| Virginia | 54-1909697 | |
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| 519 Kimball Avenue, N.E., Roanoke, VA | 24016 | |
| (Address of principal executive offices) | (Zip Code) | |
Title of Each Class |
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| Common Stock, $5 Par Value | NASDAQ Global Market | |
| Large accelerated filer | ¨ | Accelerated filer | x | |||
| Non-accelerated filer | ¨ | Smaller reporting company | ¨ | |||
2016. $95,954,187
Class | Outstanding at November 30, | |
| COMMON STOCK, $5 PAR VALUE | ||
TABLE OF CONTENTS
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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 Residential Commercial Industrial Other Utility Other Non-Utility Total Percent Total Value 2018. 2035. gas. systems. Company's financial position, results of operation and cash flows. costs. First Quarter Second Quarter Third Quarter Fourth Quarter Year Ending September 30, 2014 First Quarter Second Quarter Third Quarter Fourth Quarter Plan category Equity compensation plans approved by security holders Equity compensation plans not approved by security holders Total Operating Revenues Gross Margin Operating Income Net Income Basic Earnings Per Share Cash Dividends Declared Per Share Book Value Per Share Average Shares Outstanding Total Assets Long-Term Debt (Less Current Portion) Stockholders’ Equity Shares Outstanding at Sept. 30 subsidiary, RGC Midstream, LLC pipe over the next five years. cyber incident. price protection when the weather is colder than normal. band. at a smaller level. 2015 Gas Utilities Other Total Operating Revenues Regulated Natural Gas (DTH) Residential and Commercial Transportation and Interruptible Total Delivered Volumes Heating Degree Days (Unofficial) - General taxes increased $56,705, or 4%, primarily due to higher property taxes associated with increases in utility property. Gas Utility Other Total Gross Margin to modest customer growth. Customer Base Charge SAVE Plan Volumetric WNA Carrying Cost Other Total Gas Utilities Other Total Operating Revenues Delivered Volumes Regulated Natural Gas (DTH) Residential and Commercial Transportation and Interruptible Total Delivered Volumes Heating Degree Days (Unofficial) Gas Utility Other Total Gross Margin Customer Base Charge SAVE Plan Volumetric WNA Carrying Cost Other Total Provided by operating activities Used in investing activities Provided by (used in) financing activities Increase (decrease) in cash and cash equivalents activities is provided below: planned expenditures. instrument. Long-Term Debt (1) Short-Term Debt (2) Total Unrecorded contractual obligations, not reflected in consolidated balance sheets in accordance with US GAAP: Pipeline and Storage Capacity (3) Gas Supply (4) Interest on Short-Term Debt (5) Interest on Long-Term Debt (6) Pension Plan Funding (7) Investment in MVP (8) Other Obligations (9) Total 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. 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 December 31, 2035. MVP project. 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. Benefit obligation Fair value of assets Funded status Benefit obligation Fair value of assets Funded status lower discount rate. 2016. Management will continue to re-evaluate the return assumptions and adjust them as market conditions warrant. 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 Actuarial Assumptions Discount rate Rate of return on plan assets Rate of increase in compensation Actuarial Assumptions Discount rate Rate of return on plan assets Medical claim cost increase 8, 2016 ASSETS CURRENT ASSETS: Cash and cash equivalents Accounts receivable, net Materials and supplies Gas in storage Prepaid income taxes Deferred income taxes Under-recovery of gas costs Other Total current assets UTILITY PROPERTY: In service Accumulated depreciation and amortization In service, net Construction work in progress Utility plant, net OTHER ASSETS: Regulatory assets Other Total other assets TOTAL ASSETS LIABILITIES AND STOCKHOLDERS’ EQUITY CURRENT LIABILITIES: Borrowings under line-of-credit Dividends payable Accounts payable Customer credit balances Customer deposits Accrued expenses Over-recovery of gas costs Total current liabilities LONG-TERM DEBT Principal amount Less unamortized debt issuance costs Long-term debt net of unamortized debt issuance costs DEFERRED CREDITS AND OTHER LIABILITIES: Asset retirement obligations Regulatory cost of retirement obligations Benefit plan liabilities Deferred income taxes Total deferred credits and other liabilities COMMITMENTS AND CONTINGENCIES (Note 9) CAPITALIZATION: Stockholders’ Equity: Common stock, $5 par value; authorized 10,000,000 shares; issued and outstanding 4,741,498 and 4,720,378 shares in 2015 and 2014, respectively Preferred stock, no par; authorized 5,000,000 shares; no shares issued and outstanding in 2015 and 2014 Capital in excess of par value Retained earnings Accumulated other comprehensive loss Total stockholders’ equity TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY OPERATING REVENUES: Gas utilities Other Total operating revenues COST OF SALES: Gas utilities Other Total cost of sales GROSS MARGIN OTHER OPERATING EXPENSES: Operations and maintenance General taxes Depreciation and amortization Total other operating expenses OPERATING INCOME OTHER EXPENSE, net INTEREST EXPENSE INCOME BEFORE INCOME TAXES INCOME TAX EXPENSE NET INCOME EARNINGS PER COMMON SHARE: Basic Diluted WEIGHTED AVERAGE SHARES OUTSTANDING: Basic Diluted NET INCOME Other comprehensive income, net of tax: Interest rate swaps Defined benefit plans OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX COMPREHENSIVE INCOME Balance - September 30, 2012 Net income Other comprehensive income Stock option grants Cash dividends declared ($1.72 per share) Issuance of common stock (38,759 shares) Balance - September 30, 2013 Net income Other comprehensive income Stock option grants Cash dividends declared ($0.74 per share) Issuance of common stock (11,052 shares) Balance - September 30, 2014 Net income Other comprehensive loss Exercise of stock options (2,600 shares) Stock option grants Cash dividends declared ($0.77 per share) Issuance of common stock (18,520 shares) Balance - September 30, 2015 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 Deferred taxes and investment tax credits Other noncash items, net Changes in assets and liabilities which provided (used) cash: Accounts receivable and customer deposits, net Inventories and gas in storage Over/under recovery of gas costs Other assets Accounts payable, customer credit balances and accrued expenses, net Total adjustments Net cash provided by operating activities CASH FLOWS FROM INVESTING ACTIVITIES: Expenditures for utility property Proceeds from disposal of utility property Net cash used in investing activities CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds on collection of notes Borrowings under line-of-credit Repayments under line-of-credit Proceeds from issuance of unsecured notes Retirement of note payable Retirement of long-term debt Early termination fees Debt issuance expenses Proceeds from issuance of stock Cash dividends paid Net cash provided by (used in) financing activities NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR CASH AND CASH EQUIVALENTS AT END OF YEAR SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid during the year for: Interest Income taxes 2014 Regulatory Assets: Current Assets: Accounts receivable: Accrued WNA revenues Under-recovery of gas costs Other: Accrued pension and postretirement medical Utility Property: In service: Other Other Assets: Regulatory assets: Premium on early retirement of debt Accrued pension and postretirement medical Other Total regulatory assets Regulatory Liabilities: Current Liabilities: Over-recovery of gas costs Accrued expenses: Over-recovery of SAVE Plan revenues Deferred Credits and Other Liabilities: Asset retirement obligations Regulatory cost of retirement obligations Total regulatory liabilities Distribution and transmission LNG storage General and miscellaneous Total utility plant in service 2014. Beginning balance Liabilities incurred Liabilities settled Accretion Revisions to estimated cash flows Ending balance Beginning balance Provision for doubtful accounts Recoveries of accounts written off Accounts written off Ending balance 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 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. 11. 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 Year Ended September 30, 2015: Defined benefit plans: Net loss arising during period Amortization of actuarial losses Other comprehensive loss Year Ended September 30, 2014: Interest rate swaps: Unrealized losses Transfer of realized losses to interest expense Transfer of realized losses to regulatory asset Net interest rate swaps Defined benefit plans: Net loss arising during period Amortization of actuarial losses Net defined benefit plans Other comprehensive income Year Ended September 30, 2013: Interest rate swaps: Unrealized losses Transfer of realized losses to interest expense Net interest rate swaps Defined benefit plans: Net gain arising during period Amortization of actuarial losses Amortization of transition obligation Net defined benefit plans Other comprehensive income Balance September 30, 2012 Other comprehensive income (loss) Balance September 30, 2013 Other comprehensive income (loss) Balance September 30, 2014 Other comprehensive income (loss) Balance September 30, 2015 : 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 On Effective September 30, 2015 March 1, 2016 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 Unsecured senior notes payable, at 4.26%, due on September 18, 2034 Total Year Ending September 30 2016 2017 2018 2019 2020 Thereafter Total 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 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 Deferred tax assets: Allowance for uncollectibles Accrued pension and postretirement medical benefits Accrued vacation Over-recovery of gas costs Costs of gas held in storage Accrued gas costs Deferred compensation Other Total gross deferred tax assets Deferred tax liabilities: Utility plant Under-recovery of gas costs Accrued gas costs Total gross deferred tax liabilities Net deferred tax liability Deferred Income Tax - Balance Sheet Deferred income taxes (net current assets) Deferred income taxes (net non-current liabilities) Net deferred tax liability delayed bonus depreciation extensions. Accumulated benefit obligation Change in benefit obligation: Benefit obligation at beginning of year 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: Noncurrent liabilities Amounts recognized in accumulated other comprehensive loss: Transition obligation, net of tax Net actuarial loss, net of tax Total amounts included in other comprehensive loss, net of tax Amounts deferred to a regulatory asset: Transition obligation Net actuarial loss Amounts recognized as regulatory assets 2017. Assumptions used to determine benefit obligations: Discount rate Expected rate of compensation increase Assumptions used to determine benefit costs: Discount rate Expected long-term rate of return on plan assets Expected rate of compensation increase 2014. Service cost Interest cost Expected return on plan assets Amortization of unrecognized transition obligation Recognized loss Net periodic benefit cost 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 Effect on total service and interest cost components Effect on accumulated postretirement benefit obligation advisor. Asset category: Equity securities Debt securities Cash Other Asset Class: Cash Common and Collective Trust and Pooled Funds: Bonds Domestic Fixed Income 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 Total Asset Class: Cash Common and Collective Trust and Pooled Funds: Bonds Domestic Fixed Income 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 Total 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 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 2017. Fiscal year ending September 30 2016 2017 2018 2019 2020 2021-2025 41,000. Expected volatility Expected dividends Expected exercise term (years) Risk-free interest rate Options outstanding, September 30, 2012 Options granted Options exercised Options expired Options forfeited Options outstanding, September 30, 2013 Options granted Options exercised Options expired Options forfeited Options outstanding, September 30, 2014 Options granted Options exercised Options expired Options forfeited Options outstanding, September 30, 2015 Vested and exercisable at September 30, 2015 DRIP. 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. Beginning of year balance Granted Vested Forfeited End of year balance 2014. Total Year 2015-2016 2016-2017 2017-2018 2018-2019 2019-2020 Thereafter Total Liabilities: Natural gas purchases Total Liabilities: Natural gas purchases Total Liabilities: Long-term debt Total Liabilities: Long-term debt Total 2015. 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. 2015 Operating revenues Gross margin Operating income Net income Earnings per share of common stock: Basic Diluted 2014 Operating revenues Gross margin Operating income Net income (loss) Earnings per share of common stock: Basic Diluted balance into longer-term financing. 2016. 2016. 8, 2016 December Date December Date Item 1.1.(“Resources”("Resources" or the “Company”"Company") was incorporated in the state of Virginia on July 31, 1998, for the primary purpose of becoming the holding company for Roanoke Gas Company (“Roanoke Gas”) and its subsidiaries. Effective July 1, 1999, Roanoke Gas and its subsidiaries were reorganized into the holding company structure. Resources is currently composed of the following subsidiaries: Roanoke Gas, Diversified Energy Company RGC Ventures of Virginia, Inc and RGC Midstream, LLC.In 2000, the information technology department of Resources formed Application Resources, Inc. under RGC Ventures of Virginia, Inc. to provide information technology consulting services. In 2011, the Company also formed The Utility Consultants under RGC Ventures of Virginia, Inc to provide utility and regulatory consulting services to other utilities. The operations of RGC Ventures of Virginia, Inc. contributed less than 6% of other revenues and less than 1% of total revenues of Resources during fiscal 2015. The Utility Consultants portion of RGC Ventures of Virginia, Inc. and Diversified Energy Company currently have no active operations.123 of the Company’sCompany's annual consolidated financial statements and under the Equity Investment in Mountain Valley Pipeline section of Item 7.Services 2015 Customers Volume Revenue Margin 91.2 % 40 % 58 % 58 % 8.7 % 30 % 33 % 26 % 0.1 % 30 % 6 % 11 % 0.0 % 0 % 1 % 3 % 0.0 % 0 % 2 % 2 % 100.0 % 100 % 100 % 100 % 59,080 9,875,007 $ 68,189,607 $ 30,206,433 2014 Customers Volume Revenue Margin 91.2 % 40 % 57 % 58 % 8.7 % 29 % 34 % 25 % 0.1 % 31 % 6 % 12 % 0.0 % 0 % 1 % 3 % 0.0 % 0 % 2 % 2 % 100.0 % 100 % 100 % 100 % 58,553 10,087,651 $ 75,016,134 $ 29,337,089 2013 Customers Volume Revenue Margin 91.2 % 41 % 57 % 58 % 8.7 % 28 % 33 % 25 % 0.1 % 31 % 6 % 12 % 0.0 % 0 % 2 % 3 % 0.0 % 0 % 2 % 2 % 100.0 % 100 % 100 % 100 % 58,238 9,408,894 $ 63,205,666 $ 27,602,891 2016 Customers Volume Revenue Margin Residential 91.2 % 38 % 57 % 60 % Commercial 8.7 % 31 % 33 % 25 % Industrial 0.1 % 31 % 7 % 11 % Other Utility 0.0 % 0 % 1 % 2 % Other Non-Utility 0.0 % 0 % 2 % 2 % Total Percent 100.0 % 100 % 100 % 100 % Total Value 59,635 8,842,605 $ 59,063,291 $ 31,564,914 2015 Customers Volume Revenue Margin Residential 91.2 % 40 % 58 % 58 % Commercial 8.7 % 30 % 33 % 26 % Industrial 0.1 % 30 % 6 % 11 % Other Utility 0.0 % 0 % 1 % 3 % Other Non-Utility 0.0 % 0 % 2 % 2 % Total Percent 100.0 % 100 % 100 % 100 % Total Value 59,080 9,875,007 $ 68,189,607 $ 30,206,433 2014 Customers Volume Revenue Margin Residential 91.2 % 40 % 57 % 58 % Commercial 8.7 % 29 % 34 % 25 % Industrial 0.1 % 31 % 6 % 12 % Other Utility 0.0 % 0 % 1 % 3 % Other Non-Utility 0.0 % 0 % 2 % 2 % Total Percent 100.0 % 100 % 100 % 100 % Total Value 58,553 10,087,651 $ 75,016,134 $ 29,337,089 2014 and 2013.2014. The tabletables above indicates that residential customers represent over 91% of the Company’s customer total; however, they represent less than 50% of the total gas volumes delivered and more than half of the Company’s consolidated revenues and margin. Industrial customers include primarily transportation customers that purchase their natural gas requirements directly from a supplier other than the Company and utilize Roanoke Gas’ natural gas distribution system for delivery to their operations. Most of the revenue billed for these customers relates only to transportation service, and not to the purchase of natural gas, causing total revenues generated by these deliveries to be approximately 6%7% of total revenues, even though they represent 30%31% of total natural gas deliveries for the year ended September 30, 20152016 and approximately 11% to 12% of gross margin for each of the years presented.ResourcesRoanoke Gas to these customers is used for heating. For the fiscal year ended September 30, 2015,2016, approximately 68%64% of the Company’s total DTH of natural gas deliveries and 77%72% of the residential and commercial deliveries were made in the five-month period of November through March. These percentages are consistent withbelow the prior years.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 10.1 million DTH and 9.410.1 million DTH in fiscal 2016, 2015 and 2014, and 2013, respectively.CompanyLLC (“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”("FERC"). These tariffs contain flexible pricing provisions, which, in some instances, authorize these transporters to reduce rates and charges to meet price competition. The current pipeline contracts expire at various times from 2017 to 2020.2022. The Company anticipates being able to renew these contracts or enter into other contracts to meet customers’ continued demand for natural gas.220,000200,000 DTH of natural gas in a liquid state for use during peak demand, has the capability of providing an additional 33,00027,000 DTH per day. Combined, the pipelines and LNG facility can provide more than 111,000105,000 DTH on a single winter day. In fiscal 2015, the Company realized a maximum one day-customer demand of 91,341 DTH which represented the highest single day volume delivery in the Company’s history.and storage rights, and 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.publications. The Company expects its firm supply agreements will be sufficient to meet customer demands for natural gas during the term of the agreement, which expires March 31, 2017.Virginia, whichVirginia. During fiscal 2016, all expirethree franchise agreements were renewed for a term of 20 years with expiration dates of December 31, 2015. sources such as fuel oil, electricity, propane, coal and solar. Competition can be intense among the other energy sources and can be based primarily on price.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 newimproved drilling and extraction processes in shale formations, has served to maintain prices at lower levels. The Company continues to see a demand for its product and extends service to the new residential construction markets located along or near gas distribution mains in its service area. Although new construction activity has been limited over the last few years, the Company has been able to grow its customer base through customer conversionscustomers converting from an alternative energy source to natural gas along its distribution lines.at whichfor natural gas is sold to customers, the approval of agreements between or among affiliated companies involving the provision of goods and services, pipeline safety, and certain other corporate activities of the Company, including mergers and acquisitions related to utility operations. The SCC also grants certificates of public convenience and necessity to distribute natural gas in Virginia.2015,2016, Resources had 125126 full-time employees and 133132 total employees. As of that date, 3334 employees, or 26%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 collectiveCompany and the union successfully negotiated a newcurrent collective bargaining agreement during 2015 that will expire on July 31, 2020. Management maintains an amicable relationship with the union.