Edgar Filing: RGC RESOURCES INC

Annual Report

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Resources

125 YEARS

OF SERVING CUSTOMERS

Annual Report 2007

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Celebrating 125 Years

People have made RGC Resources’ 125 – year history possible. By providing customer service that exceeds the expectations of our customers, we hope to earn an opportunity to serve the ever-changing energy needs of our customers.

From the stockholders that have believed in the strength of a locally-owned and operated company, to the employees who have contributed to the company’s growth, to the customers that have used our gas product – it is truly the people that are responsible for making RGC Resources the successful company it is today.

RGC Resources, Inc. provides energy and related products and services to customers in Virginia and West Virginia through its operating subsidiaries including Roanoke Gas Company, Bluefield Gas Company, Diversified Energy Company and RGC Ventures of Virginia, Inc.

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Financial Highlights

Year Ended September 30, 2 0 0 7 2 0 0 6 2 0 0 5

Operating Revenue - Natural Gas $ 89,175,661 $ 93,746,408 $ 87,752,669

Other Revenue $ 725,640 $ 844,464 $ 848,167

Net Income - Continuing Operations $ 3,765,669 $ 2,961,802 $ 2,916,798

Net Income - Discontinued Operations $ 40,540 $ 549,729 $ 590,108

Basic Earnings Per Share - Continuing Operations $ 1.74 $ 1.40 $ 1.40

Basic Earnings Per Share - Discontinued Operations 0.02 0.26 0.29

Regular Dividend Per Share - Cash $ 1.22 $ 1.20 $ 1.18

Number of Customers - Natural Gas 55,420 54,629 54,153

Total Natural Gas Deliveries - DTH 9,538,229 9,514,387 10,377,153

Total Additions to plant $ 6,004,190 $ 7,175,409 $ 6,685,229

Number of Customers Natural Gas

(in thousands)

Dividend Per Share

(in dollars)

DEAR STOCKHOLDER:

I am pleased to report company earnings of $3.8 million or $1.75 per average diluted share outstanding. This compares with per share earnings of $1.65 in 2006 and $1.68 in 2005. These performance results are particularly gratifying given that 2005, 2006 and 2007 are the three warmest consecutive heating seasons since the 1930s. I am also pleased to report that your Board of Directors elected to raise the annualized dividend rate to $1.25 per share, a 2.5 percent increase, effective with the February 1, 2008, quarterly dividend for shareholders of record on January 17, 2008. This is the Company’s tenth dividend increase since 1995 and continues our 63-year record of consecutive quarterly dividend payments to shareholders.

Fiscal 2007 was a busy regulatory year including filing and processing rate case applications with both Virginia and West Virginia Public Service Commissions, and special-purpose filings with both Commissions for approval to sell Bluefield Gas Company in West Virginia and the natural gas distribution assets of Roanoke Gas Company in Bluefield, VA. The year also included continuation of our construction program at Roanoke Gas Company to expand the natural gas distribution system and to replace older portions of the system installed decades ago when cast iron and bare steel pipe were the pipeline materials of choice.

I am pleased to report company earnings of $3.8 million or $1.75 per average diluted share outstanding. This compares with per share earnings of $1.65 in 2006 and $1.68 in 2005.

A final order in the Virginia rate case is pending; however, we have placed new rates into effect subject to refund of any amounts collected above the level eventually approved by the Virginia Commission. Both states approved the sale of the Bluefield operations and effective October 31, 2007, a month after our fiscal year end, RGC Resources, Inc. sold the common stock of Bluefield Gas Company to ANGD, LLC. Roanoke Gas Company sold its Bluefield area natural gas distribution assets to Appalachian Natural Gas Distribution

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RGC Resources, Inc. {2} 2007 Annual Report

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Virginia and Tennessee Railroad

1851

Big Lick, later named Roanoke, became a stop on the Virginia and Tennessee Railroad in the 1850s. In 1882, the Shenandoah Valley Railroad, which later became the Norfolk and Western Railway, arrived and transformed the small community into Virginia’s fifth largest city within a decade.

Gas workers, early 1800s.

Roanoke, 1883.

Gas meter wagon circa 1880.

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1907

An example of Georgian Revival architecture, Roanoke’s historic Fire Station #1 opened in 1907 and was the oldest operating firehouse in Virginia. It is modeled after Independence Hall in Philadelphia and St. Paul’s Cathedral in London.

Roanoke Fire Station No 1

125 YEARS

OF MAKING HISTORY

Company, a subsidiary of ANGD, LLC. The Company received $9.2 million in cash and a promissory note for $1.3 million in proceeds at the closing. Net proceeds remaining after retirement of outstanding loans and obligations were $3 million in cash and the $1.3 million promissory note. The Company plans to utilize the available cash from the sale to help fund the ongoing cast iron and bare steel pipeline replacement program on the Roanoke Gas distribution system.

We believe the sale of the Bluefield Gas operations is an appropriate strategic move for the Company. It will allow us to redeploy capital to the Roanoke Gas utility system, which has greater growth potential and a significantly better earnings record. It will also eliminate management time spent operating a very small noncontiguous distribution system serving only 4,600 customers, with the added regulatory complexity of being a multi-state utility system.

We continued to expand and renew the Roanoke Gas Company natural gas distribution system, installing 12.1 miles of new main and replacing 5.5 miles of cast iron or bare steel main with either coated steel or plastic pipe. We also installed 960 new service lines associated with customer growth and replaced 358 bare steel service lines.

We were pleased to experience continued moderate customer growth given the recent decline in the housing and mortgage sectors of the economy. We are also pleased to have completed our two-year distribution system renewal project in the City of Salem. Since starting the distribution system renewal program in 1991, the percentage of cast iron and bare steel pipeline miles to total pipeline miles has declined from 22 percent to 8 percent. During that same period the percentage of bare steel service lines to total service lines has declined from 26 percent to 7 percent.

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RGC Resources, Inc. {5} 2007 Annual Report

Natural gas prices have continued their volatile trend; however, average prices are generally comparable to last year. The Company’s average cost of storage gas leading into this winter was $7.27 per decatherm compared with $7.03 last year. On the national level, natural gas inventories this November were at an all time high, indicating adequate supplies for the 2007-2008 winter season. Our retail price to customers for October, November and December of 2007 was essentially the same as last year, and significantly lower than for the same period in 2005, which was negatively impacted by supply constraints from the damage to natural gas production facilities caused by hurricanes Rita and Katrina in the Gulf Coast region. Current pricing and inventory levels are positively influenced by lower space heating demand from consecutive years of warmer than normal winters.

Given that burning natural gas produces far less carbon dioxide emission per unit of energy than coal, natural gas will play an increasingly prominent role in meeting future energy needs and climate change mitigation efforts.

The longer-term natural gas price and supply outlook is far more complicated. A likely return to colder weather coupled with the steadily increasing use of natural gas to generate electricity will increase the demand for natural gas. Congress has not allowed access to the outer continental shelf on the East and West coasts for natural gas exploration and new supply development, and construction of the proposed Alaskan natural gas pipeline to the lower 48 states is not a certainty. Both Republican and Democratic controlled Congress have failed to develop a long-term comprehensive energy strategy for the nation. In addition, the current Congress is considering climate change legislation to limit growth in greenhouse gas emissions, particularly carbon dioxide. Given that burning natural gas produces far less carbon dioxide emission per unit of energy than coal, natural gas will play an increasingly prominent role in meeting future energy needs and climate change

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RGC Resources, Inc. {6} 2007 Annual Report

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Mill Mountain Star

1949

In 1949, a group known as the Roanoke Merchants Association decided that it would be a great kickoff for the year’s Christmas shopping season if they built a neon star on top of Mill Mountain. The Mill Mountain Star has given the city of Roanoke the nickname “Star City”.

Building the Trinity Pipeline, 1958. The Roanoke Gas

Company Service and

Distribution fleets, 1988.

RGC Headquarters ~ 2007.

mitigation efforts. This growing importance and demand for natural gas will certainly put pressure on prices. We hope it will also pressure legislative and regulatory bodies to allow access to new areas for exploration and development of additional supplies, along with siting approval for construction of more liquefied natural gas importation facilities to allow the United States greater access to the international natural gas market.

We are pleased to provide you with our 2007 Annual Report celebrating not only a strong performance year, but also a Company service and anniversary milestone. Calendar year 2008 will mark our 125th year of service in the Roanoke Valley. We look forward to many more years of providing safe, efficient and reliable natural gas service to our customers, competitive returns to our shareholders and fulfilling careers to our employees.

We look forward to many more years of providing safe, efficient and reliable natural gas service to our customers, competitive returns to our shareholders and fulfilling careers to our employees.

On behalf of the Board of Directors and employees of RGC Resources, Inc., I thank you for your continuing interest in our operations and for your decision to become and remain an investor. We continue to offer a dividend reinvestment and stock purchase program, free of commission or transaction fees, for shareholders who desire automatic reinvestment of part or all of their dividends or who wish to make additional direct purchases of stock through the program. We also offer the option of “book entry” share ownership as a way for shareholders to avoid the need for physical possession of shares. Please contact us at 540-777-3853, or go to our website at www.rgcresources.com, if you would like additional information on either program.

Sincerely,

/s/ John B. Williamson, III

John B. Williamson, III

Chairman, President and CEO

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RGC Resources, Inc. {8} 2007 Annual Report

SELECTED FINANCIAL DATA


Years Ended September 30,	2007		2006		2005		2004			2003
Operating Revenues	$	89,901,301	$	94,590,872	$	88,600,836	$	74,152,594		$	66,483,648
Gross Margin		25,221,776		23,208,272		22,206,395		20,655,455			19,189,381
Operating Income		7,958,279		6,677,500		6,395,564		4,270,554			4,187,799
Net Income - Continuing Operations		3,765,669		2,961,802		2,916,798		1,627,165			1,485,822
Net Income - Discontinued Operations		40,540		549,729		590,108		11,306,848			2,042,567
Basic Earnings Per Share- Continuing Operations	$	1.74	$	1.40	$	1.40	$	0.80		$	0.75
Basic Earnings Per Share- Discontinued Operations		0.02		0.26		0.29		5.58	*		1.03

Cash Dividends Declared Per Share	$	1.22	$	1.20	$	1.18	$	5.67		$	1.14
Book Value Per Share		19.38		18.94		18.18		17.73			16.90
Average Shares Outstanding		2,162,803		2,120,267		2,079,851		2,027,908			1,983,970
Total Assets		116,332,455		114,662,572		113,563,416		114,972,556			104,364,733

Long-Term Debt (Less Current Portion)		23,000,000		28,000,000		28,000,000		24,000,000			28,219,987
Stockholders’ Equity		42,365,233		40,494,868		38,157,357		36,621,522			33,857,614
Shares Outstanding at Sept. 30		2,186,143		2,138,595		2,098,935		2,065,408			2,003,232

*	Reflects $4.69 gain on sale of assets.

FORWARD LOOKING STATEMENTS

From time to time, RGC Resources, Inc. (“Resources” or the “Company”) may publish forward-looking statements relating to such matters as anticipated financial performance, business prospects, technological developments, new products, research and development activities and similar matters. The Private Securities Litigation Reform Act of 1995 provides a safe harbor for forward-looking statements. In order to comply with the terms of the safe harbor, the Company notes that a variety of factors could cause the Company’s actual results and experience to differ materially from the anticipated results or other expectations expressed in the Company’s forward-looking statements. The risks and uncertainties that may affect the operations, performance, development and results of the Company’s business include, but are not limited to, the following: (i) failure to earn on a consistent basis an adequate return on invested capital; (ii) ability to retain and attract professional and technical employees; (iii) the potential loss of large-volume industrial customers to alternate fuels, facility closings or production changes; (iv) volatility in the price and availability of natural gas; (v) uncertainty in the projected rate of growth of natural gas requirements in the Company’s service area; (vi) general economic conditions both locally and nationally; (vii) increases in interest rates; (viii) increased customer delinquencies and conservation efforts resulting from high fuel costs and/or colder weather; (ix) developments in electricity and natural gas deregulation and associated industry restructuring; (x) variations in winter heating degree-days from normal; (xi) changes in environmental requirements, pipeline operating requirements and cost of compliance; (xii) impact of potential increased regulatory oversight and compliance requirements due to financial, environmental, safety and system integrity laws and regulations; (xiii) failure to obtain timely rate relief for increasing operating or gas costs from regulatory authorities; (xiv) ability to raise debt or equity capital; (xv) impact of terrorism; (xvi) volatility in actuarially determined benefit costs; (xvii) impact of natural disasters on production and distribution facilities and the related effect on supply availability and price; and (xviii) 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”, “budget” or similar words or future or conditional verbs such as “will,” “would,” “should,” “could” or “may” are intended to identify forward-looking statements.

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

RGC Resources, Inc. {9} 2007 Annual Report

MANAGEMENT’S DISCUSSION & ANALYSIS

OVERVIEW

Resources is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately 55,400 residential, commercial and industrial customers in Roanoke, Virginia and the surrounding areas through its Roanoke Gas Company (“Roanoke Gas”) subsidiary. Natural gas service is provided at rates and for the terms and conditions set forth by the State Corporation Commission (“SCC” or “Virginia Commission”). Roanoke Gas currently holds the only franchises and/or certificates of public convenience and necessity to distribute natural gas in its Virginia service areas. These franchises are effective through January 1, 2016. While there are no assurances, the Company believes that it will be able to negotiate acceptable franchises when the current agreements expire. Certificates of public convenience and necessity in Virginia are exclusive and are intended to be of perpetual duration.

Resources also provided regulated sale and distribution of natural gas to Bluefield, West Virginia, the Town of Bluefield, Virginia and surrounding areas through its Bluefield Gas Company (“Bluefield Gas”) subsidiary and the Bluefield division of Roanoke Gas (collectively called “Bluefield Operations”). On February 16, 2007, Resources entered into a Purchase and Sale Agreement for the sale of Bluefield Gas stock and on the same date Roanoke Gas entered into a Purchase and Sale Agreement for the sale of its natural gas distribution assets located in the Town of Bluefield and the County of Tazewell, Virginia. The Bluefield Operations represent approximately 4,600 customers of the total 60,000 customers of Resources as of September 30, 2007. The sale of the Bluefield stock and the assets of the Bluefield division of Roanoke Gas was closed effective as of October 31, 2007, and the corresponding activities have been classified as discontinued operations.

Resources also provided unregulated energy products through Diversified Energy Company, which operated as Highland Energy Company. Highland Energy brokered natural gas to industrial and commercial transportation customers of Roanoke Gas and Bluefield Gas. In August 2006, Diversified Energy Company sold its energy marketing operations. These operations are also classified as discontinued operations.

Please see footnote 2 and the Discontinued Operations section below for further discussion regarding the sale of the Bluefield Operations and energy marketing operations.

With the exception of the Discontinued Operations section below, all discussion and analysis excludes the activities of Bluefield Gas, the Bluefield division of Roanoke Gas and Highland Energy.

Winter weather conditions and volatility in natural gas prices both have a direct influence on the quantity of natural gas sales, and management believes each factor has the potential to significantly impact earnings. A majority of natural gas sales are for space heating during the winter season. Consequently, during warmer than normal winters, customers may significantly reduce their purchase of natural gas.

