Edgar Filing: RGC RESOURCES INC

2004 Annual Report to Shareholders

Exhibit 13

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RGC RESOURCES PROVIDES SUPERIOR CUSTOMER AND SHAREHOLDER VALUE AS A PREFERRED PROVIDER OF ENERGY AND DIVERSIFIED PRODUCTS AND SERVICES IN ITS SELECTED MARKET AREAS.

Virginia is one of the top apple-producing states in the nation, growing 11 varieties throughout the region.

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FINANCIAL HIGHLIGHTS


Years Ended September 30,	2004			2003		2002
Operating Revenue - Natural Gas	$	83,703,964		$	75,321,337	$	57,647,947
Energy Marketing Revenue	$	18,810,525		$	13,091,137	$	11,107,532
Other Revenue	$	632,575		$	421,479	$	555,639
Net Income - Continuing Operations	$	2,066,802		$	1,998,779	$	1,936,156
Net Income - Discontinued Operations	$	10,867,211		$	1,529,610	$	550,739
Basic Earnings Per Share - Continuing Operations	$	1.02		$	1.01	$	1.00
Basic Earnings Per Share - Discontinued Operations	$	5.36	*	$	0.77	$	0.28
Regular Dividend Per Share - Cash	$	1.17		$	1.14	$	1.14
Number of Customers - Natural Gas		58,081			57,691		57,229
Total Natural Gas Deliveries - DTH		11,903,920			12,041,193		10,563,514
Total Additions to plant	$	7,925,948		$	6,774,991	$	6,581,060

*	Reflects $4.69 gain on sale of assets.

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TO OUR SHAREHOLDERS

We took advantage of that convergence of forces to secure what we believe was the maximum potential value for our propane assets.

I am pleased to report company earnings of $12.9 million, $9.5 million of gain on the sale of propane assets and $3.4 million from company operations. This indicates per share earnings of $4.69 from the asset sale and $1.69 from operations. I am also pleased to report that we distributed $4.50 of the gain on the sale and $1.17 of the earnings on operations to our shareholders. The total cash dividend of $5.67 paid to shareholders in 2004 represents a 25% return on the January 2, 2004 share closing price of $22.60.

After having worked for over a decade to grow our propane distribution business, reaching the strategic decision to sell propane assets was a very deliberative process. I have long believed that the market price of our stock did not adequately reflect the value of our propane operation. We concluded the only way to allow shareholders to fully realize the hidden propane value was through a carefully researched and competitively negotiated transaction. The $4.50 special dividend reflects our success in extracting and providing that hidden value for our shareholders. The timing of the transaction was critically important. A low interest rate environment, a recovering economy, and a peaking desire by the national propane consolidators to acquire assets, combined with the strong market position of our propane operation, created a premium selling opportunity. We took advantage of that convergence of forces to secure what we believe was the maximum potential value for our propane assets. We also timed the transaction to be able to distribute the special dividend to shareholders, while we were certain the 15% federal income tax rate on common stock dividends for individuals would still be in place. In addition to distributing $9.3 million to

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NATURAL ADVANTAGE

shareholders from proceeds of the sale, we retired debt of $4.2 million and invested $3 million in natural gas operations. We anticipate investing additional proceeds from the sale in our natural gas distribution system to replace the earnings from our former propane investments.

Our near term focus is on growing and enhancing our natural gas distribution systems while looking for opportunities to develop and offer energy and utility related products and services that are a fit with our systems and core competencies. In furtherance of that focus and strategy, we invested $7.9 million in natural gas distribution system capital improvements in 2004. We completed our reinforcement program on the ten-inch natural gas distribution main serving Bluefield Gas Company, and we added a section of twelve-inch pipeline to reinforce the Roanoke Gas system eastern loop. We also replaced eight miles of older cast iron and bare steel mains with new plastic or coated steel pipe to enhance deliverability and safety and to lower repair and maintenance costs. We expect to continue the cast iron and bare steel pipe replacement program.

We also installed twelve miles of new distribution mains and over 1,200 new service lines to extend gas service to new commercial and residential customers. As a result of the economic recovery and continued low interest rates, new home construction in the Roanoke area has remained robust and builders and homeowners are continuing to choose natural gas service where it is available. The short-term pricing volatility of natural gas has continued to increase; consequently, we are focusing our marketing efforts on the comfort, reliability, and environmental advantages of using natural gas and on maintaining close working relationships with developers, home builders and heating and plumbing contractors who frequently determine or heavily influence energy use decisions.

RELIABLE SUPPLY

In spite of record high energy prices, and the obvious environmental and security advantages of natural gas, Congress continues to be unable or unwilling to adopt comprehensive energy legislation designed to encourage natural gas exploration, alternative fuels development, and energy conservation. The November 1, 2004 closing price per decatherm of natural gas at the Henry Hub was $9.39, compared to $5.13 in 2003 and $4.06 in 2002. Likewise, the cost of a barrel of crude oil on the New York Mercantile Exchange on November 1, 2004 was $50.13, compared to $29.11 in 2003 and $27.13 in 2002. The certainty of an adequate and reliable energy supply for the United States, combined with programs to promote conservation, needs to be a federal priority. If there is not an adequate supply response to the current situation, facilitated by timely accesses to additional areas for exploration, there will be a demand response, and the implications for the United States economy are not likely to be favorable. I encourage you to join me in contacting members of Congress to urge passage of comprehensive energy legislation.

We believe we have adequate gas supplies to meet our 2005 winter demand based on gas already in storage combined with our supply contracts.

We believe we have adequate gas supplies to meet our 2005 winter demand based on gas already in storage combined with our supply contracts. We recently renewed our interstate pipeline and natural gas storage capacity contracts on the Columbia Gas Transmission system through the year 2014 and our other pipeline and storage capacity contracts remain in place with renewal dates ranging from 2008 through 2014.

We continue to work toward full implementation of Sarbanes-Oxley, Section 404 federal requirements for fiscal year 2005. The additional accounting and internal controls provisions are both expensive and demanding of human resources. In fact, the projected added cost and administrative burden of Section 404 compliance was also a contributing factor in our decision to sell the propane operation prior to having to absorb the increased cost into a very price competitive line of business.

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SOLID RETURNS

Fiscal year 2005 will be a transitional year for RGC Resources. In addition to being the year for full compliance with Sarbanes-Oxley Section 404, it will be our first year without the propane operation, although we continue to provide computer and billing services and leased facilities to the purchaser of the propane assets. It will also be the year that we say good-bye to two long serving and highly valuable members of our Board of Directors. Lynn D. Avis, Chairman of Avis Construction and Thomas L. Robertson, former President and CEO of the Carilion Health System will both retire from the Board in January 2005. They joined the Board of Roanoke Gas Company in 1986 and were founding members of the RGC Resources, Inc. Board of Directors in 1999. We will miss their wisdom, experience and support. However, I am pleased and honored to announce that Nancy H. Agee, Executive Vice President and Chief Operating Officer of Carilion Health System and Raymond D. Smoot, Jr., Chief Operating Officer and Secretary-Treasurer of Virginia Tech Foundation, Inc. have agreed to join the Board. They are on the proxy ballot for approval at our January 24, 2005 annual shareholders meeting.

I remain confident in our ability to provide safe and reliable service for our customers, a supportive, engaging, and learning environment for our employees and a solid return for our shareholders.

As I have stated in the past, it continues to be an exciting time to lead a publicly traded company in the energy distribution business. The added regulatory burdens of Sarbanes-Oxley and volatile energy prices create unique challenges, but I remain confident in our ability to provide safe and reliable service for our customers, a supportive, engaging, and learning environment for our employees and a solid return for our shareholders.

I thank you for your continuing investment and interest in RGC Resources, Inc.

Sincerely,

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JOHN B. WILLIAMSON, III

Chairman, President and CEO

SELECTED FINANCIAL DATA


Years Ended September 30,	2004			2003		2002		2001			2000
Operating Revenues	$	103,147,064		$	88,833,953	$	69,311,118	$	102,397,478		$	66,384,578
Gross Margin		23,392,664			21,918,225		19,522,244		21,869,388			20,603,047
Operating Income		5,194,107			5,283,862		4,978,003		4,647,832			5,162,295
Net Income - Continuing Operations		2,066,802			1,998,779		1,936,156		1,302,024			2,082,472
Net Income - Discontinued Operations		10,867,211			1,529,610		550,739		1,004,591			791,230
Basic Earnings Per Share - Continuing Operations	$	1.02		$	1.01	$	1.00	$	0.68	**	$	1.12

Basic Earnings Per Share - Discontinued Operations		5.36	*	$	0.77	$	0.28	$	0.53		$	0.42

Cash Dividends Declared Per Share	$	5.67		$	1.14	$	1.14	$	1.12		$	1.10
Book Value Per Share		17.73			16.90		16.36		16.05			15.94
Average Shares Outstanding		2,027,908			1,983,970		1,939,511		1,898,697			1,863,275
Total Assets		114,972,556			104,364,733		96,978,115		97,324,955			90,451,800

Long-Term Debt ( Less Current Portion)		26,000,000			30,219,987		30,377,358		22,507,485			23,310,522
Stockholders’ Equity		36,621,522			33,857,614		32,068,997		30,725,072			29,985,871
Shares Outstanding at Sept. 30		2,065,408			2,003,232		1,960,418		1,914,603			1,881,733

*	Reflects $4.69 gain on sale of assets.

**	Reflects $.32 per share impairment loss.

FORWARD-LOOKING STATEMENTS

From time to time, 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. 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 the following: (i) failure to earn on a consistent basis an adequate return on invested capital; (ii) increasing expenses and labor costs and labor availability; (iii) price competition from alternative fuels; (iv) volatility in the price and availability of natural gas; (v) uncertainty in the projected rate of growth of natural gas requirements 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 and/or colder weather; (ix) developments in electricity and natural gas deregulation and associated industry restructuring; (x) variations in winter heating degree-days from normal; (xi) changes in environmental requirements, pipeline operating requirements and cost of compliance; (xii) impact of potential increased governmental oversight and compliance costs due to the Sarbanes-Oxley law; (xiii) failure to obtain timely rate relief for increasing operating or gas costs from regulatory authorities; (xiv) ability to raise debt or equity capital; (xv) impact of uncertainties in the Middle East and related terrorism issues, and (xvi) new accounting standards issued by the Financial Accounting Standards Board, 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” or similar words or future or conditional verbs such as “will,” “would,” “should,” “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.


2004 ANNUAL REPORT		- 10 -		RGC RESOURCES, INC.

MANAGEMENT’S DISCUSSION & ANALYSIS

GENERAL

Resources is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately 58,000 residential, commercial and industrial customers in Roanoke, Virginia and Bluefield, Virginia and West Virginia and the surrounding areas through its Roanoke Gas Company and Bluefield Gas Company subsidiaries. Natural gas service is provided at rates and for the terms and conditions set forth by the State Corporation Commission (SCC) in Virginia and the Public Service Commission (PSC) in West Virginia. Roanoke Gas and Bluefield Gas currently hold the only franchises and/or certificates of public convenience and necessity to distribute natural gas in its Virginia and West Virginia service areas. These franchises are effective through January 1, 2016 in Virginia and August 23, 2009 in West Virginia. While there are no assurances, the Company believes that it will be able to negotiate acceptable franchises when the current agreements expire. Certificates of public convenience and necessity in Virginia are exclusive and are intended to be of perpetual duration.

Resources also provides unregulated energy products through Diversified Energy Company, which operates as Highland Energy Company. Highland Energy brokers natural gas to numerous industrial and commercial transportation customers of Roanoke Gas Company and Bluefield Gas Company. Although the energy marketing operations do not fall under the jurisdiction of the SCC and PSC, they are subject to or affected by various federal and state regulations. Prices are determined by the Company and are subject to market demands and price competition. In addition to an energy marketing company, Diversified Energy Company operated an unregulated propane operation under the name of Highland Propane Company. In July 2004, RGC Resources, Inc. sold the propane operations. These operations as such have been classified as discontinued operations in the financial statements. Please see the Discontinued Operations section below for further discussion.

RGC Resources, Inc. also provides information system services to software providers in the utility industry through RGC Ventures, Inc. of Virginia, which operates as Application Resources.

Management views warm winter weather, energy conservation, fuel switching and bad debts due to high energy prices, and competition from alternative fuels each as factors that could have a significant impact on the Company’s earnings. In addition, management has concerns regarding the cost and time required for complying in the future with the regulations regarding internal controls promulgated pursuant to Section 404 of the Sarbanes-Oxley Act of 2002.

For the fiscal year ended September 30, 2004, the Company experienced a decline in sales volumes due to warmer winter weather. The effect of the warmer weather on the results of operations was mitigated due to the non-gas rate increase placed into effect in October 2003.

RESULTS OF OPERATIONS CONTINUING-OPERATIONS

FISCAL YEAR 2004 COMPARED WITH FISCAL YEAR 2003

OPERATING REVENUES - Total operating revenue increased $14,313,111, or 16%, for the year ended September 30, 2004 (fiscal 2004 ) compared to the year ended September 30, 2003 (fiscal 2003). The increase in revenues resulted from a combination of higher natural gas costs and increased sales volumes in the energy marketing operations. The average per unit cost of natural gas increased by 22% for regulated operations and 13% for energy marketing operations over last year.


2004 ANNUAL REPORT		- 11 -		RGC RESOURCES, INC.

GROSS MARGIN - Total gross margin increased $1,474,439, or 6.7%, for fiscal 2004 compared to fiscal 2003.


Year Ended September 30,	2004		2003		Increase/ (Decrease)			Percentage
Gross Margin:
Gas Utilities	$	22,833,506	$	21,425,681	$	1,407,825		6.6	%
Energy Marketing		254,716		285,042		(30,326	)	-10.6	%
Other		304,442		207,502		96,940		46.7	%

Total Gross Margin	$	23,392,664	$	21,918,225	$	1,474,439		6.7	%

Regulated natural gas margins increased $1,407,825, or 6.6%, as total delivered volumes decreased by 1% due to significantly warmer winter weather. Tariff sales, composed mainly of weather sensitive residential and commercial volumes, declined by 7.6%. This decline in tariff sales primarily resulted from a 10% decline in heating degree days (an industry measure by which the average daily temperature falls below 65 degrees Fahrenheit) from the same period last year. Furthermore, total heating degree days for fiscal 2004 were 7% below the 30 year normal. Transportation services, consisting of delivered volumes of natural gas purchased from other than the regulated utilities, and generally correlated more with economic conditions, increased 19.4 %, reflecting continued improvement in the economy and industrial production. Even though high natural gas prices do not appear to have had a discernable effect on demand for natural gas and gas transportation service, continued high prices could result in some customers seeking lower-cost alternative fuel sources depending upon the price of natural gas compared to other energy sources.

Although the volume of natural gas tariff sales declined by 7.6%, regulated natural gas margins increased due to Commission approved non-gas cost rate increases placed into effect on October 16, 2003 by Roanoke Gas Company and December 1, 2003 by Bluefield Gas Company. The total annual non-gas cost rate increase associated with the approved rate increases amounted to approximately $1,650,000 based upon a normal weather year. As a result of these higher rates, customer base charges, in the form of a flat monthly fee billed to each natural gas customer, rose $642,295 and volumetric margin increased $765,530.

Energy marketing margins decreased $30,326, or 10.6%, from last year, even though total delivered volumes increased by 656,876 DTH, or 28.5%. The increase in sales volume was attributable to a combination of improving economic conditions and sales to two additional customers of the marketing operations. The new customers accounted for approximately 37% of the increased volume. The decline in unit margin (margin per dekatherm) is reflective of an average 13% increase in energy prices and competitive conditions.

NATURAL FACT:

Natural gas has increasingly become the “fuel of choice” by both the environmental community and industry as an acceptable alternative in the transition away from coal nuclear power and hydro electric power.

