Operationally, 2014 was a strong and busy year. The weather was 9% colder than the 30-year average and our total natural gas deliveries exceeded 10 million deka-therms. Industrial demand increased by 6% over last year and we anticipate this higher level of natural gas use to continue next year. We are also excited to provide natural gas service to a new packaging manufacturer, Ardagh Group, which opened a $93 million metal packaging plant with the capability of producing 1.7 billion cans a year.

We invested a record $14.7 million in capital improvements in 2014 and plan to invest approximately $13.5 million in fiscal 2015. We continue to aggressively modernize our distribution system. In 2014, we replaced 13.6 miles of cast iron and bare steel pipe with polyethylene pipe. In 1991, cast iron and bare steel pipe accounted for approximately 25% of our distribution system. At the end of fiscal 2014, it represents less than 2%. Based on the estimated replacement rate, we anticipate replacing all remaining bare steel and cast iron pipe by the end of 2016, further enhancing safety and system reliability. Once we complete the replacement of our bare steel and cast iron mains, our efforts will shift to replacing all pre-1973 plastic mains with current polyethylene pipe. This infrastructure replacement program is forecast to be completed in fiscal 2019. In 2014, we replaced and upgraded one of our primary gas transfer stations and are in the final stages of replacing a critical piece of equipment at our liquefied natural gas facility that is used for peak shaving during extremely cold periods.

“INDUSTRIAL DEMAND INCREASED BY 6% OVER LAST YEAR AND WE ANTICIPATE THIS HIGHER LEVEL OF NATURAL GAS USE TO CONTINUE NEXT YEAR.”

As the economy continues to gradually improve, we are experiencing improved customer growth. In 2014, new customer additions increased 43% over last year. The new construction segment increased 7%, the conversion segment where existing homes or businesses converted to natural gas from either propane, fuel oil or electric increased 17%, and the balance of the increase was derived from the conversion of an apartment complex to individual gas meters.

We had an active year from a regulatory prospective. The rate case filed in September 2013 was settled favorably with the Virginia State Corporation Commission (SCC) in May 2014, at $887,000 with an authorized return on equity of 9.75%. We filed an updated depreciation study with the SCC in June and received approval of the new depreciation rates in September, resulting in a slight decrease in annual depreciation expense. We filed and received approval on an amendment to a separate regulatory infrastructure replacement plan designed to recover the increased investment carrying costs and depreciation expense associated with future planned infrastructure replacements through calendar year 2018. This includes modernization of our distribution system, replacement of our gas transfer station on

the interstate pipeline, and replacement of a key component at our liquefied natural gas facility. Last, we filed and received approval from the SCC for refinancing our existing long-term debt, which will reduce our annual interest expense going forward.

On a national level, natural gas industry data indicates that we have a natural gas supply of over 100 years. This abundant and increasingly accessible supply has created low and stable prices on both a near and intermediate term basis. Production continues to increase in the various shale formations around the country as natural gas exploration and production companies continue to improve drilling and fracking technologies. As production has increased, so has the demand for new pipelines to move this increased supply to market. Interstate pipeline companies are investing billions of dollars constructing new pipelines and modifying existing pipelines to make them bi-directional so they can efficiently move gas as future demand increases.

In the Commonwealth of Virginia, two pipelines are proposed: Atlantic Coast Pipeline and the Mountain Valley Pipeline. Both are designed to move gas from the Marcellus and Utica shale formations to the Southeast.

The Mountain Valley Pipeline, if constructed, may provide future opportunities to expand our footprint in Virginia to areas that currently do not have access to natural gas.

We are excited to be part of the growing natural gas industry and the pursuit of potential growth opportunities it may bring to our Company. I look forward to reporting to you at the end of 2015 on what I anticipate to be another year of solid performance.

On behalf of our dedicated employees and the Board of Directors, I thank you for your continued interest in our operations and your continuing decision to invest in RGC Resources.

Sincerely,

John D’Orazio

President & CEO

FORWARD-LOOKING STATEMENTS

This report contains forward-looking statements that relate to future transactions, events or expectations. RGC Resources, Inc. (“Resources” or the “Company”) may publish forward-looking statements relating to such matters as anticipated financial performance, business prospects, technological developments, new products, research and development activities and similar matters. These statements are based on management’s current expectations and information available at the time of such statements and are believed to be reasonable and are made in good faith. The Private Securities Litigation Reform Act of 1995 provides a safe harbor for forward-looking statements. In order to comply with the terms of the safe harbor, the Company notes that a variety of factors could cause the Company’s actual results and experience to differ materially from the anticipated results or expectations expressed in the Company’s forward-looking statements. The risks and uncertainties that may affect the operations, performance, development and results of the Company’s business include, but are not limited to those set forth in the following discussion and within Item 1A “Risk Factors” of this Annual Report

on Form 10-K. All of these factors are difficult to predict and many are beyond the Company’s control. Accordingly, while the Company believes its forward-looking statements to be reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from them will be realized. When used in the Company’s documents or news releases, the words “anticipate,” “believe,” “intend,” “plan,” “estimate,” “expect,” “objective,” “projection,” “forecast,” “budget,” “assume,” “indicate” or similar words or future or conditional verbs such as “will,” “would,” “should,” “can,” “could” or “may” are intended to identify forward-looking statements.