(“SEC”("SEC"). A copy of this annual report, as well as other recent annual and quarterquarterly reports are available on the Company’sCompany'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 atwww.sec.gov, which is hyper linkedhyper-linked on the Company’sCompany's website and is where you canmay obtain other Company filings with the SEC.Item 1A. Risk Factors TheThese risks described below are not the only ones faced by the Company. Additional risks not presently known to the Company or that the Company currently believes are immaterial may also impair business operations and financial results. If any of the following risks actually occur, the Company’s business, financial condition or results of operations could be adversely affected. In such case, the trading price of the Company’s common stock could decline and an investor could lose all or part of his, her or its investment.Increased compliance and pipeline safety requirements and fines.The Company is committed to the safe and reliable delivery of natural gas to its customers. Working in concert with this commitment are numerous laws and regulations at both the federal and state levels. The Company is subject to ongoing inspections and reviews. Failure to comply with such requirements could result in the levy of significant fines. Recent enforcement actions by the Virginia Division of Utility and Railroad Safety have resulted in increased fines for gas distribution companies across the state. There are inherent risks that may be beyond the Company’s control, including third party actions, which could result in damage to pipeline facilities, injury and even death. Such incidents could subject the Company to lawsuits, large fines, increased scrutiny and loss of customers, all of which could have a significant effect on the Company’s financial position and results of operation.breakdowns,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, ultimatelypotentially resulting in a longer-term negative impact on earnings.or failure of the Company’sCompany's investment in Mountain Valley Pipeline, LLC (the “LLC”"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 budget and fully subscribing the capacity of the pipeline once in service.Company’sCompany's earnings and financial position.Company’sCompany's earnings and financial performance through its 1% investment. The LLC’sLLC'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 recoverablebe 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, under contracts, could experience the loss of tax credits or tax incentives, or delayed or diminished returns, and could be required to write-off all or a portion of its investment in the project. Any of these events could have a material adverse effect on the LLC’s business, financial condition, results of operations and prospects. project siting, financing, construction, permitting, governmental approvals and the negotiation of project development agreements that may impede its development and operating activities. The LLC may face risks related to project siting, financing, construction, permitting, governmental approvals and the negotiation of project development agreements that may impede its development and operating activities. The LLC must periodically apply for licenses and permits from various local, state, federal and other regulatory authorities and abide by their respective conditions. Should the LLC be unsuccessful in obtaining necessary licenses or permits on acceptable terms, should there be a delay in obtaining or renewing necessary licenses or permits or should regulatory authorities initiate any associated investigations or enforcement actions or impose related penalties or disallowances on the LLC, the LLC’s business, financial condition, results of operations and prospects could be materially adversely affected. Any failure to negotiate successful project development agreements for new facilities with third parties could have similar results. The LLC’s gas infrastructure facilities and other facilities are subject to many operational risks. Operational risks could result in, among other things, lost revenues due to prolonged outages, increased expenses due to monetary penalties or fines for compliance failures, liability to third parties for property and personal injury damage, a failure to perform under applicable sales agreements and associated loss of revenues from terminated agreements or liability for liquidated damages under continuing agreements. The consequences of these risks could have a material adverse effect on the LLC’s business, financial condition, results of operations and prospects. Uncertainties and risks inherent in operating and maintaining the LLC’sLLC'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.breachincident or cyber-attacks on the Company’s computer systems could corrupt financialor information expose confidential personal information or compromise the safe and reliable delivery of natural gas.breach ofsecurity 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 ourthe 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.bothall 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 resultlead to a loss of customers and an increase in increased customer delinquencies and bad debt expense.operations.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. New regulations could result in a significant reduction inRegulations 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.relies oncurrently has liability and property insurance in place to cover a variety of capital sourcesexposures and perils. Although management considers the level of coverage to operatebe 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 businessindustry 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 fund capital expenditures, including internally generated cashthe limits of insurance may not keep pace accordingly. The proceeds received from operations, short-term borrowings under its line-of-credit, proceeds from stock issued underany such insurance may not be paid in a timely manner. The occurrence of any of the Dividend Reinvestment and Stock Purchase Plan (“DRIP”) and other sources. Access toforegoing could have a line-of-credit is essential to provide seasonal fundingmaterial adverse effect on the Company’s financial position, results of natural gas operations and provide capital budget bridge financing. Accesscash flows. capital markets and other long-termsources is important to provide more predictable financing for capital outlays and fundinglevels of the investmentplan, 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 LLC. The abilityvalue of the Company to maintain and renew its line-of-credit and to secure longer-term financing is critical to operations. Adverse market trendsinvestments that fund these plans, if not offset or deteriorationmitigated by a decline in the financial condition of the Companyplan liabilities, could increase the costexpense of borrowing or limitthese plans and require significant additional funding. Both funding obligations and increased expense could have a material impact on the Company’s ability to secure adequate funding.make natural gas a less attractive energy source to the Company’s customers; thereby potentially resultingresult in declining sales as well as increases in bad debt expense.The cost of providing post-retirement benefits and related funding obligations may increase.The costs of providing defined benefit pension and retiree medical plans are dependent on a number of factors such as the rates of return on plan assets, discount rates used in determining plan liabilities, the level of interest rates used to measure the required minimum funding levels of the plan, future government regulation, changes in life expectancy, and required or voluntary contributions made to the plan. Changes in actuarial assumptions and differences between the assumptions and actual results, as well as a significant decline in the value of investments that fund these plans, if not offset or mitigated by a decline in plan liabilities, could increase the expense of these plans and require significant additional funding of these plans. Such funding obligations could have a material impact on liquidity by reducing cash flows and could negatively affect results of operations. highly dependent upon weather conditions, specifically winter weather. The Company’s rate structure currently has a weather normalization adjustment factor that results in either a recovery or refund of revenues due to any variation from the 30-year average for heating degree-days. If the provision for the weather normalization adjustment were removed from its rate structure, the Company would be exposed to a much greater risk related to weather variability resulting in earnings volatility. A colder than normal winter could cause the Company to incur higher than normal operating and maintenance costs with no benefit of additional revenues to offset those costs as a result of the weather normalization adjustment.APrice is a significant competitive factor is price.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.Company’sCompany's liquidity and ability to borrow funds.Company’sCompany's long-term debt obligations and bank line of credit contain financial covenants. Noncompliance with any of these covenants could result in an event of default which, if not cured or waived, could accelerate payment on outstanding debt obligations or cause prepayment penalties. In such an event, the Company may not be able to refinance or repay all of its indebtedness, pay dividends or have sufficient liquidity to meet operating and capital expenditure requirements. Any such acceleration would cause a material adverse change in our financial condition.Item 1B.1B.Unresolved Staff Comments. Item 2.2.Properties.Properties.1,1251,132 miles of transmission and distribution pipeline with transmission and distribution plant representing more than 85%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.and intends to complete the replacement of its remaining cast iron and bare steel pipeline within the next two years.as additional needs arise.Item 3.3.Legal Proceedings.Proceedings.The Company was a defendant in two civil lawsuits associated with a November 2009 explosion and fire at a West Virginia residence. The first lawsuit was dismissed by order on March 31, 2015, and the second lawsuit was dismissed by order on April 27, 2015. The final resolution was consistent with management’s expectations as the settlement did not materially affect the Company’s financial position, results of operation, or liquidity.other pending legal proceedings.Item 4.4.Mine Safety Disclosures. Item 5.5.Resources’ Range of Bid Prices Cash Dividends Year Ending September 30, 2015 High Low Declared $ 22.45 $ 19.28 $ 0.1925 25.67 20.20 0.1925 22.99 19.78 0.1925 21.96 19.95 0.1925 $ 19.98 $ 18.10 $ 0.185 20.06 18.46 0.185 19.73 19.00 0.185 20.51 19.17 0.185 Range of Bid Prices Cash Dividends Year Ending September 30, 2016 High Low Declared First Quarter $ 23.94 $ 20.05 $ 0.2025 Second Quarter 23.39 20.66 0.2025 Third Quarter 26.00 21.45 0.2025 Fourth Quarter 25.09 22.32 0.2025 Year Ending September 30, 2015 First Quarter $ 22.45 $ 19.28 $ 0.1925 Second Quarter 25.67 20.20 0.1925 Third Quarter 22.99 19.78 0.1925 Fourth Quarter 21.96 19.95 0.1925 30, 2015,25, 2016, there were 1,2091,192 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.”20102011 through September 30, 20152016 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.20102011 in the Company’s common stock and in each index as of September 30, 2015,2016, 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 $172$163 for the Company’s common stock, $181$192 for the Dow Jones US Utilities Index and $187$213 for the S&P 500 Index.
2015: (a) (b) (c) Number of securities
to be issued upon
exercise of
outstanding options,
warrants and rights Weighted-average
exercise price of
outstanding
options, warrants
and rights Number of securities
remaining available
for future issuance
under equity
compensation plans
(excluding securities
reflected in column
(a)) 52,400 $ 19.83 128,134 — — — 52,400 $ 19.83 128,134 (a) (b) (c) Plan category Equity compensation plans approved by security holders 58,200 $20.25 110,307 Equity compensation plans not approved by security holders — — — Total 58,200 $20.25 110,307 Item 6.6. Year Ending September 30, 2015 2014 2013 2012 2011 $ 68,189,607 $ 75,016,134 $ 63,205,666 $ 58,799,687 $ 70,798,871 30,206,433 29,337,089 27,602,891 26,933,097 27,269,566 10,006,192 9,681,868 8,795,055 8,786,535 9,313,046 5,094,415 4,708,440 4,262,052 4,296,745 4,653,473 $ 1.08 $ 1.00 $ 0.91 $ 0.92 $ 1.01 $ 0.77 $ 0.74 $ 1.72 $ 0.70 $ 0.68 $ 11.14 $ 11.02 $ 10.51 $ 10.85 $ 10.55 4,728,210 4,715,478 4,698,727 4,647,439 4,592,713 $ 148,140,730 $ 139,127,641 $ 124,510,870 $ 129,735,019 $ 125,522,242 $ 30,500,000 $ 30,500,000 $ 13,000,000 $ 13,000,000 $ 13,000,000 52,840,991 52,020,847 49,502,422 50,682,930 48,785,778 4,741,498 4,720,378 4,709,326 4,670,567 4,624,682 Year Ending September 30, 2016 2015 2014 2013 2012 Operating Revenues $ 59,063,291 $ 68,189,607 $ 75,016,134 $ 63,205,666 $ 58,799,687 Gross Margin 31,564,914 30,206,433 29,337,089 27,602,891 26,933,097 Operating Income 11,212,092 10,006,192 9,681,868 8,795,055 8,786,535 Net Income 5,806,866 5,094,415 4,708,440 4,262,052 4,296,745 Basic Earnings Per Share $ 1.22 $ 1.08 $ 1.00 $ 0.91 $ 0.92 Cash Dividends Declared Per Share $ 0.81 $ 0.77 $ 0.74 $ 1.72 $ 0.70 Book Value Per Share $ 11.63 $ 11.14 $ 11.02 $ 10.51 $ 10.85 Average Shares Outstanding 4,766,604 4,728,210 4,715,478 4,698,727 4,647,439 $ 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 Item 7. 59,10059,600 residential, commercial and industrial customers in Roanoke, Virginia, and the surrounding localities, through its Roanoke Gas Company (“Roanoke Gas”) subsidiary. ResourcesRoanoke Gas also provides certain unregulated services through Roanoke Gas and utility information system services through RGC Ventures of Virginia, Inc., which operates as The Utility Consultants and Application Resources. The Companyservices. Resources also formed a new wholly-owned(“Midstream”("Midstream"), which was created to invest in the Mountain Valley Pipeline, (“MVP”LLC (the "LLC") project.. On October 1, 2015, Midstream executed the agreements to become a 1% member in the MVP project.LLC. More information is provided under the Equity Investment in Mountain Valley Pipeline section below. The unregulated operations represent less than 3%2% of revenues and margins of Resources.(“FERC”("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.Management anticipates replacingThe Company completed the replacement of all remaining cast iron pipe in fiscal 2016 and replacement of all bare steel pipe withinin the next two years and expects tofirst quarter of fiscal 2017. The Company will continue its renewal program with plans to replace first generation, pre-1973 plastic pipe.security attacks and other types of breaches;incidents; however, there can be no guarantee that a breachan incident will not occur. In the event of a breach,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 breach of confidential information.97%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.(“PGA”("PGA"), weather normalization adjustment factor (“WNA”("WNA"), inventory carrying cost revenue ("ICC") and a Steps to Advance Virginia Energy (“SAVE”("SAVE") adjustment rider.Company’sCompany'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 a weather measurement band around the most recent 30-year temperature average. The WNA provides the Company with a level of earnings protection when weather is warmer than normal and provides its customers withPrior to April 2014, theThe WNA provided a weather band of 3% above and below normal, wherebyallows the Company would billto recover from its customers for the lost margin (excluding gas costs) forfrom the impact of weather that was more than 3%is warmer than normal orand correspondingly requires the Company to refund customers the excess margin earned for weather that was more than 3%is colder than normal. Effective withThe WNA year runs from April through March of each year. Any billings or refunds related to the WNA year that began April 2014,are completed following the 3% weather band was removed andend of the WNA is now based strictly on temperature variationsyear. 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. ForDuring the fiscal year ended September 30, 2015, the Company recorded ahad reduced revenue by $609,000 reduction in revenuedue 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 8.8%approximately 9% colder than normal. IfPrior to April 2014, the WNA provided for a weather band had been 0% for the entire fiscal 2014 instead of 3% for the period October 1, 2013 through March 31, 2014, revenueabove and below normal whereby no WNA would have been adjusted down by $814,000. No revenue adjustment for WNAbe calculated until weather was made for fiscal 2013 as the number of heating degree days fell withinoutside the 3% band then in effect.carrying cost revenue (“ICC”)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.AsIn 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 naturalcalculating 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 has declined by more than $1.00inventories in terms of cost and a decatherm compared tolower 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 same period lastprior fiscal year, resulting from the decline in price of gas delivered into storage duringto storage. Based on the current year has declined by a similar amount. The result was a decline in the price ofnatural gas in storage to $3.38 per decatherm at September 30, 2015 compared to a price in storage of $4.71 and $4.08 at September 30, 2014 and 2013, respectively. However,futures prices, the average dollar balance of gas in storage inventory actually increased overmay decline next year, but the prior fiscal year due to the higher-priced gas in storage at the beginning of fiscal 2015 combined with a greater level of withdrawals in fiscal 2014 due to the colder winter. Although the average balance of gas in storage during the current year was higher than the prior fiscal year, ICC revenues during fiscal 2015 declined by approximately $46,000 due to a reduction in the weighted-average cost of capital. The weighted-average cost of capital declined from last year due to the refinancing of the Company’s long-term debt in September 2014 combined with an increasing allocation of low cost short-term debt in the determination of the ICC rate. Based on the current prices of natural gas futures, the average dollar balance of gas in storagedecline is expected to be much lower in the next fiscal year, resulting in lower ICC revenues in fiscal 2016.provideare 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’sCompany's infrastructure until such time a formal rate application is filed to incorporate this investment in the Company’sCompany's non-gas rates. As the Company did not file for an increase in the non-gas rates during the prior yeartwo 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 $292,000 and $169,000$292,000 in SAVE Plan revenues for years ended September 30, 2016, 2015 and 2014, and 2013. respectively. new non-gas base rates the next time the Company files for a non-gas rate increase. Additional information regarding the SAVE Rider is provided under the Regulatory Affairs section.yearfew 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, a couple ofnew business ventures have been announced in the Company’s larger industrial customers have reducedCompany's service territory that should provide some additional natural gas consumption amid lower production activities.load over the next few years. The impact of these relocations or the duration of these curtailments is unknown at this time. However, despite these losses, the local economy appears relatively stable and should continue to slowly improve absent a major economic setback on either a local, regional or national level.20152016 Compared with Fiscal Year 2014Operating Revenues Year Ended September 30, 2016 2015 Decrease Percentage Gas Utilities $ 58,079,990 $ 67,094,290 $ (9,014,300 ) (13 )% Other 983,301 1,095,317 (112,016 ) (10 )% Total Operating Revenues $ 59,063,291 $ 68,189,607 $ (9,126,316 ) (13 )% Delivered Volumes Year Ended September 30, 2016 2015 Decrease Percentage Regulated Natural Gas (DTH) Residential and Commercial 6,088,108 6,955,594 (867,486 ) (12 )% Transportation and Interruptible 2,754,497 2,919,413 (164,916 ) (6 )% Total Delivered Volumes 8,842,605 9,875,007 (1,032,402 ) (10 )% Heating Degree Days (Unofficial) 3,484 4,253 (769 ) (18 )% Gross Margin Year Ended September 30, 2016 2015 Increase / (Decrease) Percentage Gas Utility $ 31,070,660 $ 29,656,975 $ 1,413,685 5 % Other 494,254 549,458 (55,204 ) (10 )% Total Gross Margin $ 31,564,914 $ 30,206,433 $ 1,358,481 4 % Twelve Months Ended September 30, 2016 2015 Increase (Decrease) Customer Base Charge $ 12,364,811 $ 12,240,580 $ 124,231 SAVE Plan 2,538,055 1,307,795 1,230,260 Volumetric 14,099,214 15,757,907 (1,658,693 ) WNA 1,317,800 (608,560 ) 1,926,360 Carrying Cost 651,492 833,291 (181,799 ) Other 99,288 125,962 (26,674 ) Total $ 31,070,660 $ 29,656,975 $ 1,413,685 Revenuesand 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.Year Ended September 30, 2015 2014 Decrease Percentage $ 67,094,290 $ 73,865,487 $ (6,771,197 ) (9 )% 1,095,317 1,150,647 (55,330 ) (5 )% $ 68,189,607 $ 75,016,134 $ (6,826,527 ) (9 )% Delivered VolumesGeneral TaxesYear Ended September 30, 2015 2014 Decrease Percentage 6,955,594 7,005,920 (50,326 ) (1 )% 2,919,413 3,081,731 (162,318 ) (5 )% 9,875,007 10,087,651 (212,644 ) (2 )% 4,253 4,351 (98 ) (2 )% Operating Revenues Year Ended September 30, 2015 2014 Decrease Percentage Gas Utilities $ 67,094,290 $ 73,865,487 $ (6,771,197 ) (9 )% Other 1,095,317 1,150,647 (55,330 ) (5 )% Total Operating Revenues $ 68,189,607 $ 75,016,134 $ (6,826,527 ) (9 )% Delivered Volumes Year Ended September 30, 2015 2014 Decrease Percentage Regulated Natural Gas (DTH) Residential and Commercial 6,955,594 7,005,920 (50,326 ) (1 )% Transportation and Interruptible 2,919,413 3,081,731 (162,318 ) (5 )% Total Delivered Volumes 9,875,007 10,087,651 (212,644 ) (2 )% Heating Degree Days (Unofficial) 4,253 4,351 (98 ) (2 )% Gross MarginYear Ended September 30, 2015 2014 Increase /
