UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For Quarterly Period Ended March 31, 2007

Commission File Number 000-26591

RGC Resources, Inc.

(Exact name of Registrant as Specified in its Charter)

VIRGINIA	54-1909697
(State or Other Jurisdiction of Incorporation or Organization)	(I.R.S. Employer Identification No.)

519 Kimball Ave., N.E., Roanoke, VA	24016
(Address of Principal Executive Offices)	(Zip Code)

(540) 777-4427

(Registrant’s Telephone Number, Including Area Code)

None

(Former Name, Former Address and Former Fiscal Year, if Changed Since Last Report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes  x    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer” and “large accelerarted-filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer  ¨                    Accelerated filer  ¨                    Non-accelerated filer  x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act) Yes  ¨    No  x

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Class	Outstanding at April 30, 2007
Common Stock, $5 Par Value	2,163,972

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

UNAUDITED

	March 31, 2007			September 30, 2006
ASSETS
Current Assets:
Cash and cash equivalents	$	4,930,977		$	1,490,141
Accounts receivable - (less allowance for uncollectibles of $808,856 and $34,980, respectively)		14,457,081			5,217,009
Materials and supplies		682,799			649,578
Gas in storage		7,920,610			23,331,703
Prepaid income taxes		—			928,820
Deferred income taxes		2,985,040			2,436,516
Under-recovery of gas costs		—			611,435
Other		917,726			474,355
Total current assets		31,894,233			35,139,557
Utility Property:
In service		118,282,655			114,981,414
Accumulated depreciation and amortization		(39,268,846	)		(37,797,548	)
In service, net		79,013,809			77,183,866
Construction work in progress		1,447,424			1,855,743
Utility Plant, Net		80,461,233			79,039,609
Other assets		451,429			483,406
Total Assets	$	112,806,895		$	114,662,572

See notes to condensed consolidated financial statements.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

UNAUDITED

	March 31, 2007			September 30, 2006
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Borrowings under lines of credit	$	1,981,000		$	6,613,000
Dividends payable		660,011			643,067
Accounts payable		9,297,655			9,451,343
Customer credit balances		2,200,159			4,403,833
Income taxes payable		1,088,553			—
Customer deposits		1,738,201			1,293,019
Accrued expenses		3,767,612			3,701,530
Over-recovery of gas costs		3,295,030			2,112,256
Fair value of marked to market transactions		60,167			1,621,439
Total current liabilities		24,088,388			29,839,487
Long-term Debt, Excluding Current Maturities		30,000,000			30,000,000
Deferred Credits and Other Liabilities:
Asset retirement obligations		2,741,278			2,682,138
Regulatory cost of retirement obligations		5,973,504			5,547,642
Deferred income taxes		5,893,971			5,933,626
Deferred investment tax credits		149,565			164,811
Total deferred credits and other liabilities		14,758,318			14,328,217
Stockholders’ Equity:
Common stock, $5 par value; authorized, 10,000,000 shares; issued and outstanding 2,160,796 and 2,138,595 shares, respectively		10,803,980			10,692,975
Preferred stock, no par, authorized, 5,000,000 shares; no shares issued and outstanding		—			—
Capital in excess of par value		14,949,106			14,521,812
Retained earnings		18,244,431			15,282,909
Accumulated other comprehensive loss		(37,328	)		(2,828	)
Total stockholders’ equity		43,960,189			40,494,868
Total Liabilities and Stockholders’ Equity	$	112,806,895		$	114,662,572

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

FOR THE THREE-MONTH AND SIX-MONTH PERIODS ENDED MARCH 31, 2007 AND 2006

UNAUDITED

	Three Months Ended March 31,					Six Months Ended March 31,
	2007			2006		2007			2006
Operating Revenues:
Gas utilities	$	42,492,873		$	38,337,210	$	72,216,093		$	82,065,126
Other		118,865			120,786		388,689			312,227
Total operating revenues		42,611,738			38,457,996		72,604,782			82,377,353
Cost of Sales:
Gas utilities		32,812,492			29,554,713		54,461,070			65,643,012
Other		30,160			53,376		210,708			142,450
Total cost of sales		32,842,652			29,608,089		54,671,778			65,785,462
Gross Margin		9,769,086			8,849,907		17,933,004			16,591,891
Other Operating Expenses:
Operations		3,017,315			2,884,002		5,904,835			5,805,731
Maintenance		319,092			348,447		666,372			740,864
General taxes		506,937			509,861		931,720			964,584
Depreciation and amortization		1,130,391			1,066,968		2,255,782			2,133,935
Total other operating expenses		4,973,735			4,809,278		9,758,709			9,645,114
Operating Income		4,795,351			4,040,629		8,174,295			6,946,777
Other Expenses (Income), net		(348	)		7,916		(2,016	)		13,443
Interest Expense		606,610			681,480		1,266,243			1,345,135
Income from Continuing Operations Before Income Taxes		4,189,089			3,351,233		6,910,068			5,588,199
Income Tax Expense from Continuing Operations		1,596,385			1,278,769		2,631,849			2,133,389
Income from Continuing Operations		2,592,704			2,072,464		4,278,219			3,454,810
Discontinued operations:
Income from discontinued operations, net of income taxes of $51,769 and $94,499, respectively		—			84,610		—			154,446
Net Income		2,592,704			2,157,074		4,278,219			3,609,256
Other Comprehensive Income (Loss), net of tax		(23,762	)		411,479		(34,500	)		433,865
Comprehensive Income	$	2,568,942		$	2,568,553	$	4,243,719		$	4,043,121
Basic Earnings Per Common Share:
Income from continuing operations	$	1.20		$	0.98	$	1.99		$	1.64
Discontinued operations		—			0.04		—			0.07
Net income	$	1.20		$	1.02	$	1.99		$	1.71
Diluted Earnings Per Common Share:
Income from continuing operations	$	1.20		$	0.98	$	1.98		$	1.63
Discontinued operations		—			0.04		—			0.07
Net income	$	1.20		$	1.02	$	1.98		$	1.70

See notes to condensed consolidated financial statements.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE SIX-MONTH PERIODS