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

MANAGEMENT’S DISCUSSION & ANALYSIS

OVERVIEW

Resources is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately 58,600 residential, commercial and industrial customers in Roanoke, Virginia and the surrounding localities, through its Roanoke Gas Company (“Roanoke Gas”) subsidiary. Resources also provides certain unregulated services through Roanoke Gas and utility consulting and information system services through RGC Ventures of Virginia, Inc., which operates as The Utility Consultants and Application Resources. The unregulated operations represent less than 3% of revenues and margins of Resources.

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

The Company is committed to the safe and reliable delivery of natural gas to its customers. Since 1991, the Company has placed an emphasis on the modernization of its distribution system through the renewal and replacement of its cast iron and bare steel natural gas distribution pipelines. With recent regulatory actions placing a greater emphasis on pipeline safety, the Company continues to focus its efforts on completing its renewal and replacement program. Management anticipates replacing all remaining cast iron and bare steel pipe within the next three years.

The Company is also dedicated to the safeguarding of its information technology systems. These systems contain confidential customer, vendor and employee information as well as important financial data. There is risk associated with the unauthorized access of this

information with a malicious intent to corrupt data, cause operational disruptions, or compromise information. Management believes it has taken reasonable security measures to protect these systems from cyber security attacks and other types of breaches; however, there can be no guarantee that a breach will not occur. In the event of a breach, the Company will execute its Security Incident Response Plan to assist with managing the incident. The Company also maintains cyber-insurance coverage to mitigate financial implications resulting from a breach of confidential information.

Over 97% of the Company’s revenues are derived through the regulated operations of Roanoke Gas primarily associated with the sale and delivery of natural gas to its customers. The SCC authorizes the rates and fees that 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.

The Company’s business is seasonal in nature and weather sensitive as a majority of natural gas sales are for space heating during the winter season. Volatility in winter weather and the commodity price of natural gas, can impact the effectiveness of the Company’s rates in recovering its costs and providing a reasonable return for its shareholders. In order to mitigate the effect of weather variations, the Company has certain approved rate mechanisms that help provide stability in earnings. These mechanisms include a weather normalization adjustment factor, inventory carrying cost revenue and a SAVE adjustment rider.

The weather normalization adjustment mechanism (“WNA”) reduces the volatility in earnings due to the variability in temperatures during the heating season. The WNA is based on a weather measurement band around the most recent 30-year temperature average. The WNA provides the Company with a level of earnings protection

when weather is warmer than normal and provides its customers with price protection when the weather is colder than normal. Through March 31, 2014, the WNA provided for a weather band of 3% above and below the 30-year average, whereby the Company would bill its customers for the lost margin (excluding gas costs) for the impact of weather that was more than 3% warmer than normal or refund customers the excess margin earned for weather that was more than 3% colder than normal. The annual WNA period extends from April to March. For the WNA periods ending March 31, 2014, 2013 and 2012, the number of heating degree days were 10% colder than normal, less than 3% warmer than normal and 22% warmer than normal, respectively. As a result, the Company refunded customers approximately $707,000 in excess margin in fiscal 2014 and billed customers approximately $1,747,000 in additional margin in fiscal 2012. No billing or refunds were required in fiscal 2013 as the number of heating degree days fell within the 3% band. Effective with the new WNA period beginning April 1, 2014, the 3% weather band was eliminated and the WNA is now based strictly on the variations from normal. At September 30, 2014, the number of heating degree days for the six month period was less than the 30-year average and the Company accrued approximately $144,000 in additional margin. Additional information on the WNA is provided under the Regulatory Affairs section.