Other margins increased by $96,940, or 46.7%, over the same period last year due to billings for the fuel line protection program, a new service program which contributed approximately $65,000 to other margins, and net fees earned in connection with the services and facilities provided to the purchaser of the Company’s propane operations subsequent to its sale.


2004 ANNUAL REPORT		- 12 -		RGC RESOURCES, INC.


Year Ended September 30,	2004	2003	Increase/ (Decrease)		Percentage
Regulated Natural Gas -
DTH Tariff Sales	8,466,916	9,162,397	(695,481	)	-7.6	%
Transportation Volumes	3,437,004	2,878,796	558,208		19.4	%

Total Delivered Volume (DTH)	11,903,920	12,041,193	(137,273	)	-1.1	%
Highland Energy (DTH)	2,957,962	2,301,086	656,876		28.5	%
Heating Degree Days (Unofficial)	3,917	4,349	(432	)	-9.9	%

OTHER OPERATING EXPENSES - Operations expenses increased $1,122,254, or 11.3%, in fiscal 2004 compared with fiscal 2003. The increased operations expenses related to higher employee compensation and benefit costs, corporate insurance, professional services and debt retirement costs partially offset by reduced bad debt expense and greater capitalization of overheads. Employee benefit costs increased $194,782 primarily due to higher pension costs related to a reduction in the actuarial discount rate assumption and amortization of actuarial losses related to the investment performance of plan assets over the past few years. Total labor expense increased $710,642 associated with an increase in the number of employees, a focus on operational projects during the year and increased pay-for-performance compensation. Corporate property and liability insurance expense increased $73,647 on higher premiums associated with liability and workers compensation coverage. Professional services increased $217,048 due to increases in external audit fees, completion of an SCC mandated depreciation study on Roanoke Gas Company’s assets, consulting services related to Sarbanes-Oxley Section 404 compliance, and consulting services related to the Company’s pipeline integrity management program. The Company also incurred a fee of $125,547 for early termination of the $1,700,000 fixed rate note for Highland Propane. However, the Company experienced a reduction in operations bad debt expense of $89,313 related to enhanced collection efforts.

Maintenance expenses increased by $189,046, or 12.2%, as the Company completed a substantial amount of work on sections of the natural gas distribution system that are not buried in the ground, primarily on bridges, consisting of painting and/or wrapping exposed pipe to prevent corrosion. The Company also wrote off certain old and obsolete maintenance materials inventory no longer considered useful and performed additional facility, buildings and ground maintenance.

General taxes increased $127,743, or 9.3%, in fiscal 2004 compared to fiscal 2003 due to higher business and occupation (B&O) taxes, a revenue sensitive tax related to the West Virginia natural gas operations, which accounted for approximately half of the increase in general taxes. The remainder of the increase was associated with higher net payroll tax expense related to greater levels of operations and maintenance labor and increased property taxes associated with greater levels of taxable property.

Depreciation expense increased $125,151, or 3.3%, due to capital expenditures associated with system expansion for adding new natural gas customers, significant pipeline and facility renewal projects, and software and computer hardware upgrades. The level of increase in depreciation expense was smaller than would otherwise be expected due to the implementation of new depreciation rates for Roanoke Gas Company effective January 1, 2004. A depreciation study was completed and the new rates were approved by the SCC. The new depreciation rates would result in approximately $100,000 less depreciation expense on an annual basis, based upon plant account balances on the effective date.


2004 ANNUAL REPORT		- 13 -		RGC RESOURCES, INC.

Other expenses, net, decreased $131,116, or 87%, primarily due to investment income earned on the investment of proceeds from the sale of the propane operations. The Company received approximately $28.5 million from the sale of propane assets and invested the proceeds in short-term investments after retiring debt and making income-tax estimates, pending the payment of the $4.50 per share special dividend payable on December 8, 2004.

INTEREST EXPENSE - Total interest expense for fiscal 2004 decreased $81,233, or 4.1%, from fiscal 2003, although total average debt outstanding during the year increased 6.0%.

Debt Summary:


Year Ended September 30,	2004			2003			Increase/ (Decrease)			Percentage
Average Daily Balance:
Long-term Fixed Rate Debt	$	23,688,524		$	24,702,191		$	(1,013,667	)	-4.1	%
Long-term Variable Rate Debt		2,000,000			—			2,000,000		100.0	%
Short-term Variable Rate Debt		9,224,905			8,248,874			976,031		11.8	%

Total Variable Rate Debt		11,224,905			8,248,874			2,976,031		36.1	%
Total Debt		34,913,429			32,951,065			1,962,364		6.0	%

Average Interest Rate:
Long-term Fixed Rate Debt		6.89	%		7.13	%		-0.24	%	-3.4	%
Variable Rate Debt		1.92	%		1.99	%		-0.07	%	-3.5	%

The decrease in interest expense resulted from a combination of the new variable-rate $2,000,000 Bluefield Gas note that replaced a 7.28% fixed rate note, the payoff of $1,000,000 installment of Roanoke Gas debt issue with a 9.2% coupon rate and lower average rate on the Company’s line of credit balances. The downward trend in short-term interest rates experienced by the Company on its line-of-credit accounts ended in June 2004 when short term interest rates moved upward in response to market pressures and Federal Reserve actions. The above analysis does not include the $4,200,000 in Diversified Energy debt that was retired in July 2004 and the corresponding interest expense included in discontinued operations on the income statement.

INCOME TAXES - Income tax expense from continuing operations increased $54,571, or 4.7%, from last year as both pre-tax earnings and the federal income tax rate increased as a result of the gain realized on the sale of assets. The total effective tax rate for fiscal 2004 was 37.2% compared to 36.9% in fiscal 2003.

NET INCOME AND DIVIDENDS - Income from continuing operations for fiscal 2004 was $2,066,802 as compared to fiscal 2003 income from continuing operations of $1,998,779. The improvement in income from continuing operations derived from the non-gas cost rate increase, which more than offset the impact of a significantly warmer winter and higher operations and maintenance expenses. Basic and diluted earnings per share from continuing operations were $1.02 and $1.01 in fiscal 2004 compared with $1.01 and $1.00 in fiscal 2003, respectively. Dividends per share of common stock, excluding the special $4.50 dividend declared to shareholders related to the gain on sale of assets, were $1.17 in fiscal 2004 and $1.14 in fiscal 2003.


2004 ANNUAL REPORT		- 14 -		RGC RESOURCES, INC.

FISCAL YEAR 2003 COMPARED WITH FISCAL YEAR 2002 - REVISED TO EXCLUDE DISCONTINUED OPERATIONS

GROSS REVENUES - Total gross revenue increased $19,522,835, or 28.2%, for the year ended September 30, 2003 (fiscal 2003) compared to the year ended September 30, 2002 (fiscal 2002). The increase in revenues resulted from a combination of higher energy costs and increased sales volume attributable to significantly colder weather. The average per unit cost of natural gas increased by 17 percent for fiscal 2003 over fiscal 2002.

GROSS MARGIN - Total gross margin increased $2,395,981, or 12.3%, for fiscal 2003 compared to fiscal 2002.


Year Ended September 30,	2003		2002		Increase/ (Decrease)			Percentage
Gross Margin
Gas Utilities	$	21,425,681	$	19,031,178	$	2,394,503		12.6	%
Energy Marketing		285,042		265,661		19,381		7.3	%
Other		207,502		225,405		(17,903	)	-7.9	%

Total Gross Margin	$	21,918,225	$	19,522,244	$	2,395,981		12.3	%

Regulated natural gas margins increased $2,394,503, or 12.6%, primarily due to increased delivered volumes attributable to much colder winter weather and implementation of new billing rates in fiscal 2003. Total delivered natural gas volumes (tariff and transportation) increased 1,477,679 dekatherms (DTH), or 14.0%. Residential and commercial sales accounted for a majority of the increased sales volume due to the weather sensitive nature of those customers. Heating degree days (an industry measure by which the average daily temperature falls below 65 degrees Fahrenheit) increased by 24.2% over fiscal 2002; however, fiscal 2003 heating degree days were only 3% higher than the 30 year normal. Transportation service customers also reflected a net increase as an improving economy led to increased production resulting in higher gas usage for processes.

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During fiscal 2003, the Company implemented new rates in accordance with orders from the Virginia SCC and the West Virginia PSC. These new rates affected margins by increasing the customer base charge and changing the rate structure to allow for the direct recovery of the costs associated with financing natural gas inventory and prepaid gas service. The customer base charge, which is a flat monthly fee billed to each natural gas customer, increased by $384,600 for fiscal 2003 associated with the implementation of the increase in December 2002. In April 2003, Roanoke Gas Company implemented new rates that would allow the Company to recover the specific costs associated with financing its investment in gas inventory and prepaid gas service. Prior to April 2003, billing rates included a component to recover the financing costs based upon historical inventory levels and historical interest rates and the allowed rate of return on equity. Therefore, when costs increased, the Company had to absorb the higher financing costs without rate relief. The new rate structure provided for a different recovery mechanism, which also resulted in different timing of revenue recognition. The Company is able to recover higher financing costs related to increased inventory and prepaid gas balances arising from higher gas costs; conversely, the Company will pass along savings to customers if financing costs decrease due to lower inventory and prepaid gas balances resulting from reductions in gas costs. The new rate structure resulted in the recognition of additional revenue related to the recovery of these financing costs during fiscal 2003. Under the new rate structure, the revenue associated with the calculated carrying cost is accrued based upon when those costs were incurred,


2004 ANNUAL REPORT		- 15 -		RGC RESOURCES, INC.

primarily during the summer and fall as gas is being injected into storage. Under the previous rate structure, the majority of the revenue was recorded in winter and early spring when customers were billed for higher levels of gas consumption. As a result of the new rate structure, the Company recorded approximately $250,000 in additional revenues and margin related to the carrying costs during fiscal 2003, with nearly the entire amount recorded in the last three months as inventory levels increased substantially. Of the $250,000, approximately $72,000 was associated with recovery of financing costs on higher cost inventory and prepaid gas balances, while the remaining balance represents a timing issue on revenue recognition. Consequently, for comparative purposes, revenues were expected to be lower in the second quarter of fiscal 2004 when inventory levels and financing costs are reduced.

Energy marketing margins increased $19,381, or 7.3%, from fiscal 2002, even though total delivered volumes declined by 136,578 DTH, or 5.6%, from fiscal 2002 and after taking into account the absence of a one-time gain from the sale of a fixed price natural gas contract recorded in fiscal 2002. The Company was able to increase unit margins over fiscal 2002 due to the ability to effectively navigate the volatile energy market. The decline in sales volumes was associated with certain transporting customers opting to purchase their gas supply through the interruptible sales tariff of the regulated utility and the temporary switching of one industrial customer to an alternative fuel during the year.

Other margins declined by $17,903, or 7.9%, from fiscal 2002 due to reduced activity in Application Resources.


Year Ended September 30,	2003	2002	Increase/ (Decrease)		Percentage
Regulated Natural Gas (DTH)
Residential and Commercial	8,816,719	7,499,603	1,317,116		17.6	%
Interruptible Sales Service	345,678	156,923	188,755		120.3	%
Transportation Volumes	2,878,796	2,906,988	(28,192	)	-1.0	%

Total Delivered Volume (DTH)	12,041,193	10,563,514	1,477,679		14.0	%
Highland Energy (DTH)	2,301,086	2,437,664	(136,578	)	-5.6	%
Heating Degree Days - Unofficial	4,349	3,502	847		24.2	%

NATURAL FACT:

Many existing industrial operators and electric generators have switched to natural gas as a method for complying with the Clean Air Act.

OTHER OPERATING EXPENSES - Operations expenses increased $1,554,301, or 18.5%, in fiscal 2003 compared with fiscal 2002. The increased operations expenses related to higher bad debt expense, employee benefit costs, labor and corporate insurance. Operations bad debt expense increased by $309,683 due to the combined effects of the much colder winter, which increased energy usage, and higher energy prices. As a result of these two factors, total revenues increased by 28.2% over fiscal 2002, resulting in more customer account balances becoming delinquent and subject to write-off. Furthermore, fiscal 2002 bad debt reserve requirements were less than the Company’s historical averages due to the warm winter and much lower energy costs. In addition, in fiscal 2002, the Company established a regulatory asset in the amount of $316,966 that provided for the deferral of a portion of bad debt expense incurred in 2001. In December 2002, the Company began amortizing the regulatory asset in conjunction with the implementation of new rates approved by the Virginia State Corporation Commission, which included a provision for recovery of the amortized expense. Total amortization of the regulatory asset amounted to $88,046 during fiscal 2003 compared with an expense deferral


2004 ANNUAL REPORT		- 16 -		RGC RESOURCES, INC.

of $316,966 in fiscal 2002. Employee benefit costs increased $283,308 primarily due to much higher claims experience under the Company’s medical plan and higher pension and post-retirement medical expenses attributable to changes in actuarial assumptions and performance of plan assets over the past few years. Labor costs associated with operations increased $199,967 due to increased demands that the colder winter placed on the operation of the natural gas system and normal pay increases. Corporate property and liability insurance expense increased $118,910 due to much higher premiums associated with insurance carriers raising the cost of coverage to recover from the losses attributed to the September 11 terrorist attacks and the corporate accounting and finance irregularities of the past two years.

Maintenance expenses increased by $408,499, or 35.7%, as the Company focused on repairing pipeline leaks and performing additional system maintenance as a result of the cold winter. In addition, the improved earnings results in fiscal 2003 provided the Company with the resources to perform additional maintenance improvements to the general office and operations buildings as well as accelerate some scheduled maintenance for fiscal 2004 into fiscal 2003.

General taxes increased $78,754, or 6.1%, in fiscal 2003 compared to fiscal 2002 due to higher business and occupation (B&O) taxes, a revenue sensitive tax related to the West Virginia natural gas operations, higher net payroll tax expense related to increased labor expense and increased property taxes associated with increases in taxable property.

Depreciation expense increased $120,576, or 3.3% due to capital expenditures associated with adding new natural gas customers and replacing older portions of the natural gas distribution system.

Other expenses, net, increased $55,633, or 58.5%, due to increases in corporate charitable giving. The rise in charitable giving was associated with the improved Company performance which allowed management to make or commit to a higher level of giving following two years of lower earnings performance and reduced giving. The Company views its commitment to the communities and customers it serves very seriously. Charitable giving and community involvement by the Company and its employees have consistently been a priority.

INTEREST EXPENSE - Total interest expense for fiscal 2003 increased $163,308, or 9.1%, from fiscal 2002 on an increase of 13.4% in total average debt outstanding during the year.

Debt Summary:


Year Ended September 30,	2003			2002			Increase/ (Decrease)			Percentage
Average Daily Balance:
Long-term Fixed Rate Debt	$	24,702,191		$	18,029,590		$	6,672,601		37.0	%
Short-term Variable Rate Debt		8,248,874			11,023,558			(2,774,684	)	-25.2	%
Total Debt		32,951,065			29,053,148			3,897,917		13.4	%

Average Interest Rate:
Long-term Fixed Rate Debt		7.13	%		8.19	%		-1.06	%	-12.9	%
Variable Rate Debt		1.99	%		2.42	%		-0.43	%	-17.8	%


2004 ANNUAL REPORT		- 17 -		RGC RESOURCES, INC.

Interest expense increased due to the increase in borrowing to fund higher accounts receivable balances and natural gas inventories/prepayments due to rising gas costs. The increase in interest expense increased at a smaller rate than the average debt outstanding due to the issuance of an $8,000,000 intermediate variable-rate note that was converted to a fixed rate note of 4.18% through an interest rate swap. Furthermore, interest rates continued their downward momentum in fiscal 2003 resulting in a decline in the short-term rates on the Company’s variable rate lines of credit.