(Decrease) Percentage $ 29,656,975 $ 28,774,213 $ 882,762 3 % 549,458 562,876 (13,418 ) (2 )% $ 30,206,433 $ 29,337,089 $ 869,344 3 % Gross Margin Year Ended September 30, 2015 2014 Increase / (Decrease) Percentage Gas Utility $ 29,656,975 $ 28,774,213 $ 882,762 3 % Other 549,458 562,876 (13,418 ) (2 )% Total Gross Margin $ 30,206,433 $ 29,337,089 $ 869,344 3 % As the Company continues to invest in eligible SAVE Plan infrastructure, the associated SAVE Plan revenues will continue to increase. Customer base charges also increased dueAs discussed above, volumetricVolumetric 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 largestCompany's larger customers. The effect of the warmer weather was mitigated in part by the WNA mechanism. The prior yearIn fiscal 2014, the WNA mechanism provided for a weather band of 3% variance around normal during the winter heating season while the currentfiscal 2015 heating season had a 0% weather band. Because the priorfiscal 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 currentfiscal 2015 year WNA with a 0% weather band required the adjustment of margin back to the level expected for normal weather. Twelve Months Ended September 30, Increase 2015 2014 (Decrease) $ 12,240,580 $ 12,064,764 $ 175,816 1,307,795 291,946 1,015,849 15,757,907 15,990,704 (232,797 ) (608,560 ) (563,187 ) (45,373 ) 833,291 879,381 (46,090 ) 125,962 110,605 15,357 $ 29,656,975 $ 28,774,213 $ 882,762 Twelve Months Ended September 30, 2015 2014 Increase (Decrease) Customer Base Charge $ 12,240,580 $ 12,064,764 $ 175,816 SAVE Plan 1,307,795 291,946 1,015,849 Volumetric 15,757,907 15,990,704 (232,797 ) WNA (608,560 ) (563,187 ) (45,373 ) Carrying Cost 833,291 879,381 (46,090 ) Other 125,962 110,605 15,357 Total $ 29,656,975 $ 28,774,213 $ 882,762 (“pension plan”) and postretirement medical plan (“postretirement plan”) expense.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’plans' liabilities at September 30, 2014. More information on these plans and the impact on the financial statements are provided under the Pension and Postretirement Benefits section of the Critical Accounting Policies and Estimates below and in Note 6 of the consolidated financial statements. Professional services increased by $77,000 primarily due to legal expenses associated with the new union contract, the formation of the Company’sCompany's new subsidiary and the due diligence work related to the investment in MVP. Additional information on the investment in MVP is provided under the Equity Investment in Mountain Valley Pipeline section below and in Note 12 of the consolidated financial statements.Pipeline. Total capitalized overheads declined by $106,000 because of delays in the production of liquifiedliquefied natural gas due to maintenance down time, lower capital expenditures and a reduction in the capitalization rate compared to the prior year.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’sCompany's corrosion control processes. The remaining— - Other expense, net, increased by $21,909, or 11%, primarily due to an increase in charitable requests related to specific campaigns.— - 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 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 for fiscal 2015 was $5,094,415 compared to $4,708,440 for fiscal 2014. Basic and diluted earnings per share were $1.08 in fiscal 2015 compared to $1.00 in fiscal 2014. Dividends declared per share of common stock were $0.77 in fiscal 2015 compared to $0.74 in fiscal 2014.Fiscal Year 2014 Compared with Fiscal Year 2013The table below reflects operating revenues, volume activity and heating degree-days.Operating Revenues Increase / Year Ended September 30, 2014 2013 (Decrease) Percentage $ 73,865,487 $ 62,024,174 $ 11,841,313 19 % 1,150,647 1,181,492 (30,845 ) (3 )% 75,016,134 63,205,666 11,810,468 19 % Year Ended September 30, 2014 2013 Increase Percentage 7,005,920 6,498,783 507,137 8 % 3,081,731 2,910,111 171,620 6 % 10,087,651 9,408,894 678,757 7 % 4,351 4,001 350 9 % Total gas utility operating revenues for the year ended September 30, 2014 increased by 19% from the year ended September 30, 2013. The increase in gas revenues was primarily attributable to a combination of a 7% increase in total delivered natural gas volumes, a 30% per decatherm increase in the average commodity price of natural gas, implementation of a non-gas rate increase and higher SAVE Plan revenues. The increase in delivered volumes was driven by the colder winter heating season where total heating degree days increased by 9% over fiscal 2013 and were above the 30-year average by the same percentage. Transportation and interruptible volumes, which are primarily driven by production activities rather than weather, increased by 6%. Other revenues decreased by 3% due to the completion of a one-time project during the prior year more than offsetting increases in the level of certain other contract services during fiscal 2014.Gross MarginYear Ended September 30, 2014 2013 Increase Percentage $ 28,774,213 $ 27,108,112 $ 1,666,101 6 % 562,876 494,779 68,097 14 % $ 29,337,089 $ 27,602,891 $ 1,734,198 6 % Regulated natural gas margins from utility operations increased by 6% from fiscal 2013, primarily as a result of higher residential and commercial sales volumes, the implementation of a non-gas rate increase and the addition of the SAVE Plan rider. Residential and commercial volumes (which are strongly correlated to the weather) increased due to the much colder winter season. The higher margins generated by the increased residential and commercial volume were mostly offset by a net WNA refund of $563,000 recognized in fiscal 2014. The Company also implemented a non-gas rate increase effective November 1, 2013 and an increased SAVE Plan Rider beginning January 1, 2014. The non-gas rate increase was designed to provide approximately $887,000 in additional annual non-gas revenues. The implementation of the increased non-gas rates in November 2013 accounted for approximately $422,000 of the increase in customer base charges, a flat monthly fee billed to each natural gas customer, and $474,000 of the additional volumetric revenue. The SAVE Plan Rider provided an additional $123,000 in margin. ICC revenues continued to decline with a $58,000 reduction in fiscal 2014 compared to fiscal 2013 due to the larger storage withdrawals and lower ICC factor.Other margins, consisting of non-utility related services, increased by $68,097 due to an increased level of activity under one of the contracted services. The service contracts that comprise most of the non-utility related activities are subject to annual or semi-annual renewal provisions and the potential exists that these contracts may not be renewed or extended by the customer. In addition, the level of activity under these contracts will fluctuate based on customer requirements.The changes in the components of the gas utility margin are summarized below: Twelve Months Ended September 30, Increase 2014 2013 (Decrease) $ 12,064,764 $ 11,405,093 $ 659,671 291,946 168,747 123,199 15,990,704 14,497,351 1,493,353 (563,187 ) — (563,187 ) 879,381 937,684 (58,303 ) 110,605 99,237 11,368 $ 28,774,213 $ 27,108,112 $ 1,666,101 Operations and Maintenance Expense—Operations and maintenance expenses increased by $529,789, or 4%, in fiscal 2014 compared with fiscal 2013 primarily due to higher labor costs, contracted services, bad debt expense and corporate insurance expense more than offsetting significant reductions in employee benefit costs and greater capitalization of Company overheads on construction projects and LNG (liquefied natural gas) production. Labor costs and contracted services increased by $1,128,000 primarily due to a full year of increased operations staffing, timing of pipeline right-of-way clearing, a full year of costs related to an SCC mandated meter installation inspection and remediation program, expenses related to updating the Company’s corrosion control processes, benefit consulting services and network services support and training. Bad debt expense increased by approximately $64,000 related to much higher customer billings due to a colder winter heating season. Corporate property and liability insurance increased by $93,000 due to a combination of higher premiums and increased general liability coverage limits. These higher costs were partially offset by a $605,000 reduction in employee benefit expenses, specifically in the pension plan and postretirement plan. These actuarially determined expenses declined in fiscal 2014 due to a combination of a higher discount rate for valuing both plans’ liabilities at September 30, 2013 and strong investment performance of both plans’ assets. In addition, $339,000 of additional overheads was capitalized due to a significantly higher level ofconstruction expenditures related to the Company’s renewal program and other projects. Total capital expenditures rose by more than $4.7 million over the prior year. The remaining increase of $188,000 relates to a variety of areas including additional facility and equipment maintenance and support costs, higher utility expenses and increased administrative costs related to the Company’s operations.General Taxes—General taxes increased $79,640, or 5%, primarily due to higher property taxes associated with increases in utility property and greater payroll taxes related to increased operations staffing.Depreciation—Depreciation expense increased by $237,956, or 5%, corresponding to the increase in utility plant investment partially offset by lower depreciation rates.Other Expense—Other expense, net, increased by $146,770 primarily due to the absence of interest income related to the ANGD note which was paid off in fiscal 2013 combined with a greater level of corporate charitable giving and increased SCC pipeline assessments.Interest Expense—Total interest expense remained virtually unchanged from fiscal 2013 as the Company benefited in September from lower interest expense due to its debt refinancing which offset the increased interest incurred under the line-of-credit.Income Taxes—Income tax expense increased by $294,753 on higher pre-tax earnings. The effective tax rate for fiscal 2014 was 38.4% compared to 38.3% for 2013.Net Income and Dividends—Net income for fiscal 2014 was $4,708,440 compared to $4,262,052 for fiscal 2013. Basic and diluted earnings per share were $1.00 in fiscal 2014 compared to $0.91 in fiscal 2013. Dividends declared per share of common stock were $0.74 in fiscal 2014 compared to $1.72 in fiscal 2013, which included the one-time special dividend of $1.00.increaseddecreased by $341,982 in fiscal 2016 compared to an increase of $135,477 in fiscal 2015 compared to decreasesand a decrease of $1,996,467 in fiscal 2014 and $6,063,647 in fiscal 2013.2014. The following table summarizes the categories of sources and uses of cash:Cash Flow Summary Year Ended September 30, 2015 2014 2013 $ 16,760,827 $ 6,839,738 $ 10,037,070 (13,750,274 ) (14,698,570 ) (9,947,510 ) (2,875,076 ) 5,862,365 (6,153,207 ) $ 135,477 $ (1,996,467 ) $ (6,063,647 ) Cash Flow Summary Year Ended September 30, 2016 2015 2014 Provided by operating activities $ 14,921,640 $ 16,760,827 $ 6,839,738 Used in investing activities (20,996,501 ) (13,750,274 ) (14,698,570 ) Provided by (used in) financing activities 5,732,879 (2,875,076 ) 5,862,365 Increase (decrease) in cash and cash equivalents $ (341,982 ) $ 135,477 $ (1,996,467 ) 2014 and $10,037,000 in fiscal 2013.2014. Cash provided by operating activities increaseddecreased by nearly $10,000,000more than $1,800,000 from last year primarily as a result of lowera smaller decline in natural gas commodity prices and refunding part of last year's over-collection of gas costs,for tax purposes for calendar 2014.through 2017, higher net income and book depreciation. The gas cost component of the Company’s natural gas billing rates for the high volume winter period from January through March were derived based on natural gas futures pricing in early December 2014 when expectations were that prices would rise slightly during the period. Instead, the commodity price of gas declined by nearly $1.50 per decatherm from December 2014 until early February 2015, at which time the price leveled off. As a result, the Company was over-recovered on gas costs for billings rendered during this time period. The Company also benefited from the decline in natural gas prices as natural gas purchased for storage was at lower rates than in fiscal 2014. The Company purchases natural gas for storage purposes during the spring and summer months for use during the fall and winter heating season. As natural gas prices remained at lower levels during the spring and summer, theaverage 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 $4.71 per decatherm at September 30, 2014 to $3.38 at September 30, 2015, whichfiscal 2014. In addition, the significant drop in natural gas prices during the prior year resulted in an overall decline in storage inventory of $3,242,000. In addition, the extension of bonus depreciation to the end of calendar 2014 accounted for most of the increase in the deferred tax liability. Operating cash flow also increased due to higher net income and depreciation amounts. The cash windfall on the over-recoveryover-collection of gas costs will be short-lived as the excessadjustment 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 will be refunded to$1,900,000 from customers in 2016. In addition,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 tax liabilities relatedtaxes in the amount of $1,284,000 in the first quarter of fiscal 2016 to accelerated andrecognize the effect of bonus depreciation on the Company’s utility plant at September 30,balance of 2015 will beginasset additions in addition to reverse$3,065,000 in deferred tax liability recognized for the effect of 50% bonus depreciation on fiscal 2016 or later, resulting in additional cash outflows for paymentcapital additions. As a result of the taxes. Conversely, duringbonus 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 2014 storage inventory balances2015 tax return. In comparison, total deferred taxes increased by more than $1,000,000 and$2,417,000 in fiscal 2015. A summary of the Company wentkey components of the cash flows from an over-collected position to an under-collected position, resulting in a $1,208,000 use of operating cash. Twelve Months Ended September 30, Cash Flow Provided by Operating Activities: 2016 2015 Increase (Decrease) Net income $ 5,806,866 $ 5,094,415 $ 712,451 Depreciation 5,709,525 5,219,893 489,632 Decrease in gas in storage 723,713 3,242,492 (2,518,779 ) Increase / (decrease) in over-collection of gas costs (991,739 ) 2,082,257 (3,073,996 ) Increase in deferred taxes 4,466,954 2,416,841 2,050,113 Other (793,679 ) (1,295,071 ) 501,392 Net Cash Provided by Operations $ 14,921,640 $ 16,760,827 $ (1,839,187 ) and expansion have continued at elevated levels with total expenditures ofincreased to nearly $18,000,000 in fiscal 2016 from $13,800,000 in fiscal 2015 and $14,700,000 in fiscal 2014 and approximately $10,000,000 in fiscal 2013.2014. The Company renewed 1014.9 miles of bare steel and cast iron natural gas distribution main and replaced 684 services in fiscal 2016. This compares to 10 miles of main and 594 services in fiscal 2015. This compares to2015 and 13.6 miles of main and 942 services in fiscal 20142014. The Company completed the replacement of its cast iron pipe during fiscal 2016 and 13 milesfinished replacing the remainder of main and 1,064 servicesthe bare steel pipe in fiscal 2013. Total costs relatedNovember 2016. The Company also completed the replacement of two natural gas custody transfer stations connected to the renewal program continue to increase as the less complex and highly concentrated customer areas ofEast Tennessee transmission line. In addition, the Company’s natural gas distribution system have been completed, leaving the more difficult sections to be done. Completion of the remaining pipeline replacement will more than likely be at a higher cost. The Company’s capital expenditures also included costs to extend natural gas distribution mains and services to 495 new customers in fiscal 2016 compared to 609 new customers in fiscal 2015 compared toand 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 468 in fiscal 2013. In addition,borrowings under the Company completed a significant main relocation andline-of-credit. the compressor at the LNG plant in fiscal 2015.RGC Resources is committed to the safe and reliable delivery of natural gas to its customers and, as a result, plans to commit the necessary resources to its pipeline renewal program with an expectation to replace all remaining cast iron and bare steel mains completed, renewal efforts will now shift to replacing approximately 45 miles of pre-1973 first generation plastic pipe within the next two years. As a reflectionwith current polyethylene pipe. This renewal project is expected to be completed by 2021. The Company has also begun implementation of this commitment, the Company’san 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 next year is currently estimated to befiscal 2017 reflects an increase of more than $3,000,000 in excess ofexpenditures over fiscal 2015 with the continuation of the pipeline replacement program and the replacement of two additional transfer stations. Depreciation provided approximately 38% of the current year’s capital expenditures compared to 33% for 2014 and 47% for 2013. Upon completion of the bare steel and cast iron pipe replacement, the Company plans to direct its efforts to replacing all pre-1973 plastic mains with polyethylene pipe. This project encompasses approximately 40 miles of natural gas main with a 2019 anticipated completion.2016. The Company expects to increase its borrowing activity to meet the funding requirements of these plans.usedprovided by financing activities were $5,733,000 in fiscal 2016 compared to cash used in financing activities of $2,875,000 forin fiscal 2015 compared toand cash provided by financing activities of $5,862,000 for fiscal 20142014. 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 used in financing activities of $6,153,000 for fiscal 2013. After significant activityflows resulting from declines in the financing area in 2014,financing cash flow returned to a more normal pattern in fiscal 2015.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’sCompany increased the utilization of its line-of-credit to fund both the Company’s seasonal working capital needs as well asprovide bridge financing for its capital budget increased but not nearly tofor amounts in excess of those provided by operations. Proceeds from the extent expected due toissuance of stock were $1,031,000 under the higher cash flows from operations.DRIP plan. Dividends increased as the annualized dividend rate per share went from $0.74 per sharein fiscal 2014 to $0.77 per share in 2015. Fiscal 2013 included a special one-time dividend of $1.00 per share in addition to the regular quarterly dividend. The special dividend totaled $4,675,337, of which $425,630 was returned to the Company under the DRIP Plan. fiscal 2015 and $0.81 if fiscal 2016. This compares to 63.0% equity and 37.0% long-term debt at September 30, 20142015,2016, 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 with an increase in the total borrowing limit.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 $6,000,000$10,000,000 to $24,000,000 during the term of the agreement. The upper limit of the line-of-credit increased over prior years due to expected capital expenditure funding needs. The line-of-credit agreement will expire March 31, 2016.2017. 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.additionaccordance 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 Company’s ongoing capital projects,LLC. Once Midstream has a commitmentcompleted its $5 million in contributions, it may resume borrowing up to invest approximately $35the $25 million overlimit. Currently, management is considering the next three yearspossibility of an equity issue by Resources to provide Midstream with the $5 million in equity capital required under the agreement asNotes. Following the end of the 5-year term on the Notes, Midstream anticipates refinancing the $25 million Notes with a 1% member of Mountain Valley Pipeline, LLC. The Company plans to use a combination oflonger-term amortizing debt and equity financing to meet this commitment.2015,2016, the estimated recorded and unrecorded obligations are as follows: Less than 1 1-3 4-5 After Recorded contractual obligations: year Years Years 5 Years Total $ — $ — $ — $ 30,500,000 $ 30,500,000 9,340,997 — — — 9,340,997 $ 9,340,997 $ — $ — $ 30,500,000 $ 39,840,997 (1)See Note 4 to the consolidated financial statements.(2)See Note 3 to the consolidated financial statements. Less than 1