The Company is able to mitigate a portion of the risk associated with warmer than normal winter weather by the inclusion of a weather normalization adjustment (“WNA”) factor as part of Roanoke Gas’ rate structure. The WNA factor operates based on a weather occurrence band around the most recent 30-year temperature average for the Company’s service area. The weather band provision utilizes an approximate 6% range around normal weather, whereby if the number of heating degree-days (an industry measure by which the average daily temperature falls below 65 degrees Fahrenheit) fall within approximately 6% above or below the 30-year average, no adjustment would be made. However, if the number of heating degree-days were more than 6% below the 30-year average, the Company would add a surcharge to firm customer bills (those customers not subject to service interruption) equal to the equivalent margin lost below the approximate 6% level. Likewise, if the number of heating degree-days were more than 6% above the 30-year average, the Company would credit firm customer bills equal to the excess margin realized above the 6% heating degree-day level. The measurement period in determining the weather band extends from April through March with any adjustment to be made to customer bills in late spring. The heating degree-days for the period April 2006 through March 2007 were approximately 10% less than the 30-year average. As the level of degree-days fell outside the 6% band, the Company realized approximately $439,000 in additional revenues from continuing operations and billed the shortfall to customers accordingly. The Company realized approximately $316,000 and $420,000 in additional revenues from the WNA in fiscal 2006 and 2005, respectively.

RGC Resources, Inc. {10} 2007 Annual Report

Management also has concerns regarding the volatility of natural gas prices and the potential for reduced sales in response to increasing prices. Rising natural gas prices, due to increasing demand and limitations to accessible supply, may influence the level of sales due to conservation efforts by customers or by switching to an alternative fuel, particularly in the industrial market. In addition, increasing prices may increase the level of bad debts due to customers’ inability to afford the higher prices. Minimal hurricane activity during 2007, a warmer than normal early fall season and adequate storage supplies have contributed to stable natural gas prices; however, extended periods of colder than normal weather or supply disruptions could result in increasing natural gas commodity prices. The Company has an approved rate structure in place that mitigates the impact of financing costs of inventory related to rising natural gas prices. Under this rate structure, Roanoke Gas accrues revenue to cover the financing costs or “carrying costs” related to the level of investment in natural gas inventory. During times of rising gas costs and rising inventory levels, the company recognizes revenues to offset higher financing costs associated with higher inventory balances. Conversely, during times of decreasing inventory costs and lower inventory balances, the Company would recognize less carrying cost revenue as the financing costs would be less. The Company recognized approximately $1,955,000, $1,993,000 and $1,692,000 in carrying cost revenues for the years ended September 30, 2007, 2006 and 2005, respectively.

For the fiscal year ended September 30, 2007, the implementation of a $1.7 million non-gas rate increase and nominal increases in natural gas sales volumes provided for an increase in income from continuing operations of more than $800,000, more than offsetting increases in operating, maintenance and depreciation expenses.

PERFORMANCE GRAPH

COMPARE 5-YEAR CUMULATIVE TOTAL RETURN

AMONG RGC RESOURCES, INC., S&P UTILITIES AND HEMSCOTT GROUP INDEX

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ASSUMES $100 INVESTED ON OCT. 1, 2002

ASSUMES DIVIDEND REINVESTED

FISCAL YEAR ENDING SEPT. 30, 2007


	2002	2003	2004	2005	2006	2007
RGC Resources, Inc.	100.00	133.82	170.47	200.26	205.24	223.85
Hemscott Group Index	100.00	125.53	153.93	207.99	241.82	302.33
S&P Utilities	100.00	122.67	146.70	203.43	213.14	258.22

RGC Resources, Inc. {11} 2007 Annual Report

RESULTS OF OPERATIONS – CONTINUING OPERATIONS

Fiscal Year 2007 Compared With Fiscal Year 2006

Delivered Volumes—The table below reflects volume activity and heating degree-days.


Year Ended September 30,	2007	2006	Increase/ (Decrease)		Percentage
Regulated Natural Gas (DTH)
Tariff Sales	6,802,773	6,660,887	141,886		2	%
Transportation	2,735,456	2,853,500	(118,044	)	-4	%

Total	9,538,229	9,514,387	23,842		0	%
Heating Degree Days (Unofficial)	3,735	3,714	21		1	%

Total natural gas sales volumes were essentially unchanged from the prior fiscal year as total heating degree days for the year ended September 30, 2007 (fiscal 2007) only increased by 1%. Tariff sales, consisting primarily of the more weather sensitive residential and commercial customers, increased by 2% reflecting a partial rebound from the customer conservation efforts experienced in fiscal 2006. Excluding the industrial customer sales component of tariff sales, which tend to be used more in processing activities rather than for heating, total weather sensitive sales volumes increased by more than 4%. Combined, industrial sales and transportation sales declined by 8% primarily due to circumstances that began during fiscal 2006: a full-year effect of an industrial customer that converted a majority of its processes to utilize coal and two smaller industrial customers that closed their operations in the Roanoke area. The remaining reduction in volume was attributable to lower natural gas consumption due to changes in production activities.

Operating Revenues—The table below reflects operating revenues.


Year Ended September 30,	2007		2006		Increase/ (Decrease)			Percentage
Gas Utilities	$	89,175,661	$	93,746,408	$	(4,570,747	)	-5	%
Other		725,640		844,464		(118,824	)	-14	%

Total Operating Revenues	$	89,901,301	$	94,590,872	$	(4,689,571	)	-5	%

The reduction in operating revenues resulted from lower natural gas costs reflected in the billing rates more than offsetting the implementation of base rate increases and slightly higher sales volumes. The average per unit cost of natural gas declined by 11%.

Gross Margin - The table below reflects gross margins.


Year Ended September 30,	2007		2006		Increase/ (Decrease)		Percentage
Gas Utilities	$	24,833,279	$	22,860,718	$	1,972,561	9	%
Other		388,497		347,554		40,943	12	%

Total Gross Margin	$	25,221,776	$	23,208,272	$	2,013,504	9	%

RGC Resources, Inc. {12} 2007 Annual Report

Gas utility margins increased due to the combination of a 2% increase in tariff sales and the implementation of a non-gas rate increase. The increase in tariff sales, as discussed above, reflects a reversal of customers’ energy conservation efforts in the prior year presumably in response to high natural gas prices during the winter of fiscal 2006. In October 2006, Roanoke Gas placed increased non-gas rates into effect subject to refund pending a final order from the Virginia Commission. In April 2007, Roanoke Gas received a final rate order approving an increase in non-gas rates of more than $1,600,000 based on normal winter weather. The rate increase provided for both a higher customer base charge, the flat monthly fee billed to each natural gas customer, and volumetric rate. As a result of the rate increase and higher tariff sales, customer base charges accounted for approximately $496,000 of the increase in margin and volumetric sales margins accounted for approximately $1,521,000. The remainder of the difference in margin resulted from a reduction of $45,000 in inventory carrying cost and other revenues.

Other margins increased by $40,943 primarily due to billings related to temporary work performed in the unregulated operations of Roanoke Gas.

Other Operating Expenses—Operations expenses increased $347,534, or 3%, in fiscal 2007 compared with fiscal 2006 as increases in professional and contractor services and reductions in capitalized overheads more than offset declines in bad debt expense and employee benefit costs. Operations labor and contractor expenses increased by $353,000 associated with an enhanced leak survey initiative on the distribution system pipeline, increased computer network reliability and security program assessments and employee compensation. The Company also reduced the level of capital activity and the production of LNG (liquefied natural gas) resulting in a $233,000 reduction of capitalized overheads. Professional services increased $160,000 related to Sarbanes-Oxley 404 related control testing and documentation, increased actuarial work required to implement SFAS No. 158, fees to obtain consent reviews from prior external auditors and additional audit work associated with discontinued operations. Bad debt expense declined by $234,000 due to strong collection efforts and improved aging due to the warm heating season and stable energy prices. Employee benefit expenses decreased due to a $324,000 reduction in pension and other post employment benefit costs attributable to an increase in the discount rate used to determine the actuarial expense for the current year. The remaining increases were attributable to a variety of other minor expense increases.

Maintenance expenses increased by $133,098, or 10%, due to a higher level of distribution pipeline maintenance associated with increased pipeline leak survey activity and increased general facility maintenance.

General taxes remained virtually unchanged increasing by $16,356, or 1%, in fiscal 2007 compared to fiscal 2006 due to increased property taxes associated with greater levels of taxable property.

Depreciation expense increased $235,737, or 6% due to capital expenditures associated with system expansion for adding new natural gas customers and pipeline and facility renewal projects.

Interest Expense —Total interest expense for fiscal 2007 decreased $69,209, or 3%, from fiscal 2006, as the total average debt outstanding during the year decreased by 8% while the average effective interest rate on total debt increased from 6.3% to 6.6%.

Debt Summary—


Year Ended September 30,	2007		2006		Increase/ (Decrease)		Percentage
Average Daily Balance:
Long-term Fixed Rate Debt	28,000,000		27,275,708		724,292		3	%
Short-term Variable Rate Debt	2,029,016		5,402,310		(3,373,294	)	-62	%
Total Debt	30,029,016		32,678,018		(2,649,002	)	-8	%
Average Interest Rate:
Long-term Fixed Rate Debt	6.7	%	6.7	%	0.0	%	0	%
Variable Rate Debt	5.8	%	4.9	%	0.9	%	18	%

RGC Resources, Inc. {13} 2007 Annual Report

The reduction in interest expense corresponds to a 62% decline in the average outstanding balance under the line of credit even though short-term interest rates rose 18% during the period. The combination of lower average natural gas inventories, higher customer credit balances under the budget payment program, greater level of over-collection of gas costs during fiscal 2007 compared to fiscal 2006 and improved earnings all contributed to reducing the overall average borrowing requirements.

Income Taxes—Income tax expense from continuing operations increased $533,993, or 31% from fiscal 2006 corresponding to a 29% increase in pre-tax earnings. The effective tax rate for fiscal 2007 was 37.3% compared to 36.5% in fiscal 2006.

Net Income and Dividends—Income from continuing operations for fiscal 2007 was $3,765,669 compared to fiscal 2006 income from continuing operations of $2,961,802. The improvement in income from continuing operations derived primarily from the non-gas cost rate increase, which more than offset the impact of increases in operations and maintenance expenses. Basic and diluted earnings per share from continuing operations were $1.74 and $1.73 in fiscal 2007 compared with $1.40 and $1.39 in fiscal 2006, respectively. Dividends per share of common stock were $1.22 in fiscal 2007 and $1.20 in fiscal 2006.

Fiscal Year 2006 Compared With Fiscal Year 2005

Delivered Volumes—The table below reflects volume activity and heating degree-days.


Year Ended September 30,	2006	2005	Increase/ (Decrease)		Percentage
Regulated Natural Gas (DTH)
Tariff Sales	6,660,887	7,174,230	(513,343	)	-7	%
Transportation	2,853,500	3,202,923	(349,423	)	-11	%

Total	9,514,387	10,377,153	(862,766	)	-8	%
Heating Degree Days (Unofficial)	3,714	3,783	(69	)	-2	%

Tariff sales, primarily consisting of residential and commercial usage, declined 7% for the year ended September 30, 2006 (fiscal 2006)compared to the year ended September 30, 2005 (fiscal 2005) due to a decrease in heating degree-days and conservation. Transporting volumes, which correlate more with economic factors and business decisions rather than weather, reflected a reduction of 11 % from fiscal 2005. The reduction in transporting volumes appeared to be related to a combination of fuel switching and other economic factors. Nearly half of the reduction in transporting volumes related to one industrial customer that converted a majority of its processes to utilize coal to lower energy costs. Most of the remaining reduction was related to production activities and two smaller industrial transportation customers closing their operations in the Roanoke area.

Operating Revenues—The table below reflects operating revenues.


Year Ended September 30,	2006		2005		Increase/ (Decrease)			Percentage
Gas Utilities	$	93,746,408	$	87,752,669	$	5,993,739		7	%
Other		844,464		848,167		(3,703	)	0	%

Total Operating Revenues	$	94,590,872	$	88,600,836	$	5,990,036		7	%

The increase in operating revenues resulted from higher natural gas costs reflected in the billing rates and the implementation of base rate increases. The average per unit cost of natural gas increased by 16%.

RGC Resources, Inc. {14} 2007 Annual Report

Gross Margin—The table below reflects gross margins.


Year Ended September 30,	2006		2005		Increase/ (Decrease)			Percentage
Gas Utilities	$	22,860,718	$	21,716,619	$	1,144,099		5	%
Other		347,554		489,776		(142,222	)	-29	%
Total Gross Margin	$	23,208,272	$	22,206,395	$	1,001,877		5	%

Regulated natural gas margins increased by $1,144,099, or 5%, even though total delivered volume (tariff and transporting) decreased by 862,766 decatherms, or 8%. The decline in delivered tariff volumes was attributable in part to weather that had 2% fewer heating degree-days; however, the greater impact surrounding the decline in volume resulted from customers’ energy conservation presumably in response to high natural gas prices during the winter period. Transportation sales deliveries, composed of large industrial customers, declined by 11% due to energy costs and other economic factors as discussed above. Even though delivered volumes declined, the regulated natural gas margin increased due to non-gas cost rate increases and the recovery of the financing costs (“carrying costs”) related to rising interest rates and higher average dollar investments in storage gas inventories. Roanoke Gas Company placed increased non-gas rates into effect during the first quarter of fiscal 2006 subject to refund pending a final order from the Virginia Commission. The rate increase provided for both a higher customer base charge, the flat monthly fee billed to each natural gas customer, and volumetric rate. As a result, customer base charges increased by approximately $414,000 and volumetric margins increased by approximately $400,000, including the impact of reduced sales volumes and lower WNA billings. Carrying cost revenues increased by approximately $301,000 due to a combination of higher average storage gas inventory during the current fiscal year and rising interest rates.

Other margins decreased by $142,222 due to the expiration of the services agreement to provide billing, facility and other services to the acquirer of Highland Propane Company.

Other Operating Expenses—Operations expenses increased $495,176, or 5%, in fiscal 2006 compared with fiscal 2005 primarily as a result of net higher employee benefit costs. Employee benefit costs increased due to higher health care, pension and postretirement benefit expenses. The Company had been self-insured for medical insurance purposes for the past several years with stop/loss coverage only for extremely high claim activity. The self-insurance program generated volatility in expense due to fluctuating claim levels. During the quarter ended December 31, 2004, claims expense under the self-insured program was unusually low. In January 2005, the Company switched to fully insured coverage to provide a more predictable expense trend, which has reduced volatility between reporting periods but resulted in approximately $165,000 in higher cost in the first quarter of fiscal 2006 compared to fiscal 2005. The Company also experienced an increase of approximately $414,000 attributable to its pension and postretirement medical plan due to the actuarial effect of a lower discount rate used in expense and liability calculations as well as the adoption of new mortality tables. The increased benefit costs also served to increase the benefit capitalization factor as a percent of labor which provided for an increase of $130,000 in expenses capitalized in fiscal 2006 as compared to fiscal 2005.

Maintenance expenses decreased by $34,889, or 3%, as the level of leak repairs, facility maintenance and transmission right-of-way clearing were comparable with the prior fiscal year.

General taxes increased $63,125, or 6%, in fiscal 2006 compared to fiscal 2005 due to increased property taxes associated with greater levels of taxable property.

Depreciation expense increased $196,529, or 5% due to capital expenditures associated with system expansion for adding new natural gas customers and pipeline and facility renewal projects.