ENDED MARCH 31, 2007 AND 2006

UNAUDITED

	Six Months Ended March 31,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income from continuing operations	$	4,278,219		$	3,454,810
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation and amortization		2,381,212			2,254,327
Cost of removal of utility plant, net		(102,906	)		(118,254	)
Changes in assets and liabilities which provided cash, exclusive of changes and noncash transactions shown separately		5,698,056			1,786,299
Net cash provided by continuing operating activities		12,254,581			7,377,182
Net cash provided by discontinued operations		—			154,446
Net cash provided by operating activities		12,254,581			7,531,628
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant		(3,420,291	)		(3,356,760	)
Proceeds from disposal of utility property		—			1,686
Net cash used in investing activities		(3,420,291	)		(3,355,074	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		—			17,000,000
Retirement of long-term debt and capital leases		—			(13,000,000	)
Net repayments under line-of-credit agreements		(4,632,000	)		(7,509,000	)
Proceeds from issuance of common stock		538,299			546,372
Cash dividends paid		(1,299,753	)		(1,251,895	)
Net cash used in financing activities		(5,393,454	)		(4,214,523	)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		3,440,836			(37,969	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		1,490,141			1,349,518
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	4,930,977		$	1,311,549
SUPPLEMENTAL INFORMATION:
Cash paid during the year for:
Interest	$	1,243,098		$	1,346,216
Income taxes net of refunds		1,196,794			1,200,415

See notes to condensed consolidated financial statements.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

UNAUDITED

1. In the opinion of management, the accompanying unaudited condensed consolidated financial statements contain all adjustments (consisting of only normal recurring accruals) necessary to present fairly RGC Resources, Inc.’s financial position as of March 31, 2007 and the results of its operations for the three months and six months ended March 31, 2007 and 2006 and its cash flows for the six months ended March 31, 2007 and 2006. The results of operations for the three months and six months ended March 31, 2007 are not indicative of the results to be expected for the fiscal year ending September 30, 2007 as quarterly earnings are affected by the highly seasonal nature of the business and weather conditions generally result in greater earnings during the winter months.

2. The condensed consolidated interim financial statements and condensed notes are presented as permitted by Form 10-Q and do not contain certain information included in the Company’s annual consolidated financial statements and notes thereto. The condensed consolidated financial statements and condensed notes should be read in conjunction with the financial statements and notes contained in the Company’s Form 10-K.

3. Certain reclassifications were made to prior year financial statements to place them on a basis consistent with current year presentation with regard to discontinued operations, utility property, nonutility property, accrued expenses and refunds from suppliers-due customers.

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

5. On February 16, 2007, RGC Resources, Inc. (“Resources” or “Company”) entered into a Purchase and Sale Agreement with ANGD LLC (“ANGD”) for the sale of all of the capital stock of Bluefield Gas Company (“Bluefield”), a wholly owned subsidiary of Resources, to ANGD. Bluefield represents approximately 3,800 of Resources 61,400 natural gas customers. The sales price will be equal to the book value of Bluefield’s 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 (or its designee) prior to Closing, (ii) inter-company receivables or payables existing between Bluefield and the Company (including its other affiliates) will be settled as of Closing, and (iii) the Company will pay off Bluefield’s outstanding debt at Closing out of the sales proceeds. Resources anticipates using the remaining proceeds from the sale to provide additional capital investment for its other wholly owned regulated natural gas subsidiary, Roanoke Gas Company (“Roanoke”).

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

UNAUDITED

Also on February 16, 2007, Roanoke entered into an Asset Purchase and Sale Agreement with Appalachian Natural Gas Distribution Company (“Appalachian”) for the sale of Roanoke’s 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. Approximately 1,200 of Roanoke’s 57,600 customers are represented by these assets. The sales price will be 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 sale price shall be 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. Roanoke anticipates using the proceeds from the sale to retire debt.

The Board of Directors approved the Purchase and Sale Agreements of Bluefield Gas Company and the Bluefield division of Roanoke Gas Company for several reasons. The management time and effort required to oversee operations in West Virginia is significantly disproportionate to the size of the operation. The regulatory environment 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 lead 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 transactions contemplated by the purchase agreements require the approval of the respective regulatory commissions: the West Virginia Public Service Commission for the sale of Bluefield and the Virginia State Corporation Commission for the sale of Virginia assets. Furthermore, the closing of each of the purchase agreements is conditioned upon such approval of the other transaction. Therefore, the parties intend that either both transactions would close or neither would close. SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, requires that long-lived assets or disposal groups to be sold shall be classified as held for sale in the period in which certain criteria are met. Paragraph 30.d. of SFAS No. 144 specifies “The sale of the asset (disposal group) is probable, and transfer of the asset (disposal group) is expected to qualify for recognition as a completed sale within one year…” Because the approval of both commissions is required to complete the transaction and due to the uncertainty as to how each Commission will rule on the applications, the Company does not believe the proposed transaction meets the probable definition requirement of SFAS No 144 in classifying the assets contemplated in the transactions as held for sale. Therefore, the results of operations of both Bluefield Gas and the Bluefield, Virginia division of Roanoke Gas are not reflected as discontinued operations. If the requirements of SFAS No. 144 had been met, the effect on the financial statements included in this quarterly report of the proposed transactions would be as presented below.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

UNAUDITED

	Three Months Ended March 31,						Six Months Ended March 31,
	2007			2006			2007			2006
Bluefield Gas
Revenues	$	5,039,625		$	4,969,574		$	8,615,025		$	10,504,800
Pretax Operating Income		309,762			248,017			432,179			350,984
Continuing Costs		192,134			167,444			351,754			342,545
Income Tax Expense		(195,934	)		(161,702	)		(304,816	)		(269,298	)
Discontinued Operations	$	305,962		$	253,759		$	479,117		$	424,231

The carrying amounts of the major classes of assets and liabilities subject to the purchase agreements for the period ended March 31, 2007 are as follows:

	As of March 31, 2007
Current Assets	$	522,071
Utility Property		9,134,146
Other Assets		63,442
Total Assets	$	9,719,659
Current Liabilities	$	3,649,552
Debt		2,000,000
Deferred Credits and Other Liabilities		1,136,121
Total Liabilities	$	6,785,673

Each of the purchase agreements provides 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.