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

During times of rising gas costs and rising inventory levels, the Company recognizes revenues to offset higher financing costs associated with higher inventory balances. Conversely, during times of decreasing gas costs and declining inventory balances, the Company recognizes less carrying cost revenue as financing costs are lower. Although the total cost of natural gas in storage, as well as the cost per decatherm, at September 30, 2014 was higher than the cost in storage at September 30, 2013, the average balance during the year was down by more than 4% due to greater level of storage withdrawals during a much colder 2013-2014 winter season. In addition, the ICC factor declined by 2%, resulting in a reduction in ICC revenues of $58,000. Fiscal 2013 reflected a $299,000 reduction in ICC revenues due to a 14% lower average balance of natural gas in storage as compared to fiscal 2012.

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

The Company’s non-gas rates provide for the recovery of non-gas related expenses and a reasonable return to shareholders. These rates are determined based on the filing of a formal rate application with the SCC utilizing historical information including investment in natural gas facilities. Generally, investments related to extending service to new customers are recovered through the non-gas rates currently in place. The investment in replacing and upgrading existing infrastructure is not recoverable until a formal rate application is made to

include the additional investment and new non-gas rates are approved. The SAVE (“Steps to Advance Virginia’s Energy”) 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. Additional information regarding the SAVE Rider is provided under the Regulatory Affairs section.

The economic environment has a direct correlation with business and industrial production, customer growth and natural gas utilization. The local economy continues to show signs of improvement from the economic downturn that began in 2008, as industrial production activities and the related interruptible and transportation sales to support those activities have returned to pre-2008 levels. Although there are signs of improvement, residential construction and housing starts continue to remain below historical levels. If economic stagnation were to return, industrial activity and new customer growth could be negatively impacted. In addition to economic considerations, natural gas consumption continues to be affected by technological and efficiency improvements in heating equipment.

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 the current year.

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 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, as discussed in more detail in the Regulatory Affairs section below, 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:

NET UTILITY MARGIN INCREASE

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. Insurance premiums are expected to increase in fiscal 2015 as well but at a lesser amount. These higher costs were partially offset by a $605,000 reduction in employee benefit expenses, specifically in the defined benefit pension plan (“pension plan”) and the postretirement medical and life insurance plan (“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. 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 financial statements. In addition, $339,000 of additional overheads was capitalized due to a significantly higher level of construction expenditures related to the Company’s renewal program and other projects. Total capital expenditures rose by more than $4.7 million over the prior year. The remaining increase of $188,000 relates to a variety of areas including additional facility and equipment maintenance and support costs, higher utility expenses and increased administrative costs related to the Company’s operations.

GENERAL TAXES – General taxes increased $79,640, or 5%, primarily due to higher property taxes associated with increases in utility property and greater payroll taxes related to increased operations staffing.

DEPRECIATION – Depreciation expense increased by $237,956, or 5%, corresponding to the increase in utility plant investment partially offset by lower depreciation rates.

OTHER EXPENSE – Other expense, net, increased by $146,770 primarily due to the absence of interest income related to the ANGD note which was paid off in fiscal 2013 combined with a greater level of corporate charitable giving and increased SCC pipeline assessments.

INTEREST EXPENSE – Total interest expense remained virtually unchanged from last year 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.

Total gas utility operating revenues for the year ended September 30, 2013 increased by 7% from the year ended September 30, 2012. The increase in gas revenues was primarily attributable to a 22% increase in residential and commercial delivered volumes, partially offset by lower natural gas commodity prices during the winter heating season. The increase in delivered volumes was driven by the much colder winter heating season compared to

fiscal 2012, evidenced by the 25% increase in heating degree days. Although the total heating degree days increased significantly, the fiscal 2013 year weather was nearly equal to the 30-year average. Transportation and interruptible volumes declined by 2%. Other revenues increased by 3% due to the completion of a one-time project more than offsetting declines in the level of certain other contract services.

Regulated natural gas margins from utility operations increased by 3% from fiscal 2012 primarily as a result of significantly 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 increased due to the much colder winter season. The higher margins generated by the increased residential and commercial volume were mostly offset by the $1,747,000 in WNA revenues recorded in fiscal 2012. The Company also implemented a non-gas rate increase effective November 1, 2012 and a SAVE Plan Rider beginning January 1, 2013. The non-gas rate increase was designed to provide approximately $650,000 in additional non-gas revenues annually. The implementation of the increased rates in November accounted for approximately $254,000 of the increase in customer base charges and $328,000 of the additional volumetric revenue. The SAVE Plan Rider provided $169,000 in margin. Carrying cost revenues continued to decline with a $299,000 reduction due to lower average price of gas in storage during the fiscal 2013 year.

Other margins, consisting of non-utility related services, decreased by $58,551 due to a reduction in the level of services. Some of these non-utility services are subject to annual or semi-annual contract renewals and the level of activity under these contracts will fluctuate.