INCOME TAXES - Income tax expense increased $24,295, or 2.1 %, over fiscal 2002 as pre-tax earnings increased by 3%. The total effective tax rate for fiscal 2003 was 36.9% compared to 37.1% for fiscal 2002.

NET INCOME AND DIVIDENDS - Income from continuing operations for fiscal 2003 was $1,998,779 as compared to fiscal 2002 income from continuing operations of $1,936,156. The improvement in income from continuing operations derived from the non-gas cost rate increase and colder winter weather more than offsetting the impact of higher operating and maintenance expenses. Basic and diluted earnings per share from continuing operations were $1.01 and $1.00 in fiscal 2003 compared with $1.00 and $1.00 in fiscal 2002, respectively. Dividends per share of common stock were $1.14 in both fiscal 2003 and fiscal 2002.

DISCONTINUED OPERATIONS

On July 12, 2004, Resources sold the propane assets of its subsidiary, Diversified Energy Company, d/b/a Highland Propane Company (“Diversified”), for approximately $28,500,000 in cash to Inergy Propane, LLC (“Acquiror”). The sale of assets encompassed substantially all propane plant assets (with the exception of a limited number of specific assets being retained by Diversified), including the name “Highland Propane”, customer accounts receivable, propane gas inventory and inventory of propane related materials. The Company realized a gain of approximately $9,500,000 on the sale of assets, net of income taxes.

Concurrent with the sale of assets, the Company entered into an agreement with Acquiror by which the Company will continue to provide the use of office, warehouse and storage space, and computer systems and office equipment; and the limited utilization of Company personnel for billing, propane delivery and related services to Acquiror for the term of one year with an option for an additional year.

The asset purchase agreement did not include land and buildings owned by Diversified. Acquiror has leased 10 parcels of real estate consisting of bulk storage facilities and office space from Diversified and has an option to purchase such parcels. Acquiror may conduct environmental reviews before electing to exercise the option to purchase those assets. These leases have 5-year terms, each with an option for an additional term of 5 years.

Resources used the proceeds from the sale of the propane assets to provide shareholders with a special $4.50 per share dividend, retire corporate debt and invest equity capital into its natural gas operations. In July 2004, the Company retired the entire $4.2 million of long-term debt associated with the discontinued propane operations.

RESULTS OF OPERATIONS - DISCONTINUED OPERATIONS

FISCAL YEAR 2004 COMPARED WITH FISCAL YEAR 2003

The discontinued operations presented in the income statement reflect revenues and costs of the propane operations, net of income tax. Certain costs that represent allocations of shared costs from Resources and its subsidiaries to the propane operations have


2004 ANNUAL REPORT		- 18 -		RGC RESOURCES, INC.

been retained in the continuing operations section. A reconciliation of income from discontinued operations for the years ended September 30, 2004, 2003 and 2002, respectively, is provided as follows:


Year Ended September 30,	2004			2003			2002
Propane operations as reflected in historical segment footnote	$	1,344,120		$	1,724,498		$	117,037
Other operations included in sale		78,999			121,212			113,511
Recurring costs retained in continuing operations		854,076			654,449			668,921
Income tax expense		(914,313	)		(970,549	)		(348,730	)

		1,362,882			1,529,610			550,739
Gain on sale of assets - net of tax		9,504,329			—			—

Discontinued operations - net of tax	$	10,867,211		$	1,529,610		$	550,739

The costs retained in continuing operations are attributable to activities and systems not included in the agreement with Acquiror including functions such as accounting, human resources, procurement, credit and collections and general management services. The Company has continuing need for these centralized services to support its natural gas operations, and as a result, many of these costs can not be eliminated. The Company will incorporate these remaining costs, required to continue providing utility services, into both Roanoke Gas and Bluefield Gas rate case filings to recover these costs through future rates. Management expects to receive favorable rate treatment because these services are essential to natural gas operations; however, there is no guarantee that the respective Commissions will allow for the full recovery of all costs.

The following is a summary of the net assets sold as determined at September 30, 2003 and as reported on the closing date of July 12, 2004:


	July 12, 2004		September 30, 2003
Assets:
Accounts receivable	$	735,036	$	941,117
Inventories		352,589		313,498
Goodwill		298,314		298,314
Property, plant and equipment, net		11,139,527		11,336,089

Total assets	$	12,525,466	$	12,889,018

Income from discontinued operations declined by $166,728 for fiscal 2004 from fiscal 2003. The decline primarily resulted from a combination of reduced sales volumes due to warmer winter weather and a reduction in the realized benefits from propane derivatives, which more than offset the elimination of the loss months of August and September in fiscal 2004 due to the sale of the propane operations. Fiscal 2003 discontinued operations realized $471,184 in additional margin on derivative swap contracts compared to $99,747 realized during the current year.

FISCAL YEAR 2003 COMPARED WITH FISCAL YEAR 2002

Net income from discontinued operations increased by $978,871 for fiscal 2003 over fiscal 2002 as total gallons delivered increased by 1,799,471 gallons, or 20.3%. Total delivered gallons increased due to the significantly colder winter weather. Furthermore, propane operations benefited from the realization of $471,184 in additional margin on derivative swap contracts compared to a $178,870 reduction in fiscal 2002 margin due to realized losses under derivative contracts. Fiscal 2003 also incurred significant increases in employee benefit costs attributable to pension and medical expenses and delivery costs due to the increase in gallons delivered.


2004 ANNUAL REPORT		- 19 -		RGC RESOURCES, INC.

IMPACT OF COST INCREASES AND ENERGY PRICES

Energy costs represent the single largest expense of the Company with the cost of natural gas representing approximately 77% for fiscal 2004 and 2003 and 73% for fiscal 2002 of the total operating expenses of the Company’s gas utilities operations.

Natural gas prices have remained at high levels even though storage volumes are at all time highs going into the winter heating season. The high prices are perplexing considering the current storage levels, and predicting the direction of natural gas prices is extremely uncertain. Volatility in energy prices will be expected. To lessen the impact of price volatility, Roanoke Gas Company and Bluefield Gas Company use a variety of hedging mechanisms. Summer storage injections, financial instruments and fixed price contacts were utilized during the past winter period and provided the Company with lower energy costs than would have been incurred through spot market purchases alone. The Company has entered into similar arrangements for the coming year; however, due to the uncertain direction of natural gas prices, the Company has yet to enter into new derivative financial instruments for the upcoming Winter season.

Natural gas costs are fully recoverable under the present regulatory Purchased Gas Adjustment (PGA) mechanisms, and increases and decreases in the cost of gas are passed through to the Company’s customers.

Although rising energy prices are recoverable through the PGA mechanism for the regulated operations, high energy prices may have a negative impact on earnings through increases in bad debt expense and higher interest costs because the delay in recovering higher gas costs requires borrowing to temporarily fund receivables from customers, LNG and prepaid gas service levels. The Company’s rate structure provides a level of protection against the impact that rising energy prices may have on bad debts and carrying costs on LNG storage and prepaid gas service by allowing for more timely recovery of these costs. However, the rate structure will not protect the Company from increased rate of bad debts or increases in interest rates.

Rising costs affect the Company through increases in non-gas costs such as property and liability insurance, labor costs, employee benefits and supplies and services used in operations and maintenance 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 via a rate increase application. In addition to stressing performance improvements and higher gas sales volumes to offset increasing costs, management must continually review operations and economic conditions to assess the need for filing and receiving adequate and timely rate relief from the state commissions.

CAPITAL RESOURCES AND LIQUIDITY

Due to the capital intensive nature of Resources’ utility and energy businesses as well as the related weather sensitivity, Resources’ primary capital needs are the funding of its continuing construction program and the seasonal funding of its inventory and prepaid gas service commitments and accounts receivable. The Company’s capital expenditures for fiscal 2004 were a combination of replacements and expansions, reflecting the need to replace older cast iron and bare steel pipe with plastic or coated steel pipe, while continuing to meet the demands of customer growth in both natural gas and propane operations. Total capital expenditures of continuing operations for fiscal 2004 were approximately $7.9 million allocated as follows: $7.2 for Roanoke Gas Company and $0.7 million for Bluefield Gas Company. Capital expenditures for the discontinued propane operations were approximately $1.0 in 2004. Depreciation cash flow provided approximately $4.1 million in support of capital expenditures, or approximately 52% of total investment. Historically, consolidated capital expenditures for continuing operations were $6.8 million in 2003 and $6.6 million in 2002. Fiscal 2003 and 2002 capital expenditures also included $1.5 million and $2.0 million, respectively, for discontinued operations. It is anticipated that future capital expenditures will be funded with the combination of operating cash flow, sale of Company equity securities and issuance of debt.


2004 ANNUAL REPORT		- 20 -		RGC RESOURCES, INC.

Short-term borrowing, in addition to providing capital project bridge financing, is used to finance seasonal levels of accounts receivables, inventory and prepaid gas service payments as provided under the Company’s asset management agreement. (Effective November 1, 2004, the current asset management agreement expired and a new contract was awarded to another provider. A key change in the new agreement replaces prepaid gas service with natural gas inventory.) From April through October, the Company prepays or purchases natural gas to build inventory for winter delivery. At September 30, 2004, the Company had $15,923,177 in prepaid gas service compared to $14,782,752 in the prior year. The increase in prepaid gas service is related to higher energy costs, as total volumes are slightly less than in the prior year. In addition, a significant portion of the Company’s sales and billings occur during the winter months. As a result, accounts receivable balances increase during these months and decrease during the summer months.

The level of borrowing under the Company’s line of credit agreements can fluctuate significantly due to changes in the wholesale price of energy and weather outside the normal temperature ranges. As the wholesale price of natural gas increases, short-term debt generally increases because of the lag between the payment to the Company’s energy suppliers and the collection of billings from the Company’s customers.

At September 30, 2004, the Company had available lines of credit for its short-term borrowing needs totaling $24,000,000, of which $12,742,000 was outstanding. The terms of short-term borrowings are negotiable, with average rates of 1.79% in 2004, 1.99% in 2003 and 2.46% in 2002. The lines do not require compensating balances. These lines of credit will expire March 31, 2005, unless extended. The Company anticipates being able to extend the lines of credit or pursue other options. Interest rates are variable based upon 30 day LIBOR.

On October 1, 2003, the Company executed a two-year $2 million note to refinance a $1.125 million Bluefield Gas note and a portion of short-term bridge financing. The note is a variable rate note based upon 30 day LIBOR rate. In July 2004, the Company retired the $4.2 million in notes of Highland Propane from the proceeds received on the sale of propane assets.

Short-term borrowings, together with internally generated funds, long-term debt and the sale of common stock through the Company’s Dividend Reinvestment and Stock Purchase Plan (the “Plan”), have been adequate to cover construction costs, debt service and dividend payments to shareholders. The Company utilizes a cash management program, which provides for daily balancing of the Company’s temporary investment and short-term borrowing needs. The program allows the Company to maximize returns on temporary investments and minimize the cost of short-term borrowings. The Company anticipates such benefits to continue to be realized in the future.

Stockholders’ equity increased for the period by approximately $2.8 million, reflecting an increase of $1.3 million in retained earnings, exclusive of accumulated comprehensive loss, and proceeds of $1.4 million from new common stock purchases through the Plan and the Restricted Stock Plan For Outside Directors and the exercise of stock options to purchase 18,000 shares of stock during the year.

At September 30, 2004, the Company’s consolidated long-term capitalization was 58% equity and 42% debt, compared to 52% equity and 48% debt at September 30, 2003, reflective of retirement of Highland Propane notes.

LOGO


2004 ANNUAL REPORT		- 21 -		RGC RESOURCES, INC.

REGULATORY AFFAIRS

In Virginia, Roanoke Gas Company filed a rate increase request in September 2004 with the Virginia SCC for approximately $1.1 million and placed the increased rates into effect for service rendered on and after October 23, 2004 subject to refund for any differences between the implemented rates and the rates finally approved by the SCC. The rate increase was based on the 10.1% rate of return on equity that was found to be appropriate in the Company’s last general rate case. A hearing on the application is scheduled for March 2005.

In West Virginia, Bluefield Gas Company filed a rate case in January 2004. The case was settled and new rates were put into place for bills rendered on and after on December 1, 2004 designed to shift approximately $110,000 in bad debt expense on gas cost and inventory carrying cost from non-gas rates to gas cost rates recoverable as part of the PGA.

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

RGC Resources, Inc.’s contractual obligations as of September 30, 2004 representing cash obligations that are considered to be firm commitments are as follows.


	Payment due within the year ended September 30,
	2005		2006		2007		2008		2009		Thereafter
Lines of Credit ⁽¹⁾	$	12,742,000	$	—	$	—	$	—	$	—	$	—
Long-term Debt ⁽¹⁾		—		10,000,000		—		5,000,000		—		11,000,000
Capital Leases ⁽¹⁾		19,987		—		—		—		—		—
Natural Gas Commitments		5,714,729		64,750		—		—		—		—
Pipeline and Storage Capacity		11,045,973		11,048,460		11,048,460		10,799,805		10,799,805		64,589,148

Total Contractual Obligations	$	29,522,689	$	21,113,210	$	11,048,460	$	15,799,805	$	10,799,805	$	75,589,148

⁽¹⁾	Excludes interest payments attributable to the debt.

Total available lines-of-credit are scheduled to expire on March 31, 2005, at which time the Company expects to renew the contracts. See Footnote 6 in the consolidated financial statements for additional information.

See Footnote 7 in the consolidated financial statements for more information on long-term debt.

The Company has fixed price commitments to purchase natural gas and related transportation services for the energy marketing operations in the amount of $5,779,479 over the next two years.

The Company has commitments to purchase natural gas at market price over the next four years in the amount of 2,440,575 DTH, 2,369,675 DTH, 2,369,675 DTH and 338,525 DTH associated with the provisions of the Company’s asset management agreement and pipeline commitments.


2004 ANNUAL REPORT		- 22 -		RGC RESOURCES, INC.

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 estimates and judgments 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 could differ from the estimates, which would affect the related amounts reported in the Company’s financial statements. Although, estimates and judgments are applied in arriving at many of the reported amounts in the financial statements including provisions for employee medical insurance, projected useful lives of capital assets and goodwill valuation, the following items may involve a greater degree of judgment.

NATURAL FACT:

Natural gas remains the best home-energy value for five of the last six years.

REVENUE RECOGNITION - The Company bills natural gas customers on a monthly cycle basis; however, the billing cycle periods for most customers do 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, current and historical data.

BAD DEBT RESERVES - The Company evaluates the collectibility of its accounts receivable balances based upon a variety of factors including loss history, level of delinquent account balances and general economic climate.

RETIREMENT PLANS - The Company offers a defined benefit pension plan and a post-retirement medical plan to eligible employees. The expenses and liabilities associated with these plans are determined through actuarial means requiring the estimation of certain assumptions and factors. In regard to the pension plan, these factors include assumptions regarding discount rate, expected long-term rate of return on plan assets, compensation increases and life expectancies, among others. Similarly, the post-retirement medical plan also requires the estimation of many of the same factors as the pension plan in addition to assumptions regarding 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 to name a few. 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.

DERIVATIVES - As discussed in the “Market Risk” section below, the Company may hedge certain risks incurred in the normal operation of business through the use of derivative instruments. The Company applies the requirements of Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, 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 futures value used in determining fair value in prior financial statements.


2004 ANNUAL REPORT		- 23 -		RGC RESOURCES, INC.

REGULATORY ACCOUNTING - The Company’s regulated operations follow the accounting and reporting requirements of Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation. 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 results, 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 the amounts previously collected from customers and for current collection in rates of costs that are expected to be incurred in the future (regulatory liabilities).

