most instances. This is particularly true for those industrial applications that have the ability to switch to alternative fuels. The relationship between supply and demand has the greatest impact on the price of natural gas. Greater demand for natural gas for electric generation and other uses can provide upward pressure on the price of natural gas. Currently, a plentiful supply of natural gas, mostly due to improved drilling and extraction processes in shale formations, has served to maintain prices at lower levels. The Company continues to see a demand for its product and extends service to the new residential construction markets located along or near gas distribution mains in its service area. Although new construction activity has been limited over the last few years, the Company has been able to grow its customer base through customers converting from an alternative energy source to natural gas. Regulation In addition to the regulatory requirements generally applicable to all companies, Roanoke Gas is also subject to additional regulation at the federal, state and local levels. At the federal level, the Company is subject to pipeline safety regulations issued by the Department of Transportation and the Pipeline and Hazardous Materials Safety Administration. At the state level, the SCC performs regulatory oversight including the approval of rates and other charges for natural gas sold to customers, the approval of agreements between or among affiliated companies involving the provision of goods and services, pipeline safety, and certain other corporate activities of the Company, including mergers and acquisitions related to utility operations. At the local level, Roanoke Gas is further regulated by the municipalities and localities that grant franchises for the placement of gas distribution pipelines and the operation of gas distribution networks within their jurisdictions. Employees At September 30, 2016, Resources had 126 full-time employees and 132 total employees. As of that date, 34 employees, or 27% of the Company’s full-time employees, belonged to the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied-Industrial International Union, Local No. 515 and were represented under a collective 5 bargaining agreement. The union has been in place at the Company since 1952. The current collective bargaining agreement will expire on July 31, 2020. Management maintains an amicable relationship with the union. Website Access to Reports The Company’s website address is www.rgcresources.com. Information appearing on this website is not incorporated by reference in and is not a part of this annual report. The Company files reports with the Securities and Exchange Commission ("SEC"). A copy of this annual report, as well as other recent annual and quarterly reports are available on the Company's website. You may read and copy these filings with the SEC at the SEC public reference room at 100 F Street, NE, Washington, D.C. 20549. Information on the operation of the Public Reference Room can be obtained by calling the SEC at 1-800-SEC-0330. The SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding the Company’s filings at www.sec.gov, which is hyper-linked on the Company's website and is where you may obtain other Company filings with the SEC. Item 1A. Risk Factors Please carefully consider the risks described below regarding the Company. These risks are not the only ones faced by the Company. Additional risks not presently known to the Company or that the Company currently believes are immaterial may also impair business operations and financial results. If any of the following risks actually occur, the Company’s business, financial condition or results of operations could be adversely affected. In such case, the trading price of the Company’s common stock could decline and an investor could lose all or part of his, her or its investment. Availability of adequate and reliable pipeline capacity. The Company is currently served directly by two interstate pipelines. These two pipelines carry 100% of the natural gas transported to the Company’s distribution system. Depending on weather conditions and the level of customer demand, failure of one or both of these interstate transmission pipelines could have a major impact on the Company’s ability to meet customer demand for natural gas and adversely affect the Company’s earnings as a result of lost revenue and the cost of service restoration. Risks associated with the operation of a natural gas distribution pipeline and LNG storage facility. Numerous potential risks are inherent in the operation of a natural gas distribution system and LNG storage facility, including unanticipated or unforeseen events that are beyond the control of the Company. Examples of such events include adverse weather conditions, acts of terrorism or sabotage, accidents, equipment failure, failure of upstream pipelines and storage facilities, as well as catastrophic events such as explosions, fires, earthquakes, floods, or other similar events. These risks could result in injury or loss of life, property damage, pollution and customer service disruption resulting in potentially significant financial losses. The Company maintains insurance policies with financially sound carriers to protect against many of these risks. If losses result from a risk that is not fully covered by insurance, the Company’s financial condition could be significantly impacted if it were unable to recover such losses from customers through the regulatory rate making process. Even if the Company did not incur a direct financial loss as a result of any of the events noted above, it could encounter significant reputational damage from a reliability, safety, integrity or similar viewpoint, potentially resulting in a longer-term negative impact on earnings. Increased compliance and pipeline safety requirements and fines. The Company is committed to the safe and reliable delivery of natural gas to its customers. Working in concert with this commitment are numerous laws and regulations at both the federal and state levels. The Company is subject to ongoing inspections and reviews. Failure to comply with such requirements could result in the levy of significant fines. There are inherent risks that may be beyond the Company’s control, including third party actions, which could result in damage to pipeline facilities, injury and even death. Such incidents could subject the Company to lawsuits, large fines, increased scrutiny and loss of customers, all of which could have a significant effect on the Company’s financial position and results of operation. Investment in Mountain Valley Pipeline. The success of the Company's investment in Mountain Valley Pipeline, LLC (the "LLC") is predicated on several key factors including but not limited to the ability of all investors to meet their capital calls when due, the timely approval of the pipeline project by FERC and completing the construction of the pipeline within the targeted time frame and 6 budget. Any significant delay, cost over-run or the failure to receive the requisite approvals could have a significant effect on the Company's earnings and financial position. In addition, there are also numerous risks facing the LLC over time, which in turn could adversely affect the Company's earnings and financial performance through its 1% investment. The LLC's ability to complete construction of, and capital improvement to, facilities on schedule and within budget may be adversely affected by escalating costs for materials and labor and regulatory compliance, inability to obtain or renew necessary licenses, rights-of-way, permits or other approvals on acceptable terms or on schedule, disputes involving contractors, labor organizations, land owners, governmental entities, environmental groups, Native American and aboriginal groups, and other third parties, negative publicity, transmission interconnection issues, and other factors. If any development project or construction or capital improvement project is not completed, is delayed or is subject to cost overruns, certain associated costs may not be approved for recovery or be recovered through regulatory mechanisms that may otherwise be available, and the LLC could become obligated to make delay or termination payments or become obligated for other contractual damages, could experience the loss of tax credits or tax incentives, or delayed or diminished returns, and could be required to write-off all or a portion of its investment in the project. Any of these events could have a material adverse effect on the LLC’s business, financial condition, results of operations and prospects. The LLC may face risks related to project siting, financing, construction, permitting, governmental approvals and the negotiation of project development agreements that may impede its development and operating activities. The LLC must periodically apply for licenses and permits from various local, state, federal and other regulatory authorities and abide by their respective conditions. Should the LLC be unsuccessful in obtaining necessary licenses or permits on acceptable terms, should there be a delay in obtaining or renewing necessary licenses or permits or should regulatory authorities initiate any associated investigations or enforcement actions or impose related penalties or disallowances on the LLC, the LLC’s business, financial condition, results of operations and prospects could be materially adversely affected. Any failure to negotiate successful project development agreements for new facilities with third parties could have similar results. The LLC’s gas infrastructure facilities and other facilities are subject to many operational risks. Operational risks could result in, among other things, lost revenues due to prolonged outages, increased expenses due to monetary penalties or fines for compliance failures, liability to third parties for property and personal injury damage, a failure to perform under applicable sales agreements and associated loss of revenues from terminated agreements or liability for liquidated damages under continuing agreements. The consequences of these risks could have a material adverse effect on the LLC’s business, financial condition, results of operations and prospects. Uncertainties and risks inherent in operating and maintaining the LLC's facilities include, but are not limited to, risks associated with facility start-up operations, such as whether the facility will achieve projected operating performance on schedule and otherwise as planned. The LLC’s business, financial condition, results of operations and prospects can be materially adversely affected by weather conditions, including, but not limited to, the impact of severe weather. Threats of terrorism and catastrophic events that could result from terrorism, cyber-attacks, or individuals and/or groups attempting to disrupt the LLC’s business, or the businesses of third parties, may materially adversely affect the LLC’s business, financial condition, results of operations and prospects. Supply disruptions due to weather or other forces. Hurricanes and other natural or man-made disasters could damage or inhibit production and/or pipeline transportation facilities, which could result in decreased supplies of natural gas. Decreased supplies could result in an inability to meet customer demand leading to higher prices or service disruptions. Disasters could also lead to additional governmental regulations that limit production activity or increase production and transportation costs. Security incident or cyber-attacks on the Company’s computer or information systems. A security incident on the Company’s information systems from cyber-attacks or other sources could lead to disruptions in natural gas deliveries or compromise the safety of the natural gas distribution system. Such attacks could also result in corruption of the Company’s financial information or the unauthorized release of confidential customer, employee or vendor information. The Company takes reasonable precautions to safeguard its computer systems from attack; however, there is no guarantee that Company processes will adequately protect against unauthorized access to data. In the event of a successful attack, the Company could be exposed to material financial and reputational risks. General downturn in the economy or prolonged period of slow economic recovery. A weak or poorly performing economy can negatively affect the Company’s profitability. An economic downturn can result in loss of commercial and industrial customers due to plant closings, a loss of residential customers as well as 7 slow or declining growth in new customer additions, all of which would result in reduced sales volumes and lower revenues. An economic downturn could also result in rising unemployment and other factors that could lead to a loss of customers and an increase in customer delinquencies and bad debt expense. Environmental laws or regulations. Passage of new environmental legislation or implementation of regulations that mandate reductions in greenhouse gas emissions or other similar restrictions could have a negative effect on the Company’s core operations and its investment in the Mountain Valley Pipeline, LLC. Natural gas is a clean and efficient energy source; however, the combustion of natural gas results in carbon related emissions. Such legislation could impose limitations on greenhouse gas emissions, require funding of new energy efficiency objectives, impose new operational requirements or lead to other additional costs to the Company. Regulations restricting or prohibiting the use of coal as a fuel for electric power generation could increase the demand for natural gas, potentially resulting in natural gas supply concerns and higher cost for natural gas. Legislation or regulations could limit the exploration and development of natural gas reserves, making the price of natural gas less competitive and less attractive as a fuel source for consumers, resulting in reduced deliveries and earnings. Access to capital to maintain liquidity. The Company relies on a variety of capital sources to operate its business and fund capital expenditures, including internally generated cash from operations, short-term borrowings under its line-of-credit, proceeds from stock issued under the Dividend Reinvestment and Stock Purchase Plan and other sources. Access to a line-of-credit is essential to provide seasonal funding of natural gas operations and provide capital budget bridge financing. Access to capital markets and other long-term funding sources is important to provide more predictable financing for capital outlays and funding of the LLC investment. The ability of the Company to maintain and renew its line-of-credit and to secure longer-term financing is critical to operations. Adverse market trends or deterioration in the financial condition of the Company could increase the cost of borrowing or limit the Company’s ability to secure adequate funding. Inability to attract and retain professional and technical employees.. The ability to implement the Company’s business strategy and serve customers is dependent upon employing talented professionals and attracting, training, developing and retaining a skilled workforce. As the Company will be facing retirements of key personnel over the next several years, the failure to replace those departing employees with skilled and qualified employees could increase operating costs and expose the Company to other operational and financial risks. Regulatory actions or failure to obtain timely rate relief could decrease future profitability. The Company’s natural gas operations are regulated by the SCC. The SCC approves the rates that the Company charges its natural gas customers. If the SCC did not allow rates that provided for the timely recovery of costs or a reasonable rate of return on investment in natural gas distribution facilities, earnings could be negatively impacted. Issuance of debt and equity are also subject to SCC regulation and approval. Delays or lack of approvals could inhibit the ability to access capital markets and negatively impact liquidity or earnings. Insurance coverage may not be sufficient. The Company currently has liability and property insurance in place to cover a variety of exposures and perils. Although management considers the level of coverage to be appropriate considering the current environment, the insurance policies are subject to certain limits and deductibles. Insurance coverage for risks against which the Company and its industry peers typically insure may not be offered in the future or such policies may expand exclusions that limit the amount of coverage or remove it completely as an insured event. Furthermore, litigation awards continue to increase significantly and the limits of insurance may not keep pace accordingly. The proceeds received from any such insurance may not be paid in a timely manner. The occurrence of any of the foregoing could have a material adverse effect on the Company’s financial position, results of operations and cash flows. The cost of providing post-retirement benefits and related funding obligations may increase. The costs of providing defined benefit pension and retiree medical plans are dependent on a number of factors such as the rates of return on plan assets, discount rates used in determining plan liabilities, the level of interest rates used to 8 measure the required minimum funding levels of the plan, future government regulation, changes in life expectancy, and required or voluntary contributions made to the plan. Changes in actuarial assumptions and differences between the assumptions and actual results, as well as a significant decline in the value of investments that fund these plans, if not offset or mitigated by a decline in plan liabilities, could increase the expense of these plans and require significant additional funding. Both funding obligations and increased expense could have a material impact on the Company's financial position, results of operation and cash flows. Volatility in the price and availability of natural gas. Natural gas purchases represent the single largest expense of the Company. Even with increasing demand from other areas, including electric generation, natural gas prices are currently expected to remain stable in the near term, although there can be no guarantee to that effect. However, if restrictions on drilling for natural gas in the shale rock formations are imposed at either federal, state or local levels due to environmental or other concerns or other exploration and development restrictions on conventional drilling are enacted, the price of natural gas could escalate. The economic viability of the LLC could be significantly impacted by such restrictions. Furthermore, if demand for natural gas increases at a rate in excess of current expectations, natural gas prices could also face upward pressure. Increasing natural gas prices could result in declining sales as well as increases in bad debt expense. Business activities are concentrated in a limited geographic region. Changes in the Roanoke Valley’s economy, politics, regulations and weather patterns could negatively impact the existing customer base, leading to declining usage patterns and financial condition of customers, both of which could adversely affect earnings. Weather conditions may cause revenues and earnings to vary from year to year. The Company’s revenues and earnings are dependent upon weather conditions, specifically winter weather. The Company’s rate structure currently has a weather normalization adjustment factor that results in either a recovery or refund of revenues due to any variation from the 30-year average for heating degree-days. If the provision for the weather normalization adjustment were removed from its rate structure, the Company would be exposed to a much greater risk related to weather variability resulting in earnings volatility. A colder than normal winter could cause the Company to incur higher than normal operating and maintenance costs. Competition from other energy providers. The Company competes with other energy providers in its service territory, including those that provide electricity, propane, coal, fuel oil and solar. Price is a significant competitive factor. Higher natural gas costs or decreases in the price of other energy sources may enhance competition and encourage customers to convert their gas-fired equipment to systems that use alternative energy sources, thus lowering natural gas deliveries and earnings. Price considerations could also inhibit customer and revenue growth if builders and developers do not perceive natural gas to be a better value than other energy options and elect to install heating systems that use an energy source other than natural gas. Failure to comply with debt covenant requirements could lead to adverse financial consequences that could affect the Company's liquidity and ability to borrow funds. The Company's long-term debt obligations and bank line of credit contain financial covenants. Noncompliance with any of these covenants could result in an event of default which, if not cured or waived, could accelerate payment on outstanding debt obligations or cause prepayment penalties. In such an event, the Company may not be able to refinance or repay all of its indebtedness, pay dividends or have sufficient liquidity to meet operating and capital expenditure requirements. Any such acceleration would cause a material adverse change in our financial condition. Inability to complete necessary or desirable pipeline expansion or infrastructure development projects may delay or prevent the Company from adequately serving its customers or expanding its distribution system. In order to serve new customers or expand service to existing customers, the Company needs to maintain, expand or upgrade its distribution, transmission and/or storage infrastructure, including new pipeline installation. Various factors may prevent or delay the completion of such projects or make them more costly, such as the inability to obtain required approval from local, state and/or federal regulatory and governmental bodies, public opposition to the projects, inability to obtain adequate financing, competition for labor and materials, construction delays, cost overruns, 9 and an inability to negotiate acceptable agreements relating to rights-of-way, construction or other material development components. As a result, the Company may not be able to adequately serve existing customers or support customer growth, which would negatively impact earnings. Item 1B. Unresolved Staff Comments. Not applicable. Item 2. Properties. Included in “Utility Plant” on the Company’s consolidated balance sheet are storage plant, transmission plant, distribution plant and general plant of Roanoke Gas as categorized by natural gas utilities. The Company has approximately 1,132 miles of transmission and distribution pipeline with transmission and distribution plant representing more than 86% of the total investment in plant. The transmission and distribution pipelines are located on or under public roads and highways or private property for which the Company has obtained the legal authorization and rights to operate. Roanoke Gas owns and operates eight metering stations through which it measures and regulates the gas being delivered by its suppliers. These stations are located at various points throughout the Company’s distribution system. Roanoke Gas also owns a liquefied natural gas storage facility located in Botetourt County that has the capacity to store up to 220,000 DTH of natural gas. The Company’s executive, accounting and business offices, along with its maintenance and service departments, are located on Kimball Avenue in Roanoke, Virginia. Although the Company considers its present properties to be adequate, management continues to evaluate the adequacy of its current facilities as additional needs arise. Item 3. Legal Proceedings. The Company is not known to be a party to any pending legal proceedings. Item 4. Mine Safety Disclosures. Not applicable. 10 Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. PART II Market Information Resources' common stock is listed on the NASDAQ Global Market under the trading symbol RGCO. Payment of dividends is within the discretion of the Board of directors and will depend on, among other factors, earnings, capital requirements, and the operating and financial condition of the Company. Year Ending September 30, 2016 First Quarter Second Quarter Third Quarter Fourth Quarter Year Ending September 30, 2015 First Quarter Second Quarter Third Quarter Fourth Quarter $ $ Range of Bid Prices Cash Dividends High Low Declared $ $ 23.94 23.39 26.00 25.09 22.45 25.67 22.99 21.96 $ $ 20.05 20.66 21.45 22.32 19.28 20.20 19.78 19.95 0.2025 0.2025 0.2025 0.2025 0.1925 0.1925 0.1925 0.1925 As of November 25, 2016, there were 1,192 holders of record of the Company’s common stock. This number does not include all beneficial owners of common stock who hold their shares in “street name.” Comparisons of Cumulative Total Shareholder Returns The following performance graph compares the Company’s total shareholder return from September 30, 2011 through September 30, 2016 with the Dow Jones US Utility Index, a utility based index, and the Standard & Poor’s 500 Stock Index (S&P 500 Index), a broad market index. The graph below reflects the value of a hypothetical investment of $100 made September 30, 2011 in the Company’s common stock and in each index as of September 30, 2016, assuming the reinvestment of all dividends. Historical stock price performance as reflected on the graph is not indicative of future price performance. The total value at the end of the five years was $163 for the Company’s common stock, $192 for the Dow Jones US Utilities Index and $213 for the S&P 500 Index. 