Other expenses, net, decreased $48,117 as a result of a greater level of interest income on temporary cash investments in fiscal 2006 and the loss on retirement of a propane air facility in fiscal 2005.

RGC Resources, Inc. {15} 2007 Annual Report

Interest Expense - Total interest expense for fiscal 2006 increased $300,479, or 18%, from fiscal 2005, as the total average debt outstanding during the year increased by 11% while the average effective interest rate on total debt increased from 6.1% to 6.4%.

Debt Summary -


Year Ended September 30,	2006		2005		Increase/ (Decrease)		Percentage
Average Daily Balance:
Long-term Fixed Rate Debt	27,275,708		24,000,000		3,275,708		14	%
Short-term Variable Rate Debt	5,402,310		5,317,290		85,020		2	%
Total Debt	32,678,018		29,317,290		3,360,728		11	%
Average Interest Rate:
Long-term Fixed Rate Debt	6.7	%	6.8	%	-0.1	%	-1	%
Variable Rate Debt	4.9	%	2.9	%	2.0	%	69	%

The higher debt balance resulted from the refinancing of the $8,000,000 unsecured note due November 30, 2005, $3,000,000 collateralized term debenture due in 2016 and $4,000,000 in line-of-credit into a $15,000,000 five year unsecured variable rate note with a corresponding interest rate swap. The result of the refinancing provided for an effective long-term interest rate consistent with fiscal 2005. The increase in interest rates on short-term and variable rate debt was attributable to Federal Reserve policy designed to control inflation. The average effective interest rate on the Company’s variable rate lines-of-credit increased by 195 basis points, or 69%, over fiscal 2005.

Income Taxes—Income tax expense from continuing operations decreased $15,430, or 1 % from fiscal 2005 as pre-tax earnings reflected a slight increase. The effective tax rate for fiscal 2006 was 36.5% compared to 37.1% in fiscal 2005.

Net Income and Dividends—Income from continuing operations for fiscal 2006 was $2,961,802 as compared to fiscal 2005 income from continuing operations of $2,916,798. The improvement in income from continuing operations derived from the non-gas cost rate increase and increased carrying cost revenues, which more than offset the impact of warmer winter weather, the effect of customer energy conservation and higher operation expenses. Basic and diluted earnings per share from continuing operations were $1.40 and $1.39 in fiscal 2006 and 2005. Dividends per share of common stock were $1.20 in fiscal 2006 and $1.18 in fiscal 2005.

DISCONTINUED OPERATIONS

As discussed in footnote 2 of the financial statements, on February 16,2007, Resources entered into a Purchase and Sale Agreement with ANGD, LLC (“ANGD”) for the sale of all of the capital stock of Bluefield Gas to ANGD and Roanoke Gas entered into an Asset Purchase and Sale Agreement with Appalachian Natural Gas Distribution Company (“Appalachian”) for the sale of Roanoke Gas’ natural gas distribution assets located in the Town of Bluefield and the County of Tazewell, Virginia, (“Bluefield division of Roanoke Gas Company”) to Appalachian, which is a wholly owned subsidiary of ANGD. All of the 3,500 customers of Bluefield Gas and 1,100 Bluefield division of Roanoke Gas Company customers are covered by these sale agreements. The sales price of the stock is equal to the book value of Bluefield Gas’ net assets on the date of closing. The sales price of the Virginia assets is equal to the book value of net plant plus 1% plus the book value of accounts receivable, natural gas inventory, and certain other listed current assets, subject to mutually agreed upon or arbitrated purchase price adjustments determined subsequent to the closing date but no later than 230 days after closing. $1,300,000 of such sale price is payable in the form of a subordinated promissory note from ANGD with a 5-year term and a 15-year amortization schedule with annual principal payments and quarterly interest payments at a 10% interest rate. As a part of the Purchase and Sale Agreement, Resources and Roanoke Gas will provide certain customer billing, gas control, regulatory and administrative services for

RGC Resources, Inc. {16} 2007 Annual Report

Bluefield Gas and Appalachian on mutually agreeable terms. The length of time this services agreement will be in place will be dependent on the time it takes Bluefield Gas and Appalachian to assume these processes in their own operations; however, management expects most of the services to be fully assumed within one year of closing.

Although the Purchase and Sale Agreement with ANGD for the sale of the capital stock of Bluefield Gas provides for a sales price substantially equal to the book value of Bluefield’s net assets on the date of closing, the underlying tax basis that Resources has in the stock is significantly less than the book basis. This lower tax basis has resulted in the recording of an estimated income tax expense attributable to the anticipated taxable gain for the excess of the book basis of the assets over the tax basis. The current estimate of tax liability expected to be realized on this transaction is reflected as part of income tax expense in discontinued operations.

The Company received regulatory approvals from the respective regulatory commissions in Virginia and West Virginia prior to the end of the Company’s fiscal year and both transactions closed effective as of October 31, 2007. As the likelihood of the completion of these transactions met the probable definition of SFAS No. 144 prior to September 30, 2007, the activities associated with the Bluefield Operations were reclassified as Discontinued Operations. SFAS No. 144 also requires depreciation to be suspended on those assets classified as held for sale. Due to regulatory requirements, depreciation expense continued on those assets included as held for sale since June 2007 when those assets were reclassified. The total depreciation expense related to those assets while classified as held for sale was approximately $110,000. At closing the Company received payment of $9,000,000 and a subordinated note of $1,300,000 based on estimated values as of October 31, 2007. Determination of the final cash settlement will be made following the reporting of October’s results for the Bluefield Operations and mutual agreement of the final valuations of the related accounts, which may be no later than 230 days from the date of closing.

In the short-term, the sale of the Bluefield Operations could result in lower earnings for Resources in the near term. The Bluefield Operations had pre-tax operating losses of approximately $135,000, $182,000 and $279,000 for fiscal 2007, 2006 and 2005, respectively. Included in the Bluefield Operations were approximately $773,000, $732,000 and $685,000 of costs allocated from Resources or Roanoke Gas that will continue after the sale. In applying the provisions of SFAS No. 144, these continuing costs were reclassified from the discontinued operations of Bluefield Gas to the corresponding line items of continuing operations on the income statement. A portion of these continuing costs will be recovered under the services agreement with ANGD as discussed above. In addition, the $1,300,000 promissory note from ANGD will generate interest income, and the Company expects to reinvest the net after-tax proceeds from the sale of Bluefield Gas stock into Roanoke Gas to be used to reduce company debt and interest expense. In Roanoke Gas’ next non-gas cost rate filing, the Company will file for a return on the additional equity investment resulting from the Bluefield sale as well as for recovery of the balance of those costs retained by the Company after the sale, net of any service agreement revenue. Under this scenario, operating results could improve as the net loss from Bluefield Operations would be replaced by a return on the additional equity investment into Roanoke. Based on the most recent rate filing, the Company could earn a 10 percent return on this equity investment.

LOGO

In July 2006, the Company entered into an asset purchase and sale agreement for the sale of the assets relating to its Highland Energy gas marketing business. The assets sold included the gas supply contracts between Highland Energy and its customers and related business records. The operations associated with the energy marketing business were reclassified as Discontinued Operations in accordance with the provisions of SFAS No. 144. The Company recognized approximately $233,000 gain on the sale of contracts in fiscal 2006; however, under the agreement, a portion of the sales price was deferred subject to certain provisions. As these provisions had been met, the Company recognized approximately $160,000 in gain on sale of assets in fiscal 2007 as part of discontinued operations in final settlement of the sales contract.

RGC Resources, Inc. {17} 2007 Annual Report

In June 2005, the Company sold 10 parcels of real estate consisting of bulk propane storage facilities and office space owned by Diversified Energy Company. These properties were originally part of the propane operations that were sold to Inergy Propane, LLC (“Inergy”) in 2004, but were retained and leased to Inergy with an option to purchase. The Company realized a net gain on the sale of real estate of approximately $153,000.

ENERGY PRICES

Energy costs represent the single largest expense of the Company with the cost of natural gas representing approximately 79% for fiscal 2007, 81% for fiscal 2006 and 81% for fiscal 2005 of the total operating expenses of the Company’s natural gas utility operations.

To mitigate the impact of price volatility, Roanoke Gas uses a variety of hedging mechanisms including summer storage injections and financial instruments to reduce the volatility of spot market purchases during the winter. At September 30, 2007, the Company’s natural gas storage levels were near capacity with nearly 2.56 million decatherms in storage. The Company also has financially hedged 680,000 decatherms of natural gas for the 2007-08 winter period.

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

Although rising natural gas prices are recoverable through the PGA mechanism, 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. Roanoke Gas Company’s rate structure provides a level of protection against the impact that rising energy prices may have on bad debts and carrying costs on LNG storage and gas in storage by allowing for more timely recovery of these costs. However, the rate structure will not protect the Company from increases in the rate of bad debts or increases in interest rates.

ASSET MANAGEMENT

Roanoke Gas Company uses a third party as an asset manager to manage its pipeline transportation and storage rights and gas supply inventories and deliveries. In return for being able to utilize the excess capacities of the transportation and storage rights, the third party pays Roanoke Gas a monthly utilization fee, which is used to reduce the cost of gas for customers. In October 2007, Roanoke Gas executed a new three-year agreement with a new asset manager to provide the same services including the payment of a monthly utilization fee.

LOGO

CAPITAL RESOURCES AND LIQUIDITY

Due to the capital intensive nature of Resources’ utility business as well as the related weather sensitivity, Resources’ primary capital needs are the funding of its continuing construction program and the seasonal funding of its natural gas inventories and accounts receivable. The Company’s construction program is primarily composed of a combination of replacing aging bare steel and cast iron pipe with new plastic or coated steel pipe and expansion of the natural gas system to meet the demands of customer growth. Total capital expenditures of continuing operations were $6.0 million, $7.2 million and $6.7 million for fiscal 2007, 2006 and 2005, respectively. Operating cash flow provided by depreciation contributed approximately $4.3 million in support of capital expenditures, or approximately 72% of the total investment. In fiscal 2006 and 2005, such cash flow provided 57% and 58%, respectively. It is anticipated that future capital expenditures will remain consistent with current levels and will be funded with the combination of operating cash flow, sale of Company equity securities through the Dividend Reinvestment and Stock Purchase Plan (“DRIP”) and issuance of debt.

RGC Resources, Inc. {18} 2007 Annual Report

On March 20, 2007, the Company and Wachovia Bank renewed the Company’s line-of-credit agreements. The agreements maintain the same variable interest rates based upon 30-day LIBOR and continue a tiered borrowing level to accommodate the Company’s seasonal borrowing demands. Due to the seasonality of the business, the Company’s borrowing needs generally are at their lowest in spring and early summer, increase during the late summer and fall due to gas storage purchases and construction and reach their maximum levels in winter. The tiered approach keeps the Company’s borrowing costs to a minimum by improving the level of utilization on its line-of-credit agreements and providing increased credit availability as borrowing requirements increase. The Company’s available limits under the remaining term of the line-of-credit agreements excluding Bluefield Gas’ $6,000,000 available limit that was terminated at closing are as follows:


Beginning	Continuing Operations
September 30, 2007	$	17,000,000
November 16, 2007		21,000,000
February 16, 2008		16,000,000

At September 30, 2007, the Company had $4,808,000 outstanding under its available lines-of-credit. The average rates on debt outstanding during the year under the lines-of-credit were 5.83% in 2007, 4.86% in 2006 and 2.94% in 2005. The lines do not require compensating balances. These lines-of-credit will expire March 31, 2008, unless extended. The Company anticipates being able to extend or replace the lines-of-credit.

In November 2005, Roanoke Gas entered into an unsecured 5-year note with provision for annual renewals in the amount of $15,000,000. The proceeds of this note were used to retire the $8,000,000 unsecured note due November 30, 2005 and $4,000,000 in outstanding line-of-credit balance. The remainder of the proceeds were used to call the $3,000,000 collateralized term debenture due in 2016 including the payment of a call premium. The Company entered into an interest rate swap agreement on the note for the purpose of fixing the interest rate at 5.74% over the total term of the note.

In July 2008, Roanoke Gas’ $5,000,000 note matures. Management anticipates being able to obtain new financing on terms acceptable to the Company to meet the cash requirements of the maturing note.

As discussed above, the Company and Roanoke Gas closed on the sale of the Bluefield Operations effective as of October 31, 2007. On the date of closing the Company received payment of $9,000,000 and a subordinated note of $1,300,000 based on estimated values as of October 31, 2007. After payoff of Bluefield’s outstanding debt at the date of closing and payment of the estimated income taxes associated with the taxable gain on sale of the stock of Bluefield Gas, the Company will increase its cash resources by approximately $3,300,000. The Company will use the net proceeds to reduce the corporate borrowing requirements under its line-of-credit agreements and to invest capital in Roanoke Gas to help fund its construction and pipeline renewal programs.

Short-term borrowings, together with internally generated funds through net income and operating cash flow, long-term debt and the sale of common stock through the Company’s DRIP Plan, have been adequate to cover construction costs, natural gas purchases, tax payments, debt service and dividend payments to shareholders. Management expects such sources of funds will continue to meet future cash requirements.

RGC Resources, Inc. {19} 2007 Annual Report

Stockholders’ equity increased for the period by $1,870,365, primarily due to earnings and proceeds from stock issued under the DRIP Plan. The activity is summarized below:


Net income	$	3,806,209
Dividends		(2,646,101	)
DRIP		855,322
Restricted stock and stock options		327,362
Net comprehensive income		(472,427	)

Increase in stockholders’ equity	$	1,870,365

At September 30, 2007, the Company’s consolidated long-term capitalization was 60% equity and 40% debt, compared to 59% equity and 41 % debt at September 30, 2006.

REGULATORY AFFAIRS

On September 14, 2006, Roanoke filed an application with the SCC for an expedited increase in non-gas rates to provide approximately $1,750,000 in additional revenues. The requested rates were placed into effect on October 23, 2006 subject to refund for any differences between the implemented rates and the final rates approved by the SCC. In April 2007, Roanoke received the final rate order approving $1,667,940 in additional revenues. In June 2007, Roanoke completed the refund of customer billings in excess of the final approved rates plus interest. Roanoke Gas Company also filed a new request to increase non-gas rates on September 17, 2007. These new rates, designed to provide approximately $700,000 in additional revenues, were placed into effect on November 1, 2007 subject to refund for any differences between the implemented rates and the final rates approved by the SCC. An SCC rate order is expected in the late spring of 2008.

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

RGC Resources, Inc.’s contractual obligations as of September 30, 2007 representing cash obligations that are considered to be firm commitments are as follows.

Payment due within the year ended September 30,


	2008		2009		2010		2011		2012		Thereafter
Lines-of-credit¹	$	4,808,000	$	—	$	—	$	—	$	—	$	—
Long-term debt¹		5,000,000		—		—		15,000,000		—		8,000,000
Natural gas (see below)
Pipeline and storage capacity		9,729,451		9,729,451		9,729,451		9,729,451		9,729,451		26,318,956

Total contractual obligations	$	19,537,451	$	9,729,451	$	9,729,451	$	24,729,451	$	9,729,451	$	34,318,956

1	Excludes interest payments attributable to the debt

Total available lines-of-credit are scheduled to expire on March 31, 2008, at which time the Company expects to renew the contracts. See footnote 4 in the consolidated financial statements for additional information.

See footnote 5 in the consolidated financial statements for more information on long-term debt.