year 1-3
Years 4-5
Years After
5 Years Total $ 11,392,645 $ 17,787,400 $ 8,599,382 $ — $ 37,779,427 — — — — — 24,457 — — — 24,457 1,299,300 2,598,600 2,598,600 18,192,200 24,688,700 — — — — — 5,300,000 25,000,000 4,700,000 — 35,000,000 114,501 34,598 2,340 27,380 178,819 $ 18,130,903 $ 45,420,598 $ 15,900,322 $ 18,219,580 $ 97,671,403 (3)Recoverable through the PGA process.(4)Volumetric obligation is for the purchase of contracted decatherms of natural gas at market prices in effect at the time of purchase. Unable to estimate related payment obligation until time of purchase. See Note 9 to the consolidated financial statements.(5)Accrued interest on line-of-credit balance at September 30, 2015, including minimum facility fee on unused line-of-credit. See Note 3 to the consolidated financial statements.(6)Semi-annual interest payment on 20-year $30.5 million note payable September 18, 2034. See Note 4 to the consolidated financial statements.(7)Estimated minimum funding assuming application of credit balances in plan to offset funding. Minimum funding requirements beyond five years is not available. See Note 6 to the consolidated financial statements.(8)Projected funding of the Company’s 1% interest in MVP as entered into on October 1, 2015.(9)Various lease, maintenance, equipment and service contracts.Recorded contractual obligations: Less than 1 year 1-3 Years 4-5 Years After 5 Years Total Long-Term Debt (1) $ — $ — $ 3,396,200 $ 30,500,000 $ 33,896,200 Short-Term Debt (2) 14,556,785 — — — 14,556,785 Total $ 14,556,785 $ — $ 3,396,200 $ 30,500,000 $ 48,452,985 (1) See Note 5 to the consolidated financial statements. (2) See Note 4 to the consolidated financial statements. Unrecorded contractual obligations, not reflected in consolidated balance sheets in accordance with US GAAP: Less than 1 year 1-3 Years 4-5 Years After 5 Years Total Pipeline and Storage Capacity (3) $ 10,474,339 $ 15,999,239 $ 7,276,676 $ 2,682,848 $ 36,433,102 Gas Supply (4) — — — — — Interest on Short-Term Debt (5) 32,824 — — — 32,824 Interest on Long-Term Debt (6) 1,371,200 2,742,400 2,688,200 17,277,081 24,078,881 Pension Plan Funding (7) — — — — — Investment in MVP (8) 3,500,000 28,444,254 — — 31,944,254 Other Obligations (9) 117,780 24,502 4,661 25,540 172,483 Total $ 15,496,143 $ 47,210,395 $ 9,969,537 $ 19,985,469 $ 92,661,544 (3) Recoverable through the PGA process. (4) Volumetric obligation is for the purchase of contracted decatherms of natural gas at market prices in effect at the time of purchase. Unable to estimate related payment obligation until time of purchase. See Note 10 to the consolidated financial statements. (5) Accrued interest on line-of-credit balance at September 30, 2016, including minimum facility fee on unused line-of-credit. See Note 4 to the consolidated financial statements. (6) Calculated interest payments on 20-year $30.5 million Roanoke Gas Co. note payable due September 18, 2034 and on 09/30/2016 balance on Midstream notes due December 29, 2020. See Note 5 to the consolidated financial statements. (7) Estimated minimum funding assuming application of credit balances in plan to offset funding. Minimum funding requirements beyond five years is not available. See Note 7 to the consolidated financial statements. (8) Projected remaining funding of the Company's 1% interest in MVP as entered into on October 1, 2015. (9) Various lease, maintenance, equipment and service contracts. Mountain Valley Pipeline, LLC (the “LLC”), an investment in the Mountain Valley Pipeline project.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 pipelinepipeline. 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 an expected decisionthe implementation of the LLC's proposed mitigation plans in lateaddition to measures recommended in the EIS. Comments regarding the draft EIS must be filed on or before December 22, 2016. Assuming a favorable response byBased on the schedule provided in the NOS, the MVP expects to receive the FERC thecertificate in mid-2017. The pipeline is expectedtargeted to be in service byplaced in-service during the endfourth quarter of calendar 2018.the CompanyRoanoke Gas will benefit from access to another source of natural gas to its distribution system. Currently, Roanoke Gas is served by two pipelines and aCompany’sCompany's ability to serve its customers. A third pipeline would reduce the risk related toimpact 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.Midstream’sMidstream'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 forrelated to pre-construction activities including the acquisition of land, easements and materials related to the construction of the pipeline and other pre-construction costs.materials. Once approved and construction begins, more significant cash draws will be required.2015,2016, the Company filed an application with the SCC for modification of theto its SAVE (Steps to Advance Virginia’s Energy) Plan and Rider. The original SAVE Plan and Rider were approved by the SCC through an order issued on August 29, 2012 and has been modified or amended each year since. The original SAVE Plan was designed to facilitate the accelerated replacement of the remaining bare steel and cast iron natural gas pipe by providing a mechanism for theincluded additionaladded projects related to the replacement of bare steel and cast iron natural gas pipe in addition to two other major projects and added the investment for the related meter and regulator installations located on customer premises. On September 25,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 received approval for its most recent amendmentto recover it's investment up to the SAVE Plan effective for calendar yearnew variance limits. The 2016 whichapplication included an increase inprovisions to continue the investment to complete replacement of the bare steel and cast iron natural gasongoing pipeline renewal project with a focus on pre-1973 plastic pipe, in addition to the replacement of first generation plastic pipe. The SCC also approved the inclusion ofthree natural gas custody transfer stations, the replacement of two of the Company’s natural gas transfer stationscoated steel tubing services and related meter installations. The 2017 SAVE revenue requirement is approximately $4,000,000, representing an increase inof almost $1,000,000 over the allowed spending variance for projects under the SAVE Plan. The projects included under theestimated 2016 SAVE Plan will enhance the safety and reliability of the Company’s gas distribution system and reduce greenhouse emissions. In addition, the recovery of the depreciation and related expenses on these projects through theyear. The additional SAVE Plan riderrevenue as approved by the SCC will allow the Company to foregoforgo a formal non-gas rate increase application at this time.Company’sCompany's service territory. These certificates are intended for perpetual duration subject to compliance and regulatory standards. Franchises are granted by the local cities and towns served by the Company and are generally granted for a defined period of time. The current franchisesCompany 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 January 1, 2016. The Company is currently in negotiations to renew the franchises in each of these localities. Management anticipates that it will be able to renew all of its franchises.Mountain Valley PipelineMVP project by FERC and reconsider the application at a later date. The SCC granted the stay on July 31, 2015, which permitted the Company to continue its application request at a later date.On June 4, 2014, The Company intends to pursue the Company filed an application with the SCC requesting approval to extend its authority to incur short-term indebtedness of up to $30,000,000 and to issue up to $60,000,000 in long-term debt securities as part of its long-term financing plan, which included the refinancing of higher interest rate debt and funding for the Company’s pipeline replacement program and other infrastructure projects. On June 25, 2014, the SCC issued an order granting theassuming FERC approval of the Company’s request. The authority to issue long-term debt extends through September 30, 2019. In September 2014, the Company retired $28,000,000 in outstanding debt and replaced it with $30,500,000 in lower interest rate long-term debt. With significant capital expenditures planned over the next few years related to the SAVE Plan and other projects, the Company will have the flexibility to seek and manage the timing of long-term financing.The Company’s provision for depreciation is computed principally based on composite rates determined by depreciation studies. These depreciation studies are required to be performed on the regulated utility assets of Roanoke Gas Company at least every five years. In June 2014, the Company filed an updated depreciation study with the SCC to update the previous study that was implemented in fiscal 2009. The SCC approved new rates in September 2014 which resulted in a small reduction in the overall composite depreciation rate from 3.35% in 2013 to 3.25% in fiscal 2014 and 2015. The new rates were implemented retroactive to October 1, 2013.Operations.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).$1,001,418$1,004,061 and $1,071,128$1,001,418 as of September 30, 2016 and 2015, and 2014, respectively.67 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 actual4.22%3.42% and 4.15%3.33%, respectively, for valuing its pension plan liability and postretirement plan liability at September 30, 2015. This rate was unchanged for the pension plan and increased by only 0.05%2016. These rates decreased significantly from the prior year for the postretirement plan. The ongoing low interest rate environment has keptwith a decline of 0.80% and 0.82%, respectively. Interest rates moved even lower in 2016 keeping the discount rate depressed, thereby keepingelevating the liabilities at higher levels. Althoughplan liabilities. The downward movement of the discount rate is evidenced by the 30-year Treasury rate, which decreased from 3.21%2.87% to 2.87%,2.32% and the Moody’sMoody's Aaa was nearly unchanged decreasingrate, which declined by only 0.05% which corresponds toa corresponding 0.56%. This reduction in discount rate, combined with other factors, increased the minimal change inpension liability by more than $2,300,000 and the discount rates usedpostretirement medical liability by the benefit plans. As the discount rates remained at or near last year’s levels, the increase in each plan’s liability wasdriven in part to an additional year of accreated service. However,approximately $3,150,000. In fiscal 2015, the most significant impact to the liabilities iswas attributed to the adoption of new mortality tables. On October 27, 2014, the Society of Actuaries released the final reports of the pension plan RP-2014 Mortality Tables and the Mortality Improvement Scale MP-2014.MP-2015. The new mortality tables, which were adopted by the Company for its currentSeptember 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, therebymillion. The Company used the RP-2014 Mortality Tables under the Projection Scale MP-2015 for the current year valuation.expense.betterlower than expected returns in fiscal 2013 and 2014,2015, the returns on the related pension and postretirement assets for fiscal 2015 fell short of2016 exceeded the corresponding long-term rate of return assumptions. During fiscal 2015 fourth quarter,Furthermore, the equity markets experienced a greater than 10% market correction which was reflected in the plans’ asset balances at September 30, 2015. The Company took advantage of lower equity prices and contributed an additional $900,000 during the quarter,$1,000,000 over and above the previously projected $800,000$500,000 annual contribution to the pension plan. The increased contributions servedcombination of better than expected returns and higher funding levels were not enough to mitigate the impact of the adoption of the RP-2014 Mortiality Tables and lower investment returns. As a result ofoffset 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 in fiscal 2016 dueas the plan experienced no beneficial offsets to an increase inreduce the amortizationimpact of the actuarial loss. The following tables reflect the funded status of both plans at the corresponding fiscal year ends.Funded status - September 30, 2015 Pension Postretirement Total $ 27,167,621 $ 15,355,668 $ 42,523,289 21,394,399 10,443,629 31,838,028 $ (5,773,222 ) $ (4,912,039 ) $ (10,685,261 ) Funded status - September 30, 2014 Pension Postretirement Total $ 24,636,695 $ 14,983,169 $ 39,619,864 20,514,179 10,646,249 31,160,428 $ (4,122,516 ) $ (4,336,920 ) $ (8,459,436 ) Funded status - September 30, 2016 Pension Postretirement Total Benefit obligation $ 29,494,950 $ 18,504,710 $ 47,999,660 Fair value of assets 23,113,057 11,122,783 34,235,840 Funded status $ (6,381,893 ) $ (7,381,927 ) $ (13,763,820 ) Funded status - September 30, 2015 Pension Postretirement Total Benefit obligation $ 27,167,621 $ 15,355,668 $ 42,523,289 Fair value of assets 21,394,399 10,443,629 31,838,028 Funded status $ (5,773,222 ) $ (4,912,039 ) $ (10,685,261 ) CurrentDuring 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,rates. However, any expectation or trend beyond an initial increase is indeterminable.purely speculation. If the economy improves,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 2016.2017. These rates are consistent with the expected long-term rates in placeexperienced during fiscal 2015.21st21st 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(Pension Benefit Guaranty Corporation) premiums paid by sponsors of pension plans to protect participants in the event of default by the employer. Management estimates that, under the provisions of HATFA, the Company will have no minimum funding requirements next year. Although HATFA and MAP-21 allow the Company some short-term funding relief, management expects to continue its pension funding plan by contributing the greater ofat least the minimum annual pension contribution requirement or its expense level for subsequent years. The Company currently expects to contribute approximately $500,000$750,000 to its pension plan and $500,000$1,000,000 to its postretirement plan in fiscal 2016. With pension expense expected to be approximately $837,000 in fiscal 2016, management is still following the funding strategy when considering the $900,000 in additional funding made in the fiscal fourth quarter of 2015.2017. 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. Change in
Assumption Increase in
Pension Cost Increase in
Projected
Benefit
Obligation -0.25 % $ 114,000 $ 1,132,000 -0.25 % 53,000 N/A 0.25 % 55,000 306,000 Actuarial Assumptions Change in Assumption Increase in Pension Cost Increase in Projected Benefit Obligation Discount rate -0.25 % $ 125,000 $ 1,233,000 Rate of return on plan assets -0.25 % 57,000 N/A Rate of increase in compensation 0.25 % 56,000 314,000 Change in
Assumption Increase in
Postretirement
Benefit Cost Increase in
Accumulated
Postretirement
Benefit
Obligation -0.25 % $ 35,000 $ 569,000 -0.25 % 26,000 N/A 0.25 % 78,000 596,000 Actuarial Assumptions Change in Assumption Increase (Decrease) in Postretirement Benefit Cost Increase in Accumulated Postretirement Benefit Obligation Discount rate -0.25 % $ (19,000 ) $ 787,000 Rate of return on plan assets -0.25 % 35,000 N/A Medical claim cost increase 0.25 % 22,000 756,000 20152016 and 2014.2015.Item 7A. Quantitative and Qualitative Disclosures About Market Risk. 2015,2016, the Company has $9,340,997$14,556,785 outstanding under its variable rate line-of-credit.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 $64,700.$120,000. The Company’s remaining debt is at a fixed rate.2015,2016, the Company had no outstanding derivative instruments to hedge the price of natural gas. The Company had approximately 2,418,0002,537,000 decatherms of gas in storage, including LNG, at an average price of $3.38$2.93 per decatherm compared to 2,424,0002,418,000 decatherms at an average price of $4.71$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 the derivative contracts and other price hedging techniques are passed through to customers when realized through the regulated natural gas PGA mechanism.Item 8. Data.Data. 20142013,2014, and Report of Independent Page 31 Consolidated Financial Statements for the Years Ended September 30, 2016, 2015 and 2014: CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED SEPTEMBER 30, 2015, 2014 and 2013: 32 34 35 36 37 38
20152016 and 2014,2015, and the related consolidated statements of income, comprehensive income, stockholders’stockholders' equity, and cash flows for each of the years in the three-year period ended September 30, 2015.2016. 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.20152016 and 2014,2015, and the consolidated results of its operations and its cash flows for each of the years in the three-year period ended September 30, 2015,2016, in conformity with accounting principles generally accepted in the United States of America.2015,2016, based on criteria established inInternal Control-Integrated Framework —1992- 2013 issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated December 4, 20158, 2016 expressed an unqualified opinion.