11 A summary of the Company’s equity compensation plans follows as of September 30, 2016: Plan category Equity compensation plans approved by security holders Equity compensation plans not approved by security holders Total (a) (b) (c) Number of securities to be issued upon exercise of outstanding options, warrants and rights Weighted-average exercise price of outstanding options, warrants and rights Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) 58,200 — 58,200 $20.25 — $20.25 110,307 — 110,307 12 Item 6. Selected Financial Data. Year Ending September 30, 2016 2015 2014 2013 2012 Operating Revenues Gross Margin Operating Income Net Income $ 59,063,291 $ 68,189,607 $ 75,016,134 $ 63,205,666 $ 58,799,687 31,564,914 30,206,433 29,337,089 27,602,891 26,933,097 11,212,092 10,006,192 5,806,866 5,094,415 9,681,868 4,708,440 8,795,055 4,262,052 8,786,535 4,296,745 Basic Earnings Per Share Cash Dividends Declared Per Share Book Value Per Share Average Shares Outstanding Total Assets (1) $ $ $ 1.22 0.81 11.63 $ $ $ 1.08 0.77 11.14 $ $ $ 1.00 0.74 11.02 $ $ $ 0.91 1.72 10.51 $ $ $ 0.92 0.70 10.85 4,766,604 4,728,210 4,715,478 4,698,727 4,647,439 $165,552,849 $145,847,194 $137,423,321 $121,658,797 $127,363,410 Long-Term Debt (Less Unamortized Debt Expense) $ 33,636,051 $ 30,316,573 $ 30,306,919 $ 12,984,169 $ 12,978,681 Stockholders' Equity 55,667,072 52,840,991 52,020,847 49,502,422 50,682,930 Shares Outstanding at Sept. 30 4,788,289 4,741,498 4,720,378 4,709,326 4,670,567 (1)Total assets for the prior years were revised to reflect the reclassification of current deferred tax assets against deferred tax liabilities as provided for in ASU 2015-17, Income Taxes: Balance Sheet Classification of Deferred Taxes. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. Forward-Looking Statements This report contains forward-looking statements that relate to future transactions, events or expectations. RGC Resources, Inc. (“Resources” or the “Company”) may publish forward-looking statements relating to such matters as anticipated financial performance, business prospects, technological developments, new products, research and development activities and similar matters. These statements are based on management’s current expectations and information available at the time of such statements and are believed to be reasonable and are made in good faith. The Private Securities Litigation Reform Act of 1995 provides a safe harbor for forward-looking statements. In order to comply with the terms of the safe harbor, the Company notes that a variety of factors could cause the Company’s actual results and experience to differ materially from the anticipated results or expectations expressed in the Company’s forward-looking statements. The risks and uncertainties that may affect the operations, performance, development and results of the Company’s business include, but are not limited to, those set forth in the following discussion and within Item 1A “Risk Factors” of this Annual Report on Form 10-K. All of these factors are difficult to predict and many are beyond the Company’s control. Accordingly, while the Company believes its forward-looking statements to be reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from them will be realized. When used in the Company’s documents or news releases, the words “anticipate,” “believe,” “intend,” “plan,” “estimate,” “expect,” “objective,” “projection,” “forecast,” “budget,” “assume,” “indicate” or similar words or future or conditional verbs such as “will,” “would,” “should,” “can,” “could” or “may” are intended to identify forward-looking statements. Forward-looking statements reflect the Company’s current expectations only as of the date they are made. The Company assumes no duty to update these statements should expectations change or actual results differ from current expectations except as required by applicable laws and regulations. 13 Overview Resources is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately 59,600 residential, commercial and industrial customers in Roanoke, Virginia, and the surrounding localities, through its Roanoke Gas Company (“Roanoke Gas”) subsidiary. Roanoke Gas also provides certain unregulated services. Resources also formed a wholly-owned subsidiary, RGC Midstream, LLC ("Midstream"), to invest in the Mountain Valley Pipeline, LLC (the "LLC"). On October 1, 2015, Midstream executed agreements to become a 1% member in the LLC. More information is provided under the Equity Investment in Mountain Valley Pipeline section below. The unregulated operations represent less than 2% of revenues and margins of Resources. The utility operations of Roanoke Gas are regulated by the Virginia State Corporation Commission (“SCC”), which oversees the terms, conditions, and rates to be charged to customers for natural gas service, safety standards, extension of service, accounting and depreciation. The Company is also subject to federal regulation from the Department of Transportation in regard to the construction, operation, maintenance, safety and integrity of its transmission and distribution pipelines. The Federal Energy Regulatory Commission ("FERC") regulates prices for the transportation and delivery of natural gas to the Company’s distribution system and underground storage services. The Company is also subject to other regulations which are not necessarily industry specific. The Company is committed to the safe and reliable delivery of natural gas to its customers. Since 1991, the Company has placed an emphasis on the modernization of its distribution system through the renewal and replacement of its cast iron and bare steel natural gas distribution pipelines. With recent regulatory actions placing a greater emphasis on pipeline safety, the Company continues to focus its efforts on completing its renewal and replacement program. The Company completed the replacement of all cast iron pipe in fiscal 2016 and replacement of all bare steel pipe in the first quarter of fiscal 2017. The Company will continue its renewal program with plans to replace first generation, pre-1973 plastic pipe over the next five years. The Company is also dedicated to the safeguarding of its information technology systems. These systems contain confidential customer, vendor and employee information as well as important financial data. There is risk associated with the unauthorized access of this information with a malicious intent to corrupt data, cause operational disruptions, or compromise information. Management believes it has taken reasonable security measures to protect these systems from cyber attacks and other types of incidents; however, there can be no guarantee that an incident will not occur. In the event of a cyber incident, the Company will execute its Security Incident Response Plan to assist with managing the incident. The Company also maintains cyber-insurance coverage to mitigate financial implications resulting from a cyber incident. Over 98% of the Company’s revenues are derived from the sale and delivery of natural gas to Roanoke Gas customers. The SCC authorizes the rates and fees the Company charges its customers for these services. These rates are designed to provide the Company with the opportunity to recover its gas and non-gas expenses and to earn a reasonable rate of return for shareholders based on normal weather. Normal weather refers to the average number of heating degree days (an industry measure by which the average daily temperature falls below 65 degrees Fahrenheit) over the previous 30- year period. As the Company’s business is seasonal in nature, volatility in winter weather and the commodity price of natural gas, can impact the effectiveness of the Company’s rates in recovering its costs and providing a reasonable return for its shareholders. In order to mitigate the effect of weather variations, the Company has certain approved rate mechanisms in place that help provide stability in earnings, adjust for volatility in the price of natural gas and provide a return on increased infrastructure investment. These mechanisms include a purchased gas adjustment factor ("PGA"), weather normalization adjustment factor ("WNA"), inventory carrying cost revenue ("ICC") and a Steps to Advance Virginia Energy ("SAVE") adjustment rider. The Company's approved billing rates include a component designed to allow for the recovery of the cost of natural gas used by its customers. The cost of natural gas is considered a pass-through cost and is independent of the non-gas rates of the Company. This rate component, referred to as the PGA clause, allows the Company to pass along to its customers increases and decreases in natural gas costs incurred by its regulated operations. On a quarterly basis, the Company files a PGA rate adjustment request with the SCC to adjust the gas cost component of its rates up or down depending on projected price and activity. Once administrative approval is received, the Company adjusts the gas cost component of its rates to reflect the approved amount. As actual costs will differ from the projections used in establishing the PGA rate, the Company will either over-recover or under-recover its actual gas costs during the period. The difference 14 between actual costs incurred and costs recovered through the application of the PGA is recorded as a regulatory asset or liability. At the end of the annual deferral period, the balance is amortized over an ensuing 12-month period as amounts are reflected in customer billings. The WNA reduces the volatility in earnings due to the variability in temperatures during the heating season. The WNA is based on the most recent 30-year temperature average. The WNA provides the Company with a level of earnings protection when weather is warmer than normal and provides its customers with price protection when the weather is colder than normal. The WNA allows the Company to recover from its customers the lost margin (excluding gas costs) from the impact of weather that is warmer than normal and correspondingly requires the Company to refund the excess margin earned for weather that is colder than normal. The WNA year runs from April through March of each year. Any billings or refunds related to the WNA are completed following the end of the WNA year. For the fiscal year ended September 30, 2016, the Company recorded $1,318,000 in additional revenue from the WNA for weather that was approximately 13% warmer than normal. During the fiscal year ended September 30, 2015, the Company had reduced revenue by $609,000 due to the WNA for weather that was approximately 6.5% colder than normal. During the fiscal year ended September 30, 2014, the Company recorded a reduction in revenue of $563,000 to reflect the WNA adjustment for weather that was approximately 9% colder than normal. Prior to April 2014, the WNA provided for a weather band of 3% above and below normal whereby no WNA would be calculated until weather was outside the 3% band. The Company also has an approved rate structure in place that mitigates the impact of financing costs of its natural gas inventory. Under this rate structure, Roanoke Gas recognizes revenue for the financing costs, or “carrying costs”, of its investment in natural gas inventory. The ICC factor applied to average inventory is based on the Company’s weighted- average cost of capital including interest rates on short-term and long-term debt and the Company’s authorized return on equity. During times of rising gas costs and rising inventory levels, the Company recognizes ICC revenues to offset higher financing costs associated with higher inventory balances. Conversely, during times of decreasing gas costs and declining inventory balances, the Company recognizes less carrying cost revenue as financing costs are lower. In addition, ICC revenues are impacted by changes in the weighted-average cost of capital. The decline in commodity prices during the 2016 summer storage refill period continued the downward trend on the cost of gas in storage. Although total average volumes in storage were higher during the current year, the lower commodity price of gas resulted in a lower cost of gas in storage, which is the basis for calculating ICC revenues. Furthermore, the increase in the utilization of the line-of-credit resulted in a greater allocation of the lower-rate debt in the overall weighted-average cost of capital, thereby reducing the ICC factor. The combination of lower average storage gas inventories in terms of cost and a lower ICC factor resulted in a $182,000 decline in ICC revenues in fiscal 2016. This decline follows a reduction of $46,000 in ICC revenues during the prior fiscal year, resulting from the decline in price of gas delivered to storage. Based on the current natural gas futures prices, the average dollar balance of gas in storage may decline next year, but the decline is expected to be at a smaller level. Generally, as investment in natural gas inventory increases so does the level of borrowing under the Company’s line-of- credit. However, as the carrying cost factor used in determining carrying cost revenues is based on the Company’s weighted-average cost of capital, carrying cost revenues do not directly correspond with incremental short-term financing costs. Therefore, when inventory balances decline due to a reduction in commodity prices, net income will decline as carrying cost revenues decrease by a greater amount than short-term financing costs decrease. The inverse occurs when inventory costs increase. The Company’s non-gas rates are designed to allow for the recovery of non-gas related expenses and provide a reasonable return to shareholders. These rates are determined based on the filing of a formal rate application with the SCC utilizing historical information including investment in natural gas facilities. Generally, investments related to extending service to new customers are recovered through the non-gas rates currently in place. The investment in replacing and upgrading existing infrastructure is not recoverable until a formal rate application is made to include the additional investment and new non-gas rates are approved. The SAVE Plan and Rider provides the Company with the ability to recover costs related to these investments on a prospective basis rather than on a historical basis. The SAVE Plan provides a mechanism to recover the related depreciation and expenses and provide a return on rate base of the additional capital investments related to improving the Company's infrastructure until such time a formal rate application is filed to incorporate this investment in the Company's non-gas rates. As the Company did not file for an increase in the non-gas rates during the prior two years and the level of SAVE qualifying capital investment continues to grow, SAVE Plan revenues have increased significantly. The Company recognized approximately $2,538,000, $1,308,000 and $292,000 in SAVE Plan revenues for years ended September 30, 2016, 2015 and 2014, respectively. 15 SAVE revenues will be included as part of the non-gas base rates the next time the Company files for a non-gas rate increase. Additional information regarding the SAVE Rider is provided under the Regulatory Affairs section. The economic environment has a direct correlation with business and industrial production, customer growth and natural gas utilization. The local economy has lost some key business activities over the last few years as some companies have either shut down or relocated all or portions of their operations elsewhere. However, the Company continues to experience some customer and sales growth including the addition of a large natural gas fleet refueling station at a commercial customer. In addition, new business ventures have been announced in the Company's service territory that should provide some additional natural gas load over the next few years. The local economy appears relatively stable and should continue to improve absent a major economic setback on a local, regional or national level. Results of Operations Fiscal Year 2016 Compared with Fiscal Year 2015 The table below reflects operating revenues, volume activity and heating degree-days. Operating Revenues Year Ended September 30, 2016 2015 Gas Utilities Other Total Operating Revenues $ $ 58,079,990 983,301 59,063,291 $ $ 67,094,290 1,095,317 68,189,607 $ $ Decrease (9,014,300) (112,016) (9,126,316) Percentage (13)% (10)% (13)% Delivered Volumes Year Ended September 30, Regulated Natural Gas (DTH) Residential and Commercial Transportation and Interruptible Total Delivered Volumes Heating Degree Days (Unofficial) 2016 2015 Decrease Percentage 6,088,108 2,754,497 8,842,605 6,955,594 2,919,413 9,875,007 (867,486) (164,916) (1,032,402) 3,484 4,253 (769) (12)% (6)% (10)% (18)% Total gas utility operating revenues for the year ended September 30, 2016 declined by 13% from the year ended September 30, 2015 primarily due to a combination of lower gas costs and a reduction in natural gas deliveries more than offsetting revenues from the SAVE plan rider and WNA. The average commodity price of natural gas declined by 28% per decatherm sold. Delivered volumes declined primarily due to weather, as reflected in the lower residential and commercial volumes. Industrial consumption also declined, causing a reduction in transportation and interruptible volumes. Residential and commercial deliveries tend to be more weather sensitive as reflected by a 12% decline in volumes on 18% fewer heating degree days. Transportation and interruptible volumes, which are primarily driven by production activities rather than weather, decreased by 6%. Other revenues experienced a 10% decrease. Approximately half of the decrease in other revenues was attributable to the cessation of operations for Utility Consultants during the prior year and Application Resources during the current year. Gross Margin Year Ended September 30, 2016 2015 Increase / (Decrease) Percentage Gas Utility Other Total Gross Margin $ $ 31,070,660 494,254 31,564,914 $ $ 29,656,975 549,458 30,206,433 $ $ 1,413,685 (55,204) 1,358,481 5 % (10)% 4 % 16 Regulated natural gas margins from utility operations increased by 5% from fiscal 2015, primarily as a result of WNA revenues, increasing SAVE Plan revenues and customer base charges related to customer growth more than offsetting lower volumetric margins and ICC revenues. SAVE Plan revenues increased by $1,230,000 as the Company was in the third year of the current SAVE Plan. The growth in SAVE Plan revenues has been fueled by the Company's pipeline renewal program as the Company continues to invest in eligible SAVE Plan infrastructure projects. As noted above, volumetric margin declined due to a reduction in total volumes delivered. Residential and commercial volumes declined due to much warmer weather compared to the prior year. Interruptible and transportation volumes declined due to a combination of reduced activity at one large customer, the closing of another industrial customer's operations during the prior fiscal year and a significant decrease in usage by another industrial customer that uses natural gas as its back up fuel source. The impact of the warmer weather on volumetric margin was offset by the WNA mechanism. As discussed in more detail above, the WNA mechanism allowed the Company to recognize margin related to those natural gas volumes not sold due to the warmer weather. ICC revenues continued to decline with a $182,000 reduction in fiscal 2016 compared to the prior year due to lower commodity prices and a lower ICC factor. Other margins, consisting of non-utility related services, decreased by $55,204 on comparable activity. The Utility Consultants, which ceased activity last year, and Application Resources, which terminated in fiscal 2016, accounted for approximately $25,000 of the reduction in non-utility related margin. The remainder of the decrease in other margins is attributable to the level of activity under these contracts which fluctuates based on customer requirements. In addition, service contracts which generate the majority of the non-utility related revenues are subject to annual or semi- annual renewal provisions and the potential exists that these contracts may not be renewed or extended by the customer which could impact future revenues and margins. The changes in the components of the gas utility margin are summarized below: Customer Base Charge $ 12,364,811 $ 12,240,580 $ 124,231 Twelve Months Ended September 30, 2016 2015 Increase (Decrease) SAVE Plan Volumetric WNA Carrying Cost Other Total 2,538,055 14,099,214 1,317,800 651,492 99,288 1,307,795 15,757,907 (608,560) 833,291 125,962 $ 31,070,660 $ 29,656,975 $ 1,230,260 (1,658,693) 1,926,360 (181,799) (26,674) 1,413,685 Operations and Maintenance Expense - Operations and maintenance expenses declined by $388,799, or 3%, from last year due to much higher overhead capitalization and lower bad debt expenses more than offsetting higher benefit and labor costs. Capitalized overheads, which include general and administrative costs, payroll overheads and engineering costs, increased by 30%, or nearly $873,000, over fiscal 2015 due to higher benefit costs, a 30% increase in capital expenditures and a 38% increase in the amount of LNG produced. In addition, bad debt expense declined by $77,000 due to the combination of reduced sales related to much warmer weather and lower gas costs. Total benefit costs increased by $456,000 due to increased pension and postretirement medical costs related to the amortization of higher actuarial losses attributable to the adoption of a new mortality table that reflects extended life expectancies. Operating and maintenance labor costs increased by $141,000, or 2%, due to normal wage adjustments. The remaining decrease relates to a variety of areas, including the level of contracted and professional services, as the prior year included expenses related to the union contract negotiations and due diligence work related to the investment in the LLC. General Taxes - General taxes increased $56,705, or 4%, primarily due to higher property taxes associated with increases in utility property. Depreciation - Depreciation expense increased by $484,675, or more than 9%, corresponding to a similar increase in utility plant investment. 17 Equity in Earnings of Unconsolidated Affiliate - The investment in Mountain Valley Pipeline began in fiscal 2016 and the $152,864 equity in earnings is primarily composed of allowance for funds used during construction ("AFUDC"). The investment in Mountain Valley Pipeline and the related AFUDC earnings are discussed further under the Equity Investment in Mountain Valley Pipeline section below. Other Expense - Other expense, net, increased by $26,789, or 12%, primarily due to higher pipeline assessments. Interest Expense - Total interest expense increased by $123,902, or 8%, due to a 15% increase in the average debt outstanding. The combination of the investments in Mountain Valley Pipeline and the level of capital expenditures during the year have required increased borrowing. Income Taxes - Income tax expense increased by $495,622, or 16%, on higher pre-tax earnings. The effective tax rate was 38.7% for fiscal 2016 compared to 38.4% for fiscal 2015. Net Income and Dividends - Net income for fiscal 2016 was $5,806,866 compared to $5,094,415 for fiscal 2015. Basic and diluted earnings per share were $1.22 in fiscal 2016 compared to $1.08 in fiscal 2015. Dividends declared per share of common stock were $0.81 in fiscal 2016 compared to $0.77 in fiscal 2015. Fiscal Year 2015 Compared with Fiscal Year 2014 The table below reflects operating revenues, volume activity and heating degree-days. Operating Revenues Year Ended September 30, 2015 2014 Gas Utilities Other Total Operating Revenues $ $ 67,094,290 1,095,317 68,189,607 $ $ 73,865,487 1,150,647 75,016,134 $ $ Decrease (6,771,197) (55,330) (6,826,527) Percentage (9)% (5)% (9)% Delivered Volumes Year Ended September 30, Regulated Natural Gas (DTH) Residential and Commercial Transportation and Interruptible Total Delivered Volumes Heating Degree Days (Unofficial) 2015 2014 Decrease Percentage 6,955,594 2,919,413 9,875,007 7,005,920 3,081,731 10,087,651 (50,326) (162,318) (212,644) 4,253 4,351 (98) (1)% (5)% (2)% (2)% Total gas utility operating revenues for the year ended September 30, 2015 decreased by 9% from the year ended September 30, 2014 primarily due to lower gas costs and a reduction in natural gas deliveries. The average commodity price of natural gas declined by 21% per decatherm sold. Delivered volumes declined due in part to weather, as reflected in the decline in residential and commercial volumes, and a reduction in industrial consumption. Residential and commercial deliveries tend to be more weather sensitive as reflected by a decline of 1% in volumes on 2% fewer heating degree days. Transportation and interruptible volumes, which are primarily driven by production activities rather than weather, decreased by 5%. Other revenues decreased by 5% as well. 18 Gross Margin Year Ended September 30, 2015 2014 Increase / (Decrease) Percentage Gas Utility Other Total Gross Margin $ $ 29,656,975 549,458 30,206,433 $ $ 28,774,213 562,876 29,337,089 $ $ 882,762 (13,418) 869,344 3 % (2)% 3 % Regulated natural gas margins from utility operations increased by 3% from fiscal 2014, primarily as a result of higher SAVE Plan revenues and customer base charges more than offsetting lower volumetric margins and ICC revenues. SAVE Plan revenues increased by $1,016,000. Customer base charges also increased due to modest customer growth. Volumetric margin declined due to a reduction in total volumes delivered. Residential and commercial volumes declined primarily due to slightly warmer weather. Interruptible and transportation volumes declined due to the loss of a customer during fiscal 2015 and decreased usage at two of the Company's larger customers. The effect of the warmer weather was mitigated in part by the WNA mechanism. In fiscal 2014, the WNA mechanism provided for a weather band of 3% variance around normal during the winter heating season while the fiscal 2015 heating season had a 0% weather band. Because the fiscal 2014 year had a 3% weather band in place for part of the year and weather was colder than normal, the Company was able to retain approximately $251,000 in excess margin realized on the 3% weather band, while the fiscal 2015 year WNA with a 0% weather band required the adjustment of margin back to the level expected for normal weather. Other margins, consisting of non-utility related services, decreased by $13,418 on comparable activity. The Utility Consultants, which ceased activity during fiscal 2015, contributed $17,000 to the non-utility related margin. The service contracts that comprise most of the non-utility related activities are subject to annual or semi-annual renewal provisions and the potential exists that these contracts may not be renewed or extended by the customer. In addition, the level of activity under these contracts will fluctuate based on customer requirements which may result in fluctuations in revenues and margins. The changes in the components of the gas utility margin are summarized below: Customer Base Charge $ 12,240,580 $ 12,064,764 $ 175,816 Twelve Months Ended September 30, 2015 2014 Increase (Decrease) SAVE Plan Volumetric WNA Carrying Cost Other Total 