MARKET RISK

The Company is exposed to market risks associated with interest rates and commodity prices. Interest rate risk is related to the Company’s outstanding long-term and short-term debt. Commodity price risk is experienced by the Company’s regulated natural gas operations and energy marketing business. The Company’s risk management 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 and interest rate risks 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 is exposed to market risk related to changes in interest rates associated with its borrowing activities. As of September 30, 2004, the Company had $12,742,000 outstanding under its lines of credit and $2,000,000 outstanding on an intermediate-term variable rate note. Based upon outstanding borrowings at September 30, 2004, a 100 basis point increase in market interest rates applicable to the Company’s variable rate debt (excluding those for which the Company has entered into fixed rate swaps) would have resulted in an increase in annual interest expense of approximately $147,000. The Company also has an $8,000,000 intermediate-term variable rate note that is currently being hedged by a fixed rate interest swap. The fair value of the interest rate swap at September 30, 2004 amounted to a $73,356 unrealized loss on marked to market transactions included on the Consolidated Balance Sheet.

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

LOGO

As of September 30, 2004, the Company had not entered derivative instruments for the purpose of hedging the price of natural gas. If the Company had entered into such derivative instruments, any cost incurred or benefit received from the derivative or other hedging arrangements would be expected to be recoverable or refunded through the PGA mechanism. Both the Virginia State Corporation Commission and the West Virginia Public Service Commission currently allow 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 will be passed through to customers when realized.


2004 ANNUAL REPORT		- 24 -		RGC RESOURCES, INC.

ASSET MANAGEMENT

Effective November 1, 2001, Roanoke Gas Company and Bluefield Gas Company (the Companies) entered into a contract with a third party to provide future gas supply needs. The third party assumed the management and financial obligation of the Company’s firm transportation and storage agreements. In connection with the agreement, the Companies exchanged gas in storage at November 1, 2001 for the right to receive an equal amount of gas in the future as provided by the agreement. As a result of this arrangement, natural gas inventories on the balance sheet are replaced with a new classification called “prepaid gas service.” This contract expired on October 31, 2004.

Effective November 1, 2004, Roanoke Gas Company and Bluefield Gas Company each entered into a new asset management contract with a different party third party (Sequent Energy Management, L.P.). Each new contract is a three-year agreement with similar terms to the expiring contract described above with a key difference being that the Company maintains title to gas in storage. As of September 30, 2004, the total value of prepaid gas service on the Balance Sheet was $15,923,177.

ENVIRONMENTAL ISSUES

Both Roanoke Gas Company and Bluefield Gas Company, subsidiaries of RGC Resources, Inc., operated manufactured gas plants (MGPs) as a source of fuel for lighting and heating until the early 1950’s. A by-product of operating MGPs was coal tar, and the potential exists for on-site tar waste contaminants at the former plant sites. The extent of contaminants at these sites, if any, is unknown at this time. An analysis at the Bluefield Gas Company site indicates some soil contamination. The Company, with concurrence of legal counsel, does not believe any events have occurred requiring regulatory reporting. Further, the Company has not received any notices of violation or liabilities associated with environmental regulations related to the MGP sites and is not aware of any off-site contamination or pollution as a result of prior operations. Therefore, the Company has no plans for subsurface remediation at the MGP sites. Should the Company eventually be required to remediate either site, the Company will pursue all prudent and reasonable means to recover any related costs, including insurance claims and regulatory approval for rate case recognition of expenses associated with any work required. A stipulated rate case agreement between the Company and the West Virginia Public Service Commission recognized the Company’s right to defer MGP clean-up costs, should any be incurred, and to seek rate relief for such costs. If the Company eventually incurs costs associated with a required clean-up of either MGP site, the Company anticipates recording a regulatory asset for such clean-up costs to be recovered in future rates. Based on anticipated regulatory actions and current practices, management believes that any costs incurred related to this matter will not have a material effect on the Company’s financial condition or results of operations.

OTHER RISKS

Several other 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, the regulated natural gas operations in Virginia and West Virginia have a means to recover increased costs through formal rate application filings, as well as the ability to automatically pass along increases in natural gas cost. However, rate applications are generally filed based upon historical expenses, which generally results in the Company lagging in the recovery of rapidly increasing operating expenses. Moreover, there can be no guarantee that the respective regulatory commissions in Virginia or West Virginia will allow recovery for all such increased costs when rate applications are filed.

TERRORISM - The terrorist attacks of September 11, 2001 and the ongoing war on terrorism continue to affect the business climate of this country and the need for operational and facility security. The Company has responded to terrorism concerns by improving security at the Company’s office locations and at critical gas operations such as the liquefied natural gas plant. The Company is also using insurance as a means to mitigate potential terrorism impact.


2004 ANNUAL REPORT		- 25 -		RGC RESOURCES, INC.

STOCK MARKET PERFORMANCE - Although equity investments have largely recovered from the worst of the 2001 and 2002 stock market decline, the poor stock market performance over those years has affected the Company’s performance by increasing certain benefit plan expenses. RGC Resources, Inc. offers both a defined benefit pension plan and post-retirement medical benefits. The Company funds both of these plans. Prior poor returns on the investments of these plans continued to have a negative impact resulting in increased expense accruals over the last several years. The Company has increased its funding levels for the defined benefit pension plan and has maintained a consistent funding plan for post retirement medical benefits. This funding plan, in combination with improved plan returns over the past year, have significantly reduced the underfunded position of both plans and have contributed to the reduction in pension expense and post-retirement medical expense for fiscal 2005. The reduction in pension expense for continuing operations will be approximately $64,000, while the reduction in post-retirement medical expense will be approximately $201,000 with most of this reduction associated with the expected effect of the Medicare Part D subsidy effective in 2006.

CORPORATE ACCOUNTING IRREGULARITIES - As a consequence of the high-profile irregularities and accounting scandals at a few well-publicized companies, additional regulation and oversight have been legislated by Congress through the Sarbanes-Oxley law to be enforced by the SEC. These additional requirements have resulted in, or will result in, increased compliance and administrative costs to the Company in the form of professional consultation and internal staff costs, establishment of a formal internal audit program and increased external audit fees.

NATURAL FACT:

The U.S. Produces about 83% of the natural gas it consumes. Most of the rest is imported from Canada.

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. In 2003, Roanoke Gas Company received approval from the SCC for the use of a weather normalization adjustment factor, based on a weather occurrence band around the most recent 30-year average. The weather band would provide approximately a 6 percent range around normal weather, whereby if the number of heating degree days fell within approximately 6 percent above or below the 30-year average, no adjustments would be made. However, if the number of heating degree-days were more than 6 percent below the average, a surcharge would be added to customers’ bills. Likewise, if the number of heating degree-days were more than 6 percent above the average, a credit would be applied to customers’ bills. The Company should be at risk for no more than a 6 percent swing in heating degree-days above or below average. For the fiscal year ended September 30, 2004, the total heating degree deficiency from the 30- year average exceeded the 6 percent band; however, the band measurement for fiscal 2004 is determined based upon the degree days from April 1, 2003 to March 31, 2004. The degree day differential from normal was within the 6 percent band during these months; therefore, no rate surcharge was added to customer bills.


2004 ANNUAL REPORT		- 26 -		RGC RESOURCES, INC.

CAPITALIZATION STATISTICS


	2004			2003			2002			2001			2000
COMMON STOCK:
Shares Issued		2,065,408			2,003,232			1,960,418			1,914,603			1,881,733
Continuing Operations:
Basic Earnings Per Share	$	1.02		$	1.01		$	1.00		$	0.68	**	$	1.12
Diluted Earnings Per Share	$	1.01		$	1.00		$	1.00		$	0.68		$	1.12
Discontinued Operations - Basic Earnings Per Share	$	5.36	*	$	0.77		$	0.28		$	0.53		$	0.42
Diluted Earnings Per Share	$	5.32		$	0.77		$	0.28		$	0.53		$	0.42
Dividends Paid Per Share (Cash)	$	5.67		$	1.14		$	1.14		$	1.12		$	1.10
Dividends Paid Out Ratio		88.9	%		64.0	%		89.1	%		92.6	%		71.4	%


CAPITALIZATION RATIOS:
Long-Term Debt, Including Current Maturities		41.5			48.0			48.7			43.1			43.8
Common Stock And Surplus		58.5			52.0			51.3			56.9			56.2

Total		100.0			100.0			100.0			100.0			100.0

Long-Term Debt, Including Current Maturities	$	26,019,987		$	31,252,359		$	30,482,485		$	23,310,522		$	23,336,614
Common Stock And Surplus		36,621,522			33,857,614			32,068,997			30,725,072			29,985,871
Total Capitalization Plus Current Maturities	$	62,641,509		$	65,109,973		$	62,551,482		$	54,035,594		$	53,322,485

*	Reflects $4.69 gain on sale of assets.

**	Reflects $.32 per share impairment loss.


2004 ANNUAL REPORT		- 27 -		RGC RESOURCES, INC.

SUMMARY OF GAS SALES & STATISTICS


Years Ended September 30,	2004		2003		2002		2001		2000
REVENUES:
Residential Sales	$	47,739,414	$	42,749,256	$	33,261,150	$	50,432,183	$	32,605,568
Commercial Sales		31,899,455		28,371,913		21,723,467		32,486,778		20,270,890
Interruptible Sales		1,680,953		2,238,792		771,439		1,300,369		859,504
Transportation Gas Sales		2,158,411		1,712,960		1,686,141		1,609,974		1,784,508
Backup Services		51,452		89,590		64,287		77,514		10,979
Late Payment Charges		76,142		101,785		100,015		237,579		112,210
Miscellaneous Gas Utility Revenue		98,137		57,041		41,448		50,724		41,509
Energy Marketing		18,810,525		13,091,137		11,107,532		14,756,066		8,828,492
Other		632,575		421,479		555,639		1,446,291		1,870,918

Total	$	103,147,064	$	88,833,953	$	69,311,118	$	102,397,478	$	66,384,578

NET INCOME
Continuing Operations	$	2,066,802	$	1,998,779	$	1,936,156	$	1,302,024	$	2,082,472
Discontinued Operations		10,867,211		1,529,610		550,739		1,004,591		791,230

Net Income	$	12,934,013	$	3,528,389	$	2,486,895	$	2,306,615	$	2,873,702

DTH DELIVERED:
Residential		4,785,309		5,120,975		4,230,055		5,121,119		4,572,256
Commercial		3,468,138		3,685,017		3,258,766		3,732,953		3,315,915
Interruptible		207,939		345,678		156,923		192,659		177,387
Transportation Gas		3,437,004		2,878,796		2,906,988		2,833,758		3,186,497
Backup Service		5,530		10,727		10,782		9,738		1,893

Total		11,903,920		12,041,193		10,563,514		11,890,227		11,253,948
HEATING DEGREE DAYS		3,917		4,349		3,502		4,342		3,721

NUMBER OF CUSTOMERS:
Natural Gas
Residential		52,413		52,006		51,557		51,198		50,520
Commercial		5,623		5,638		5,627		5,529		5,502
Interruptible and Interruptible Transportation Service		45		47		45		43		45

Total		58,081		57,691		57,229		56,770		56,067

GAS ACCOUNT (DTH):
Natural Gas Available		12,250,411		12,392,866		10,992,271		12,516,840		11,933,719

Natural Gas Deliveries		11,903,920		12,041,193		10,563,514		11,890,227		11,253,948
Storage - LNG		117,378		102,907		112,692		70,704		123,002
Company Use And Miscellaneous		52,972		44,450		62,046		31,480		47,325
System Loss		176,141		204,316		254,019		524,429		509,444

Total Gas Available		12,250,411		12,392,866		10,992,271		12,516,840		11,933,719
TOTAL ASSETS	$	114,972,556	$	104,364,733	$	96,978,115	$	97,324,955	$	90,451,800
LONG-TERM OBLIGATIONS	$	26,000,000	$	30,219,987	$	30,377,358	$	22,507,485	$	23,310,522


2004 ANNUAL REPORT		- 28 -		RGC RESOURCES, INC.

MARKET PRICE & DIVIDEND PRICE INFORMATION

RGC Resources’ common stock is listed on the Nasdaq National 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 dividends based on cumulative net earnings and dividends previously paid.


	Range of Bid Prices				Cash Dividends Declared
Year Ended September 30,	High		Low		Cash Dividends Declared
2004
First Quarter	$	23.560	$	22.210	$	0.285
Second Quarter		24.850		21.790		0.295
Third Quarter		25.250		23.020		0.295
Fourth Quarter		35.750		23.251		0.295
Special Dividend						4.500

2003
First Quarter	$	18.400	$	17.250	$	0.285
Second Quarter		19.900		17.860		0.285
Third Quarter		25.500		19.200		0.285
Fourth Quarter		23.790		22.350		0.285


2004 ANNUAL REPORT		- 29 -		RGC RESOURCES, INC.

OFFICERS

JOHN B. WILLIAMSON, III

Chairman of the Board, President, and Chief Executive Officer (1) (2) (3) (4) (5)

J. DAVID ANDERSON

Assistant Secretary and Assistant Treasurer (1) (2) (3) (4) (5)

JOHN S. D’ORAZIO

Vice President and Chief Operating Officer (2)

HOWARD T. LYON

Vice President, Treasurer and Controller (1) (2) (3) (4) (5)

DALE P. MOORE

Vice President and Secretary (1) (2) (3) (4) (5)

JANE N. O’KEEFFE

Vice President Human Resources (1)

C. JAMES SHOCKLEY, JR.

Vice President Operations (3) (5)

ROBERT L. WELLS

Vice President, Application Resources Operations (4)

(1)	RGC Resources, Inc.

(2)	Roanoke Gas Company

(3)	Diversified Energy Company

(4)	RGC Ventures of Virginia, Inc.

(5)	Bluefield Gas Company


2004 ANNUAL REPORT		- 30 -		RGC RESOURCES, INC.

BOARD OF DIRECTORS

LYNN D. AVIS

Chairman of the Board

Avis Construction Company, Inc.

Director (1) (2)

ABNEY S. BOXLEY, III

President and Chief Executive Officer

Boxley Materials Company

Director (1) (2)

JOHN S. D’ORAZIO

Vice President and Chief Operating Officer

Roanoke Gas Company

Director (3) (4)

FRANK T. ELLETT

President

Virginia Truck Center, Inc.

Director (1) (2) (3) (4)

MARYELLEN F. GOODLATTE

Attorney and Principal

Glenn, Feldmann Darby & Goodlatte

Director (1) (2) (5)

J. ALLEN LAYMAN

Private Investor

Director (1) (2) (5)

GEORGE W. LOGAN

Chairman of the Board

Valley Financial Corporation

Chairman of the Board

Alliance Logistics Center (Warsaw, Poland)

Principal

Pine Street Partners, LLC

Faculty

University of Virginia Darden Graduate School of Business

Director (1)

HOWARD T. LYON

Vice President, Treasurer and Controller

RGC Resources, Inc.

Director (5)

DALE P. MOORE

Vice President and Secretary

RGC Resources, Inc.

Director (5)

THOMAS L. ROBERTSON

Chairman of the Board

Carilion Foundation

Director (1) (2)

C. JAMES SHOCKLEY, JR.

Vice President Operations

Diversified Energy Company

Director (3) (4) (5)

S. FRANK SMITH

Consultant

Alpha Natural Resources, LLC

Director (1) (2) (3) (4)

JOHN B. WILLIAMSON, III

Chairman of the Board, President and Chief Executive Officer

RGC Resources, Inc.

Director (1) (2) (3) (4) (5)

(1)	RGC Resources, Inc.

(2)	Roanoke Gas Company

(3)	Diversified Energy Company

(4)	RGC Ventures of Virginia, Inc.

(5)	Bluefield Gas Company


2004 ANNUAL REPORT		- 31 -		RGC RESOURCES, INC.

CORPORATE INFORMATION

CORPORATE OFFICE

RGC Resources, Inc.

