FORWARD LOOKING STATEMENTS

This report contains forward-looking statements that relate to future transactions, events or expectations. In addition, RGC Resources, Inc. (“Resources” or the “Company”) may 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, the following: (i) general economic conditions both locally and nationally; (ii) impact of potential increased regulatory oversight and compliance requirements due to financial, environmental, safety or system integrity laws and regulations; (iii) impact of potential climate change legislation regarding limitations on carbon dioxide emissions; (iv) failure to obtain timely rate relief from regulatory authorities for increased operating or gas costs including a reasonable return on invested capital; (v) the potential loss of large-volume industrial customers to alternative fuels, facility closings or production changes; (vi) ability to attract and retain professional and technical employees to replace an aging workforce; (vii) access to capital markets and the availability of debt and equity financing to support future capital expenditures; (viii) volatility in the price and availability of natural gas, including restrictions on the exploration

and development of natural gas reserves; (ix) changes in accounting regulations and practices, which could change the accounting treatment for certain transactions and increase the cost of compliance; (x) effect of the federal budget deficit and its potential impact on corporate taxes; (xi) effect of weather conditions and natural disasters on production and distribution facilities and the related effect on supply availability and price; (xii) potential effect of health-care legislation on healthcare costs; (xiii) increased customer delinquencies and conservation efforts resulting from difficult economic conditions and/or colder weather; and (xiv) volatility in the actuarially determined benefit costs and asset performance of the Company’s benefit plans. 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 AND ANALYSIS

OVERVIEW

RGC Resources is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately 57,700 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 pipeline integrity of its transmission and distribution pipelines. The Federal Energy Regulatory Commission regulates the 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 SCC authorizes the rates and fees that the Company charges its customers for regulated natural gas service. 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. 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. 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 rate of return for its shareholders. Over the past several years, the Company has implemented certain approved rate mechanisms that reduce some of the volatility in earnings associated with variations in winter weather and the cost of natural gas.

Since 2003, Roanoke Gas has had in place a weather normalization adjustment mechanism (“WNA”) based on a weather measurement band around the most recent 30-year temperature average. Because the SCC authorizes billing rates for the utility operations of Roanoke Gas based on normal weather, warmer than normal weather may result in the Company failing to earn its authorized rate of return. Therefore, the WNA provides the Company with a level of earnings protection when weather is significantly warmer than normal and provides its customers with price protection when the weather is significantly colder than normal. The WNA mechanism provides 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. The total number of heating degree days during both the current and the prior WNA periods fell within the weather band. As a result, the WNA mechanism was not triggered for either period.

The Company also has an approved rate structure in place that mitigates the impact of financing costs of its natural gas inventory. Over the past four years, the commodity price of natural gas has fluctuated significantly from a price of more than $13 a decatherm in July 2008 to around $4 a decatherm in 2011. 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 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 lower inventory balances, the Company recognizes less carrying cost

revenue as financing costs are lower. As a result of the lower commodity price of natural gas, the average price of gas in storage during fiscal 2011 has declined 10% from last year’s levels from $5.75 to $5.16. Correspondingly, carrying cost revenues declined by $151,000 from $1,547,000 in fiscal 2010 to $1,396,000 in fiscal 2011. Carrying cost revenues are expected to be less during the next fiscal year due to lower average price of gas in storage.

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. Due to its strong cash position related to lower gas costs and other factors, the Company has not accessed its line-of-credit facility since early 2009 to finance its natural gas inventory.

The economic environment generally has a direct correlation on business and industrial production,

customer growth and natural gas utilization. The economic downturn that began in 2008 continued into 2011. However, the impact on industrial production in the Company’s service area appears to have stabilized and improved as transportation and industrial gas deliveries increased by 10% in fiscal 2011 compared to a 5% increase in fiscal 2010 and a 12% decline in fiscal 2009. Nevertheless, uncertainty continues to be an issue as three transportation customers have notified the Company of their anticipated reduction in natural gas consumption during the first quarter or portions of the second quarter of fiscal 2012 due to production cutbacks. Currently, the Company does not expect these reductions to have a significant impact on the overall transportation and interruptible sales in fiscal 2012. The economic issues have also directly impacted residential construction with housing starts remaining well below historical levels thereby limiting the opportunity to expand the Company’s customer base. As a result, the Company has increased its total customer count through conversions where homeowners along the Company’s distribution system are electing to convert their heating systems or other appliances to natural gas. The Company has also benefited from the conversion of certain apartment complexes from master meter configurations to individual metered apartments as discussed in further detail below.