RGC Resources, Inc. {20} 2007 Annual Report

The Company has commitments to purchase pipeline and storage capacity with related fees in the amount of $74,966,211 under contracts expiring at various times through the year 2020. The Company expects to recover these costs through the PGA mechanism. The Company also has commitments to purchase natural gas at market price over the next year in the amount of 285,985 decatherms. Under the new asset management agreement executed subsequent to September 30, 2007, the Company has additional commitments to purchase the following decatherms of natural gas at market price over the next four years:


Year Ended September 30,	Decatherms	Current Price
2008	1,907,195	$	12,728,000
2009	2,225,059		14,849,000
2010	2,225,059		14,849,000
2011	317,864		2,121,000

CRITICAL ACCOUNTING POLICIES

The consolidated financial statements of Resources are prepared in accordance with accounting principles generally accepted in the United States of America. The amounts of assets, liabilities, revenues and expenses reported in the Company’s financial statements are affected by accounting policies, estimates and 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. The following policies and estimates are important in understanding certain key components of the 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 (SFAS No. 71). The economic effects of regulation can result in a regulated company deferring costs that have been or are expected to be recovered from customers in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as assets in the consolidated balance sheet (regulatory assets) and recorded as expenses when such amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for current collection in rates of costs that are expected to be incurred in the future (regulatory liabilities).

If any portion of the current regulated operations ceased to meet the criteria for application of the provisions of SFAS No. 71, the Company would remove the corresponding regulatory assets or liabilities from the consolidated balance sheets and reflect them in the consolidated statement of income and comprehensive income for the period in which the discontinuance occurred.

Revenue recognition—Regulated utility sales and transportation revenues are based upon rates approved by the SCC. The non-gas cost component of rates may not be changed without a formal rate increase application and corresponding authorization by the SCC; however, the gas cost component of rates may be adjusted periodically through the PGA mechanism with approval from the SCC.

The Company bills its regulated natural gas customers on a monthly cycle. 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 and current and historical data. The financial statements included unbilled revenue of $1,287,362 and $1,462,878 as of September 30, 2007 and 2006.

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.

RGC Resources, Inc. {21} 2007 Annual Report

Retirement plans - The Company offers a defined benefit pension plan (“pension plan”) and a postretirement medical and life insurance plan (“postretirement plan”) to eligible employees. The expenses and liabilities associated with these plans, as disclosed in footnote 7 to the consolidated financial statements, are based on 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. Similarly, the postretirement 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. 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.

The following schedule reflects the sensitivity of pension costs to changes in certain actuarial assumptions, while the other components of the calculation remain constant.


Actuarial Assumption	Change in Assumption		Impact on 2007 Pension Cost		Impact on Projected Benefit Obligation
Discount rate	-0.25	%	$	61,000	$	514,000
Rate of return on plan assets	-0.25	%		23,000		N/A
Rate of increase in compensation	0.25	%		36,000		189,000

The following schedule reflects the sensitivity of postretirement benefit costs from changes in certain actuarial assumptions, while the other components of the calculation remain constant.


Actuarial Assumption	Change in Assumption		Impact on 2007 Postretirement Benefit Cost		Impact on Accumulated Postretirement Benefit Obligation
Discount rate	-0.25	%	$	49,000	$	234,000
Rate of return on plan assets	-0.25	%		11,000		N/A
Health care cost trend rate	0.25	%		32,000		264,000

Derivatives—As discussed in the “Market Risk” section below, the Company may hedge certain risks incurred in its operation through the use of derivative instruments. The Company applies the requirements of Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, which requires the recognition of derivative instruments as assets or liabilities in the Company’s balance sheet at fair value. In most instances, fair value is based upon quoted futures prices for natural gas commodities and interest rate futures for interest rate swaps. Changes in the commodity and futures markets will impact the estimates of fair value in the future. Furthermore, the actual market value at the point of realization of the derivative may be significantly different from the values used in determining fair value in prior financial statements.

MARKET RISK

The Company is exposed to market risks associated with commodity prices. Commodity price risk is experienced by the Company’s regulated natural gas operations. 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 risk of its business operations. The policy also specifies that the combination of all commodity hedging contracts for any 12-month period shall not exceed a total hedged volume of 90% of projected volumes. Finally, the policy specifically prohibits the utilization of derivatives for the purposes of speculation.

RGC Resources, Inc. {22} 2007 Annual Report

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

As of September 30, 2007, the Company had collar agreements outstanding for the purpose of hedging the price of natural gas during the winter period for 680,000 decatherms. Any cost incurred or benefit received from the derivative or other hedging arrangements would be expected to be recoverable or refunded through the regulated natural gas purchased gas adjustment (PGA) mechanism. The SCC currently allows for full recovery of prudent costs associated with natural gas purchases, and any additional costs or benefits associated with the settlement of the derivative contracts will be passed through to customers when realized.

The Company is also exposed to market risk related to changes in interest rates associated with its borrowing activities. As of September 30, 2007, the Company had $4,808,000 outstanding under its lines-of-credit. Based upon outstanding borrowings at September 30, 2007, a 100 basis point increase in market interest rates applicable to the Company’s variable rate debt would have resulted in an increase in annual interest expense of approximately $48,000.

OTHER RISKS

The Company is exposed to certain risks other than commodity and interest rates. Such 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 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 SCC will allow recovery for all such increased costs when rate applications are filed.

LOGO

Credit and Customer—Gas costs represent a major portion of the total customer bill. Although gas costs are lower than last year, they are expected to remain above long-term historical levels. The Company has worked diligently at minimizing bad debts and bad debt write offs. However, management anticipates that future significant increases or spikes in natural gas prices could result in an increased rate of delinquencies as customers face higher natural gas bills as well as other higher energy costs. In addition, the SCC has specific notice requirements with which the Company must comply before disconnecting natural gas service for customer nonpayment. The Company has mitigated some of the risk through increased deposit requirements based upon higher energy prices as well as obtained credit insurance coverage on certain of the Company’s larger volume industrial customers. Furthermore, the Company’s approved rate structure provides a level of protection against the impact that rising energy prices may have on bad debts. Nevertheless, the Company has no such protection if the percentage of bad debts to revenues increases above recent historical levels.

Actuarial Assumptions and Investment Returns—RGC Resources, Inc. offers both a defined benefit pension plan and postretirement medical benefits plan. The actuarially determined expenses of each of these plans are significantly impacted by key assumptions including the discount rate, the expected return on plan assets, life expectancies and medical inflation

RGC Resources, Inc. {23} 2007 Annual Report

(postretirement plan). From year to year, volatility in the discount rate has perhaps the most significant impact on determining benefit expense, the benefit obligation and corresponding funded status of each plan. For fiscal 2008, the discount remained unchanged at 6.25% and pension and postretirement expense are expected to be comparable with fiscal 2007. In addition, the actual return on plan assets also impacts the expense calculation and funded status. The Company has maintained a funding plan designed to increase plan assets and mitigate the impact of the underfunded position on both plans. However, a 10% loss on the plan assets would increase the underfunded position of the pension plan by nearly $1,100,000 and the postretirement plan by more than $500,000.

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. Since 2003, Roanoke Gas Company’s rate structure has included a weather normalization adjustment factor as discussed above. The Company should be at risk for no more than a 6% swing in heating degree-days above or below average.

Inflation—As with most businesses, the Company is subject to the effect of inflationary pressures. The single greatest cost to the Company is natural gas, which represented approximately 80% of the Company’s natural gas utility operations over each of the past three years. As discussed above, the PGA mechanism provides the Company with the ability to recover rising gas costs. Furthermore, rising operating and capital costs including labor, materials, contractors and other costs impact the Company’s results of operations and cash requirements. To obtain relief from these rising costs from both an expense and capital exposure, the Company will periodically file a request for a non-gas rate increase. See the Regulatory Affairs section above for additional information on current filings. While both the PGA and non-gas rate increases can provide protection for rising costs, approval of the full amount requested by the SCC is not guaranteed and the approved rate adjustments ultimately placed into effect are on a lagged basis to the expenses.

RGC Resources, Inc. {24} 2007 Annual Report

CAPITALIZATION STATISTICS


Years Ended September 30,	2007			2006			2005			2004			2003
COMMON STOCK:
Shares Issued		2,186,143			2,138,595			2,098,935			2,065,408			2,003,232
Continuing Operations:
Basic Earnings Per Share	$	1.74		$	1.40		$	1.40		$	0.80		$	0.75
Diluted Earnings Per Share	$	1.73		$	1.39		$	1.39		$	0.80		$	0.75
Discontinued Operations:
Basic Earnings Per Share	$	0.02		$	0.26		$	0.29		$	5.58	*	$	1.03
Diluted Earnings Per Share	$	0.02		$	0.26		$	0.29		$	5.53		$	1.02
Dividends Paid Per Share (Cash)	$	1.22		$	1.20		$	1.18		$	5.67		$	1.14
Dividends Paid Out Ratio		69.3	%		72.3	%		69.8	%		88.9	%		64.0	%

CAPITALIZATION RATIOS:
Long-Term Debt, Including Current Maturities		39.8			40.9			42.3			39.6			46.4
Common Stock And Surplus		60.2			59.1			57.7			60.4			53.6

Total		100.0			100.0			100.0			100.0			100.0

Long-Term Debt, Including Current Maturities	$	28,000,000		$	28,000,000		$	28,000,000		$	24,019,987		$	29,252,359
Common Stock And Surplus		42,365,233			40,494,868			38,157,357			36,621,522			33,857,614

Total Capitalization Plus Current Maturities	$	70,365,233		$	68,494,868		$	66,157,357		$	60,641,509		$	63,109,973

*	Reflects $4.69 gain on sale of assets.

RGC Resources, Inc. {25} 2007 Annual Report

MARKET PRICE & DIVIDEND PRICE INFORMATION

RGC Resources' common stock is listed on the Nasdaq National Market under the trading symbol RGCO. Payment of dividends is within the discretion of the Board of Directors and will depend on, among other factors, earnings, capital requirements, and the operating and financial condition of the Company. The Company's long-term indebtedness contains restrictions on dividends based on cumulative net earnings and dividends previously paid.


	Range of Bid Prices				Cash Dividends Declared
Fiscal Year Ended September 30,	High		Low		Cash Dividends Declared
2007
First Quarter	$	27.800	$	24.770	$	0.305
Second Quarter		28.700		24.840		0.305
Third Quarter		29.010		27.010		0.305
Fourth Quarter		28.700		25.880		0.305
2006
First Quarter	$	27.580	$	24.500	$	0.300
Second Quarter		25.740		24.300		0.300
Third Quarter		26.900		22.720		0.300
Fourth Quarter		28.140		24.020		0.300

RGC Resources, Inc. {26} 2007 Annual Report

SUMMARY OF GAS SALES & STATISTICS


Years Ended September 30,	2007		2006		2005		2004		2003
REVENUES:
Residential Sales	$	50,791,195	$	52,274,204	$	49,332,645	$	42,826,979	$	38,233,811
Commercial Sales		34,566,385		36,159,320		33,059,542		27,154,959		24,048,119
Interruptible Sales		1,379,870		3,054,240		3,029,697		1,234,144		1,887,212
Transportation Gas Sales		2,254,594		2,067,929		2,110,002		2,120,506		1,672,522
Backup Services		3,600		3,600		62,756		51,452		89,590
Late Payment Charges		55,438		70,191		55,109		71,065		96,941
Miscellaneous Gas Utility Revenue		124,579		116,924		102,918		92,433		50,889
Other		725,640		844,464		848,167		601,056		404,564

Total	$	89,901,301	$	94,590,872	$	88,600,836	$	74,152,594	$	66,483,648
NET INCOME
Continuing Operations	$	3,765,669	$	2,961,802	$	2,916,798	$	1,627,165	$	1,485,822
Discontinued Operations		40,540		549,729		590,108		11,306,848		2,042,567

Net Income	$	3,806,209	$	3,511,531	$	3,506,906	$	12,934,013	$	3,528,389
DTH DELIVERED:
Residential		3,778,194		3,588,364		3,987,368		4,281,320		4,563,672
Commercial		2,886,403		2,793,988		2,859,471		2,937,469		3,101,259
Interruptible		138,176		278,535		321,860		153,714		294,172
Transportation Gas		2,735,456		2,853,500		3,202,923		3,391,620		2,829,700
Backup Service		0		0		5,531		5,530		10,727

Total		9,538,229		9,514,387		10,377,153		10,769,653		10,799,530
HEATING DEGREE DAYS		3,735		3,714		3,783		3,917		4,349
NUMBER OF CUSTOMER
Natural Gas
Residential		50,371		49,649		49,178		48,215		47,672
Commercial		5,017		4,948		4,939		4,903		4,900
Interruptible and Interruptible
Transportation Service		32		32		36		36		37
Total		55,420		54,629		54,153		53,154		52,609
GAS ACCOUNT (DTH):
Natural Gas Available		9,744,431		9,703,011		10,546,259		11,061,144		11,089,300
Natural Gas Deliveries		9,538,229		9,514,387		10,377,153		10,769,653		10,799,530
Storage-LNG		65,279		98,936		89,896		117,378		102,907
Company Use And Miscellaneous		28,862		36,321		47,568		52,440		42,902
System Loss		112,061		53,367		31,642		121,673		143,961

Total Gas Available		9,744,431		9,703,011		10,546,259		11,061,144		11,089,300
TOTAL ASSETS	$	116,332,455	$	114,662,572	$	113,563,416	$	114,972,556	$	104,364,733
LONG-TERM OBLIGATIONS	$	23,000,000	$	28,000,000	$	28,000,000	$	24,000,000	$	28,219,987

RGC Resources, Inc. {27} 2007 Annual Report

OFFICERS AND BOARD OF 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) (3) (4)}

Howard T. Lyon

Vice President, Treasurer and

Controller ^{(1) (2) (3) (4) (5)}

Dale P. Lee

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⁽⁵⁾

Robert L. Wells

Vice President,

Information Technology ^{(1) (3) (4)}

DIRECTORS

Nancy H. Agee

Chief Operating Officer/

Executive Vice President

Carilion Clinic

Director: ^{(1) (2)}

Abney S. Boxley, III

President and

Chief Executive Officer

Boxley Materials Company

Director: ^{(1) (2)}

Frank T. Ellett

President

Virginia Truck Center, Inc.

Director: ^{(1) (2)}

Maryellen F. Goodlatte

Attorney and Principal

Glenn Feldmann Darby

& Goodlatte

Director: ^{(1) (2)}

J. Allen Layman

Private Investor

Director: ^{(1) (2)}

George W. Logan

Chairman of the Board

Valley Financial Corporation

Principal

Pine Street Partners

Faculty

University of Virginia

Darden Graduate School

of Business

Director: ⁽¹⁾

S. Frank Smith

Vice President Eastern Sales -

Market Analysis & Research

Alpha Coal Sales Company, LLC

Director: ^{(1) (2)}

Raymond D. Smoot, Jr.

Chief Operating Officer and

Secretary-Treasurer

Virginia Tech Foundation, Inc.

Director: ⁽¹⁾

John B. Williamson, III

Chairman of the Board, President

and Chief Executive Officer

Director: ^{(1) (2) (3) (4) (5)}

SUBSIDIARY BOARDS OF DIRECTORS:

John S. D Orazio

Vice President and

Chief Operating Officer

Roanoke Gas Company

Director: ^{(1) (2) (3)}

Howard T. Lyon

Vice President, Treasurer and

Controller

RGC Resources, Inc.