519 Kimball Avenue, N.E.

P.O. Box 13007

Roanoke, VA 24030

(540) 777-4GAS (4427)

Fax (540) 777-2636

AUDITORS

Deloitte & Touche LLP

1100 Carillon Building

227 West Trade Street

Charlotte, NC 28202-1675

COMMON STOCK TRANSFER AGENT, REGISTRAR, DIVIDEND DISBURSING

Agent & Dividend Reinvestment Agent

Wachovia Bank, N.A.

Corporate Trust Group

1525 West W.T. Harris Boulevard - 3C3

Charlotte, NC 28262-8522

COMMON STOCK

RGC Resources’ common stock is listed on the Nasdaq

National Market under the trading symbol RGCO.

DIRECT DEPOSIT OF DIVIDENDS & SAFEKEEPING OF STOCK CERTIFICATES

Shareholders can have their cash dividends deposited automatically into checking, saving or money market accounts. The shareholder’s financial institution must be a member of the Automated Clearing House. Also, RGC Resources offers safekeeping of stock certificates for shares enrolled in the dividend reinvestment plan. For more information about these shareholder services, please contact the Transfer Agent, Wachovia Bank, N.A. of North Carolina.

10–K REPORT

A copy of RGC Resources, Inc. latest annual report to the Securities & Exchange Commission on Form 10-K will be provided without charge upon written request to:

Dale P. Moore

Vice President and Secretary

RGC Resources, Inc.

P.O. Box 13007

Roanoke, VA 24030

(540) 777-3846

Access all RGC Resources Inc.’s Securities and Exchange filings through the links provided on our website at www.rgcresources.com.

SHAREHOLDER INQUIRIES

Questions concerning shareholder accounts, stock transfer requirements, consolidation of accounts, lost stock certificates, safekeeping of stock certificates, replacement of lost dividend checks, payment of dividends, direct deposit of dividends, initial cash payments, optional cash payments and name or address changes should be directed to the Transfer Agent, Wachovia Bank, N.A.

All other shareholder questions should be directed to:

RGC Resources, Inc.

Vice President and Secretary

P.O. Box 13007

Roanoke, VA 24030

(540) 777-3846

FINANCIAL INQUIRIES

All financial analysts and professional investment managers should direct their questions and requests for financial information to:

RGC Resources, Inc.

Vice President and Secretary

P.O. Box 13007

Roanoke, VA 24030

(540) 777-3846

Access up-to-date information on RGC Resources and its subsidiaries at www.rgcresources.com.


2004 ANNUAL REPORT		- 32 -		RGC RESOURCES, INC.

RGC Resources, Inc.

and Subsidiaries

Consolidated Financial Statements

for the Years Ended September 30, 2004, 2003 and 2002,

and Report of Independent Registered Public

Accounting Firm

RGC RESOURCES, INC. AND SUBSIDIARIES

TABLE OF CONTENTS


		Page
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM		1

CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED SEPTEMBER 30, 2004, 2003 AND 2002:

Consolidated Balance Sheets		2-3

Consolidated Statements of Income and Comprehensive Income		4-5

Consolidated Statements of Stockholders’ Equity		6

Consolidated Statements of Cash Flows		7-8

Notes to Consolidated Financial Statements		9-32


		Deloitte & Touche LLP 1100 Carillon Building 2700 West Trade Street Charlotte, NC 28202 USA

		Tel: Fax:		+1 704 887 1500 +1 704 887 1561
		www.deloitte.com

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

RGC Resources, Inc.

We have audited the accompanying consolidated balance sheets of RGC Resources, Inc. and subsidiaries (the “Company”) as of September 30, 2004 and 2003, and the related consolidated statements of income and comprehensive income, stockholders’ equity and cash flows for each of the three years in the period ended September 30, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of September 30, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended September 30, 2004, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the financial statements, on July 12, 2004, the Company sold substantially all of the assets of its subsidiary, Diversified Energy Company, d/b/a Highland Propane Company.

LOGO

Charlotte, North Carolina

December 15, 2004

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

SEPTEMBER 30, 2004 AND 2003


	2004			2003
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	9,461,217		$	135,998
Short-term investments		4,991,460			—
Accounts receivable, less allowance for doubtful accounts of $38,525 in 2004 and $163,900 in 2003		5,978,065			5,242,046
Inventories		2,470,249			2,245,808
Assets of discontinued operations		—			12,889,018
Prepaid gas service		15,923,177			14,782,752
Prepaid income taxes		2,278,361			1,079,802
Deferred income taxes		1,818,280			23,141
Under-recovery of gas costs		580,166			790,126
Other		306,966			541,322

Total current assets		43,807,941			37,730,013


UTILITY PROPERTY:
In service		102,086,697			96,385,022
Accumulated depreciation and amortization		(34,493,087	)		(33,136,643	)

In service—net		67,593,610			63,248,379

Construction work in progress		2,405,107			1,992,222

Utility plant—net		69,998,717			65,240,601


NONUTILITY PROPERTY:
Nonutility property		794,013			765,837
Accumulated depreciation and amortization		(184,624	)		(141,472	)

Nonutility property—net		609,389			624,365

Other assets		556,509			769,754

TOTAL ASSETS	$	114,972,556		$	104,364,733

(Continued)

- 2 -

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

SEPTEMBER 30, 2004 AND 2003


	2004			2003
LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES:
Current maturities of long-term debt	$	19,987		$	1,032,372
Borrowings under lines of credit		12,742,000			12,992,000
Dividends payable		9,903,993			571,458
Accounts payable		10,740,943			9,289,899
Customer deposits		712,892			477,465
Accrued expenses		4,356,680			4,798,106
Refunds from suppliers—due customers		22,292			42,320
Over-recovery of gas costs		2,174,313			1,172,585
Fair value of marked-to-market transactions		73,356			319,264

Total current liabilities		40,746,456			30,695,469

LONG-TERM DEBT, EXCLUDING CURRENT MATURITIES		26,000,000			30,219,987


DEFERRED CREDITS AND OTHER LIABILITIES:
Asset retirement obligations		6,197,549			5,449,702
Deferred income taxes		5,174,829			3,875,623
Deferred investment tax credits		232,200			266,338

Total deferred credits and other liabilities		11,604,578			9,591,663

COMMITMENTS AND CONTINGENCIES (Notes 12 and 13)

CAPITALIZATION:
Stockholders’ equity:
Common stock, $5 par value; authorized 10,000,000 shares; issued and outstanding 2,065,408 and 2,003,232 shares in 2004 and 2003, respectively		10,327,040			10,016,160
Preferred stock, no par; authorized 5,000,000 shares; no shares issued or outstanding in 2004 and 2003		—			—
Capital in excess of par value		13,064,566			11,977,084
Retained earnings		13,275,426			12,018,920
Accumulated other comprehensive loss		(45,510	)		(154,550	)

Total stockholders’ equity		36,621,522			33,857,614

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	114,972,556		$	104,364,733

(Concluded)

See notes to consolidated financial statements.

- 3 -

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

YEARS ENDED SEPTEMBER 30, 2004, 2003 AND 2002


	2004		2003			2002
OPERATING REVENUES:
Gas utilities	$	83,703,964	$	75,321,337		$	57,647,947
Energy marketing		18,810,525		13,091,137			11,107,532
Other		632,575		421,479			555,639

Total operating revenues		103,147,064		88,833,953			69,311,118

COST OF SALES:
Gas utilities		60,870,458		53,895,656			38,616,769
Energy marketing		18,555,809		12,806,095			10,841,871
Other		328,133		213,977			330,234

Total cost of sales		79,754,400		66,915,728			49,788,874

GROSS MARGIN		23,392,664		21,918,225			19,522,244


OTHER OPERATING EXPENSES:
Operations		11,070,433		9,948,179			8,393,878
Maintenance		1,741,853		1,552,807			1,144,308
General taxes		1,495,130		1,367,387			1,288,633
Depreciation and amortization		3,891,141		3,765,990			3,645,414
Impairment loss		—		—			72,008

Total other operating expenses		18,198,557		16,634,363			14,544,241

OPERATING INCOME		5,194,107		5,283,862			4,978,003

OTHER EXPENSES—Net		19,621		150,737			95,104

INTEREST EXPENSE		1,883,736		1,964,969			1,801,661

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		3,290,750		3,168,156			3,081,238

INCOME TAX EXPENSE FROM CONTINUING OPERATIONS		1,223,948		1,169,377			1,145,082

INCOME FROM CONTINUING OPERATIONS		2,066,802		1,998,779			1,936,156

DISCONTINUED OPERATIONS:
Income from discontinued operations—net of income taxes of $7,218,695; $970,549 and $348,730 in 2004, 2003, and 2002, respectively		10,867,211		1,529,610			550,739

NET INCOME		12,934,013		3,528,389			2,486,895

OTHER COMPREHENSIVE INCOME (LOSS)—NET OF TAX		109,040		(288,793	)		209,097

COMPREHENSIVE INCOME	$	13,043,053	$	3,239,596		$	2,695,992

(Continued)

- 4 -

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

YEARS ENDED SEPTEMBER 30, 2004, 2003 AND 2002


	2004		2003		2002
BASIC EARNINGS PER COMMON SHARE:
Income from continuing operations	$	1.02	$	1.01	$	1.00
Discontinued operations		5.36		0.77		0.28

Net income	$	6.38	$	1.78	$	1.28

DILUTED EARNINGS PER COMMON SHARE:
Income from continuing operations	$	1.01	$	1.00	$	1.00
Discontinued operations		5.32		0.77		0.28

Net income	$	6.33	$	1.77	$	1.28

WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING:
Basic		2,027,908		1,983,970		1,939,511
Diluted		2,042,312		1,989,460		1,942,058

(Concluded)

See notes to consolidated financial statements.

- 5 -

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

YEARS ENDED SEPTEMBER 30, 2004, 2003 AND 2002


	Common Stock		Capital in Excess of Par Value		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Stockholders’ Equity
BALANCE—September 30, 2001	$	9,573,015	$	10,736,536	$	10,490,375		$	(74,854	)	$	30,725,072
Net income						2,486,895						2,486,895
Gains on hedging activities—net of tax									209,097			209,097
Cash dividends declared ($1.14 per share)						(2,218,779	)					(2,218,779	)
Issuance of common stock (45,815 shares)		229,075		637,637								866,712

BALANCE—September 30, 2002		9,802,090		11,374,173		10,758,491			134,243			32,068,997
Net income						3,528,389						3,528,389
Losses on hedging activities—net of tax									(288,793	)		(288,793	)
Cash dividends declared ($1.14 per share)						(2,267,960	)					(2,267,960	)
Issuance of common stock (42,814 shares)		214,070		602,911								816,981

BALANCE—September 30, 2003		10,016,160		11,977,084		12,018,920			(154,550	)		33,857,614
Net income						12,934,013						12,934,013
Gains on hedging activities—net of tax									109,040			109,040
Cash dividends declared ($5.67 per share)						(11,677,507	)					(11,677,507	)
Issuance of common stock (62,176 shares)		310,880		1,087,482								1,398,362

BALANCE—September 30, 2004	$	10,327,040	$	13,064,566	$	13,275,426		$	(45,510	)	$	36,621,522

See notes to consolidated financial statements.

- 6 -

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

YEARS ENDED SEPTEMBER 30, 2004, 2003 AND 2002


	2004			2003			2002
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income from continuing operations	$	2,066,802		$	1,998,779		$	1,936,156

Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		4,128,980			3,989,081			3,857,887
Cost of removal of utility plant—net		(229,670	)		(27,534	)		(45,580	)
Impairment loss		—			—			72,008
Loss on disposal of property		—			—			1,067
Change in over/under recovery of gas costs		1,141,538			364,268			(1,932,247	)
Deferred taxes and investment tax credits		(596,789	)		681,386			1,686,802
Other noncash items—net		213,245			(101,736	)		(296,926	)
Changes in assets and liabilities which provided (used) cash:
Accounts receivable and customer deposits—net		(500,591	)		(1,408,206	)		2,291,175
Inventories		(1,364,866	)		(5,735,169	)		1,911,211
Other current assets		(964,203	)		21,834			(858,825	)
Accounts payable and accrued expenses		1,009,618			2,229,747			(168,850	)
Refunds from suppliers—due customers		(20,028	)		(9,569	)		(64,869	)

Total adjustments		2,817,234			4,102			6,452,853

Net cash provided by continuing operating activities		4,884,036			2,002,881			8,389,009

Net cash provided by (used in) discontinued operations		(2,757,941	)		2,514,860			2,425,300

Net cash provided by operating activities		2,126,095			4,517,741			10,814,309

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant and nonutility property		(7,925,948	)		(6,774,991	)		(6,581,060	)
Proceeds from disposal of equipment		31,345			15,492			40,571
Purchase of short-term investments		(4,991,460	)		—			—

Cash flows used in investing activities		(12,886,063	)		(6,759,499	)		(6,540,489	)
Net cash provided by (used in) investing activities of discontinued operations		26,514,169			(1,242,558	)		(1,998,047	)

Net cash provided by (used in) investing activities		13,628,106			(8,002,057	)		(8,538,536	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		2,000,000			8,000,000			—
Retirement of long-term debt and capital leases		(6,357,372	)		(105,126	)		(828,038	)
Net borrowings under line-of-credit agreements		(1,125,000	)		(3,124,000	)		(716,000	)
Proceeds from issuance of common stock		1,398,362			816,981			866,712
Cash dividends paid		(2,344,972	)		(2,255,571	)		(2,196,095	)

Net cash provided by (used in) financing activities		(6,428,982	)		3,332,284			(2,873,421	)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		9,325,219			(152,032	)		(597,648	)

CASH AND CASH EQUIVALENTS—Beginning of year		135,998			288,030			885,678

CASH AND CASH EQUIVALENTS—End of year	$	9,461,217		$	135,998		$	288,030

(Continued)

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RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

YEARS ENDED SEPTEMBER 30, 2004, 2003 AND 2002


	2004			2003			2002
SUPPLEMENTAL DISCLOSURE OF CASH FLOWS INFORMATION:

Cash paid during the year for:
Interest	$	2,076,895		$	2,145,317		$	2,086,391

Income taxes—net of refunds	$	10,237,991		$	1,254,623		$	640,145

Noncash transactions:
In 2004, 2003 and 2002, the Company entered into derivative price swaps, caps, and collar arrangements for the purpose of hedging the cost of natural gas and propane. In accordance with hedge accounting requirements, the underlying derivatives were marked to market with the corresponding non-cash impacts to the consolidated balance sheets:
Unrealized gain (loss) on marked-to-market transactions	$	245,908		$	(2,099,155	)	$	3,686,062
Under (over) recovery of gas costs		(70,150	)		1,630,150			(3,343,560	)
Deferred tax asset (liability)		(66,718	)		180,212			(133,405	)

(Concluded)

See notes to consolidated financial statements.

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RGC RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2004, 2003 AND 2002

1.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General—RGC Resources, Inc. is an energy services company engaged in the sale and distribution of natural gas and propane. The consolidated financial statements include the accounts of RGC Resources, Inc. and its wholly owned subsidiaries (the “Company”); Roanoke Gas Company; Bluefield Gas Company; Diversified Energy Company, operating as Highland Propane Company and Highland Energy; and RGC Ventures, Inc. of Virginia, operating as Application Resources. Roanoke Gas Company and Bluefield Gas Company are natural gas utilities, which distribute and sell natural gas to residential, commercial and industrial customers within their service areas. Highland Propane Company distributes and sells propane in southwestern Virginia and southern West Virginia. Highland Energy brokers natural gas to several industrial transportation customers of Roanoke Gas Company and Bluefield Gas Company. Application Resources provides information system services to software providers in the utility industry.

