Edgar Filing: RGC RESOURCES INC

2003 Annual Report To Shareholders

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Who We Are

RGC Resources provides superior customer and shareholder value as a preferred provider of energy and diversified products and services in its selected market areas.

Products and Markets

Product	Division	Market	Territory
Natural Gas	Roanoke Gas & Bluefield Gas	Natural gas sales & service	Parts of Virginia & West Virginia

Propane	Highland Propane	Propane sales & service	Virginia & West Virginia

Computer Services	Application Resources	Information system services	National

Financial Highlights

Years Ended September 30,	2003		2002		2001

Operating Revenue - Natural Gas	$	75,321,337	$	57,647,947	$	86,195,121

Operating Revenue - Propane	$	15,211,015	$	10,718,404	$	14,929,570

Energy Marketing Revenue	$	13,091,137	$	11,107,532	$	14,756,066

Other Revenue	$	738,070	$	751,790	$	1,562,390

Net Income	$	3,528,389	$	2,486,895	$	2,306,615

Basic Earnings Per Share	$	1.78	$	1.28	$	1.21	*

Dividend Per Share - Cash	$	1.14	$	1.14	$	1.12

Number of Customers - Natural Gas		57,691		57,229		56,770

Number of Customers - Propane		18,105		18,156		17,105

Total Natural Gas Deliveries - DTH		12,041,193		10,563,514		11,890,227

Total Propane Sales - Gallons		10,655,557		8,856,086		10,174,329

Total Additions to plant	$	8,347,654	$	8,614,454	$	8,029,853

*	Reflects $.32 per share impairment loss.

To Our Shareholders:

I am pleased to report company earnings of $3.5 million, or $1.77 per diluted share, exceeding last year per share results by 38%, and our best ever performance. Fiscal year heating degree days were 3% greater than the 30-year average and 24% greater than last year. Our natural gas deliveries increased by 1,478,000 decatherms, or 14%, and our propane deliveries increased by 1,799,000 gallons, just over 20%. Total revenue was $104 million with $75 million or 72% coming from regulated natural gas utility sales and deliveries. The remaining 28% were from non-utility operations, primarily sales of propane and non-regulated natural gas sales to large industrial customers.

I am also pleased that during a period when many energy and utility companies have lingering credit concerns and are heavily debt leveraged, we are operating with a strong balance sheet. Total assets at year end were $100.5 million, of which $71.8 million was in the form of net plant, $16.2 million was in the form of prepaid and inventory gas, and the remaining $12.5 million was primarily in the form of receivables from customers and other prepaid charges. Our long term capital structure at the fiscal year end was composed of 48% long-term debt and 52% owners’ equity. During the year, shareholders participating in the Company’s dividend reinvestment and stock purchase plan elected to reinvest 17% of dividend distributions to purchase new shares of common stock.

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During the year, the Company invested $8.3 million in a variety of capital projects. Funding for these projects was provided from the proceeds from stock sales, retained earnings, depreciation derived cash flow and modestly increased borrowings. Approximately $6.7 million was invested in natural gas distribution facilities and $1.6 million in propane distribution and delivery facilities and equipment. The Company’s largest single new investment project was the construction of 2.5 miles of high pressure gas pipeline to establish a new connection with the East Tennessee Natural Gas Pipeline. Our new pipeline will provide additional natural gas supplies into the western portion of the Roanoke Gas Company distribution system. The Company’s largest single renewal project was the replacement of 2 miles of bare steel pipe with new plastic pipe associated with the City of Roanoke’s upgrade to a commercial section of Route 11.

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To ensure the timely recovery of increased depreciation and carrying costs associated with increased investment in natural gas plant, rate increase applications were filed with the utility regulatory commissions in Virginia and West Virginia. In addition to recovering the costs associated with new plant investment, the filed rate increase requests are designed to recover increasing costs associated with employee health care and other insurance and benefit coverages.

Customer growth for the year was very modest associated with a still somewhat sluggish economy for most of the fiscal year, loss of delinquent customers due to service termination for non-payment of bills, and our purposeful restructuring of service and pricing for low volume propane customers. We discontinued service to approximately 350 propane customers because their annual consumption had declined to the point it would not justify the Company’s continued investment in the tanks and equipment needed to maintain service. In addition, over 500 low usage customers purchased their propane tanks from the Company as a way of ensuring continued delivery service by lowering the Company’s costs to serve these customers. While we regret the need to discontinue service to some customers, I believe it was the appropriate economic decision. We will continue to evaluate our customers’ usage in the future to ensure that we are providing both reliable and profitable service to all of our customers.

Natural gas and propane commodity prices have been at unusually high levels over the last several months, and we will enter the 2003-2004 heating season with the highest embedded prepaid and inventory gas costs in history, as will the rest of the natural gas distribution utility industry. I believe the recent elevated natural gas and propane prices are the result of the accumulated impact of years of incongruent regulatory policy and the continued failure of Congress and the last two Presidential administrations to develop balanced national energy use and resource development legislation and regulation. For over a decade, environmentalists, federal regulators and in some cases, the natural gas industry itself, have promoted the use of natural gas as a more environmentally friendly way to meet the growing demand for additional electricity generation.

I believe it is a wasteful use of resources to burn natural gas to generate electricity because of the inefficiency in conversion of fossil fuel energy to electricity. The typical natural gas electric generating units have an energy conversion rate of about 50%. By contrast, natural gas delivered by pipeline to the end users results in over 90% of the energy value reaching the consumer. In spite of this obvious inefficient use of a clean, reliable and economic fuel, the electric industry, with the encouragement of regulators, plunged headlong into a natural gas based electricity supply program.

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The increasing use of natural gas to generate more electricity, when combined with incompatible regulations for limiting access to new natural gas supply, is creating a growing natural gas supply/demand imbalance. One set of environmental policies is driving up the demand for natural gas, while other environmental policies are simultaneously severely limiting development of adequate natural gas supplies. The resulting impact on price is clear and is being reflected in current natural gas utility billing rates.

For over a decade, environmentalists, federal regulators and in some cases, the natural gas industry itself, have promoted the use of natural gas as a more environmentally friendly way to meet the growing demand for additional electricity generation.

The American Gas Association has been urging Congress to adopt comprehensive energy legislation for the last three years. Congress once again failed to pass an energy bill in the closing weeks of 2003. Regardless of the provisions of a potential future energy bill, it will likely take several years before the supply and access enhancement provisions of the legislation result in significant increases in available energy supplies and material mitigation of the supply and demand imbalance. The severity of winter weather and the rate of economic recovery will be the major determinants on demand and the resulting pricing pressures in the short run.

While I remain concerned about the impact of higher energy costs on our customers and on the nation’s economic recovery, I believe RGC Resources has planned for adequate supply for our customer needs for the coming winter. In addition, we have largely hedged against significant further escalation of prices in the near term. We have fixed or capped the price for approximately 75% of the projected winter volumes of natural gas demand for our residential and commercial customers. In addition, we have fixed or capped the price of approximately 60% of the projected winter volume demand for our propane customers.

We continue to work with the changing regulations associated with the Sarbanes-Oxley federal legislation adopted in July of 2002 and the various implementation phases expected to occur through the year 2005 as promulgated by the Securities and Exchange Commission. We have developed and adopted an updated code of ethics for our directors, officers and employees, as well as an updated Audit Committee charter and new Audit Committee guidelines. We are governed by a nine member board of directors who met 10 times during the last fiscal year. With the exception of myself, all of the members of the Board are “independent directors”, while all of the members of the Audit and Compensation Committees of the Board are independent directors. We continue to use Deloitte and Touche as our external auditor. We believe we are complying with both the spirit and the letter of the new regulations for publicly traded companies. Howard Lyon, our Controller and Vice President, and I have been formally certifying as to the accuracy of our reported financial statements for the past five quarters.

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I believe the recent federal tax relief and economic stimulus legislation passed by Congress and signed by President Bush has had a positive impact on our shareholders and our Company. The maximum tax rate on corporate dividends paid to individual shareholders was reduced from 38% to 15%. It appears this tax law changed combined with our improved earnings performance facilitated the achievement of a new all-time high stock price of $25.50 per share in May of 2003, up from a stock price of approximately $18 in early January 2003. On September 30, the stock price closed at $22.85 per share. At that price, the current annual dividend yield on the Company’s stock is 5%. In addition to a lower tax rate on dividends, the tax bill increased the amount of first year depreciation expense allowed for federal income tax purposes on new plant investment which will accelerate our capital recovery of investment in new and replacement natural gas pipelines.

We have developed and adopted an updated code of ethics for our directors, officers and employees, as well as an updated Audit Committee charter and new Audit Committee guidelines.

It continues to be an exciting and challenging time to lead a publicly traded energy distribution company. I am very appreciative of the hard work and dedication of our capable employees and our talented Board of Directors. I am also appreciative of the cooperative working relationship we have with our state regulatory bodies who are partners in our work to provide safe, reliable and equitably priced natural gas utility services. At a time when we all need to show continued pride in our nation, our way of life, and our citizens and neighbors in the armed services, I am also proud to be associated with the fine people that help make RGC Resources successful.

I thank you for continuing to be an owner of what I believe is a great company. If you are not participating in our dividend reinvestment and stock purchase plan and would like to do so, please call us at 540-777-3853 and ask for a prospectus.

Sincerely,

/s/ John B. Williamson, III

John B. Williamson, III

Chairman, President and CEO

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Officers and Directors

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

President,

Application Resources Operations ⁽⁴⁾

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, Inc.

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) (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 Schockley, 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, Inc. & RGC Ventures of Virginia, Inc.

⁽⁵⁾	Bluefield Gas Company

Did You Know ~ RGC Resources has paid a consecutive quarterly dividend for nearly 60 years!