Total gas utility operating revenues for the year ended September 30, 2011 (“fiscal 2011”) decreased by 4% from the year ended September 30, 2010 (“fiscal 2010”) even though total delivered volumes increased by 2% over fiscal 2010. The decrease in gas revenues is due to the continued downward trend in gas costs. Natural gas commodity prices were approximately $4 a decatherm as of the end of September 2011. For the year, the average per unit cost of natural gas reflected in cost of sales decreased by 10% compared to last year. Residential and commercial volumes declined by 1% from fiscal 2010 even though total heating degree days increased by 1%. The decline in residential and commercial

volumes resulted from a large commercial customer switching to firm transportation service at the beginning of the year combined with the continuing slow, steady decline in residential usage per customer as a result of installation of more efficient equipment, better insulation of homes and greater customer awareness regarding conservation. Transportation and interruptible volumes increased by 10% mainly due to additional consumption with the balance of the increase attributed to volumes associated with the previously discussed commercial customer switching to firm transportation service. Other revenues declined by 6% due to the decline in certain contract services from last year’s levels.

Gas utility margins increased by 4% primarily due to the implementation of a non-gas base rate increase and the completion of master meter conversion projects during the prior year, which combined to more than offset a reduction in carrying cost revenues. The increase in non-gas billing rates accounted for approximately $800,000 in higher margins with approximately $330,000 attributable to customer base charges, a flat monthly fee billed to each natural gas customer, with the balance related to volumetric sales. The remaining increase in customer base charges was primarily attributable to the conversion of six apartment complexes from a single master meter for each building to individual meters located at each apartment during 2010 and the higher customer fee associated with a customer switching to firm transportation service as discussed above. As a result of the master meter program, the Company added more than 1,000 meters subject to the monthly customer base charge. The balance of the increase in volumetric revenue was attributable to the increase in total delivered volumes. Carrying cost revenues declined by $151,000 due to lower average price of gas in storage combined with lower inventory balances as discussed in more detail above.

Other margins, consisting of non-utility related services, decreased by $102,117 due to a reduction in certain contract services. Some of these non-utility services are subject to annual contract renewals. A significant contract for services is subject to rebidding in 2012. If the Company is unable to retain this contract, other margins would be significantly impacted. The Company intends to provide a competitive bid to retain this contract. The Company anticipates being able to extend or renew the other contracts for 2012; however, any continuation beyond 2012 is uncertain.

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 $308,502, or more than 2%, in fiscal 2011 compared with fiscal 2010 as a result of increases in employee benefit costs, labor and contracted services, partially offset by reductions in bad debt expense and a greater level of capitalized expenses. Employee benefit expenses increased $325,000 due to higher medical insurance premiums and increases in pension and postretirement medical costs attributable to the amortization of larger actuarial losses in fiscal 2011. The Company expects medical insurance, pension costs and postretirement medical costs to increase again in fiscal 2012. Labor and contracted services increased by $257,000 primarily due to brush removal along pipeline right-of-ways, a public awareness campaign to educate local residents and businesses regarding pipeline safety and general cost increases. Bad debt expense declined by $72,000 as total utility revenues decreased by 4% associated with lower gas costs. Low natural gas prices and a continued emphasis on customer delinquencies contributed to the reduction in bad debt expense. The Company capitalized an additional $244,000 in overheads primarily due to increased capital expenditures and higher employee benefit costs. The remaining difference in operation and maintenance expenses resulted from a variety of other minor expense variances.

GENERAL TAXES – General taxes were nearly unchanged as higher property taxes were offset by greater capitalization of payroll taxes.

DEPRECIATION – Depreciation expense increased by $185,784, or 5%, due to a higher natural gas plant investment, primarily the result of completing several distribution pipeline renewal projects.

OTHER INCOME (EXPENSE) – This line item moved from a net other expense to a net other income primarily due to greater investment earnings on higher available cash balances.

INTEREST EXPENSE – Total interest expense for fiscal 2011 remained virtually unchanged from fiscal 2010 as the Company did not access its line-of-credit facility during 2011 or 2010.