The primary business of the Company is the distribution of natural gas to residential, commercial and industrial customers in Roanoke, Virginia; Bluefield, Virginia; Bluefield, West Virginia; and the surrounding areas. The Company distributes natural gas to its customers at rates regulated by the State Corporation Commission in Virginia (“SCC”) and the Public Service Commission in West Virginia (“PSC”).

As discussed in Note 2, the Company exited the propane business in July 2004 when substantially all of the assets of Highland Propane Company were sold. The results of operations for propane activities are reflected in the discontinued operations line of the accompanying consolidated statements of income and comprehensive income with the corresponding gain. Certain reclassifications to the September 2003 balance sheet have been made to segregate the propane assets as assets of discontinued operations.

All intercompany transactions have been eliminated in consolidation.

Rate Regulated Basis of Accounting—The Company’s regulated operations follow the accounting and reporting requirements of Statement of Financial Accounting Standards (“SFAS”) No. 71, Accounting for the Effects of Certain Types of Regulation. 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 results, 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).

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The amounts recorded by the Company as regulatory assets and regulatory liabilities are as follows:


	September 30
	2004		2003
Regulatory assets:
Under-recovery of gas costs	$	580,166	$	790,126
Bad debt expense deferral		123,265		228,920
Line break expense deferral		196,113		229,076
Other		49,021		44,747

Total regulatory assets	$	948,565	$	1,292,869


Regulatory liabilities:
Asset retirement obligation	$	6,197,549	$	5,449,702
Over-recovery of gas costs		2,174,313		1,172,585
Refunds from suppliers—due customers		22,292		42,320

Total regulatory liabilities	$	8,394,154	$	6,664,607

During 2002, the Company reached an agreement with the regulatory staff of the SCC that provided for the deferral of $316,966 of bad debt expense to be amortized over a three-year period beginning in December 2002.

During 2003, the Company received authorization from the PSC to defer the costs of restoring gas service attributable to a natural gas line break in January 2003. The Company began recovering these costs through rates in December 2003.

Utility Plant and Depreciation—Utility plant is stated at original cost. The cost of additions to utility plant includes direct charges and overhead. The cost of depreciable property retired is charged to accumulated depreciation. The cost of asset removals, less salvage, is charged to asset retirement obligations. Maintenance, repairs, and minor renewals and betterments of property are charged to operations and maintenance.

Provisions for depreciation are computed principally at composite straight-line rates with annual composite rates ranging up to 17% for utility property. Depreciable lives for non-utility property range from 3 to 40 years. The annual composite rates for utility property are determined by periodic depreciation studies. A depreciation study was completed and new rates were approved by the SCC on the Roanoke Gas utility plant assets. These new depreciation rates were effective January 1, 2004.

The composite rates are comprised of two components, one based on average service life and one based on cost of removal. Therefore, the Company accrues estimated cost of removal of long-lived assets through depreciation expense. Removal costs are not a legal obligation as defined by SFAS No. 143 but rather the result of cost-based regulation and accounted for under the provisions of SFAS No. 71. Therefore, beginning October 1, 2002 such amounts are classified as a regulatory liability.

The Company reviews long-lived assets and certain identifiable intangibles for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Our reviews have not resulted in a material effect on results of operations or financial condition.

- 10 -

Cash, Cash Equivalents and Short-Term Investments—For purposes of the consolidated statements of cash flows, the Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. Short-term investments include commercial paper with original maturities greater than three months and less than one year which are valued at cost which approximates fair market value.

Inventories—Inventories consist of natural gas in storage and materials. Inventories are recorded at average cost.

Unbilled Revenues—The Company bills its natural gas customers on a monthly cycle basis; however, the billing cycle period for most customers does not coincide with the accounting periods used for financial reporting. The Company accrues estimates for natural gas delivered to customers not yet billed during the accounting period. The Company recognizes revenue when gas is delivered. The amounts of unbilled revenue receivable included in accounts receivable on the consolidated balance sheets at September 30, 2004 and 2003 were $1,235,833 and $1,251,253, respectively.

Income Taxes—Income taxes are accounted for using the asset and liability method. Under the asset and liability method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the years in which those temporary differences are expected to be recovered or settled. A valuation allowance against deferred tax assets is provided if it is more likely than not the deferred tax asset will not be realized. The Company and its subsidiaries file a consolidated federal income tax return.

Debt Expenses—Debt issuance expenses are being amortized over the lives of the debt instruments.

Over/Under Recovery of Natural Gas Costs—Pursuant to the provisions of the Company’s Purchased Gas Adjustment (“PGA”) clause, increases or decreases in natural gas costs incurred by regulated operations, including gains and losses on derivative hedging instruments, are passed through to customers. Accordingly, the difference between actual costs incurred and costs recovered through the application of the PGA is reflected as a regulatory asset or liability. At the end of the deferral period, the balance of the net deferred charge or credit is amortized over an ensuing 12-month period as amounts are reflected in customer billings. The Company is subject to multiple jurisdictions, which may result in both a regulatory asset and a regulatory liability reported in the financial statements.

Use of Estimates—The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Reclassifications—The Company reclassified certain financial statement items for 2002 and 2003 to reflect the effect of discontinued operations discussed in Note 2.

Earnings Per Share—Basic earnings per share and diluted earnings per share are calculated by dividing net income by the weighted average common shares outstanding during the period and the weighted average common shares outstanding during the period plus dilutive potential common shares. Dilutive potential common shares are calculated in accordance with the treasury stock method, which assumes that proceeds from the exercise of all options are used to repurchase common stock at market value. The amount of shares remaining after the proceeds are exhausted represents the potentially dilutive effect of

- 11 -

the securities. A reconciliation of the weighted average common shares and the diluted average common shares is provided below:


	Year Ended September 30
	2004	2003	2002
Weighted average common shares	2,027,908	1,983,970	1,939,511

Effect of dilutive securities:
Options to purchase common stock	14,404	5,490	2,547

Diluted average common shares	2,042,312	1,989,460	1,942,058

Stock option awards to purchase approximately 110 shares and 2,366 shares as of September 30, 2003 and 2002, respectively, were not included in the computation of diluted earnings per share because inclusion of these shares would have been antidilutive as the option exercise prices were greater than the shares market prices during these periods.

Derivative and Hedging Activities—The Company applies provisions of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted. SFAS No. 133 requires the recognition of all derivative instruments as assets or liabilities in the Company’s balance sheet and measurement of those instruments at fair value.

The Company’s risk management policy allows management to enter into derivatives for the purpose of managing commodity and financial market risks of its business operations. The Company’s risk management policy specifically prohibits the use of derivatives for speculative purposes. The key market risks that RGC Resources, Inc. would seek to hedge include the price of natural gas and propane gas and the cost of borrowed funds.

The Company has historically entered into futures, swaps and caps for the purpose of hedging the price of propane in order to provide price stability during the winter months. During the fiscal year ended September 30, 2004, the Company realized gains on derivative swap arrangements of $99,747 compared to a $471,184 gain in 2003 and a $178,870 loss in 2002. The hedges qualified as cash flow hedges; therefore, changes in the fair value are reported in other comprehensive income. No portions of the hedges were ineffective during the year.

In addition, the Company has historically entered into futures, swaps and caps for the purpose of hedging the price of natural gas in order to provide price stability during the winter months. The fair value of these instruments is recorded in the balance sheet with the offsetting entry to under-recovery of gas costs. Net income and other comprehensive income are not affected by the change in market value as any cost incurred or benefit received from these instruments is recoverable or refunded through the PGA. Both the Virginia State Corporation Commission and the West Virginia Public Service Commission currently allow for full recovery of prudent costs associated with natural gas purchases, and any additional costs or benefits associated with the settlement of these instruments will be passed through to customers when realized. Due to the volatility and uncertainty in the natural gas market, the Company had not entered into any derivative contracts as of September 30, 2004.

The Company also entered into an interest rate swap related to the $8,000,000 note issued in November 2002. The swap essentially converted the three-year floating rate note into fixed rate debt with a 4.18% interest rate. The swap qualifies as a cash flow hedge with changes in fair value reported in other comprehensive income.

- 12 -

A summary of other comprehensive income and financial instrument activity is provided below:


Year Ended September 30, 2004	Propane Derivatives			Interest Rate Swap			Natural Gas Derivatives			Total
Unrealized gains	$	99,747		$	16,292		$	—		$	116,039
Income tax expense		(38,852	)		(6,185	)		—			(45,037	)

Net unrealized gains		60,895			10,107			—			71,002

Transfer of realized (gains) losses to income		(99,747	)		159,466			—			59,719
Income tax expense (benefit)		38,852			(60,533	)		—			(21,681	)

Net transfer of realized losses (gains) to income		(60,895	)		98,933			—			38,038

Net other comprehensive income	$	—		$	109,040		$	—		$	109,040

Fair value of marked to market transactions	$	—		$	(73,356	)	$	—		$	(73,356	)

Accumulated comprehensive loss	$	—		$	(45,510	)	$	—		$	(45,510	)


Year Ended September 30, 2003	Propane Derivatives			Interest Rate Swap			Natural Gas Derivatives			Total
Unrealized gains (losses)	$	251,293		$	(364,063	)	$	—		$	(112,770	)
Income tax (expense) benefit		(97,879	)		138,199			—			40,320

Net unrealized gains (losses)		153,414			(225,864	)		—			(72,450	)

Transfer of realized losses (gains) to income		(471,184	)		114,949			—			(356,235	)
Income tax (benefit) expense		183,527			(43,635	)		—			139,892

Net transfer of realized losses (gains) to income		(287,657	)		71,314			—			(216,343	)

Net other comprehensive loss	$	(134,243	)	$	(154,550	)	$	—		$	(288,793	)

Fair value of marked to market transactions	$	—		$	(249,114	)	$	(70,150	)	$	(319,264	)

Accumulated comprehensive loss	$	—		$	(154,550	)	$	—		$	(154,550	)


Year Ended September 30, 2002	Propane Derivatives			Interest Rate Swap			Natural Gas Derivatives			Total
Unrealized gains	$	163,632		$	—			—		$	163,632
Income tax expense		(63,735	)		—			—			(63,735	)

Net unrealized gains		99,897			—			—			99,897

Transfer of realized losses to income		178,870			—			—			178,870
Income tax benefit		(69,670	)		—			—			(69,670	)

Net transfer of realized losses to income		109,200			—			—			109,200

Net other comprehensive income	$	209,097		$	—		$	—		$	209,097

Fair value of marked to market transactions	$	219,891		$	—		$	1,560,000		$	1,779,891

Accumulated comprehensive income	$	134,243		$	—		$	—		$	134,243

Stock-Based Compensation—The Company adopted SFAS No. 148, Accounting for Stock-Based Compensation—Transition and Disclosure—an amendment of SFAS No. 123. SFAS No. 148 provides alternative methods of transition for a voluntary change to the fair-value-based method of accounting for

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stock-based employee compensation and the effect of the method used on reported results. This statement requires that companies follow the prescribed format and provide the additional disclosures in their annual reports.

The Company applies the recognition and measurement principles of Accounting Principle Board Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations in accounting for this Plan. No stock-based employee compensation expense is reflected in net income as all options granted under the Plan had an exercise price equal to the market value of the underlying common stock on the date of the grant. The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of SFAS No. 123, Accounting for Stock-Based Compensation, to the options granted under the plan. No options were granted in fiscal 2004.


	Twelve Months Ended September 30
	2004		2003			2002
Net income—as reported	$	12,934,013	$	3,528,389		$	2,486,895

Deduct: Total stock-based employee compensation expense determined under fair value method for all awards—net of tax		—		(19,747	)		(17,481	)

Proforma net income	$	12,934,013	$	3,508,642		$	2,469,414


Earnings per share—as reported:
Basic	$	6.38	$	1.78		$	1.28
Diluted	$	6.33	$	1.77		$	1.28

Earnings per share—pro forma:
Basic	$	6.38	$	1.77		$	1.27
Diluted	$	6.33	$	1.76		$	1.27

New Accounting Standards—In December 2003, the Medicare Prescription Drug Improvement and Modernization Act of 2003 (“Medicare Act”) was signed into law. In accordance with guidance issued by the Financial Accounting Standards Board (“FASB”) in FASB Staff Position 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003, the Company elected to defer accounting for the effects of the Medicare Act and the accounting for certain provisions of the Medicare Act. In May 2004, the FASB issued definitive accounting guidance for the Medicare Act in FASB Staff Position (“FSP”) 106-2. The Company has elected the prospective method of recording the effects of this FSP; therefore, it was effective for the Company in the fourth quarter of fiscal 2004. FSP 106-2 results in the recognition of lower other postretirement employment benefit costs to reflect prescription drug-related federal subsidies to be received under the Medicare Act. As a result of the Medicare Act, the Company’s accumulated postretirement benefit obligation was reduced by approximately $1.2 million. The Company recorded approximately $50,000 of the net periodic cost reduction for the quarter ended September 30, 2004.

In June 2001, the FASB issued SFAS No. 142, Goodwill and Other Intangible Assets. SFAS No. 142 was adopted by the Company as of October 1, 2002. SFAS No. 142 requires that goodwill no longer be amortized over an estimated useful life, as previously required. Instead, goodwill amounts will be subject to a fair-value-based annual impairment assessment. The standard also requires acquired

- 14 -

intangible assets to be recognized separately and amortized as appropriate. For the year ended September 30, 2002, the Company’s amortization expense was approximately $30,000. As the Company’s goodwill was associated with the discontinued propane operations, no goodwill is reflected on the balance sheet at September 30,2004 and is reflected in the assets of discontinued operations line for the prior year. The following table reflects the impact of removing goodwill amortization on fiscal 2002 net income.


	Twelve Months Ended September 30, 2002
Net income	$	2,486,895
Add: Goodwill amortization, as recorded—net of tax		18,064

Adjusted net income	$	2,504,959

Basic earnings per share—as reported	$	1.28
Goodwill amortization		0.01

Adjusted basic earnings per share	$	1.29

Diluted earnings per share—as reported	$	1.28
Goodwill amortization		0.01

Adjusted diluted earnings per share	$	1.29

The Company adopted SFAS No. 143, Accounting for Asset Retirement Obligations, on October 1, 2002. SFAS No. 143 requires the reporting at fair value of a legal obligation associated with the retirement of tangible long-lived assets that result from acquisition, construction or development. Management has determined that the Company has no material legal obligations for the retirement of its assets. However, the Company provides a provision, as part of its depreciation expense, for the ultimate cost of asset retirements and removal. Removal costs are not a legal obligation as defined by SFAS No. 143 but rather the result of cost-based regulation and therefore accounted for under the provisions of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. Upon adoption of SFAS No. 143, the Company classified removal costs that do not have an associated legal retirement obligation as a regulatory liability, in accordance with regulatory treatment. The adoption of this statement had no effect on results of operations.

The Company adopted SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, on October 1, 2002. SFAS No. 144 supersedes SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of. The new rules retain many of the fundamental recognition and measurement provisions, but significantly change the criteria for classifying an asset as held-for-sale and for accounting for discontinued operations. The adoption did not have a material impact on the Company’s financial position or results of operation.

In January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities, which significantly changed the consolidation requirements for special purpose entities and similar entity structures. The Company has no relationship with variable interest entities as defined by Interpretation No. 46; therefore, the adoption of this Interpretation had no effect on the Company’s financial position or results of operations.

- 15 -

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. The Company does not have any such debt or equity instruments as defined in SFAS No. 150; therefore, the implementation of the statement had no effect on the Company’s financial position or results of operations.

In December 2003, the FASB issued SFAS No. 132 (Revised 2003), Employers’ Disclosures about Pensions and Other Postretirement Benefits. This statement expands the level of disclosure regarding the Company’s pension plan and other postretirement benefit plans to include additional information describing the types of plan assets, investment strategy, measurement dates, plan obligations and expected cash flows. This Statement pertains to disclosures only and does not impact the Company’s financial position or results of operations. See Note 9 for these disclosures.