1,307,795 15,757,907 (608,560) 833,291 125,962 291,946 15,990,704 (563,187) 879,381 110,605 1,015,849 (232,797) (45,373) (46,090) 15,357 $ 29,656,975 $ 28,774,213 $ 882,762 Operations and Maintenance Expense - Operations and maintenance expenses increased by $103,497, or 1%, in fiscal 2015 compared with fiscal 2014 due to higher benefit costs and professional services and less overhead capitalization more than offsetting reductions in the level of bad debt expense, labor and contracted labor. Employee benefit expenses increased by $260,000 primarily due to higher medical, defined benefit pension plan and postretirement medical plan. The actuarially determined expenses for the pension and postretirement plans increased in fiscal 2015 due to a decline in the discount rate for valuing both plans' liabilities at September 30, 2014. Professional services increased by $77,000 primarily due to legal expenses associated with the new union contract, the formation of the Company's new subsidiary and the due diligence work related to the investment in the Mountain Valley Pipeline. Total capitalized overheads declined by $106,000 because of delays in the production of liquefied natural gas due to maintenance down time, lower capital expenditures and a reduction in the capitalization rate compared to fiscal 2014. Bad debt expense decreased by $61,000 due to lower customer billings resulting from warmer weather and a lower commodity price of gas. Labor and contracted services costs declined by $133,000 due to timing of pipeline right-of- way clearing and prior year costs related to updating the Company's corrosion control processes. The remaining 19 decrease relates to a variety of areas including the level of facility and equipment maintenance, advertising and administrative costs. General Taxes - General taxes increased $46,035, or 3%, primarily due to higher property taxes associated with increases in utility property. Depreciation - Depreciation expense increased by $395,488, or 8%, corresponding to a similar increase in utility plant investment. Other Expense - Other expense, net, increased by $21,909, or 11%, primarily due to an increase in charitable requests related to specific campaigns. Interest Expense - Total interest expense decreased by $314,582, or 17%, due to a lower interest rate on long-term debt. In September 2014, the Company refinanced its $28,000,000 in long-term debt, which had an average interest rate of 6.30% with $30,500,000 in new debt having a rate of 4.26%. Income Taxes - Income tax expense increased by $231,022 on higher pre-tax earnings. The effective tax rate was 38.4% for both fiscal 2015 and 2014. Net Income and Dividends - Net income for fiscal 2015 was $5,094,415 compared to $4,708,440 for fiscal 2014. Basic and diluted earnings per share were $1.08 in fiscal 2015 compared to $1.00 in fiscal 2014. Dividends declared per share of common stock were $0.77 in fiscal 2015 compared to $0.74 in fiscal 2014. Capital Resources and Liquidity Due to the capital intensive nature of the utility business, as well as the related weather sensitivity, the Company’s primary capital needs are for the funding of its continuing construction program, the seasonal funding of its natural gas inventories and accounts receivables and payment of dividends. To meet these needs, the Company relies on its operating cash flows, line-of-credit agreement, long-term debt, and to a lesser extent, capital raised through the Company’s stock plans. Cash and cash equivalents decreased by $341,982 in fiscal 2016 compared to an increase of $135,477 in fiscal 2015 and a decrease of $1,996,467 in fiscal 2014. The following table summarizes the categories of sources and uses of cash: Cash Flow Summary Year Ended September 30, Provided by operating activities Used in investing activities Provided by (used in) financing activities Increase (decrease) in cash and cash equivalents Cash Flows Provided by Operating Activities: 2016 2015 2014 $ 14,921,640 (20,996,501) 5,732,879 $ 16,760,827 (13,750,274) (2,875,076) 6,839,738 (14,698,570) 5,862,365 (341,982) $ 135,477 $ (1,996,467) $ $ The seasonal nature of the natural gas business causes operating cash flows to fluctuate significantly during the year as well as from year to year. Factors, including weather, energy prices, natural gas storage levels and customer collections, all contribute to working capital levels and related cash flows. Generally, operating cash flows are positive during the second and third quarters as a combination of earnings, declining storage gas levels and collections on customer accounts all contribute to higher cash levels. During the first and fourth quarters, operating cash flows generally decrease due to the combination of increases in natural gas storage levels and rising customer receivable balances. Cash provided by operating activities was $14,922,000 in fiscal 2016, $16,761,000 in fiscal 2015 and $6,840,000 in fiscal 2014. Cash provided by operating activities decreased by more than $1,800,000 from last year primarily as a result of a smaller decline in natural gas commodity prices and refunding part of last year's over-collection of gas costs, 20 offset by a greater increase in deferred tax liability due to the subsequent extension of 50% bonus tax depreciation through 2017, higher net income and book depreciation. The average price of gas in storage declined by 13% during fiscal 2016 as natural gas commodity prices continued their decline even though total volumes increased by nearly 5%, resulting in an overall decrease in gas in storage of $724,000. During fiscal 2015, the average price of gas in storage declined by 28% on nearly unchanged volumes resulting in a $3,242,000 decrease in gas in storage from fiscal 2014. In addition, the significant drop in natural gas prices during the prior year resulted in an increase in over-collection of gas costs as the adjustment to the PGA factor used to bill customers for the gas component of rates lagged behind the declining price of gas. As a result, the Company collected $1,900,000 from customers in excess of actual gas costs in fiscal 2015. During fiscal 2016, the Company reduced its over-collection by nearly $1,000,000 as the Company began refunding the excess collections. Subsequent to the issuance of fiscal 2015 financial statements, Congress passed, and the President signed into law, the Protecting Americans from Tax Hikes ("PATH" Act) which extended the 50% bonus depreciation for calendar 2015 through December 31, 2017 and provided for 40% bonus depreciation for calendar 2018 and 30% bonus depreciation for calendar 2019. As a result of the passage of the PATH Act, the Company recorded an adjustment to deferred taxes in the amount of $1,284,000 in the first quarter of fiscal 2016 to recognize the effect of bonus depreciation on the balance of 2015 asset additions in addition to $3,065,000 in deferred tax liability recognized for the effect of 50% bonus depreciation on fiscal 2016 capital additions. As a result of the bonus depreciation extension for 2015, the Company requested and received a refund of $1,600,000 in federal taxes related to the additional deduction claimed on the fiscal 2015 tax return. In comparison, total deferred taxes increased by $2,417,000 in fiscal 2015. A summary of the key components of the cash flows from operating activities is provided below: Cash Flow Provided by Operating Activities: 2016 2015 Increase (Decrease) Twelve Months Ended September 30, Net income Depreciation Decrease in gas in storage Increase / (decrease) in over-collection of gas costs Increase in deferred taxes Other Net Cash Provided by Operations $ Cash Flows Used in Investing Activities: $ 5,806,866 $ 5,094,415 $ 712,451 5,709,525 723,713 (991,739) 4,466,954 (793,679) 14,921,640 $ 5,219,893 3,242,492 2,082,257 2,416,841 (1,295,071) 16,760,827 $ 489,632 (2,518,779) (3,073,996) 2,050,113 501,392 (1,839,187) Investing activities primarily consist of expenditures under the Company’s construction program, which involves a combination of replacing aging bare steel and cast iron pipe with new plastic or coated steel pipe, making improvements to the LNG plant and expansion of its natural gas system to meet the demands of customer growth. The Company’s expenditures related to its pipeline renewal program and other system and infrastructure improvements increased to nearly $18,000,000 in fiscal 2016 from $13,800,000 in fiscal 2015 and $14,700,000 in fiscal 2014. The Company renewed 14.9 miles of natural gas distribution main and replaced 684 services in fiscal 2016. This compares to 10 miles of main and 594 services in fiscal 2015 and 13.6 miles of main and 942 services in fiscal 2014. The Company completed the replacement of its cast iron pipe during fiscal 2016 and finished replacing the remainder of the bare steel pipe in November 2016. The Company also completed the replacement of two natural gas custody transfer stations connected to the East Tennessee transmission line. In addition, the Company’s capital expenditures included costs to extend natural gas distribution mains and services to 495 new customers in fiscal 2016 compared to 609 new customers in fiscal 2015 and 673 in fiscal 2014. Depreciation covered approximately 32% of the current year's capital expenditures compared to 38% for 2015 and 33% for 2014, with the balance provided from other operating cash flows and borrowings under the line-of-credit. Capital expenditures are expected to remain at elevated levels over the next few years. With the replacement of cast iron and bare steel mains completed, renewal efforts will now shift to replacing approximately 45 miles of pre-1973 first generation plastic pipe with current polyethylene pipe. This renewal project is expected to be completed by 2021. The Company has also begun implementation of an automated meter reading system, expected to be completed in fiscal 2017, whereby all customer meters will be retrofitted with transmitters which will allow consumption data to be collected remotely. The current capital budget for fiscal 2017 reflects an increase of more than $3,000,000 in expenditures over fiscal 2016. The Company expects to increase its borrowing activity to meet the funding requirements of these planned expenditures. 21 Investing cash flows also reflect the Company's $3,055,746 funding of its participation in the Mountain Valley Pipeline. The Company expects to invest an additional $32 million over the remaining three-year project period, pending FERC approval. Funding for the investment in the LLC is provided through a combination of a $25 million credit facility, which matures in 2020, and equity capital. More information regarding the credit facility is provided in Note 5 of the Consolidated Financial Statements and under the Equity Investment in Mountain Valley Pipeline section below. Cash Flows Provided by (Used in) Financing Activities: Financing activities generally consist of long-term and short-term borrowings and repayments, issuance of stock and the payment of dividends. As mentioned above, the Company uses its line-of-credit arrangement to fund seasonal working capital and provide temporary financing for capital projects. Cash flows provided by financing activities were $5,733,000 in fiscal 2016 compared to cash used in financing activities of $2,875,000 in fiscal 2015 and cash provided by financing activities of $5,862,000 for fiscal 2014. The combination of greater capital investment related to the pipeline renewal program and other projects, including the Mountain Valley Pipeline, required increased borrowing activity. In fiscal 2015, net borrowing activity under the line-of-credit was nearly unchanged as the Company benefited from higher operating cash flows resulting from declines in the price of natural gas and the extension of 50% bonus depreciation for tax purposes. In 2014, the Company refinanced $28,000,000 of its debt, including $2,238,000 in early termination fees on notes and interest rate swaps with $30,500,000 in unsecured 20-year term notes. The early termination fees were deferred as a regulatory asset and are being amortized over the term of the new notes as a component of interest expense. The $28,000,000 in retired debt had an average interest rate of 6.30% with an effective rate of 6.43%. The new debt has a stated interest rate of 4.26% and an effective rate of 4.67%. The nearly $315,000 reduction in interest expense in fiscal 2015 is entirely due to the refinancing. The Company increased the utilization of its line-of-credit to provide bridge financing for its capital budget for amounts in excess of those provided by operations. Proceeds from the issuance of stock were $1,031,000 under the DRIP plan. Dividends increased as the annualized dividend rate per share went from $0.74 in fiscal 2014 to $0.77 in fiscal 2015 and $0.81 if fiscal 2016. The Company’s consolidated capitalization was 62.2% equity and 37.8% long-term debt at September 30, 2016. This compares to 63.4% equity and 36.6% long-term debt at September 30, 2015. Effective March 31, 2016, the Company entered into a new line-of-credit agreement. This new agreement maintains the same terms and rates as provided for under the expired agreement. The interest rate is based on 30-day LIBOR plus 100 basis points and includes an availability fee of 15 basis points applied to the difference between the face amount of the note and the average outstanding balance during the period. The Company maintained multi-tiered borrowing limits to accommodate seasonal borrowing demands and minimize overall borrowing costs, with available limits ranging from $10,000,000 to $24,000,000 during the term of the agreement. The line-of-credit agreement will expire March 31, 2017. The Company anticipates being able to extend or replace the line-of-credit upon expiration; however, there is no guarantee that the line-of-credit will be extended or replaced under the same or equivalent terms currently in place. On December 29, 2015, Midstream entered into a Credit Agreement (the "Credit Agreement") and related Promissory Notes (the "Notes"), under which Midstream may borrow up to a total of $25 million, over a period of 5 years, with an interest rate of 30-day LIBOR plus 160 basis points. In accordance with the terms of the Credit Agreement, at such time as Midstream has borrowed $17.5 million under the Notes, Midstream is required to provide the next $5 million in equity towards its capital contributions to the LLC. Once Midstream has completed its $5 million in contributions, it may resume borrowing up to the $25 million limit. Currently, management is considering the possibility of an equity issue by Resources to provide Midstream with the $5 million in equity capital required under the Notes. Following the end of the 5-year term on the Notes, Midstream anticipates refinancing the $25 million Notes with a longer-term amortizing debt instrument. Off-Balance Sheet Arrangements The Company has no off-balance sheet arrangements as defined in Regulation S-K, Item 303(a)(4)(ii). Contractual Obligations and Commitments The Company has incurred various contractual obligations and commitments in the normal course of business. As of September 30, 2016, the estimated recorded and unrecorded obligations are as follows: 22 Recorded contractual obligations: Less than 1 year 1-3 Years 4-5 Years After 5 Years Total Long-Term Debt (1) Short-Term Debt (2) Total $ — $ — $ 3,396,200 $ 30,500,000 $ 33,896,200 14,556,785 — — — 14,556,785 $ 14,556,785 $ — $ 3,396,200 $ 30,500,000 $ 48,452,985 (1) See Note 5 to the consolidated financial statements. (2) See Note 4 to the consolidated financial statements. Unrecorded contractual obligations, not reflected in consolidated balance sheets in accordance with US GAAP: Less than 1 year 1-3 Years 4-5 Years After 5 Years Total Pipeline and Storage Capacity (3) Gas Supply (4) Interest on Short-Term Debt (5) Interest on Long-Term Debt (6) Pension Plan Funding (7) $ 10,474,339 — 32,824 1,371,200 — $ 15,999,239 — — 2,742,400 — $ 7,276,676 — — 2,688,200 — $ 2,682,848 — — 17,277,081 — $ 36,433,102 — 32,824 24,078,881 — Investment in MVP (8) Other Obligations (9) 3,500,000 117,780 28,444,254 24,502 — 4,661 — 25,540 31,944,254 172,483 Total $ 15,496,143 $ 47,210,395 $ 9,969,537 $ 19,985,469 $ 92,661,544 (3) Recoverable through the PGA process. (4) Volumetric obligation is for the purchase of contracted decatherms of natural gas at market prices in effect at the time of purchase. Unable to estimate related payment obligation until time of purchase. See Note 10 to the consolidated financial statements. (5) Accrued interest on line-of-credit balance at September 30, 2016, including minimum facility fee on unused line-of- credit. See Note 4 to the consolidated financial statements. (6) Calculated interest payments on 20-year $30.5 million Roanoke Gas Co. note payable due September 18, 2034 and on 09/30/2016 balance on Midstream notes due December 29, 2020. See Note 5 to the consolidated financial statements. (7) Estimated minimum funding assuming application of credit balances in plan to offset funding. Minimum funding requirements beyond five years is not available. See Note 7 to the consolidated financial statements. (8) Projected remaining funding of the Company's 1% interest in MVP as entered into on October 1, 2015. (9) Various lease, maintenance, equipment and service contracts. Equity Investment in Mountain Valley Pipeline On October 1, 2015, the Company, through its newly formed wholly-owned subsidiary, Midstream, entered into an agreement to become a 1% member in the LLC. The purpose of the LLC is to construct and operate the Mountain Valley Pipeline ("MVP"), a natural gas pipeline connecting an existing gathering and transmission system in northern West Virginia to another interstate pipeline in south central Virginia. This project falls under the jurisdiction of FERC and is subject to its approval prior to beginning construction. In October 2015, the LLC filed the application with FERC to construct the pipeline. On June 28, 2016, FERC issued the Notice of Schedule for Environmental Review (NOS) and on September 16, 2016, FERC issued its draft environmental impact statement ("EIS") regarding the MVP. In the draft EIS, FERC staff concluded that approval of the MVP would result in some adverse environmental impacts; however, they acknowledged that such impacts would be reduced to less than significant levels with the implementation of the LLC's proposed mitigation plans in addition to measures recommended in the EIS. Comments regarding the draft EIS must be filed on or before December 22, 2016. Based on the schedule provided in the NOS, the MVP expects to receive the FERC certificate in mid-2017. The pipeline is targeted to be placed in-service during the fourth quarter of 2018. Management believes the investment in the LLC will be beneficial for the Company, its shareholders and southwest Virginia. In addition to the potential returns from the investment in the LLC, Roanoke Gas will benefit from access to another source of natural gas to its distribution system. Currently, Roanoke Gas is served by two pipelines and a 23 liquefied natural gas storage facility. Damage to or interruption in supply from any of these sources, especially during the winter heating season, could have a significant impact on the Company's ability to serve its customers. A third pipeline would reduce the impact from such an event. In addition, the proposed pipeline path would provide the Company with a more economically feasible opportunity to provide natural gas service to previously unserved areas in southwest Virginia. The total project cost is anticipated to be $3.5 billion. As a 1% member in the LLC, Midstream's contribution is expected to be approximately $35 million. The agreement provides for a schedule of cash draws to fund the project. The initial payments are related to pre-construction activities including the acquisition of land, easements and materials. Once approved and construction begins, more significant cash draws will be required. Initial funding for the investment in the LLC is provided through the Midstream credit facility under which Midstream may borrow up to a total of $25 million, over a period of 5 years with the balance coming from equity capital. A majority of the earnings from the investment in MVP relates to the allowance for funds used during construction ("AFUDC") income generated by the deployment of capital in the design, engineering, materials procurement, project management and ultimately construction phases of the pipeline. AFUDC is an accounting method whereby the costs of debt and equity funds used to finance facility infrastructure are credited to income and charged to the cost of the project. The level of investment in MVP will continue to grow at a steady pace until such time FERC issues their decision on the project. If approved by FERC, construction on the pipeline should begin in earnest and both the investment in MVP and the AFUDC will increase at a much greater rate until the pipeline is placed in service. Earnings after the pipeline is operational would be derived from the fees charged for transporting natural gas through the pipeline. Regulatory Affairs The Company continues to recover the costs of its infrastructure replacement program through its SAVE Plan. On June 30, 2016, the Company filed an application with the SCC for modification to its SAVE Plan and Rider. The original SAVE Plan and Rider were approved by the SCC through an order issued on August 29, 2012 and has been modified or amended each year since. The original SAVE Plan was designed to facilitate the accelerated replacement of the remaining bare steel and cast iron natural gas pipe by providing a mechanism for the Company to recover the related depreciation and expenses and return on rate base of the additional capital investment without the filing of a formal application for an increase in non-gas base rates. The projects included under the SAVE Plan will enhance the safety and reliability of the Company’s gas distribution system and reduce greenhouse emissions. The amendments in 2013 and 2014 added projects related to the replacement of bare steel and cast iron natural gas pipe in addition to two other major projects and the investment for related meter and regulator installations located on customer premises. In 2015, the SCC approved the Company's request to expand the authorized annual spending variance from 10% to 20% and set a 5% cumulative SAVE spending variance. This allows the Company to recover it's investment up to the new variance limits. The 2016 application included provisions to continue the ongoing pipeline renewal project with a focus on pre-1973 plastic pipe, the replacement of three natural gas custody transfer stations, the replacement of coated steel tubing services and related meter installations. The 2017 SAVE revenue requirement is approximately $4,000,000, representing an increase of almost $1,000,000 over the estimated 2016 SAVE Plan year. The additional SAVE Plan revenue as approved by the SCC will allow the Company to forgo a formal non-gas rate increase application at this time. The Company currently holds the only franchises and certificates of public convenience and necessity to distribute natural gas in its service area. Certificates of public convenience and necessity are issued by the SCC to provide service in the cities and counties in the Company's service territory. These certificates are intended for perpetual duration subject to compliance and regulatory standards. Franchises are granted by the local cities and towns served by the Company and are generally granted for a defined period of time. The Company renewed the expiring franchise agreements with the City of Roanoke, the City of Salem and the Town of Vinton under terms and conditions similar to the expiring agreements. The new agreements have twenty-year terms and will expire December 31, 2035. On March 25, 2015, the Company filed an application for approval of a Certificate of Public Convenience and Necessity with the SCC to include the remaining uncertificated portions of Franklin County into its authorized natural gas service territory. On July 30, 2015, the Company filed a Motion to Stay Proceeding requesting the SCC stay the application request pending further progress in the review of the MVP project by FERC and reconsider the application at a later date. The SCC granted the stay on July 31, 2015, which permitted the Company to continue its application request at a later date. The Company intends to pursue the application assuming FERC approval of the MVP project. 