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

NET UTILITY MARGIN INCREASE

OPERATIONS AND MAINTENANCE EXPENSE – Operations and maintenance expenses increased by $305,906, or 2%, in fiscal 2013 compared with fiscal 2012 primarily due to higher labor costs, contracted services, bad debt expense, corporate insurance expense and stock option expense more than offsetting greater capitalization of Company overheads on construction projects and LNG (liquefied natural gas) production. Labor costs and contracted services increased by $453,000 primarily due to an increase in operations staffing, timing of leak surveys and pipeline right-of-way clearing, costs related to an SCC mandated meter installation inspection and remediation program, and network services support and training. Bad debt expense increased by approximately $74,000. Total bad debt expense was 0.13% of gross natural gas billings for fiscal 2013 and is consistent with the five-year average. Fiscal 2012’s bad debt expense ratio was only 0.02%. This unusually low rate was due to much warmer weather and low gas prices, resulting in the lowest bad debt write-off in over twenty-five years. Corporate property and liability insurance increased by $126,000 due to a combination of higher premiums and increased general liability coverage limits. The Company also recognized $85,000 in expense related to the granting of stock options. These were the first option grants since 2002. These higher costs were partially offset by greater capitalization of overheads due to a higher level of pipeline construction expenditures and increased LNG production. The Company continued to increase activity under its pipeline renewal program, with total capital expenditures rising by more than $1.3 million over fiscal 2012, resulting in a greater capitalization of overheads.

GENERAL TAXES – General taxes increased $114,066, or 8%, primarily due to higher property taxes associated with increases in utility property.

DEPRECIATION – Depreciation expense increased by $241,302, or 6%, corresponding to the increase in utility plant investment.

OTHER INCOME (EXPENSE) – Other expense, net, increased by $40,161 primarily due to the reduction in interest income related to the payoff of the ANGD note in fiscal 2013.

INTEREST EXPENSE – Total interest expense remained virtually unchanged from fiscal 2012 as the Company only briefly accessed its line-of-credit during fiscal 2013.

INCOME TAXES – Income tax expense was nearly unchanged on slightly less pre-tax earnings. The effective tax rate for fiscal 2013 was 38.3% compared to 38.0% for 2012.

NET INCOME AND DIVIDENDS – Net income for fiscal 2013 was $4,262,052 compared to $4,296,745 for fiscal 2012. Basic and diluted earnings per share were $0.91 in fiscal 2013 compared to $0.92 in fiscal 2012. Dividends declared per share of common stock were $1.72 in fiscal 2013, which includes the onetime special dividend of $1.00 paid in December 2012, compared to $0.70 in fiscal 2012.

ASSET MANAGEMENT

Roanoke Gas uses a third-party asset manager to manage its pipeline transportation, storage rights and gas supply inventories and deliveries. In return for being able to utilize the excess capacities of the transportation and storage rights, the third party pays Roanoke Gas a monthly utilization fee, which is used to reduce the cost of gas for customers. Under the provision of the asset management contract, the Company has an obligation to purchase its winter storage requirements during the spring and summer injection periods at the market price in place at the time of purchase. This commitment amounts to approximately 2,071,000 decatherms per year or approximately one-third of the Company’s total annual purchases. In addition to the storage purchase requirements, the Company generally purchases its monthly supply requirements from the asset manager based on market price.

CAPITAL RESOURCES AND LIQUIDITY

Due to the capital intensive nature of the utility business, as well as the related weather sensitivity, the Company’s primary capital needs are for the funding of its continuing construction program, the seasonal funding of its natural gas inventories and accounts receivables and payment of dividends. To meet these needs, the Company relies on its

operating cash flows, line-of-credit agreement, long-term debt, and to a lesser extent, capital raised through the Company’s stock plans.

Cash and cash equivalents decreased by $1,996,467 in fiscal 2014 compared to a decrease of $6,063,647 in fiscal 2013 and an increase of $958,442 in fiscal 2012. The following table summarizes the categories of sources and uses of cash:

As discussed below, the Company increased its capital spending in fiscal 2014 and financed the increase through operating cash flow and utilization of the line-of-credit.