INCOME TAXES – Income tax expense increased by $156,110, or 6%, from fiscal 2010 corresponding to a 5% increase in pre-tax earnings. The effective tax rate for fiscal 2011 was 38.0 % compared to 37.7% in fiscal 2010.

NET INCOME AND DIVIDENDS – Income from continuing operations for fiscal 2011 was $4,653,473 compared to $4,445,436 for fiscal 2010. Basic and diluted earnings per share were $1.01 in fiscal 2011 compared to $0.98 in fiscal 2010. Dividends declared per share of common stock were $0.68 in fiscal 2011 and $0.66 in fiscal 2010 as adjusted on a post stock split basis.

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 2,225,000 decatherms per year or approximately one-third of the Company’s total annual purchases. The current agreement expires in October 2013.

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 receivable and payment of dividends. To meet these needs, the Company relies on its operating cash flows, line-of-credit agreement, long-term debt and capital raised through the Company’s Dividend Reinvestment and Stock Purchase Plan (“DRIP”).

Cash and cash equivalents increased by $1,205,799 in fiscal 2011 compared to a $676,730 decrease in fiscal 2010. The following table summarizes the categories of sources and uses of cash:

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, rising customer receivable balances and construction activity.

In fiscal 2011, cash provided by operating activities increased by approximately $3,564,000, from $7,119,000 in fiscal 2010 to $10,683,000 in fiscal 2011.

Cash provided by operations in fiscal 2011 was primarily derived from a combination of net income and depreciation. In addition, the Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010, which was signed into law in December 2010, extended the 50% bonus depreciation that expired December 31, 2009 and provided for 100% bonus depreciation for qualified investments from September 2010 through December 2011. As a result of the Act, the Company’s deferred income tax liability associated with its utility property increased by more than $2,300,000, thereby contributing to the positive operating cash flow. The Company also recorded a net refund of income taxes in the amount of $705,000. The Company has more than $12,000,000 in deferred tax liabilities related to accelerated and bonus depreciation on its utility plant that will begin to reverse at some point in the future resulting in additional cash outflows. The commodity price of natural gas remained stable during fiscal 2011; however, the price of natural gas in storage declined from $5.26 per decatherm at

September 30, 2010 to $4.92 per decatherm at September 30, 2011 resulting in approximately a $920,000 decline in gas in storage. In fiscal 2011, the Company utilized operating cash to refund $2,300,000 in prior year over-collections balance. Fiscal 2010 had less cash generated from operating activities primarily due to the level of refunding of over-collected balances and customer credit balances compared to fiscal 2011.

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 and expansion of its natural gas system to meet the demands of customer growth. Cash flows used in investing activities increased by approximately $1,615,000 due to higher capital expenditures. Total capital expenditures were approximately $7,589,000 and $5,974,000 for the years ended September 30, 2011 and 2010, respectively. The ongoing economic climate has continued to limit system expansion and customer growth. With limited new business opportunities and a strong cash position, the Company placed an increased emphasis on its pipeline renewal program in fiscal 2011. The Company renewed 8.9 miles of bare steel and cast iron natural gas distribution main and replaced 720 services in fiscal 2011 compared to 6.4 miles of gas main and 420 services replaced in fiscal 2010. There are approximately 60 miles

of cast iron and bare steel pipe remaining to be replaced. The Company plans to continue its focus on pipeline renewals in 2012 and expects such expenditures to continue at comparable or higher levels as it anticipates completing the replacement of the remaining cast iron and bare steel pipe within the next 10 years. Depreciation provided 55% of the current year’s capital expenditures compared to 66% for the prior year. With future capital expenditures expected to remain at or near these levels, the balance of the funding will come from net income, available cash and corporate borrowing activity.

Financing activities generally consist of long-term and short-term borrowings and repayments, issuance of stock and the payment of dividends. As discussed above, the Company uses its line-of-credit arrangement to fund seasonal working capital needs as well as provide temporary financing for capital projects as needed. During fiscal 2011 and 2010, the Company did not access its line-of-credit because of its strong cash position primarily attributable to low natural gas prices. Cash flows used in financing activities were $1,888,000, composed of approximately $1,119,000 of proceeds related to stock issuances, $87,000 receipt on the note with ANGD, LLC and approximately $3,094,000 in dividends paid.