24 Critical Accounting Policies and Estimates The consolidated financial statements of Resources are prepared in accordance with accounting principles generally accepted in the United States of America. The amounts of assets, liabilities, revenues and expenses reported in the Company’s financial statements are affected by accounting policies, estimates and assumptions that are necessary to comply with generally accepted accounting principles. Estimates used in the financial statements are derived from prior experience, statistical analysis and professional judgments. Actual results may differ significantly from these estimates and assumptions. The Company considers an estimate to be critical if it is material to the financial statements and requires assumptions to be made that were uncertain at the time the estimate was made and changes in the estimate are reasonably likely to occur from period to period. The Company considers the following accounting policies and estimates to be critical. Regulatory accounting - The Company’s regulated operations follow the accounting and reporting requirements of FASB ASC No. 980, Regulated Operations. The economic effects of regulation can result in a regulated company deferring costs that have been or are expected to be recovered from customers in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as assets in the consolidated balance sheet (regulatory assets) and recorded as expenses when such amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for current collection in rates of costs that are expected to be incurred in the future (regulatory liabilities). If, for any reason, the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the Company would remove the applicable regulatory assets or liabilities from the balance sheet and include them in the consolidated statements of income and comprehensive income for the period in which the discontinuance occurred. Revenue recognition - Regulated utility sales and transportation revenues are based upon rates approved by the SCC. The non-gas cost component of rates may not be changed without a formal rate application and corresponding authorization by the SCC in the form of a Commission order; however, the gas cost component of rates may be adjusted quarterly through the PGA mechanism. When the Company files a request for a non-gas rate increase, the SCC may allow the Company to place such rates into effect subject to refund pending a final order. Under these circumstances, the Company estimates the amount of increase it anticipates will be approved based on the best available information. The Company also bills customers through a SAVE Rider that provides a mechanism to recover on a prospective basis the costs associated with the Company’s expected investment related to the replacement of natural gas distribution pipe and other qualifying projects. As required under the provisions of FASB ASC No. 980, Regulated Operations, the Company recognizes billed revenue related to the SAVE projects to the extent such revenues have been earned under the provisions of the SAVE Plan. The Company bills its regulated natural gas customers on a monthly cycle. The billing cycle for most customers does not coincide with the accounting periods used for financial reporting. The Company accrues estimated revenue for natural gas delivered to customers but not yet billed during the accounting period based on weather during the period and current and historical data. The financial statements include unbilled revenue of $1,004,061 and $1,001,418 as of September 30, 2016 and 2015, respectively. Allowance for Doubtful Accounts - The Company evaluates the collectability of its accounts receivable balances based upon a variety of factors including loss history, level of delinquent account balances, collections on previously written off accounts and general economic conditions. Pension and Postretirement Benefits - The Company offers a defined benefit pension plan (“pension plan”) and a postretirement medical and life insurance plan (“postretirement plan”) to eligible employees. The expenses and liabilities associated with these plans, as disclosed in Note 7 to the consolidated financial statements, are based on numerous assumptions and factors, including provisions of the plans, employee demographics, contributions made to the plan, return on plan assets and various actuarial calculations, assumptions and accounting requirements. In regard to the pension plan, specific factors include assumptions regarding the discount rate used in determining future benefit obligations, expected long-term rate of return on plan assets, compensation increases and life expectancies. Similarly, the postretirement medical plan also requires the estimation of many of the same factors as the pension plan in addition to assumptions regarding the rate of medical inflation and Medicare availability. Actual results may differ materially from the results expected from the actuarial assumptions due to changing economic conditions, differences in actual 25 returns on plan assets, different rates of medical inflation, volatility in interest rates and changes in life expectancy. Such differences may result in a material impact on the amount of expense recorded in future periods or the value of the obligations on the balance sheet. In selecting the discount rate to be used in determining the benefit liability, the Company utilized the Citigroup yield curves which incorporate the rates of return on high-quality, fixed-income investments that corresponded to the length and timing of benefit streams expected under both the pension plan and postretirement plan. The Company used a discount rate of 3.42% and 3.33%, respectively, for valuing its pension plan liability and postretirement plan liability at September 30, 2016. These rates decreased significantly from the prior year with a decline of 0.80% and 0.82%, respectively. Interest rates moved even lower in 2016 keeping the discount rate depressed, thereby elevating the plan liabilities. The downward movement of the discount rate is evidenced by the 30-year Treasury rate, which decreased from 2.87% to 2.32% and the Moody's Aaa rate, which declined by a corresponding 0.56%. This reduction in discount rate, combined with other factors, increased the pension liability by more than $2,300,000 and the postretirement medical liability by approximately $3,150,000. In fiscal 2015, the most significant impact to the liabilities was attributed to the adoption of new mortality tables. On October 27, 2014, the Society of Actuaries released the final reports of the RP-2014 Mortality Tables and the Mortality Improvement Scale MP-2015. The new mortality tables, which were adopted by the Company for its September 30, 2015 defined benefit plan valuations, extend the assumed life expectancy of participants in the plans and provide a better measure of defined benefit plan liabilities. The impact of the change in assumed mortality increased the Company’s pension liability for the prior year by approximately 5% or nearly $1.3 million and the postretirement liability by approximately 7% or about $1 million. The Company used the RP-2014 Mortality Tables under the Projection Scale MP-2015 for the current year valuation. Due to a variety of factors including volatility in the pension expense and corresponding liabilities, continued depressed interest rates and increasing life expectancies, the Company is implementing a risk reduction strategy for its pension plan. This risk reduction strategy included two components. The first offered a one-time lump sum pay out of the pension benefit to vested terminated employees who were not currently receiving payments under the pension plan. Approximately 63% of those vested, terminated employees elected to receive their pension in a lump sum resulting in a payout of $1,242,000 from plan assets in September 2016. These lump sum payments removed approximately $1,500,000 in pension plan liabilities and reduced the number of participants on which the Pension Benefit Guaranty Corporation ("PBGC") premiums are determined. The second was to take action on the pension plan similar to what was done with the postretirement plan back in 2000 by closing the pension plan to new employees effective January 1, 2017. Employees hired prior to that date will continue to accrue benefits. This "soft freeze" of the pension plan will not provide immediate relief to the Plan; but, pension liability growth will slow and eventually decline as no new participants will enter the pension plan. Likewise, pension expense will begin to decline in the future as less service cost is accrued due to fewer active employees in the pension plan. As more of the pension liability becomes fixed through retirements, management will begin to align the duration of the plan's liabilities with its assets in an effort to further reduce market volatility. Following lower than expected returns in fiscal 2015, the returns on the related pension and postretirement assets for fiscal 2016 exceeded the corresponding long-term rate of return assumptions. Furthermore, the Company contributed an additional $1,000,000 over and above the previously projected $500,000 annual contribution to the pension plan. The combination of better than expected returns and higher funding levels were not enough to offset the increase in the pension benefit obligation associated with the reduction in the discount rate and the accretion of service and interest costs. As a result, the funded deficit for both the pension and postretirement plans increased during the period. Generally, the reduction in the discount rate would result in an increase in benefit plan expense for the following year; however, the combination of higher investment returns and contributions combined with the removal of the liabilities related to the lump sum payments will result in a small decrease in pension expense in fiscal 2017. The postretirement medical plan expense will increase as the plan experienced no beneficial offsets to reduce the impact of the lower discount rate. Funded status - September 30, 2016 Pension Postretirement Total Benefit obligation Fair value of assets Funded status $ $ 29,494,950 $ 18,504,710 $ 47,999,660 23,113,057 (6,381,893) $ 11,122,783 (7,381,927) $ 34,235,840 (13,763,820) 26 Funded status - September 30, 2015 Pension Postretirement Total Benefit obligation Fair value of assets Funded status $ $ 27,167,621 $ 15,355,668 $ 42,523,289 21,394,399 (5,773,222) $ 10,443,629 (4,912,039) $ 31,838,028 (10,685,261) The economic environment makes it difficult to project interest rates and future investment returns. During the prior year, management believed that market conditions supported an increase in interest rates during fiscal 2016. Twelve months later, interest rates have declined and the discount rate is nearly 1% lower than the same time last year. A similar scenario exists this year as current indications tend to support an increase in interest rates. However, any expectation or trend is purely speculation. If the economy shows indications of stronger growth, long-term interest rates could increase, thereby reducing the benefit liabilities. However, increasing interest rates could have a negative effect on investment returns, especially in the fixed income allocation, and any benefit obtained from reduced benefit liabilities could be mitigated by less than expected returns on assets. Conversely, if the economy stagnates or declines, interest rates could remain at lower levels or even drop, leading to an increase in the benefit liabilities. The Company annually evaluates the returns on its targeted investment allocation model. The investment policy as of the measurement date in September reflected a targeted allocation of 60% equity and 40% fixed income on the pension plan and a targeted allocation of 50% equity and 50% fixed income for the postretirement plan. As a result of this evaluation, the Company set its expected long-term annual return on pension assets at 7.00% and postretirement assets at 4.89% (net of income taxes) for fiscal 2017. These rates are consistent with the expected long-term rates in experienced during fiscal 2016. Management will continue to re-evaluate the return assumptions and adjust them as market conditions warrant. In August 2014, the Highway and Transportation Funding Act of 2014 (“HATFA”) was signed into law, which included a provision to extend the interest rate corridors introduced in 2012 under the Moving Ahead for Progress in the 21st Century Act (“MAP-21”). MAP-21 provided temporary funding relief for defined benefit pension plans. The requirements of the Employee Retirement Income Security Act of 1974 (ERISA) and the Pension Protection Act of 2006 (PPA) subject defined benefit plans to minimum funding rules. As a result, when interest rates are low, pension plan liabilities increase thereby resulting in higher mandatory contributions to meet minimum funding obligations. MAP-21 provided funding relief by allowing pension plans to adjust the interest rates used in determining funding requirements so that they are within 10% of the average of interest rates for the 25-year period preceding the current year for funding calculations for 2013 to within 30% for funding periods beginning in 2016. HATFA extended the period of time that the 10% corridor instituted by MAP-21 may be used for funding calculations. Under HATFA, the 10% corridor extends through plan years that begin in 2017 and phases out to a 30% corridor in 2021 and later. HATFA significantly increases the effective interest rates used in determining funding requirements and could result in a deterioration of the pension plan funded status resulting in much greater funding requirements in the future as well as higher PBGC premiums paid by sponsors of pension plans to protect participants in the event of default by the employer. Management estimates that, under the provisions of HATFA, the Company will have no minimum funding requirements next year. Although HATFA and MAP-21 allow the Company some short-term funding relief, management expects to continue its pension funding plan by contributing at least the minimum annual pension contribution requirement or its expense level for subsequent years. The Company currently expects to contribute approximately $750,000 to its pension plan and $1,000,000 to its postretirement plan in fiscal 2017. The Company will continue to evaluate its benefit plan funding levels in light of funding requirements and ongoing investment returns and make adjustments, as necessary, to avoid benefit restrictions. The following schedule reflects the sensitivity of pension costs to changes in certain actuarial assumptions, assuming that the other components of the calculation remain constant. Actuarial Assumptions Discount rate Rate of return on plan assets Rate of increase in compensation Change in Assumption Increase in Pension Cost Increase in Projected Benefit Obligation -0.25% $ -0.25% 0.25% 125,000 $ 1,233,000 57,000 56,000 N/A 314,000 The following schedule reflects the sensitivity of postretirement benefit costs from changes in certain actuarial assumptions, while the other components of the calculation remain constant. 27 Actuarial Assumptions Discount rate Rate of return on plan assets Medical claim cost increase Change in Assumption Increase (Decrease) in Postretirement Benefit Cost Increase in Accumulated Postretirement Benefit Obligation -0.25% $ -0.25% 0.25% (19,000) $ 35,000 22,000 787,000 N/A 756,000 Derivatives - The Company may hedge certain risks incurred in its operation through the use of derivative instruments. The Company applies the requirements of FASB ASC No. 815, Derivatives and Hedging, which requires the recognition of derivative instruments as assets or liabilities in the Company’s balance sheet at fair value. In most instances, fair value is based upon quoted futures prices for natural gas commodities and interest rate futures for interest rate swaps. Changes in the commodity and futures markets will impact the estimates of fair value in the future. Furthermore, the actual market value at the point of realization of the derivative may be significantly different from the values used in determining fair value in prior financial statements. The Company had no commodity or interest rate derivatives outstanding at September 30, 2016 and 2015. Item 7A. Quantitative and Qualitative Disclosures About Market Risk. The Company is exposed to market risks associated with interest rates and commodity prices. Interest rate risk is related to the Company’s outstanding variable rate debt. Commodity price risk is experienced by the Company’s regulated natural gas operations. The Company’s risk management policy, as authorized by the Company’s Board of Directors, allows management to enter into derivatives for the purpose of managing commodity and financial market risks of its business operations. Interest Rate Risk The Company is exposed to market risk related to changes in interest rates associated with its borrowing activities. As of September 30, 2016, the Company has $14,556,785 outstanding under its variable rate line-of-credit with an average balance outstanding during the year of $9,991,078. The Company also had $3,396,200 outstanding under a 5-year variable rate term loan. A hypothetical 100 basis point increase in market interest rates applicable to the Company’s variable rate debt outstanding during the year would have resulted in an increase in interest expense for the current year of approximately $120,000. The Company’s remaining debt is at a fixed rate. Commodity Price Risk The Company is also exposed to market risks through its natural gas operations associated with commodity prices. The Company’s hedging and derivatives policy, as authorized by the Company’s Board of Directors, allows management to enter into both physical and financial transactions for the purpose of managing the commodity risk of its business operations. The policy also specifies that the combination of all commodity hedging contracts for any 12-month period shall not exceed a total hedged volume of 90% of projected volumes. The policy specifically prohibits the use of derivatives for the purposes of speculation. The Company manages the price risk associated with purchases of natural gas by using a combination of liquefied natural gas (LNG) storage, underground storage gas, fixed price contracts, spot market purchases and derivative commodity instruments including futures, price caps, swaps and collars. At September 30, 2016, the Company had no outstanding derivative instruments to hedge the price of natural gas. The Company had approximately 2,537,000 decatherms of gas in storage, including LNG, at an average price of $2.93 per decatherm compared to 2,418,000 decatherms at an average price of $3.38 per decatherm last year. The SCC currently allows for full recovery of prudent costs associated with natural gas purchases, and any additional costs or benefits associated with the settlement of derivative contracts and other price hedging techniques are passed through to customers when realized through the regulated natural gas PGA mechanism. 28 Item 8. Financial Statements and Supplementary Data. 29 RGC Resources, Inc. and Subsidiaries Consolidated Financial Statements for the Years Ended September 30, 2016, 2015 and 2014, and Report of Independent Registered Public Accounting Firm 30 RGC RESOURCES, INC. AND SUBSIDIARIES TABLE OF CONTENTS Report of Independent Registered Public Accounting Firm Consolidated Financial Statements for the Years Ended September 30, 2016, 2015 and 2014: Consolidated Balance Sheets Consolidated Statements of Income Consolidated Statements of Comprehensive Income Consolidated Statements of Stockholders’ Equity Consolidated Statements of Cash Flows Notes to Consolidated Financial Statements Page 32 33 35 36 37 38 39 31 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Board of Directors and Stockholders RGC Resources, Inc. Roanoke, Virginia We have audited the accompanying consolidated balance sheets of RGC Resources, Inc. and Subsidiaries (“the Company”) as of September 30, 2016 and 2015, and the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows for each of the years in the three-year period ended September 30, 2016. RGC Resources, Inc.’s management is responsible for these financial statements. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of RGC Resources, Inc. and Subsidiaries as of September 30, 2016 and 2015, and the consolidated results of its operations and its cash flows for each of the years in the three-year period ended September 30, 2016, in conformity with accounting principles generally accepted in the United States of America. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), RGC Resources, Inc. and Subsidiaries’ internal control over financial reporting as of September 30, 2016, based on criteria established in Internal Control-Integrated Framework - 2013 issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated December 8, 2016 expressed an unqualified opinion. 1715 Pratt Drive, Suite 2700 Blacksburg, Virginia December 8, 2016 CERTIFIED PUBLIC ACCOUNTANTS 32 RGC RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS AS OF SEPTEMBER 30, 2016 AND 2015 ASSETS CURRENT ASSETS: Cash and cash equivalents Accounts receivable, net Materials and supplies Gas in storage Prepaid income taxes Other Total current assets UTILITY PROPERTY: In service Accumulated depreciation and amortization In service, net Construction work in progress Utility plant, net OTHER ASSETS: Regulatory assets Investment in unconsolidated affiliate Other Total other assets TOTAL ASSETS 2016 2015 $ 643,252 $ 3,478,983 824,139 7,436,785 1,550,836 1,548,329 985,234 3,196,573 968,108 8,160,498 1,657,066 1,182,343 15,482,324 16,149,822 185,577,286 (56,156,287) 129,420,999 2,707,139 132,128,138 14,332,451 3,496,404 113,532 17,942,387 168,033,032 (53,307,079) 114,725,953 3,903,599 118,629,552 10,923,243 — 144,577 11,067,820 $ 165,552,849 $ 145,847,194 (Continued) 33 RGC RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS AS OF SEPTEMBER 30, 2016 AND 2015 LIABILITIES AND STOCKHOLDERS’ EQUITY CURRENT LIABILITIES: Borrowings under line-of-credit Dividends payable Accounts payable Capital contributions payable Customer credit balances Customer deposits Accrued expenses Over-recovery of gas costs Total current liabilities LONG-TERM DEBT: Principal amount Less unamortized debt issuance costs Long-term debt net of unamortized debt issuance costs DEFERRED CREDITS AND OTHER LIABILITIES: Asset retirement obligations Regulatory cost of retirement obligations Benefit plan liabilities Deferred income taxes Total deferred credits and other liabilities COMMITMENTS AND CONTINGENCIES (Note 10) CAPITALIZATION: Stockholders’ Equity: 2016 2015 $ 14,556,785 $ 970,244 5,345,575 287,794 1,605,608 1,627,105 3,194,255 909,687 9,340,997 912,995 5,141,677 — 1,560,351 1,579,441 2,766,097 1,901,426 28,497,053 23,202,984 33,896,200 (260,149) 33,636,051 5,682,556 9,348,443 13,763,820 18,957,854 47,752,673 30,500,000 (183,427) 30,316,573 5,295,868 8,885,486 10,685,261 14,620,031 39,486,646 Common Stock, $5 par value; authorized 10,000,000 shares; issued and outstanding 4,788,289 and 4,741,498 shares in 2016 and 2015, respectively Preferred stock, no par; authorized 5,000,000 shares; no shares issued and outstanding in 2016 and 2015 Capital in excess of par value Retained earnings Accumulated other comprehensive loss Total stockholders’ equity 23,941,445 23,707,490 — 9,509,548 24,713,310 (2,497,231) 55,667,072 — 8,647,669 22,772,377 (2,286,545) 52,840,991 TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY $ 165,552,849 $ 145,847,194 See notes to consolidated financial statements. (Concluded) 34 RGC RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME YEARS ENDED SEPTEMBER 30, 2016, 2015 AND 2014 OPERATING REVENUES: Gas utilities Other Total operating revenues COST OF SALES: Gas utilities Other Total cost of sales GROSS MARGIN OTHER OPERATING EXPENSES: Operations and maintenance General taxes Depreciation and amortization Total other operating expenses OPERATING INCOME Equity in earnings of unconsolidated affiliate Other expense, net Interest expense INCOME BEFORE INCOME TAXES INCOME TAX EXPENSE NET INCOME EARNINGS PER COMMON SHARE: Basic Diluted WEIGHTED AVERAGE SHARES OUTSTANDING: Basic Diluted 2016 2015 2014 $ 58,079,990 $ 67,094,290 $ 73,865,487 983,301 59,063,291 1,095,317 68,189,607 1,150,647 75,016,134 27,009,330 37,437,315 489,047 27,498,377 31,564,914 545,859 37,983,174 30,206,433 45,091,274 587,771 45,679,045 29,337,089 13,098,086 13,486,885 13,383,388 1,663,126 5,591,610 20,352,822 11,212,092 152,864 255,585 1,636,321 9,473,050 3,666,184 5,806,866 1.22 1.22 $ $ $ 1,606,421 5,106,935 20,200,241 10,006,192 — 228,796 1,512,419 8,264,977 3,170,562 5,094,415 1.08 1.08 $ $ $ 1,560,386 4,711,447 19,655,221 9,681,868 — 206,887 1,827,001 7,647,980 2,939,540 4,708,440 1.00 1.00 4,766,604 4,773,175 4,728,210 4,731,676 4,715,478 4,716,282 $ $ $ See notes to consolidated financial statements. 35 RGC RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME YEARS ENDED SEPTEMBER 30, 2016, 2015 AND 2014 NET INCOME Other comprehensive income, net of tax: Interest rate swaps Defined benefit plans OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX COMPREHENSIVE INCOME 2016 2015 2014 $ 5,806,866 $ 5,094,415 $ 4,708,440 — (210,686) (210,686) 5,596,180 $ — (1,147,219) (1,147,219) 3,947,196 $ 1,232,546 (220,638) 1,011,908 $ 5,720,348 See notes to consolidated financial statements. 36 Accumulated Other Comprehensive Income (Loss) $ (2,151,234) $ 49,502,422 4,708,440 Total Stockholders’ Equity — — 1,011,908 1,011,908 — — — 75,310 (3,490,624) 213,391 $ (1,139,326) $ 52,020,847 5,094,415 (1,147,219) 49,366 — (1,147,219) — — — — 83,640 (3,643,093) 383,035 $ (2,286,545) $ 52,840,991 5,806,866 (210,686) 41,762 — (210,686) — — 64,640 (3,865,933) 989,432 $ (2,497,231) $ 55,667,072 — — RGC RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY YEARS ENDED SEPTEMBER 30, 2016, 2015 AND 2014 Balance - September 30, 2013 $ 23,546,630 $ 8,003,787 $ 20,103,239 Common Stock Capital in Excess of Par Value Retained Earnings Net income Other comprehensive income Stock option grants Cash dividends declared ($0.74 per share) — — — — Issuance of common stock (11,052 shares) 55,260 — — 75,310 — 158,131 4,708,440 — (3,490,624) — Balance - September 30, 2014 $ 23,601,890 $ 8,237,228 $ 21,321,055 Net income Other comprehensive loss Exercise of stock options (2,600 shares) Stock option grants Cash dividends declared ($0.77 per share) — — 13,000 — — — — 36,366 83,640 — Issuance of common stock (18,520 shares) 92,600 290,435 5,094,415 — — — (3,643,093) — Balance - September 30, 2015 $ 23,707,490 $ 8,647,669 $ 22,772,377 Net income Other comprehensive loss Exercise of stock options (2,200 shares) Stock option grants Cash dividends declared ($0.81 per share) — — 11,000 — — — — 30,762 64,640 — Issuance of common stock (44,591 shares) 222,955 766,477 5,806,866 — — — (3,865,933) — Balance - September 30, 2016 $ 23,941,445 $ 9,509,548 $ 24,713,310 See notes to consolidated financial statements. 37 RGC RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS YEARS ENDED SEPTEMBER 30, 2016, 2015 AND 2014 CASH FLOWS FROM OPERATING ACTIVITIES: Net income Adjustments to reconcile net income to net cash provided by operations: Depreciation and amortization Cost of retirement of utility plant, net Stock option grants Equity in earnings of unconsolidated affiliate Deferred taxes and investment tax credits Other noncash items, net Changes in assets and liabilities which provided (used) cash: Accounts receivable and customer deposits, net Inventories and gas in storage Over/under recovery of gas costs Other assets Accounts payable, customer credit balances and accrued expenses, net Total adjustments Net cash provided by operating activities CASH FLOWS FROM INVESTING ACTIVITIES: Expenditures for utility property Investment in unconsolidated affiliate Proceeds from disposal of utility property Net cash used in investing activities CASH FLOWS FROM FINANCING ACTIVITIES: Borrowings under line-of-credit Repayments under line-of-credit Proceeds from issuance of unsecured notes Retirement of note payable Retirement of long-term debt Early termination fees Debt issuance expenses Proceeds from issuance of stock Cash dividends paid Net cash provided by (used in) financing activities NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR CASH AND CASH EQUIVALENTS AT END OF YEAR SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid (refunded) during the year for: 2016 2015 2014 $ 5,806,866 $ 5,094,415 $ 4,708,440 5,709,525 (449,201) 64,640 (152,864) 4,466,954 197,298 5,219,893 (406,731) 83,640 — 2,416,841 105,815 (258,960) 867,682 (991,739) (398,864) 60,303 9,114,774 14,921,640 638,917 3,168,056 2,082,257 (768,922) (873,354) 11,666,412 16,760,827 4,838,062 (452,834) 75,310 — 859,788 38,073 12,424 (1,219,641) (1,208,134) (306,744) (505,006) 2,131,298 6,839,738 (17,945,719) (3,055,746) 4,964 (20,996,501) (13,780,356) — 30,082 (13,750,274) (14,715,428) — 16,858 (14,698,570) 38,310,326 (33,094,539) 3,396,200 — — — (101,619) 1,031,194 (3,808,683) 5,732,879 (341,982) 985,234 643,252 $ 34,698,924 (34,402,977) 25,363,774 (16,318,724) — 30,500,000 — (15,000,000) — (13,000,000) — (2,237,961) (193,081) — 213,391 432,401 (3,465,034) (3,603,424) (2,875,076) 5,862,365 (1,996,467) 135,477 2,846,224 849,757 849,757 985,234 $ $ Interest Income taxes $ 1,480,665 (907,000) $ 1,002,462 1,266,573 $ 1,966,263 2,387,000 See notes to consolidated financial statements. 