Resources does not anticipate the closing of the purchase agreements to result in a material gain or loss in the consolidated results of operations.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

UNAUDITED

6. 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 discontinued operations related to the sale of Highland Energy contracts for the three and six months ended March 31, 2006 are reflected below.

	Three Months Ended March 31,				Six Months Ended March 31,
	2007	2006			2007	2006
Highland Energy
Revenues	—	$	7,323,070		—	$	16,167,712
Pretax Operating Income	—		123,733		—		219,826
Continuing Costs	—		12,646		—		29,119
Income Tax Expense	—		(51,769	)	—		(94,499	)
Discontinued Operations	—	$	84,610		—	$	154,446

7. Since 2003, Roanoke Gas Company has had in place a weather normalization adjustment tariff (“WNA”) based on a weather occurrence band around the most recent 30-year temperature average. The weather band provides approximately a 6 percent 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) fell within the weather band, no adjustment would be made. However, if the number of heating-degree days were below the weather band, the Company would add a surcharge to customer bills equal to the equivalent margin lost beyond the weather band deficiency. Likewise, if the number of heating-degree days were above the weather band, the Company would credit customer bills equal to the excess margin realized above the weather band. The measurement period in determining the weather band extends from April through March. As of March 31, 2007, heating-degree days for the period April 2006 through March 2007 were approximately 12 percent less than the 30-year average. The Company recorded approximately $118,000 in additional revenues for the quarter and approximately $446,000 in additional revenues during the first six months to reflect the estimated impact of the WNA tariff for the difference in margin realized for weather between 12 percent and 6 percent warmer than the 30-year average. For the measurement period of April 2005 through March 2006, the heating-degree days were approximately 11 percent less than the 30-year average. As a result, the income statements for the three and six month periods ended March 31, 2006 include approximately $338,000 in additional revenues related to the application of the WNA tariff. The Company applied the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 71, Accounting for the Effects of Certain Types of Regulation, in recording the estimated revenue.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

UNAUDITED

8. In April 2007, Roanoke Gas Company received the final rate order approving rates that provide for $1,667,940 in additional annual non gas revenues. Since October 23, 2006, Roanoke Gas Company had placed rates into effect providing for approximately $1.75 million in additional annual non-gas revenues subject to refund. As a result of this final order, Roanoke Gas Company has recorded a provision for refund of approximately $53,000 plus interest. The Company expects to complete the refund during the June billing cycle.

9. On March 22, 2007, the Company and Wachovia Bank renewed the Company’s line-of-credit agreements. The new agreements maintain the same variable interest rates based upon 30 day LIBOR and continue the multi-tier level for borrowing limits to accommodate the Company’s seasonal borrowing demands. The multi-tier approach will keep 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. Effective with the execution of the new agreements, the Company’s total available limits under the lines-of-credit are as follows:

Beginning	Available Line of Credit
April 1, 2007	$	10,000,000
July 16, 2007		15,000,000
September 16, 2007		23,000,000
November 16, 2007		27,000,000
February 16, 2008		22,000,000

The line-of-credit agreements will expire March 31, 2008, unless extended. The Company anticipates being able to extend or replace the credit lines upon expiration. At March 31, 2007, the Company had $1,981,000 outstanding under its lines-of-credit agreements.

10. 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 the Company would seek to hedge include the price of natural gas and the cost of borrowed funds.

The Company has historically entered into futures, swaps and caps for the purpose of hedging the price of natural gas in order to provide price stability during the winter months. During the quarter ended March 31, 2007, the Company had settled all outstanding swap and price cap arrangements for the purchase of natural gas. Net income and other comprehensive income are not affected by the change in market value as any cost incurred or benefit received from these instruments is recoverable or refunded through the regulated natural gas purchased gas adjustment (PGA) mechanism. Both the Virginia State Corporation

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

UNAUDITED

Commission and the West Virginia Public Service Commission currently allow for full recovery of prudent costs associated with natural gas purchases, and any additional costs or benefits associated with the settlement of these instruments will be passed through to customers when realized.

The Company 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 upon LIBOR into fixed rate debt with a 5.74 percent interest rate. The swap qualifies as a cash flow hedge with changes in fair value reported in other comprehensive income.

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

Three Months Ended March 31, 2007
	Interest Rate Swap			Minimum Pension Liability			Total
Unrealized losses	$	(28,103	)	$	—		$	(28,103	)
Income tax benefit		10,668			—			10,668
Net unrealized losses		(17,435	)		—			(17,435	)
Transfer of realized gains to income		(10,198	)		—			(10,198	)
Income tax expense		3,871			—			3,871
Net transfer of realized gains to income		(6,327	)		—			(6,327	)
Net other comprehensive loss	$	(23,762	)	$	—		$	(23,762	)
Three Months Ended March 31, 2006
	Interest Rate Swap			Minimum Pension Liability			Total
Unrealized gains	$	447,186		$	196,227		$	643,413
Income tax expense		(169,752	)		(74,566	)		(244,318	)
Net unrealized gains		277,434			121,661			399,095
Transfer of realized losses to income		19,960			—			19,960
Income tax benefit		(7,576	)		—			(7,576	)
Net transfer of realized losses to income		12,384			—			12,384
Net other comprehensive income	$	289,818		$	121,661		$	411,479

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

UNAUDITED

Six Months Ended March 31, 2007
	Interest Rate Swap			Minimum Pension Liability			Total
Unrealized losses	$	(35,027	)	$	—		$	(35,027	)
Income tax benefit		13,296			—			13,296
Net unrealized losses		(21,731	)		—			(21,731	)
Transfer of realized gains to income		(20,581	)		—			(20,581	)
Income tax expense		7,812			—			7,812
Net transfer of realized gains to income		(12,769	)		—			(12,769	)
Net other comprehensive loss	$	(34,500	)	$	—		$	(34,500	)
Fair value of marked to market transactions	$	(60,167	)		—		$	(60,167	)
Accumulated comprehensive loss	$	(37,328	)		—		$	(37,328	)
Six Months Ended March 31, 2006
	Interest Rate Swap			Minimum Liability Pension			Total
Unrealized gains	$	286,989		$	392,454		$	679,443
Income tax expense		(108,941	)		(149,133	)		(258,074	)
Net unrealized gains		178,048			243,321			421,369
Transfer of realized losses to income		20,141			—			20,141
Income tax benefit		(7,645	)		—			(7,645	)
Net transfer of realized losses to income		12,496			—			12,496
Net other comprehensive income	$	190,544		$	243,321		$	433,865
Fair value of marked to market transactions	$	320,736			—		$	320,736
Accumulated comprehensive income (loss)	$	198,985			(145,591	)	$	53,394