Director: ^{(3) (4) (5)}

Dale P. Lee

Vice President and Secretary

RGC Resources, Inc.

Director: ^{(3) (4) (5)}

C. James Shockley, Jr.

Vice President,

Operations

Bluefield Gas Company

Director: ⁽⁵⁾

Robert L. Wells

Vice President,

Information Technology

RGC Resources, Inc.

Director: ⁽³⁾ ⁽⁴⁾

(1)

RGC Resources, Inc.

(2)

Roanoke Gas Company

(3)

Diversified Energy Company

(4)

RGC Ventures of Virginia, Inc.

(5)

Bluefield Gas Company

RGC Resources, Inc. {28} 2007 Annual Report

LOGO

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

Brown Edwards & Company, L.L.P.

319 McClanahan Street, S.W.

Roanoke, VA 24014

COMMON STOCK TRANSFER AGENT, REGISTRAR, DIVIDEND DISBURSING

American Stock Transfer & Trust Company

59 Maiden Lane

New York, NY 10038

COMMON STOCK

RGC Resources’ common stock is listed on the Nasdaq National

Market under the trading symbol RGCO.

DIRECT DEPOSIT OF DIVIDENDS AND

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 in-

formation about these shareholder services, please contact the

Transfer Agent, Wachovia Bank, N.A. of North Carolina.

10-K REPORT

A copy of RGC Resources, Inc. latest annual report to the Securities

& Exchange Commission on Form 10-K will be provided without

charge upon written request to:

Dale P. Lee

VICE PRESIDENT AND SECRETARY

RGC Resources, Inc.

P.O. Box 13007

Roanoke, VA 24030

(540) 777-3846

Access all RGC Resources Inc.’s Securities and Exchange filings

through the links provided on our website at www.rgcresources.com.

SHAREHOLDER INQUIRIES

Questions concerning shareholder accounts, stock transfer require-

ments, consolidation of accounts, lost stock certificates, safekeep-

ing of stock certificates, replacement of lost dividend checks,

payment of dividends, direct deposit of dividends, initial cash pay-

ments, optional cash payments and name or address changes

should be directed to the Transfer Agent, Wachovia Bank, N.A. All

other shareholder questions should be directed to:

RGC Resources, Inc.

Vice President and Secretary

P.O. Box 13007

Roanoke, VA 24030

(540) 777-3846

FINANCIAL INQUIRIES

All financial analysts and professional investment managers should

direct their questions and requests for financial information to:

RGC Resources, Inc.

Vice President and Secretary

P.O. Box 13007

Roanoke, VA 24030

(540) 777-3846

Access up-to-date information on RGC Resources and its sub-

sidiaries at www.rgcresources.com.

LOGO

519 Kimball Avenue, N.E.

P.O. Box 13007

Roanoke, VA 24030

www.rgcresources.com

Trading on NASDAQ as RGCO

RGC Resources, Inc. and Subsidiaries

Consolidated Financial Statements for the Years Ended September 30, 2007, 2006, and 2005, and Report of Independent Registered Public Accounting Firm

This page intentionally left blank.

RGC RESOURCES, INC. AND SUBSIDIARIES

TABLE OF CONTENTS


		Page
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM		1

CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED SEPTEMBER 30, 2007, 2006, AND 2005:

Consolidated Balance Sheets		2-3

Consolidated Statements of Income and Comprehensive Income		4-5

Consolidated Statements of Stockholders’ Equity		6

Consolidated Statements of Cash Flows		7-8

Notes to Consolidated Financial Statements		9-31

This page intentionally left blank.

LOGO

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

RGC Resources, Inc.

Roanoke, Virginia

We have audited the accompanying consolidated balance sheet of RGC Resources, Inc. and Subsidiaries (“the Company”) as of September 30, 2007 and 2006, and the related consolidated statements of income and comprehensive income, stockholders’ equity, and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit. The financial statements of RGC Resources, Inc. and Subsidiaries for the year ended September 30, 2005, before the adjustment to reflect the Bluefield, Virginia and West Virginia operations and the energy marketing division as discontinued operations as described in Note 2, were audited by other auditors whose report, dated December 15, 2005, expressed an unqualified opinion on those statements.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also 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 audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of RGC Resources, Inc. and Subsidiaries as of September 30, 2007 and 2006, and the consolidated results of its operations and its cash flows for the years then ended in conformity with U.S. generally accepted accounting principles.

On February 16, 2007 the Company entered into agreements to sell its Bluefield, Virginia and West Virginia operations, and on July 10, 2006, the Company sold certain of its assets related to the energy marketing business. We have audited the adjustments to the 2005 financial statements to retroactively reflect the Bluefield, Virginia and West Virginia operations and the energy marketing business as Discontinued Operations as more fully described in Note 2. In our opinion, such adjustments are appropriate and have been properly applied. We were not engaged to audit, review, or apply any procedures to the 2005 financial statements of the Company other than with respect to the adjustments and, accordingly, we do not express an opinion or any other form of assurance on the 2005 financial statements taken as a whole.

As discussed in Notes 1 and 7, the Company changed its method of accounting for its defined benefit pension plan and its post retirement benefit plan to adopt Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106, and 132(R).

/s/ Brown, Edwards & Company, L.L.P.

CERTIFIED PUBLIC ACCOUNTANTS

319 McClanahan Street, S.W.

Roanoke, Virginia

November 14, 2007


		Providing Professional Business Advisory & Consulting Services

319 McClanahan Street, S.W. • P.O. Box 12388 • Roanoke, VA 24025-2388 • 540-345-0936 • Fax: 540-342-6181 • www.BEcpas.com

Member: SEC and Private Companies Practice Sections of American Institute of Certified Public Accountants

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

AS OF SEPTEMBER 30, 2007 AND 2006


	2007			2006
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	1,408,317		$	1,490,141
Accounts receivable, less allowance for doubtful accounts of $46,710 in 2007 and $26,584 in 2006		4,447,928			4,558,458
Materials and supplies		515,722			553,773
Gas in storage		19,156,833			19,932,064
Assets available for sale		12,825,344			13,726,791
Prepaid income taxes		1,649,788			879,957
Deferred income taxes		1,001,162			2,654,548
Other		455,445			392,564

Total current assets		41,460,539			44,188,296

UTILITY PROPERTY:
In service		108,348,844			102,822,594
Accumulated depreciation and amortization		(36,424,831	)		(34,447,514	)

In service—net		71,924,013			68,375,080

Construction work in progress		663,256			1,702,416

Utility plant—net		72,587,269			70,077,496

Other assets		2,284,647			396,780

TOTAL ASSETS	$	116,332,455		$	114,662,572

(Continued)

- 2 -

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

AS OF SEPTEMBER 30, 2007 AND 2006


	2007			2006
LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES:
Current maturities of long-term debt	$	5,000,000		$	—
Borrowings under lines of credit		4,808,000			3,353,000
Dividends payable		667,245			643,067
Accounts payable		6,457,602			8,328,365
Customer credit balances		4,308,415			4,027,668
Customer deposits		1,439,765			1,245,508
Accrued expenses		2,106,222			3,484,476
Liabilities of assets available for sale		7,558,605			8,252,463
Over-recovery of gas costs		567,295			2,112,256
Fair value of marked-to-market transactions		86,025			1,486,699

Total current liabilities		32,999,174			32,933,502

LONG-TERM DEBT, excluding current maturities		23,000,000			28,000,000

DEFERRED CREDITS AND OTHER LIABILITIES:
Asset retirement obligations		2,499,345			2,404,839
Regulatory cost of retirement obligations		6,043,088			5,319,198
Benefit plan liabilities		3,855,292			—
Deferred income taxes		5,442,563			5,351,746
Deferred investment tax credits		127,760			158,419

Total deferred credits and other liabilities		17,968,048			13,234,202

COMMITMENTS AND CONTINGENCIES (Notes 10 and 11)

CAPITALIZATION:
Stockholders’ equity:
Common stock, $5 par value; authorized 10,000,000 shares; issued and outstanding 2,186,143 and 2,138,595 shares in 2007 and 2006, respectively	$	10,930,715		$	10,692,975
Preferred stock, no par; authorized 5,000,000 shares; no shares issued or outstanding in 2007 and 2006		—			—
Capital in excess of par value		15,466,756			14,521,812
Retained earnings		16,443,017			15,282,909
Accumulated other comprehensive loss		(475,255	)		(2,828	)

Total stockholders’ equity		42,365,233			40,494,868

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	116,332,455		$	114,662,572

(Concluded)

See notes to consolidated financial statements.

- 3 -

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

YEARS ENDED SEPTEMBER 30, 2007, 2006, AND 2005


	2007			2006		2005
OPERATING REVENUES:
Gas utilities	$	89,175,661		$	93,746,408	$	87,752,669
Other		725,640			844,464		848,167

Total operating revenues		89,901,301			94,590,872		88,600,836


COST OF SALES:
Gas utilities		64,342,382			70,885,690		66,036,050
Other		337,143			496,910		358,391

Total cost of sales		64,679,525			71,382,600		66,394,441

GROSS MARGIN		25,221,776			23,208,272		22,206,395


OTHER OPERATING EXPENSES:
Operations		10,624,555			10,277,021		9,781,845
Maintenance		1,419,830			1,286,732		1,321,621
General taxes		1,130,522			1,114,166		1,051,041
Depreciation and amortization		4,088,590			3,852,853		3,656,324

Total other operating expenses		17,263,497			16,530,772		15,810,831

OPERATING INCOME		7,958,279			6,677,500		6,395,564

OTHER EXPENSES—Net		24,758			12,630		60,747

INTEREST EXPENSE		1,931,444			2,000,653		1,700,174


INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		6,002,077			4,664,217		4,634,643

INCOME TAX EXPENSE FROM CONTINUING OPERATIONS		2,236,408			1,702,415		1,717,845


INCOME FROM CONTINUING OPERATIONS		3,765,669			2,961,802		2,916,798


DISCONTINUED OPERATIONS:
Income from discontinued operations—net of income taxes of $835,836, $382,558 and $395,482 in 2007, 2006, and 2005, respectively		40,540			549,729		590,108

NET INCOME		3,806,209			3,511,531		3,506,906

OTHER COMPREHENSIVE INCOME (LOSS)— NET OF TAX		(50,542	)		377,643		(334,961	)

COMPREHENSIVE INCOME	$	3,755,667		$	3,889,174	$	3,171,945

(Continued)

- 4 -

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

YEARS ENDED SEPTEMBER 30, 2007, 2006, AND 2005


	2007		2006		2005
BASIC EARNINGS PER COMMON SHARE:
Income from continuing operations	$	1.74	$	1.40	$	1.40
Discontinued operations		0.02		0.26		0.29

Net income	$	1.76	$	1.66	$	1.69


DILUTED EARNINGS PER COMMON SHARE:
Income from continuing operations	$	1.73	$	1.39	$	1.39
Discontinued operations		0.02		0.26		0.29

Net income	$	1.75	$	1.65	$	1.68


WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING:
Basic		2,162,803		2,120,267		2,079,851
Diluted		2,173,258		2,130,720		2,093,115

(Concluded)

See notes to consolidated financial statements.

- 5 -

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

YEARS ENDED SEPTEMBER 30, 2007, 2006 AND 2005


	Common Stock		Capital in Excess of Par Value		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Stockholders’ Equity
BALANCE—September 30, 2004	$	10,327,040	$	13,064,566	$	13,275,426		$	(45,510	)	$	36,621,522

Net income		—		—		3,506,906			—			3,506,906

Gain on hedging activities— net of tax		—		—		—			53,951			53,951

Minimum pension liability— net of tax		—		—		—			(388,912	)		(388,912	)

Cash dividends declared ($1.18 per share)		—		—		(2,459,527	)		—			(2,459,527	)

Issuance of common stock (33,527 shares)		167,635		655,782		—			—			823,417

BALANCE—September 30, 2005		10,494,675		13,720,348		14,322,805			(380,471	)		38,157,357

Net income		—		—		3,511,531			—			3,511,531

Loss on hedging activities— net of tax		—		—		—			(11,269	)		(11,269	)

Minimum pension liability—net of tax		—		—		—			388,912			388,912

Cash dividends declared ($1.20 per share)		—		—		(2,551,427	)		—			(2,551,427	)

Issuance of common stock (39,660 shares)		198,300		801,464		—			—			999,764

BALANCE—September 30, 2006		10,692,975		14,521,812		15,282,909			(2,828	)		40,494,868

Net income		—		—		3,806,209			—			3,806,209

Loss on hedging activities— net of tax		—		—		—			(50,542	)		(50,542	)

Adoption of SFAS No. 158		—		—		—			(421,885	)		(421,885	)

Cash dividends declared ($1.22 per share)		—		—		(2,646,101	)		—			(2,646,101	)

Issuance of common stock (47,548 shares)		237,740		944,944		—			—			1,182,684

BALANCE—September 30, 2007	$	10,930,715	$	15,466,756	$	16,443,017		$	(475,255	)	$	42,365,233

See notes to consolidated financial statements.

- 6 -

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

YEARS ENDED SEPTEMBER 30, 2007, 2006 AND 2005


	2007			2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income from continuing operations	$	3,765,669		$	2,961,802		$	2,916,798
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		4,301,102			4,064,704			3,882,593
Cost of removal of utility plant—net		(252,931	)		(243,015	)		(213,924	)
Loss on disposal of property		—			—			33,590
Gain on sale of short-term investments		—			—			(8,540	)
Change in over/under recovery of gas costs		(3,027,101	)		5,322,010			(3,896,107	)
Deferred taxes and investment tax credits		2,003,043			55,201			(154,638	)
Other noncash items—net		18,201			(144,761	)		96,406
Changes in assets and liabilities which provided (used) cash:
Accounts receivable and customer deposits—net		304,787			2,399,290			(948,205	)
Inventories, gas in storage and prepaid gas		813,282			225,010			(4,984,889	)
Other current assets		(832,712	)		64,213			1,081,587
Accounts payable, customer credit balances and accrued expenses		(1,463,285	)		(5,454,627	)		7,052,308

Total adjustments		1,864,386			6,288,025			1,940,181

Net cash provided by continuing operating activities		5,630,055			9,249,827			4,856,979
Net cash provided by discontinued operations		991,317			1,046,633			656,916

Net cash provided by operating activities		6,621,372			10,296,460			5,513,895

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant and nonutility property		(6,004,190	)		(7,175,409	)		(6,685,229	)
Proceeds from disposal of utility and nonutility property		12,340			3,416			83,371
Proceeds from sale of short-term investments		—			—			5,000,000

Net cash used in continuing investing activities		(5,991,850	)		(7,171,993	)		(1,601,858	)
Net cash used in discontinued investing activities		(204,107	)		(406,716	)		(3,178	)

Net cash used in investing activities		(6,195,957	)		(7,578,709	)		(1,605,036	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		—			15,000,000			—
Retirement of long-term debt and capital leases		—			(11,000,000	)		(19,987	)
Net repayments under line-of-credit agreements		1,455,000			(4,672,000	)		(1,049,000	)
Proceeds from issuance of common stock		1,182,684			999,764			823,417
Cash dividends paid		(2,621,923	)		(2,527,892	)		(11,743,988	)

Net cash provided by (used in) continuing financing activities		15,761			(2,200,128	)		(11,989,558	)
Net cash used in discontinued financing activities		(523,000	)		(377,000	)		(31,000	)

Net cash used in financing activities		(507,239	)		(2,577,128	)		(12,020,558	)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(81,824	)		140,623			(8,111,699	)
CASH AND CASH EQUIVALENTS—Beginning of year		1,490,141			1,349,518			9,461,217

CASH AND CASH EQUIVALENTS—End of year	$	1,408,317		$	1,490,141		$	1,349,518

(Continued)

- 7 -

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

YEARS ENDED SEPTEMBER 30, 2007, 2006 AND 2005


	2007			2006			2005
SUPPLEMENTAL DISCLOSURE OF CASH FLOWS INFORMATION:

Cash paid during the year for:
Interest	$	2,335,713		$	2,377,906		$	2,131,430

Income taxes—net of refunds	$	1,952,794		$	1,888,858		$	912,844


Non-cash transactions:

In 2007, 2006 and 2005, the Company entered into derivative arrangements for the purpose of hedging the cost of gas and in 2005 entered into an interest rate swap to hedge interest expense. In accordance with hedge accounting requirements, the underlying derivatives were marked to market with the corresponding non-cash impacts to the consolidated balance sheets:

Fair value of marked-to-market transactions	$	(1,400,674	)	$	1,500,305		$	(86,962)
Over recovery of gas costs		1,482,140			(1,482,140	)		—
Deferred tax liability		32,655			6,896			(33,011)

In September 2007, the Company adopted FASB No. 158 (as discussed in Note 7) which resulted in the establishment of a benefit liability attributable to the Company’s underfunded positions under its pension and post-retirement medical plans as well as a regulatory asset related to the portion pertaining to the regulated operations. Prior to the adoption of SFAS No. 158, the Company recorded a minimum pension liability in 2005 which reversed in 2006.

