Officers

John B. Williamson, III

Chairman of the Board, President and

Chief Executive Officer ^(1)(2)(3)(4)

John S. D’Orazio

Vice President and

Chief Operating Officer ^(2)(3)(4)

Howard T. Lyon

Vice President, Treasurer and

Chief Financial Officer ^(1)(2)(3)(4)

Dale P. Lee

Vice President and

Secretary ^(1)(2)(3)(4)

Robert L. Wells, II

Vice President,

Information Technology,

Assistant Secretary and

Assistant Treasurer ^(1)(2)(3)(4)

Directors

Nancy Howell Agee

President and

Chief Operating Officer

Carilion Clinic

Director: ⁽¹⁾⁽²⁾

Abney S. Boxley, III

President and

Chief Executive Officer

Boxley Materials Company

Director: ⁽¹⁾

Frank T. Ellett

President

Virginia Truck Center, Inc.

Director: ⁽¹⁾⁽²⁾

Maryellen F. Goodlatte

Attorney and Principal

Glenn Feldmann Darby & Goodlatte

Director: ⁽¹⁾⁽²⁾

J. Allen Layman

Private Investor

Director: ⁽¹⁾⁽²⁾

George W. Logan

Chairman of the Board

Valley Financial Corporation

Principal

Pine Street Partners

Faculty

University of Virginia

Darden Graduate School of Business

Director: ⁽¹⁾⁽²⁾

S. Frank Smith

Vice President Industrial Sales

Alpha Coal Sales Company, LLC

Director: ⁽¹⁾⁽²⁾

Raymond D. Smoot, Jr.

Chief Executive Officer and

Secretary-Treasurer

Virginia Tech Foundation, Inc.

Director: ⁽¹⁾

John B. Williamson, III

Chairman of the Board, President and

Chief Executive Officer

Director: ^(1)(2)(3)(4)

Subsidiary Boards of Directors

John S. D’Orazio

Vice President and

Chief Operating Officer

Roanoke Gas Company

Director: ⁽³⁾⁽⁴⁾

Howard T. Lyon

Vice President, Treasurer and

Chief Financial Officer

RGC Resources, Inc.

Director: ⁽³⁾⁽⁴⁾

Dale P. Lee

Vice President and Secretary

RGC Resources, Inc.

Director: ⁽³⁾⁽⁴⁾

Robert L. Wells, II

Vice President,

Information Technology,

Assistant Secretary and

Assistant Treasurer

RGC Resources, Inc.

Director: ⁽³⁾⁽⁴⁾

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 other 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) failure to earn on a consistent basis an adequate return on invested capital; (ii) ability to retain and attract professional and technical employees; (iii) the potential loss of large-volume industrial customers to alternate fuels, facility closings or production changes; (iv) volatility in the price and availability of natural gas; (v) uncertainty in the demand for natural gas in the Company’s service area; (vi) general economic conditions both locally and nationally; (vii) increases in interest rates; (viii) increased customer delinquencies and conservation efforts resulting from high fuel costs, difficult economic conditions and/or colder weather; (ix) variations in winter heating degree-days from the 30-year average on which the Company’s billing rates are set; (x) impact of potential climate change legislation regarding limitations on carbon dioxide emissions; (xi) impact of potential increased regulatory oversight and compliance requirements due to financial, environmental, safety and system integrity laws and regulations; (xii) failure to obtain timely rate relief from regulatory authorities for increasing operating or gas costs; (xiii) access to capital markets and the availability of debt and equity financing to support capital expenditures; (xiv) impact of potential increases in corporate income tax rates and other taxes; (xv) volatility in actuarially

determined benefit costs and plan asset performance; (xvi) effect of weather conditions and natural disasters on production and distribution facilities and the related effect on supply availability and price; (xvii) potential effect of health-care legislation on health-care costs; and (xviii) changes in accounting regulations and practices, which could change the accounting treatment for certain transactions. 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 57,000 residential, commercial and industrial customers in Roanoke, Virginia and the surrounding areas through its Roanoke Gas Company (“Roanoke Gas”) subsidiary. The utility operations of Roanoke Gas are regulated by the Virginia State Corporation Commission (“SCC” or “Virginia Commission”). Natural gas service is provided at rates and for the terms and conditions approved by the SCC.