11. Basic earnings per common share for the three months and six months ended March 31, 2007 and 2006 are calculated by dividing net income by the weighted average common shares outstanding during the period. Diluted earnings per common share for the three months and six months ended March 31, 2007 and 2006 are calculated by dividing net income by the weighted average common shares outstanding during the period plus dilutive potential

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

UNAUDITED

common shares. Dilutive potential common shares are calculated in accordance with the treasury stock method, which assumes that proceeds from the exercise of all options are used to repurchase common stock at market value. The amount of shares remaining after the proceeds are exhausted represents the potentially dilutive effect of the securities. A reconciliation of the weighted average common shares and the diluted average common shares is provided below:

	Three Months Ended March 31,		Six Months Ended March 31,
	2007	2006	2007	2006
Weighted average common shares	2,157,532	2,114,012	2,152,741	2,108,996
Effect of dilutive securities:
Options to purchase common stock	10,642	10,214	9,937	10,503
Diluted average common shares	2,168,174	2,124,226	2,162,678	2,119,499

12. The Company has both a defined benefit pension plan (the “pension plan”) and a post- retirement benefits plan (the “post-retirement plan”). The pension plan covers substantially all of the Company’s employees and provides retirement income based on years of service and employee compensation. The post-retirement plan provides certain healthcare and supplemental life insurance benefits to retired employees who meet specific age and service requirements. Net pension plan and post-retirement plan expense recorded by the Company is detailed as follows:

	Three Months Ended March 31,						Six Months Ended March 31,
	2007			2006			2007			2006
Components of net periodic pension cost:
Service cost	$	101,227		$	119,320		$	202,454		$	238,640
Interest cost		185,228			173,896			370,456			347,792
Expected return on plan assets		(172,816	)		(157,068	)		(345,632	)		(314,136	)
Recognized loss		18,050			60,077			36,100			120,154
Net periodic pension cost	$	131,689		$	196,225		$	263,378		$	392,450

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

UNAUDITED

	Three Months Ended March 31,						Six Months Ended March 31,
	2007			2006			2007			2006
Components of post-retirement benefit cost:
Service cost	$	36,923		$	42,468		$	73,846		$	85,301
Interest cost		125,461			125,060			250,922			248,021
Expected return on plan assets		(59,724	)		(56,640	)		(119,448	)		(109,343	)
Amortization of unrecognized transition obligation		47,223			49,434			94,446			108,759
Recognized loss		2,472			19,458			4,944			42,665
Net post-retirement benefit cost	$	152,355		$	179,780		$	304,710		$	375,403

The Company contributed $400,000 to its pension plan for the six-month period ended March 31, 2007. The Company expects to make a total contribution of approximately $800,000 to its pension plan and $700,000 to its post-retirement benefit plan during the fiscal year ending September 30, 2007.

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

14. 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

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

UNAUDITED

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 fiscal years beginning after December 15, 2006. 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, results of operations or cash flows.

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. 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 Company has not completed its evaluation of this statement and has not yet determined the full impact on the Company’s financial position or results of operations in light of the current regulatory environment and the application of SFAS No. 71. In the absence of the considerations of SFAS No. 71 and using the most recent actuarial valuation as of June 30, 2006, the effect on the March 31, 2007 balance sheet would have been to increase accrued postretirement benefits and accumulated comprehensive loss by approximately $4,200,000 and $2,600,000, respectively, and decrease the deferred income tax liability by approximately $1,700,000. The Company does not expect the adoption of this statement to adversely affect the results of operations or cash flows on a going forward basis.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

UNAUDITED

In June 2006, the FASB issued Emerging Issues Tax Force (“EITF”) Issue No. 06-3, How Sales Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross Versus Net Presentation). EITF requires disclosure of accounting policy regarding the gross or net presentation of point-of-sales taxes such as sales tax and value-added tax. If taxes included in gross revenues are significant, the amount of such taxes for each period for which an income statement is presented should be disclosed. With the exception of the West Virginia Business and Occupation Taxes (“B&O”) imposed on sales within the state of West Virginia, all such taxes are encompassed by this EITF are recorded at net and not gross. The level of West Virginia B&O taxes included in revenues and general taxes for the three month and six month periods ended March 31, 2007 and 2006 is provided below:

	Three Months Ended March 31,				Six Months Ended March 31,
	2007		2006		2007		2006
West Virginia B&O Taxes
Included in Revenues	$	163,710	$	167,772	$	279,375	$	306,585
Included in General Taxes		163,710		167,772		279,375		306,585

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.

RGC RESOURCES, INC. AND SUBSIDIARIES

ITEM 2 - MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Statements

From time to time, RGC Resources, Inc. (“Resources” or the “Company”) may publish forward-looking statements relating to such matters as anticipated financial performance, business prospects, technological developments, new products, research and development activities and similar matters. The Private Securities Litigation Reform Act of 1995 provides a safe harbor for forward-looking statements. In order to comply with the terms of the safe harbor, the Company notes that a variety of factors could cause the Company’s actual results and experience to differ materially from the anticipated results or other expectations expressed in the Company’s forward-looking statements. The risks and uncertainties that may affect the operations, performance, development and results of the Company’s business include the following: (i) failure to earn on a consistent basis an adequate return on invested capital; (ii) ability to retain and attract professional and technical employees; (iii) price competition from alternative fuels; (iv) volatility in the price and availability of natural gas; (v) uncertainty in the projected rate of growth of natural gas requirements in the Company’s service area; (vi) general economic conditions both locally and nationally (for instance, southern West Virginia); (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 (such as hurricanes) 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. AND SUBSIDIARIES

ITEM 2 - MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview

Resources is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately 61,400 residential, commercial and industrial customers in Roanoke, Virginia and Bluefield, Virginia and West Virginia and the surrounding areas through its Roanoke Gas Company (“Roanoke”) and Bluefield Gas Company (“Bluefield”) subsidiaries. Natural gas service is provided at rates and for the terms and conditions set forth by the State Corporation Commission (“SCC”) in Virginia and the Public Service Commission (“PSC”) in West Virginia.