38 RGC RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED SEPTEMBER 30, 2016, 2015 AND 2014 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Principles of Consolidation—RGC Resources, Inc. is an energy services company primarily engaged in the sale and distribution of natural gas. The consolidated financial statements include the accounts of RGC Resources, Inc. and its wholly owned subsidiaries (“Resources” or the “Company”): Roanoke Gas Company (“Roanoke Gas”); Diversified Energy Company; RGC Ventures of Virginia, Inc., operating as Application Resources and The Utility Consultants; and RGC Midstream, LLC. Roanoke Gas is a natural gas utility, which distributes and sells natural gas to approximately 59,600 residential, commercial and industrial customers within its service areas in Roanoke, Virginia and the surrounding localities. The Company’s business is seasonal in nature as a majority of natural gas sales are for space heating during the winter season. Roanoke Gas is regulated by the Virginia State Corporation Commission (“SCC” or “Virginia Commission”). RGC Ventures of Virginia, Inc. was dissolved in 2016 after Application Resources, which provided information system services to software providers in the utility industry, ceased operations in 2016, and The Utility Consultants, which provided regulatory consulting services to other utilities, ceased operations in 2015. RGC Midstream, LLC is a wholly-owned subsidiary created in 2015 to invest in the Mountain Valley pipeline project. Diversified Energy Company is currently inactive. The Company follows accounting and reporting standards established by the Financial Accounting Standards Board (“FASB”) and the Securities and Exchange Commission (“SEC”). Resources has only one reportable segment as defined under FASB ASC No. 280 – Segment Reporting. All intercompany transactions have been eliminated in consolidation. Rate Regulated Basis of Accounting—The Company’s regulated operations follow the accounting and reporting requirements of FASB ASC No. 980, Regulated Operations. The economic effects of regulation can result in a regulated company deferring costs that have been or are expected to be recovered from customers in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this situation occurs, costs are deferred as assets in the consolidated balance sheet (regulatory assets) and recorded as expenses when such amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for current collection in rates of costs that are expected to be incurred in the future (regulatory liabilities). In the event the provisions of FASB ASC No. 980 no longer apply to any or all regulatory assets or liabilities, the Company would write off such amounts and include them in the consolidated statements of income and comprehensive income in the period for which FASB ASC No. 980 no longer applied. 39 Regulatory assets and liabilities included in the Company’s consolidated balance sheets as of September 30, 2016 and 2015 are as follows: Regulatory Assets: Current Assets: Accounts receivable: Accrued WNA revenues Other: September 30 2016 2015 $ 148,663 $ 229,281 Accrued pension and postretirement medical 835,704 530,781 Utility Property: In service: Other Other Assets: Regulatory assets: Premium on early retirement of debt Accrued pension and postretirement medical Other Total regulatory assets Regulatory Liabilities: Current Liabilities: Over-recovery of gas costs Accrued expenses: Over-recovery of SAVE Plan revenues Deferred Credits and Other Liabilities: Asset retirement obligations Regulatory cost of retirement obligations Total regulatory liabilities 11,945 11,945 2,055,369 11,460,738 816,344 15,328,763 $ 2,169,556 8,378,419 375,268 11,695,250 909,687 $ 1,901,426 238,694 153,365 5,682,556 9,348,443 16,179,380 $ 5,295,868 8,885,486 16,236,145 $ $ $ As of September 30, 2016, the Company had regulatory assets in the amount of $13,261,449 on which the Company did not earn a return during the recovery period. These assets primarily pertain to the net funded position of the Company’s benefit plans related to its regulated operations. As such, the amortization period is not specifically defined. Utility Plant and Depreciation—Utility plant is stated at original cost and includes direct labor and materials, contractor costs, and all allocable overhead charges. The Company applies the group method of accounting, where the costs of like assets are aggregated and depreciated by applying a rate based on the average expected useful life of the assets. In accordance with Company policy, expenditures for depreciable assets with a life greater than one year are capitalized, along with any upgrades or improvements to existing assets, when they significantly improve or extend the original expected useful life of an asset. Expenditures for maintenance, repairs, and minor renewals and betterments are expensed as incurred. The original cost of depreciable property retired is removed from utility plant and charged to accumulated depreciation. The cost of asset removals, less salvage, is charged to “regulatory cost of retirement obligations” or “asset retirement obligations” as explained under Asset Retirement Obligations below. Utility plant is composed of the following major classes of assets: Distribution and transmission LNG storage General and miscellaneous Total utility plant in service 40 Years Ended September 30 2016 2015 $ 160,354,300 $ 143,172,628 12,594,294 12,628,692 185,577,286 $ 12,501,179 12,359,225 168,033,032 $ Provisions for depreciation are computed principally at composite straight-line rates over periods ranging from 5 to 76 years. Rates are determined by depreciation studies which are required to be performed at least every 5 years on the regulated utility assets of Roanoke Gas. The Company completed its last depreciation study in June 2014. The composite weighted-average depreciation rate realized using the most recently completed depreciation study was 3.25% for each of the fiscal years ended September 30, 2016, 2015 and 2014. The composite rates are composed of two components, one based on average service life and one based on cost of retirement. As a result, the Company accrues the estimated cost of retirement of long-lived assets through depreciation expense. Retirement costs are not a legal obligation but rather the result of cost-based regulation and are accounted for under the provisions of FASB ASC No. 980. Such amounts are classified as a regulatory liability. The Company reviews long-lived assets and certain identifiable intangibles for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. These reviews have not identified any impairments which would have a material effect on the results of operations or financial condition. Asset Retirement Obligations—FASB ASC No. 410, Asset Retirement and Environmental Obligations, requires entities to record the fair value of a liability for an asset retirement obligation when there exists a legal obligation for the retirement of the asset. When the liability is initially recorded, the entity capitalizes the cost, thereby increasing the carrying amount of the underlying asset. In subsequent periods, the liability is accreted, and the capitalized cost is depreciated over the useful life of the underlying asset. The Company has recorded asset retirement obligations for its future legal obligations related to purging and capping its distribution mains and services upon retirement, although the timing of such retirements is uncertain. The Company’s composite depreciation rates include a component to provide for the cost of retirement of assets. As a result, the Company accrues the estimated cost of retirement of its utility plant through depreciation expense and creates a corresponding regulatory liability. The costs of retirement considered in the development of the depreciation component include those costs associated with the legal liability. Therefore, the asset retirement obligation is reclassified from the regulatory cost of retirement obligation. If the legal obligations were to exceed the regulatory liability provided for in the depreciation rates, the Company would establish a regulatory asset for such difference with the anticipation of future recovery through rates charged to customers. In 2016, the Company increased its asset retirement obligation to reflect revisions to the estimated cash flows for asset retirements. The following is a summary of the asset retirement obligation: Beginning balance Liabilities incurred Liabilities settled Accretion Revisions to estimated cash flows Ending balance Years Ended September 30 2016 5,295,868 85,263 (176,090) 310,568 166,947 5,682,556 $ $ 2015 4,802,015 62,890 (162,072) 281,762 311,273 5,295,868 $ $ Cash, Cash Equivalents and Short-Term Investments—From time to time, the Company will have balances on deposit at banks in excess of the amount insured by the Federal Deposit Insurance Corporation (“FDIC”). The Company has not experienced any losses on these accounts and does not consider these amounts to be at credit risk. As of September 30, 2016, the Company did not have any bank deposits in excess of the FDIC insurance limits. For purposes of the consolidated statements of cash flows, the Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. Customer Receivables and Allowance for Doubtful Accounts—Accounts receivable include amounts billed to customers for natural gas sales and related services and gas sales occurring subsequent to normal billing cycles but before the end of the period. The Company provides an estimate for losses on these receivables by utilizing historical information, current account balances, account aging and current economic conditions. Customer accounts are charged off annually when deemed uncollectible or when turned over to a collection agency for action. 41 A reconciliation of changes in the allowance for doubtful accounts is as follows: Beginning balance Provision for doubtful accounts Recoveries of accounts written off Accounts written off Ending balance Years Ended September 30 2016 2015 2014 $ $ 52,721 14,074 137,055 (126,916) 76,934 $ $ 70,747 87,908 139,282 (245,216) 52,721 $ $ 68,539 148,881 136,369 (283,042) 70,747 Financing Receivables—Financing receivables represent a contractual right to receive money either on demand or on fixed or determinable dates and are recognized as assets on the entity’s balance sheet. Trade receivables are the Company's one primary type of financing receivables, resulting from the sale of natural gas and other services to its customers. These receivable are short-term in nature with a provision for uncollectible balances included in the financial statements. Inventories—Inventories, consisting of natural gas in storage and materials and supplies, are recorded at average cost. Injections into storage are priced at the purchase cost at the time of injection and withdrawals from storage are priced at the weighted average price in storage. Materials and supplies are removed from inventory at average cost. Unbilled Revenues—The Company bills its natural gas customers on a monthly cycle; however, the billing cycle period for most customers does not coincide with the accounting periods used for financial reporting. As the Company recognizes revenue when gas is delivered, an accrual is made to estimate revenues for natural gas delivered to customers but not billed during the accounting period. The amounts of unbilled revenue receivable included in accounts receivable on the consolidated balance sheets at September 30, 2016 and 2015 were $1,004,061 and $1,001,418, respectively. Income Taxes—Income taxes are accounted for using the asset and liability method. Under the asset and liability method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the years in which those temporary differences are expected to be recovered or settled. A valuation allowance against deferred tax assets is provided if it is more likely than not the deferred tax asset will not be realized. The Company and its subsidiaries file state and federal consolidated income tax returns. Debt Expenses—Debt issuance expenses are deferred and amortized over the lives of the debt instruments. The unamortized balances are offset against the carrying value of long-term debt. Over/Under-Recovery of Natural Gas Costs—Pursuant to the provisions of the Company’s Purchased Gas Adjustment (“PGA”) clause, the SCC provides the Company with a method of passing along to its customers increases or decreases in natural gas costs incurred by its regulated operations, including gains and losses on natural gas derivative hedging instruments. On a quarterly basis, the Company files a PGA rate adjustment request with the SCC to adjust the gas cost component of its rates up or down depending on projected price and activity. Once administrative approval is received, the Company adjusts the gas cost component of its rates to reflect the approved amount. As actual costs will differ from the projections used in establishing the PGA rate, the Company may either over-recover or under-recover its actual gas costs during the period. Any difference between actual costs incurred and costs recovered through the application of the PGA is recorded as a regulatory asset or liability. At the end of the deferral period, the balance of the net deferred charge or credit is amortized over an ensuing 12-month period as amounts are reflected in customer billings. Fair Value—Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The Company determines fair value based on the following fair value hierarchy which prioritizes each input to the valuation methods into one of the following three broad levels: • • Level 1 – Unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date. Level 2 – Inputs other than quoted prices in Level 1 that are either for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in 42 markets that are not active, inputs other than quoted prices that are observable for the asset or liability, or inputs that are derived principally from or corroborated by observable market data by correlation or other means. • Level 3 – Unobservable inputs for the asset or liability where there is little, if any, market activity which require the Company to develop its own assumptions. The fair value hierarchy gives the highest priority to unadjusted quoted prices in active markets (Level 1) and the lowest priority to unobservable inputs (Level 3). All fair value disclosures are categorized within one of the three categories in the hierarchy. See fair value disclosures below and in Notes 7 and 11. Use of Estimates—The preparation of financial statements in conformity with Generally Accepted Accounting Principles in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Excise and Sales Taxes—Certain excise and sales taxes imposed by the state and local governments in the Company’s service territory are collected by the Company from its customers. These taxes are accounted for on a net basis and therefore are not included as revenues in the Company’s Consolidated Statements of Income. Earnings Per Share—Basic earnings per share and diluted earnings per share are calculated by dividing net income by the weighted-average common shares outstanding during the period and the weighted-average common shares outstanding during the period plus dilutive potential common shares, respectively. Dilutive potential common shares are calculated in accordance with the treasury stock method, which assumes that proceeds from the exercise of all options are used to repurchase common stock at market value. The amount of shares remaining after the proceeds are exhausted represents the potentially dilutive effect of the securities. A reconciliation of basic and diluted earnings per share is presented below: Net Income Weighted-average common shares Effect of dilutive securities: Options to purchase common stock Diluted average common shares Earnings Per Share of Common Stock: Basic Diluted Years Ended September 30 2016 5,806,866 4,766,604 $ 2015 5,094,415 4,728,210 $ 2014 4,708,440 4,715,478 6,571 4,773,175 3,466 4,731,676 804 4,716,282 1.22 1.22 $ $ 1.08 1.08 $ $ 1.00 1.00 $ $ $ Business and Credit Concentrations—The primary business of the Company is the distribution of natural gas to residential, commercial and industrial customers in its service territories. No sales to individual customers accounted for more than 5% of total revenue in any period or amounted to more than 5% of total accounts receivable. Roanoke Gas currently holds the only franchises and certificates of public convenience and necessity to distribute natural gas in its service area. These franchises are effective through January 1, 2036. The Company's current certificates of public convenience and necessity in Virginia are exclusive and are intended for perpetual duration. Roanoke Gas is served directly by two primary pipelines that provide all of the natural gas supplied to the Company’s customers. Depending upon weather conditions and the level of customer demand, failure of one or both of these transmission pipelines could have a major adverse impact on the Company. Derivative and Hedging Activities—FASB ASC No. 815, Derivatives and Hedging, requires the recognition of all derivative instruments as assets or liabilities in the Company’s balance sheet and measurement of those instruments at fair value. 43 The Company’s hedging and derivatives policy allows management to enter into derivatives for the purpose of managing commodity and financial market risks of its business operations. The Company’s hedging and derivatives policy specifically prohibits the use of derivatives for speculative purposes. The key market risks that RGC Resources, Inc. hedges against include the price of natural gas and the cost of borrowed funds. The Company historically has entered into collars, swaps and caps for the purpose of hedging the price of natural gas in order to provide price stability during the winter months. The fair value of these instruments is recorded in the balance sheet with the offsetting entry to either under-recovery of gas costs or over-recovery of gas costs. Net income and other comprehensive income are not affected by the change in market value as any cost incurred or benefit received from these instruments is recoverable or refunded through the PGA as the SCC allows for full recovery of prudent costs associated with natural gas purchases. At September 30, 2016 and 2015, the Company had no outstanding derivative instruments for the purchase of natural gas. The Company also had two interest rate swaps that essentially converted its variable interest rate notes to fixed rate debt instruments. Both swaps were terminated in September 2014 as part of the Company's debt refinancing. These swaps qualified as cash flow hedges with changes in fair value reported in other comprehensive income. No derivative instruments were deemed to be ineffective for any period presented. Non-Cash Activity — Non-cash increase in investment in unconsolidated affiliate and corresponding increase in capital contributions payable of $287,794. Other Comprehensive Income(Loss)—A summary of other comprehensive income is provided below: Year Ended September 30, 2016: Defined benefit plans: Net loss arising during period Amortization of actuarial losses Other comprehensive loss Year Ended September 30, 2015: Defined benefit plans: Net loss arising during period Amortization of actuarial losses Other comprehensive loss Year Ended September 30, 2014: Interest rate swaps: Unrealized losses Transfer of realized losses to interest expense Transfer of realized losses to regulatory asset Net interest rate swaps Defined benefit plans: Net loss arising during period Amortization of actuarial losses Net defined benefit plans Other comprehensive income Before Tax Amount Tax (Expense) or Benefit Net of Tax Amount $ $ $ $ $ $ (560,887) $ 221,070 (339,817) $ (1,910,573) $ 60,221 (1,850,352) $ (58,800) $ 926,262 1,119,233 1,986,695 (397,714) 41,846 (355,868) 1,630,827 $ $ $ $ $ $ 213,137 (84,006) 129,131 726,017 (22,884) 703,133 22,321 (351,609) (424,861) (754,149) 151,131 (15,901) 135,230 (618,919) $ (347,750) 137,064 (210,686) (1,184,556) 37,337 (1,147,219) (36,479) 574,653 694,372 1,232,546 (246,583) 25,945 (220,638) 1,011,908 The amortization of actuarial losses and transition obligation is included as components of net periodic pension and postretirement benefit costs and is included in operations and maintenance expense. 44 Composition of Accumulated Other Comprehensive Income (Loss): Balance September 30, 2013 Other comprehensive income (loss) Balance September 30, 2014 Other comprehensive income (loss) Balance September 30, 2015 Other comprehensive income (loss) Balance September 30, 2016 Interest Rate Swaps (1,232,546) $ 1,232,546 — — — — — $ $ $ Defined Benefit Plans Accumulated Other Comprehensive Income (Loss) (918,688) $ (220,638) (1,139,326) (1,147,219) (2,286,545) (210,686) (2,497,231) $ (2,151,234) 1,011,908 (1,139,326) (1,147,219) (2,286,545) (210,686) (2,497,231) Recently Adopted Accounting Standards—In April 2015, the FASB issued ASU 2015-03, Interest-Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs. This ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. The Company previously recognized debt issuance costs in assets and amortized those costs over the term of the debt. This guidance is effective for the Company for the annual reporting period ending September 30, 2017 and interim periods within that annual period. Early application is permitted. The Company adopted the ASU in the period ended September 30, 2015. The adoption of this ASU did not have any effect on the Company's results of operations or cash flows; however, the unamortized balance of debt issuance costs were reclassified from assets to an offset against long-term debt. Certain deferred costs related to the early retirement of debt in 2014 are classified as regulatory assets and are not offset against debt. In November 2015, the FASB issued ASU 2015-17, Income Taxes: Balance Sheet Classification of Deferred Taxes. The ASU requires that all deferred tax assets and liabilities be presented as noncurrent and eliminates prior guidance to classify and present deferred tax assets and liabilities as current and noncurrent. This ASU is effective for the Company for the annual reporting period ended September 30, 2018 and interim periods within that annual period. Early application is permitted. The Company adopted this ASU for the quarter ended December 31, 2015. The Company applied the retrospective approach in adopting this ASU and reclassified $2,293,536 previously reflected as a current deferred income tax asset against the balance of the non-current deferred tax liability in the September 30, 2015 consolidated balance sheet. There was no other impact to the Company’s financial position, results of operations or cash flows. In March 2016, the FASB issued ASU 2016-09, Compensation - Stock Compensation: Improvements to Employee Share-Based Payment Accounting. The guidance simplifies several aspects of the accounting for share-based payment award transactions, including income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. The new guidance is effective for the Company for the annual reporting period ending September 30, 2018 and interim periods within that annual period. Early adoption is permitted. The Company adopted this ASU for the quarter ended September 30, 2016. Under the prior guidance, excess tax benefits were to be tracked in an APIC pool and not recognized in the income statement. Tax deficiencies were netted against the accumulated APIC pool and only recognized in the income statement starting at the time tax deficiencies exceeded the pool. Under ASU 2016-09, the APIC pool is eliminated with all excess tax benefits and deficiencies recognized in income tax expense on the income statement. Prior to the adoption of this ASU, stock option activity did not result in the accumulation of an APIC pool; therefore, adopting the ASU had minimal impact on the Company’s current financial position, results of operations or cash flows and no impact on prior results. Recently Issued Accounting Standards—In May 2014, the FASB issued guidance under FASB ASC No. 606 - Revenue from Contracts with Customers that affects any entity that enters into contracts with customers for the transfer of goods or services or transfer of non-financial assets. This guidance supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. The core principle of the new guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve that core principle, an entity should apply the following steps: (1) identify the contract with the customer, (2) identify the performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to the performance obligations in the contract, and (5) recognize revenue when, or as, the entity 45 satisfies the performance obligation. The new guidance is effective for the Company for the annual reporting period ending September 30, 2018 and interim periods within that annual period. Early application was not permitted. In August 2015, the FASB issued ASU 2015-14 that deferred the effective date of this guidance by one year to September 30, 2019. The FASB has issued subsequent guidance under ASC No. 606 to provide clarification of certain aspects of the original ASU. All additional guidance is being considered as part of the Company's evaluation of the revenue recognition standard. Although Management has not completed its evaluation of all the issued guidance under ASC No. 606, the Company does not currently expect the guidance to have a material effect on its financial position, results of operations or cash flows. In January 2016, the FASB issued ASU 2016-01, Financial Instruments - Overall: Recognition and Measurement of Financial Assets and Financial Liabilities. The ASU enhances the reporting model for financial instruments to provide users of the financial statements with more useful information through several provisions, including the following: (1) requires equity investments, excluding investments accounted for under the equity method, be measured at fair value with changes in fair value recognized in net income, (2) simplifies the impairment assessment of equity investments without readily determinable fair values, (3) eliminates the requirement to disclose the method(s) and significant assumptions used to estimate the fair value that is required to be disclosed for financial instruments measured at amortized cost on the balance sheet, (4) requires entities to use the exit price notion when measuring the fair value of financial instruments for disclosure purposes, and (5) requires separate presentation of financial assets and financial liabilities by measurement category and form of financial asset on the balance sheet or the accompanying notes to the financial statements. The new guidance is effective for the Company for the annual reporting period ending September 30, 2019 and interim periods within that annual period. Management has not completed its evaluation of the new guidance. However, the Company does not currently expect the new guidance to have a material effect on its financial position, results of operations or cash flows. In February 2016, the FASB issued ASU 2016-02, Leases. The ASU leaves the accounting for leases mostly unchanged for lessors, with the exception of targeted improvements for consistency; however, the new guidance requires lessees to recognize assets and liabilities for leases with terms of more than 12 months. The ASU also revises the definition of a lease as a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment for a period of time in exchange for consideration. Consistent with current GAAP, the presentation and cash flows arising from a lease by a lessee will primarily depend on its classification as a finance or operating lease. In contrast, the new ASU requires both types of leases to be recognized on the balance sheet. In addition, the new guidance includes quantitative and qualitative disclosure requirements to aid financial statement users in better understanding the amount, timing and uncertainty of cash flows arising from leases. The new guidance is effective for the Company for the annual reporting period ending September 30, 2020 and interim periods within that annual period. Early adoption is permitted. Management has not completed its evaluation of the new guidance. However, the Company does not currently expect the new guidance to have a material effect on its financial position, results of operations or cash flows. Other accounting standards that have been issued or proposed by the FASB or other standard–setting bodies are not currently applicable to the Company or are not expected to have a significant impact on the Company’s financial position, results of operations and cash flows. 