Resources also provides certain unregulated natural gas related services through Roanoke Gas and information system services through RGC Ventures of Virginia, Inc., which operates as Application Resources. The unregulated operations represent less than 3% of revenues and margins of Resources.

Economic conditions, winter weather conditions and natural gas prices all have a direct influence on the quantity of natural gas deliveries, and management believes each factor has the potential to significantly impact earnings.

The economic environment generally has a direct correlation on business and industrial production and natural gas utilization. The economic downturn that began prior to last year has continued through 2010. However, the impact on industrial production in the Company’s service area appears to have stabilized as transportation and industrial gas deliveries increased by 5% in fiscal 2010 compared to a 12% decline during the prior year. Although industrial activity has shown some improvement, significant growth in the

economy has yet to materialize and customer growth has been stagnant as new construction has been very limited.

Natural gas prices continued their downward trend that began after the sharp run-up in prices in July 2008. Since the peak of more than $13.00 per decatherm, the price of natural gas has declined to below $4.00 per decatherm at the end of September 30, 2010. Natural gas prices are the lowest the Company has experienced in recent years, which have contributed significantly to the Company’s continuing low bad debt expense and make natural gas an attractive low cost fuel source. Currently, futures prices for natural gas on the NYMEX (New York Mercantile Exchange) do not exceed $5.00 per decatherm over the next 12 months, implying relative stability in prices for 2011.

A majority of natural gas sales are for space heating during the winter season. Consequently, during warmer winters or unevenly cold winters, customers may significantly reduce their consumption of natural gas. The effect of warmer than normal winters is mitigated by a weather normalization adjustment (“WNA”) factor as discussed below.

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. The Company has been able to mitigate a significant portion of the risk associated with warmer than normal winter weather by the inclusion of a WNA factor as part of its rate structure. This factor allows the Company to recover revenues equivalent to the margin that would be realized at approximately

3% warmer than the most recent 30-year temperature average for the Company’s service area or refund revenues for any margin realized for weather greater than approximately 3% colder than the 30-year average. The measurement period for determining the weather band extends from April through March with any adjustment made to customer bills in late spring. For the WNA periods ending March 31, 2010 and 2009, the Company did not record a WNA adjustment as the number of heating degree-days fell within the weather band during the measurement period.

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 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 inventory costs and lower inventory balances, the Company recognizes less carrying cost revenue as financing costs are lower. The Company recognized approximately $1,547,000 and $2,328,000 in carrying cost revenues for the years

ended September 30, 2010 and 2009, respectively. Carrying cost revenues for fiscal 2010 declined by 34% due to the much lower average price of natural gas in storage during the year ended September 30, 2010 compared to September 30, 2009 ($5.75 per decatherm compared to $8.31 per decatherm) and an average of 7% fewer decatherms in storage during those periods. The decline in net income in 2010 from the prior year was primarily the result of a reduction in carrying cost revenues. Carrying cost revenues for fiscal 2011 are expected to be lower than fiscal 2010 as the average price of gas in storage is projected to decrease as a result of lower natural gas prices.

In the short run, as investment in natural gas inventories increases so does the level of borrowing under the Company’s line-of-credit. However, as the factor used in determining the carrying cost revenues is based on the Company’s weighted average cost of capital, carrying cost revenues do not directly correspond with the short-term incremental 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. The inverse occurs when inventory costs increase. Due to a strong cash position, the Company did not access its line-of-credit during the fiscal year ended September 30, 2010.