Resources also provides certain unregulated natural gas related services through Roanoke Gas Company and information system services to software providers in the utility industry through RGC Ventures, Inc. of Virginia, which operates as Application Resources. Such operations represent less than one percent of total revenues and income of Resources.

Winter weather conditions and volatility in natural gas prices both have a direct influence on the quantity of natural gas sales to the Company’s customers 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. Furthermore, rising natural gas commodity prices could also affect customer usage through conservation or use of alternative fuels.

Because the respective regulatory commissions in Virginia and West Virginia authorize billing rates for each of the natural gas operations based upon normal weather, warmer than normal weather may result in the Company failing to earn its authorized rate of return. For the quarter ended March 31, 2007, heating degree-days (an industry measure by which the average daily temperature falls below 65 degrees Fahrenheit) were 6 percent more than the same period last year and 8 percent lower than the 30-year normal.

The Company has been 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’s rate structure, which allows the company to recover revenues equivalent to the margin that would be realized at approximately 6 percent warmer than the 30-year normal. The Company recorded approximately $118,000 and $446,000 in additional revenues for the three-month and six-month periods ended March 31, 2007 to reflect the estimated impact of the WNA for the difference in margin realized for weather between 12 percent and 6 percent warmer than the 30-year average. In the prior fiscal year, the Company recorded approximately $338,000 in additional revenues for the three-month and six-month periods ended March 31, 2006.

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 may influence the level of sales due to conservation efforts by customers or may result in customers switching to an alternative fuel. In addition, increasing prices may increase the level of bad debts due to

RGC RESOURCES, INC. AND SUBSIDIARIES

ITEM 2 - MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

customers’ inability to afford the higher prices. After natural gas prices spiked in December 2005 following the impact of hurricanes on natural gas supplies and prices, the Company experienced reduced consumption in the following two quarters by customers in what appeared to be a response to the high energy prices. Based on the level of sales for the quarter ended March 31, 2007, the Company believes that much of the conservation it encountered last year has declined and natural gas consumption has returned to its prior trends as natural gas prices have declined. Although natural gas production facilities and pipelines are better prepared for the impact of severe weather in the Gulf of Mexico, the forecast of a more active 2007 hurricane season still is a cause for concern regarding the potential impact on natural gas production and prices if another hurricane entered the Gulf of Mexico and caused damage to natural gas production facilities.

Results of Operations

Consolidated net income for the three-month and six-month periods ended March 31, 2007 was $2,592,704 and $4,278,219, respectively, compared to $2,157,074 and $3,609,256 for the same periods last year. Net income from continuing and discontinued operations is as follows:

	Three Months Ended March 31,				Six Months Ended March 31,
	2007		2006		2007		2006
Net Income
Continuing Operations	$	2,592,704	$	2,072,464	$	4,278,219	$	3,454,810
Discontinued Operations		—		84,610		—		154,446
Net Income	$	2,592,704	$	2,157,074	$	4,278,219	$	3,609,256

RGC RESOURCES, INC. AND SUBSIDIARIES

ITEM 2 - MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Continuing Operations

Three Months Ended March 31, 2007:

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

	Three Months Ended March 31,		Increase/ (Decrease)
	2007	2006			Percentage
Delivered Volumes
Regulated Natural Gas (DTH)
Tariff Sales	3,598,058	3,246,778	351,280		11	%
Transportation	780,539	797,778	(17,239	)	-2	%
Total	4,378,597	4,044,556	334,041		8	%
Heating Degree Days	1,978	1,868	110		6	%
(Unofficial)

The table below reflects operating revenues.

	Three Months Ended March 31,				Increase/ (Decrease)
	2007		2006					Percentage
Operating Revenues
Gas Utilities	$	42,492,873	$	38,337,210	$	4,155,663		11	%
Other		118,865		120,786		(1,921	)	-2	%
Total Operating Revenues	$	42,611,738	$	38,457,996	$	4,153,742		11	%

Total operating revenues from continuing operations for the three months ended March 31, 2007 increased by $4,153,742, or 11 percent, compared to the same period last year, due to the effect that colder weather had on energy consumption and the implementation of a non-gas cost rate increase. The total average unit cost of natural gas for the quarter was consistent with last year’s level. Total regulated natural gas delivered volumes increased by 11 percent as the total number of heating degree-days increased by 6 percent from the same period last year. Other revenues were flat with last year.

RGC RESOURCES, INC. AND SUBSIDIARIES

ITEM 2 - MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

	Three Months Ended March 31,				Increase/ (Decrease)
	2007		2006				Percentage
Gross Margin
Gas Utilities	$	9,680,381	$	8,782,497	$	897,884	10	%
Other		88,705		67,410		21,295	32	%
Total Gross Margin	$	9,769,086	$	8,849,907	$	919,179	10	%