Regulatory asset	$	1,906,068		$	—		$	—
Benefit plan liability		3,855,292			—			—
Deferred tax liability		(258,575	)		238,366			(238,366)
Accrued expenses		(1,268,764	)		(627,278	)		627,278

(Concluded)

See notes to consolidated financial statements.

- 8 -

RGC RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2007, 2006, AND 2005

1.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General—RGC Resources, Inc. is an energy services company engaged in the sale and distribution of natural gas. The consolidated financial statements include the accounts of RGC Resources, Inc. and its wholly owned subsidiaries (“Resources” or the “Company”); Roanoke Gas Company (“Roanoke Gas”); Diversified Energy Company; and RGC Ventures, Inc. of Virginia, operating as Application Resources. Roanoke Gas is a natural gas utility, which distributes and sells natural gas to residential, commercial and industrial customers within its service areas in Roanoke, VA and the surrounding areas. Application Resources provides information system services to software providers in the utility industry.

Roanoke Gas is regulated by the State Corporation Commission (“SCC” or “Virginia Commission”).

The Company’s business is seasonal in nature and weather dependent as a majority of natural gas sales are for space heating during the winter season.

On February 16, 2007, Resources entered into a Purchase and Sale Agreement with ANGD, LLC for the sale of all of the capital stock of Bluefield Gas Company (“Bluefield Gas”), and Roanoke Gas entered into a Purchase and Sale Agreement with Appalachian Natural Gas Distribution Company for the sale of Roanoke Gas’ natural gas distribution assets located in the Town of Bluefield and the County of Tazewell, Virginia (“Bluefield division of Roanoke Gas Company”.) Both transactions closed on November 2, 2007 with an effective date of October 31, 2007. In August 2006, Resources sold the assets of Highland Energy, its energy marketing operation that brokered natural gas to industrial transportation customers of Roanoke Gas and Bluefield Gas. These operations have been reflected as discontinued operations in the consolidated financial statements of Resources. With the sale of Highland Energy, Resources has only one reportable segment as defined under SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information. Please see footnote 2 below for further discussions on the sale of Bluefield Gas, the assets of the Bluefield division of Roanoke Gas Company and certain assets of Highland Energy.

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).

- 9 -

Regulatory assets and liabilities included in the Company’s consolidated balance sheets as of September 30, 2007 and 2006 are as follows:


	September 30
	2007		2006
Regulatory assets:
Premium on early retirement of debt	$	248,077	$	278,454
Benefit plan assets		1,906,068		—
Other		11,945		11,945

Total regulatory assets	$	2,166,090	$	290,399


Regulatory liabilities:
Over-recovery of gas costs	$	567,295	$	2,112,256
Regulatory cost of retirement obligation		6,043,088		5,319,198
Asset retirement obligation		2,499,345		2,404,839
Other		330		2,447

Total regulatory liabilities	$	9,110,058	$	9,838,740

Utility Plant and Depreciation—Utility plant is stated at original cost. The cost of additions to utility plant includes direct charges and overhead. The cost of depreciable property retired is charged to accumulated depreciation. The cost of asset removals, less salvage, is charged to “regulatory cost of retirement obligations” or “asset retirement obligations” as explained in footnote 13.

Maintenance, repairs, and minor renewals and betterments of property are charged to operations and maintenance.

Provisions for depreciation are computed principally at composite straight-line rates with annual composite rates ranging up to 17% for utility property. The annual composite rates for utility property are determined by periodic depreciation studies that are approved by the SCC. The Virginia Commission requires Roanoke Gas to conduct a depreciation study every five years and propose new depreciation rates for approval. The results of Roanoke Gas’ last depreciation study were placed into effect January 1, 2004.

The composite rates are comprised of two components, one based on average service life and one based on cost of retirement. Therefore, the Company accrues the estimated cost of retirement of long-lived assets through depreciation expense. Retirement costs are not a legal obligation as defined by SFAS No. 143 but rather the result of cost-based regulation and are accounted for under the provisions of SFAS No. 71. Therefore, such amounts are classified as a regulatory liability. See footnote 13 regarding legal obligations related to asset retirements.

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

Cash, Cash Equivalents and Short-Term Investments—For purposes of the consolidated statements of cash flows, the Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents.

- 10 -

Reserve for Bad Debts –The Company provides an estimate for losses on accounts receivable utilizing historical information, current account balances, account aging and current economic conditions.

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

Unbilled Revenues—The Company bills its natural gas customers on a monthly cycle basis; however, the billing cycle period for most customers does not coincide with the accounting periods used for financial reporting and, therefore, accrues estimates for natural gas delivered to customers not yet billed during the accounting period. The Company recognizes revenue when gas is delivered. The amounts of unbilled revenue receivable included in accounts receivable on the consolidated balance sheets at September 30, 2007 and 2006 were $1,287,362 and $1,462,878, 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 income tax return.

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

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

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

Reclassifications—Certain prior period amounts have been reclassified to conform to current year presentation. Specifically, the Company reclassified certain financial statement items including footnote information for 2006 and 2005 to reflect the effect of discontinued operations discussed in footnote 2. The Company reclassified “non-utility property” and related “accumulated depreciation” into the corresponding utility property accounts. The Company also reclassified “refunds from suppliers – due customers” to “accrued expenses”.

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


	Year Ended September 30
	2007	2006	2005
Weighted average common shares	2,162,803	2,120,267	2,079,851

Effect of dilutive securities:
Options to purchase common stock	10,455	10,453	13,264


Diluted average common shares	2,173,258	2,130,720	2,093,115

- 11 -

Business and Credit Concentrations—The primary business of the Company is the distribution of natural gas to residential, commercial and industrial customers in its service territories. The level of natural gas requirements by certain industrial customers may result in a level of concentration above 5% of total sales or total accounts receivable for the periods reported.

No regulated sales to individual customers accounted for more than 5% of total revenue in any period.

Roanoke Gas is served by multiple natural gas transmission pipelines; however, by the stage of physical interconnection with the company’s distribution facilities the transmission of natural gas has consolidated into two primary pipelines. Depending upon weather conditions and the level of customer demand, failure of one or both of these transmission pipelines could have a major adverse impact on the Company.

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

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

The Company enters into collars, swaps and caps for the purpose of hedging the price of natural gas in order to provide price stability during the winter months. The fair value of these instruments is recorded in the balance sheet with the offsetting entry to either under-recovery of gas costs or over-recovery of gas costs. Net income and other comprehensive income are not affected by the change in market value as any cost incurred or benefit received from these instruments is recoverable or refunded through the PGA. The Virginia Commission allows 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. At September 30, 2007, the Company has collar agreements outstanding for the winter period to hedge 680,000 decatherms of natural gas, and the futures price for delivery of natural gas during the periods hedged fell between the upper and lower limits of the collar contracts.

The Company also entered into an interest rate swap related to the $15,000,000 note issued in November 2005. The swap essentially converted the floating rate note based on LIBOR into fixed rate debt with a 5.74% interest rate. The swap qualifies as a cash flow hedge with changes in fair value reported in other comprehensive income.

No derivative instruments were deemed to be ineffective as defined under SFAS No. 133 for any period.

- 12 -

Other Comprehensive Income—A summary of other comprehensive income and financial instrument activity including the effect of adopting SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, is provided below:


Year Ended September 30, 2007	Interest Rate Swap			Natural Gas Derivative			SFAS No. 158			Total
Unrealized losses	$	(37,233	)	$	—		$	—		$	(37,233	)
Income tax benefit		14,134			—			—			14,134

Net unrealized losses		(23,099	)		—			—			(23,099	)

Transfer of realized gains to income		(44,233	)		—			—			(44,233	)
Income tax expense		16,790			—			—			16,790

Net transfer of realized gains to income		(27,443	)		—			—			(27,443	)

Net other comprehensive loss	$	(50,542	)	$	—		$	—		$	(50,542	)

Fair value of marked to market transactions	$	(86,025	)	$	—		$	—		$	(86,025	)

Accumulated comprehensive loss	$	(53,370	)	$	—		$	(421,885	)	$	(475,255	)


Year Ended September 30, 2006	Interest Rate Swap			Natural Gas Derivative			Minimum Pension Liability			Total
Unrealized gains (losses)	$	(29,000	)	$	—		$	627,278		$	598,278
Income tax (expense) benefit		11,008			—			(238,366	)		(227,358	)

Net unrealized gains (losses)		(17,992	)		—			388,912			370,920

Transfer of realized losses to income		10,835			—			—			10,835
Income tax benefit		(4,112	)		—			—			(4,112	)

Net transfer of realized losses to income		6,723			—			—			6,723

Net other comprehensive income (loss)	$	(11,269	)	$	—		$	388,912		$	377,643

Fair value of marked to market transactions	$	(4,559	)	$	(1,482,140	)	$	—		$	(1,486,699	)

Accumulated comprehensive loss	$	(2,828	)	$	—		$	—		$	(2,828	)


Year Ended September 30, 2005	Interest Rate Swap			Natural Gas Derivative			Minimum Pension Liability			Total
Unrealized gains (losses)	$	54,634		$	—		$	(627,278	)	$	(572,644	)
Income tax (expense) benefit		(20,739	)		—			238,366			217,627

Net unrealized gains (losses)		33,895			—			(388,912	)		(355,017	)

Transfer of realized losses to income		32,328			—			—			32,328
Income tax benefit		(12,272	)		—			—			(12,272	)

Net transfer of realized losses to income		20,056			—			—			20,056

Net other comprehensive income (loss)	$	53,951		$	—		$	(388,912	)	$	(334,961	)

Fair value of marked to market transactions	$	13,606		$	—		$	—		$	13,606

Accumulated comprehensive loss	$	8,441		$	—		$	(388,912	)	$	(380,471	)

- 13 -

Stock-Based Compensation—On October 1, 2005, the Company adopted SFAS No. 123R, Share-Based Payment, a revision of SFAS No. 123, Accounting for Stock-Based Compensation. This statement eliminates the alternative to use the intrinsic value method of accounting as prescribed under Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees. Under APB Opinion No. 25, the Company did not recognize stock-based employee compensation expense related to its Key Employees Stock Option Plan (“Plan”) 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. SFAS No. 123R requires entities to recognize the cost of employee services received in exchange for awards of equity instruments using a fair-value-based method on the grant-date. The Company has adopted the provisions of this statement using the modified prospective application. Under the modified prospective application, only new grants and grants that have been modified, cancelled or have not yet vested as of the effective date of the statement require recognition of compensation cost. All awards granted and vested prior to the effective date remain under the provisions of APB Opinion No. 25. No options were granted in fiscal 2007, 2006 and 2005 and all outstanding options were fully vested at the date of adoption.

New Accounting Standards— In June 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes – an Interpretation of FASB Statement No. 109. This statement clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes. This Interpretation prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The recognition threshold is based upon whether it is more-likely-than-not that a tax position taken by an enterprise will be sustained upon examination. The measurement attribute of a more-likely-than-not tax position is measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement. The effective date of this statement is for the Company’s first quarter of fiscal year ending September 30, 2008. The Company has not completed its evaluation of this statement but does not anticipate the adoption to have a material impact on the Company’s financial position or results of operations or cash flows.

- 14 -

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. This statement defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value methods. This statement does not require any new fair value measurements. Instead, it provides for increased consistency and comparability in fair value measurements and for expanded disclosure surrounding the fair value measurements. This statement is effective for fiscal years beginning after November 15, 2007. The Company does not anticipate the adoption of this statement to have a material impact on the Company’s financial position, results of operations or cash flows.

In September 2006, the FASB issued SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – an amendment of FASB Statements No. 87, 88, 106, and 132R (“SFAS No. 158”). This statement requires employers who sponsor one or more single-employer defined benefit plans to recognize the overfunded or underfunded position of such plan(s) as an asset or liability in its balance sheet and to recognize changes in that funded status in the year in which the changes occur through comprehensive income. This statement also requires the measurement of the defined benefit plan assets and obligations as of the date of the employer’s balance sheet date and additional disclosures in the financial statement footnotes. The effective date of this statement is for fiscal years ending after December 15, 2006. The requirement to measure plan assets and benefit obligations as of the fiscal year end balance sheet date is effective for fiscal years ending after December 15, 2008. The adoption of SFAS No. 158 resulted in the Company recording an additional benefit liability of $2,586,528 associated with the net underfunded positions of its defined benefit pension plan and post-retirement benefit plan. The Company also recorded a regulatory asset of $1,906,068 associated with the regulated operations of Roanoke Gas in accordance with the provisions of SFAS No. 71 whereby the Company believes that it will continue to be able to recover the change in funded status of the plans through future rates. The Company also recognized other comprehensive loss of $421,885, net of tax, for the associated liabilities not associated with the regulated operations. Footnote 7 includes more information regarding the effect of SFAS No. 158.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities. This statement permits, but does not require, entities to choose to measure selected financial assets and liabilities at fair value. Although SFAS No. 159 does not eliminate the fair value disclosure requirements included in other accounting standards, it does provide for additional presentation and disclosures designed to facilitate comparisons between companies that choose different measurement attributes for similar assets and liabilities. The effective date of this statement is for fiscal years beginning after November 15, 2007. The Company has not completed its evaluation of this statement, nor determined the potential effect on its financial position, results of operations or cash flows.