2. REGULATORY MATTERS The SCC exercises regulatory authority over the natural gas operations of Roanoke Gas. Such regulation encompasses terms, conditions and rates to be charged to customers for natural gas service, safety standards, service extension, accounting and depreciation. On June 30, 2016, the Company filed with the SCC an application for a modification to the SAVE (Steps to Advance Virginia's Energy) Plan and Rider. The original SAVE Plan has been modified each year to incorporate certain changes and to include new projects that qualify for rate recovery under the the Plan. The SAVE Plan provides a mechanism for the Company to recover the related depreciation and expenses and return on rate base of the additional capital investment without the filing of a formal application for an increase in non-gas base rates. On October 18, 2016, the Company received approval of its application for a modification to the SAVE Plan and Rider. Under the order, the SCC approved the extension of the SAVE Plan for an additional three years through 2021, the replacement of three gas custody transfer stations and the replacement of coated steel tubing services in addition to the existing plan to replace pre-1973 plastic pipe. 46 3. OTHER INVESTMENTS In October 2015, the Company, through its wholly-owned subsidiary, RGC Midstream, LLC ("Midstream"), acquired a 1% equity interest in the Mountain Valley Pipeline, LLC (the “LLC”). The LLC was established to construct and operate a natural gas pipeline originating in northern West Virginia and extending through south central Virginia. The proposed pipeline will have the capacity to transport approximately 2 million decatherms of natural gas per day. If approved by the Federal Energy Regulatory Commission, the pipeline is expected to be in service by late 2018. The total project cost is estimated to be approximately $3.5 billion. The Company's 1% equity interest in the LLC will require a total estimated investment of approximately $35 million, by periodic capital contributions throughout the design and construction phases of the project. Midstream held an approximate $3.5 million equity method investment in the LLC at September 30, 2016. Initial funding for Midstream's investment in the LLC is provided through two unsecured Promissory Notes, each with a 5-year term, as further described in Note 5 below. The Company will participate in the earnings generated from the transportation of natural gas through the pipeline in proportion to its level of investment. The financial statement locations of the investment in the LLC are as follows: Balance Sheet Location of Other Investments: Other Assets: September 30 2016 2015 Investment in unconsolidated affiliate $ 3,496,404 $ Current Liabilities: Capital contributions payable $ 287,794 $ — — Income Statement Location of Other Investments: Equity in earnings of unconsolidated affiliate For the Years ended September 30 2016 152,864 $ $ 2015 2014 — $ — 4. SHORT-TERM DEBT The Company has available an unsecured line-of-credit with a bank which will expire March 31, 2017. The Company anticipates being able to extend or replace this line-of-credit upon expiration. The Company’s available unsecured line-of-credit varies during the year to accommodate its seasonal borrowing demands. Available limits under this agreement for the remaining term are as follows: Effective September 30, 2016 March 1, 2017 Available Line-of-Credit $ 24,000,000 17,000,000 47 A summary of the line-of-credit follows: Line-of-credit at year-end Outstanding balance at year-end Highest month-end balance outstanding Average daily balance Average rate of interest during year on outstanding balances Interest rate at year-end Interest rate on unused line-of-credit 2016 $ 24,000,000 14,556,785 15,246,089 9,620,914 September 30 2015 $ 24,000,000 9,340,997 17,366,052 6,377,040 2014 $ 15,000,000 9,045,050 9,045,050 1,340,833 1.40% 1.53% 0.15% 1.17% 1.20% 0.15% 1.16% 1.16% 0.15% Associated with the line-of-credit is a credit agreement that contains various provisions including a requirement that the Company maintain an interest coverage ratio of not less than 1.5 to 1. 5. LONG-TERM DEBT On December 29, 2015, Midstream, a wholly-owned subsidiary of Resources, entered into a Credit Agreement (the “Agreement”) and related Promissory Notes (the “Notes”) with Union Bank & Trust and Branch Banking & Trust (collectively, the “Banks”), under which Midstream may borrow up to a total of $25 million, over a period of 5 years, with an interest rate of 30-day LIBOR plus 160 basis points. Midstream issued the Notes to provide financing for capital contributions in respect of its 1% interest in the LLC. Coinciding with Midstream's entry into the Agreement and Notes, Resources entered into a Guaranty in favor of the Banks by which it guarantees Midstream's payment and performance on the Notes. Interest on the Notes is due monthly with the outstanding balance on the Notes due in full on December 29, 2020. The Notes are unsecured. In accordance with the terms of the Agreement, at such point in time as Midstream has borrowed $17.5 million under the Notes, Midstream is required to provide the next $5 million towards its capital contributions to the LLC. Once Midstream has completed its $5 million in contributions, it may resume borrowing under the Notes up to the $25 million limit. Long-term debt consists of the following: September 30 2016 2015 Principal Unamortized Debt Issuance Costs Principal Unamortized Debt Issuance Costs Roanoke Gas Company: Unsecured senior notes payable, at 4.26%, due on September 18, 2034 RGC Midstream, LLC: Unsecured term notes payable, at 30-day LIBOR plus 1.60% due December 29, 2020 Total $ 30,500,000 $ 173,773 $ 30,500,000 $ 183,427 3,396,200 86,376 — — $ 33,896,200 $ 260,149 $ 30,500,000 $ 183,427 Debt issuance costs are amortized over the life of the related debt. As of September 30, 2016 and 2015, the Company also had an unamortized loss on the early retirement of debt of $2,055,369 and $2,169,556, respectively, which has been deferred as a regulatory asset and is being amortized over a 20 year period. The unsecured notes payable contain various provisions, including two financial covenants. First, total long-term debt, including current maturities, shall not exceed 65% of total capitalization. Second, the Company shall not allow priority indebtedness to exceed 15% of total assets. 48 The aggregate annual maturities of long-term debt for the next five years ending after September 30, 2016 are as follows: Year Ending September 30 2017 2018 2019 2020 2021 Thereafter Total Maturities — — — — 3,396,200 30,500,000 33,896,200 $ $ 6. INCOME TAXES The details of income tax expense are as follows: Years Ended September 30 2016 2015 2014 Current income taxes: Federal State Total current income taxes Deferred income taxes: Federal State Total deferred income taxes Amortization of investment tax credits Total income tax expense 379,180 $ 1,789,294 $ (1,216,745) $ 415,975 (800,770) 4,302,906 164,048 4,466,954 — 374,541 753,721 2,289,729 127,112 2,416,841 — $ 3,666,184 $ 3,170,562 $ 290,458 2,079,752 687,417 175,464 862,881 (3,093) 2,939,540 Income tax expense for the years ended September 30, 2016, 2015 and 2014 differed from amounts computed by applying the U.S. Federal income tax rate of 34% to earnings before income taxes due to the following: Income before income taxes Income tax expense computed at the federal statutory rate State income taxes, net of federal income tax benefit Amortization of investment tax credits Other, net Total income tax expense Years Ended September 30 $ $ 2016 9,473,050 3,220,837 382,815 — 62,532 $ $ 2015 8,264,977 2,810,092 331,091 — 29,379 2014 7,647,980 2,600,313 307,509 (3,093) 34,811 3,666,184 $ 3,170,562 $ 2,939,540 $ $ $ 49 The tax effects of temporary differences that give rise to the deferred tax assets and deferred tax liabilities are as follows: Deferred tax assets: Allowance for uncollectibles Accrued pension and postretirement medical benefits Accrued vacation Over-recovery of gas costs Costs of gas held in storage Deferred compensation Other Total gross deferred tax assets Deferred tax liabilities: Utility plant MVP investment Accrued gas costs Total gross deferred tax liabilities Net deferred tax liability September 30 2016 2015 $ 29,203 $ 2,532,672 262,273 345,318 1,077,849 770,868 340,121 5,358,304 20,012 2,502,774 249,837 721,782 930,524 651,336 265,951 5,342,216 24,264,165 19,804,862 40,776 11,217 24,316,158 $ 18,957,854 $ — 157,385 19,962,247 14,620,031 Current federal tax expense for fiscal 2016 reflected the effect of 50% bonus depreciation for the entire fiscal year 2016 as well as for nine months of fiscal 2015. The Protecting Americans from Tax Hikes (PATH Act), which extended 50% bonus depreciation for calendar 2015, was signed into law on December 18, 2015, subsequent to the issuance of the Company's September 30, 2015 annual report. As a result, $1,283,925 of deferred taxes that related to fiscal 2015 bonus depreciation were reflected in the current year's tax provision, thereby reducing the current tax expense and increasing deferred tax expense by the same amount. The same situation occurred in fiscal 2014 when the extension of 50% bonus depreciation was not signed into law until December 19, 2014, following the issuance of the Company's financial statements for the year ended September 30, 2014. Correspondingly, fiscal 2015 income tax expense included the tax effect of the 50% bonus depreciation for fixed asset additions during the last nine months of fiscal 2014, which resulted in $1,442,211 in deferred tax expense related to fiscal 2014 being included in fiscal 2015. The recording of the effect of the adjustments for bonus depreciation had no effect on total income tax expense, net income or earnings per share. Only the current and deferred components of income tax expense and their corresponding assets and liabilities were affected. The passage of the PATH Act provides for 50% bonus depreciation through December 31, 2017, 40% in calendar 2018 and 30% in calendar 2019 with no provision for bonus depreciation after 2019. Virginia tax law does not recognize bonus depreciation; therefore, state income taxes were not impacted by the delayed bonus depreciation extensions. FASB ASC No. 740 - Income Taxes provides for the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recognized in the financial statements. The Company has evaluated its tax positions and accordingly has not identified any significant uncertain tax positions. The Company’s policy is to classify interest associated with uncertain tax positions as interest expense in the financial statements. Penalties are classified under other expense. The Company files a consolidated federal income tax return and state income tax returns in Virginia and West Virginia. The federal returns and the state returns for both Virginia and West Virginia for the tax years ended prior to September 30, 2013 are no longer subject to examination. 7. EMPLOYEE BENEFIT PLANS The Company sponsors both a noncontributory defined benefit pension plan ("pension plan") and a postretirement benefit plan ("postretirement plan"). The pension plan covers substantially all employees and benefits fully vest after 5 years of credited service. Benefits paid to retirees are based on age at retirement, years of service and average compensation. In November 2016, the Board of Directors approved a "soft freeze" to the pension plan, whereby no 50 employees hired on or after January 1, 2017 will be eligible to participate in the pension plan. Employees hired prior to January 1, 2017 will continue to participate in the plan and accrue benefits. The Board of Directors is also considering the implementation of a contribution to the 401(k) Plan for employees hired on or after January 1, 2017. The Company paid contribution would be equal to 3% of the employees' annual compensation. This Company contribution would be in addition to any employee elected deferrals and employer match as provided for under the 401(k) Plan. The postretirement benefit plan provides certain health care, supplemental retirement and life insurance benefits to retired employees who meet specific age and service requirements. Employees hired prior to January 1, 2000 are eligible to participate in the postretirement benefit plan. Employees must have a minimum of 10 years of service and retire after attaining the age of 55 in order to vest in the postretirement plan. Retiree contributions to the plan are based on the number of years of service to the Company as determined under the defined benefit plan. Employers who sponsor defined benefit plans must recognize the funded status of defined benefit pension and other postretirement plans as an asset or liability in its statement of financial position and recognize changes in that funded status in the year in which the changes occur through comprehensive income. For pension plans, the benefit obligation is the projected benefit obligation, and for other postretirement plans, the benefit obligation is the accumulated benefit obligation. The Company established a regulatory asset for the portion of the obligation expected to be recovered in rates in future periods. The regulatory asset is adjusted for the amortization of the transition obligation and recognition of actuarial gains and losses. The portion of the obligation attributable to the unregulated operations of the holding company is recognized in other comprehensive income. The following tables set forth the benefit obligation, fair value of plan assets, the funded status of the benefit plans, amounts recognized in the Company’s financial statements and the assumptions used. Accumulated benefit obligation Change in benefit obligation: Pension Plan Postretirement Plan 2016 2015 2016 2015 $ 25,090,968 $ 22,853,206 $ 18,504,710 $ 15,355,668 Benefit obligation at beginning of year $ 27,167,621 $ 24,636,695 $ 15,355,668 $ 14,983,169 Service cost Interest cost Actuarial loss Benefit payments, net of retiree contributions Benefit obligation at end of year Change in fair value of plan assets: Fair value of plan assets at beginning of year Actual return on plan assets, net of taxes Employer contributions Benefit payments, net of retiree contributions Fair value of plan assets at end of year Funded status Amounts recognized in the balance sheets consist of: 694,375 654,782 1,132,776 1,025,908 148,018 624,579 167,580 600,096 2,440,957 (1,940,779) $ 29,494,950 1,487,278 (637,042) $ 27,167,621 2,812,516 (436,071) $ 18,504,710 70,196 (465,373) $ 15,355,668 2,159,437 $ 21,394,399 $ 10,443,629 $ 10,646,249 (237,247) 500,000 1,500,000 (465,373) (1,940,779) $ 23,113,057 $ 10,443,629 $ (6,381,893) $ (5,773,222) $ (7,381,927) $ (4,912,039) $ 20,514,179 (182,738) 1,700,000 (637,042) $ 21,394,399 500,000 (436,071) $ 11,122,783 615,225 Noncurrent liabilities $ (6,381,893) $ (5,773,222) $ (7,381,927) $ (4,912,039) Amounts recognized in accumulated other comprehensive loss: Net actuarial loss, net of tax Total amounts included in other comprehensive loss, net of tax Amounts deferred to a regulatory asset: Net actuarial loss 1,583,345 1,694,924 913,886 591,621 $ 1,583,345 $ 1,694,924 $ 913,886 $ 591,621 6,732,800 5,280,756 5,563,642 3,628,448 Amounts recognized as regulatory assets $ 6,732,800 $ 5,280,756 $ 5,563,642 $ 3,628,448 51 Effective with the valuation of the September 30, 2015 defined benefit obligations, the Company adopted the RP-2014 Mortality Tables as issued by the Society of Actuaries in late 2014. The adoption of the new tables, which reflected an increase in assumed life expectancy, increased the September 30, 2015 pension liability by an estimated $1,300,000 and the postretirement liability by an estimated $1,000,000. During 2016, the Company offered a one-time, lump sum pay out option for vested, terminated employees not currently receiving payments under the pension plan. The lump sum offer was accepted by 40 of the 63 eligible participants. In September, the pension plan distributed $1,241,529 to the participants electing to receive the lump sum payments, which resulted in a corresponding reduction of approximately $1,500,000 in the projected pension obligation. The Company expects that approximately $256,000 before tax, of accumulated other comprehensive loss will be recognized as a portion of net periodic benefit costs in fiscal 2017 and approximately $836,000 of amounts deferred as regulatory assets will be amortized and recognized in net periodic benefit costs in fiscal 2017. The following table details the actuarial assumptions used in determining the projected benefit obligations and net benefit cost of the pension and the accumulated benefit obligations and net benefit cost of the postretirement plan for 2016, 2015 and 2014. Pension Plan Postretirement Plan 2016 2015 2014 2016 2015 2014 Assumptions used to determine benefit obligations: Discount rate Expected rate of compensation increase 3.42% 4.00% 4.22% 4.00% 4.22% 4.00% 3.33% N/A 4.15% N/A 4.10% N/A Assumptions used to determine benefit costs: Discount rate Expected long-term rate of return on plan assets Expected rate of compensation increase 4.22% 4.22% 4.82% 4.15% 4.10% 4.73% 7.00% 4.00% 7.00% 4.00% 7.00% 4.00% 4.89% N/A 4.90% N/A 4.92% N/A To develop the expected long-term rate of return on assets assumption, the Company, with input from the plans' actuaries and investment advisors, considered the historical returns and the future expectations for returns for each asset class, as well as the target asset allocation of each plan’s portfolio. Components of net periodic benefit cost are as follows: Service cost Interest cost Expected return on plan assets Recognized loss Pension Plan Postretirement Plan 2016 2015 2014 2016 2015 2014 $ 694,375 $ 654,782 $ 553,291 $ 148,018 $ 167,580 $ 168,634 1,132,776 (1,492,241) 501,678 1,025,908 (1,440,846) 257,378 1,020,302 (1,312,354) 136,394 624,579 (507,858) 250,173 600,096 (516,656) 197,058 602,684 (496,476) 89,515 Net periodic benefit cost $ 836,588 $ 497,222 $ 397,633 $ 514,912 $ 448,078 $ 364,357 The assumed health care cost trend rates used in measuring the accumulated benefit obligation for the postretirement medical plan as of September 30, 2016, 2015 and 2014 are presented below: 2016 Pre 65 2015 2014 2016 Post 65 2015 2014 Health care cost trend rate assumed for next year Rate to which the cost trend is assumed to decline (the ultimate trend rate) Year that the rate reaches the ultimate trend rate 7.50% 8.00% 8.50% 5.00% 5.00% 5.00% 5.00% 2021 5.00% 2021 5.00% 2021 5.00% 2016 5.00% 2015 5.00% 2014 52 The health care cost trend rate assumptions could have a significant effect on the amounts reported. A change of 1% would have the following effects: Effect on total service and interest cost components Effect on accumulated postretirement benefit obligation 1% Increase 1% Decrease $ 137,000 3,083,000 $ (109,000) (2,491,000) The primary objectives of the Plan’s investment policy are to maintain investment portfolios that diversify risk through prudent asset allocation parameters, achieve asset returns that meet or exceed the plans’ actuarial assumptions, achieve asset returns that are competitive with like institutions employing similar investment strategies and meet expected future benefits in both the short-term and long-term. The investment policy provides for a range of investment allocations to allow for flexibility in responding to market conditions. The investment policy is periodically reviewed by the Company and a third-party investment advisor. The Company’s target and actual asset allocation in the pension and postretirement benefit plans as of September 30, 2016 and 2015 were: Asset category: Equity securities Debt securities Cash Other Pension Plan Postretirement Plan Target 2016 2015 Target 2016 2015 60% 40% —% —% 63% 36% 1% —% 64% 35% 1% —% 50% 50% —% —% 52% 47% —% 1% 52% 47% 1% —% 53 The assets of the plans are invested in mutual funds. The Company uses the fair value hierarchy described in Note 1 to classify these assets. The mutual funds are included under Level 2 in the fair value hierarchy as their fair values are determined based on individual prices for each security that comprises the mutual funds. Most of the individual investments are determined based on quoted market prices for each security; however, certain fixed income securities and other investments are not actively traded and are valued based on similar investments. The following table contains the fair value classifications of the benefit plan assets: Defined Benefit Pension Plan Fair Value Measurements - September 30, 2016 Fair Value Level 1 Level 2 Level 3 $ 117,265 $ 117,265 $ — $ Asset Class: Cash Common and Collective Trust and Pooled Funds: Bonds Domestic Fixed Income 4,497,373 Equities Domestic Large Cap Growth Domestic Large Cap Value Domestic Small/Mid Cap Core Foreign Large Cap Value 3,426,041 4,543,385 2,149,566 1,795,897 Mutual Funds: Bonds Domestic Fixed Income Foreign Fixed Income Equities Domestic Large Cap Growth Foreign Large Cap Growth Foreign Large Cap Value Foreign Large Cap Core Total $ 3,615,209 234,622 1,043,395 366,420 373,480 950,404 23,113,057 $ — — — — — — — — — — — 117,265 $ 4,497,373 3,426,041 4,543,385 2,149,566 1,795,897 3,615,209 234,622 1,043,395 366,420 373,480 950,404 22,995,792 $ — — — — — — — — — — — — — 54 Defined Benefit Pension Plan Fair Value Measurements - September 30, 2015 Fair Value Level 1 Level 2 Level 3 $ 106,502 $ 106,502 $ — $ Asset Class: Cash Common and Collective Trust and Pooled Funds: Bonds Domestic Fixed Income 3,996,246 Equities Domestic Large Cap Growth Domestic Large Cap Value Domestic Small/Mid Cap Core Foreign Large Cap Value Mutual Funds: Bonds Domestic Fixed Income Foreign Fixed Income Equities Domestic Large Cap Growth Foreign Large Cap Value Foreign Large Cap Core 3,150,561 4,183,172 1,937,613 1,873,313 3,313,331 213,118 1,030,957 653,276 936,310 — — — — — — — — — — 3,996,246 3,150,561 4,183,172 1,937,613 1,873,313 3,313,331 213,118 1,030,957 653,276 936,310 Total $ 21,394,399 $ 106,502 $ 21,287,897 $ Postretirement Benefit Plan Fair Value Measurements - September 30, 2016 Fair Value Level 1 Level 2 Level 3 $ 43,455 $ 43,455 $ — $ Asset Class: Cash Mutual Funds Bonds Domestic Fixed Income Foreign Fixed Income Equities Domestic Large Cap Growth Domestic Large Cap Value Domestic Small/Mid Cap Growth Domestic Small/Mid Cap Value Domestic Small/Mid Cap Core Foreign Large Cap Value Foreign Large Cap Core Other Total 5,109,834 87,821 1,824,796 1,770,664 195,319 198,884 427,409 964,827 456,100 43,674 — — — — — — — — — — 5,109,834 87,821 1,824,796 1,770,664 195,319 198,884 427,409 964,827 456,100 43,674 $ 11,122,783 $ 43,455 $ 11,079,328 $ — — — — — — — — — — — — — — — — — — — — — — — — 55 Postretirement Benefit Plan Fair Value Measurements - September 30, 2015 Fair Value Level 1 Level 2 Level 3 $ 58,749 $ 58,749 $ — $ Asset Class: Cash Mutual Funds Bonds Domestic Fixed Income Foreign Fixed Income Equities Domestic Large Cap Growth Domestic Large Cap Value Domestic Small/Mid Cap Growth Domestic Small/Mid Cap Value Domestic Small/Mid Cap Core Foreign Large Cap Value Foreign Large Cap Core Other Total 4,845,174 38,654 1,746,621 1,638,695 194,260 186,344 417,980 893,115 378,596 45,441 — — — — — — — — — — 4,845,174 38,654 1,746,621 1,638,695 194,260 186,344 417,980 893,115 378,596 45,441 $ 10,443,629 $ 58,749 $ 10,384,880 $ — — — — — — — — — — — — Each mutual fund has been categorized based on its primary investment strategy. The Company expects to contribute $750,000 to its pension plan and $1,000,000 to its postretirement benefit plan in fiscal 2017. The following table reflects expected future benefit payments: Fiscal year ending September 30 2017 2018 2019 2020 2021 2022-2026 $ Pension Plan Postretirement Plan $ 774,312 836,309 910,261 983,917 1,048,990 6,613,848 642,842 656,790 679,876 705,769 747,426 4,226,050 The Company also sponsors a defined contribution plan (the “401k Plan”) covering all employees who elect to participate. Employees may contribute from 1% to 50% of their annual compensation to the 401k Plan, limited to a maximum annual amount as set periodically by the Internal Revenue Service. The Company matches 100% of the participant’s first 4% of contributions and 50% on the next 2% of contributions. Company matching contributions were $353,793, $338,896 and $330,241 for 2016, 2015 and 2014, respectively. 