On March 14, 2011, the Company renewed its line-of-credit agreement. The new agreement maintained the same terms and rates as provided for under the expired agreement. The interest rate is based on 30-day LIBOR plus 100 basis points and includes an availability fee of 15 basis points applied to the difference between the face amount of the note and the average outstanding balance during the period. The Company maintained the multi-tiered borrowing limits to accommodate seasonal borrowing demands and minimize overall borrowing costs. Under the new agreement, total available limits during its term were reduced from the prior agreement due to the expected reduced funding requirements. The new agreement provides for available limits ranging from $1,000,000 to $5,000,000. The line-of-credit agreement will expire March 31, 2012, 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.

On October 20, 2010, the Company executed a modification to its $15,000,000 unsecured variable rate note with the current lender under the same terms and covenants providing for the extension of the maturity date until March 31, 2012 to coincide with the expiration of the Company’s line-of-credit agreement. Due to the economic climate and its effect on the credit markets and credit spreads, the Company was unable to extend the note at this time beyond the current 16-month extension without incurring a higher interest rate than is currently in place. The Company anticipates being able to extend this note prior to its maturity on a yearly basis under comparable terms to those currently in place until such time the corresponding swap on the note matures on December 1, 2015.

As mentioned above, the Company has not accessed its line-of-credit facility during the last two years and has been able to finance operations with its operating cash flow. The key factor behind the improved cash position of the Company is the reduction in the commodity price of natural gas from more than $13 in 2008 to under $4 in 2011. As a result of the lower commodity price of gas, the average balance of gas in storage declined from $18,300,000 in fiscal 2008 to $10,000,000 during fiscal 2011. Likewise, the average balance in accounts receivable experienced a similar decline from an average balance during fiscal 2008 of $9,300,000 to $6,900,000 in fiscal 2011. If natural gas prices remain at the levels experienced in fiscal 2011, the Company anticipates that it will be able to finance its operations, including its pipeline renewal program, over the next few years with its operating cash flows and line-of-credit.

The Company’s consolidated long-term capitalization, including current maturities, was 64% equity and 36% debt at September 30, 2011 and 62% equity and 38% debt at September 30, 2010.

REGULATORY AFFAIRS

On November 1, 2010, Roanoke Gas Company placed into effect new base rates, subject to refund, that provided for approximately $1,400,000 in additional annual non-gas revenues. On April 6, 2011, the SCC issued a final order granting the Company a rate award in the amount of $814,000 in additional non-gas revenues.

In June 2011, the Company completed its refund for the difference between the rates placed into effect on November 1 and the final rates approved in the Commission order.

On September 15, 2011, the Company filed a request for an expedited increase in rates with the SCC. The request was for an increase of approximately $1,100,000 in annual non-gas revenues. As provided for under this expedited rate request, the Company was able to place the increased rates into effect for service rendered on and after November 1, 2011, subject to refund pending a final order by the SCC. The public hearing on the request for this rate increase is scheduled for March 27, 2012, with a final order expected some time after that date.

During 2011, the Company completed its Distribution Integrity Management Plan (“DIMP”) as required by federal regulations issued by the Pipeline and Hazardous Materials Safety Administration (PHMSA). Under these regulations, distribution operators are required to develop and implement a written DIMP plan that includes the following elements: (i) an operator must demonstrate an understanding of the gas distribution system, (ii) an operator must define the potential threats to the gas distribution pipeline and determine the relative probability of each threat (a risk based approach), (iii) an operator must determine and implement measures designed to reduce the risks of failure of its gas distribution system, (iv) an operator must develop and monitor performance measures to evaluate the effectiveness of its plan, and (v) an operator must continually re-evaluate threats and risks on its entire system and update its plan as necessary.

The Company has been proactive in the area of pipeline safety well before the DIMP regulations. Over the past 20 years, the Company has replaced much of its cast iron and bare steel pipe. As all of this pipe has been underground for well over 40 years, the leak potential from such pipe is much higher than the plastic or coated steel pipe currently being installed. The Company prioritized its replacement program using a risk based evaluation that included leak history, population density and other factors. During this time period the Company has replaced approximately 135 miles of bare steel and cast iron distribution main. The Company expects to replace the remaining 60 miles of pipe within the next 10 years.

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 it 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 statement 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 increase 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 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 $1,088,611 and $1,070,062 as of September 30, 2011 and 2010.