Total gross margin increased by $919,179, or 10 percent, for the quarter ended March 31, 2007 over the same period last year. Regulated natural gas margins increased by $897,884, or 10 percent, corresponding to the 8 percent increase in total delivered natural gas volumes (both tariff and transporting). The increase in regulated operations margin is due to the increase in firm volume sales and the implementation of a non-gas cost rate increase, partially offset by the recognition of a smaller WNA surcharge accrual and reduced level of carrying cost revenues. The increase in firm sales resulted from an increase in heating degree-days and a partial lessening of customer conservation efforts begun in 2006 in response to the high energy prices and high customer bills incurred in the first quarter of fiscal 2006. Total heating degree-days increased by 6 percent while total tariff volumes (most of which are weather dependent) increased by 11 percent. In addition, both Roanoke and Bluefield placed increased rates into effect during the first quarter. Roanoke’s rates were placed into effect subject to refund pending a final order from the Virginia SCC. Bluefield’s rates were placed into effect in accordance with a final rate order issued by the West Virginia PSC. See Regulatory Affairs section for more information regarding these rate awards. As a result of these rate awards and the increase in total natural gas deliveries, the Company realized approximately $123,000 in additional margin from customer base charges, which is a flat monthly fee billed to each natural gas customer, and approximately $1,045,000 associated with increase in the volumetric price of natural gas. Carrying cost revenues, as explained below, decreased by approximately $55,000 due to changes implemented as part of the new rates placed into effect for Bluefield Gas. WNA revenues declined by approximately $221,000, as the current quarter was approximately 8 percent warmer than the 30-year normal, while the same quarter last year was approximately 15 percent warmer than the 30-year normal. The WNA adjustments essentially increased the regulated margins for Roanoke to a position equivalent to margins that would have been realized if the weather had been approximately 6 percent warmer than the 30-year normal during the measurement period of April to March. As a result, the WNA negated a majority of the effect that weather had on the gross margin between periods. The components of the gas utility margin increase are summarized below:

RGC RESOURCES, INC. AND SUBSIDIARIES

ITEM 2 - MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Net Margin Increase

Customer Base Charge including rate increase	$	123,222
WNA		(220,835	)
Carrying Cost		(55,183	)
Volumetric including rate increase and volume		1,045,178
Other		5,502
Total	$	897,884

Roanoke had an approved rate structure in place during the quarter that allowed it to accrue revenue to cover the financing costs related to the level of investment in natural gas inventory. During times of rising gas costs and rising inventory levels, Roanoke recognizes revenues to offset the higher financing costs. Conversely, Roanoke passes along savings to customers during times of declining gas costs and lower inventories. Bluefield had a similar mechanism in place. However, as a result of an order by the West Virginia PSC in Bluefield’s 2006 rate case, Bluefield ended its separate calculation of carrying cost revenue in November 2006. These revenues are now included as part of the base non-gas rates and will only be adjusted as a result of future rate case filings. The net effect of the change in the rate structure for Bluefield’s carrying cost accounted for most of the $55,000 decline in these revenues; however, these revenues are now included as part of volumetric sales and margins. Other margins increased last year primarily due to billings to Atmos Energy Marketing, LLC, the acquirer of the Highland Energy operations. The agreement for the sale of the energy marketing assets included the provision for Resources to provide for one year, with an option for a second year, ongoing transitioning assistance to those customers previously served by Highland Energy.

Operations expenses increased by $133,313, or 5 percent, compared to the same period last year. Increases in bad debt expense, labor costs and audit fees more than offset decreases in employee benefit expenses. Bad debt expense increased by approximately $20,000 as total operating revenues increased by 11 percent. Professional services increased by $31,000 primarily related to additional fees associated with the Company’s prior auditors providing their consent to the fiscal 2006 year end financial statements. Labor costs increased $90,000 due to annual performance increases. Employee benefit expenses decreased by $80,000 due to reductions 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. Maintenance expenses decreased $29,355, or 8 percent, from the same period last year. The decrease in maintenance primarily relates to timing of repairs of pipeline leaks in the Company’s distribution system determined through leak surveys. During the current quarter, the Company conducted much of its annual leak surveys, which may lead to a reallocation of Company resources in the upcoming quarters related to any discovered leaks requiring repair.

General taxes were nearly unchanged from the same period last year. Depreciation expense increased $63,423, or 6 percent, due to the growth in utility plant associated with extending service to new customers and replacing cast iron and bare steel pipe. Net other expense (income) changed by $8,264 due to a higher level of investment earnings.

RGC RESOURCES, INC. AND SUBSIDIARIES

ITEM 2 - MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Interest expense decreased by $74,870, or 11 percent, as significant reductions in borrowings under the Company’s line-of-credit agreements more than offset the impact of higher interest rates on variable rate debt. The combination of lower natural gas inventories, higher customer credit balances under the budget payment program, greater level of overcollection of gas costs and improved earnings all contributed to reducing the overall average borrowing requirements for the quarter by nearly $7,900,000, while the effective average interest rate on the Company’s line-of-credit increased from 5.0 percent last year to 5.9 percent for the current period.

Income tax expense increased by $317,616, which corresponds to the increase in pre-tax income on continuing operations for the quarter. The effective tax rate for the quarter was 38.1 percent compared to 38.2 percent for the same period last year.

Six Months Ended March 31, 2007:

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

	Six Months Ended March 31,		Increase/ (Decrease)
	2007	2006			Percentage
Delivered Volumes
Regulated Natural Gas (DTH)
Tariff Sales	5,983,730	5,915,939	67,791		1	%
Transportation	1,543,023	1,590,427	(47,404	)	-3	%
Total	7,526,753	7,506,366	20,387		0	%
Heating Degree Days	3,330	3,370	(40	)	-1	%
(Unofficial)

The table below reflects operating revenues.

	Six Months Ended March 31,				Increase/ (Decrease)
	2007		2006					Percentage
Operating Revenues
Gas Utilities	$	72,216,093	$	82,065,126	$	(9,849,033	)	-12	%
Other		388,689		312,227		76,462		24	%
Total Operating Revenues	$	72,604,782	$	82,377,353	$	(9,772,571	)	-12	%

RGC RESOURCES, INC. AND SUBSIDIARIES

ITEM 2 - MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Total operating revenues from continuing operations for the six months ended March 31, 2007 decreased by $9,772,571, or 12 percent, compared to the same period last year, due to lower gas costs in the first quarter, partially offset by the implementation of non-gas cost rate increases. Although total tariff sales of the gas utilities increased slightly by 1 percent, the average unit cost of natural gas delivered to customers decreased by 18 percent as energy prices spiked in December 2005 due to the combination of cold weather and production issues in the Gulf of Mexico attributable to damage caused by hurricanes in 2005. Other revenues increased by 24 percent due to certain one-time projects related to other non-regulated natural gas related services.