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Selected Financial Data

Years Ended September 30,	2003		2002		2001			2000		1999
Operating Revenues	$	104,361,559	$	80,225,673	$	117,443,147		$	77,749,995	$	64,202,709
Operating Margin		29,724,714		24,831,089		28,173,186			26,040,519		23,892,521
Operating Income		8,064,174		6,136,417		6,728,633			6,915,177		6,649,827
Net Income		3,528,389		2,486,895		2,306,615			2,873,702		2,883,407
Basic Earnings Per Share		1.78		1.28		1.21	*		1.54		1.59

Cash Dividends Declared Per Share		1.14		1.14		1.12			1.10		1.08
Book Value Per Share		16.90		16.36		16.05			15.94		15.36
Average Shares Outstanding		1,983,970		1,939,511		1,898,697			1,863,275		1,814,864
Total Assets		100,497,399		92,401,455		93,571,129			87,407,494		77,789,982

Long-Term Debt (Less Current Portion)		30,219,987		30,377,358		22,507,485			23,310,522		23,336,614
Stockholders’ Equity		33,857,614		32,068,997		30,725,072			29,985,871		28,154,923
Shares Outstanding at Sept. 30		2,003,232		1,960,418		1,914,603			1,881,733		1,832,771

*	Reflects $.32 per share impairment loss.

Forward-Looking Statements

From time to time, 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 and propane; (v) uncertainty in the projected rate of growth of natural gas and propane 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 and cost of compliance; (xii) impact of potential increased governmental oversight and compliance costs due to the Sarbanes-Oxley law; (xiii) cost and availability of property and liability insurance in the wake of terrorism concerns and corporate failures; (xiv) ability to raise debt or equity capital in the wake of recent corporate financial irregularities; (xv) impact of uncertainties in the Middle East, 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. We assume no duty to update these statements should expectations change or actual results differ from current expectations.

Management’s Discussion & Analysis

General

RGC Resources, Inc. is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately 57,700 residential, commercial and industrial customers in Roanoke, Virginia and 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 are exclusive and are of perpetual duration.

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RGC Resources, Inc. also provides unregulated energy products through Diversified Energy Company, which operates as Highland Propane Company and Highland Energy Company. Highland Propane sells and distributes propane to approximately 18,100 customers in western Virginia and southern West Virginia. Highland Energy brokers natural gas to several industrial transportation customers of Roanoke Gas Company and Bluefield Gas Company. Although the propane and 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. Propane sales have become a significant portion of the consolidated operation.

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.

For the fiscal year ended September 30, 2003, the Company experienced increased sales volumes due to colder winter weather, benefited from realized gains on propane derivative contracts and implemented a new rate structure in the regulated natural gas operations. These items more than offset the impact rising energy prices had on bad debt expense and the increases in other expenses due to the colder weather and increased insurance and benefit costs, resulting in significantly improved earnings compared to last year.

Results of Operations

Fiscal Year 2003 Compared With Fiscal Year 2002

Operating Revenues – Total operating revenue increased $24,135,886, or 30.1%, 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 and propane increased by 17 percent and 13 percent, respectively.

Operating Margin - Total operating margin increased $4,893,625, or 19.7%, for fiscal 2003 compared to the same period last year. The table below reflects volume activity and heating degree-days.

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	%
Transported 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	%
Propane - Gallons	10,655,557	8,856,086	1,799,471		20.3	%
Highland Energy - DTH	2,301,086	2,437,664	(136,578	)	-5.6	%
Heating Degree Days - Unofficial	4,349	3,502	847		24.2	%

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. Total delivered natural gas volumes (tariff and transporting) 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 the same period last year; however, fiscal 2003 heating degree days were only 3% higher than the 30 year normal. Interruptible Sales and Transport customers also reflected a combined net increase as an improving economy has led to increased production resulting in higher gas usage for processes.

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, or 5.3%, 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 provides for a different recovery mechanism, which also results 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, 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 will be lower in the second quarter of fiscal 2004 when inventory levels and financing costs are reduced.

Propane margins increased $2,485,554, or 47.7%, as total gallons delivered increased over last year by 1,799,471 gallons, or 20.3%. Several factors contributed to the increase in propane margins. The colder winter generated the increase in gallons delivered and resulted in higher unit margins due to the impact that colder weather had on the sales mix between heating (higher margin) and production (lower margin.) The remainder of the increase is attributable to the benefits realized on propane derivative and fixed price contracts. Propane operations realized $471,184 in additional margin on derivative swap contracts compared to a $178,870 reduction in margin in the prior year due to realized losses under derivative contracts. Due to the volatility in propane prices, management is unable to determine the impact current and future hedges will have on reported results.

Energy marketing margins increased $19,381, or 7.3%, from last year, even though total delivered volumes declined by 136,578 DTH, or 5.6%, from last year 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 last year 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. Management expects energy-marketing margins to return to more historical levels in future periods.

Other margins declined by $5,813, or 1.8%, from the same period last year as the gain from the sale of more than 500 propane tanks to propane customers in the current year nearly offset the earnings on a one-time contract for work performed for another utility in fiscal 2002. The sale of propane tanks derived from the Company’s efforts to improve profitability on its underperforming accounts by implementing additional tank rent or selling the propane tank to the customer. This process has resulted in the loss of some customers; however, as these customers were not generating profits for the Company, their departure is not expected to have a negative impact on the overall performance of the propane operations. For the affected customers that remain with the Company, management expects their profitability to improve. The overall result is a small decline in net customers for the year and slower growth in the near future as the Company focuses on adding quality customers that will provide profitable returns.

“It makes me proud to be a part of Roanoke Gas and RGC Resources because of their team spirit and dedication to making this company the dynamic best that it can be.”

Other Operating Expenses – Operations expenses increased $2,357,200, or 21.9%, 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 $580,393 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 30.1% over fiscal 2002, resulting in more customer account balances becoming delinquent and subject to write-off. Furthermore, last year’s 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 SCC, which included a provision for recovery of the amortized expense. Total amortization of the regulatory asset amounted to $88,046 during the current year compared with an expense deferral of $316,966 last year. Employee benefit costs increased $543,341, or 29.4%, 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 $274,317 due to increased demands that the colder winter placed on the operation of the natural gas system and greater propane delivery activity. Corporate property and liability insurance expense increased $140,580 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.

“First and foremost I am proud to be an American and to have the freedom that we have.”

Maintenance expenses increased by $425,994, or 34.2%, 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 the current year 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 next year into the current year.

General taxes increased $170,019, or 11.3%, 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 84,663, or 1.7% due to capital expenditures associated with adding new natural gas customers and replacing older portions of the natural gas distribution system. The level of increase in depreciation has declined from the prior year due to reduced level of growth in the propane operations.

Other deductions increased $118,561, or 113.0%, due to increases in corporate charitable giving and losses recognized on disposal of assets. The rise in charitable giving is 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. The losses realized on assets were associated with the disposal of older, unusable or obsolete equipment.

Interest Expense – Total interest expense for fiscal 2003 increased $121,588, or 5.9%, from fiscal 2002 on an increase of 8.6% 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	26,402,192		19,729,589		6,672,603		33.8	%
Long-term Variable Rate Debt	2,500,000		2,500,000		0		0.0	%
Short-term Variable Rate Debt	9,085,351		12,751,542		(3,666,191	)	-28.8	%
Total Variable Rate Debt	11,585,351		15,251,542		(3,666,191	)	-24.0	%
Total Debt	37,987,543		34,981,131		3,006,412		8.6	%
Average Interest Rate:
Long-term Fixed Rate Debt	7.13	%	8.10	%	-0.97	%	-12.0	%
Variable Rate Debt	2.10	%	2.59	%	-0.49	%	-18.9	%

Variable rate debt amounted to 30.5% and 43.6% of the total average debt outstanding during fiscal 2003 and 2002, respectively. The downward trend in interest rates kept interest expense from rising at the same rate as the increase in debt. The average effective interest rate on the Company’s variable rate debt declined from 2.59% in 2002 to 2.10% in 2003. The level of variable rate debt declined due to the $8,000,000 intermediate term note issued in November 2002, which served to refinance a portion of the line-of-credit balances. Although the note was variable rate, it was converted to a fixed rate of 4.18% through an interest rate swap. Higher accounts receivable balances and natural gas inventories/prepayments due to rising gas costs necessitated the need for higher debt levels.

Income Taxes – Income tax expense increased $646,114, or 43.3% from last year as pre-tax earnings increased by more than 42%.

Net Income and Dividends - Net income for fiscal 2003 was $3,528,389 as compared to fiscal 2002 net income of $2,486,895. Net income improved over last year due to significantly greater natural gas and propane sales attributable to the much colder winter weather. Basic and diluted earnings per share of common stock were $1.78 and $1.77 in fiscal 2003 compared with $1.28 and $1.28 in fiscal 2002, respectively. Dividends per share of common stock were $1.14 in fiscal 2003 and 2002.

Fiscal Year 2002 Compared With Fiscal Year 2001

Operating Revenues – Total operating revenue declined $37,217,474, or 31.7%, for the year ended September 30, 2002 (fiscal 2002) compared to the year ended September 30, 2001(fiscal 2001). The reduction in revenues resulted from a combination of much lower energy costs and lower sales volume attributable to significantly warmer weather. As the cost of energy represents well over 50 percent of the average sales price on natural gas and propane gas, significant changes in the cost of energy have a corresponding impact on total energy revenues.

Operating Margin - Total operating margin decreased by $3,342,097, or 11.9%, for fiscal 2002 compared to fiscal 2001. The table below reflects volume activity and heating degree-days.

Volume Summary

Year Ended September 30	2002	2001	Increase/ (Decrease)		Percentage
Regulated Natural Gas - DTH:
Residential and Commercial	7,499,603	8,863,810	(1,364,207	)	-15.4	%
Interruptible Sales Service	156,923	192,659	(35,736	)	-18.5	%
Transported Volumes	2,906,988	2,833,758	73,230		2.6	%

Total Delivered Volumes – DTH	10,563,514	11,890,227	(1,326,713	)	-11.2	%
Propane – Gallons	8,856,086	10,174,329	(1,318,243	)	-13.0	%
Energy Marketing - DTH	2,437,664	2,431,943	5,721		0.2	%
Heating Degree Days	3,502	4,342	(840	)	-19.3	%

Natural gas margins decreased $1,936,166, or 9.2%, as total delivered natural gas volumes (firm sales and transportation) declined by 11.2% from fiscal 2001 levels. Residential and commercial firm sales volumes decreased by 15.4% while transportation volumes increased slightly by 2.6%. The decrease in residential and commercial sales volume related directly to weather that was 19.3% warmer than fiscal 2001 and 16.8% warmer than the 30-year normal. The increase in transportation volumes related to the resumption of natural gas usage by those industrial customers that switched fuel during fiscal 2001 winter months as a result of the high cost on natural gas. However, during the last few months of fiscal year 2002, transportation volumes lagged fiscal 2001 volumes due to the economic slow-down in some of the industrial sectors.