2.	DISCONTINUED OPERATIONS

On July 12, 2004, the Company sold the propane assets of its subsidiary, Diversified Energy Company, d/b/a Highland Propane Company (“Diversified”), for approximately $28,500,000 in cash to Inergy Propane, LLC (“Acquiror”). The sale of assets encompassed substantially all of the propane plant assets (with the exception of a limited number of specific assets being retained by Diversified), the name “Highland Propane,” customer accounts receivable, propane gas inventory and inventory of propane related materials. The Company realized a gain of approximately $9,500,000 on the sale of assets, net of income taxes.

Concurrent with the sale of assets, the Company entered into an agreement with Acquiror by which the Company will continue to provide the use of office, warehouse and storage space, and computer systems and office equipment; and the utilization of Company personnel for billing, propane delivery and related services for the term of one year with an option for an additional year.

The asset purchase agreement did not include land and buildings owned by Diversified. Acquiror has leased ten parcels of real estate consisting of bulk storage facilities and office space from Diversified and has an option to purchase such parcels. Acquiror may conduct environmental reviews before electing to exercise the option to purchase those assets. These leases have five-year terms, each with an option for an additional term of five years.

The Company used the proceeds from the sale of the propane assets to provide shareholders with a special $4.50 per share dividend and retire corporate debt. In July 2004, the Company retired the entire $4.2 million of long-term debt associated with the discontinued propane operations.

The discontinued operations presented in the income statement reflect revenues and costs of the propane operations, net of income tax. Certain costs that represent allocations of shared costs from the Company and its subsidiaries to the propane operations have been retained in the continuing operations section.

- 16 -

A reconciliation of income from discontinued operations for the years ended September 30, 2004, 2003 and 2002, respectively, is provided as follows:


	2004			2003			2002
Propane operations as reflected in historical segment footnote	$	1,344,120		$	1,724,498		$	117,037
Other operations included in sale		78,999			121,212			113,511
Recurring costs retained in continuing operations		854,076			654,449			668,921
Income tax expense		(914,313	)		(970,549	)		(348,730	)

		1,362,882			1,529,610			550,739
Gain on sale of assets—net of tax		9,504,329			—			—

Discontinued operations—net of tax	$	10,867,211		$	1,529,610		$	550,739

The following is a summary of the assets sold as determined at September 30, 2003 and as finally reported on the closing date of July 12, 2004:


	July 12, 2004		September 30, 2003
Assets:
Accounts receivable	$	735,036	$	941,117
Inventories		352,589		313,498
Goodwill		298,314		298,314
Property, plant and equipment—net		11,139,527		11,336,089

Total assets	$	12,525,466	$	12,889,018

3.	FINANCIAL INFORMATION BY BUSINESS SEGMENTS

Operating segments are defined as components of an enterprise for which separate financial information is available and is evaluated regularly by the chief decision maker in deciding how to allocate resources and assess performance. The Company uses gross margin to assess segment performance.

The reportable segments of the Company disclosed herein are as follows:

Gas Utilities—The natural gas segment of the Company generates revenue from its tariff rates, under which it provides distribution energy services for its residential, commercial, and industrial customers.

Energy Marketing—The energy marketing segment generates revenue through the sale of natural gas to transportation customers of Roanoke Gas Company and Bluefield Gas Company.

Parent and Other—The other segment includes appliance services, information system services, and certain corporate eliminations.

- 17 -

Information related to the segments of the Company is detailed below:


	Gas Utilities		Energy Marketing		Parent and Other			Consolidated Total
Year Ended September 30, 2004
Operating revenues	$	83,703,964	$	18,810,525	$	632,575		$	103,147,064

Gross margin		22,833,506		254,716		304,442			23,392,664
Operations, maintenance, and general taxes		13,926,929		49,236		331,251			14,307,416
Depreciation and amortization		3,850,198		—		40,943			3,891,141

Operating income		5,056,379		205,480		(67,752	)		5,194,107
Other expenses—net		80,940		—		(61,319	)		19,621
Interest charges		1,883,736		—		—			1,883,736
Income before income taxes		3,091,703		205,480		(6,433	)		3,290,750

As of September 30, 2004

Total assets*	$	97,164,310	$	2,320,974	$	15,487,272		$	114,972,556
Gross additions to long-lived assets		7,897,772		—		28,176			7,925,948

* The Parent and Other Segment includes $12,962,171 in cash and cash equivalents and short-term investments to pay the $4.50 per share dividend from the sale of the propane assets.
	Gas Utilities		Energy Marketing		Parent and Other			Consolidated Total
Year Ended September 30, 2003
Operating revenues	$	75,321,337	$	13,091,137	$	421,479		$	88,833,953

Gross margin		21,425,681		285,042		207,502			21,918,225
Operations, maintenance, and general taxes		12,817,147		44,976		6,250			12,868,373
Depreciation and amortization		3,716,841		—		49,149			3,765,990

Operating income		4,891,693		240,066		152,103			5,283,862
Other expenses—net		150,737		—		—			150,737
Interest charges		1,964,969		—		—			1,964,969
Income before income taxes		2,775,987		240,066		152,103			3,168,156

As of September 30, 2003

Total assets	$	89,196,889	$	2,020,249	$	13,147,595		$	104,364,733
Gross additions to long-lived assets		6,774,401		—		590			6,774,991

- 18 -


	Gas Utilities		Energy Marketing		Parent and Other			Consolidated Total
Year Ended September 30, 2002
Operating revenues	$	57,647,947	$	11,107,532	$	555,639		$	69,311,118

Gross margin		19,031,178		265,661		225,405			19,522,244
Operations, maintenance, and general taxes		10,455,695		30,148		340,976			10,826,819
Impairment loss		—		—		72,008			72,008
Depreciation and amortization		3,554,814		—		90,600			3,645,414

Operating income		5,020,669		235,513		(278,179	)		4,978,003
Other expenses—net		93,997		—		1,107			95,104
Interest charges		1,768,853		—		32,808			1,801,661
Income before income taxes		3,157,819		235,513		(312,094	)		3,081,238

As of September 30, 2002
Total assets	$	81,390,321	$	1,320,944	$	14,266,850		$	96,978,115
Gross additions to long-lived assets		6,537,397		—		43,663			6,581,060

Certain balances under gas utilities and other categories have been restated to reflect the impact of discontinued operations. Specifically, the previously reported propane segment has been eliminated. Additionally, propane assets totaling $12,889,018 and $12,591,734 at September 30, 2003 and 2002, respectively, which are classified as held for sale, have been included the Parent and Other Segment.

During 2004, one customer accounted for 5.5% of the Company’s sales and 8.3% of the Company’s total accounts receivable at September 30, 2004. During 2003 and 2002, no single customer accounted for more than 5% of the Company’s sales. One customer’s accounts receivable balance accounted for 8.7% of the Company’s total accounts receivable at September 30, 2003. No accounts receivable from any customer exceeded 5% of the Company’s total accounts receivable at September 30, 2002.

4.	RESTRUCTURING

As a result of the Company’s evaluation of its heating and air conditioning operations during 2002, the Company decided to discontinue the sales of heating and air conditioning equipment portion of the business. The Company sold its heating and cooling inventory and fixed assets and reflected an impairment loss of $72,008 in 2002. In 2003, the Company sold the customer list and associated warranties on customers to another heating and air conditioning company for a nominal price. In addition, on September 30, 2003, the Company executed merger documents that resulted in the merger of RGC Ventures, Inc. into Diversified Energy Company.

In 2002, management decided to forego third party sales from its mapping operations, GIS Resources, Inc. These operations were integrated into the natural gas operations for the purpose of maintaining system maps and other related functions. No impairment losses were incurred as a consequence of the GIS Resources, Inc. integration.

- 19 -

5.	ALLOWANCE FOR DOUBTFUL ACCOUNTS

A summary of the changes in the allowance for doubtful accounts follows:


	Years Ended September 30
	2004			2003			2002
Balances, beginning of year	$	163,900		$	42,767		$	317,797
Provision for doubtful accounts		486,949			574,871			273,926
Recoveries of accounts written off		289,179			282,446			362,256
Accounts written off		(901,503	)		(736,184	)		(911,212	)

Balances, end of year	$	38,525		$	163,900		$	42,767

Prior year balances have been restated to remove the discontinued propane operations.

6.	BORROWINGS UNDER LINES OF CREDIT

The Company has available unsecured lines-of-credit with a bank for $24,000,000 as of September 30, 2004. These lines-of-credit will expire March 31, 2005. The Company anticipates being able to extend the lines-of-credit or pursue other options. The Company’s available unsecured lines-of-credit vary during the year to accommodate its seasonal borrowing demands. Generally, the Company’s borrowing needs are at their lowest in spring, increase during the summer and fall due to gas prepayments and construction and reach their maximum levels in winter. Available limits under the line-of-credit agreements for the remaining term are as follows:


Effective	Available Line of Credit
September 30, 2004	$	24,000,000
November 2, 2004		21,000,000
November 16, 2004		25,000,000
February 16, 2005		20,000,000

A summary of short-term lines-of-credit follows:


	2004			2003			2002
Lines of credit at year-end	$	24,000,000		$	28,000,000		$	20,500,000
Outstanding balance at year-end		12,742,000			12,992,000			8,991,000
Highest month-end balances outstanding		20,904,000			20,184,000			21,236,000
Average month-end balances		10,559,000			10,104,000			13,669,000
Average rates of interest during year		1.79	%		1.99	%		2.46	%
Average rates of interest on balances outstanding at year-end		2.40	%		1.70	%		2.38	%

- 20 -

7.	LONG-TERM DEBT

Long-term debt consists of the following:


	September 30
	2004			2003
Roanoke Gas Company:
First Mortgage notes payable, at 7.804%, due July 1, 2008	$	5,000,000		$	5,000,000
Collateralized term debentures with provision for retirement in varying annual payments through October 1, 2016, at interest rates ranging from 9.20% to 9.625%		3,000,000			4,000,000
Unsecured senior notes payable, at 7.66%, with provision for retirement of $1,600,000 each year beginning December 1, 2014 through December 1, 2018		8,000,000			8,000,000
Obligations under capital leases, aggregate monthly payments of $2,924, through April 2005		19,987			52,359
Unsecured note payable, with variable interest rate based on 30-day LIBOR (1.84% at September 30, 2004) plus 100 basis point spread, with provision for retirement on November 30, 2005.		8,000,000			8,000,000
Bluefield Gas Company:
Unsecured note payable, at 7.28%, with provision for retirement of $25,000 quarterly, beginning January 1, 2002 and a final payment of $1,125,000 on October 1, 2003		—			1,125,000
Unsecured note payable with variable interest rate based on 30-day LIBOR (1.84% at September 30, 2004) plus 113 basis point spread, due November 21, 2005		2,000,000			—
Highland Propane Company:
Unsecured note payable, with variable interest rate based on 90-day LIBOR plus 95 basis point spread, retired July 2004		—			2,500,000
Unsecured note payable, at 7%, retired July 2004		—			1,700,000
Line-of-credit		—			875,000

Total long-term debt		26,019,987			31,252,359
Less current maturities		(19,987	)		(1,032,372	)

Total long-term debt—excluding current maturities	$	26,000,000		$	30,219,987

The above debt obligations contain various provisions, including a minimum interest charge coverage ratio and limitations on debt as a percentage of total capitalization. The obligations also contain a provision restricting the payment of dividends, primarily based on the earnings of the Company and dividends previously paid. The Company was in compliance with these provisions at September 30, 2004 and 2003. At September 30, 2004, approximately $6,775,000 of retained earnings were available for dividends.

On October 1, 2003, the Company entered into a $2,000,000 unsecured note payable, which refinanced $1,125,000 of current maturities on other long-term debt obligations and $875,000 of line-of-credit balances. The unsecured note payable pays a variable interest rate based on the 30-day LIBOR plus 113 basis point spread and is due on November 21, 2005.

- 21 -

The aggregate annual maturities of long-term debt, subsequent to September 30, 2004, are as follows:


Years Ended September 30
2005	$	19,987
2006		10,000,000
2007		—
2008		5,000,000
2009		—
Thereafter		11,000,000

Total	$	26,019,987

8.	INCOME TAXES

The details of income tax expense (benefit) are as follows:


	Years Ended September 30
	2004			2003			2002
Current income taxes:
Federal	$	179,253		$	396,468		$	(250,156	)
State		285,478			122,044			73,247

Total current income taxes		464,731			518,512			(176,909	)

Deferred income taxes:
Federal		885,112			615,585			1,245,946
State		(91,757	)		69,486			110,423

Total deferred income taxes		793,355			685,071			1,356,369

Amortization of investment tax credits		(34,138	)		(34,206	)		(34,378	)

Total income tax expense	$	1,223,948		$	1,169,377		$	1,145,082

- 22 -

Income tax expense for the years ended September 30, 2004, 2003 and 2002 differed from amounts computed by applying the U.S. federal income tax rate of 35%, 34% and 34%, respectively, to earnings before income taxes as a result of the following:


	Years Ended September 30
	2004			2003			2002
Income before income taxes	$	3,290,750		$	3,168,156		$	3,081,238

Income tax expense computed at statutory rate of 35% in 2004 and 34% in 2003 and 2002	$	1,151,762		$	1,077,173		$	1,047,621
Increase (reduction) in income tax expense resulting from:
State income taxes, net of federal income tax benefit		125,919			126,410			121,222
Amortization of investment tax credits		(34,138	)		(34,206	)		(34,378	)
Other, net		(19,595	)		—			10,617

Total income tax expense	$	1,223,948		$	1,169,377		$	1,145,082

The tax effects of temporary differences that give rise to the deferred tax assets and deferred tax liabilities are as follows:


	September 30
	2004			2003
Deferred tax assets:
Allowance for uncollectibles	$	14,745		$	122,484
Accrued medical insurance		131,046			173,553
Accrued pension and medical benefits		1,591,655			1,565,853
Accrued vacation		187,682			193,861
Over (under) recovery of gas costs		593,651			156,436
Costs of gas held in storage		720,449			728,348
Valuation allowance		(24,488	)		—
Other		286,856			348,307

Total deferred tax assets		3,501,596			3,288,842

Deferred tax liabilities:
Utility plant basis differences		6,858,145			7,141,324

Total deferred tax liabilities		6,858,145			7,141,324

Net deferred tax liability	$	3,356,549		$	3,852,482

The Company recorded a valuation allowance to reflect the estimated amount of deferred tax assets associated with Diversified’s operation in West Virginia, which may not be realized due to the uncertain availability of future taxable income. As Diversified files a stand alone state income tax return in West Virginia, the sale of propane assets eliminated any future West Virginia taxable income. As the Company files a consolidated federal income tax return, management expects to be able to fully realize the federal portion of the deferred tax asset.