	Six Months Ended March 31,				Increase/ (Decrease)
	2007		2006				Percentage
Gross Margin
Gas Utilities	$	17,755,023	$	16,422,114	$	1,332,909	8	%
Other		177,981		169,777		8,204	5	%
Total Gross Margin	$	17,933,004	$	16,591,891	$	1,341,113	8	%

Total gross margin increased by $1,341,113, or 8 percent, for the six-month period ended March 31, 2007 over the same period last year. Regulated natural gas margins increased by $1,332,909, or 8 percent, even though total delivered volume (tariff and transporting) remained virtually unchanged from last year’s volumes. The increase in margin is attributable to the implementation of non-gas cost rate increases, a lessening in customer conservation efforts that began in the prior year in response to high natural gas prices and a higher WNA accrual. The components of the regulated margin increase are summarized below:

Net Margin Increase

Customer Base Charge including rate increase	$	230,396
WNA		107,764
Carrying Cost		(70,942	)
Volumetric including rate increase and volume		1,054,699
Other		10,992
Total	$	1,332,909

Operations expenses increased by $99,104, or 2 percent, for the six-month period ended March 31, 2007 compared to the same period last year. Increases in audit fees, contracted services and operations labor more than offset reductions in employee benefit expenses. Audit fees increased $46,000 primarily due to timing of internal audit services and additional fees associated with the Company’s prior auditors providing their consent to the fiscal 2006 year end financial

RGC RESOURCES, INC. AND SUBSIDIARIES

ITEM 2 - MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

statements. Contract services and labor increased approximately $197,000 related to timing of distribution pipeline leak surveys, network support services and salary increases. Employee benefit expenses decreased by $167,000 due to reductions in pension and other post employment benefit costs. Maintenance expenses decreased $74,792, or 10 percent, from the same period last year. The decrease in maintenance primarily related to timing of repairs of pipeline leaks in the Company’s distribution system. Maintenance expenses are expected to increase over the next two quarters to repair pipeline leak repairs discovered during the annual leak survey process currently being conducted.

General taxes decreased $32,864, or 3 percent, for the six-month period ended March 31, 2007 compared to the same period last year primarily due to a reduction in the West Virginia Business and Occupation Tax, a revenue sensitive tax, resulting from reduced revenues in the West Virginia natural gas operations. Depreciation expense increased $121,847, or 6 percent, due to the growth in utility plant associated with extending service to new customers and replacing cast iron and bare steel pipe. Net other expense (income) changed by $15,459 due to a higher level of investment earnings.

Interest expense decreased by $78,892, or 6 percent, as significant reductions in borrowings under the Company’s line-of-credit agreements more than offset the impact of higher interest rates on variable rate debt. As discussed above, the combination of lower natural gas inventories, higher customer credit balances under the budget payment program, greater level of overcollection of gas costs and improved earnings all contributed to reducing the overall average borrowing requirements for the quarter by nearly $6,400,000, while the effective average interest rate on the Company’s line-of-credit increased from 4.8 percent last year to 5.9 percent for the current period. The lower borrowing levels and the corresponding reduction in interest expense experienced by the Company are the result of a combination of multiple factors as discussed above. The continuation of these factors in future periods is not expected, and the Company expects borrowings under its line-of-credit agreements will return to higher levels next year.

Income tax expense increased $498,460, which corresponds to the rise in pre-tax income on continuing operations. The effective tax rate was 38.1 percent compared to 38.2 percent for the same period last year.

The three-month and six-month earnings presented herein should not be considered as reflective of the Company’s consolidated financial results for the fiscal year ending September 30, 2007. The total revenues and margins realized during the first six months reflect higher billings due to the weather sensitive nature of the gas business. Improvement or decline in earnings for the balance of the year will depend primarily on the level of operating and maintenance costs and, to a lesser extent, weather.

Pending Divestitures

As discussed in note 5 of the financial statements, Resources entered into a Purchase and Sale Agreement with ANGD for the sale of all of the capital stock of Bluefield to ANGD and

RGC RESOURCES, INC. AND SUBSIDIARIES

ITEM 2 - MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Roanoke entered into an Asset Purchase and Sale Agreement with Appalachian Natural Gas Distribution Company (“Appalachian”) for the sale of Roanoke’s 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 3,800 customers of Bluefield and 1,200 Roanoke customers are represented by these sale agreements. The sales price of the Roanoke assets will be 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 shall be 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. The Company anticipates using the proceeds from both sales to reduce debt and provide additional capital investment for Roanoke.

The Board of Directors approved the Purchase and Sale Agreements of Bluefield Gas Company and the Bluefield division of Roanoke Gas Company for several reasons. The management time and effort required to oversee operations in West Virginia is significantly disproportionate to the size of the operation. The regulatory environment 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 lead to a loss of population and gas customers in our West Virginia service area. Management believes that the net proceeds realized from these transactions can be reinvested in the Roanoke’s operations and ultimately provide a better return for the Company than could be realized in the Bluefield operations.

The transactions contemplated by the purchase agreements require the approval of the respective regulatory commissions: the West Virginia Public Service Commission for the sale of Bluefield and the Virginia State Corporation Commission for the sale of the assets of the Bluefield Division of Roanoke Gas Company. Furthermore, the closing of each of the purchase agreements is conditioned upon such approval of the other transaction. Each of the purchase agreements provides at closing for a services agreement to be executed whereby Resources and Roanoke will provide certain customer billing, gas control, regulatory and administrative services for Bluefield and Appalachian on mutually agreeable terms.

If both commissions approve the proposed transaction and the agreements are executed, the sale of Bluefield Gas Company and the Bluefield Division of Roanoke Gas Company could result in lower earnings for Resources in the near term. Even though the combined annual loss for both of these operations were approximately $142,000 and $195,000 for the fiscal years ended September 30, 2006 and 2005, these operations also included $729,000 and $683,000, respectively, in allocated costs from Resources and Roanoke that would be retained by the Company. A portion of these retained costs would be recovered under the services agreement with ANGD discussed above. In addition, the promissory note from ANGD would generate interest income, and the approximately $2,000,000 of net proceeds from the sale of Bluefield stock would be reinvested in Roanoke and be used to reduce company debt and interest expense.