2.	DISCONTINUED OPERATIONS

On February 16, 2007, Resources entered into a Purchase and Sale Agreement with ANGD, LLC (“ANGD”), for the sale of all of the capital stock of Bluefield Gas Company, a wholly owned subsidiary of Resources, to ANGD. The sales price is equal to the book value of Bluefield Gas’ net assets on the date of closing, subject to mutually agreed upon or arbitrated purchase price adjustments determined subsequent to the closing date but no later than 230 days after Closing. In connection with the sale, (i) certain real estate will be distributed to the Company prior to Closing, (ii) inter-company receivables or payables existing between Bluefield Gas and the Company (including its other affiliates) will be settled as of Closing, and (iii) the Company will pay off Bluefield Gas outstanding debt at Closing out of the sales proceeds.

- 15 -

Also on February 16, 2007, Roanoke Gas entered into an Asset Purchase and Sale Agreement with Appalachian Natural Gas Distribution Company (“Appalachian”) for the sale of Roanoke Gas’ natural gas distribution assets located in the Town of Bluefield and the County of Tazewell, Virginia, (“Bluefield division of Roanoke Gas Company”) to Appalachian, which is a wholly owned subsidiary of ANGD. The sales price is equal to the book value of net plant plus 1% and the book value of accounts receivable, natural gas inventory, and certain other listed current assets, subject to mutually agreed upon or arbitrated purchase price adjustments determined subsequent to the closing date but no later than 230 days after Closing. $1,300,000 of such sales price is payable in the form of a promissory note from ANGD with a 5-year term and a 15-year amortization schedule with annual principal payments and quarterly interest payments at a 10% interest rate.

Although the Purchase and Sale Agreement with ANGD, LLC for the sale of the capital stock of Bluefield Gas provides for a sales price substantially equal to the book value of Bluefield’s net assets on the date of closing, the underlying tax basis that Resources has in the stock is significantly less than the book basis. This lower tax basis has resulted in the recording of an estimated income tax expense attributable to the anticipated taxable gain for the excess of the book basis of the assets over the tax basis. The current estimate of tax liability expected to be realized on this transaction is reflected as part of income tax expense in discontinued operations.

Bluefield Gas and the Bluefield division of Roanoke Gas Company (“Bluefield Operations”) represent approximately 4,600 of Resources’ 60,000 customers and approximately $12,800,000 of the consolidated assets and $7,600,000 of the consolidated liabilities of the Company as of September 30, 2007 as reflected below. The sale of the Bluefield Operations closed effective as of October 31, 2007.

The Board of Directors approved the Purchase and Sale Agreements of Bluefield Gas and the Bluefield division of Roanoke Gas Company for several reasons. The management time and effort required to oversee Bluefield operations were significantly disproportionate to the size of these operations. The regulatory environment in West Virginia has historically hindered the ability to recover increasing expenses on a timely basis resulting in net losses from those operations in each of the last four fiscal years. The economic conditions in southern West Virginia have led to a loss of population and gas customers in the West Virginia service area. Management believes that the net proceeds realized from these transactions can be reinvested in the Roanoke Gas operations and ultimately provide a better return for the Company than could be realized in the Bluefield operations.

The Company received regulatory approvals from the respective regulatory commissions in Virginia and West Virginia prior to the end of the Company’s fiscal year. The operations of both Bluefield Gas and Bluefield Division of Roanoke Gas Company were classified as discontinued operations in accordance with the provisions of SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, as the pending sale met the probable definition requirement. Both transactions closed on November 2, 2007 with an effective date of October 31, 2007.

In July 2006, the Company entered into an asset purchase and sale agreement for the sale of the assets relating to its Highland Energy gas marketing business. The assets sold included the gas supply contracts between Highland Energy and its customers and related business records. The operations associated with the energy marketing business were reclassified as Discontinued Operations in accordance with the provisions of SFAS No. 144. Under the agreement, a portion of the purchase price was deferred as realization of those revenues was subject to certain provisions. The Company met substantially all of the provisions of the agreement and recorded $160,162 gain on sale of assets in final settlement of the sales contract as part of discontinued operations in 2007.

- 16 -

In June 2005, the Company sold 10 parcels of real estate consisting of bulk propane storage facilities and office space owned by Diversified Energy Company. These properties were originally part of the propane operations that were sold to Inergy Propane, LLC (“Inergy”) in 2004, but were retained and leased to Inergy with an option to purchase. Inergy exercised its option to purchase all properties in 2005 and the corresponding rental activities and gain on sale of the real estate were recorded in discontinued operations for that period.

The activities associated with the Bluefield Operations, Highland Energy and the real estate operations are included in discontinued operations and are summarized as follows:


	Years Ended September 30
	2007			2006			2005
Bluefield Operations
Total Revenues	$	11,229,432		$	13,206,878		$	11,475,831

Pretax Operating Loss		(134,650	)		(181,671	)		(279,258	)
Continuing Costs		773,304			732,007			684,987
Income Tax Expense		(745,598	)		(237,544	)		(174,887	)

Discontinued Operations	$	(106,944	)	$	312,792		$	230,842


Highland Energy
Revenues	$	—		$	21,962,564		$	21,571,120

Gain on Sale of Assets		160,162			233,216			—
Pretax Operating Income		77,560			98,743			331,420
Continuing Costs		—			49,992			55,928
Income Tax Expense		(90,238	)		(145,014	)		(147,055	)

Discontinued Operations	$	147,484		$	236,937		$	240,293


Real Estate
Revenues	$	—		$	—		$	39,366

Gain on Sale of Assets		—			—			153,147
Pretax Operating Income		—			—			39,366
Continuing Costs		—			—			—
Income Tax Expense		—			—			(73,540	)

Discontinued Operations	$	—		$	—		$	118,973

Total
Revenues	$	11,229,432		$	35,169,442		$	33,086,317

Gain on Sale of Assets		160,162			233,216			153,147
Pretax Operating Income (Loss)		(57,090	)		(82,928	)		91,528
Continuing Costs		773,304			781,999			740,915
Income Tax Expense		(835,836	)		(382,558	)		(395,482	)

Discontinued Operations	$	40,540		$	549,729		$	590,108

- 17 -

The carrying amounts of the major classes of assets and liabilities subject to the purchase agreements at September 30, 2007 and 2006 are as follows:


	September 30
	2007		2006
Assets:

Accounts receivable, net	$	429,582	$	658,551
Gas in storage		3,230,624		3,399,639
Other current assets		90,913		619,862
Net utility plant		9,018,903		8,962,113
Other assets		55,322		86,626

Assets available for sale	$	12,825,344	$	13,726,791


Liabilities:

Accounts payable and customer credit balances	$	1,499,604	$	1,499,143
Accrued expenses		99,821		217,054
Other current liabilities		4,800,048		3,442,251
Non-current liabilities		1,159,132		3,094,015

Liabilities of assets available for sale	$	7,558,605	$	8,252,463

The purchase agreements related to the sale of the Bluefield Operations provide, at Closing for a services agreement to be executed whereby Resources and Roanoke will provide certain customer billing, gas control, regulatory and other administrative services for Bluefield and Appalachian on mutually agreeable terms.

3.	ALLOWANCE FOR DOUBTFUL ACCOUNTS

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


	Years Ended September 30
	2007			2006			2005
Balances, beginning of year	$	26,584		$	73,725		$	25,866
Provision for doubtful accounts		120,671			354,947			282,313
Recoveries of accounts written off		294,887			213,503			264,825
Accounts written off		(395,432	)		(615,591	)		(499,279	)

Balances, end of year	$	46,710		$	26,584		$	73,725

The amounts above are exclusive of the Bluefield operations.

4.	BORROWINGS UNDER LINES-OF-CREDIT

The Company has available unsecured lines-of-credit with a bank which will expire March 31, 2008. The Company anticipates being able to extend or replace the lines-of-credit. The Company’s

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available unsecured lines-of-credit vary during the year to accommodate its seasonal borrowing demands. Generally, the Company’s borrowing needs are at their lowest in spring, increase during the summer and fall due to gas storage purchases and construction expenditures and reach their maximum levels in winter. Available limits under these agreements for the remaining term are as follows:


Effective	Available Line of Credit
September 30, 2007	$	17,000,000
November 16, 2007		21,000,000
February 16, 2008		16,000,000

A summary of the lines-of-credit follows:


	2007			2006			2005
Lines-of-credit at year-end	$	17,000,000		$	20,000,000		$	20,000,000
Outstanding balance at year-end		4,808,000			3,353,000			4,025,000
Highest month-end balances outstanding		8,421,000			17,827,000			14,016,000
Average month-end balances		2,715,000			6,565,000			6,334,000
Average rates of interest during year		5.83	%		4.86	%		2.94	%
Average rates of interest on balances outstanding at year-end		5.62	%		5.82	%		4.36	%

5.	LONG-TERM DEBT

Long-term debt consists of the following:


	September 30
	2007			2006
First Mortgage notes payable, at 7.804%, due July 1, 2008	$	5,000,000		$	5,000,000
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
Unsecured note payable, with variable interest rate based on 30-day LIBOR (5.13% at September 30, 2007) plus 69 basis point spread, with provision for retirement on December 1, 2010		15,000,000			15,000,000

Total long-term debt		28,000,000			28,000,000
Less current maturities		(5,000,000	)		—

Total long-term debt—excluding current maturities	$	23,000,000		$	28,000,000

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

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Company and dividends previously paid. The Company was in compliance with these provisions at September 30, 2007 and 2006. At September 30, 2007, approximately $12,283,000 of retained earnings were available for dividends.

The First Mortgage notes are secured by the Company’s land and buildings.

The aggregate annual maturities of long-term debt, subsequent to September 30, 2007, are as follows:


Years Ended September 30	Maturities
2008	$	5,000,000
2009		—
2010		—
2011		15,000,000
2012		—
Thereafter		8,000,000

Total	$	28,000,000

6.	INCOME TAXES

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


	Years Ended September 30
	2007			2006			2005
Current income taxes:
Federal	$	806,956		$	1,448,286		$	1,491,928
State		113,461			232,491			301,527

Total current income taxes		920,417			1,680,777			1,793,455

Deferred income taxes:
Federal		1,100,072			8,990			(16,384	)
State		246,407			44,929			(26,058	)

Total deferred income taxes		1,346,479			53,919			(42,442	)

Amortization of investment tax credits		(30,488	)		(32,281	)		(33,168	)

Total income tax expense	$	2,236,408		$	1,702,415		$	1,717,845

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Income tax expense for the years ended September 30, 2007, 2006 and 2005 differed from amounts computed by applying the U.S. Federal income tax rate of 34 percent to earnings before income taxes as a result of the following:


	Years Ended September 30
	2007			2006			2005
Income before income taxes	$	6,002,077		$	4,664,217		$	4,634,643

Income tax expense computed at the federal statutory rate	$	2,040,706		$	1,585,834		$	1,575,779
Increase (reduction) in income tax expense resulting from:
State income taxes, net of federal income tax benefit		237,513			183,097			181,810
Amortization of investment tax credits		(30,488	)		(32,281	)		(33,168	)
Other—net		(11,323	)		(34,235	)		(6,576	)

Total income tax expense	$	2,236,408		$	1,702,415		$	1,717,845

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


	September 30
	2007		2006
Deferred tax assets:
Allowance for uncollectibles	$	18,838	$	73,197
Accrued pension and post-retirement medical benefits		1,454,905		1,282,947
Accrued vacation		187,173		184,857
Over recovery of gas costs		215,346		1,364,433
Costs of gas held in storage		853,169		825,850
Deferred compensation		338,891		258,231
Other		202,170		126,199

Total deferred tax assets		3,270,492		4,115,714


Deferred tax liabilities:
Utility plant		7,054,425		6,759,555
Accrued gas costs		51,630		53,357
Sale of Bluefield Gas stock		605,838		—

Total deferred tax liabilities		7,711,893		6,812,912

Net deferred tax liability	$	4,441,401	$	2,697,198

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7.	EMPLOYEE BENEFIT PLANS

The Company sponsors both a defined benefit plan and a postretirement benefit plan (“Plans”). The defined benefit plan covers substantially all employees and benefits fully vest after five years of credited service. Benefits paid to retirees are based on age at retirement, years of service and average compensation. The postretirement benefit plan provides certain healthcare, supplemental retirement and life insurance benefits to retired employees who meet specific age and service requirements.

On September 30, 2007, the Company adopted SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132R (SFAS No. 158). This Standard retains the previous periodic expense calculation on an actuarial basis under the provisions of SFAS No. 87, Employers’ Accounting for Pensions and SFAS No. 106, Employers Accounting for Postretirement Benefits Other Than Pensions. In addition, this statement also requires an employer to recognize the overfunded or underfunded status of defined benefit pensions and other postretirement plans as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income. For pension plans, the benefit obligation is the projected benefit obligation, and for other postretirement plans, the benefit obligation is the accumulated benefit obligation. The Company established a regulatory asset for the portion of the obligation expected to be recovered in rates in future periods in accordance with SFAS No. 71. The portion of the obligation attributable to the unregulated operations of the holding company parent is recognized in comprehensive income. SFAS No. 158 also requires an employer to measure the funded status of each plan as of the Company’s fiscal year end for fiscal years ending after December 31, 2008. The Company currently uses a June 30 measurement date for its benefit plans.

The following table summarizes the effect of the adoptions of SFAS No. 158 on the Company’s financial statements as of September 30, 2007:


	Before Application of SFAS No. 158		Effect of SFAS No. 158			After Application of SFAS No. 158
Regulatory assets	$	—	$	1,906,068		$	1,906,068
Benefit liabilities		1,268,764		2,586,528			3,855,292
Accumulated other comprehensive loss, net of tax		—		(421,885	)		(421,885	)

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The following tables set forth the benefit obligation, fair value of plan assets, and the funded status of the Plans; amounts recognized in the Company’s financial statements and the assumptions used:


	Pension Benefits						Postretirement Benefits
	2007			2006			2007			2006
Accumulated benefit obligation	$	9,364,621		$	9,106,162		$	8,427,326		$	8,266,411

Change in projected benefit obligation:
Benefit obligation at beginning of year	$	12,102,103		$	13,488,753		$	8,266,411		$	9,612,853
Service cost		404,909			477,279			147,693			164,539
Interest cost		740,918			695,593			501,838			481,368
Participant contributions		—			—			44,042			49,675
Plan amendments		—			—			—			(343,313	)
Actuarial gain		(307,353	)		(2,102,764	)		(113,471	)		(1,193,081	)
Benefit payments		(402,277	)		(456,758	)		(419,187	)		(505,630	)

Benefit obligation at end of year	$	12,538,300		$	12,102,103		$	8,427,326		$	8,266,411

Change in plan assets:
Fair value of plan assets at beginning of year	$	9,248,810		$	8,424,279		$	4,212,556		$	3,586,307
Actual return on plan assets		1,312,622			506,289			624,768			245,374
Employer contributions		825,000			775,000			770,000			896,830
Participant contributions		—			—			44,042			49,675
Tax payments		—			—			(30,000	)		(60,000	)
Benefit payments		(402,277	)		(456,758	)		(419,187	)		(505,630	)

Fair value of plan assets at end of year	$	10,984,155		$	9,248,810		$	5,202,179		$	4,212,556

Reconciliation of funded status:
Funded status	$	(1,554,145	)	$	(2,853,293	)	$	(3,225,147	)	$	(4,053,855	)
Unrecognized actuarial gain		N/A			1,986,054			N/A			947,260
Unrecognized transition obligation		N/A			—			N/A			1,322,246
Contributions made between the measurement date and fiscal year-end		200,000			225,000			724,000			770,000

Net amount recognized	$	(1,354,145	)	$	(642,239	)	$	(2,501,147	)	$	(1,014,349	)

Amounts recognized in the balance sheets consist of:
Noncurrent liabilities	$	(1,354,145	)				$	(2,501,147	)

Amounts recognized in accumulated other comprehensive loss:
Transition obligation, net of tax	$	—					$	175,671
Net actuarial loss, net of tax		160,387						85,827

Total amounts included in other comprehensive loss, net of tax	$	160,387					$	261,498

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The Company established regulatory assets of $726,454 and $1,179,614 as of September 30, 2007 for the portion of the pension and postretirement obligations to be recovered through rates in future periods in accordance with SFAS No. 71.