8. COMMON STOCK OPTIONS The Company’s stockholders approved the RGC Resources, Inc. Key Employee Stock Option Plan (“KESOP”). The KESOP provides for the issuance of common stock options to officers and certain other full-time salaried employees to acquire shares of the Company’s common stock. As of September 30, 2016, the number of shares available for future grants was 41,000. FASB ASC No. 718 - Compensation-Stock Compensation requires that compensation expense be recognized for the issuance of equity instruments to employees. During the fiscal years ended 2016, 2015 and 2014, the Board approved stock option grants to certain officers. As required by the KESOP, each option's exercise price per share equaled the 56 fair value of the Company's common stock on the grant date. Pursuant to the Plan, the options vest over a six-month period and are exercisable over a ten-year period from the date of issuance. As the Company's stock options are not traded on the open market, the fair value of each grant is estimated on the date of grant using the Black-Scholes option pricing model including the following assumptions: Expected volatility Expected dividends Expected exercise term (years) Risk-free interest rate Years Ended September 30, 2016 28.78% 3.99% 7.00 2.10% 2015 34.34% 4.11% 7.00 1.98% 2014 35.01% 4.21% 7.00 2.23% The underlying methods regarding each assumption are as follows: Expected volatility is based on the historical volatilities of the daily closing price of the Company's common stock. Expected dividend rate is based on historical dividend payout trends. Expected exercise term is based on the average time historical option grants were outstanding before being exercised. Risk-free interest rate is based on the 7-year Treasury rate on the date of option grant. Forfeitures are recognized when they occur. Stock option transactions under the Company's plans for the years ended September 30, 2016, 2015 and 2014 are summarized below: Number of Shares Weighted- Average Exercise Price Options outstanding, September 30, 2013 Options granted Options exercised Options expired Options forfeited Options outstanding, September 30, 2014 Options granted Options exercised Options expired Options forfeited Options outstanding, September 30, 2015 Options granted Options exercised Options expired Options forfeited $ 21,000 17,000 — — — 38,000 17,000 (2,600) — — 52,400 16,000 (2,200) — (8,000) Options outstanding, September 30, 2016 58,200 $ 19.01 18.95 — — — 18.98 21.60 18.99 — — 19.83 21.22 18.98 — 19.80 20.25 Vested and exercisable at September 30, 2016 58,200 $ 20.25 1 Aggregate intrinsic value includes only those options where the exercise price is below the market price. 57 Weighted- Average Remaining Contractual Terms (years) 9.5 Aggregate Intrinsic Value 1 $ 5,229 8.8 34,840 8.3 43,086 7.8 7.8 $ $ 200,211 200,211 The weighted-average grant-date fair value of options granted during the years ended September 30, 2016, 2015 and 2014 was $4.04, $4.92 and $4.43, respectively. The intrinsic value of the options exercised during fiscal 2016 and 2015 was $8,418 and $5,624, respectively. The Company recognized $64,640, $83,640 and $75,310 in stock option expense in fiscal 2016, 2015 and 2014, respectively. The Company received $41,762 and $49,366 from the exercise of options in 2016 and 2015. No options were exercised in 2014. 9. OTHER STOCK PLANS Dividend Reinvestment and Stock Purchase Plan The Company offers a Dividend Reinvestment and Stock Purchase Plan (the “DRIP”) to shareholders of record for the reinvestment of dividends and the purchase of up to $40,000 per year in additional shares of common stock of the Company. Under the DRIP, the Company issued 34,764, 8,431 and 7 shares in 2016, 2015 and 2014, respectively. As of September 30, 2016, the Company had 323,613 shares of stock available for issuance under the DRIP. Restricted Stock Plan The Board of Directors of the Company implemented the Restricted Stock Plan for Outside Directors (the “Plan”) effective January 27, 1997. Under the Plan, a minimum of 40% of the monthly retainer fee paid to each non-employee director of Resources was paid in shares of common stock (“Restricted Stock”). The number of shares of Restricted Stock awarded each month is determined based on the closing sales price of Resources' common stock on the NASDAQ Global Market on the first business day of the month. The Restricted Stock issued under the Plan vests only in the case of a participant's death, disability, retirement, or in the event of a change in control of Resources. The Restricted Stock may not be sold, transferred, assigned or pledged by the participant until the shares have vested under the terms of the Plan. The shares of Restricted Stock will be forfeited to Resources by a participant's voluntary resignation during his or her term on the Board or removal for cause as a director. Effective October 1, 2016, the Board of Directors amended the Plan to remove the requirement that directors take a minimum 40% of their retainer in Restricted Stock for those directors who owned at least 10,000 shares of Resources stock. The Company assumes all directors will complete their term and there will be no forfeiture of the Restricted Stock. Since the inception of the Plan, no director has forfeited any shares of Restricted Stock. The Company recognizes as compensation the market value of the Restricted Stock in the period it is issued. The following table reflects the director compensation activity pursuant to the Restricted Stock Plan: 2016 2015 2014 Weighted-Average Fair Value on Date of Grant Shares Weighted-Average Fair Value on Date of Grant Shares Weighted-Average Fair Value on Date of Grant Shares Beginning of year balance 66,915 $ Granted Vested Forfeited 4,433 — — 14.70 22.18 — — 62,844 $ 4,071 — — 14.29 20.88 — — 59,064 $ 3,780 — — 13.97 19.37 — — End of year balance 71,348 $ 15.16 66,915 $ 14.70 62,844 $ 14.29 The fair market value of the Restricted Stock issued as compensation during fiscal 2016, 2015 and 2014 was $98,334, $85,000 and $73,200. No Restricted Stock vested or was forfeited during fiscal 2016, 2015 and 2014. As of September 30, 2016, the Company had 63,008 shares available for issuance under the Restricted Stock Plan. Stock Bonus Plan Under the Stock Bonus Plan, executive officers are encouraged to own a position in the Company’s common stock of at least 50% of the value of their annual salary. To promote this policy, the Plan provides that all officers with stock ownership positions below 50% of the value of their annual salaries must, unless approved by the Committee, use no 58 less than 50% of any performance bonus to purchase Company common stock. Shares from the Stock Bonus Plan may also be issued to certain employees and management personnel in recognition of their performance and service. Under the Stock Bonus Plan, the Company issued 1,875, 2,731 and 4,098 shares valued at $39,819, $59,332 and $78,841, respectively, in 2016, 2015 and 2014. As of September 30, 2016 the Company had 6,299 shares of stock available for issuance under the Stock Bonus Plan. 10. COMMITMENTS AND CONTINGENCIES Long-Term Contracts Due to the nature of the natural gas distribution business, the Company enters into agreements with both suppliers and pipelines to contract for natural gas commodity purchases, storage capacity and pipeline delivery capacity. The Company obtains most of its regulated natural gas supply through an asset management contract between Roanoke Gas and a third party asset manager. The Company utilizes an asset manager to optimize the use of its transportation, storage rights, and gas supply inventories which helps to ensure a secure and reliable source of natural gas. Under the current asset management contract, the Company has designated the asset manager to act as agent for the Company's storage capacity and all gas balances in storage. The Company retains ownership of gas in storage. Under provisions of this contract, the Company is obligated to purchase its winter storage requirements from the asset manager during the spring and summer injection periods at market price. The table below details the volumetric obligations as of September 30, 2016 for the remainder of the contract period. The current asset management contract will expire in March 2018. Year 2016-2017 2017-2018 Total Natural Gas Contracts (In Decatherms) 2,071,061 295,866 2,366,927 The Company also has contracts for pipeline and storage capacity which extend for various periods. These capacity costs and related fees are valued at tariff rates in place as of September 30, 2016. These rates may increase or decrease in the future based upon rate filings and rate orders granting a rate change to the pipeline or storage operator. Roanoke Gas expended approximately $24,852,000, $33,405,000 and $44,884,000 under the asset management, pipeline and storage contracts in fiscal years 2016, 2015 and 2014, respectively. The table below details the pipeline and storage capacity obligations as of September 30, 2016 for the remainder of the contract period. Year 2016-2017 2017-2018 2018-2019 2019-2020 2020-2021 Thereafter Total Other Contracts Pipeline and Storage Capacity $ 10,474,339 8,784,004 7,215,235 4,800,201 2,476,475 2,682,848 $ 36,433,102 The Company maintains other agreements in the ordinary course of business covering various lease, maintenance, equipment and service contracts. These agreements currently extend through December 2031 and are not material to the Company. Legal From time to time, the Company may become involved in litigation or claims arising out of its operations in the normal course of business. At the current time, the Company is not known to be a party to any legal proceedings that would be expected to have a materially adverse impact on its financial position, results of operations or cash flows. 59 Environmental Matters Both Roanoke Gas and a previously owned gas subsidiary operated manufactured gas plants (MGPs) as a source of fuel for lighting and heating until the early 1950’s. A by-product of operating MGPs was coal tar, and the potential exists for tar waste contaminants at the former plant sites. While the Company does not currently recognize any commitments or contingencies related to environmental costs at either site, should the Company ever be required to remediate either site, it will pursue all prudent and reasonable means to recover any related costs, including the use of insurance claims and regulatory approval for rate case recognition of expenses associated with any work required. 11. FAIR VALUE MEASUREMENTS The following table summarizes the Company’s financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements by level within the fair value hierarchy as defined in Note 1 as of September 30, 2016 and 2015, respectively: Liabilities: Natural gas purchases Total Liabilities: Natural gas purchases Total Fair Value Measurements - September 30, 2016 Quoted Prices in Active Markets Level 1 Significant Other Observable Inputs Level 2 Significant Unobservable Inputs Level 3 Fair Value 1,052,930 1,052,930 $ $ — $ — $ 1,052,930 1,052,930 $ $ — — Fair Value Measurements - September 30, 2015 Quoted Prices in Active Markets Level 1 Significant Other Observable Inputs Level 2 Significant Unobservable Inputs Level 3 Fair Value 712,710 712,710 $ $ — $ — $ 712,710 712,710 $ $ — — $ $ $ $ Under the asset management contract, a timing difference can exist between the payment for natural gas purchases and the actual receipt of such purchases. Payments are made based on a predetermined monthly volume with the price based on the weighted average first of the month index prices corresponding to the month of the scheduled payment. At September 30, 2016 and 2015, the Company had recorded in accounts payable the estimated fair value of the liability determined on the corresponding first of month index prices for which the liability was expected to be settled. The Company’s nonfinancial assets and liabilities that are measured at fair value on a nonrecurring basis consist of its asset retirement obligations. The asset retirement obligations are measured at fair value at initial recognition based on expected future cash flows to settle the obligation. The carrying value of cash and cash equivalents, accounts receivable, borrowings under line-of-credit, accounts payable (with the exception of the timing difference under the asset management contract), customer credit balances and customer deposits is a reasonable estimate of fair value due to the short-term nature of these financial instruments. The following table summarizes the fair value of the Company’s financial assets and liabilities that are not adjusted to fair value in the financial statements as of September 30, 2016 and 2015. Liabilities: Long-term debt Total Fair Value Measurements - September 30, 2016 Carrying Amount Quoted Prices in Active Markets Level 1 Significant Other Observable Inputs Level 2 Significant Unobservable Inputs Level 3 $ $ 33,896,200 33,896,200 $ $ — $ — $ — $ — $ 36,163,523 36,163,523 60 Liabilities: Long-term debt Total Fair Value Measurements - September 30, 2015 Carrying Amount Quoted Prices in Active Markets Level 1 Significant Other Observable Inputs Level 2 Significant Unobservable Inputs Level 3 $ $ 30,500,000 30,500,000 $ $ — $ — $ — $ — $ 28,570,585 28,570,585 The fair value of long-term debt for Roanoke Gas is estimated by discounting the future cash flows of the fixed rate debt based on the underlying 20-year Treasury rate and estimated credit spread extrapolated based on market conditions since the issuance of the debt. A 52 basis point drop in the 20-year Treasury combined with a reduction in the assumed credit spreads accounted for the increase in the fair value of the fixed rate debt. The fair value for the RGC Midstream debt is estimated by discounting the estimated credit spread extrapolated based on market conditions. FASB ASC 825 – Financial Instruments requires disclosures regarding concentrations of credit risk from financial instruments. Cash equivalents are investments in high-grade, short-term securities (original maturity less than three months), placed with financially sound institutions. Accounts receivable are from a diverse group of customers including individuals and small and large companies in various industries. The Company maintains certain credit standards with its customers and requires a customer deposit if such evaluation warrants. 12. QUARTERLY FINANCIAL INFORMATION (UNAUDITED) Quarterly financial data for the years ended September 30, 2016 and 2015 is summarized as follows: 2016 Operating revenues Gross margin Operating income Net income Earnings per share of common stock: Basic Diluted 2015 Operating revenues Gross margin Operating income Net income Earnings per share of common stock: Basic Diluted 13. SUBSEQUENT EVENTS First Quarter 16,010,056 8,738,116 3,498,052 1,922,790 0.40 0.40 First Quarter 21,250,065 8,622,143 3,514,352 1,924,376 0.41 0.41 $ $ $ $ $ $ $ $ $ $ $ $ Second Quarter 21,777,773 10,649,269 5,444,314 3,111,447 0.65 0.65 Second Quarter 26,431,729 10,213,770 4,879,469 2,779,344 0.59 0.59 $ $ $ $ $ $ $ $ $ $ $ $ Third Quarter 11,295,197 6,312,340 1,453,350 627,068 0.13 0.13 Third Quarter 10,774,409 5,961,828 956,219 354,940 0.08 0.07 $ $ $ $ $ $ $ $ $ $ $ $ Fourth Quarter 9,980,265 5,865,189 816,376 145,561 0.03 0.03 Fourth Quarter 9,733,404 5,408,692 656,152 35,755 0.01 0.01 $ $ $ $ $ $ $ $ $ $ $ $ On November 1, 2016, Roanoke Gas entered into a 5-year unsecured note with Branch Banking and Trust in the principal amount of $7,000,000. The note is variable rate with interest based on 30-day LIBOR plus 90 basis points. In addition, Roanoke Gas also entered into a swap agreement to convert the variable rate debt into a fixed-rate instrument with an annual interest rate of 2.30%. The swap agreement is effective November 1, 2017, with the monthly interest rate floating until the swap period begins. The proceeds from the note will be used to convert a portion of the Company's line-of-credit balance into longer-term financing. 61 The Company has evaluated subsequent events through the date the financial statements were issued. There were no other items not otherwise disclosed which would have materially impacted the Company’s consolidated financial statements. * * * * * * 62 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. None. Item 9A. Controls and Procedures. The Company maintains disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) that are designed to be effective in providing reasonable assurance that information required to be disclosed in reports under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission (the “SEC”), and that such information is accumulated and communicated to management to allow for timely decisions regarding required disclosure. As of September 30, 2016, the Company completed an evaluation, under the supervision and with the participation of management, including the chief executive officer and the chief financial officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures. Based upon that evaluation, the chief executive officer and chief financial officer concluded that the Company’s disclosure controls and procedures were effective at the reasonable assurance level as of September 30, 2016. Management routinely reviews the Company’s internal control over financial reporting and makes changes, as necessary, to enhance the effectiveness of the internal controls over financial reporting. There were no changes in the internal controls over financial reporting during the fourth quarter of the fiscal year covered by this report that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting. MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) under the Securities and Exchange Act of 1934). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation and fair presentation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America and include those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorizations of the management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the financial statements. Because of the inherent limitations, any system of internal control over financial reporting, no matter how well designed, may not prevent or detect misstatements due to the possibility that a control can be circumvented or overridden or that misstatements due to error or fraud may occur that are not detected. Projections of the effectiveness to future periods are subject to the risk that the internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures included in such controls may deteriorate. The Company’s internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. The Company has conducted an evaluation of the design and effectiveness of the Company’s system of internal control over financial reporting as of September 30, 2016, based on the framework set forth in ”Internal Control - Integrated Framework (2013)” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based upon such evaluation, the Company concluded that, as of September 30, 2016, the Company’s internal control over financial reporting was effective. The Company’s independent registered public accounting firm, Brown, Edwards & Company, LLP, has issued its report on the effectiveness of the Company’s internal control over financial reporting as of September 30, 2016. 63 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Board of Directors and Stockholders RGC Resources, Inc. Roanoke, Virginia We have audited RGC Resources, Inc. and Subsidiaries (“the Company”)’s internal control over financial reporting as of September 30, 2016, based on criteria established in Internal Control-Integrated Framework - 2013 issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). RGC Resources, Inc. and Subsidiaries’ management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. In our opinion, RGC Resources, Inc. and Subsidiaries (“the Company”) maintained, in all material respects, effective internal control over financial reporting as of September 30, 2016, based on criteria established in Internal Control-Integrated Framework - 2013 issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets as of September 30, 2016 and 2015 and the related consolidated statements of income, comprehensive income, stockholders’ equity, and cash flows of RGC Resources, Inc. and Subsidiaries for each of the years in the three year period ended September 30, 2016, and our report dated December 8, 2016 expressed an unqualified opinion. CERTIFIED PUBLIC ACCOUNTANTS 1715 Pratt Drive, Suite 2700 Blacksburg, Virginia December 8, 2016 64 Item 9B. Other Information None 65 Item 10. Directors, Executive Officers and Corporate Governance. PART III For information with respect to the executive officers of the registrant, see “Executive Officers" section in the Proxy Statement for the 2017 Annual Meeting of Shareholders of Resources incorporated herein by reference. For information with respect to the Company’s directors and nominees and the Company’s Audit Committee, see Proposal 1 “Election of Directors of Resources” and “Report of the Audit Committee”, respectively, in the Proxy Statement for the 2017 Annual Meeting of Shareholders of Resources, which information is incorporated herein by reference. In addition, the Board of Directors has determined that George W. Logan and Raymond D. Smoot, Jr. are audit committee financial experts under applicable SEC rules. For information regarding the process for identifying and evaluating candidates to be nominated as directors, see "Director Nominations" in the Proxy Statement for the 2017 Annual Meeting of Shareholders of Resources, which is incorporated herein by reference. Information with respect to compliance with Section 16(a) of the Exchange Act, which is set forth under the caption "Section 16 Compliance" in the Proxy Statement for the 2017 Annual Meeting of Shareholders of Resources, is incorporated herein by reference. The Company has adopted a Code of Ethics applicable to all of its officers, directors and employees. The Company has posted the text of its Code of Ethics on its website at www.rgcresources.com. The Board of Directors has adopted charters for the Audit, Compensation, and Corporate Governance and Nominating Committees of the Board of Directors. These documents may also be found on the Company’s website at www.rgcresources.com. Item 11. Executive Compensation. The information set forth under "Compensation of Directors", "Compensation Discussion and Analysis" and "Report of the Compensation Committee" in the Proxy Statement for the 2017 Annual Meeting of Shareholders of Resources is incorporated herein by reference. Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. For information pertaining to securities authorized for issuance under equity compensation plans, see Part II, Item 5 above. The information pertaining to shareholders beneficially owning more than five percent of the registrant’s common stock and the security ownership of management, which is set forth under the caption “Security Ownership of Certain Beneficial Owners and Management" in the Proxy Statement for the 2017 Annual Meeting of Shareholders of Resources, is incorporated herein by reference. Item 13. Certain Relationships and Related Transactions, and Director Independence. For information with respect to certain relationships and related transactions, see "Transactions with Related Persons" section in the Proxy Statement for the 2017 Annual Meeting of Shareholders of Resources, which is incorporated herein by reference. The information pertaining to director independence is set forth under the caption “Board of Directors and Committees of the Board of Directors” and pertaining to transactions with related persons is set forth under the caption "Transactions with Related Persons" in the Proxy Statement for the 2017 Annual Meeting of Shareholders of Resources, which information is incorporated herein by reference. Item 14. Principal Accounting Fees and Services. The information set forth under the caption "Report of the Audit Committee" in the Proxy Statement for the 2017 Annual Meeting of Shareholders of Resources is incorporated herein by reference. 66 Item 15. Exhibits and Financial Statement Schedules. (a) List of documents filed as part of this report: PART IV 1. 2. Financial statements filed as part of this report: All financial statements of the registrant as set forth under Item 8 of this Report on Form 10-K. Financial statement schedules filed as part of this report: All information is inapplicable or presented in the consolidated financial statements or related notes thereto. 3. Exhibits to this Form 10-K filed as part of this report: 10 (l)(l) Second Amendment to RGC Resources, Inc. Restricted Stock Plan for Outside Directors 21 23 31.1 31.2 32.1* 32.2* 101 Subsidiaries of the Company Consent of Brown, Edwards & Company, LLP Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer Section 1350 Certification of Principal Executive Officer Section 1350 Certification of Principal Financial Officer The following documents from the Registrant’s Annual Report on Form 10-K for the years ended September 30, 2016, 2015 and 2014, formatted in XBRL (eXtensible Business Reporting Language); Consolidated Balance Sheets at September 30, 2016 and 2015, (ii) Consolidated Statements of Income for the years ended September 30, 2016, 2015 and 2014, (iii) Consolidated Statements of Comprehensive Income for the years ended September 30, 2016, 2015 and 2014, (iv) Consolidated Statements of Stockholders’ Equity for the years ended September 30, 2016, 2015 and 2014, (v) Consolidated Statements of Cash Flows for the years ended September 30, 2016, 2015 and 2014, and (vi) Notes to Consolidated Financial Statements. * These certifications are being furnished solely to accompany this annual report pursuant to 18 U.S.C. Section 1350, and are not being filed for purposes of Section 18 of the Securities Exchange Act of 1934 and are not to be incorporated by reference into any filing of the registrant, whether made before or after the date hereof, regardless of any general incorporation language in such filing. 