Propane margins decreased $1,044,253, or 16.7%, as total gallons delivered declined from last year by 1,318,243 gallons, or 13.0%. The decrease in gallons delivered corresponded to significantly warmer winter weather. Net realized losses of $178,870 on derivative contracts during the year compared with a net realized derivative benefit of $153,169 realized during fiscal 2001 also negatively affected the change in margins. The Company continued to experience competition from other propane vendors in the Company’s service territory; however, customer base continued to grow with the net addition of more than 1,000 customers during fiscal 2002.

Energy marketing margins declined $259,298, or 49.4%, as total dekatherms delivered were virtually unchanged from fiscal 2001. In fiscal 2002, Highland Energy realized a one-time gain of $78,600 related to the sale of a fixed-price contract for the purchase of 120,000 dekatherms of natural gas. In fiscal 2001, however, Highland Energy benefited from another fixed price natural gas contract, which provided a much greater contribution to margins than the sale of the fixed price contract in fiscal 2002. The contract locked-in the purchase price of natural gas significantly below the high winter spot-market prices of early 2001. The lower priced gas benefited both the energy marketing division and its customers during the winter months by allowing the Company to boost unit margins and provide its customers with energy at below market prices. Energy-marketing margins were expected to return to normal levels of approximately $0.05 to $0.07 per dekatherm.

Other margins declined $102,380, or 23.8%, from fiscal 2001 as a result of minimal activity in the heating and air conditioning operations and significantly reduced work levels for Application Resources, Inc. due to the current business environment. Service margins related to work performed through the natural gas and propane operations showed strong growth with a 37.3% increase. Most of the increase, however, related to earnings on a one-time contract that was more than 80% complete as of the end of the fiscal year.

Other Operating Expenses – Operations and maintenance expenses declined by $1,569,554, or 11.6%, in fiscal 2002 compared with fiscal 2001. Operations expenses decreased $1,418,271. Most of this decrease related to reductions in bad debt expense across all segments of the Company, partially offset by increases in employee benefits and corporate property and liability insurance premiums. The reduction in bad debt expense was attributable to significantly lower gross revenues, improved collection results on prior bad debts and the recording of a regulatory asset resulting from an agreement with the regulatory staff of the SCC of Virginia. Warmer winter weather resulted in lower gross revenues and reduced total sales volumes of both propane and natural gas and also allowed wholesale energy prices to remain stable and less volatile compared to the high prices in fiscal 2001. Fiscal 2001’s high-energy prices and cold weather combined to generate high energy bills for our customers. These extremely high customer bills, combined with regulatory restrictions during last year’s winter months, which limited the periods when customers could be disconnected for nonpayment, enabled delinquent balances to build to high levels in fiscal 2001. During fiscal 2002, the warm winter reduced sales volumes, better enabled customers to pay their bills and provided for a more timely disconnect process for delinquent customers. Management increased collection efforts through greater utilization of various legal remedies, including judgements. In addition to improved delinquencies, the agreement with the regulatory staff of the SCC provided for the deferral of incurred bad debt expense in the amount of $316,966 to be amortized over a three-year period beginning in December 2002, coinciding with the anticipated implementation date of new rates associated with the Company’s pending rate filing. The significant reductions in bad debt expense were partially offset by increases in employee benefits and corporate property and liability insurance premiums.

“I feel proud to know that I work with people who are not just acquaintances but, are family in a crisis.”

Maintenance expenses declined by $151,283, or 10.8%, due to the warmer winter requiring less maintenance and a shift in the Company’s focus from general maintenance to system renewal and expansion. This change in emphasis resulted in the capitalization of a greater amount of Company labor and corresponding benefits compared to fiscal 2001. All critical maintenance continued to be performed, while certain routine maintenance items had been reduced. Management expected maintenance expenses to return to 2001 levels in 2003, although the focus away from routine maintenance could result in additional maintenance costs in future periods.

General taxes decreased $838,929, or 35.8%, in fiscal 2002 compared to fiscal 2001 primarily as a result of the elimination of state and local gross receipts tax on Virginia public utilities by the Commonwealth of Virginia beginning January 1, 2001. Virginia state and local governments switched from a tax based on gross receipts to a tax based on consumption. The consumption tax is added to customer bills based on the volume of natural gas consumed. Unlike the gross receipts tax, the Company does not include the consumption tax in either operating revenues or general tax expense. This tax is a pass-through from the customer to the Commonwealth of Virginia and the localities in which the utility operates within Virginia. Bluefield Gas Company, which operates in the state of West Virginia, continues to have a gross receipts tax in the form of a business and occupation tax. The business and occupation tax in West Virginia declined as a result of reduced revenues upon which the tax is determined.

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Capital expenditures for adding new customers to the natural gas and propane business and replacing older portions of the natural gas distribution system resulted in depreciation expense increasing by $286,224, or 5.9%.

The Company recognized an impairment loss of $699,630 for the year ended September 30, 2001 related to the restructuring of the Company’s heating and air conditioning operations due to losses. The Company decided to significantly reduce its presence in the heating and air conditioning market. In connection with this restructuring, the Company adjusted the valuation of several assets to estimated net realizable value. These adjustments included the write-off of goodwill and other intangible assets and the write-down of equipment and other assets. In fiscal 2002, the Company completed the disposition of those assets previously written down resulting in an additional $72,008 in realized losses.

Interest Expense – Total interest expense for fiscal 2002 decreased $698,096, or 25.4%, from fiscal 2001 on a reduction of 6.9% in total average debt outstanding during the year.

Debt Summary:

Year Ended September 30,	2002		2001		Increase/ (Decrease)		Percentage
Average Daily Balance:
Long-term Fixed Rate Debt	19,729,589		20,457,534		(727,945	)	-3.6	%
Long-term Variable Rate Debt	2,500,000		2,500,000		0		0.0	%
Short-term Variable Rate Debt	12,751,542		14,598,403		(1,846,861	)	-12.7	%
Total Variable Rate Debt	15,251,542		17,098,403		(1,846,861	)	-10.8	%
Total Debt	34,981,131		37,555,937		(2,574,806	)	-6.9	%
Average Interest Rate:
Long-term Fixed Rate Debt	8.10	%	8.13	%	-0.03	%	-0.4	%
Variable Rate Debt	2.59	%	5.85	%	-3.26	%	-55.7	%

Variable rate debt amounted to 43.6% and 45.5% of the total average debt outstanding during fiscal 2002 and 2001, respectively. Continued declines in interest rates generated most of the reduction in interest expense as the interest rates on the Company’s variable rate debt fell throughout the year. The average effective interest rate on the Company’s variable rate debt declined from 5.85% in 2001 to 2.59% in 2002. The decline in total average debt outstanding resulted from lower energy prices, which reduced the amount of capital needed to fund accounts receivables and natural gas inventories/prepayments.

Income Taxes – Income tax expense decreased $66,207, or 4.2% from fiscal 2001. Although pre-tax income increased by $114,073, fiscal 2001’s earnings included the amortization and write-down of $508,631 in goodwill related to the heating and air conditioning operations. The goodwill was not deductible for income tax purposes resulting in a higher average effective income tax rate for fiscal 2001. The lower average effective tax rate for the fiscal year 2002 was partially offset by the state income tax on regulated Virginia natural gas operations. The state income tax was in place for the entire year of fiscal 2002; however, it was only in effect for the last nine months of fiscal 2001. Consequently, from a tax rate perspective, the average rate on taxable income was effectively higher in 2002, while the total effective tax rate was lower in 2001, excluding the non-deductible goodwill.

Net Income and Dividends - Net income for fiscal 2002 was $2,486,895 as compared to fiscal year 2001 net income of $2,306,615. Net income improved despite the warmer winter as a result of a significant reduction in bad debt expense in fiscal 2002 and the impairment loss related to the restructuring of the heating and air conditioning operation recorded in fiscal 2001. Basic and diluted earnings per share of common stock were $1.28 in fiscal 2002 compared with $1.21 in fiscal 2001. Dividends per share of common stock were $1.14 in fiscal 2002 compared with $1.12 in fiscal 2001.

Gas Line Break

On January 27, 2003, a break occurred on a natural gas main located in the Company’s Bluefield, WV service territory due to a ground shift attributed to much colder than normal temperatures. As a result of the leak and its subsequent repair, service to approximately 4,300 customers was interrupted for periods ranging from several hours to 4 days. The Company was able to restore service due to assistance provided by five other natural gas distribution companies. Over 75 service technicians worked extended shifts around the clock. The final cost attributed to this incident amounted to $296,956 for the repair of the gas line and the reestablishment of service to its customers. In addition, the Company has installed a parallel natural gas distribution main to provide service redundancy for the repaired gas main.

The Company has received authorization from the staff of the West Virginia PSC to defer the costs associated with the West Virginia portion of the outage totaling $229,076 as a regulatory asset and apply for recovery of these costs through future rate filings. The Company has negotiated a settlement with the PSC Staff regarding the full recovery of these costs over future periods. The Company received the final rate order in December 2003 authorizing the Company to recover these costs over future periods.

The costs attributable to the Virginia portion of the gas outage were expensed during the year. Due to the dollar amount, the Company elected not to file for special rate relief on these costs. The total expense allocated to the Virginia operations was $67,880.

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 2003, 74% for fiscal 2002 and 81% for fiscal 2001 of the total operating expenses of the Company’s gas utilities operations.

Natural gas and propane storage volumes began the injection season at very low levels due to cold winter weather combined with declining production from existing natural gas fields. High injection rates during the summer brought about impressive storage refills according to the Energy Information Administration (EIA), a governmental agency that tracks energy statistics, both natural gas and propane storage levels are currently in the normal range for this time of the year. Furthermore, EIA reported that energy prices during fiscal 2003 were higher than fiscal 2002, and if projections are correct, natural gas and propane prices are expected to remain at a higher level for the near term. To lessen the impact of price volatility, Roanoke Gas Company, Bluefield Gas Company and Highland Propane 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 much 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, given the uncertainty of future prices, fiscal 2004 hedging benefits are expected to be lower than fiscal 2003.