CERTIFIED PUBLIC ACCOUNTANTS 4, 201520152016 AND 20142015 2015 2014 $ 985,234 $ 849,757 3,196,573 3,730,173 968,108 893,672 8,160,498 11,402,990 1,657,066 1,144,214 2,293,536 1,704,320 — 180,831 1,182,343 1,104,660 18,443,358 21,010,617 168,033,032 155,360,200 (53,307,079 ) (50,645,642 ) 114,725,953 104,714,558 3,903,599 4,029,019 118,629,552 108,743,577 10,923,243 9,273,389 144,577 100,058 11,067,820 9,373,447 $ 148,140,730 $ 139,127,641 2016 2015 ASSETS CURRENT ASSETS: Cash and cash equivalents $ 643,252 $ 985,234 Accounts receivable, net 3,478,983 3,196,573 Materials and supplies 824,139 968,108 Gas in storage 7,436,785 8,160,498 Prepaid income taxes 1,550,836 1,657,066 Other 1,548,329 1,182,343 Total current assets 15,482,324 16,149,822 UTILITY PROPERTY: In service 185,577,286 168,033,032 Accumulated depreciation and amortization (56,156,287 ) (53,307,079 ) In service, net 129,420,999 114,725,953 Construction work in progress 2,707,139 3,903,599 Utility plant, net 132,128,138 118,629,552 OTHER ASSETS: Regulatory assets 14,332,451 10,923,243 Investment in unconsolidated affiliate 3,496,404 — Other 113,532 144,577 Total other assets 17,942,387 11,067,820 TOTAL ASSETS $ 165,552,849 $ 145,847,194 20152016 AND 20142015 2015 2014 $ 9,340,997 $ 9,045,050 912,995 873,326 5,141,677 5,367,299 1,560,351 1,373,927 1,579,441 1,492,150 2,766,097 2,200,882 1,901,426 — 23,202,984 20,352,634 30,500,000 30,500,000 (183,427 ) (193,081 ) 30,316,573 30,306,919 5,295,868 4,802,015 8,885,486 8,575,147 10,685,261 8,459,436 16,913,567 14,610,643 41,780,182 36,447,241 23,707,490 23,601,890 — — 8,647,669 8,237,228 22,772,377 21,321,055 (2,286,545 ) (1,139,326 ) 52,840,991 52,020,847 $ 148,140,730 $ 139,127,641 2016 2015 LIABILITIES AND STOCKHOLDERS’ EQUITY CURRENT LIABILITIES: Borrowings under line-of-credit $ 14,556,785 $ 9,340,997 Dividends payable 970,244 912,995 Accounts payable 5,345,575 5,141,677 Capital contributions payable 287,794 — Customer credit balances 1,605,608 1,560,351 Customer deposits 1,627,105 1,579,441 Accrued expenses 3,194,255 2,766,097 Over-recovery of gas costs 909,687 1,901,426 Total current liabilities 28,497,053 23,202,984 LONG-TERM DEBT: Principal amount 33,896,200 30,500,000 Less unamortized debt issuance costs (260,149 ) (183,427 ) Long-term debt net of unamortized debt issuance costs 33,636,051 30,316,573 DEFERRED CREDITS AND OTHER LIABILITIES: Asset retirement obligations 5,682,556 5,295,868 Regulatory cost of retirement obligations 9,348,443 8,885,486 Benefit plan liabilities 13,763,820 10,685,261 Deferred income taxes 18,957,854 14,620,031 Total deferred credits and other liabilities 47,752,673 39,486,646 COMMITMENTS AND CONTINGENCIES (Note 10) CAPITALIZATION: Stockholders’ Equity: Common Stock, $5 par value; authorized 10,000,000 shares; issued and outstanding 4,788,289 and 4,741,498 shares in 2016 and 2015, respectively 23,941,445 23,707,490 Preferred stock, no par; authorized 5,000,000 shares; no shares issued and outstanding in 2016 and 2015 — — Capital in excess of par value 9,509,548 8,647,669 Retained earnings 24,713,310 22,772,377 Accumulated other comprehensive loss (2,497,231 ) (2,286,545 ) Total stockholders’ equity 55,667,072 52,840,991 TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY $ 165,552,849 $ 145,847,194 2014 AND 20132014 2015 2014 2013 $ 67,094,290 $ 73,865,487 $ 62,024,174 1,095,317 1,150,647 1,181,492 68,189,607 75,016,134 63,205,666 37,437,315 45,091,274 34,916,062 545,859 587,771 686,713 37,983,174 45,679,045 35,602,775 30,206,433 29,337,089 27,602,891 13,486,885 13,383,388 12,853,599 1,606,421 1,560,386 1,480,746 5,106,935 4,711,447 4,473,491 20,200,241 19,655,221 18,807,836 10,006,192 9,681,868 8,795,055 228,796 206,887 60,117 1,512,419 1,827,001 1,828,099 8,264,977 7,647,980 6,906,839 3,170,562 2,939,540 2,644,787 $ 5,094,415 $ 4,708,440 $ 4,262,052 $ 1.08 $ 1.00 $ 0.91 $ 1.08 $ 1.00 $ 0.91 4,728,210 4,715,478 4,698,727 4,731,676 4,716,282 4,698,766 2016 2015 2014 OPERATING REVENUES: Gas utilities $ 58,079,990 $ 67,094,290 $ 73,865,487 Other 983,301 1,095,317 1,150,647 Total operating revenues 59,063,291 68,189,607 75,016,134 COST OF SALES: Gas utilities 27,009,330 37,437,315 45,091,274 Other 489,047 545,859 587,771 Total cost of sales 27,498,377 37,983,174 45,679,045 GROSS MARGIN 31,564,914 30,206,433 29,337,089 OTHER OPERATING EXPENSES: Operations and maintenance 13,098,086 13,486,885 13,383,388 General taxes 1,663,126 1,606,421 1,560,386 Depreciation and amortization 5,591,610 5,106,935 4,711,447 Total other operating expenses 20,352,822 20,200,241 19,655,221 OPERATING INCOME 11,212,092 10,006,192 9,681,868 Equity in earnings of unconsolidated affiliate 152,864 — — Other expense, net 255,585 228,796 206,887 Interest expense 1,636,321 1,512,419 1,827,001 INCOME BEFORE INCOME TAXES 9,473,050 8,264,977 7,647,980 INCOME TAX EXPENSE 3,666,184 3,170,562 2,939,540 NET INCOME $ 5,806,866 $ 5,094,415 $ 4,708,440 EARNINGS PER COMMON SHARE: Basic $ 1.22 $ 1.08 $ 1.00 Diluted $ 1.22 $ 1.08 $ 1.00 WEIGHTED AVERAGE SHARES OUTSTANDING: Basic 4,766,604 4,728,210 4,715,478 Diluted 4,773,175 4,731,676 4,716,282 2014 AND 20132014 2015 2014 2013 $ 5,094,415 $ 4,708,440 $ 4,262,052 — 1,232,546 576,985 (1,147,219 ) (220,638 ) 1,221,866 (1,147,219 ) 1,011,908 1,798,851 $ 3,947,196 $ 5,720,348 $ 6,060,903 2016 2015 2014 NET INCOME $ 5,806,866 $ 5,094,415 $ 4,708,440 Other comprehensive income, net of tax: Interest rate swaps — — 1,232,546 Defined benefit plans (210,686 ) (1,147,219 ) (220,638 ) OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX (210,686 ) (1,147,219 ) 1,011,908 COMPREHENSIVE INCOME $ 5,596,180 $ 3,947,196 $ 5,720,348 2014 AND 2013 Common
Stock Capital in
Excess of
Par Value Retained
Earnings Accumulated
Other
Comprehensive
Income (Loss) Total
Stockholders’
Equity $ 23,352,835 $ 7,375,666 $ 23,904,514 $ (3,950,085 ) $ 50,682,930 — — 4,262,052 — 4,262,052 — — — 1,798,851 1,798,851 — 84,840 — — 84,840 — — (8,063,327 ) — (8,063,327 ) 193,795 543,281 — — 737,076 $ 23,546,630 $ 8,003,787 $ 20,103,239 $ (2,151,234 ) $ 49,502,422 — — 4,708,440 — 4,708,440 — — — 1,011,908 1,011,908 — 75,310 — — 75,310 — — (3,490,624 ) — (3,490,624 ) 55,260 158,131 — — 213,391 $ 23,601,890 $ 8,237,228 $ 21,321,055 $ (1,139,326 ) $ 52,020,847 — — 5,094,415 — 5,094,415 — — — (1,147,219 ) (1,147,219 ) 13,000 36,366 — — 49,366 — 83,640 — — 83,640 — — (3,643,093 ) — (3,643,093 ) 92,600 290,435 — — 383,035 $ 23,707,490 $ 8,647,669 $ 22,772,377 $ (2,286,545 ) $ 52,840,991 Balance - September 30, 2013 $ 23,546,630 $ 8,003,787 $ 20,103,239 $ (2,151,234 ) $ 49,502,422 Net income — — 4,708,440 — 4,708,440 Other comprehensive income — — — 1,011,908 1,011,908 Stock option grants — 75,310 — — 75,310 Cash dividends declared ($0.74 per share) — — (3,490,624 ) — (3,490,624 ) Issuance of common stock (11,052 shares) 55,260 158,131 — — 213,391 Balance - September 30, 2014 $ 23,601,890 $ 8,237,228 $ 21,321,055 $ (1,139,326 ) $ 52,020,847 Net income — — 5,094,415 — 5,094,415 Other comprehensive loss — — — (1,147,219 ) (1,147,219 ) Exercise of stock options (2,600 shares) 13,000 36,366 — — 49,366 Stock option grants — 83,640 — — 83,640 Cash dividends declared ($0.77 per share) — — (3,643,093 ) — (3,643,093 ) Issuance of common stock (18,520 shares) 92,600 290,435 — — 383,035 Balance - September 30, 2015 $ 23,707,490 $ 8,647,669 $ 22,772,377 $ (2,286,545 ) $ 52,840,991 Net income — — 5,806,866 — 5,806,866 Other comprehensive loss — — — (210,686 ) (210,686 ) Exercise of stock options (2,200 shares) 11,000 30,762 — — 41,762 Stock option grants — 64,640 — — 64,640 Cash dividends declared ($0.81 per share) — — (3,865,933 ) — (3,865,933 ) Issuance of common stock (44,591 shares) 222,955 766,477 — — 989,432 Balance - September 30, 2016 $ 23,941,445 $ 9,509,548 $ 24,713,310 $ (2,497,231 ) $ 55,667,072 2014 AND 2013 2015 2014 2013 $ 5,094,415 $ 4,708,440 $ 4,262,052 5,219,893 4,838,062 4,656,716 (406,731 ) (452,834 ) (502,587 ) 83,640 75,310 84,840 2,416,841 859,788 786,990 105,815 38,073 39,186 638,917 12,424 (374,682 ) 3,168,056 (1,219,641 ) (997,378 ) 2,082,257 (1,208,134 ) 1,714,497 (768,922 ) (306,744 ) 1,106,590 (873,354 ) (505,006 ) (739,154 ) 11,666,412 2,131,298 5,775,018 16,760,827 6,839,738 10,037,070 (13,780,356 ) (14,715,428 ) (9,977,433 ) 30,082 16,858 29,923 (13,750,274 ) (14,698,570 ) (9,947,510 ) — — 1,142,770 34,698,924 25,363,774 4,354,402 (34,402,977 ) (16,318,724 ) (4,354,402 ) — 30,500,000 — — (15,000,000 ) — — (13,000,000 ) — — (2,237,961 ) — — (193,081 ) — 432,401 213,391 737,076 (3,603,424 ) (3,465,034 ) (8,033,053 ) (2,875,076 ) 5,862,365 (6,153,207 ) 135,477 (1,996,467 ) (6,063,647 ) 849,757 2,846,224 8,909,871 $ 985,234 $ 849,757 $ 2,846,224 $ 1,002,462 $ 1,966,263 $ 1,803,528 1,266,573 2,387,000 622,076 2016 2015 2014 CASH FLOWS FROM OPERATING ACTIVITIES: Net income $ 5,806,866 $ 5,094,415 $ 4,708,440 Adjustments to reconcile net income to net cash provided by operations: Depreciation and amortization 5,709,525 5,219,893 4,838,062 Cost of retirement of utility plant, net (449,201 ) (406,731 ) (452,834 ) Stock option grants 64,640 83,640 75,310 Equity in earnings of unconsolidated affiliate (152,864 ) — — Deferred taxes and investment tax credits 4,466,954 2,416,841 859,788 Other noncash items, net 197,298 105,815 38,073 Changes in assets and liabilities which provided (used) cash: Accounts receivable and customer deposits, net (258,960 ) 638,917 12,424 Inventories and gas in storage 867,682 3,168,056 (1,219,641 ) Over/under recovery of gas costs (991,739 ) 2,082,257 (1,208,134 ) Other assets (398,864 ) (768,922 ) (306,744 ) Accounts payable, customer credit balances and accrued expenses, net 60,303 (873,354 ) (505,006 ) Total adjustments 9,114,774 11,666,412 2,131,298 Net cash provided by operating activities 14,921,640 16,760,827 6,839,738 CASH FLOWS FROM INVESTING ACTIVITIES: Expenditures for utility property (17,945,719 ) (13,780,356 ) (14,715,428 ) Investment in unconsolidated affiliate (3,055,746 ) — — Proceeds from disposal of utility property 4,964 30,082 16,858 Net cash used in investing activities (20,996,501 ) (13,750,274 ) �� (14,698,570 ) CASH FLOWS FROM FINANCING ACTIVITIES: Borrowings under line-of-credit 38,310,326 34,698,924 25,363,774 Repayments under line-of-credit (33,094,539 ) (34,402,977 ) (16,318,724 ) Proceeds from issuance of unsecured notes 3,396,200 — 30,500,000 Retirement of note payable — — (15,000,000 ) Retirement of long-term debt — — (13,000,000 ) Early termination fees — — (2,237,961 ) Debt issuance expenses (101,619 ) — (193,081 ) Proceeds from issuance of stock 1,031,194 432,401 213,391 Cash dividends paid (3,808,683 ) (3,603,424 ) (3,465,034 ) Net cash provided by (used in) financing activities 5,732,879 (2,875,076 ) 5,862,365 NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (341,982 ) 135,477 (1,996,467 ) CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 985,234 849,757 2,846,224 CASH AND CASH EQUIVALENTS AT END OF YEAR $ 643,252 $ 985,234 $ 849,757 SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid (refunded) during the year for: Interest $ 1,480,665 $ 1,002,462 $ 1,966,263 Income taxes (907,000 ) 1,266,573 2,387,000 2014 AND 201320141.1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES 59,10059,600 residential, commercial and industrial customers within its service areas in Roanoke, Virginia and the surrounding localities. The Company’s business is seasonal in nature and weather dependent as a majority of natural gas sales are for space heating during the winter season. Roanoke Gas is regulated by the Virginia State Corporation Commission (“SCC” or “Virginia Commission”). RGC Ventures of Virginia, Inc. was dissolved in 2016 after Application Resources, provideswhich provided information system services to software providers in the utility industry.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 new wholly-owned subsidiary created in 2015 to invest in athe Mountain Valley pipeline project. More information is provided in Note 12. Diversified Energy Company is currently inactive.setestablished by the Financial Accounting Standards Board (“FASB”) and the Securities and Exchange Commission (“SEC”).Reporting.Reporting. All intercompany transactions have been eliminated in consolidation.Operations.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.20152016 and 20142015 are as follows: September 30 2015 2014 $ 229,281 $ 143,753 — 180,831 530,781 394,215 11,945 11,945 2,169,556 2,283,744 8,378,419 6,884,812 375,268 104,833 $ 11,695,250 $ 10,004,133 $ 1,901,426 $ — 153,365 187,203 5,295,868 4,802,015 8,885,486 8,575,147 $ 16,236,145 $ 13,564,365 September 30 2016 2015 Regulatory Assets: Current Assets: Accounts receivable: Accrued WNA revenues $ 148,663 $ 229,281 Other: Accrued pension and postretirement medical 835,704 530,781 Utility Property: In service: Other 11,945 11,945 Other Assets: Regulatory assets: Premium on early retirement of debt 2,055,369 2,169,556 Accrued pension and postretirement medical 11,460,738 8,378,419 Other 816,344 375,268 Total regulatory assets $ 15,328,763 $ 11,695,250 Regulatory Liabilities: Current Liabilities: Over-recovery of gas costs $ 909,687 $ 1,901,426 Accrued expenses: Over-recovery of SAVE Plan revenues 238,694 153,365 Deferred Credits and Other Liabilities: Asset retirement obligations 5,682,556 5,295,868 Regulatory cost of retirement obligations 9,348,443 8,885,486 Total regulatory liabilities $ 16,179,380 $ 16,236,145 2015,2016, the Company had regulatory assets in the amount of $9,513,749$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.cost. The cost of additions to utility plantand includes direct chargeslabor and overhead.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. Maintenance, repairs, and minor renewals and betterments of property are charged to operations and maintenance.comprisedcomposed of the following major classes of assets: Years Ended September 30 2015 2014 $ 143,172,628 $ 134,439,225 12,501,179 9,163,158 12,359,225 11,757,817 $ 168,033,032 $ 155,360,200 Years Ended September 30 2016 2015 Distribution and transmission $ 160,354,300 $ 143,172,628 LNG storage 12,594,294 12,501,179 General and miscellaneous 12,628,692 12,359,225 Total utility plant in service $ 185,577,286 $ 168,033,032 asover 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 Company at least every five years.Gas. The Company completed its most recentlast depreciation study in June 2014. The composite weighted-average depreciation rates provided for underrate realized using the newmost recently completed depreciation study werewas 3.25% for each of the fiscal years ended September 30, 2016, 2015 and 2014 compared to 3.35% for the fiscal year ended September 30, 2013 under the prior rates. For the year ended September 30, 2014, the implementation of the new depreciation rates reduced depreciation expense by $126,875 and increased net income by $78,713 and earnings per share by $0.02.comprisedcomposed 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.evacuatingpurging and capping its distribution mains and services upon retirement, although the timing of such retirements is uncertain.2015,2016, the Company increased its asset retirement obligation to reflect revisions to the estimated cash flows for asset retirements. Years Ended September 30 2015 2014 $ 4,802,015 $ 4,525,355 62,890 74,276 (162,072 ) (165,845 ) 281,762 258,763 311,273 109,466 $ 5,295,868 $ 4,802,015 Years Ended September 30 2016 2015 Beginning balance $ 5,295,868 $ 4,802,015 Liabilities incurred 85,263 62,890 Liabilities settled (176,090 ) (162,072 ) Accretion 310,568 281,762 Revisions to estimated cash flows 166,947 311,273 Ending balance $ 5,682,556 $ 5,295,868 2015,2016, 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. Years Ended September 30 2015 2014 2013 $ 70,747 $ 68,539 $ 65,219 87,908 148,881 85,033 139,282 136,369 122,432 (245,216 ) (283,042 ) (204,145 ) $ 52,721 $ 70,747 $ 68,539 Years Ended September 30 2016 2015 2014 Beginning balance $ 52,721 $ 70,747 $ 68,539 Provision for doubtful accounts 14,074 87,908 148,881 Recoveries of accounts written off 137,055 139,282 136,369 Accounts written off (126,916 ) (245,216 ) (283,042 ) Ending balance $ 76,934 $ 52,721 $ 70,747 Company’sCompany'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.2014 were $1,001,418, and $1,071,128, respectively.67 and 10. Years Ended September 30 2015 2014 2013 $ 5,094,415 $ 4,708,440 $ 4,262,052 4,728,210 4,715,478 4,698,727 3,466 804 39 4,731,676 4,716,282 4,698,766 $ 1.08 $ 1.00 $ 0.91 $ 1.08 $ 1.00 $ 0.91 Years Ended September 30 2016 2015 2014 Net Income $ 5,806,866 $ 5,094,415 $ 4,708,440 Weighted-average common shares 4,766,604 4,728,210 4,715,478 Effect of dilutive securities: Options to purchase common stock 6,571 3,466 804 Diluted average common shares 4,773,175 4,731,676 4,716,282 Earnings Per Share of Common Stock: Basic $ 1.22 $ 1.08 $ 1.00 Diluted $ 1.22 $ 1.08 $ 1.00 2016.2036. The Company’sCompany's current certificates of public convenience and necessity in Virginia are exclusive and are intended for perpetual duration.20152016 and 2014,2015, the Company had no outstanding derivative instruments for the purchase of natural gas.Company’sCompany's debt refinancing. These swaps qualified as cash flow hedges with changes in fair value reported in other comprehensive income.OtherNon-Cash Activity — Non-cash increase in investment in unconsolidated affiliate and corresponding increase in capital contributions payable of $287,794.Income (Loss)Income(Loss)—A summary of other comprehensive income is provided below: Before Tax