Total gas utility operating revenues for the year ended September 30, 2010 (“fiscal 2010”) decreased by 10% from the year ended September 30, 2009 (“fiscal 2009”) even though total delivered volumes increased by 1% over fiscal 2009. The decrease in gas revenues is due to the continued reduction in gas costs that began two years ago when natural gas prices peaked at more than $13 a decatherm. Natural gas commodity prices have fallen below $4 a decatherm as of the end of September 2010. For the year, the average per unit cost of natural gas reflected in cost of sales decreased by 13%. Total natural gas volumes were nearly unchanged from the prior year

as residential and commercial volumes reflected a 1% decline from fiscal 2009 even though total heating degree days increased by 3%. Approximately half of the decline resulted from a large commercial customer switching to transportation service. Transportation and interruptible sales increased by 5% as economic and production activities appear to have stabilized following last year’s 12% decline combined with the aforementioned commercial customer switching to transportation service.

Other revenues were nearly unchanged.

Gas utility margins decreased by 2% primarily due to declining carrying cost revenues attributable to lower gas costs as discussed above. Volumetric margin declined slightly due to a reduction in the higher margin residential and commercial sales volumes. These declines were partially offset by an increase in customer base charges, the flat monthly fee billed to each natural gas customer, the result of a combination of master meter conversions and increased demand fees related to two customers moving to industrial firm transportation service during the year. The Company converted six apartment complexes from a single master meter for each building to individual meters located at each apartment. This increase in the number of meters generated additional monthly base charge fees. As a result of the move of two customers to industrial firm transportation service, a shift in revenue occurred with volumetric revenues decreasing due to the lower transportation rate while the customer base charge, or demand fee, increased.

Other margins, consisting of non-utility related services, remained nearly unchanged as the margin increased by $5,388. Some of these non-utility services are subject to annual contract renewals. The loss of one or more of these contracts could have a

significant impact on other revenues and margins. The Company anticipates being able to extend or renew the major contracts for 2011; however, any continuation beyond 2011 is uncertain.

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

NET UTILITY MARGIN DECREASE

Other Operating Expenses – Operations expenses increased $368,943, or 3%, in fiscal 2010 compared with fiscal 2009 as a result of increases in employee benefit costs, partially offset by reductions in bad debt expense and a greater level of capitalized expenses. Employee benefit expenses increased due to a $190,000 increase in medical insurance premiums and a $300,000 increase in pension costs attributable to the amortization of a larger actuarial loss in fiscal 2010. The Company expects medical insurance and

pension costs to increase again in fiscal 2011. Bad debt expense declined by $63,000 as total utility revenues decreased by 10%. Even though the economic downturn that began in late 2008 continued to have an impact in the Company’s service territory, lower natural gas prices and a continued focus on customer delinquencies contributed to the decline in bad debt expense. The Company capitalized an additional $40,000 in overheads primarily due to higher employee benefit costs. The remaining difference in other operating expenses resulted from a variety of other minor expense variances.

Maintenance expenses decreased by $346,242, or 20%, due to the timing of pipeline leak repairs on the Company’s distribution system and transmission pipeline right-of-way clearing in addition to fewer facility maintenance projects performed during fiscal 2010.

General taxes increased $46,384, or 4%, in fiscal 2010 compared to fiscal 2009 due to higher property taxes on a greater level of taxable property.

Depreciation expense increased by $157,599, or 4%, due to a higher natural gas plant investment, primarily the result of completing several master meter conversion and distribution pipeline renewal projects.

Other Expense – Other expense decreased by $59,638 due to a reduction in the level of charitable giving. Fiscal 2009 included one-time commitments to specific charitable projects.

Interest Expense – Total interest expense for fiscal 2010 decreased by $82,815, or 4%, from fiscal 2009, as the Company did not access its line-of-credit facility during 2010.

Income Taxes – Income tax expense decreased $296,308, or 10%, from fiscal 2009 corresponding to a 9% decrease in pre-tax earnings. The effective tax rate for fiscal 2010 was 37.7% compared to 38.0% in fiscal 2009.

Net Income and Dividends – Income from continuing operations for fiscal 2010 was $4,445,436 compared to $4,869,010 for fiscal 2009. Basic and diluted earnings per share were $1.97 and $1.96 in fiscal 2010 compared to $2.19 and $2.18 in fiscal 2009. Dividends declared per share of common stock were $1.32 in fiscal 2010 and $1.28 in fiscal 2009.