“ At Roanoke Gas I feel proud when I see my company helping the Christmas families that are in need.”

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. The unregulated propane and energy marketing operations are able to more rapidly adjust pricing structures to compensate for increasing costs. However, due to the competitive nature of these unregulated markets, there can be no assurance that the Company can adjust its pricing to sufficiently recover cost increases without negatively affecting sales and competitive position.

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. As discussed below, the implementation of a new rate structure will provide the Company 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 new 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 RGC Resources’ utility and energy businesses as well as the related weather sensitivity, RGC 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 2003 were a combination of replacements and expansions, reflecting the need to replace older cast iron and bare steel pipe with coated steel or plastic pipe, while continuing to meet the demands of customer growth in both natural gas and propane operations. Total capital expenditures for fiscal 2003 were approximately $8.3 million allocated as follows: $6.1 for Roanoke Gas Company, $0.6 million for Bluefield Gas Company and $1.6 million for Highland Propane Company. Depreciation cash flow provided approximately $5.4 million in support of capital expenditures, or approximately 65% of total investment. Historically, consolidated capital expenditures were $8.6 million in 2002 and $8.0 million in 2001. 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.

“I am proud to have a company president that never fails to smile when he sees you.”

Short-term borrowing, in addition to providing limited 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. From April through October, the Company prepays its asset manager for the right to receive additional natural gas in the colder winter months. The gas prepayment replaces the underground natural gas storage that was used prior to the current asset management agreement. At September 30, 2003, the Company had $14,782,752 in prepaid gas service compared to $9,372,493 in the prior year. The increase in prepaid gas service is entirely related to higher energy costs, as total volumes are the same for both years. Furthermore, a majority 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. Higher energy costs have resulted in accounts receivable balances and reserves for bad debts at September 30, 2003 that are above the levels at September 30, 2002.

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 the payment to the Company’s energy suppliers is due before the Company can recover its costs through the monthly billing of its customers. In addition, colder weather requires the Company to purchase greater volumes of natural gas, the cost of which is recovered from customers on a delayed basis.

At September 30, 2003, the Company had available lines of credit for its short-term borrowing needs totaling $28,000,000, of which $12,992,000 was outstanding. The terms of short-term borrowings are negotiable, with average rates of 1.99% in 2003, 2.46% in 2002 and 5.68% in 2001. The lines do not require compensating balances. These lines of credit will expire March 31, 2004, 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 with Bank of America for the purposes of refinancing a $1.125 million balloon payment due on a Bluefield Gas note and converting a portion of the short-term line of credit. The note is a variable rate note based upon 30 day LIBOR rate. Because the Company had both the intent and ability to execute the note at September 30, 2003, the balance sheet reflects the corresponding reclassification of $2 million from current maturities and borrowings under lines of credit to long-term debt.

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.

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Stockholders’ equity increased for the period by $1,788,617, reflecting an increase of $1,260,429 in retained earnings, exclusive of accumulated comprehensive income, and proceeds of $816,981 from new common stock purchases through the Plan and the Restricted Stock Plan For Outside Directors.

At September 30, 2003, the Company’s consolidated long-term capitalization was 52% equity and 48% debt, compared to 51% equity and 49% debt at September 30, 2002.

Regulatory Affairs

In Virginia, Roanoke Gas Company filed a rate increase request in September 2003 with the Virginia SCC and placed the increased rates into effect on October 16, 2003, subject to refund for any difference 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 February 2004.

In West Virginia, Bluefield Gas Company filed a rate case in February 2003. The case was settled with a final order approving increased rates of $112,000 for service rendered on and after December 4, 2003.

Contractual Obligations and Commercial Commitments

RGC Resources, Inc.’s contractual obligations as of September 30, 2003 representing cash obligations that are considered to be firm commitments are as follows.

Payment due within

	1 Year		2-3 Years		4-5 Years		After 5 Years		Total
Lines-of-Credit	$	12,992,000	$	—	$	—	$	—	$	12,992,000
Long-term Debt		1,000,000		12,500,000		6,700,000		11,000,000		31,200,000
Capital Leases		32,372		19,987		—		—		52,359
Pipeline and Storage Capacity		11,196,246		10,596,835		10,018,994		42,594,951		74,407,026
Propane Commitments		463,900		—		—		—		463,900

Total Contractual Obligations	$	25,684,518	$	23,116,822	$	16,718,994	$	53,594,951	$	119,115,285

The lines-of-credit have been reduced by $875,000 in refinancing that has been reclassified to long-term debt on the balance sheet. Total available lines-of-credit are scheduled to expire on March 31, 2004, at which time the Company expects to renew the contracts. See Footnote 5 in the consolidated financial statements for additional information.

Long-term debt includes $2,000,000 due in 2005 related to the refinancing that has been reclassified to long-term debt from lines-of-credit and current maturities of long-term debt. See Footnote 6 in the consolidated financial statements for more information.

The Company has commitments to purchase natural gas at market price over the next two years in the amount of 2,965,857 DTH and 420,513 DTH associated with the prepaid gas provisions of the Company’s asset management agreement and pipeline commitments. See Footnote 12 in the consolidated financial statements for more information on commitments.

Propane commitments include the fixed price purchase of 840,000 gallons of propane. In addition, the Company has commitments to purchase 3,891,100 gallons of propane at market price in 2004. See Footnote 12 in the consolidated financial statements for more information on commitments.

Critical Accounting Policies and Estimates

The consolidated financial statements of RGC Resources, Inc. 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.

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 hedges 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 the commodities of propane and natural gas. 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.

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).

“I feel proud when I hear someone take a stand for Christ and His Church, even at work. I feel proud every time I hear President Bush ask God to bless us.”

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, propane 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, 2003, the Company had $12,992,000 outstanding under its lines of credit and $2,500,000 outstanding on an

intermediate-term variable rate note. Based upon outstanding borrowings at September 30, 2003, 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 $155,000. 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, 2003 amounted to a $249,114 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 and propane 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.

As of September 30, 2003, the Company had entered into derivative price caps for the purpose of hedging the price of propane gas. Consequently, a hypothetical 10 percent reduction in market price would have no effect on the fair value of the Company’s propane gas derivative contracts.

As of September 30, 2003, the Company had entered into both derivative price caps and swap arrangements for the purpose of hedging the price of natural gas. Any cost incurred or benefit received from derivative or other hedging arrangements is expected to be recoverable or refunded through the regulated natural gas purchased gas adjustment (PGA) mechanism. Both the Virginia SCC and the West Virginia PSC 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. A hypothetical 10 percent reduction in the market price of natural gas would result in a decrease in fair value of approximately $249,000 for the Company’s natural gas derivative contracts at September 30, 2003.

“I love that I have choices in religion, government, where I shop, where I eat and where I sleep.”

Operational Changes

Effective September 30, 2003, RGC Ventures, Inc. was merged into Diversified Energy Company. The merger was done to consolidate the appliance service work into one entity and preserve the state net operating loss carry-forward generated by RGC Ventures, Inc.

Asset Management

Effective November 1, 2001, Roanoke Gas Company and Bluefield Gas Company (the Companies) entered into a contract with a third party (counter-party) to provide future gas supply needs. The counter-party has also 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 expires on October 31, 2004.

Under the asset management agreement, the Companies no longer have title or ownership of the physical asset; instead, the Companies make monthly payments for the right to receive gas in the future. Therefore, a greater risk exists regarding the ultimate realization of the prepayment depending on the ongoing viability of the counter-party. The Companies have attempted to mitigate the risks in the event of a failure to perform or bankruptcy on the part of the counter-party by requiring certain contractual restrictions on inventory and other provisions. As of September 30, 2003, the total value of prepaid gas service on the Balance Sheet was $14,782,752.

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 PSC 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. Although the unregulated propane operations are able to be more flexible in adjusting rates for increases in costs, competition in the propane market means there is no assurance that the Company can increase prices sufficiently to effectively recover all cost increases.

Terrorism: The terrorist attacks of September 11, 2001 and the ongoing war on terrorism continue to affect the business climate of this country. However, with an improving economy and greater vigilance regarding security, business has begun to return to some form of normalcy. 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 terrorism threats. Insurance premiums during fiscal 2003 increased 31% over fiscal 2002 as insurance companies worked to restore reserves depleted as a result of the terrorist attacks. The Company is currently in the process of renewing its insurance coverage for the current year; although increases in premiums are anticipated, the rate of increase is expected to be less than experienced in fiscal 2003.

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Stock Market Performance: Although equity investments in general have rallied over the past several months, the poor stock market performance over the last few 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. The poor returns on the investments of these plans has had a significant negative impact on these plans as total plan assets in the pension plan have declined by more than 19% over the past three years. The reduction in plan assets and decline in the discount rate to 6% will increase pension expense for fiscal 2004 by $200,000 on top of an increase of $228,000 in fiscal 2003 and will require the Company to increase the amount needed to fund the plan. Post-retirement medical expense will increase by $61,000 in fiscal 2004 as a result of both market performance and a reduction in the discount rate. Benefit plan expenses are expected to remain at higher levels for the foreseeable future.

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 increased compliance and administrative costs to the Company in the form of legal consultation and internal staff costs, and increased external audit fees.

Weather: The most significant factor that affects the future results of the Company is 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. Historically, the Company’s authorized billing rates charged to customers for natural gas service were based upon normal weather over the last 71 years. Over the past 6 years, the Company has experienced four winters that were warmer than normal and, as a result, has not fully earned its authorized rate of return. In Roanoke Gas Company’s recent rate order issued by the SCC in response to the rate application filed in 2002, Roanoke Gas Company received approval for the use of a weather normalization adjustment factor, based on a weather occurrence band around the most recent 30-year normal. The weather band would provide a 6 percent range around normal weather, whereby if the number of heating degree days fell within 6 percent above or below the 30-year normal, no adjustments would be made. However, if the number of heating degree-days was more than 6 percent below normal, a surcharge would be added to customers’ bills. Likewise, if the number of heating degree-days was more than 6 percent above normal, 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 normal. Of the four recent winters that were warmer than normal, the new weather normalization component would have resulted in the recording and billing of additional revenues in three of those years. Implementation of this new rate structure will begin in fiscal 2004.