CASH FLOWS FROM OPERATING ACTIVITIES:

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

Cash provided by operating activities was $6,840,000 in fiscal 2014, $10,037,000 in fiscal 2013 and $11,783,000 in fiscal 2012. Cash provided by operating activities declined by approximately $3,197,000 from last year primarily as a result of a significant move from an over-recovery of gas costs to an under-recovery position during fiscal 2014. As provided under the provisions of the Company’s Purchased Gas Adjustment (“PGA”) clause, the Company

is allowed to recover the actual cost of natural gas from its customers. Any amounts billed in excess of the actual cost are considered an over-recovery of these costs and are reflected as a liability on the financial statements. Conversely, any actual costs incurred in excess of amounts billed are considered an under-recovery of gas costs and are reflected as an asset on the financial statements. During fiscal 2014, the Company went from an over-recovered position of $1,027,000 to an under-recovered position of $181,000, which used $1,208,000 in operating cash. Conversely, during fiscal 2013, the Company went from an under-recovered position of $687,000 to an over-recovered position of $1,027,000, which generated $1,714,000 in operating cash. Increases in operating cash flows due to greater contributions from net income and depreciation offset the impact of increased investment in gas in storage and other operating variances.

Cash provided by operating activities decreased for fiscal 2013 from fiscal 2012 by $1,746,000 due to an increase in cost of gas in storage partially offset by an over-recovery on gas costs and the tax deferral benefits of bonus depreciation. The cost of gas in storage had declined for the last few years as the commodity price of gas declined; however, when the Company began its fiscal 2013 summer storage program to refill the storage balances,

the commodity price of gas was higher than fiscal 2012 resulting in higher storage balances by year-end. The average price of natural gas in storage was $4.08 and $3.51 as of September 30, 2013 and 2012, respectively. During fiscal 2013, the Company had a $1,714,000 operating source of cash as the Company went from an under-recovered position to an over-recovered position. During fiscal 2012, the Company had an operating use of cash of $1,043,000 as the Company went from an over-recovered position to an under-recovered position. In addition, 50% bonus depreciation for tax purposes was in place for fiscal 2013 resulting in the Company’s deferred income tax liability associated with its utility property increasing by $1,700,000 in fiscal 2013 and more than $2,200,000 in fiscal 2012, thereby deferring payment of income taxes until future periods. The deferred tax liability related to utility property increased by less than $500,000 in fiscal 2014 as bonus depreciation expired December 31, 2013. The Company has approximately $17,100,000 in deferred tax liabilities related to accelerated and bonus depreciation at September 30, 2014 on its utility plant that will begin to reverse in 2015 or later resulting in additional cash outflows for payment of the deferred taxes.

CASH FLOWS USED IN INVESTING ACTIVITIES:

Investing activities are generally composed of expenditures under the Company’s construction program, which involves a combination of replacing aging bare steel and cast iron pipe with new plastic or coated steel pipe, making improvements to the LNG plant and expansion of its natural gas system to meet the demands of customer growth. The Company’s expenditures related to its pipeline renewal program and other system and infrastructure improvements and expansion have continued to trend upward with more than $14,700,000 spent in fiscal 2014 compared to approximately $10,000,000 in fiscal 2013 and $8,700,000 in fiscal 2012. The Company renewed 13.6 miles of bare steel and cast iron natural gas distribution main and replaced 942 services in fiscal 2014. This compares to 13 miles main and 1,064 services in fiscal 2013 and 15.8 miles of main and 1,429 services in fiscal 2012. Total costs related to the renewal program are higher this year even though the total miles of mains were slightly higher and the number of services replaced were less than last year. As the renewal program has progressed, most of the less complex and more highly concentrated areas of the Company’s natural gas distribution system have been completed leaving the more difficult and smaller sections to be done. Completion of the remaining pipeline replacement will more than likely be at a higher per foot cost. The Company’s capital expenditures also included costs to extend mains and services to 673 new customers in fiscal 2014 compared to 468 in fiscal 2013 and 450 in fiscal 2012. In addition, the Company completed the replacement of its Gala transfer station and made significant progress in the replacement of the boil off compressor at the LNG plant.

RGC Resources is committed to the safe and reliable delivery of natural gas to its customers and, as a result, plans to commit the necessary resources to its pipeline renewal program with an expectation to replace all remaining cast iron and bare steel pipe within the next three years. As a reflection of this commitment, the Company’s capital budget for next year currently is estimated to be near the fiscal 2014 level as work continues on the pipeline replacement program and the installation of a new boil off compressor at the LNG plant is completed. Depreciation provided approximately 33% of the current year’s capital expenditures compared to 47% for 2013 and 51% for 2012. 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 current polyethylene pipe. This project encompasses approximately 40 miles of natural gas main with a 2019 anticipated completion. With future capital expenditures projected to remain at higher than historical levels over these next few years, the Company expects to increase its borrowing activity.