ALLOWANCE FOR DOUBTFUL ACCOUNTS – The Company evaluates the collectibility 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 7 to the consolidated financial statements, are based on numerous assumptions and factors, including provisions of the plans, employee demographics, contributions made to

the plan, return on plan assets and various actuarial calculations, assumptions and accounting requirements. In regard to the pension plan, specific factors include assumptions regarding the discount rate used in determining future benefit obligations, expected long-term rate of return on plan assets, compensation increases and life expectancies. Similarly, the postretirement medical plan also requires the estimation of many of the same factors as the pension plan in addition to assumptions regarding the rate of medical inflation and Medicare availability. Actual results may differ materially from the results expected from the actuarial assumptions due to changing economic conditions, 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 evaluated the IRS yield curves and the Citigroup yield curves which incorporates 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 5.04% and 4.96% for valuing its pension benefit liability and postretirement plan liability at September 30, 2011, representing a decrease of 0.21% and 0.04% in the respective discount rates from the prior year. The decrease in the discount rates combined with lower asset balances at September 30, 2011, due to a significant decline in the equity markets, were the primary factors in the overall increase in the benefit plan liabilities on the balance sheet and increase in expense in fiscal 2012. The Company also used an asset/liability model to evaluate the probability of meeting 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 for an assumed long-term rate of return of 7.25% on the pension plan and a targeted allocation of 50% equity and 50% fixed income for an assumed long-term rate of return of 5.09% (net of income taxes) for the postretirement plan. Based on the assumptions

described above and in Note 7, pension expense is expected to increase from approximately $787,000 in fiscal 2011 to $991,000 in fiscal 2012 and postretirement expense is expected to rise from approximately $808,000 in fiscal 2011 to $849,000 in fiscal 2012. The Company expects to contribute approximately $1,000,000 to its pension plan and $850,000 to its postretirement plan in fiscal 2012. Funding levels are expected to remain at this level or higher over the next several years. The Company anticipates being able to meet the funding needs of these plans and recover benefit plan expenses through its non-gas rates. The Company will continue to evaluate its benefit plan funding levels in light of the requirements under the Pension Protection Act of 2006 and ongoing investment returns and make adjustments as necessary to avoid benefit restrictions and to manage the cost of the benefit plans.

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.

MARKET RISK

The Company is exposed to market risks through its natural gas operations associated with commodity prices. The Company’s hedging and derivatives policy, as authorized by the Company’s Board of Directors, allows management to enter into both physical and financial transactions for the purpose of managing commodity risk of its business operations. The policy also specifies that the combination of all commodity hedging contracts

for any 12-month period shall not exceed a total hedged volume of 90% of projected volumes. Finally, the policy specifically prohibits the utilization of derivatives for the purposes of speculation.

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

At September 30, 2011, the Company had no outstanding derivative instruments to hedge the price of natural gas. The Company had approximately 2,622,000 decatherms of gas in storage, including LNG, at an average price of $4.92 per decatherm compared to 2,626,000 decatherms at an average price of $5.26 per decatherm last year. In addition to the gas in storage, the Company had collar agreements outstanding at September 30, 2010 for the purpose of hedging the price of natural gas for 1,300,000 decatherms. 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.

The Company also has a variable rate line-of-credit with a bank with the interest rate based on the London Interbank Offered Rate (“LIBOR”). As of September 30, 2011, the Company had no outstanding balance under its line-of-credit.

OTHER RISKS

The Company is exposed to risks other than commodity and interest rates. Such events, situations or conditions have or potentially could have an impact on the future results of operations of the Company. For most of the items described below, Roanoke Gas has a means to recover increased costs through formal rate application filings, as well as the ability to pass along increases in natural gas costs.

REGULATORY AND GOVERNMENTAL ACTIONS – As discussed above, Virginia has a means to allow the regulated operations of the Company to recover increased costs and earn a reasonable rate of return on equity. The SCC is the state agency responsible for regulating the operations of Roanoke Gas and approves the rates charged to its customers. If the SCC were to impose limitations that delayed or prohibited the Company from placing rates into effect to timely recover costs and earn its authorized rate of return, the earnings of the Company could be negatively impacted. Furthermore, legislation at the state or federal level could result in increased costs and place additional burdens on the Company.

ENVIRONMENTAL LEGISLATION – The passage of environmental legislation that mandates reductions in carbon emissions or other similar restrictions could have a negative effect on the Company over the long-term as it relates to the Company’s core operations. Natural gas is a clean and efficient energy source; however, the combustion of natural gas results in carbon related emissions. The extent to which carbon emissions would be restricted under any such legislation and the ability of technological improvements to minimize such emissions would be critical in determining any potential impact to the Company.