Capitalization Statistics

Years Ended September 30,	2003			2002			2001			2000			1999
Common Stock:
Shares Issued		2,003,232			1,960,418			1,914,603			1,881,733			1,832,771
Basic Earnings Per Share	$	1.78		$	1.28		$	1.21	*	$	1.54		$	1.59
Diluted Earnings Per Share	$	1.77		$	1.28		$	1.21	*	$	1.54		$	1.59
Dividends Paid Per Share (Cash)	$	1.14		$	1.14		$	1.12		$	1.10		$	1.08
Dividends Paid Out Ratio		64.0	%		89.1	%		92.6	%		71.4	%		67.9	%

Capitalization Ratios:
Long-Term Debt, Including
Current Maturities		48.0			48.7			43.1			43.8			45.3
Common Stock And Surplus		52.0			51.3			56.9			56.2			54.7

Total		100.0			100.0			100.0			100.0			100.0

Long-Term Debt, Including
Current Maturities	$	31,252,359		$	30,482,485		$	23,310,522		$	23,336,614		$	23,360,896
Common Stock And Surplus		33,857,614			32,068,997			30,725,072			29,985,871			28,154,923

Total Capitalization Plus
Current Maturities	$	65,109,973		$	62,551,482		$	54,035,594		$	53,322,485		$	51,515,819

*	Reflects $.32 per share impairment loss.

Summary of Gas Sales and Statistics

Years Ended September 30,	2003		2002		2001		2000		1999
Revenues:
Residential Sales	$	42,749,256	$	33,261,150	$	50,432,183	$	32,605,568	$	28,152,236
Commercial Sales		28,371,913		21,723,467		32,486,778		20,270,890		17,812,922
Interruptible Sales		2,238,792		771,439		1,300,369		859,504		646,256
Transportation Gas Sales		1,712,960		1,686,141		1,609,974		1,784,508		1,776,049
Backup Services		89,590		64,287		77,514		10,979		89,061
Late Payment Charges		101,785		100,015		237,579		112,210		108,340
Miscellaneous Gas Utility Revenue		57,041		41,448		50,724		41,509		34,279
Propane		15,211,015		10,718,404		14,929,570		11,246,152		8,469,728
Energy Marketing		13,091,137		11,107,532		14,756,066		8,828,492		5,639,783
Other		738,070		751,790		1,562,390		1,990,183		1,474,055

Total	$	104,361,559	$	80,225,673	$	117,443,147	$	77,749,995	$	64,202,709
Net Income	$	3,528,389	$	2,486,895	$	2,306,615	$	2,873,702	$	2,883,407

DTH Delivered:
Residential		5,120,975		4,230,055		5,121,119		4,572,256		4,528,752
Commercial		3,685,017		3,258,766		3,732,953		3,315,915		3,198,766
Interruptible		345,678		156,923		192,659		177,387		164,348
Transportation Gas		2,878,796		2,906,988		2,833,758		3,186,497		3,021,229
Backup Service		10,727		10,782		9,738		1,893		15,376

Total		12,041,193		10,563,514		11,890,227		11,253,948		10,928,471
Gallons Delivered (Propane)		10,655,557		8,856,086		10,174,329		9,666,772		8,977,524
Heating Degree Days		4,349		3,502		4,342		3,721		3,717
Number of Customers:
Natural Gas
Residential		52,006		51,557		51,198		50,520		49,860
Commercial		5,638		5,627		5,529		5,502		5,379
Interruptible and Interruptible Transportation Service		47		45		43		45		44

Total		57,691		57,229		56,770		56,067		55,283
Propane		18,105		18,156		17,105		15,973		13,832

Total Customers		75,796		75,385		73,875		72,040		69,115
Gas Account (DTH):
Natural Gas Available		12,392,866		10,992,271		12,516,840		11,933,719		11,525,469
Natural Gas Deliveries		12,041,193		10,563,514		11,890,227		11,253,948		10,928,471
Storage - LNG		102,907		112,692		70,704		123,002		136,338
Company Use And Miscellaneous		44,450		62,046		31,480		47,325		62,189
System Loss		204,316		254,019		524,429		509,444		398,471

Total Gas Available		12,392,866		10,992,271		12,516,840		11,933,719		11,525,469
Total Assets	$	100,497,399	$	92,401,455	$	93,571,129	$	87,407,494	$	77,789,982
Long Term Obligations	$	30,219,987	$	30,377,358	$	22,507,485	$	23,310,522	$	23,336,614

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

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 28288-1153

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:

RGC Resources, Inc.

Vice President and Secretary

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, optimal 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.

Market Price and Dividend 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.

Fiscal Year Ended September 30,	Range of Bid Prices				Cash Dividends Declared
Fiscal Year Ended September 30,	High		Low		Cash Dividends Declared

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

2002
First Quarter	$	20.500	$	18.500	$	0.285
Second Quarter		20.250		18.800		0.285
Third Quarter		20.750		17.500		0.285
Fourth Quarter		20.010		16.990		0.285

LOGO

RGC Resources, Inc. and

Subsidiaries

Consolidated Financial Statements

as of and for the Years Ended

September 30, 2003, 2002 and 2001,

and Independent Auditors’ Report

RGC RESOURCES, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

		Page
INDEPENDENT AUDITORS’ REPORT		1

CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED SEPTEMBER 30, 2003, 2002 AND 2001:

Consolidated Balance Sheets		2-3

Consolidated Statements of Income and Comprehensive Income		4

Consolidated Statements of Stockholders’ Equity		5

Consolidated Statements of Cash Flows		6-7

Notes to Consolidated Financial Statements		8-26

INDEPENDENT AUDITORS’ REPORT

To the Board of Directors and Stockholders of

RGC Resources, Inc.:

We have audited the accompanying consolidated balance sheets of RGC Resources, Inc. and subsidiaries (the “Company”) as of September 30, 2003 and 2002, 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, 2003. 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 auditing standards generally accepted in the United States of America. 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, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended September 30, 2003 in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche

December 17, 2003

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

SEPTEMBER 30, 2003 AND 2002

	2003			2002
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	135,998		$	288,030
Accounts receivable, less allowance for doubtful accounts of $318,899 in 2003 and $155,062 in 2002		6,183,162			4,460,867
Inventories		2,559,306			2,172,808
Prepaid gas service		14,782,752			9,372,493
Prepaid income taxes		1,079,802			1,189,154
Deferred income taxes		1,605,509			2,579,879
Under-recovery of gas costs		790,126			—
Unrealized gains on marked-to-market transactions		—			1,779,891
Other		541,322			453,804

Total current assets		27,677,977			22,296,926


UTILITY PLANT:
In service		96,385,022			89,504,217
Accumulated depreciation and amortization		(38,586,345	)		(34,386,639	)

In service, net		57,798,677			55,117,578

Construction work in progress		1,992,222			1,810,520

Utility plant, net		59,790,899			56,928,098


NONUTILITY PROPERTY:
Nonutility property		20,793,278			19,869,186
Accumulated depreciation and amortization		(8,832,823	)		(7,659,087	)

Nonutility property, net		11,960,455			12,210,099


OTHER ASSETS:
Goodwill		298,314			298,314
Other assets		769,754			668,018

Total other assets		1,068,068			966,332


TOTAL	$	100,497,399		$	92,401,455

(Continued)

- 2 -

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

SEPTEMBER 30, 2003 AND 2002

	2003			2002
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt	$	1,032,372		$	105,127
Borrowings under lines of credit		12,992,000			8,991,000
Dividends payable		571,458			559,069
Accounts payable		9,289,899			7,897,084
Customer deposits		477,465			543,891
Accrued expenses		4,798,106			3,961,174
Refunds from suppliers—due customers		42,320			51,889
Over-recovery of gas costs		1,172,585			1,742,905
Unrealized losses on marked-to-market transactions		319,264			—

Total current liabilities		30,695,469			23,852,139


LONG-TERM DEBT, EXCLUDING CURRENT MATURITIES		30,219,987			30,377,358


DEFERRED CREDITS:
Deferred income taxes		5,457,991			5,802,417
Deferred investment tax credits		266,338			300,544

Total deferred credits		5,724,329			6,102,961


COMMITMENTS AND CONTINGENCIES (Notes 11 and 12)

CAPITALIZATION:
Stockholders’ equity:
Common stock, $5 par value; authorized 10,000,000 shares; issued and outstanding 2,003,232 and 1,960,418 shares in 2003 and 2002, respectively		10,016,160			9,802,090
Preferred stock, no par; authorized 5,000,000 shares; no shares issued and outstanding in 2003 and 2002		—			—
Capital in excess of par value		11,977,084			11,374,173
Retained earnings		12,018,920			10,758,491
Accumulated other comprehensive income (loss)		(154,550	)		134,243

Total stockholders’ equity		33,857,614			32,068,997


TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	100,497,399		$	92,401,455

See notes to consolidated financial statements.