- 23 -

9.	EMPLOYEE BENEFIT PLANS

The Company has a defined benefit pension plan and a postretirement plan. The defined benefit plan covers substantially all employees and fully vests after five years of credited service. Benefits paid to retirees are based on age at retirement, years of service and average compensation. The postretirement benefit plan provides certain healthcare, supplemental retirement and life insurance benefits to active and retired employees who meet specific age and service requirements. The Company uses a June 30 measurement date for both of these plans. The following tables set forth the benefit obligation, fair value of plan assets, and the funded status of the Plans; amounts recognized in the Company’s financial statements and the assumptions used:


	Pension Benefits						Postretirement Benefits
	2004			2003			2004			2003
Change in benefit obligation:
Benefit obligation at beginning of year	$	10,457,455		$	8,835,323		$	9,350,513		$	8,158,724
Service cost		381,588			300,867			192,088			171,508
Interest cost		613,397			602,282			528,218			555,424
Participant contributions		—			—			49,065			34,768
Actuarial (gain) loss		(509,059	)		1,147,934			(1,161,957	)		852,318
Recognition of Medicare Part D subsidy		—			—			(1,164,146	)		—
Benefit payments		(435,379	)		(428,951	)		(444,055	)		(422,229	)

Benefit obligation at end of year	$	10,508,002		$	10,457,455		$	7,349,726		$	9,350,513

Change in plan assets:
Fair value of plan assets at beginning of year	$	6,589,170		$	6,511,141		$	2,536,425		$	2,272,137
Actual return on plan assets		769,026			200,827			385,124			89,749
Employer contributions		800,000			306,153			709,000			562,000
Participant contributions		—			—			49,065			34,768
Tax payments		—			—			(50,000	)		—
Benefit payments		(435,379	)		(428,951	)		(444,055	)		(422,229	)

Fair value of plan assets at end of year	$	7,722,817		$	6,589,170		$	3,185,559		$	2,536,425

Reconciliation of funded status:
Funded status	$	(2,785,185	)	$	(3,868,285	)	$	(4,164,167	)	$	(6,814,088	)
Unrecognized actuarial gain (loss)		1,677,521			2,570,757			(89,139	)		2,529,210
Unrecognized transition obligation		—			—			2,135,700			2,373,000
Contributions made between the measurement date and fiscal year-end		150,000			110,000			772,000			709,000

Accrued benefit cost	$	(957,664	)	$	(1,187,528	)	$	(1,345,606	)	$	(1,202,878	)

The Company amortizes the unrecognized transition obligation over 20 years.

- 24 -

The following table details the weighted-average actuarial assumptions used in determining the projected benefit obligation and net benefit cost of the pension and other postretirement plan for 2004, 2003 and 2002:


	Pension Benefits						Postretirement Benefits
	2004		2003		2002		2004		2003		2002
Assumptions related to benefit obligations:
Discount rate	6.25	%	6.00	%	N/A		6.25	%	6.00	%	N/A
Expected rate of compensation increase	5.00	%	5.00	%	N/A		N/A		N/A		N/A

Assumptions related to benefit costs:
Discount rate	6.00	%	7.00	%	7.25	%	6.00	%	7.00	%	7.25	%
Expected long-term rate of return on plan assets	8.00	%	8.00	%	8.50	%	7.00	%	7.00	%	7.00	%
Expected rate of compensation increase	5.00	%	5.00	%	5.00	%	N/A		N/A		N/A

To develop the expected long-term rate of return on assets assumption, the Company considered the historical returns and the future expectations for returns for each asset class, as well as the target asset allocation of each plan’s portfolio. This resulted in the selection of the corresponding long-term rate of return assumptions used for each plan’s assets.


	Pension Plan									Postretirement Plan
	2004			2003			2002			2004			2003			2002
Components of net periodic benefit cost:
Service cost	$	381,588		$	300,867		$	228,710		$	192,088		$	171,508		$	155,451
Interest cost		613,397			602,282			568,557			528,218			555,424			501,320
Expected return on plan assets		(508,401	)		(510,138	)		(612,876	)		(134,519	)		(121,640	)		(147,312	)
Amortization of unrecognized transition obligation		—			1,133			4,931			237,300			237,300			237,300
Prior service cost recognized		—			—			7			—			—			—
Recognized loss		123,553			23,425			—			91,641			59,908			—

Net periodic benefit cost	$	610,137		$	417,569		$	189,329		$	914,728		$	902,500		$	746,759

The net periodic costs for postretirement benefits decreased during the fiscal year ended September 30, 2004 due to the implementation of FASB Staff Position 106-2. See discussion in Note 1.

- 25 -

Actuarial estimates for the postretirement benefit plan assumed a weighted average annual rate increase in the per capita cost of covered health care benefits (i.e., medical trend rate) were 10%, 10% and 11% for 2004, 2003 and 2002, respectively. The rates were assumed to decrease gradually to 5% by the year 2009 and remain at that level thereafter. The medical-trend rate assumption has a significant effect on the amounts reported. For example, a 1% change in the assumed medical-cost trend rate would have the following effects:


	2004			2003
One percentage point increase:
Aggregate of service and interest cost	$	86,495		$	118,991
Accumulated postretirement benefit obligation		871,231			1,298,401

One percentage point decrease:
Aggregate of service and interest cost	$	(69,354	)	$	(94,898	)
Accumulated postretirement benefit obligation		(714,789	)		(1,052,395	)

The accumulated benefit obligation for the defined benefit pension plan was $7,778,749 and $7,806,861 in 2004 and 2003, respectively.

The Company’s target and actual asset allocation in the pension and postretirement benefit plans as of June 30 were:


	Pension Plan			Postretirement Benefit Plan
	Target	2004		Target	2004
Asset category:
Equity securities	50%-70%	66	%	35%-65%	56	%
Debt securities	30%-50%	31	%	35%-65%	41	%
Other	0%-20%	3	%	0%-20%	3	%

The primary objectives of the Company’s investment policies are to maintain investment portfolios that diversify risk through prudent asset allocation parameters, achieve asset returns that meet or exceed the plans’ actuarial assumptions, achieve asset returns that are competitive with like institutions employing similar investment strategies and meet expected future benefits. The investment policies are periodically reviewed by the Company and a third-party fiduciary for investment matters.

The Company expects to contribute $500,000 to its pension plan and $750,000 to its postretirement benefit plan in 2005.

- 26 -

The following table reflects expected future benefit payments.


Fiscal year ending September 30	Pension Plan		Postretirement Benefit Plan
2005	$	433,866	$	482,894
2006		428,571		462,604
2007		434,338		425,793
2008		441,429		439,714
2009		449,262		457,235
2010-2014		2,593,280		2,411,853

The Company also sponsors a defined contribution plan/401k (“Plan”) covering all of its employees who elect to participate. Employees may contribute from 1% to 50% of their annual compensation to the Plan, limited to a maximum annual amount as set periodically by the Internal Revenue Service. The Company made annual matching contributions to the plan for fiscal years ended September 30, 2003 and 2002 and through December 31, 2003, based on 70% of the net participants’ first 6% in contributions. Beginning in January 2004, that matching formula changed to match 100% on the participants’ first 3% of contributions and 50% on the next 3% of contributions. Company matching contributions were $254,121, $228,737 and $227,403 for 2004, 2003 and 2002, respectively.

10.

COMMON STOCK OPTIONS

The Company’s stockholders approved the RGC Resources, Inc. Key Employee Stock Option Plan (“KESOP”). KESOP provides for the issuance of common stock options to officers and certain other full-time salaried employees to acquire a maximum of 100,000 shares of the Company’s common stock. The KESOP requires each option’s exercise price per share to equal the fair value of the Company’s common stock as of the date of the grant. As of September 30, 2004, the number of shares available for future grants under the KESOP is 2,000 shares.

- 27 -

The aggregate number of shares under option pursuant to the RGC Resources, Inc. Key Employee Stock Option Plan are as follows:


	Number of Shares		Weighted- Average Exercise Price		Option Price Per Share
Options outstanding, September 30, 2001	72,000		$	19.135	$	15.500-$20.875
Options granted	13,000			19.360
Options exercised	(13,500	)
Options expired	(11,500	)


Options outstanding, September 30, 2002	60,000		$	19.319	$	15.500-$20.875
Options granted	13,500			18.100
Options exercised	—
Options expired	(2,000	)


Options outstanding, September 30, 2003	71,500		$	19.049	$	15.500-$20.875
Options exercised	(18,000	)
Options expired	—


Options outstanding, September 30, 2004	53,500		$	19.288	$	15.500-$20.875


	Shares	Remaining Life (Years)	Exercise Price
	2,500	1.1	$	15.500
	4,000	2.1		16.875
	8,500	3.3		20.625
	11,000	5.2		20.875
	9,000	6.2		19.250
	10,000	7.2		19.360
	8,500	8.2		18.100

Weighted average	53,500	5.5	$	19.288

Under the terms of the KESOP, the options become exercisable six months from the grant date and expire ten years subsequent to the grant date. All options outstanding were fully vested and exercisable at September 30, 2004 and 2003. No options were granted in 2004.

- 28 -

The per share weighted-average fair values of stock options granted during 2003 and 2002 were $1.82 and $2.17, respectively, on the dates of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions.


	2003		2002
Expected dividend yield	6.30	%	5.89	%
Risk-free interest rate	3.70	%	3.73	%
Expected volatility	26.60	%	22.20	%
Expected life	10 years		10 years

11.

RELATED-PARTY TRANSACTIONS

Certain of the Company’s directors and officers are affiliated with companies that render services or sell products to the Company. Management believes such transactions are entered into on terms equivalent to normal business terms.

The Company purchased beeper, internet and telephone services of approximately $97,000, $91,000 and $83,000 in 2004, 2003 and 2002, respectively. Management anticipates similar services will be provided to the Company in 2005.

The products sold to the Company include propane truck purchases and repair services of approximately $29,000, $40,000 and $210,000 in 2004, 2003 and 2002, respectively. Management does not anticipate that similar services will be provided to the Company in 2005, as most of these expenses were incurred by the discontinued propane operations.

12.

ENVIRONMENTAL MATTER

Both Roanoke Gas Company and Bluefield Gas Company operated manufactured gas plants (“MGPs”) as a source of fuel for lighting and heating until the early 1950’s. A by-product of operating MGPs was coal tar, and the potential exists for on-site tar waste contaminants at the former plant sites. The extent of contaminants at these sites, if any, is unknown at this time. An analysis at the Bluefield Gas Company site indicates some soil contamination. The Company, with concurrence of legal counsel, does not believe any events have occurred requiring regulatory reporting. Further, the Company has not received any notices of violation or liabilities associated with environmental regulations related to the MGP sites and is not aware of any off-site contamination or pollution as a result of prior operations. Therefore, the Company has no plans for subsurface remediation at the MGP sites. Should the Company eventually be required to remediate either site, the Company will pursue all prudent and reasonable means to recover any related costs, including insurance claims and regulatory approval for rate case recognition of expenses associated with any work required. A stipulated rate case agreement between the Company and the West Virginia Public Service Commission recognized the Company’s right to defer MGP clean-up costs, should any be incurred, and to seek rate relief for such costs. If the Company eventually incurs costs associated with a required clean up of either MGP site, the Company anticipates recording a regulatory asset for such clean-up costs to be recovered in future rates. Based on anticipated regulatory actions and current practices, management believes that any costs incurred related to this matter will not have a material effect on the Company’s financial condition or results of operations.

- 29 -

13.

COMMITMENTS

Due to the nature of the natural gas distribution business, the Company has entered into agreements with both suppliers and pipelines to contract for natural gas commodity purchases, storage capacity and pipeline delivery capacity.

The Company obtains most of its regulated natural gas supply from its asset manager from the contract effective November 1,2001, between the Company and a third party (“counter-party”). The counterparty has also assumed the management and financial obligation of the Company’s firm transportation and storage agreements. Under the agreement, the Company exchanged gas in storage at November 1, 2001 for the right to receive from the counter-party an equal amount of gas in the future as provided by the agreement. Under this arrangement, the Company has an obligation to prepay for a specified level of gas at market prices to be used during the winter months. This contract expired on October 31, 2004.

Highland Energy, the unregulated energy marketing company, also contracts for the purchase of natural gas from suppliers for future deliveries. These commitments generally are for fixed volumes at fixed prices for the upcoming year.

The Company has contracts for pipeline and storage capacity extending for various periods. These capacity costs and related fees are valued at tariff rates in place as of September 30, 2004. These rates may increase or decrease in the future based upon rate filings and rate orders granting a rate change to the pipeline or storage operator.

The following schedule reflects the financial and volumetric obligations as of September 30, 2004 for each of the years presented:


	Fixed Price Contracts				Market Price Contracts
	Pipeline and Storage Capacity		Natural Gas Contracts		Natural Gas Contracts (Dekatherms)
2005	$	11,045,973	$	5,714,729	409,425
2006		11,048,460		64,750	—
2007		11,048,460		—	—
2008		10,799,805		—	—
2009		10,799,805		—	—
2010-2020		64,589,148		—	—

Management does not anticipate that these contracts will have a material impact on the Company’s fiscal year 2004, 2005 or 2006 and thereafter consolidated results of operations.

The Company has historically entered into derivative financial contracts for the purpose of hedging the price of natural gas. As of September 30, 2004, the Company had no outstanding derivative contracts for natural gas.

- 30 -

In November 2004, the Company entered into a new asset management agreement requiring the scheduled payment for storage gas purchases over the next three years. The following schedule reflects the obligations for the contracts executed subsequent to September 30, 2004:


Fiscal Year Ended September 30		Market Price Contracts
Fiscal Year Ended September 30		Natural Gas Contracts (Dekatherms)
2005		2,031,150
2006		2,369,675
2007		2,369,675
2008		338,525

14.

FAIR VALUE OF FINANCIAL INSTRUMENTS

The carrying amount of cash and cash equivalents, short-term cash investments and borrowings under lines of credit are a reasonable estimate of fair value due to their short-term nature and because the rates of interest paid on borrowings under lines of credit approximate market rates.

The fair value of long-term debt is estimated by discounting the future cash flows of each issuance at rates currently offered to the Company for similar debt instruments of comparable maturities. The carrying amounts and approximate fair values for the years ended September 30, 2004 and 2003 are as follows:


	2004				2003
	Carrying Amounts		Approximate Fair Value		Carrying Amounts		Approximate Fair Value
Long-term debt	$	26,019,987	$	29,302,836	$	31,252,359	$	35,316,240

Judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates determined as of September 30, 2004 and 2003 are not necessarily indicative of the amounts the Company could have realized in current market exchanges.

- 31 -

15.

QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Quarterly financial data for the years ended September 30, 2004 and 2003 is summarized as follows:


2004	First Quarter		Second Quarter		Third Quarter			Fourth Quarter
Operating revenues	$	29,867,898	$	39,721,044	$	18,233,478		$	15,324,644

Operating margin	$	6,733,567	$	8,212,985	$	4,402,763		$	4,043,349

Operating income (loss)	$	2,344,645	$	3,548,755	$	11,530		$	(710,823	)

Net income (loss) from continuing operations	$	1,143,536	$	1,875,448	$	(275,743	)	$	(676,439	)

Net income (loss) from discontinued operations	$	455,867	$	1,272,804	$	(236,921	)	$	9,375,461

Net income (loss)	$	1,599,403	$	3,148,252	$	(512,664	)	$	8,699,022

Basic earnings (loss) per share:
Continuing operations	$	0.57	$	0.93	$	(0.13	)	$	(0.35	)
Discontinued operations	$	0.23	$	0.63	$	(0.12	)	$	4.62

Net income (loss)	$	0.80	$	1.56	$	(0.25	)	$	4.27


2003	First Quarter		Second Quarter		Third Quarter			Fourth Quarter
Operating revenues	$	23,949,916	$	33,564,882	$	17,797,875		$	13,521,280

Operating margin	$	6,293,405	$	7,752,382	$	4,212,519		$	3,659,919

Operating income (loss)	$	2,064,547	$	3,252,546	$	40,799		$	(74,030	)

Net income (loss) from continuing operations	$	941,848	$	1,672,395	$	(276,461	)	$	(339,003	)

Net income (loss) from discontinued operations	$	596,289	$	1,468,558	$	(285,946	)	$	(249,291	)

Net income (loss)	$	1,538,137	$	3,140,953	$	(562,407	)	$	(588,294	)

Basic earnings (loss) per share:
Continuing operations	$	0.48	$	0.85	$	(0.14	)	$	(0.18	)
Discontinued operations	$	0.30	$	0.74	$	(0.14	)	$	(0.13	)

Net income (loss)	$	0.78	$	1.59	$	(0.28	)	$	(0.31	)

The pattern of quarterly earnings is the result of the highly seasonal nature of the business, as variations in weather conditions generally result in greater earnings during the winter months.

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