The Company is amortizing the unrecognized transition obligation over a remaining life of 6 years and projects approximately $29,000 of other comprehensive loss to be recognized as a component of net periodic benefit cost for the year ended September 30, 2008.

The following table details the actuarial assumptions used in determining the projected benefit obligations and net benefit cost of the pension and the accumulated benefit obligations and net benefit cost of the postretirement plan for 2007, 2006 and 2005:


	Pension Benefits						Postretirement Benefits
	2007		2006		2005		2007		2006		2005
Assumptions related to benefit obligations:
Discount rate	6.25	%	6.25	%	5.25	%	6.25	%	6.25	%	5.25	%
Expected rate of compensation increase	5.00	%	5.00	%	5.00	%	N/A		N/A		N/A

Assumptions related to benefit costs:
Discount rate	6.25	%	5.25	%	6.25	%	6.25	%	5.25	%	6.25	%
Expected long-term rate of return on plan assets	7.50	%	7.50	%	7.50	%	7.00	%	7.00	%	7.00	%
Expected rate of compensation increase	5.00	%	5.00	%	5.00	%	N/A		N/A		N/A

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


	Pension Plan									Postretirement Plan
	2007			2006			2005			2007			2006			2005
Components of net periodic pension cost:
Service cost	$	404,909		$	477,279		$	327,424		$	147,693		$	164,539		$	128,972
Interest cost		740,918			695,593			631,731			501,838			481,368			444,267
Expected return on plan assets		(691,262	)		(628,273	)		(571,881	)		(238,896	)		(215,026	)		(185,810	)
Amortization of unrecognized transition obligation		—			—			—			188,892			200,994			237,300
Recognized loss		72,225			240,307			62,395			9,887			78,969			—

Net periodic benefit cost	$	526,790		$	784,906		$	449,669		$	609,414		$	710,844		$	624,729

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Actuarial estimates for the postretirement benefit plan assumed a weighted average annual rate increase in the per capita cost of covered health care benefits (i.e., medical trend rate) of 9%, 10%, and 9% for 2007, 2006 and 2005, respectively. The rates were assumed to decrease gradually to 5% by 2011 and remain at that level thereafter. Assumed medical trend rates have a significant effect on the amounts reported. A 1% point change in assumed healthcare cost trend rates would have the following effects:


	1% Point Increase		1% Point Decrease
Effect on total service and interest cost components	$	94,808	$	(77,294	)
Effect on accumulated postretirement benefit obligation		1,008,371		(836,137	)

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


	Pension Plan			Postretirement Benefit Plan
	Target	2007	2006	Target	2007	2006
Asset category:
Equity securities	50%-70%	60%	61%	35%-65%	51%	50%
Debt securities	30%-50%	34%	36%	35%-65%	41%	42%
Other	0%-20%	6%	3%	0%-20%	8%	8%

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

The Company expects to contribute $600,000 to its pension plan and $600,000 to its postretirement benefit plan in 2008.

The following table reflects expected future benefit payments.


Fiscal year ending September 30	Pension Plan		Postretirement Benefit Plan
2008	$	410,000	$	490,000
2009		423,000		497,000
2010		435,000		501,000
2011		465,000		512,000
2012		512,000		515,000
2013-2017		3,193,000		2,784,000

The Company also sponsors a defined contribution plan/401k (“Plan”) covering all employees who elect to participate. Employees may contribute from 1% to 50% of their annual compensation to the

- 25 -

Plan, limited to a maximum annual amount as set periodically by the Internal Revenue Service. The Company makes matching contributions to the plan with a 100% match on the participants’ first 3% of contributions and 50% on the next 3% of contributions. Company matching contributions were $240,946, $233,327 and $229,441 for 2007, 2006 and 2005, respectively.

8.	COMMON STOCK OPTIONS

The Company’s stockholders approved the RGC Resources, Inc. Key Employee Stock Option Plan (“KESOP”). The 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, 2007, the number of shares available for future grants under the KESOP is 2,000 shares.

The aggregate number of shares under option pursuant to the KESOP are as follows:


	Number of Shares		Weighted- Average Price		Option Price Per Share
Options outstanding, September 30, 2004	53,500		$	19.288	$	15.500-$ 20.875
Options exercised	(7,500	)	$	17.708
Options expired	—


Options outstanding, September 30, 2005	46,000		$	19.545	$	16.875-$ 20.875
Options exercised	(2,000	)	$	20.875
Options expired	—


Options outstanding, September 30, 2006	44,000		$	19.485	$	16.875-$ 20.875
Options exercised	(12,500	)	$	19.425
Options expired	—


Options outstanding, September 30, 2007	31,500		$	19.508	$	18.100-$ 20.875


	Options Outstanding and Exercisable Remaining
	Shares		Life (Years)		Exercise Price
	9,000			2.2	$	20.875
	7,000			3.2		19.250
	9,000			4.2		19.360
	6,500			5.2		18.100

Weighted average	31,500			3.6	$	19.508

- 26 -

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, 2007 and 2006. No options were granted in 2007, 2006 and 2005. The Company received $242,812 from the exercise of options in 2007.

9.	OTHER STOCK PLANS

Dividend Reinvestment and Stock Purchase Plan

The Company offers a Dividend Reinvestment and Stock Purchase Plan (“DRIP”) to shareholders of record for the reinvestment of dividends and the purchase of additional investments of up to $40,000 per year in shares of common stock of the Company. Under the DRIP plan, the Company issued 28,490, 29,721 and 20,349 shares in 2007, 2006 and 2005, respectively. As of September 30, 2007, the Company had 287,401 shares available for issuance under this plan.

Restricted Stock Plan

The Board of Directors of the Company implemented the Restricted Stock Plan for Outside Directors effective January 27, 1997. The Plan is applicable to not more than 50,000 shares of Resources’ common stock. Under the Plan, a minimum of 40% of the monthly retainer fee paid to each non-employee director of Resources is paid in shares of common stock (“Restricted Stock”). The number of shares of Restricted Stock is calculated each month based on the closing sales price of Resources’ common stock on the NASDAQ National Market on the first day of the month, if the first day of the month is a trading day, or if not, the first trading day prior to the first day of the month. Beginning in fiscal 1998, a participant can, subject to approval of the Board, elect to receive up to 100% of his retainer fee for the fiscal year in Restricted Stock. Resources requires that all dividends or other distributions paid on shares of Restricted Stock be automatically sequestered and reinvested on an immediate or deferred basis in additional Restricted Stock.

The directors received a total of 4,091 shares of Restricted Stock in fiscal 2007, representing $84,550 in compensation and $25,013 in dividends reinvested. The directors also received 4,038 shares of Restricted Stock in fiscal 2006, representing $83,080 in compensation and $19,662 in dividends reinvested and 3,366 shares of Restricted Stock in fiscal 2005, representing $68,601 in compensation and $18,770 in dividends reinvested. As of September 30, 2007, the Company had 19,720 shares available for issuance under this plan.

Stock Bonus Plan

Under the Stock Bonus Plan, executive officers are encouraged to own a position in the Company’s common stock of at least 50% of the amount of their annual salary. To promote this policy, the Plan provides that all officers with stock ownership positions below 50% of their annual salaries must, unless approved by the Compensation Committee of the Board of Directors, receive no less than 50% of any performance bonus in the form of Company common stock. Under the Stock Bonus Plan, the Company issued 2,462, 3,899 and 2,314 shares valued at $68,573, $101,438 and $61,895, respectively, in 2007, 2006 and 2005. As of September 30, 2007, the Company had 23,779 shares available for issuance under this plan.

10.

ENVIRONMENTAL MATTER

Both Roanoke Gas and Bluefield Gas, subsidiaries of RGC Resources, Inc., operated manufactured gas plants (“MGPs”) as a source of fuel for lighting and heating until the late 1940s or early 1950s. A by-product of operating MGPs was coal tar, and the potential exists for on-site tar waste

- 27 -

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 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 right of Bluefield Gas to defer MGP clean-up costs, should any be incurred, and to seek rate recovery for such costs. While the Company is selling the stock of Bluefield Gas to ANGD, it has retained ownership of the former MPG site, and entered into an Indemnification and Cost Sharing Agreement with ANGD and Bluefield Gas concerning the site that requires Bluefield Gas and ANGD to seek recovery of any environmental remediation costs through rate recovery and under any applicable insurance policies or from any third party and to reimburse the Company for 25% of any such costs to the extent they are not otherwise recovered. If the Company eventually incurs costs associated with a required clean-up of the Roanoke Gas 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.

11.

COMMITMENTS

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

The Company obtains most of its regulated natural gas supply under asset management contracts. The Company uses an asset manager to assist in optimizing the use of its transportation, storage rights, and gas supply inventories to provide a reliable source of natural gas supply.

Under the same asset manager contract mentioned above, the Company designated the asset manager as agent for their storage capacity and all gas balances in storage. The asset manager provides agency service and manages the utilization of storage assets and the corresponding withdrawals from and injections into storage. The Company retains physical ownership of storage. Under the provision of the asset management contract, the Company has an obligation to purchase its winter storage requirements during the spring and summer injection periods at market price.

The Company also has contracts for pipeline and storage capacity extending for various periods. These capacity costs and related fees are valued at tariff rates in place as of September 30, 2007. These rates may increase or decrease in the future based upon rate filings and rate orders granting a rate change to the pipeline or storage operator.

- 28 -

The following table reflects the financial and volumetric obligations as of September 30, 2007 for each of the years presented for Roanoke Gas. The table does not include the contracts related to the discontinued operations of Bluefield Gas.


	Fixed Price Contracts		Market Price Contracts
Fiscal Year Ending September 30,	Pipeline and Storage Capacity		Natural Gas Contracts (Decatherms)
2008	$	9,729,451	285,985
2009		9,729,451	—
2010		9,729,451	—
2011		9,729,451	—
2012		9,729,451	—

The Company purchased approximately $60,121,000 in gas under the asset management contracts in fiscal 2007.

Subsequent to September 30, 2007, the Company executed a new asset management agreement effective November 1, 2007. The new three-year asset management agreement will result in additional volumetric obligations of 1,907,195; 2,225,059; 2,225,059 and 317,864 decatherms for fiscal 2008, 2009, 2010 and 2011, respectively.

The Company has historically entered into derivative financial contracts for the purpose of hedging the price of natural gas. As of September 30, 2007, the Company has contracted to hedge a set amount of decatherms of natural gas for each month in the winter period, totaling 680,000 decatherms. All decatherm amounts have a ceiling price of $9.90 per decatherm and floor prices ranging from $5.30 to $7.95 per decatherm; see Derivative and Hedging Activities section in footnote 1 for more information.

12.

FAIR VALUE OF FINANCIAL INSTRUMENTS

The carrying value of cash and cash equivalents, temporary cash investments, accounts receivable, accounts payable 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 values for the years ended September 30, 2007 and 2006 are as follows:


	2007				2006
	Carrying Amounts		Approximate Fair Value		Carrying Amounts		Approximate Fair Value
Long-term debt	$	28,000,000	$	28,934,541	$	28,000,000	$	29,009,682

Judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates determined as of September 30, 2007 and 2006 are not necessarily indicative of the amounts the Company could have realized in market exchanges.

- 29 -

13.

ASSET RETIREMENT OBLIGATIONS

The Company adopted FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (“FIN 47”), as of September 30, 2006. FIN 47 requires that a liability be recognized for an asset retirement obligation which is conditional based on the occurrence of a future event even if the timing or method of settlement is uncertain. SFAS No. 143 and FIN 47 require entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes the cost, thereby increasing the carrying amount of the underlying asset. In subsequent periods, the liability is accreted, and the capitalized cost is depreciated over the useful life of the underlying asset. Under the provisions of FIN 47, the Company recorded asset retirement obligations for its future legal obligations related to purging and capping its distribution mains and services upon retirement, although the timing of such retirements is uncertain. The Company recorded a conditional asset retirement obligation of $2,499,345 and $2,404,839 pursuant to its legal obligations upon retirement of its distribution pipeline system as of September 30, 2007 and 2006, respectively.

The Company’s composite depreciation rates include a component to provide for the cost of retirement of assets. As a result, the Company accrues estimated cost of retirement of its utility plant through depreciation expense and creates a corresponding regulatory liability in accordance with the provisions of SFAS No. 71. The costs of retirement considered in the development of the depreciation component include those costs associated with the legal liability as defined under SFAS No. 143 and FIN 47. Therefore, at the time of adoption of FIN 47, the Company reclassified a portion of its regulatory liability for cost of retirement to asset retirement obligations for the legal liability as determined above. If the legal obligations would exceed the regulatory liability provided for in the depreciation rates, the Company would establish a regulatory asset for such difference with the anticipation of future recovery through rates charged to customers.

14.

QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Quarterly financial data for the years ended September 30, 2007 and 2006 is summarized as follows:


2007	First Quarter		Second Quarter		Third Quarter			Fourth Quarter
Operating revenues	$	26,417,644	$	37,572,113	$	15,131,375		$	10,780,169

Gross margin	$	7,243,434	$	8,540,116	$	4,947,278		$	4,490,948

Operating income	$	2,962,789	$	4,167,463	$	764,884		$	63,143

Net income (loss) from continuing operations	$	1,511,653	$	2,286,035	$	236,520		$	(268,539	)

Net income (loss) from discontinued operations	$	173,862	$	306,669	$	(459,586	)	$	19,595

Net income (loss)	$	1,685,515	$	2,592,704	$	(223,066	)	$	(248,944	)

Basic earnings (loss) per share
Continuing operations	$	0.70	$	1.06	$	0.11		$	(0.13	)
Discontinued operations	$	0.08	$	0.14	$	(0.21	)	$	0.01

Net income (loss)	$	0.78	$	1.20	$	(0.10	)	$	(0.12	)

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2006	First Quarter		Second Quarter		Third Quarter			Fourth Quarter
Operating revenues	$	38,384,131	$	33,488,422	$	11,495,048		$	11,223,271

Gross margin	$	6,618,623	$	7,778,537	$	4,387,464		$	4,223,648

Operating income	$	2,511,910	$	3,493,431	$	457,497		$	214,662

Net income (loss) from continuing operations	$	1,211,167	$	1,817,998	$	26,127		$	(93,490	)

Net income (loss) from discontinued operations	$	241,015	$	339,076	$	(83,086	)	$	52,724

Net income (loss)	$	1,452,182	$	2,157,074	$	(56,959	)	$	(40,766	)

Basic earnings (loss) per share
Continuing operations	$	0.58	$	0.86	$	0.01		$	(0.05	)
Discontinued operations	$	0.11	$	0.16	$	(0.04	)	$	0.03

Net income (loss)	$	0.69	$	1.02	$	(0.03	)	$	(0.02	)

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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