(Concluded)

- 3 -

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

YEARS ENDED SEPTEMBER 30, 2003, 2002 AND 2001

	2003			2002		2001
OPERATING REVENUES:
Gas utilities	$	75,321,337		$	57,647,947	$	86,195,121
Propane operations		15,211,015			10,718,404		14,929,570
Energy marketing		13,091,137			11,107,532		14,756,066
Other		738,070			751,790		1,562,390

Total operating revenues		104,361,559			80,225,673		117,443,147


COST OF SALES:
Gas utilities		53,895,656			38,616,769		65,227,777
Propane operations		7,518,371			5,511,314		8,678,227
Energy marketing		12,806,095			10,841,871		14,231,107
Other		416,723			424,630		1,132,850

Total cost of sales		74,636,845			55,394,584		89,269,961

OPERATING MARGIN		29,724,714			24,831,089		28,173,186


OTHER OPERATING EXPENSES:
Operations		13,115,861			10,758,661		12,176,932
Maintenance		1,671,255			1,245,261		1,396,544
General taxes		1,674,441			1,504,422		2,343,351
Depreciation and amortization		5,198,983			5,114,320		4,828,096
Impairment loss		—			72,008		699,630

Total other operating expenses		21,660,540			18,694,672		21,444,553


OPERATING INCOME		8,064,174			6,136,417		6,728,633

OTHER EXPENSES—Net		223,517			104,956		113,149

INTEREST EXPENSE		2,172,342			2,050,754		2,748,850


INCOME BEFORE INCOME TAXES		5,668,315			3,980,707		3,866,634

INCOME TAX EXPENSE		2,139,926			1,493,812		1,560,019


NET INCOME		3,528,389			2,486,895		2,306,615

OTHER COMPREHENSIVE INCOME (LOSS)—Net of tax		(288,793	)		209,097		(74,854	)


COMPREHENSIVE INCOME	$	3,239,596		$	2,695,992	$	2,231,761


BASIC EARNINGS PER SHARE	$	1.78		$	1.28	$	1.21


DILUTED EARNINGS PER SHARE	$	1.77		$	1.28	$	1.21


WEIGHTED-AVERAGE SHARES OUTSTANDING:
Basic		1,983,970			1,939,511		1,898,697

Diluted		1,989,460			1,942,058		1,902,293

- 4 -

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

YEARS ENDED SEPTEMBER 30, 2003, 2002 AND 2001

	Common Stock		Capital in Excess of Par Value		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Stockholders’ Equity

BALANCE—October 1, 2000	$	9,408,665	$	10,262,252	$	10,314,954		$	—		$	29,985,871

Net income						2,306,615						2,306,615

Gains (losses) on hedging activities, net of tax									(74,854	)		(74,854	)

Cash dividends declared ($1.12 per share)						(2,131,194	)					(2,131,194	)

Issuance of common stock (32,870 shares)		164,350		474,284								638,634


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 (losses) 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

Gains (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

See notes to consolidated financial statements.

- 5 -

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

YEARS ENDED SEPTEMBER 30, 2003, 2002 AND 2001

	2003			2002			2001
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	3,528,389		$	2,486,895		$	2,306,615
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation and amortization		5,422,074			5,297,678			4,967,332
Impairment loss		—			72,008			699,630
(Gain) loss on asset disposition		(5,640	)		1,872			5,944
Change in over/under recovery of gas costs		364,268			(1,932,247	)		3,003,839
Deferred taxes and investment tax credits		681,386			1,686,802			(1,218,486	)
Other noncash items, net		(101,736	)		(296,926	)		150,503
Changes in assets and liabilities which provided (used) cash:
Accounts receivable and customer deposits, net		(1,788,721	)		2,707,666			(879,956	)
Inventories and prepaid gas service		(5,796,757	)		1,928,685			(1,052,659	)
Other current assets		21,834			(858,825	)		110,473
Accounts payable and accrued expenses		2,229,747			(168,850	)		(2,709,804	)
Refunds from suppliers—due customers		(9,569	)		(64,869	)		(106,251	)

Net cash provided by operating activities		4,545,275			10,859,889			5,277,180

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant and nonutility property		(8,347,654	)		(8,614,454	)		(8,029,853	)
Cost of removal of utility plant, net		(27,534	)		(45,580	)		(38,618	)
Proceeds from sales of assets		345,597			75,918			43,814

Net cash used in investing activities		(8,029,591	)		(8,584,116	)		(8,024,657	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		8,000,000			—			—
Retirement of long-term debt		(105,126	)		(828,038	)		(26,092	)
Net borrowings under lines of credit		(3,124,000	)		(716,000	)		4,412,000
Proceeds from issuance of common stock		816,981			866,712			638,634
Cash dividends paid		(2,255,571	)		(2,196,095	)		(2,112,636	)

Net cash provided by (used in) financing activities		3,332,284			(2,873,421	)		2,911,906


NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(152,032	)		(597,648	)		164,429

CASH AND CASH EQUIVALENTS:
Beginning of year		288,030			885,678			721,249

End of year	$	135,998		$	288,030		$	885,678

SUPPLEMENTAL DISCLOSURES OF CASH FLOWS INFORMATION:
Cash paid during the year for:
Interest	$	2,145,317		$	2,086,391		$	2,537,343

Income taxes, net of refunds	$	1,254,623		$	640,145		$	2,670,227

(Continued)

- 6 -

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)

YEARS ENDED SEPTEMBER 30, 2003, 2002 AND 2001

Noncash transactions:

In 2003, 2002, and 2001, 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 balance sheet:

	2003		2002		2001
Unrealized gain (loss) on marked-to-market transactions	(2,099,155	)	3,686,062		(1,906,171	)
Under (over) recovery of gas costs	1,630,150		(3,343,560	)	1,783,560
Deferred tax asset (liability)	180,212		(133,405	)	47,757

Subsequent to September 30, 2003, the Company executed a $2,000,000 two-year intermediate term note to refinance currently maturing debt and a portion of the line of credit balances. A $2 million reclassification from short-term to long-term debt was made to the September 30, 2003 balance sheet. (See Note 5.)

See notes to consolidated financial statements.

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RGC RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2003, 2002 AND 2001

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; RGC Ventures, Inc., operating as Highland Heating and Cooling; and RGC Ventures, Inc. of Virginia, operating as Application Resources. Roanoke Gas Company and Bluefield Gas Company are the 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 western Virginia and southern West Virginia. Highland Energy brokers natural gas to several industrial transportation customers of Roanoke Gas Company and Bluefield Gas Company. Highland Heating and Cooling provided heating and cooling service and installation in West Virginia. 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”).

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,
	2003		2002
Regulatory assets:
Rate case costs	$	—	$	1,087
Under-recovery of gas costs		790,126		—
Bad debt expense deferral		228,920		316,966
Line break expense deferral		229,076		—
Other		44,747		52,103

Total regulatory assets	$	1,292,869	$	370,156


	September 30,
	2003		2002
Regulatory liabilities:
Refunds from suppliers—due customers	$	42,320	$	51,889
Over-recovery of gas costs		1,172,585		1,742,905

Total regulatory liabilities	$	1,214,905	$	1,794,794

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. These costs will be recovered through future rates beginning 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, plus cost of removal, less salvage, is charged to accumulated depreciation. 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 from 2% to 17% for utility property. Depreciable lives for non-utility property range from 3 to 25 years. The annual composite rates for utility property are determined by periodic depreciation studies.

We review 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.

Cash and Cash Equivalents—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.

Inventories—Inventories consist of natural gas in storage, propane, and materials. Natural gas inventories are recorded at average cost. Propane inventories are valued at the lower of average cost or market.

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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 amounts of unbilled revenue receivable included in accounts receivable on the consolidated balance sheets at September 30, 2003 and 2002 were $1,251,253 and $875,316, 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 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 the next 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.

Derivative and Hedging Activities—Effective October 1, 2000, the Company adopted the provisions of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted. SFAS No. 133 requires the recognition of 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 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 2003, the Company entered into price cap arrangements due to the uncertainty of energy prices in the coming heating season. The price caps will provide protection against increasing prices and allow the Company to benefit from reduction in energy prices. The price caps qualify 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.

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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. As of September 30, 2003, the Company had entered into price cap and swap arrangements for the purchase of natural gas. 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 regulated natural gas PGA mechanism. Both the SCC and the PSC 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.

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 percent interest rate. The swap qualifies as a cash flow hedge with changes in fair value reported in other comprehensive income.

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

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	)

Unrealized (loss) on 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 (losses)	$	163,632		$	—		$	—		$	163,632
Income tax (expense) benefit		(63,735	)		—			—			(63,735	)

Net unrealized gains (losses)		99,897			—			—			99,897

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

Net transfer of realized losses (gains) to income		109,200			—			—			109,200

Net other comprehensive (loss)	$	209,097		$	—		$	—		$	209,097

Unrealized (loss) on marked to market transactions	$	219,891		$	—		$	1,560,000		$	1,779,891

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

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Year Ended September 30, 2001	Propane Derivatives			Interest Rate Swap		Natural Gas Derivatives			Total
Unrealized gains/(losses)	$	30,558		$	—	$	—		$	30,558
Income tax (expense)/benefit		(11,902	)		—		—			(11,902	)

Net unrealized gains/(losses)		18,656			—		—			18,656

Transfer of realized losses/(gains) to income		(153,169	)		—		—			(153,169	)
Income tax (benefit)/expense		59,659			—		—			59,659

Net transfer of realized losses/(gains) to income		(93,510	)		—		—			(93,510	)

Net other comprehensive (loss)	$	(74,854	)	$	—	$	—		$	(74,854	)

Unrealized (loss) on marked to market transactions	$	(122,611	)	$	—	$	(1,783,560	)	$	(1,906,171	)

Accumulated comprehensive (loss)	$	(74,854	)	$	—	$	—		$	(74,854	)

New Accounting Standards—In June 2001, the Financial Accounting Standards Board (“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 intangible assets to be recognized separately and amortized as appropriate. The Company has completed its annual testing of goodwill using a discounted future cash flow method and determined that no impairment existed as of September 30, 2003. The following table reflects the impact of removing goodwill amortization on prior years’ net income.

	Twelve Months Ended September 30,
	2003		2002		2001
Net Income	$	3,528,389	$	2,486,895	$	2,306,615
Add: Goodwill amortization, as recorded—net of tax		—		18,064		18,064

Adjusted net income	$	3,528,389	$	2,504,959	$	2,324,679

Basic earnings per share—as reported	$	1.78	$	1.28		1.21
Goodwill amortization		—		0.01		0.01

Adjusted basic earnings per share	$	1.78	$	1.29	$	1.22

Diluted earnings per share—as reported	$	1.77	$	1.28		1.21
Goodwill amortization		—		0.01		0.01

Adjusted diluted earnings per share	$	1.77	$	1.29	$	1.22

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

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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. The utility plant accumulated depreciation amount reflected on the Company’s balance sheet at September 30, 2003 and 2002 contains approximately $5.4 million and $4.6 million, respectively, of accumulated provisions for retirement costs.

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. The adoption did not have a material impact on the Company’s financial position or results of operation.

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 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 (“APB”) 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 FASB Statement No. 123, Accounting for Stock-Based Compensation, to the options granted under the plan.