CASH FLOWS PROVIDED BY (USED IN) FINANCING ACTIVITIES:

Financing activities generally consist of long-term and short-term borrowings and repayments, issuance of stock and the payment of dividends. As mentioned above, the Company uses its line-of-credit arrangement to fund seasonal working capital and provide temporary financing for capital projects. Cash flows provided by financing activities were $5,862,000 for fiscal 2014 compared to cash flows used in financing activities of $6,153,000 for fiscal 2013 and $2,174,000 for fiscal 2012. The Company experienced significant activity in financing cash flows in 2014. The Company refinanced $28,000,000 of its debt, including $2,238,000 in early termination fees on the notes and corresponding interest rate swaps, with $30,500,000 in unsecured 20-year term notes. The early termination fees have been deferred as a regulatory asset and will be 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 Company will realize approximately $376,000 in lower annual interest expense as a result of the refinancing. The Company also increased the utilization of its line-of-credit to fund both the Company’s seasonal working capital needs as well as bridge financing for its capital budget. At the current level of capital expenditures, operating cash flows are not sufficient to meet both the capital expenditure requirements and the payment of dividends. Dividends returned to normal levels in fiscal 2014 at an annual rate of $0.74 per share. Last year included a special $1.00 per share dividend paid by the Company on December 17, 2012. The special dividend totaled $4,675,337, of which $425,630 was returned

to the Company under the DRIP Plan. The Company’s consolidated capitalization was 63.0% equity and 37.0% long-term debt at September 30, 2014. This compares to 63.9% equity and 36.1% debt, including the note payable, at September 30, 2013. Including the line-of-credit as part of total consolidated capitalization, September 30, 2014 ratios would be 56.8% equity and 43.2% debt.

The remaining difference in financing activities related to the receipt of the pay-off of the balance on the two notes in fiscal 2013 offset by an increase in the regular annual dividend payment rate from $0.72 per share to $0.74 per share.

On March 31, 2014, the Company entered into a new line-of-credit agreement. This new agreement maintains the same terms and rates as provided for under the expired agreement with an increase in the total borrowing limit. The interest rate is based on 30-day LIBOR plus 100 basis points and includes an availability fee of 15 basis points applied to the difference between the face amount of the note and the average outstanding balance during the period. The Company maintained the multi-tiered borrowing limits to accommodate seasonal borrowing demands and minimize overall borrowing costs, with available limits ranging from $1,000,000 to $19,000,000 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, 2015, unless extended. 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.

OFF-BALANCE SHEET ARRANGEMENTS

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

REGULATORY AFFAIRS

On November 1, 2013, the Company placed into effect new base rates, subject to refund, that would provide approximately $1,664,000 in additional annual non-gas revenues. On March 17, 2014, the Company reached a stipulated agreement with the SCC staff that would provide $887,062 in annual non-gas revenues. A hearing was held on March 25, 2014 resulting in the approval of the stipulated agreement. The stipulation provided for a 9.75% authorized return on equity as was previously in place; however, this was below the 10.1% requested by the Company in the rate filing. On May 9, 2014, the SCC issued its final order approving the increase in annual non-gas revenues agreed to in the stipulation. The Company completed its refund of revenues collected in excess of the approved rates plus interest to its customers in the Company’s fiscal third quarter.

In connection with the order approving the non-gas rate award, the SCC also approved a change to the Company’s WNA mechanism. Previously, the WNA provided for a weather band of 3% above or below the 30-year temperature average whereby the Company would recover from its customers the lost margin (excluding gas costs) from the impact of weather that was more than 3% warmer than the 30-year average or refund to customers the excess earned from weather that is more than 3% colder than the 30-year average. The WNA is an important regulatory feature for the Company. As the Company’s non-gas rates are established and approved by the SCC based on the 30-year average temperatures, weather that is warmer than the 30-year average will result in the Company earning less than what they are allowed under the rates, while weather that is colder than the 30-year average will result in the Company earning at a level above what the rates were designed. The weather band reduced the volatility in earnings due to weather by limiting both the upside and the downside to a 3% swing in weather. During the WNA year ended March 31, 2014, the number of heating degree days were more than 10% colder than the 30-year average. As a result, the Company refunded to customers $707,000 in margin for the additional sales resulting from weather that was between 3% and 10% colder than the 30-year average. The Company was able to keep the additional margin earned on weather up to the 3% weather band.

Effective with the WNA period that began April 1, 2014, the SCC removed the 3% weather band. The WNA will

now result in either a recovery or refund of revenues due to any variation from the 30-year average. Although the model to calculate and adjust for the impact of the deviation from the 30-year average has some limitations, it provides the Company with a more predictable utility operating margin that better aligns with the authorized return as provided for in the Company’s utility billing rates. As of September 30, 2014, the Company accrued $144,000 in WNA revenues attributable to weather that had 58 fewer heating degree days than the 30-year average during the first six months of the new WNA period.