Amount Tax
(Expense)
or Benefit Net-of Tax
Amount $ (1,910,573 ) $ 726,017 $ (1,184,556 ) 60,221 (22,884 ) 37,337 $ (1,850,352 ) $ 703,133 $ (1,147,219 ) $ (58,800 ) $ 22,321 $ (36,479 ) 926,262 (351,609 ) 574,653 1,119,233 (424,861 ) 694,372 1,986,695 (754,149 ) 1,232,546 (397,714 ) 151,131 (246,583 ) 41,846 (15,901 ) 25,945 (355,868 ) 135,230 (220,638 ) $ 1,630,827 $ (618,919 ) $ 1,011,908 $ (20,479 ) $ 7,774 $ (12,705 ) 950,501 (360,811 ) 589,690 930,022 (353,037 ) 576,985 1,714,890 (651,659 ) 1,063,231 219,890 (83,558 ) 136,332 35,972 (13,669 ) 22,303 1,970,752 (748,886 ) 1,221,866 $ 2,900,774 $ (1,101,923 ) $ 1,798,851 Year Ended September 30, 2016: Defined benefit plans: Net loss arising during period $ (560,887 ) $ 213,137 $ (347,750 ) Amortization of actuarial losses 221,070 (84,006 ) 137,064 Other comprehensive loss $ (339,817 ) $ 129,131 $ (210,686 ) Year Ended September 30, 2015: Defined benefit plans: Net loss arising during period $ (1,910,573 ) $ 726,017 $ (1,184,556 ) Amortization of actuarial losses 60,221 (22,884 ) 37,337 Other comprehensive loss $ (1,850,352 ) $ 703,133 $ (1,147,219 ) Year Ended September 30, 2014: Interest rate swaps: Unrealized losses $ (58,800 ) $ 22,321 $ (36,479 ) Transfer of realized losses to interest expense 926,262 (351,609 ) 574,653 Transfer of realized losses to regulatory asset 1,119,233 (424,861 ) 694,372 Net interest rate swaps 1,986,695 (754,149 ) 1,232,546 Defined benefit plans: Net loss arising during period (397,714 ) 151,131 (246,583 ) Amortization of actuarial losses 41,846 (15,901 ) 25,945 Net defined benefit plans (355,868 ) 135,230 (220,638 ) Other comprehensive income $ 1,630,827 $ (618,919 ) $ 1,011,908 Interest Rate
Swaps Defined Benefit
Plans Accumulated
Other
Comprehensive
Income (Loss) $ (1,809,531 ) $ (2,140,554 ) $ (3,950,085 ) 576,985 1,221,866 1,798,851 (1,232,546 ) (918,688 ) (2,151,234 ) 1,232,546 (220,638 ) 1,011,908 — (1,139,326 ) (1,139,326 ) — (1,147,219 ) (1,147,219 ) $ — $ (2,286,545 ) $ (2,286,545 ) Balance September 30, 2013 $ (1,232,546 ) $ (918,688 ) $ (2,151,234 ) Other comprehensive income (loss) 1,232,546 (220,638 ) 1,011,908 Balance September 30, 2014 — (1,139,326 ) (1,139,326 ) Other comprehensive income (loss) — (1,147,219 ) (1,147,219 ) Balance September 30, 2015 — (2,286,545 ) (2,286,545 ) Other comprehensive income (loss) — (210,686 ) (210,686 ) Balance September 30, 2016 $ — $ (2,497,231 ) $ (2,497,231 ) Change in Method of Accounting for Long-term Debt—During the fiscal year ended September 30, 2015, the Company adopted the provisions of ASU 2015-03 as described further under the Recently Adopted Accounting Standards section below. Under ASU 2015-03, the unamortized balance of debt issuance costs are reclassified from assets to liabilities and netted against the carrying value of long-term debt. The change had no impact on net income.Management retrospectively applied the change. The carrying value of long-term debt and the reclassified debt issuance costs are presented separately on the Company’s Consolidated Balance Sheets and in Note 4 for the periods ended September 30, 2015 and 2014.Recently Adopted Accounting Standards—In June 2011, the FASB issued guidance under FASB ASC No. 220—Comprehensive Income that defines the presentation of Comprehensive Income in the financial statements. According to the guidance, an entity may present a single continuous statement of comprehensive income or two separate statements—a statement of income and a statement of other comprehensive income that immediately follows the statement of income. In either presentation, the entity is required to present on the face of the financial statement the components of other comprehensive income including the reclassification adjustment for items that are reclassified from other comprehensive income to net income. In December 2011, the FASB issued additional guidance under FASB ASC No. 220 that deferred the effective date of earlier guidance with regard to the presentation of reclassifications of items out of accumulated other comprehensive income. All other provisions of the original guidance remain in effect. In February 2013, the FASB issued additional guidance regarding the reporting of amounts reclassified out of accumulated other comprehensive income. Under the new provisions, an entity must present the effects on the line items of net income of significant amounts reclassified out of accumulated other comprehensive income. The disclosures required under this guidance are provided above.duringin the current reporting period.period ended September 30, 2015. The adoption of this ASU did not have anany effect on the Company’sCompany'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.changes required underASU 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.are presentedsimplifies 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 Note 1, Note 4an APIC pool and not recognized in the Consolidated Balance Sheets.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.606—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 thesethe 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 entityAccounting Standards Update (ASU)ASU 2015-14 that deferred the effective date of this guidance by one year. Therefore,year to September 30, 2019. The FASB has issued subsequent guidance under ASC No. 606 to provide clarification of certain aspects of the neworiginal ASU. All additional guidance is effective forbeing considered as part of the Company forCompany's evaluation of theannual reporting period ended September 30, 2019 and interim periods within that annual period. Early application is not permitted. revenue recognition standard. Although Management has not completed its evaluation of all the new guidance; however,issued guidance under ASC No. 606, the Company does not currently expect itthe guidance to have a material effect on its financial position, results of operations or cash flows.2.2. REGULATORY MATTERS Gas Company.Gas. Such regulation encompasses terms, conditions and rates to be charged to customers for natural gas service, safety standards, service extension, accounting and depreciation.September 25, 2015,June 30, 2016, the Company received approval of itsfiled with the SCC an application for a modification to the SAVE (Steps to Advance Virginia’sVirginia's Energy) Plan and Rider. The original SAVE Plan filed in 2012 has been modified each year to incorporate certain changes and to include new projects that qualify for rate recovery under the the Plan. The SAVE RiderPlan 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.June 25, 2014,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 Company’s application requesting approvalextension 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 extend its authoritythe existing plan to incur short-term indebtedness of up to $30,000,000 and to issue up to $60,000,000 in long-term securities. The short-term indebtedness authority allowsreplace pre-1973 plastic pipe.3. OTHER INVESTMENTS continueconstruct 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 access its line-of-credittransport approximately 2 million decatherms of natural gas per day. If approved by the Federal Energy Regulatory Commission, the pipeline is expected to provide seasonal fundingbe in service by late 2018.its workingapproximately $35 million, by periodic capital needs as well as provide temporary bridge financing for its capital expenditures. The authority to issue long-term securities allowedcontributions throughout the Company to refinance its higher interest debtdesign and construction phases of the project. Midstream held an approximate $3.5 million equity method investment in the LLC at September 2014 and provides the Company with the approval to secure longer term30, 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.capital expenditures.level of investment. September 30 Balance Sheet Location of Other Investments: 2016 2015 Other Assets: Investment in unconsolidated affiliate $ 3,496,404 $ — Current Liabilities: Capital contributions payable $ 287,794 $ — For the Years ended September 30 Income Statement Location of Other Investments: 2016 2015 2014 Equity in earnings of unconsolidated affiliate $ 152,864 $ — $ — 3.4. SHORT-TERM DEBT 2016.2017. 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: Available
Line-of-Credit $ 24,000,000 17,000,000 Effective September 30, 2016 $ 24,000,000 March 1, 2017 17,000,000 September 30 2015 2014 2013 $ 24,000,000 $ 15,000,000 $ 5,000,000 9,340,997 9,045,050 — 17,366,052 9,045,050 1,414,955 6,377,040 1,340,833 80,593 1.17 % 1.16 % 1.21 % 1.20 % 1.16 % 1.18 % 0.15 % 0.15 % 0.15 % September 30 2016 2015 2014 Line-of-credit at year-end $ 24,000,000 $ 24,000,000 $ 15,000,000 Outstanding balance at year-end 14,556,785 9,340,997 9,045,050 Highest month-end balance outstanding 15,246,089 17,366,052 9,045,050 Average daily balance 9,620,914 6,377,040 1,340,833 Average rate of interest during year on outstanding balances 1.40 % 1.17 % 1.16 % Interest rate at year-end 1.53 % 1.20 % 1.16 % Interest rate on unused line-of-credit 0.15 % 0.15 % 0.15 % financial ratiorequirement that requires the Company to maintain an interest coverage ratio of not less than 1.5 to 1.4.5. LONG-TERM DEBT September 30 2015 2014 Principal Unamortized
Debt Issuance
Costs Principal Unamortized
Debt Issuance
Costs $ 30,500,000 $ 183,427 $ 30,500,000 $ 193,081 $ 30,500,000 $ 183,427 $ 30,500,000 $ 193,081 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 $ 30,500,000 $ 173,773 $ 30,500,000 $ 183,427 RGC Midstream, LLC: Unsecured term notes payable, at 30-day LIBOR plus 1.60% due December 29, 2020 3,396,200 86,376 — — Total $ 33,896,200 $ 260,149 $ 30,500,000 $ 183,427 20152016 and 2014,2015, the Company also had an unamortized loss on the early retirement of debt of $2,169,556$2,055,369 and $2,283,744,$2,169,556, respectively, which has been deferred as a regulatory asset and is being amortized over a 20 year period.20152016 are as follows: Maturities $ — — — — — 30,500,000 $ 30,500,000 Year Ending September 30 Maturities 2017 $ — 2018 — 2019 — 2020 — 2021 3,396,200 Thereafter 30,500,000 Total $ 33,896,200 5.6. INCOME TAXES Years Ended September 30 2015 2014 2013 $ 379,180 $ 1,789,294 $ 1,404,450 374,541 290,458 453,347 753,721 2,079,752 1,857,797 2,289,729 687,417 829,080 127,112 175,464 (33,051 ) 2,416,841 862,881 796,029 — (3,093 ) (9,039 ) $ 3,170,562 $ 2,939,540 $ 2,644,787 Years Ended September 30 2016 2015 2014 Current income taxes: Federal $ (1,216,745 ) $ 379,180 $ 1,789,294 State 415,975 374,541 290,458 Total current income taxes (800,770 ) 753,721 2,079,752 Deferred income taxes: Federal 4,302,906 2,289,729 687,417 State 164,048 127,112 175,464 Total deferred income taxes 4,466,954 2,416,841 862,881 Amortization of investment tax credits — — (3,093 ) Total income tax expense $ 3,666,184 $ 3,170,562 $ 2,939,540 2014 and 20132014 differed from amounts computed by applying the U.S. Federal income tax rate of 34% to earnings before income taxes due to the following: Years Ended September 30 2015 2014 2013 $ 8,264,977 $ 7,647,980 $ 6,906,839 $ 2,810,092 $ 2,600,313 $ 2,348,325 331,091 307,509 277,395 — (3,093 ) (9,039 ) 29,379 34,811 28,106 $ 3,170,562 $ 2,939,540 $ 2,644,787 Years Ended September 30 2016 2015 2014 Income before income taxes $ 9,473,050 $ 8,264,977 $ 7,647,980 Income tax expense computed at the federal statutory rate $ 3,220,837 $ 2,810,092 $ 2,600,313 State income taxes, net of federal income tax benefit 382,815 331,091 307,509 Amortization of investment tax credits — — (3,093 ) Other, net 62,532 29,379 34,811 Total income tax expense $ 3,666,184 $ 3,170,562 $ 2,939,540 September 30 2015 2014 $ 20,012 $ 26,855 2,502,774 2,077,409 249,837 230,842 721,782 — 930,524 973,651 — 36,305 651,336 579,451 265,951 295,654 5,342,216 4,220,167 19,804,862 17,057,847 — 68,643 157,385 — 19,962,247 17,126,490 $ 14,620,031 $ 12,906,323 September 30 2015 2014 $ 2,293,536 $ 1,704,320 16,913,567 14,610,643 $ 14,620,031 $ 12,906,323 September 30 2016 2015 Deferred tax assets: Allowance for uncollectibles $ 29,203 $ 20,012 Accrued pension and postretirement medical benefits 2,532,672 2,502,774 Accrued vacation 262,273 249,837 Over-recovery of gas costs 345,318 721,782 Costs of gas held in storage 1,077,849 930,524 Deferred compensation 770,868 651,336 Other 340,121 265,951 Total gross deferred tax assets 5,358,304 5,342,216 Deferred tax liabilities: Utility plant 24,264,165 19,804,862 MVP investment 40,776 — Accrued gas costs 11,217 157,385 Total gross deferred tax liabilities 24,316,158 19,962,247 Net deferred tax liability $ 18,957,854 $ 14,620,031 20152016 reflected the effect of 50% bonus depreciation for the entire calendarfiscal year of 2014, which included2016 as well as for nine months of the prior fiscal year.2015. The extension ofProtecting Americans from Tax Hikes (PATH Act), which extended 50% bonus depreciation for 2014calendar 2015, was signed into law on December 18, 2015, subsequent to the issuance of the Company’sCompany'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. As a result, $1,442,211 of deferred taxes that related to the prior year were reflected in the current year tax provision, thereby reducing the current tax expense by the same amount. TotalCorrespondingly, fiscal 2015 income tax expense wasincluded 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.classification change between current and deferred income taxes.20122013 are no longer subject to examination.6.7. EMPLOYEE BENEFIT PLANS (“Plans”("postretirement plan"). The defined benefit pension plan covers substantially all employees and benefits fully vest after 5 years of credited service. Benefits paid to retirees are based on age at retirement, years of service and average compensation. In November 2016, the Board of Directors approved a "soft freeze" to the pension plan, whereby nohealthcare,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. Pension Plan Postretirement Plan 2015 2014 2015 2014 $ 22,853,206 $ 20,697,734 $ 15,355,668 $ 14,983,169 $ 24,636,695 $ 21,468,769 $ 14,983,169 $ 13,028,628 654,782 553,291 167,580 168,634 1,025,908 1,020,302 600,096 602,684 1,487,278 2,199,697 70,196 1,673,552 (637,042 ) (605,364 ) (465,373 ) (490,329 ) $ 27,167,621 $ 24,636,695 $ 15,355,668 $ 14,983,169 $ 20,514,179 $ 18,801,262 $ 10,646,249 $ 10,114,062 (182,738 ) 1,750,033 (237,247 ) 522,516 1,700,000 568,248 500,000 500,000 (637,042 ) (605,364 ) (465,373 ) (490,329 ) $ 21,394,399 $ 20,514,179 $ 10,443,629 $ 10,646,249 $ (5,773,222 ) $ (4,122,516 ) $ (4,912,039 ) $ (4,336,920 ) $ (5,773,222 ) $ (4,122,516 ) $ (4,912,039 ) $ (4,336,920 ) $ — $ — $ — $ — 1,694,924 616,352 591,621 522,974 $ 1,694,924 $ 616,352 $ 591,621 $ 522,974 $ — $ — $ — $ — 5,280,756 4,166,900 3,628,448 3,112,127 $ 5,280,756 $ 4,166,900 $ 3,628,448 $ 3,112,127 Pension Plan Postretirement Plan 2016 2015 2016 2015 Accumulated benefit obligation $ 25,090,968 $ 22,853,206 $ 18,504,710 $ 15,355,668 Change in benefit obligation: Benefit obligation at beginning of year $ 27,167,621 $ 24,636,695 $ 15,355,668 $ 14,983,169 Service cost 694,375 654,782 148,018 167,580 Interest cost 1,132,776 1,025,908 624,579 600,096 Actuarial loss 2,440,957 1,487,278 2,812,516 70,196 Benefit payments, net of retiree contributions (1,940,779 ) (637,042 ) (436,071 ) (465,373 ) Benefit obligation at end of year $ 29,494,950 $ 27,167,621 $ 18,504,710 $ 15,355,668 Change in fair value of plan assets: Fair value of plan assets at beginning of year $ 21,394,399 $ 20,514,179 $ 10,443,629 $ 10,646,249 Actual return on plan assets, net of taxes 2,159,437 (182,738 ) 615,225 (237,247 ) Employer contributions 1,500,000 1,700,000 500,000 500,000 Benefit payments, net of retiree contributions (1,940,779 ) (637,042 ) (436,071 ) (465,373 ) Fair value of plan assets at end of year $ 23,113,057 $ 21,394,399 $ 11,122,783 $ 10,443,629 Funded status $ (6,381,893 ) $ (5,773,222 ) $ (7,381,927 ) $ (4,912,039 ) Amounts recognized in the balance sheets consist of: 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 1,583,345 1,694,924 913,886 591,621 Total amounts included in other comprehensive loss, net of tax $ 1,583,345 $ 1,694,924 $ 913,886 $ 591,621 Amounts deferred to a regulatory asset: Net actuarial loss 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 new RP-2014 Mortality Tables as issued by the Society of Actuaries in late 2014. The adoption of the new tables, which reflected an increase in assumed life expectancy, increased the September 30, 2015 pension liability by an estimated $1,300,000 and the postretirement liability by an estimated $1,000,000.