	Twelve Months Ended September 30,
	2003			2002			2001
Net Income, as reported	$	3,528,389		$	2,486,895		$	2,306,615
Deduct: Total stock-based employee compensation expense determined under fair value method for all awards, net of tax		(19,747	)		(17,481	)		(22,767	)

Proforma net income	$	3,508,642		$	2,469,414		$	2,283,848

Earnings per share—as reported:
Basic	$	1.78		$	1.28		$	1.21
Diluted	$	1.77		$	1.28		$	1.21

Earnings per share—pro forma:
Basic	$	1.77		$	1.27		$	1.20
Diluted	$	1.76		$	1.27		$	1.20

Weighted Average Shares		1,983,970			1,939,511			1,898,697
Diluted Shares		1,989,460			1,942,058			1,902,293

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2.	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 operating 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.

Propane Operations—The propane gas segment of the Company generates revenue from the sale and delivery of propane gas and related services to its residential, commercial, and industrial customers located in western Virginia and southern West Virginia.

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

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

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

	Gas Utilities		Propane Operations		Energy Marketing		Parent and Other		Consolidated Total
For the year ended September 30, 2003:
Operating revenues	$	75,321,337	$	15,211,015	$	13,091,137	$	738,070	$	104,361,559
Operating margin		21,425,681		7,692,644		285,042		321,347		29,724,714
Operations, maintenance, and general taxes		12,201,542		4,208,789		44,976		6,250		16,461,557
Depreciation and amortization		3,716,841		1,479,204		—		2,938		5,198,983
Interest charges		1,964,969		207,373		—		—		2,172,342
Income before income taxes		3,391,592		1,724,498		240,066		312,159		5,668,315

As of September 30, 2003:
Total assets		83,747,187		13,658,311		2,020,249		1,071,652		100,497,399
Gross additions to long-lived assets		6,774,401		1,573,253		—		—		8,347,654

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	Gas Utilities		Propane Operations		Energy Marketing		Parent and Other			Consolidated Total
For the year ended September 30, 2002:
Operating revenues	$	57,647,947	$	10,718,404	$	11,107,532	$	751,790		$	80,225,673
Operating margin		19,031,178		5,207,090		265,661		327,160			24,831,089
Operations, maintenance, and general taxes		9,823,575		3,313,645		30,148		340,976			13,508,344
Impairment loss		—		—		—		72,008			72,008
Depreciation and amortization		3,554,814		1,517,463		—		42,043			5,114,320
Interest charges		1,768,853		249,093		—		32,808			2,050,754
Income before income taxes		3,789,939		117,037		235,513		(161,782	)		3,980,707

As of September 30, 2002:
Total assets	$	76,813,661	$	13,432,357	$	1,320,944	$	834,493		$	92,401,455
Gross additions to long-lived assets		6,537,397		2,075,891		—		1,166			8,614,454

For the year ended September 30, 2001:
Operating revenues	$	86,195,121	$	14,929,570	$	14,756,066	$	1,562,390		$	117,443,147
Operating margin		20,967,344		6,251,343		524,959		429,540			28,173,186
Operations, maintenance, and general taxes		11,677,941		3,372,455		32,147		834,284			15,916,827
Impairment loss		—		—		—		699,630			699,630
Depreciation and amortization		3,325,814		1,385,236		—		117,046			4,828,096
Interest charges		2,231,918		429,633		—		87,299			2,748,850
Income before income taxes		3,643,127		1,051,845		492,812		(1,321,150	)		3,866,634

As of September 30, 2001:
Total assets		75,791,015		14,023,168		1,567,179		2,189,767			93,571,129
Gross additions to long-lived assets		5,981,165		2,037,547		—		11,141			8,029,853

During 2003, 2002 and 2001, no single customer accounted for more than 5% of the Company’s sales. One customer’s accounts receivable balance accounted for 7.4% 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.

3.	RESTRUCTURING

In September 2001, the Company decided to restructure the heating and air conditioning sales and services operations in West Virginia due to the poor performance of these operations and the unlikelihood of a timely market recovery. Several factors contributed to the underperformance of these operations including increasing competition in the markets served, the general economic slowdown and lower than expected demand for equipment sales and service, among others. The restructuring resulted in the reduction of heating and air conditioning operations.

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As a result of the decision to restructure and reduce its heating and air conditioning operations, the Company adjusted the valuation of several assets to estimated net realizable value in accordance with the guidance in SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of. Additionally, goodwill and other intangible assets associated with the heating and air conditioning operations were written off, as management determined there were no future benefits associated with these amounts. The following is a summary of the impairment loss recorded in 2001:

Write-off of goodwill and other intangibles	$	597,949
Write-down of fixed and other assets		101,681

Total impairment loss	$	699,630

In April 2002, the auction of the inventory and fixed assets of the heating and cooling operations was completed. The results of the auction generated a loss of $72,008 in excess of the amount provided for at the end of the previous year.

As a result of the ongoing evaluation of the remaining heating and air conditioning operations, during 2002, the Company decided to discontinue the heating and air conditioning equipment portion of the business. In 2003, the Company sold the customer list and associated warranties on equipment 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.

4.	ALLOWANCE FOR DOUBTFUL ACCOUNTS

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

	Years Ended September 30,
	2003			2002			2001
Balances, beginning of year	$	155,062		$	531,991		$	314,081
Provision for doubtful accounts		871,967			300,312			1,462,436
Recoveries of accounts written off		315,539			400,283			207,455
Accounts written off		(1,023,669	)		(1,077,524	)		(1,451,981	)

Balances, end of year	$	318,899		$	155,062		$	531,991

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5.	BORROWINGS UNDER LINES OF CREDIT

The Company has available unsecured lines of credit with a bank for $28,000,000 as of September 30, 2003. These lines of credit will expire March 31, 2004. The Company anticipates being able to extend the lines of credit or pursue other options. On October 1, 2003, the Company executed a $2,000,000 26-month intermediate term note to refinance $1,125,000 of currently maturing debt and $875,000 line of credit balance. As the Company met the requirements of both the intent and ability to refinance, a $2,000,000 reclassification was made from current maturities and lines of credit to long-term debt on the balance sheet. The table below reflects this reclassification.

A summary of short-term lines of credit follows:

	2003			2002			2001
Lines of credit at year-end	$	28,000,000		$	20,500,000		$	23,500,000
Outstanding balance at year-end		12,992,000			8,991,000			17,707,000
Highest month-end balances outstanding		20,184,000			21,236,000			23,405,000
Average month-end balances		10,104,000			13,669,000			16,592,000
Average rates of interest during year		1.99	%		2.46	%		5.68	%
Average rates of interest on balances outstanding at year-end		1.70	%		2.38	%		3.54	%

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6.	LONG-TERM DEBT

Long-term debt consists of the following:

	September 30,
	2003			2002
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 6.75% to 9.625%		4,000,000			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		52,359			82,485
Unsecured note payable, with variable interest rate based on 30-day LIBOR (1.2% at September 30, 2003) plus 100 basis point spread, with provision for retirement on November 21, 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			1,200,000
Highland Propane Company:
Unsecured note payable, with variable interest rate based on 90-day LIBOR (1.1% and 1.8% at September 30, 2003 and 2002, respectively), plus 95 basis point spread, with provision for retirement on August 26, 2006		2,500,000			2,500,000
Unsecured note payable, at 7%, with provision for retirement on December 31, 2007		1,700,000			1,700,000
Line of credit		875,000			—

Total long-term debt		31,252,359			30,482,485
Less current maturities		(1,032,372	)		(105,127	)

Total long-term debt, excluding current maturities	$	30,219,987		$	30,377,358

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, 2003 and 2002. At September 30, 2003, approximately $5,519,000 of retained earnings were available for dividends.

Long-term debt includes $2,000,000 related to the refinancing of $1,125,000 of current maturities and $875,000 of line-of-credit balances. On October 1, 2003, the Company entered into an unsecured note payable with a variable interest rate based on the 30-day LIBOR plus 113 basis point spread. This note has a provision for retirement on November 21, 2005.

At September 30, 2002, long-term debt includes $8,000,000 due in 2005 related to the refinancing to line-of-credit balances.

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The aggregate annual maturities of long-term debt, subsequent to September 30, 2003 are as follows:

Years Ended September 30,
2004	$	1,032,372
2005		19,987
2006		12,500,000
2007		—
2008		6,700,000
Thereafter		11,000,000

Total	$	31,252,359

7.	INCOME TAXES

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

	Years Ended September 30,
	2003			2002			2001
Current income taxes:
Federal	$	1,070,948		$	(287,947	)	$	2,376,081
State		293,028			94,957			405,528

Total current income taxes		1,363,976			(192,990	)		2,781,609

Deferred income taxes:
Federal		729,142			1,567,525			(916,314	)
State		81,014			153,655			(266,142	)

Total deferred income taxes		810,156			1,721,180			(1,182,456	)

Amortization of investment tax credits		(34,206	)		(34,378	)		(39,134	)

Total income tax expense	$	2,139,926		$	1,493,812		$	1,560,019

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Income tax expense for the years ended September 30, 2003, 2002 and 2001 differed from amounts computed by applying the U.S. federal income tax rate of 34% to earnings before income taxes as a result of the following:

	Years Ended September 30,
	2003			2002			2001
Income before income taxes	$	5,668,315		$	3,980,707		$	3,866,634

Income tax expense computed at statutory rate of 34%	$	1,927,227		$	1,353,440		$	1,314,655
Increase (reduction) in income tax expense resulting from:
State income taxes, net of federal income tax benefit		246,868			164,084			91,995
Amortization and write-off of nondeductible goodwill		—			—			172,935
Amortization of investment tax credits		(34,206	)		(34,378	)		(39,134	)
Other, net		37			10,666			19,568

Total income tax expense	$	2,139,926		$	1,493,812		$	1,560,019

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

	September 30,
	2003		2002
Deferred tax assets:
Allowance for uncollectibles	$	122,484	$	37,736
Accrued medical insurance		173,553		96,321
Accrued pension and medical benefits		1,565,853		1,394,204
Accrued vacation		193,861		168,934
Over (under) recovery of gas costs		156,436		117,724
Costs of gas held in storage		728,348		724,082
Other		348,307		200,839

Total deferred tax assets		3,288,842		2,739,840

Deferred tax liabilities:
Utility plant basis differences		7,141,324		5,962,378

Total deferred tax liabilities		7,141,324		5,962,378

Net deferred tax liability	$	3,852,482	$	3,222,538

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8.	EMPLOYEE BENEFIT PLANS

The Company has a defined benefit pension plan (the “Plan”) covering substantially all of its employees. The benefits are based on years of service and employee compensation. Plan assets are invested principally in cash equivalents and corporate stocks and bonds. Company contributions are intended to provide not only for benefits attributed to date but also for those expected to be earned in the future.