On June 4, 2014, the Company filed an application with the SCC requesting approval to extend its authority to incur short-term indebtedness of up to $30,000,000 and to issue up to $60,000,000 in long-term debt securities as part of its long-term financing plan, which included the refinancing of higher interest rate debt and funding for the Company’s pipeline replacement program and other infrastructure projects. On June 25, 2014, the SCC issued an order granting the approval of the Company’s request.

On June 30, 2014, the Company filed an application for modification of the SAVE (Steps to Advance Virginia’s Energy) Plan and Rider. The original SAVE Plan and Rider were approved by the SCC through an order issued on August 29, 2012 and was amended on August 16, 2013. The original SAVE Plan was designed to facilitate the accelerated replacement of the remaining bare steel and cast iron natural gas pipe by providing a mechanism for the Company to recover the related depreciation and expenses and return on rate base of the additional capital investment without the filing of a formal application for an increase in non-gas base rates. With the amendment, the Company added two unique projects; the replacement of the boil-off compressor at the Company’s LNG plant and replacement of the natural gas transfer station located in Gala, VA. The Plan was amended again in June 2014 to increase the expected investment for the continued replacement of the Company’s natural gas distribution pipe and added the investment for the related meter and regulator installations located on customer premises for the 2015 SAVE Plan year. All of these projects included under the SAVE Plan will enhance the safety and reliability of the Company’s gas distribution system. In addition, the recovery of the depreciation and related expenses on these projects through the SAVE Plan rider will allow the Company to forego a formal non-gas rate increase at this time.

The Company’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% to 3.25%. The new rates were implemented retroactive to October 1, 2013.

In 2013, the SCC issued new inspection protocols requiring all meter installations to be inspected once every three years, on a continuous cycle. The Company has implemented the program and the inspection and remediation program is ongoing.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

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

REGULATORY ACCOUNTING – The Company’s regulated operations follow the accounting and reporting requirements of FASB ASC No. 980, “Regulated Operations.” The economic effects of regulation can result in a regulated company deferring

costs that have been or are expected to be recovered from customers in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as assets in the consolidated balance sheet (regulatory assets) and recorded as expenses when such amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for current collection in rates of costs that are expected to be incurred in the future (regulatory liabilities).

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

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

The Company bills its regulated natural gas customers on a monthly cycle. The billing cycle for most customers does not coincide with the accounting periods used for financial reporting. The Company accrues estimated revenue for natural gas delivered to customers but

not yet billed during the accounting period based on weather during the period and current and historical data. The financial statements include unbilled revenue of $1,071,128 and $1,056,253 as of September 30, 2014 and 2013, respectively.

ALLOWANCE FOR DOUBTFUL ACCOUNTS – The Company evaluates the collectability of its accounts receivable balances based upon a variety of factors including loss history, level of delinquent account balances, collections on previously written off accounts and general economic climate.

PENSION AND POSTRETIREMENT BENEFITS – The Company offers a defined benefit pension plan (“pension plan”) and a postretirement medical and life insurance plan (“postretirement plan”) to eligible employees. The expenses and liabilities associated with these plans, as disclosed in Note 6 to the consolidated financial statements, are based on numerous assumptions and factors, including provisions of the plans, employee demographics, contributions made to the plan, return on plan assets and various actuarial calculations, assumptions and accounting requirements. In regard to the pension plan, specific factors include assumptions regarding the discount rate used in

determining future benefit obligations, expected long-term rate of return on plan assets, compensation increases and life expectancies. Similarly, the postretirement medical plan also requires the estimation of many of the same factors as the pension plan in addition to assumptions regarding the rate of medical inflation and Medicare availability. Actual results may differ materially from the results expected from the actuarial assumptions due to changing economic conditions, differences in actual returns on plan assets, different rates of medical inflation, volatility in interest rates and changes in life expectancy. Such differences may result in a material impact on the amount of expense recorded in future periods or the value of the obligations on the balance sheet.