$221,000$256,000 before tax, of accumulated other comprehensive loss will be recognized as a portion of net periodic benefit costs in fiscal 20162017 and approximately $531,000$836,000 of amounts deferred as regulatory assets will be amortized and recognized in net periodic benefit costs in fiscal 2016.The Company amortized the unrecognized transition obligation over 20 years ending in June 2013.2014 and 2013. Pension Plan Postretirement Plan 2015 2014 2013 2015 2014 2013 4.22 % 4.22 % 4.82 % 4.15 % 4.10 % 4.73 % 4.00 % 4.00 % 4.00 % N/A N/A N/A 4.22 % 4.82 % 4.06 % 4.10 % 4.73 % 3.95 % 7.00 % 7.00 % 7.25 % 4.90 % 4.92 % 5.11 % 4.00 % 4.00 % 4.00 % N/A N/A N/A Pension Plan Postretirement Plan 2016 2015 2014 2016 2015 2014 Assumptions used to determine benefit obligations: Discount rate 3.42 % 4.22 % 4.22 % 3.33 % 4.15 % 4.10 % Expected rate of compensation increase 4.00 % 4.00 % 4.00 % N/A N/A N/A Assumptions used to determine benefit costs: Discount rate 4.22 % 4.22 % 4.82 % 4.15 % 4.10 % 4.73 % Expected long-term rate of return on plan assets 7.00 % 7.00 % 7.00 % 4.89 % 4.90 % 4.92 % Expected rate of compensation increase 4.00 % 4.00 % 4.00 % N/A N/A N/A plans’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. Pension Plan Postretirement Plan 2015 2014 2013 2015 2014 2013 $ 654,782 $ 553,291 $ 634,892 $ 167,580 $ 168,634 $ 213,131 1,025,908 1,020,302 946,247 600,096 602,684 531,845 (1,440,846 ) (1,312,354 ) (1,184,787 ) (516,656 ) (496,476 ) (452,383 ) — — — — — 141,671 257,378 136,394 578,263 197,058 89,515 241,747 $ 497,222 $ 397,633 $ 974,615 $ 448,078 $ 364,357 $ 676,011 Pension Plan Postretirement Plan 2016 2015 2014 2016 2015 2014 Service cost $ 694,375 $ 654,782 $ 553,291 $ 148,018 $ 167,580 $ 168,634 Interest cost 1,132,776 1,025,908 1,020,302 624,579 600,096 602,684 Expected return on plan assets (1,492,241 ) (1,440,846 ) (1,312,354 ) (507,858 ) (516,656 ) (496,476 ) Recognized loss 501,678 257,378 136,394 250,173 197,058 89,515 Net periodic benefit cost $ 836,588 $ 497,222 $ 397,633 $ 514,912 $ 448,078 $ 364,357 2014 and 20132014 are presented below: Pre 65 Post 65 2015 2014 2013 2015 2014 2013 8.00 % 8.50 % 9.00 % 5.00 % 5.00 % 5.00 % 5.00 % 5.00 % 5.00 % 5.00 % 5.00 % 5.00 % 2021 2021 2021 2015 2014 2013 Pre 65 Post 65 2016 2015 2014 2016 2015 2014 Health care cost trend rate assumed for next year 7.50 % 8.00 % 8.50 % 5.00 % 5.00 % 5.00 % Rate to which the cost trend is assumed to decline (the ultimate trend rate) 5.00 % 5.00 % 5.00 % 5.00 % 5.00 % 5.00 % Year that the rate reaches the ultimate trend rate 2021 2021 2021 2016 2015 2014 1% Increase 1% Decrease $ 137,000 $ (109,000 ) 2,383,000 (1,938,000 ) 1% Increase 1% Decrease Effect on total service and interest cost components $ 137,000 $ (109,000 ) Effect on accumulated postretirement benefit obligation 3,083,000 (2,491,000 ) fiduciary for investment matters.and 2014 were: Pension Plan Postretirement
Plan Target 2015 2014 Target 2015 2014 60 % 64 % 60 % 50 % 52 % 55 % 40 % 35 % 39 % 50 % 47 % 44 % — % 1 % 1 % — % 1 % 1 % — % — % — % — % — % — % Pension Plan Postretirement
Plan Target 2016 2015 Target 2016 2015 Asset category: Equity securities 60 % 63 % 64 % 50 % 52 % 52 % Debt securities 40 % 36 % 35 % 50 % 47 % 47 % Cash — % 1 % 1 % — % — % 1 % Other — % — % — % — % 1 % — % all of the individual investments are determined based on quoted market prices for each security; however, certain fixed income securities and other investments are not actively traded and are valued based on similar investments. The following table contains the fair value classifications of the benefit plan assets: Defined Benefit Pension Plan
Fair Value Measurements - September 30, 2015 Fair Value Level 1 Level 2 Level 3 $ 106,502 $ 106,502 $ — $ — 3,996,246 — 3,996,246 — 3,150,561 — 3,150,561 — 4,183,172 — 4,183,172 — 1,937,613 — 1,937,613 — 1,873,313 — 1,873,313 — 3,313,331 — 3,313,331 — 213,118 — 213,118 — 1,030,957 — 1,030,957 — 653,276 — 653,276 — 936,310 — 936,310 — $ 21,394,399 $ 106,502 $ 21,287,897 $ — Defined Benefit Pension Plan
Fair Value Measurements - September 30, 2014 Fair Value Level 1 Level 2 Level 3 $ 182,644 $ 182,644 $ — $ — 1,455,153 — 1,455,153 — 2,079,566 — 2,079,566 — 3,295,144 — 3,295,144 — 1,850,340 — 1,850,340 — 1,641,619 — 1,641,619 — 6,289,437 — 6,289,437 — 204,747 — 204,747 — 2,088,528 — 2,088,528 — 608,787 — 608,787 — 818,214 — 818,214 — $ 20,514,179 $ 182,644 $ 20,331,535 $ — Postretirement Benefit Plan
Fair Value Measurements - September 30, 2015 Fair Value Level 1 Level 2 Level 3 $ 58,749 $ 58,749 $ — $ — 4,845,174 — 4,845,174 — 38,654 — 38,654 — 1,746,621 — 1,746,621 — 1,638,695 — 1,638,695 — 194,260 — 194,260 — 186,344 — 186,344 — 417,980 — 417,980 — 893,115 — 893,115 — 378,596 — 378,596 — 45,441 — 45,441 — $ 10,443,629 $ 58,749 $ 10,384,880 $ — Postretirement Benefit Plan
Fair Value Measurements - September 30, 2014 Fair Value Level 1 Level 2 Level 3 $ 116,173 $ 116,173 $ — $ — 4,658,299 — 4,658,299 — 101,904 — 101,904 — 1,789,381 — 1,789,381 — 1,759,740 — 1,759,740 — 400,898 — 400,898 — 396,537 — 396,537 — 37,741 — 37,741 — 941,153 — 941,153 — 394,769 — 394,769 — 49,654 — 49,654 — $ 10,646,249 $ 116,173 $ 10,530,076 $ — Defined Benefit Pension Plan
Fair Value Measurements - September 30, 2016 Fair Value Level 1 Level 2 Level 3 Asset Class: Cash $ 117,265 $ 117,265 $ — $ — Common and Collective Trust and Pooled Funds: Bonds Domestic Fixed Income 4,497,373 — 4,497,373 — Equities Domestic Large Cap Growth 3,426,041 — 3,426,041 — Domestic Large Cap Value 4,543,385 — 4,543,385 — Domestic Small/Mid Cap Core 2,149,566 — 2,149,566 — Foreign Large Cap Value 1,795,897 — 1,795,897 — Mutual Funds: Bonds Domestic Fixed Income 3,615,209 — 3,615,209 — Foreign Fixed Income 234,622 — 234,622 — Equities Domestic Large Cap Growth 1,043,395 — 1,043,395 — Foreign Large Cap Growth 366,420 — 366,420 — Foreign Large Cap Value 373,480 — 373,480 — Foreign Large Cap Core 950,404 — 950,404 — Total $ 23,113,057 $ 117,265 $ 22,995,792 $ — Defined Benefit Pension Plan
Fair Value Measurements - September 30, 2015 Fair Value Level 1 Level 2 Level 3 Asset Class: Cash $ 106,502 $ 106,502 $ — $ — Common and Collective Trust and Pooled Funds: Bonds Domestic Fixed Income 3,996,246 — 3,996,246 — Equities Domestic Large Cap Growth 3,150,561 — 3,150,561 — Domestic Large Cap Value 4,183,172 — 4,183,172 — Domestic Small/Mid Cap Core 1,937,613 — 1,937,613 — Foreign Large Cap Value 1,873,313 — 1,873,313 — Mutual Funds: Bonds Domestic Fixed Income 3,313,331 — 3,313,331 — Foreign Fixed Income 213,118 — 213,118 — Equities Domestic Large Cap Growth 1,030,957 — 1,030,957 — Foreign Large Cap Value 653,276 — 653,276 — Foreign Large Cap Core 936,310 — 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 Asset Class: Cash $ 43,455 $ 43,455 $ — $ — Mutual Funds Bonds Domestic Fixed Income 5,109,834 — 5,109,834 — Foreign Fixed Income 87,821 — 87,821 — Equities Domestic Large Cap Growth 1,824,796 — 1,824,796 — Domestic Large Cap Value 1,770,664 — 1,770,664 — Domestic Small/Mid Cap Growth 195,319 — 195,319 — Domestic Small/Mid Cap Value 198,884 — 198,884 — Domestic Small/Mid Cap Core 427,409 — 427,409 — Foreign Large Cap Value 964,827 — 964,827 — Foreign Large Cap Core 456,100 — 456,100 — Other 43,674 — 43,674 — Total $ 11,122,783 $ 43,455 $ 11,079,328 $ — Postretirement Benefit Plan
Fair Value Measurements - September 30, 2015 Fair Value Level 1 Level 2 Level 3 Asset Class: Cash $ 58,749 $ 58,749 $ — $ — Mutual Funds Bonds Domestic Fixed Income 4,845,174 — 4,845,174 — Foreign Fixed Income 38,654 — 38,654 — Equities Domestic Large Cap Growth 1,746,621 — 1,746,621 — Domestic Large Cap Value 1,638,695 — 1,638,695 — Domestic Small/Mid Cap Growth 194,260 — 194,260 — Domestic Small/Mid Cap Value 186,344 — 186,344 — Domestic Small/Mid Cap Core 417,980 — 417,980 — Foreign Large Cap Value 893,115 — 893,115 — Foreign Large Cap Core 378,596 — 378,596 — Other 45,441 — 45,441 — Total $ 10,443,629 $ 58,749 $ 10,384,880 $ — $500,000$750,000 to its pension plan and $500,000$1,000,000 to its postretirement benefit plan in fiscal 2016. Pension
Plan Postretirement
Plan $ 655,968 $ 617,386 698,403 625,167 773,580 634,509 818,585 655,095 944,944 695,924 6,531,464 4,012,407 Fiscal year ending September 30 Pension
Plan Postretirement
Plan 2017 $ 774,312 $ 642,842 2018 836,309 656,790 2019 910,261 679,876 2020 983,917 705,769 2021 1,048,990 747,426 2022-2026 6,613,848 4,226,050 (“401k(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 $306,382 for 2015, 2014, and 2013, respectively.7.8. COMMON STOCK OPTIONS 2015,2016, the number of shares available for future grants was 49,000.718—Compensation-Stock 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 2014 and 2013,2014, the Board approved stock option grants to certain officers. As required by the KESOP, each option’soption's exercise price per share equaled theCompany’sCompany'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.Company’sCompany'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: Years Ended September 30, 2015 2014 2013 34.34 % 35.01 % 34.75 % 4.11 % 4.21 % 4.32 % 7.00 7.00 7.00 1.98 % 2.23 % 1.23 % Years Ended September 30, 2016 2015 2014 Expected volatility 28.78% 34.34% 35.01% Expected dividends 3.99% 4.11% 4.21% Expected exercise term (years) 7.00 7.00 7.00 Risk-free interest rate 2.10% 1.98% 2.23% Company’sCompany's common stock.NoforfeituresForfeitures are assumed torecognized when they occur.Company’sCompany's plans for the years ended September 30, 2016, 2015 2014 and 20132014 are summarized below: Weighted- Average Weighted- Remaining Number of Average-Exercise Contractual Aggregate Shares Price Terms (years) Intrinsic Value 1 — $ — 0.0 $ — 21,000 19.01 — — — — — — 21,000 19.01 9.5 5,229 17,000 18.95 — — — — — — 38,000 18.98 8.8 34,840 17,000 21.60 (2,600 ) 18.99 — — — — 52,400 $ 19.83 8.3 $ 43,086 52,400 $ 19.83 8.3 $ 43,086 1 Aggregate intrinsic value includes only those options where the exercise price is below the market price. Number of Shares Weighted- Average Exercise Price Weighted- Average Remaining Contractual Terms (years) Options outstanding, September 30, 2013 21,000 $ 19.01 9.5 $ 5,229 Options granted 17,000 18.95 Options exercised — — Options expired — — Options forfeited — — Options outstanding, September 30, 2014 38,000 18.98 8.8 34,840 Options granted 17,000 21.60 Options exercised (2,600 ) 18.99 Options expired — — Options forfeited — — Options outstanding, September 30, 2015 52,400 19.83 8.3 43,086 Options granted 16,000 21.22 Options exercised (2,200 ) 18.98 Options expired — — Options forfeited (8,000 ) 19.80 Options outstanding, September 30, 2016 58,200 $ 20.25 7.8 $ 200,211 Vested and exercisable at September 30, 2016 58,200 $ 20.25 7.8 $ 200,211 2013 was $4.92, $4.43, and $4.04, respectively. The intrinsic value of the options exercised during fiscal 2016 and 2015 was $5,624.$8,418 and $5,624, respectively. The Company recognized $64,640, $83,640 $75,310 and $84,840$75,310 in stock option expense in fiscal 2016, 2015 and 2014, and 2013, respectively.2013 or 2014.8.9. OTHER STOCK PLANS (“DRIP”(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, plan, the Company issued 34,764, 8,431 7 and 24,9057 shares in 2016, 2015 2014 and 2013,2014, respectively. As of September 30, 2015,2016, the Company had 358,377323,613 shares of stock available for issuance under the DRIP Plan.(“Plan”(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 iswas paid in shares of common stock (“Restricted Stock”). The number of shares of Restricted Stock is calculatedawarded each month is determined based on the closing sales price of Resources’Resources' common stock on the NASDAQ Global Market on the first business day of the month. The Restricted Stock issued under thisthe Plan vests only in the case of a participant’sparticipant'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 thisthe Plan. The shares of Restricted Stock will be forfeited to Resources by a participant’sparticipant's voluntary resignation during his or her term on the Board or removal for cause as a director. 2015 2014 2013 Weighted-Average Weighted-Average Weighted-Average Fair Value on Fair Value on Fair Value on Shares Date of Grant Shares Date of Grant Shares Date of Grant 62,844 $ 14.29 59,064 $ 13.97 54,011 $ 13.51 4,071 20.88 3,780 19.37 5,053 18.93 — — — — — — — — — — — — 66,915 $ 14.70 62,844 $ 14.29 59,064 $ 13.97 2016 2015 2014 Shares 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 Beginning of year balance 66,915 $ 14.70 62,844 $ 14.29 59,064 $ 13.97 Granted 4,433 22.18 4,071 20.88 3,780 19.37 Vested — — — — — — Forfeited — — — — — — End of year balance 71,348 $ 15.16 66,915 $ 14.70 62,844 $ 14.29 2013 was $85,000, $73,200 and $95,667.$73,200. No Restricted Stock vested or was forfeited during fiscal 2016, 2015 2014 and 2013.2015,2016, the Company had 70,96063,008 shares available for issuance under the Restricted Stock Plan.receiveuse noin the form ofto 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 4,098 and 4,0224,098 shares valued at $39,819, $59,332 $78,841 and $72,580,$78,841, respectively, in 2016, 2015 2014 and 2013.2014. As of September 30, 20152016 the Company had 8,1746,299 shares of stock available for issuance under the Stock Bonus Plan.9.10. COMMITMENTS AND CONTINGENCIES Company’sCompany'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, 20152016 for the remainder of the contract period. The current asset management contract will expire in March 2018. Year Natural Gas Contracts
(In Decatherms)Year(In Decatherms)2015-20162016-2017 2,071,061 2016-20172017-2018 295,866 2,366,927 2015.2016. 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. The CompanyRoanoke Gas expended approximately $24,852,000, $33,405,000 $44,884,000 and $35,348,000$44,884,000 under the asset management, pipeline and storage contracts for Roanoke Gas in fiscal years 2016, 2015 2014 and 2013,2014, respectively. The table below details the pipeline and storage capacity obligations as of September 30, 20152016 for the remainder of the contract period. Pipeline and Storage Capacity $ 11,392,645 9,999,402 7,787,998 6,171,421 2,427,961 — $ 37,779,427 Year Pipeline and
Storage Capacity 2016-2017 $ 10,474,339 2017-2018 8,784,004 2018-2019 7,215,235 2019-2020 4,800,201 2020-2021 2,476,475 Thereafter 2,682,848 Total $ 36,433,102 Company and a previously owned gas subsidiary operated manufactured gas plants (MGPs) as a source of fuel for lighting and heating until the early 1950’s. A by-product of operating MGPs was coal tar, and the potential exists for on-site tar waste contaminants at the former plant sites. While the Company does not currently recognize any commitments or contingencies related to environmental costs at either site, should the Company ever be required to remediate either site, it will pursue all prudent and reasonable means to recover any related costs, including the use of insurance claims and regulatory approval for rate case recognition of expenses associated with any work required.10.11. FAIR VALUE MEASUREMENTS and 2014, respectively: Fair Value Measurements - September 30, 2015 Significant Other Significant Quoted Prices in Observable Unobservable Active Markets Inputs Inputs Fair Value Level 1 Level 2 Level 3 $ 712,710 $ — $ 712,710 $ — $ 712,710 $ — $ 712,710 $ — Fair Value Measurements - September 30, 2014 Significant Other Significant Quoted Prices in Observable Unobservable Active Markets Inputs Inputs Fair Value Level 1 Level 2 Level 3 $ 795,019 $ — $ 795,019 $ — $ 795,019 $ — $ 795,019 $ — Fair Value Measurements - September 30, 2016 Fair Value Quoted Prices in
Active Markets
Level 1 Significant Other
Observable
Inputs
Level 2 Significant
Unobservable
Inputs
Level 3 Liabilities: Natural gas purchases $ 1,052,930 $ — $ 1,052,930 $ — Total $ 1,052,930 $ — $ 1,052,930 $ — Fair Value Measurements - September 30, 2015 Fair Value Quoted Prices in
Active Markets
Level 1 Significant Other
Observable
Inputs
Level 2 Significant
Unobservable
Inputs