In 2009, the U. S. House of Representatives approved H.R. 2454, “The American Clean Energy and Security Act of 2009”, referred to as the Waxman-Markey Climate Change Bill. A companion bill, “The American Power Act”, referred to as the Kerry-Lieberman Bill, was introduced in the U. S. Senate in 2010, but was not approved. Both bills were designed to reduce the level of carbon dioxide emissions from burning fossil fuels such as coal, oil and natural gas. Limits on carbon emissions could lead to a gradual reduction in the use of fossil fuels, including natural gas, in the U. S. economy. A federally mandated reduction in natural gas consumption would likely negatively impact Company operations if legislation does not adequately reflect the lower emissions generated by natural gas consumption. The election held on November 2, 2010 materially changed the makeup of the U. S. House of Representatives and U. S. Senate, lessening the likelihood of passage of carbon emissions reduction legislation by the current Congress. Nevertheless, carbon emissions legislation could be reintroduced in the future. The Company will continue to monitor legislative activity and evaluate any potential impact.

ENERGY PRICES AND INFLATION – Energy costs represent the single largest expense of the Company with the cost of natural gas representing approximately 71% and 73% for fiscal 2011 and 2010 of the total operating expenses of the Company’s natural gas utility operations. Increases or decreases in natural gas costs are passed through to customers under the present PGA mechanism. The Company may adjust its gas cost billing rate quarterly through the PGA with administrative approval from the SCC. Increases in the commodity price of natural gas may cause existing customers to conserve, switch to alternate sources of energy or be unable to pay their natural gas bills. On the other side, declining natural gas prices reduce the level of inventory carrying cost revenues that the Company realizes.

Rising costs affect the Company through increases in non-gas costs such as property and liability insurance, labor costs, employee benefits, supplies, contracted services and the replacement cost of plant and equipment. The rates charged to natural gas customers to cover these costs may only be increased through the regulatory process with a non-gas cost rate increase application. Because of the inherent lag in the rate application process for increases in the non-gas cost

portion of rates, approved Company billing rates may not fully keep pace with costs during high inflationary periods; however, timely non-gas rate filings should allow the Company to cover its reasonable and expected costs. Management must continually review operations and economic conditions to assess the need for filing and receiving adequate and timely rate relief from the SCC.

PIPELINE RELIABILITY – Roanoke Gas is served directly by two primary pipelines. These two pipelines provide 100% of the natural gas supplied to the Company’s customers. Depending upon weather conditions and the level of customer demand, failure of one or both of these transmission pipelines could have a major adverse impact on the Company.

CUSTOMER CREDIT – Gas costs represent a major portion of the total customer bill. The Company has worked diligently at minimizing bad debts and bad debt write offs. However, significant increases or spikes in natural gas prices could result in an increased rate of delinquencies as customers face higher natural gas bills as well as other higher energy costs. Furthermore, adverse economic conditions and rising unemployment could also lead to an increase in delinquency of customer payments and higher bad debts. In addition, the SCC has specific notice requirements that the Company must first comply with before disconnecting natural gas service for customer nonpayment. The Company has benefited from declining natural gas prices as reflected in the low bad debt expense during the last few years.

WEATHER – The nature of the Company’s business is highly dependent upon weather – specifically, winter weather. Cold weather increases energy consumption by customers and therefore increases revenues and margins. Conversely, warm weather reduces energy consumption and ultimately revenues and margins. Roanoke Gas Company’s rate structure has a weather normalization adjustment factor that operates around a weather band of approximately 3% above and below the 30-year average for heating degree-days. This weather band significantly reduces the exposure to weather risk by limiting the impact of warmer than normal weather to no more than 3% from the 30-year average. Conversely, the protection provided by the weather band to the downside risk also limits the upside potential from colder than normal weather by the same 3%.

CREDIT AND CAPITAL AVAILABILITY – The capital intensive and seasonal nature of the utility operations requires the access to sufficient levels of debt and equity capital. The ongoing economic issues on the local and national levels have impacted the cost and availability of short-term and long-term credit funding. The inability to obtain funding when needed, or obtain funding only on less than favorable terms, could have a significant negative impact to the Company.