In selecting the discount rate to be used in determining the benefit liability, the Company utilized the Citigroup yield curves which incorporate the rates of return on high-quality, fixed-income investments that corresponded to the length and timing of benefit streams expected under both the pension plan and postretirement plan. The Company used a discount rate of 4.22% and 4.10% for valuing its pension plan liability and postretirement plan liability at September 30, 2014, representing a decrease of 0.60% and 0.63% in their respective rates from the prior year. The decrease in the discount rates corresponded with similar decreases in long-term interest rates. The 30-year Treasury rate decreased from 3.69% to 3.21%. Likewise, the Moody’s Aaa and Moody’s Baa decreased by 0.51% and 0.58%, respectively. The decrease in discount rates for valuing the benefit liabilities nearly reversed the increase in rates experienced in the prior fiscal year. The pension and postretirement plan liability discount rates increased by 0.76% and 0.78% for the September 30, 2013 valuation from those used for the September 30, 2012 valuation. The decrease in the discount rates for both plans resulted in a significant increase in the benefit obligation at September 30, 2014. Both plans experienced better than expected returns on the related pension and postretirement assets, which partially offset the deterioration in the funded status of both plans due to the reduction in the discount rates used to value both plans’ liabilities. As a result of the larger funded deficit, pension and postretirement medical plan expense will increase in fiscal 2015 due to an increase in the amortization of the actuarial loss due to the reduction in the discount rate and an increase in life expectancy assumptions as discussed below. The following tables reflect the funded status of both plans at the corresponding fiscal year ends.

The current economic environment makes it difficult to project interest rates and future investment returns. If the economy improves, long-term interest rates could increase, reducing the benefit liabilities and increasing the investment returns. However, if the economy stagnates or declines, interest rates could remain at these lower levels or even drop, leading to an increase in the benefit liabilities and potential reduction in investment returns. The Company also 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 annual return on pension assets at 7.00% and postretirement assets at 4.90% (net of income taxes) for fiscal 2015. These rates are consistent with the expected long-term rates in place during fiscal 2014.

In August 2014, the Highway and Transportation Funding Act of 2014 (“HATFA”) was signed into law, which included a provision to extend the interest rate corridors introduced in 2012 under the Moving Ahead for Progress in the 21st Century Act (“MAP-21”). MAP-21 provided

temporary funding relief for defined benefit pension plans. The requirements of the Employee Retirement Income Security Act of 1974 (ERISA) and the Pension Protection Act of 2006 (PPA) subject defined benefit plans to minimum funding rules. As a result, when interest rates are low, pension plan liabilities increase thereby resulting in higher mandatory contributions to meet minimum funding obligations. MAP-21 provided funding relief by allowing pension plans to adjust the interest rates used in determining funding requirements so that they are within 10% of the average of interest rates for the 25-year period preceding the current year for funding calculations for 2013 to within 30% for funding periods beginning in 2016. HATFA extended the period of time that the 10% corridor instituted by MAP-21 may be used for funding calculations. Under HATFA, the 10% corridor extends through plan years that begin in 2017 and phases out to a 30% corridor in 2021 and later. HATFA is expected to significantly increase the effective interest rates used in determining funding requirements and could result in a deterioration of the pension plan funded status resulting in much greater funding requirements in the future as well as higher PBGC (Pension Benefit Guaranty Corporation) premiums paid by sponsors of pension plans to protect participants in the event of default by the employer. Management estimates that under the

provisions of HATFA, the Company may have no minimum funding requirements over the next few years. Although HATFA and MAP-21 allow the Company some short-term funding relief, management expects to continue to fund its pension plan at the greater of any minimum pension contribution requirement or its expense level for subsequent years. As a result, the Company expects to contribute approximately $800,000 to its pension plan and $500,000 to its postretirement plan in fiscal 2015. The Company will continue to evaluate its benefit plan funding levels in light of funding requirements and ongoing

investment returns and make adjustments, as necessary, to avoid benefit restrictions.

On October 27, 2014, the Society of Actuaries released the final reports of the pension plan RP-2014 Mortality Tables and the Mortality Improvement Scale MP-2014. The new mortality tables, which will be adopted by the Company for its next pension valuation, extend the assumed life expectancy of participants in defined benefit plans. The estimated impact of the change in assumed mortality would increase the Company’s pension liability by 6% to 8% and increase future pension expense.

DERIVATIVES – The Company may hedge certain risks incurred in its operation through the use of derivative instruments. The Company applies the requirements of FASB ASC No. 815, “Derivatives and Hedging,” which requires the recognition of derivative instruments as assets or liabilities in the Company’s balance sheet at fair value. In most instances, fair value is based upon quoted futures prices for natural gas commodities and interest rate

futures for interest rate swaps. Changes in the commodity and futures markets will impact the estimates of fair value in the future. Furthermore, the actual market value at the point of realization of the derivative may be significantly different from the values used in determining fair value in prior financial statements. The Company had no commodity or interest rate derivatives outstanding at September 30, 2014.

RGC Resources’ common stock is listed on the NASDAQ Global Market under the trading symbol RGCO. Payment of dividends is within the discretion of the Board of Directors and will depend on, among other factors,

earnings, capital requirements, and the operating and financial condition of the Company. The company’s long-term indebtedness contains restrictions on long-term capitalization ratios.