The plan assets and obligations were measured as of June 30. The following sets forth the Plan’s funded status and amounts recognized in the consolidated balance sheet as of September 30, 2003 and 2002:

	2003			2002
Change in projected benefit obligation:
Benefit obligation at beginning of year	$	8,835,323		$	8,068,414
Service cost		300,867			228,710
Interest cost		602,282			568,557
Actuarial loss		1,147,934			401,810
Benefit payments		(428,951	)		(432,168	)

Benefit obligation at end of year	$	10,457,455		$	8,835,323

Change in plan assets:
Fair value of plan assets at beginning of year	$	6,511,141		$	7,325,329
Actual return (loss) on Plan assets		200,827			(401,151	)
Employer contributions		306,153			19,131
Benefit payments		(428,951	)		(432,168	)

Fair value of Plan assets at end of year	$	6,589,170		$	6,511,141

Change in plan assets:
Fair value of plan assets at beginning of year	$	6,511,141		$	7,325,329
Actual return (loss) on Plan assets		200,827			(401,151	)
Employer contributions		306,153			19,131
Benefit payments		(428,951	)		(432,168	)

Fair value of Plan assets at end of year	$	6,589,170		$	6,511,141

Reconciliation of funded status:
Funded status	$	(3,868,285	)	$	(2,324,182	)
Unrecognized actuarial loss		2,570,757			1,136,939
Unrecognized transition obligation		—			1,133
Contributions made between measurement date and fiscal year-end		110,000			100,000

Net pension liability recognized	$	(1,187,528	)	$	(1,086,110	)

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	2003			2002			2001
Components of net periodic pension cost:
Service cost	$	300,867		$	228,710		$	218,310
Interest cost		602,282			568,557			563,150
Expected return on plan assets		(510,138	)		(612,876	)		(680,255	)
Amortization of unrecognized transition obligation		1,133			4,931			7,586
Prior service cost recognized		—			7			18,874
Recognized (gain) loss		23,425			—			(64,985	)

Net periodic pension cost	$	417,569		$	189,329		$	62,680

Assumptions used for pension accounting:
Discount rate		6.00	%		7.00	%		7.25	%
Expected rate of compensation increase		5.00	%		5.00	%		5.00	%
Expected long-term rate of return on Plan assets		8.00	%		8.00	%		8.50	%

In addition to pension benefits, the Company has a postretirement benefits plan, which provides certain healthcare, supplemental retirement and life insurance benefits to active and retired employees who meet specific age and service requirements. The Plan is contributory. The Company has elected to fund the Plan over future years.

The postretirement medical and life insurance Plan assets and obligations were measured as of June 30. The following sets forth the postretirement medical and life insurance Plans’ funded status and amounts recognized in the consolidated balance sheet as of September 30, 2002 and 2001:

	2003			2002
Change in projected benefit obligation:
Benefit obligation at beginning of year	$	8,158,724		$	7,122,071
Service cost		171,508			155,451
Interest cost		555,424			501,320
Participant contributions		34,768			52,501
Actuarial loss		852,318			730,630
Benefit payments		(422,229	)		(403,249	)

Benefit obligation at end of year	$	9,350,513		$	8,158,724

Change in Plan assets:
Fair value of Plan assets at beginning of year	$	2,272,137		$	2,255,569
Actual return (loss) on Plan assets		89,749			(195,684	)
Employer contributions		562,000			563,000
Participant contributions		34,768			52,501
Benefit payments		(422,229	)		(403,249	)

Fair value of Plan assets at end of year	$	2,536,425		$	2,272,137

Reconciliation of funded status:
Funded status	$	(6,814,088	)	$	(5,886,587	)
Contribution made between measurement date and year-end		709,000			562,000
Unrecognized actuarial loss		2,529,210			1,704,909
Unrecognized transition obligation		2,373,000			2,610,300

Net postretirement benefit liability	$	(1,202,878	)	$	(1,009,378	)

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	2003			2002			2001
Components of net periodic postretirement benefit cost:
Service cost	$	171,508		$	155,451		$	155,017
Interest cost		555,424			501,320			524,755
Amortization of unrecognized transition obligation		237,300			237,300			237,300
Expected return on plan assets		(121,640	)		(147,312	)		(164,434	)
Recognized losses		59,908			—			10,346

Net periodic benefit cost	$	902,500		$	746,759		$	762,984

The Company amortizes the unrecognized transition obligations over 20 years.

The weighted-average discount rate used for postretirement benefits accounting was 6.0%, 7.0% and 7.25% for 2003, 2002 and 2001, respectively.

For measurement purposes, 10%, 11%, and 8.5% annual rates of increase in the per capita cost of covered benefits (i.e., medical trend rate) were assumed for 2003, 2002 and 2001, respectively; the rates were assumed to decrease gradually to 5.5% by the year 2010 and remain at that level thereafter. The medical-trend rate assumption has a significant effect on the amounts reported. For example, increasing the assumed medical-cost trend rate by one percentage point each year would increase the accumulated postretirement benefits obligation as of September 30, 2003 by approximately $1,298,000 or 14%, and would increase the aggregate of the service and interest cost components of net postretirement benefits cost by approximately $119,000 or 16%.

The Company also has a defined contribution plan covering all of its employees who elect to participate. The Company made annual matching contributions to the plan in 2003, 2002 and 2001, based on 70% of the net participants’ basic contributions (from 1 to 6% of their total compensation). The annual cost of the plan was $228,737, $227,403 and $233,756 for 2003, 2002 and 2001, respectively.

9.	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, 2003, the number of shares available for future grants under the KESOP is 2,000 shares.

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

	Number of Shares		Weighted- Average Exercise Price		Option Price Per Share
Options outstanding, September 30, 2000	57,000		$	19.105	$	15.500-20.875
Options granted	15,000			19.250
Options exercised	—

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

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, 2003 and 2002.

The per share weighted-average fair values of stock options granted during 2003, 2002 and 2001 were $1.82, $2.17 and $2.45, respectively, on the dates of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions.

	2003		2002		2001
Expected dividend yield	6.30	%	5.89	%	5.82	%
Risk-free interest rate	3.70	%	3.73	%	4.65	%
Expected volatility	26.60	%	22.20	%	21.00	%
Expected life	10 years		10 years		10 years

10.

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 $91,000, $83,000 and $92,000 in 2003, 2002 and 2001, respectively. Management anticipates similar services will be provided to the Company in 2004.

The products sold to the Company include natural gas and propane purchases of approximately $2,190,000 in 2001, and propane truck purchases and repair services of approximately $40,000, $210,000 and $292,000 in 2003, 2002 and 2001, respectively. Management does anticipate that similar services will be provided to the Company in 2004.

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11.

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.

12.

COMMITMENTS

Effective November 1, 2001, the Company entered into a contract with a third party to provide future gas supply needs. The counter-party has also assumed the management and financial obligation of Roanoke Gas Company’s and Bluefield Gas Company’s (the “Companies’”) 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 from the counter-party 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 expires on October 31, 2004.

The Company has contracts for pipeline and storage capacity extending for various periods. Additionally, the Company has contracts with natural gas suppliers requiring the purchase at fixed and market prices of the following volumes of gas for the periods specified. 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:

	2004		2005		2006		After 3 Years
Fixed Price Contracts:
Pipeline and storage capacity	$	11,196,246	$	5,511,538	$	5,009,497	$	52,689,745
Fixed price propane contracts		463,900		—		—		—
Market Price—Volumes:
Natural gas contracts—dekatherms		2,965,857		420,513		—		—
Propane contracts—gallons		3,891,100		—		—		—

The Company has also entered into derivative financial contracts for the purpose of hedging the price on both natural gas and propane gas. These contracts are financial in nature and do not provide for the

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physical delivery of the product. The volume of gas subject to the financial hedges included 1,450,000 dekatherms of natural gas and 2,394,000 gallons of propane in 2004.

13.

FAIR VALUE OF FINANCIAL INSTRUMENTS

The carrying amount of cash and cash equivalents 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, 2003 and 2002 are as follows:

	2003				2002
	Carrying Amounts		Approximate Fair Value		Carrying Amounts		Approximate Fair Value
Long-term debt	$	31,252,359	$	35,316,240	$	30,482,485	$	35,215,485

Judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates determined as of September 30, 2003 and 2002 are not necessarily indicative of the amounts the Company could have realized in current market exchanges.

14.

QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Quarterly financial data for the years ended September 30, 2003 and 2002 is summarized as follows:

2003	First Quarter		Second Quarter		Third Quarter			Fourth Quarter
Operating revenues	$	28,456,127	$	41,222,570	$	19,292,181		$	15,390,681

Operating margin	$	8,665,797	$	11,710,972	$	4,860,715		$	4,487,230

Operating income (loss)	$	3,099,384	$	5,731,519	$	(375,906	)	$	(390,823	)

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

Basic earnings (loss) per share	$	0.78	$	1.59	$	(0.28	)	$	(0.31	)


2002	First Quarter		Second Quarter		Third Quarter			Fourth Quarter
Operating revenues	$	22,854,607	$	31,744,381	$	14,175,352		$	11,451,333

Operating margin	$	7,053,911	$	9,387,426	$	4,602,085		$	3,787,667

Operating income (loss)	$	1,959,618	$	4,535,062	$	59,709		$	(417,972	)

Net income (loss)	$	840,775	$	2,470,446	$	(297,733	)	$	(526,593	)

Basic earnings (loss) per share	$	0.44	$	1.28	$	(0.15	)	$	(0.29	)

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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