Level 3 Liabilities: Natural gas purchases $ 712,710 $ — $ 712,710 $ — Total $ 712,710 $ — $ 712,710 $ — 20152016 and 2014,2015, 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.20152016 and 2014. Fair Value Measurements - September 30, 2015 Significant Other Significant Quoted Prices in Observable Unobservable Carrying Active Markets Inputs Inputs Amount Level 1 Level 2 Level 3 $ 30,500,000 $ — $ — $ 28,570,585 $ 30,500,000 $ — $ — $ 28,570,585 Fair Value Measurements - September 30, 2014 Significant Other Significant Quoted Prices in Observable Unobservable Carrying Active Markets Inputs Inputs Amount Level 1 Level 2 Level 3 $ 30,500,000 $ — $ — $ 30,622,664 $ 30,500,000 $ — $ — $ 30,622,664 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 Liabilities: Long-term debt $ 33,896,200 $ — $ — $ 36,163,523 Total $ 33,896,200 $ — $ — $ 36,163,523 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 Liabilities: Long-term debt $ 30,500,000 $ — $ — $ 28,570,585 Total $ 30,500,000 $ — $ — $ 28,570,585 11.12. QUARTERLY FINANCIAL INFORMATION (UNAUDITED) 20152016 and 20142015 is summarized as follows: First
Quarter Second
Quarter Third
Quarter Fourth
Quarter $ 21,250,065 $ 26,431,729 $ 10,774,409 $ 9,733,404 $ 8,622,143 $ 10,213,770 $ 5,961,828 $ 5,408,692 $ 3,514,352 $ 4,879,469 $ 956,219 $ 656,152 $ 1,924,376 $ 2,779,344 $ 354,940 $ 35,755 $ 0.41 $ 0.59 $ 0.08 $ 0.01 $ 0.41 $ 0.59 $ 0.07 $ 0.01 First
Quarter Second
Quarter Third
Quarter Fourth
Quarter $ 20,011,194 $ 32,699,965 $ 12,024,817 $ 10,280,158 $ 8,202,992 $ 10,161,125 $ 5,721,551 $ 5,251,421 $ 3,272,646 $ 5,121,022 $ 940,691 $ 347,509 $ 1,722,788 $ 2,846,795 $ 283,194 $ (144,337 ) $ 0.37 $ 0.60 $ 0.06 $ (0.03 ) $ 0.37 $ 0.60 $ 0.06 $ (0.03 ) 2016 First
Quarter Second
Quarter Third
Quarter Fourth
Quarter Operating revenues $ 16,010,056 $ 21,777,773 $ 11,295,197 $ 9,980,265 Gross margin $ 8,738,116 $ 10,649,269 $ 6,312,340 $ 5,865,189 Operating income $ 3,498,052 $ 5,444,314 $ 1,453,350 $ 816,376 Net income $ 1,922,790 $ 3,111,447 $ 627,068 $ 145,561 Earnings per share of common stock: Basic $ 0.40 $ 0.65 $ 0.13 $ 0.03 Diluted $ 0.40 $ 0.65 $ 0.13 $ 0.03 2015 First
Quarter Second
Quarter Third
Quarter Fourth
Quarter Operating revenues $ 21,250,065 $ 26,431,729 $ 10,774,409 $ 9,733,404 Gross margin $ 8,622,143 $ 10,213,770 $ 5,961,828 $ 5,408,692 Operating income $ 3,514,352 $ 4,879,469 $ 956,219 $ 656,152 Net income $ 1,924,376 $ 2,779,344 $ 354,940 $ 35,755 Earnings per share of common stock: Basic $ 0.41 $ 0.59 $ 0.08 $ 0.01 Diluted $ 0.41 $ 0.59 $ 0.07 $ 0.01 12.13. SUBSEQUENT EVENTS OctoberNovember 1, 2015, the Company, through its newly formed wholly-owned subsidiary, RGC Midstream, LLC,2016, Roanoke Gas entered into ana 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 becomeconvert the variable rate debt into a 1% member in the Mountain Valley Pipeline, LLC (the “LLC”)fixed-rate instrument with an annual interest rate of 2.30%. The LLC was establishedswap 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 construct and operateconvert a natural gas pipeline originating in northern West Virginia and extending through south central Virginia. This project, if approved by the Federal Energy Regulatory Commission, will require an estimated $35 million investment by the Company to support the constructionportion of the pipeline over the next 3 years. The projected in service date of the pipeline is late 2018. The Company will participate in the earnings generated from the transportation of natural gas on the pipeline in proportion to its level of investment. The Company will apply the equity method to account for the transactions and activity of the investment.On October 1, 2015, RGC Midstream borrowed $1,500,000 under a temporaryCompany's line-of-credit agreement to make its initial investment in the LLC.Item 9. Disclosure.Disclosure.Item 9A. Procedures.Procedures.2015,2016, 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, 2015.2015,2016, based on the framework set forth in “Internal”Internal Control - Integrated Framework (1992)(2013)”issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based upon such evaluation, the Company concluded that, as of September 30, 2015,2016, the Company’s internal control over financial reporting was effective.2015.2015,2016, based on criteria established inInternal Control-Integrated Framework - 19922013 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’sManagement'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.2015,2016, based on criteria established inInternal Control-Integrated Framework - 19922013 issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).20152016 and 20142015 and the related consolidated statements of income, comprehensive income, stockholders’ equity, and cash flows of RGC Resources, Inc. and Subsidiaries for each of the years in the three year period ended September 30, 2015,2016, and our report dated December 4, 20158, 2016 expressed an unqualified opinion.CERTIFIED PUBLIC ACCOUNTANTS 4, 2015Item 9B. Other Information Item 10. Officers”Officers" section in the Proxy Statement for the 20162017 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 20162017 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.“Director Nominations”"Director Nominations" in the Proxy Statement for the 20162017 Annual Meeting of Shareholders of Resources, which is incorporated herein by reference.“Section"Section 16 Compliance”Compliance" in the Proxy Statement for the 20162017 Annual Meeting of Shareholders of Resources, is incorporated herein by reference.Item 11. Compensation.Compensation.“Compensation"Compensation of Directors”Directors", “Compensation"Compensation Discussion and Analysis”Analysis" and “Report"Report of the Compensation Committee”Committee" in the Proxy Statement for the 20162017 Annual Meeting of Shareholders of Resources is incorporated herein by reference.Item 12. Matters.Matters.Management”Management" in the Proxy Statement for the 20162017 Annual Meeting of Shareholders of Resources, is incorporated herein by reference.Item 13. Independence.Independence.“Transactions"Transactions with Related Persons”Persons" section in the Proxy Statement for the 20162017 Annual Meeting of Shareholders of Resources, which is incorporated herein by reference.“Transactions"Transactions with Related Persons”Persons" in the Proxy Statement for the 20162017 Annual Meeting of Shareholders of Resources, which information is incorporated herein by reference.Item 14. Services.Services.“Report"Report of the Audit Committee”Committee" in the Proxy Statement for the 20162017 Annual Meeting of Shareholders of Resources is incorporated herein by reference.Item 15. Schedules.Schedules.(a) List of documents filed as part of this report: 1. Financial statements filed as part of this report: 2. Financial statement schedules filed as part of this report: 3. Exhibits to this Form 10-K filed as part of this report: 13 2015 Annual Report to Shareholders (such report, except to the extent incorporated herein by reference, is being furnished for the information of the Commission only and is not to be deemed filed as part of this Annual Report on Form 10-K)10 (l)(l) Second Amendment to RGC Resources, Inc. Restricted Stock Plan for Outside Directors 21 Subsidiaries of the Company 23 Consent of Brown, Edwards & Company, LLP 31.1 Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer 31.2 Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer 32.1* Section 1350 Certification of Principal Executive Officer 32.2* Section 1350 Certification of Principal Financial Officer 101 The following documents from the Registrant’s Annual Report on Form 10-K for the years ended September 30, 2016, 2015 2014 and 2013,2014, formatted in XBRL (eXtensible Business Reporting Language); Consolidated Balance Sheets at September 30, 20152016 and 2014,2015, (ii) Consolidated Statements of Income for the years ended September 30, 2016, 2015 2014 and 2013,2014, (iii) Consolidated Statements of Comprehensive Income for the years ended September 30, 2016, 2015 2014 and 2013,2014, (iv) Consolidated Statements of Stockholders’ Equity for the years ended September 30, 2016, 2015 2014 and 2013,2014, (v) Consolidated Statements of Cash Flows for the years ended September 30, 2016, 2015 2014 and 2013,2014, 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. RGC RESOURCES, INC. By: December 8, 2016 December 10, 2015 Paul W. Nester Date Vice President, Secretary, Treasurer and CFO (principal accounting and financial officer) JOHNJOHN S. D’ORAZIO D'ORAZIO John S. D’Orazio 10, 2015 Date President and Chief Executive Officer, Director /S/ PAUL W. NESTER Paul W. Nester December 10, 2015 December 8, 2016 Paul W. Nester Date John B. Williamson, III 10, 2015Date Chairman of the Board and Director /S/ NANCY H. AGEE Nancy H. Agee December 10, 2015Date Director Nancy H. Agee Date December 8, 2016 Director Abney S. Boxley, III Date December 8, 2016 Director Maryellen F. Goodlatte Date December 8, 2016 Director J. Allen Layman Date December 8, 2016 Director George W. Logan Date December 8, 2016 Director S. Frank Smith Date December 8, 2016 Director Raymond D. Smoot, Jr. Date /S/ ABNEY S. BOXLEY, III Abney S. Boxley, III December 10, 2015Date Director/S/ MARYELLEN F. GOODLATTE Maryellen F. GoodlatteDecember 10, 2015DateDirector/S/ J. ALLEN LAYMAN J. Allen LaymanDecember 10, 2015DateDirector/S/ GEORGE W. LOGAN George W. LoganDecember 10, 2015DateDirector/S/ S. FRANK SMITH S. Frank SmithDecember 10, 2015DateDirector/S/ RAYMOND D. SMOOT, JR. Raymond D. Smoot, Jr.December 10, 2015DateDirectorEXHIBIT INDEXExhibit No.Description3 (a) 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) 3 (b) 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) 4 (a) 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) 4 (b) 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) 10 (a) 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)) 10 (b) 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) 10 (c) 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) 10 (d) 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) 10 (e) 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) 10 (f) 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) 10 (g) 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)) 10 (h) 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)) 10 (i) 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)) 10 (j) 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) 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)) 10 (l) 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)) 10 (m) 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)) 10 (n) 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)) 10 (o) 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)) 10 (p) 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)) 10 (q) 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)) 10 (r) 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)) 10 (s) 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) 10 (t) 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) 10 (u) 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) 10 (v) 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) 10 (w) 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) 10 (x) 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) 10 (t)(y) 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 (u)(z) 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) 10 (v)(a)(a) 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) 10 (w)(b)(b) Certificate of Public Convenience and Necessity for Franklin County dated September 8, 1964 (incorporated herein by reference to Exhibit 10(t) of Registration Statement No. 33-36605, on Form S-2, filed with the Commission on August 29, 1990, and amended by Amendment No. 1, filed with the Commission on September 19, 1990) 10 (x)(c)(c) 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) 10 (y)(d)(d) Resolution of the Council for the Town of Troutville, Virginia dated November 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)10 (z)(e)(e)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) 10 (f)(f) 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) 10 (g)(g) Gas Franchise Agreement between the Town of Vinton, Virginia, and Roanoke Gas Company dated July 2, 1996November 17, 2015 (incorporated herein by reference to Exhibit 10(n)(n) of Annual Report10.3 on Form 10-K for the fiscal year ended September 30, 1996 (SEC file number reference 0-367))8-K as filed December 16, 2015)10 (a) (a)Gas Franchise Agreement between the City of Salem, Virginia, and Roanoke Gas Company dated July 9, 1996 (incorporated herein by reference to Exhibit 10(o)(o) of Annual Report on Form 10-K for the fiscal year ended September 30, 1996 (SEC file number reference 0-367))10 (b) (b)Gas Franchise Agreement between the City of Roanoke, Virginia, and Roanoke Gas Company dated July 12, 1996 (incorporated herein by reference to Exhibit 10(p)(p) of Annual Report on Form 10-K for the fiscal year ended September 30, 1996 (SEC file number reference 0-367))10 (c) (c)(h)(h) 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) 10 (d) (d)(i)(i) 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)) 10 (e) (e)(j)(j) 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) 10 (f) (f)(k)(k)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) 10 (l)(l) Second Amendment to RGC Resources, Inc. Restricted Stock Plan for Outside Directors 10 (m)(m) 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) 10 (g) (g)(n)(n) 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) 10 (h) (h)(o)(o) 10 (i) (i)(p)(p) Change in Control Agreement between John S. D’Orazio and RGC Resources, Inc. and John S. D'Orazio effective April 1, 20112016 (incorporated herein by reference to Exhibit 10.210.1 on Form 8-K as filed April 4, 2011 (SEC file number reference 0-367))2016)10 (j) (j)(q)(q) 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, 20152016 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed April 3, 2015)4, 2016)10 (k)(k)(r)(r) Credit Agreement by and between Roanoke Gas Company and Wells Fargo Bank, N.A. dated March 31, 20152016 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed April 3, 2015)4, 2016)10 (l)(l)(s)(s) Continuing guarantyGuaranty by RGC Resources, Inc. andin favor of Wells Fargo Bank, N. A.N.A. dated March 31, 20152016 (incorporated by reference to Exhibit 10.3 on Form 8-K as filed April 3, 2015)4, 2016)10 (m)(m)(t)(t) Indemnification and Cost Sharing Agreement by and between RGC Resources, Inc., Bluefield Gas Company and ANGD, LLC (incorporated herein by reference to Exhibit 10(x)(x) on Form 10-K as filed December 21, 2007 (SEC file number reference 0-367)) 10 (n)(n)(u)(u) 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) 10 (o)(o)(v)(v) 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) 10 (p)(p)(w)(w) 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) 10 (q)(q)(x)(x) 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) 10 (r)(r)(y)(y) 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) 10 (s)(s)(z)(z) 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)) 10 (t)(t)(a)(a)(a) 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)) 10 (b)(b)(b) 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) 10 (c)(c)(c) 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) 10 (d)(d)(d) 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) 10 (e)(e)(e) 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) 1310 (f)(f)(f)** 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) 10 (g)(g)(g) ** 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) 10 (h)(h)(h) Guaranty Agreement by RGC Resources, Inc. in favor of Mountain Valley Pipeline, LLC dated October 1, 2015 Annual Report to Shareholders (such report, except to the extent incorporated(incorporated herein by reference is being furnished for the information of the Commission only and is not to be deemed filed as part of this Annual ReportExhibit 10.2 on Form 10-K)10-Q as filed February 5, 2016)21 Subsidiaries of the Company 23 Consent of Brown, Edwards & Company, LLP 31.1 Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer 31.2 Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer 32.1* Section 1350 Certification of Principal Executive Officer 32.2* Section 1350 Certification of Principal Financial Officer 101 2014 and 2013,2014, formatted in XBRL (eXtensible Business Reporting Language); Consolidated Balance Sheets at September 30, 20152016 and 2014,2015, (ii) Consolidated Statements of Income for the years ended September 30, 2016, 2015 2014 and 2013,2014, (iii) Consolidated Statements of Comprehensive Income for the years ended September 30, 2015.2016. 2015 and 2014, and 2013, (iv) Consolidated Statements of Stockholders’ Equity for the years ended September 30, 2016, 2015 2014 and 2013,2014, (v) Consolidated Statements of Cash Flows for the years ended September 30, 2016, 2015 2014 and 2013,2014, 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. 71** 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.