67 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Annual Report on Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized. SIGNATURES RGC RESOURCES, INC. By: /S/ PAUL W. NESTER Paul W. Nester Vice President, Secretary, Treasurer and CFO (principal accounting and financial officer) December 8, 2016 Date 68 Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report on Form 10-K has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated. /S/ JOHN S. D'ORAZIO December 8, 2016 John S. D'Orazio Date President and Chief Executive Officer, Director /S/ PAUL W. NESTER December 8, 2016 Paul W. Nester Date Vice President, Treasurer and CFO (principal accounting and financial officer) /S/ JOHN B. WILLIAMSON, III December 8, 2016 Chairman of the Board and Director John B. Williamson, III Date /S/ NANCY H. AGEE December 8, 2016 Director Nancy H. Agee Date /S/ ABNEY S. BOXLEY, III December 8, 2016 Director Abney S. Boxley, III Date /S/ MARYELLEN F. GOODLATTE December 8, 2016 Director Maryellen F. Goodlatte Date /S/ J. ALLEN LAYMAN J. Allen Layman December 8, 2016 Director Date /S/ GEORGE W. LOGAN George W. Logan December 8, 2016 Director Date /S/ S. FRANK SMITH S. Frank Smith December 8, 2016 Director Date /S/ RAYMOND D. SMOOT, JR. December 8, 2016 Director Raymond D. Smoot, Jr. Date 69 Exhibit No. 3 (a) 3 (b) 4 (a) 4 (b) 10 (a) 10 (b) 10 (c) 10 (d) 10 (e) 10 (f) 10 (g) 10 (h) 10 (i) 10 (j) EXHIBIT INDEX Description Articles of Incorporation of RGC Resources, Inc. (incorporated herein by reference to Exhibit 3(a) of Registration Statement No. 33-67311, on Form S-4, filed with the Commission on November 13, 1998, and amended by Amendment No. 5, filed with the Commission on January 28, 1999) Amended and Restated Bylaws of RGC Resources, Inc. (incorporated herein by reference to Exhibit 3(b) on the Form 10-K for the year ended September 30, 2011) Specimen copy of certificate for RGC Resources, Inc. common stock, $5.00 par value (incorporated herein by reference to Exhibit 3(b) of Registration Statement No. 33-67311, on Form S-4, filed with the Commission on November 13, 1998, and amended by Amendment No. 5, filed with the Commission on January 28, 1999) RGC Resources, Inc., Amended and Restated Dividend Reinvestment and Stock Purchase Plan (incorporated by reference to Exhibit 4(b) of the Form 10-K for the year ended September 30, 2014) Firm Transportation Agreement between East Tennessee Natural Gas Company and Roanoke Gas Company dated November 1, 1993 (incorporated herein by reference to Exhibit 10(a) of the Annual Report on Form 10-K for the fiscal year ended September 30, 1994 (SEC file number reference 0-367)) NTS Service Agreement between Columbia Gas Transmission Corporation and Roanoke Gas Company dated September 3, 2004 (incorporated herein by reference to Exhibit 10(g)(g)(g) of the Quarterly Report on Form 10-Q for the period ended December 31, 2004) FSS Service Agreement between Columbia Gas Transmission Corporation and Roanoke Gas Company dated September 3, 2004 (incorporated herein by reference to Exhibit 10(h)(h)(h) of the Quarterly Report Form 10-Q for the period ended December 31, 2004) FTS Service Agreement between Columbia Gas Transmission Corporation and Roanoke Gas Company dated September 3, 2004 (incorporated herein by reference to Exhibit 10(i)(i)(i) of the Quarterly Report on Form 10-Q for the period ended December 31, 2004) SST Service Agreement between Columbia Gas Transmission Corporation and Roanoke Gas Company dated September 3, 2004 (incorporated herein by reference to Exhibit 10(j)(j)(j) of the Quarterly Report on Form 10-Q for the period ended December 31, 2004) FTS-1 Service Agreement between Columbia Gulf Transmission Corporation and Roanoke Gas Company dated September 3, 2004 (incorporated herein by reference to Exhibit 10(k)(k)(k) of the Quarterly Report on Form 10-Q for period ended December 31, 2004) ITS-1 Service Agreement between Columbia Gulf Transmission Company and Roanoke Gas Company dated November 1, 1993 (incorporated herein by reference to Exhibit 10(j) of the Annual Report on Form 10-K for the fiscal year ended September 30, 1994 (SEC file number reference 0-367)) Gas Transportation Agreement, for use under FT-A rate schedule, between Tennessee Gas Pipeline Company and Roanoke Gas Company dated November 1, 1993 (incorporated herein by reference to Exhibit 10(k) of the Annual Report on Form 10-K for the fiscal year ended September 30, 1994 (SEC file number reference 0-367)) Gas Transportation Agreement, for use under IT rate schedule, between Tennessee Gas Pipeline Company and Roanoke Gas Company dated September 1, 1993 (incorporated herein by reference to Exhibit 10(l) of the Annual Report on Form 10-K for the fiscal year ended September 30, 1994 (SEC file number reference 0-367)) Gas Storage Contract under rate schedule FS (Production Area) Bear Creek II between Tennessee Gas Pipeline Company and Roanoke Gas Company dated November 1, 1993 (incorporated herein by reference to Exhibit 10(m) of the Annual Report on Form 10-K for the fiscal year ended September 30, 1994 (SEC file number reference 0-367)) 10 (k) 10 (l) 10 (m) 10 (n) 10 (o) 10 (p) 10 (q) 10 (r) 10 (s) 10 (t) 10 (u) 10 (v) 10 (w) 10 (x) 10 (y) Gas Storage Contract under rate schedule FS (Production Area) Bear Creek I between Tennessee Gas Pipeline Company and Roanoke Gas Company dated September 1, 1993 (incorporated herein by reference to Exhibit 10(n) of the Annual Report on Form 10-K for the fiscal year ended September 30, 1994 (SEC file number reference 0-367)) Gas Storage Contract under rate schedule FS (Market Area) Portland between Tennessee Gas Pipeline Company and Roanoke Gas Company dated November 1, 1993 (incorporated herein by reference to Exhibit 10(k)(k) of the Annual Report on Form 10-K for the fiscal year ended September 30, 1994 (SEC file number reference 0-367)) FTA Gas Transportation Agreement effective November 1, 1998, between East Tennessee Natural Gas Company and Roanoke Gas Company (incorporated herein by reference to Exhibit 10(s)(s) of Annual Report on Form 10-K for the fiscal year ended September 30, 1998 (SEC file reference number 0-367)) FTS Service Agreement effective November 1, 1999, between Columbia Gas Transmission Corporation and Roanoke Gas Company (incorporated herein by reference to Exhibit 10(p)(p) of Annual Report on Form 10-K for the fiscal year ended September 30, 2001 (SEC file reference number 0-367)) Firm Storage Service Agreement effective March 19, 1997, between Virginia Gas Storage Company and Roanoke Gas Company (incorporated herein by reference to Exhibit 10(w)(w) of Annual Report on Form 10-K for the fiscal year ended September 30, 1998 (SEC file reference number 0-367)) Firm Storage Service Agreement by and between Roanoke Gas Company and Virginia Gas Pipeline Company, dated June 1, 2001 (incorporated herein by reference to Exhibit 10(b)(b)(b) of Annual Report on Form 10-K for the fiscal year ended September 30, 2001 (SEC file number reference 0-367)) Firm Pipeline Service Agreement by and between Roanoke Gas Company and Virginia Gas Pipeline Company, dated June 1, 2001 (incorporated herein by reference to Exhibit 10(c)(c)(c) of Annual Report on Form 10-K for the fiscal year ended September 30, 2001 (SEC file number reference 0-367)) Natural Gas Asset Management Agreement by and between Roanoke Gas Company and Sequent Energy Management LP effective as of November 1, 2013 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed October 9, 2013 (SEC file number reference 0-367)) Notice of Renewal of Natural Gas Asset Management Agreement originally dated November 1, 2013 between Sequent Energy Management and Roanoke Gas Company with an effective date of March 31, 2017 (incorporated by reference to Exhibit 10.4 of Form 10-Q as filed August 4, 2016) Guaranty Agreement between RGC Resources, Inc. and Sequent Energy Management effective June 7, 2016. (incorporated herein by reference to Exhibit 10.5 on Form 10-Q as filed August 4, 2016) Gas Transportation Agreement between Tennessee Gas Pipeline Company and Roanoke Gas Company originally dated November 1, 1999 as amended May 17, 2016 (incorporated herein by reference to Exhibit 10.3 of Form 10-Q as filed August 4, 2016) Amendment dated May 17, 2016 to Gas Transportation Agreement originally dated December 1, 1993 between Tennessee Gas Pipeline Company and Roanoke Gas Company (incorporated herein by reference to Exhibit 10.1 of Form 10-Q as filed August 4, 2016) Amendment dated May 17, 2016 to Gas Transportation Agreement originally dated November 1, 1993 between Tennessee Gas Pipeline Company and Roanoke Gas Company (incorporated herein by reference to Exhibit 10.2 of Form 10-Q as filed August 4, 2016) Certificate of Public Convenience and Necessity for Bedford County dated February 21, 1966 (incorporated herein by reference to Exhibit 10(o) of Registration Statement No. 33-36605, on Form S-2, filed with the Commission on August 29, 1990, and amended by Amendment No. 1, filed with the Commission on September 19, 1990) Certificate of Public Convenience and Necessity for Roanoke County dated October 19, 1965 (incorporated herein by reference to Exhibit 10(p) of Registration Statement No. 33-36605, on Form S-2, filed with the Commission on August 29, 1990, and amended by Amendment No. 1, filed with the Commission on September 19, 1990) 10 (z) 10 (a)(a) 10 (b)(b) 10 (c)(c) 10 (d)(d) 10 (e)(e) 10 (f)(f) 10 (g)(g) 10 (h)(h) 10 (i)(i) 10 (j)(j) 10 (k)(k) 10 (l)(l) 10 (m)(m) 10 (n)(n) 10 (o)(o) Certificate of Public Convenience and Necessity for Botetourt County dated August 30, 1966 (incorporated herein by reference to Exhibit 10(q) of Registration Statement No. 33-36605, on Form S-2, filed with the Commission on August 29, 1990, and amended by Amendment No. 1, filed with the Commission on September 19, 1990) Certificate of Public Convenience and Necessity for Montgomery County dated July 8, 1985 (incorporated herein by reference to Exhibit 10(r) of Registration Statement No. 33-36605, on Form S-2, filed with the Commission on August 29, 1990, and amended by Amendment No. 1, filed with the Commission on September 19, 1990) Certificate of Public Convenience and Necessity for Franklin County dated September 8, 1964 (incorporated herein by reference to Exhibit 10(t) of Registration Statement No. 33-36605, on Form S-2, filed with the Commission on August 29, 1990, and amended by Amendment No. 1, filed with the Commission on September 19, 1990) Resolution of the Council for the Town of Fincastle, Virginia dated June 8, 1970 (incorporated herein by reference to Exhibit 10(f) of Registration Statement No. 33-11383, on Form S-4, filed with the Commission on January 16, 1987) Resolution of the Council for the Town of Troutville, Virginia dated November 4, 1968 (incorporated herein by reference to Exhibit 10(g) of Registration Statement No. 33-11383, on Form S-4, filed with the Commission on January 16, 1987) Gas Franchise Agreement between the City of Roanoke, Virginia, and Roanoke Gas Company dated December 14, 2015 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed December 16, 2015) Gas Franchise Agreement between the City of Salem, Virginia, and Roanoke Gas Company dated December 14, 2015 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed December 16, 2015) Gas Franchise Agreement between the Town of Vinton, Virginia, and Roanoke Gas Company dated November 17, 2015 (incorporated herein by reference to Exhibit 10.3 on Form 8-K as filed December 16, 2015) RGC Resources Amended and Restated Key Employee Stock Option Plan (incorporated herein by reference to Exhibit 4(c) of Registration Statement No. 333-02455, Post Effective Amendment on Form S-8, filed with the Commission on July 2, 1999) RGC Resources, Inc. Amended and Restated Stock Bonus Plan (incorporated herein by reference to Exhibit 10 on Form 8-K filed on January 27, 2005 (SEC file reference number 0-367)) RGC Resources, Inc. Restricted Stock Plan for Outside Directors (incorporated herein by reference to Exhibit 10(r)(r) of Annual Report on Form 10-K for the fiscal year ended September 30, 1999 SEC file reference number 0-367) Amendment to RGC Resources, Inc. Restricted Stock Plan for Outside Directors (incorporated herein by reference to Exhibit 10.2 on Form 10-Q as filed May 6, 2016) Second Amendment to RGC Resources, Inc. Restricted Stock Plan for Outside Directors Change in Control Agreement between RGC Resources, Inc. and Paul W. Nester effective May 1, 2015 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed May 5, 2015) Change in Control Agreement by and between RGC Resources, Inc. and Robert L. Wells, II effective May 1, 2015 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed May 5, 2015) Change in Control Agreement between RGC Resources, Inc. and Mr. Carl J. Shockley effective May 1, 2015 (incorporated herein by reference to Exhibit 10.3 on Form 8-K as filed May 5, 2015) 10 (p)(p) 10 (q)(q) 10 (r)(r) 10 (s)(s) 10 (t)(t) 10 (u)(u) 10 (v)(v) 10 (w)(w) 10 (x)(x) 10 (y)(y) 10 (z)(z) 10 (a)(a)(a) 10 (b)(b)(b) 10 (c)(c)(c) 10 (d)(d)(d) 10 (e)(e)(e) Change in Control Agreement between RGC Resources, Inc. and John S. D'Orazio effective April 1, 2016 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed April 4, 2016) Revolving Line of Credit Note in the original principal amount of $24,000,000 by Roanoke Gas Company in favor of Wells Fargo Bank, N.A. dated March 31, 2016 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed April 4, 2016) Credit Agreement by and between Roanoke Gas Company and Wells Fargo Bank, N.A. dated March 31, 2016 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed April 4, 2016) Continuing Guaranty by RGC Resources, Inc. in favor of Wells Fargo Bank, N.A. dated March 31, 2016 (incorporated by reference to Exhibit 10.3 on Form 8-K as filed April 4, 2016) Indemnification and Cost Sharing Agreement by and between RGC Resources, Inc., Bluefield Gas Company and ANGD, LLC (incorporated herein by reference to Exhibit 10(x)(x) on Form 10-K as filed December 21, 2007 (SEC file number reference 0-367)) Note Purchase Agreement for 4.26% Senior Guaranteed Notes due September 18, 2034 in the original principal amount of $30,500,000 in favor of The Prudential Insurance Company of America, PAR U Hartford Life & Annuity Comfort Trust and PRUCO Life Insurance Company of New Jersey (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed August 4, 2014) Unconditional Parent Guaranty by RGC Resources, Inc. in favor of each of the olders of the notes: The Prudential Life Insurance Company of America, PAR U Hartford Life & Annuity Comfort Trust and PRUCO Life Insurance Company of New Jersey (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed August 4, 2014) 4.26% Senior Guaranteed Notes due September 18, 2034 in the original principal amount of $15,250,000 in favor of The Prudential Insurance Company of America (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed September 23, 2014) 4.26% Senior Guaranteed Notes due September 18, 2034 in the original principal amount of $9,700,000 in favor of PAR U Hartford Life & Annuity Comfort Trust (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed September 23, 2014) 4.26% Senior Guaranteed Notes due September 18, 2034 in the original principal amount of $5,550,000 in favor of PRUCO Life Insurance Company of New Jersey (incorporated herein by reference to Exhibit 10.3 on Form 8-K as filed September 23, 2014) ISDA Master Agreement by and between Roanoke Gas Company and Branch Bank and Trust dated as of October 27, 2008 (incorporated herein by reference to Exhibit 10.3 on Form 8-K as filed November 5, 2008 (SEC file number reference 0-367)) Unconditional guaranty by and between RGC Resources, Inc. and Wachovia Bank, National Association, dated March 23, 2009 for the benefit of Roanoke Gas Company (incorporated by reference to Exhibit 10.2 on Form 8-K as filed March 26, 2009 (SEC file number reference 0-367)) Credit Agreement between RGC Midstream, LLC, Union Bank & Trust and Branch Banking and Trust Company dated December 29, 2015 (incorporated by reference to Exhibit 10.1 on Form 8-K as filed December 31, 2015) Promissory Note dated December 29, 2015 by RGC Midstream, LLC in the principal amount of $15,000,000 in favor of Union Bank &Trust due December 29, 2020 (incorporated by reference to Exhibit 10.2 on Form 8-K as filed December 31, 2015) Promissory Note dated December 29, 2015 by RGC Midstream, LLC in the principle amount of $10,000,000 in favor of Branch Banking and Trust Company due December 29, 2020 (incorporated by reference to Exhibit 10.3 on Form 8-K as filed December 31, 2015) Guaranty by RGC Resources, Inc. in favor of Union Bank & Trust and Branch Banking and Trust Company dated December 29, 2015 (incorporated herein by reference to Exhibit 10.4 on Form 8-K as filed December 31, 2015) 10 (f)(f)(f) ** 10 (g)(g)(g) ** 10 (h)(h)(h) Second Amended and Restated Limited Liability Company Agreement of Mountain Valley Pipeline, LLC dated March 10, 2015 (incorporated by reference to Exhibit 10.1 on Form 10-Q as filed February 5, 2016) First Amendment to Second Amended and Restated Limited Liability Agreement of Mountain Valley Pipeline, LLC (incorporated by reference to Exhibit 10.1 on Form 10-Q as filed May 6, 2016) Guaranty Agreement by RGC Resources, Inc. in favor of Mountain Valley Pipeline, LLC dated October 1, 2015 (incorporated herein by reference to Exhibit 10.2 on Form 10-Q as filed February 5, 2016) 21 23 31.1 31.2 32.1* 32.2* 101 Subsidiaries of the Company Consent of Brown, Edwards & Company, LLP Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer Section 1350 Certification of Principal Executive Officer Section 1350 Certification of Principal Financial Officer The following documents from the Registrant’s Annual Report on Form 10-K for the years ended September 30, 2016, 2015 and 2014, formatted in XBRL (eXtensible Business Reporting Language); Consolidated Balance Sheets at September 30, 2016 and 2015, (ii) Consolidated Statements of Income for the years ended September 30, 2016, 2015 and 2014, (iii) Consolidated Statements of Comprehensive Income for the years ended September 30, 2016. 2015 and 2014, (iv) Consolidated Statements of Stockholders’ Equity for the years ended September 30, 2016, 2015 and 2014, (v) Consolidated Statements of Cash Flows for the years ended September 30, 2016, 2015 and 2014, and (vi) Notes to Consolidated Financial Statements. * These certifications are being furnished solely to accompany this annual report pursuant to 18 U.S.C. Section 1350, and are not being filed for purposes of Section 18 of the Securities Exchange Act of 1934 and are not to be incorporated by reference into any filing of the registrant, whether made before or after the date hereof, regardless of any general incorporation language in such filing. ** Confidential treatment has been granted with respect to portions of this exhibit, indicated by asterisks, which has been filed separately with the Securities and Exchange Commission. Exhibit 10 (l)(l) Second Amendment to the Restricted Stock Plan for Outside Directors The Amended and Restated Restricted Stock Plan for Outside Directors of RGC Resources, Inc. (the "Plan"), is amended effective October 1, 2016, to change the first sentence of Section 3 of the Plan so that it reads as follows: Unless a Participant owns at least 10,000 shares of Company Stock, on the first day of each month during each Plan Year, forty percent (40%) of a Participant’s Compensation for the month shall be paid in shares of Restricted Stock of the Company. This Amendment was adopted by the Board of Directors on July 25, 2016. /s/ Paul W. Nester_____________ Paul W. Nester Secretary RGC Resources, Inc. Subsidiaries of Registrant Exhibit 21 Roanoke Gas Company Diversified Energy Company RGC Ventures of Virginia, Inc. RGC Midstream, LLC Exhibit 23 CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We consent to the incorporation by reference in Registration Statement No. 333-187529 on Form S-8, Registration Statement No. 333-178136 on Form S-8, Registration Statement No. 333-122746 on Form S-8, Registration Statement No. 333-122742 on Form S-3 of RGC Resources, Inc. of our report dated December 8, 2016 appearing in this Annual Report on Form 10-K of RGC Resources, Inc. for the year ended September 30, 2016. CERTIFIED PUBLIC ACCOUNTANTS 1715 Pratt Drive, Suite 2700 Blacksburg, Virginia December 8, 2016 Exhibit 31.1 I, John S. D'Orazio, certify that: CERTIFICATION 1. 2. 3. 4. I have reviewed this annual report on Form 10-K of RGC Resources, Inc.; Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: (a) (b) (c) (d) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and 5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): (a) (b) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. Date: December 8, 2016 /s/ John S. D'Orazio President and Chief Executive Officer Exhibit 31.2 I, Paul W. Nester, certify that: CERTIFICATION 1. 2. 3. 4. I have reviewed this annual report on Form 10-K of RGC Resources, Inc.; Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: (a) (b) (c) (d) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and 5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): (a) (b) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. Date: December 8, 2016 /s/ Paul W. Nester Vice-President, Secretary,Treasurer and CFO CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 Exhibit 32.1 In connection with the Annual Report of RGC Resources, Inc. (the “Company”) on Form 10-K for the period ended September 30, 2016 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John S. D'Orazio, President and Chief Executive Officer of the Company, certify to my knowledge, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that: (1) (2) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company. /s/ John S. D'Orazio John S. D'Orazio President and Chief Executive Officer December 8, 2016 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 Exhibit 32.2 In connection with the Annual Report of RGC Resources, Inc. (the “Company”) on Form 10-K for the period ended September 30, 2016 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Paul W. Nester, Vice-President, Secretary, Treasurer and CFO of the Company, certify to my knowledge, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company. /s/ Paul W. Nester Paul W. Nester Vice-President, Secretary, Treasurer and CFO December 8, 2016 25-Year Gas Pipeline Modernization Program Completion Roanoke Gas Company announced the completion of a quarter century modernization project to improve the safety and reliability of natural gas service throughout the City of Roanoke and surrounding area. Prior to the 1960’s, the nation’s natural gas suppliers installed cast iron or bare steel pipelines to deliver natural gas to customers. In Roanoke, some of these underground lines dated back to the 19th century. Starting in 1991, the project was intentionally spaced over 25 years to limit service interruptions. With the completion of the project, 200 miles of bare steel and cast iron pipelines have been replaced with modern polyethylene plastic pipe. Captured in the photograph below, Company personnel and city officials commemorated the replacement of the final section with the ceremonial installation of the last section of upgraded pipeline. Board of Directors Nancy Howell Agee President and CEO Carilion Clinic Abney S. Boxley, III President and CEO Boxley Materials Company John S. D’Orazio President and CEO RGC Resources, Inc. Maryellen F. Goodlatte Attorney and Principal Glenn Feldmann J. Allen Layman Private Investor George W. Logan Principal, Pine Street Partners, LLC; Faculty, UVA Darden Graduate School of Business S. Frank Smith Consultant Alpha Coal Sales Co., LLC Raymond D. Smoot, Jr. Senior Fellow Virginia Tech Foundation, Inc. John B. Williamson, III Chairman of the Board Corporate Information ANNUAL REPORT AND 10-K submitted This annual report, 10-K and the statements contained financial the herein are shareholders of the Company for their general information and not in connection with any sale or offer to sell, or solicitation of any offer to buy, any securities. to ANNUAL MEETING The annual meeting of shareholders of the Company will be held at The Hotel Roanoke and Conference Center, 110 Shenandoah Avenue, on Roanoke, Virginia, Monday, February 6, 2017, at 9:00 a.m. Proxies for the annual meeting will be requested from shareholders when notice of meeting, proxy statement and form of proxy are mailed on or about December 15, 2016. 24016 FINANCIAL INQUIRIES All financial analysts and professional investment managers should direct their requests for information to: RGC Resources, Inc. Vice President and CFO P.O. Box 13007, Roanoke, VA 24030 (540) 777-3853 Access up-to-date information on RGC Resources, Inc. and its subsidiaries at www.rgcresources.com. DIVIDEND REINVESTMENT AND STOCK PURCHASE PLAN INQUIRIES the Company’s Dividend and other stock or shareholders of Through Reinvestment and Stock Purchase Plan, record are offered a convenient way to acquire and reinvest cash dividends in additional shares of the Company’s avoid common commissions charges. Additionally, shareholders are given on-line access transfers, consolidate accounts, replace stock certificates and dividend payments, set-up update information and much personal more. Broadridge Corporate Issuer Solutions administers the plan and is the agent for participants. For more information, inquiries may be directed to RGC Resources, Inc., Shareholder Services, P.O. Box 13007, Roanoke, VA 24030, (540) 777-3853. to make deposit, direct STOCK PLAN ADMINISTRATOR Broadridge Corporate Issuer Solutions 1155 Long Island Avenue Edgewood, NY 11717 (855) 449-0975 Email: shareholder@broadridge.com Shareholder Portal: https://investor.broadridge.com/rgco EGISTERED ACCOUNTING FIRM INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Brown Edwards & Company, L.L.P. 1715 Pratt Drive, Suite 2700 Blacksburg, VA 24060 Photography by Amy Nance-Pearman at boydphotography.com 519 Kimball Avenue, N.E. P.O. Box 13007 Roanoke, Virginia 24030 www.rgcresources.com NASDAQ: RGCO 

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