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. In September 2010, Roanoke Gas executed a new three-year agreement with the incumbent asset manager to continue to provide the same services including the payment of the monthly utilization fee.

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 decreased by $676,730 in fiscal 2010 compared to a $6,546,924 increase in fiscal 2009. 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 increases in natural gas storage levels, rising customer receivable balances and construction activity. In fiscal 2010, cash

provided by continuing operating activities decreased by approximately $15,587,000, from $22,706,000 in fiscal 2009 to $7,119,000 in fiscal 2010. Fiscal 2009 had significantly higher cash generated from operating activities primarily due to an increase in over-collection of gas costs combined with reductions in gas in storage and accounts receivable all resulting from significant declines in the commodity price of natural gas. Cash provided by operations in fiscal 2010 was derived from a combination of net income and depreciation. The commodity price of natural gas continued its decline in 2010 leading to further reductions in gas in storage, accounts receivable and accounts payable. As a result of the declining price of natural gas, the average price of natural gas in storage declined from $9.81 per decatherm at September 30, 2008, to $6.05 at September 30, 2009, to $5.26 at September 30, 2010. The Company also began refunding the prior over-collection of gas costs in January 2010 resulting in a nearly $3,000,000 net refund to its customers during fiscal 2010. Furthermore, the extension of bonus depreciation for tax purposes contributed to the positive operating cash flow as the Company’s deferred tax liability continued to increase. The Company has more than $10,000,000 in deferred tax liabilities related to accelerated and bonus depreciation on its utility plant. Over the next few years, the Company expects these liabilities to begin to reverse resulting in additional cash outflows for income taxes.

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 $738,000 due to higher capital expenditures and $500,000 proceeds from the sale of a short-term investment in fiscal 2009. Total capital expenditures from continuing operations were approximately $5,974,000 and $5,753,000 for the years ended September 30, 2010 and 2009, respectively. The ongoing depressed economic environment has continued to limit system expansion and customer growth with much of the capital expenditures related to pipeline and facilities replacement. The Company continued its pipeline renewal program with 6.4 miles of natural gas distribution main replaced and 420 services renewed in fiscal 2010 compared to 5.6 miles of main and 684 services in fiscal 2009. There are approximately 66 miles of cast iron and bare steel pipe remaining to be replaced. The Company plans to continue its focus on pipeline renewals in 2011 and expects such expenditures to continue at comparable or higher levels for the next several years. Operating cash flow provided by depreciation contributed approximately $3,960,000 and $3,815,000 in support of fiscal 2010 and 2009 capital expenditures, or approximately 66% of the total investment during both years. The Company also relies on its line-of-credit agreement, other operating cash flows and long-term debt financing to provide the balance of the underlying funding for its capital expenditures.

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. During fiscal 2010, the Company did not access its line-of-credit because of its strong cash

position due to declining natural gas prices. Cash flow used in financing activities declined $9,102,000, from $10,934,000 in fiscal 2009 to $1,832,000 in fiscal 2010. The primary factor in the reduction in cash used for financing activities is attributable to the net pay down in the Company’s line-of-credit balance in fiscal 2009. The Company entered into a $5,000,000 variable rate note in October 2008 and used the proceeds to refinance a portion of the line-of-credit balance that provided temporary funding for the retirement of a $5,000,000 first mortgage note which had matured in July 2008.

On March 29, 2010 the Company renewed its line-of-credit agreement for Roanoke Gas. The new agreement maintained the same terms and rates as provided for under the expiring 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 the overall borrowing costs. Under the new agreement, the Company’s total available limits during its term range from $1,000,000 to $13,000,000. The line-of-credit agreement will expire March 31, 2011, 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 on terms comparable to those currently in place.

The Company’s $15,000,000 unsecured variable rate note was scheduled to mature December 1, 2010. On October 20, 2010, the Company executed

a modification of the note with the current lender under the same terms and covenants providing for the extension of the maturity date until March 31, 2012. Due to the current 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 currently in place until such time the corresponding swap on the note matures on December 1, 2015.

The remainder of the financing cash flows was associated with approximately $1,032,000 of proceeds related to stock issuances, $87,000 receipt on the note with ANGD, LLC and approximately $2,950,000 in dividends paid.

As the commodity price of natural gas appears to have stabilized after a two year decline, the pipeline renewal program continues and the refunding of the prior year gas cost over-collection is completed, the Company’s cash position will return to a pattern more consistent with historical norms, which includes seasonal borrowing under the Company’s line-of-credit arrangement. If natural gas prices continue to remain at their current low levels, short-term borrowing needs will be limited. If inflationary pressures, increasing demand or supply issues begin to elevate the price of natural gas, the Company will be much more dependent on the seasonal funding provided by its line-of-credit to support the Company’s operations.

The Company expects that cash provided by operations combined with its line-of-credit will be sufficient to meet operating and projected capital expenditure requirements and to pay shareholder dividends for 2011 and the foreseeable future.

At September 30, 2010 and 2009, the Company’s consolidated long-term capitalization was 62% equity and 38% debt.

REGULATORY AFFAIRS

On September 13, 2010, the Company filed a request for an expedited increase in rates with the SCC. The request was for an increase of approximately $1,400,000 in annual non-gas revenues. As allowed under Virginia law for an expedited rate request, the Company placed the increased rates into effect for service rendered on and after November 1, 2010, subject to refund pending a final order by the SCC. The public hearing on the request for this rate increase is scheduled for March 24, 2011, with a final order expected some time after that date.

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 are adjusted quarterly through the purchased gas adjustment (“PGA”) mechanism with administrative approval from the SCC.

The Company bills its regulated natural gas customers on a monthly cycle. The billing cycle for most customers does not coincide with the accounting periods used for financial reporting. The Company accrues estimated revenue for natural gas delivered to customers not yet billed during the accounting period. Determination of unbilled revenue relies on the use of estimates, weather during the period and current and historical data. The financial statements included unbilled revenue of $1,070,062 and $1,173,561 as of September 30, 2010 and 2009.

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 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, 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 considered 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 5.25% and 5.00% for valuing its pension benefit liability and postretirement plan liability at September 30, 2010, representing a decrease of 0.25% and 0.50% in the respective discount rates from the prior year. The Company based the discount rate assumption on high-quality fixed-income investments with maturity schedules spanning the expected payment stream of the benefits. The decrease in the discount rates was a primary factor in the overall increase in the benefit plan liabilities on the balance sheet and increase in expense in fiscal 2011. 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 5.14% (net of income taxes) for the postretirement plan. Based on the assumptions described above and in Note 6, pension expense is expected to increase from approximately $759,000 in fiscal 2010 to $787,000 in fiscal 2011 and postretirement expense is expected to rise from approximately $606,000 in fiscal 2010 to $808,000 in fiscal 2011. The Company expects to contribute approximately $1,000,000 to its pension plan and $700,000 to its postretirement plan in fiscal 2011. 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.

As of September 30, 2010, the Company has collar agreements outstanding for the purpose of hedging the price of natural gas during the winter period for 1,300,000 decatherms. In addition, the Company also has approximately 2,626,000 decatherms of gas in storage at an average price of $5.26 per decatherm. 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 will be 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, 2010, 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 cost.

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”, sometimes referred to as the Waxman-Markey Climate Change Bill. A companion bill, “The American Power Act”, sometimes referred to as the Kerry-Lieberman Bill, was introduced in the U. S. Senate in 2010, but was not approved. Both bills are 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 in 2011 or 2012.

Energy Prices and Inflation – Energy costs represent the single largest expense of the Company with the cost of natural gas representing approximately 73% and 76% for fiscal 2010 and 2009 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. As discussed above, 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 through 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 keep pace with costs during inflationary periods. 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. Although the depressed economic environment that began prior to last year has continued through fiscal 2010, bad debts have remained at lower levels due to the continuing decline in the commodity price of natural gas.

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.