RGC RESOURCES, INC. AND SUBSIDIARIES

ITEM 2 - MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In Roanoke’s next non-gas cost rate filing, the Company would file for a return on the $2,000,000 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 by more than $300,000 as Bluefield’s net loss would be replaced by a return on the $2,000,000 equity investment into Roanoke. Based on the most recent rate filing, the Company could earn a 10 percent return on this equity investment.

Discontinued Operations

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 sales price was deferred until August 2007. The final amount of the payment due is subject to certain customer retention and sales levels realized by the acquiring entity.

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 to understanding certain key components of the financial statements.

Revenue recognition –Regulated utility sales and transportation revenues are based upon rates approved by the SCC for Roanoke and the PSC for Bluefield. The non-gas cost component of rates may not be changed without a formal rate increase application and corresponding authorization by the appropriate regulatory commission; however, the gas cost component of rates may be adjusted periodically through the PGA mechanism with approval from the respective commission. Roanoke also utilizes a WNA, which is designed to partially offset the impact of weather that is either more than approximately 6 percent warmer than normal or approximately 6 percent colder than normal over a 12 month period. The calculation of the WNA requires the use of estimates. Without the WNA, the Company’s operating revenues and gross margins would have been reduced by approximately $118,000 and $338,000 for the quarters ended March 31, 2007 and 2006, respectively.

RGC RESOURCES, INC. AND SUBSIDIARIES

ITEM 2 - MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 revenues of $2,895,636 and $1,565,727 at March 31, 2007 and September 30, 2006, respectively. Roanoke also accrues a provision for rate refund during periods in which it has implemented new billing rates pending the results of a final review and hearing on the increases by the SCC. The Company’s estimated refund provision is based upon historical experience, discussions with the SCC and other relevant factors.

Bad debt reserves – The Company evaluates the collectibility of its accounts receivable balances based upon a variety of factors including loss history, level of delinquent account balances and general economic climate.

Retirement plans – The Company offers a defined benefit pension plan (“pension plan”) and a postretirement medical and life insurance plan (“postretirement plan”) to eligible employees. The expenses and liabilities associated with these plans are determined through actuarial means requiring the use of estimates and assumptions. In regard to the pension plan, these factors include assumptions regarding discount rate, expected long-term rate of return on plan assets, compensation increases and life expectancies, among others. Similarly, the postretirement 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.

Derivatives – As discussed in the “Item 3 - Qualitative and Quantitative Disclosures about Market Risk” section below, the Company may hedge certain risks incurred in the normal operation of business through the use of derivative instruments. The Company applies the requirements of Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, which requires the recognition of all derivative instruments as assets or liabilities in the Company’s balance sheet at fair value. In most instances, fair value is based upon quoted futures prices for the 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.

Regulatory accounting – The Company’s regulated operations follow the accounting and reporting requirements of Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation. The economic effects of regulation can result in a regulated company deferring costs that have been or are expected to be recovered from

RGC RESOURCES, INC. AND SUBSIDIARIES

ITEM 2 - MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

customers in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this results, costs are deferred as assets in the consolidated balance sheet (regulatory assets) and recorded as expenses when such amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for the amounts previously collected from customers and for current collection in rates of costs that are expected to be incurred in the future (regulatory liabilities).

If any portion of the current regulated operations cease 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 within the consolidated statement of income for the period in which the discontinuance occurred.

Asset Management

Both Roanoke and Bluefield use a third party as an asset manager to manage their 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 both Roanoke and Bluefield a monthly utilization fee, which is used to reduce the cost of gas for their customers. The current agreements expire October 31, 2007.

Energy Costs

Natural gas prices remained stable during the quarter and NYMEX closing prices at March 31, 2007 were under $8.00 a decatherm. Quarter-end prices were slightly higher than the March 31, 2006 ending prices as the prior year recovered from the supply and pricing issues attributable to the hurricane damage to natural gas production facilities in August 2005. The forecast for 2007 predicts a very active hurricane season with an above average number of hurricanes to develop in the Atlantic. If these predictions prove accurate and if a hurricane makes its way into the Gulf of Mexico and strikes natural gas production facilities, natural gas prices could again experience sharp increases similar to the price spikes that occurred in late 2005.

In light of these issues, management believes that it has planned for adequate supplies to fulfill projected customer needs. The Company uses various hedging mechanisms, including summer storage injections and financial instruments, to mitigate volatility in energy prices.

Prudently incurred natural gas costs are fully recoverable under the present regulatory Purchased Gas Adjustment (PGA) mechanisms, and increases and decreases in the cost of gas are passed through to the Company’s customers. Although rising energy prices are recoverable through the PGA mechanism for the regulated operations, high energy prices may have a negative impact on earnings through increases in bad debt expense and higher interest costs because the delay in recovering higher gas costs requires borrowing to temporarily fund receivables from customers. The Company’s rate structure provides a level of protection against the impact that rising energy prices may have on bad debts and carrying costs of gas in storage by allowing for more timely recovery of these costs. However, the rate structure will not protect the Company from increased rate of bad debts or increases in interest rates.

RGC RESOURCES, INC. AND SUBSIDIARIES

ITEM 2 - MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Regulatory Affairs

On September 14, 2006, Roanoke filed an application with the Virginia 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 March 2007, Roanoke reached a stipulated agreement with the SCC staff for a rate award of $1,667,940. In April 2007, Roanoke received the final rate order approving the stipulated agreement. The Company has recorded a provision for rate refund including interest associated with the total billings in excess of the final approved rates. The refund is expected to be completed with the June billing cycle.

On October 3, 2006, Bluefield received a final order from the West Virginia PSC approving a rate increase of more than $300,000, based on normal weather. These new base rates were placed into effect on November 16, 2006. The final order moved the revenue calculations attributable to carrying cost associated with natural gas in storage and the gas cost portion of bad debts from a gas cost component to a non-gas component of rates included in the increase above. As a result, revenue to cover these costs will only be adjusted as a result of future non-gas rate filings and will not automatically be adjusted for the level and/or price on natural gas in storage, the price of natural gas included in bad debts or changes in interest rates. On January 4, 2007, Bluefield filed a new rate application with the West Virginia PSC for an increase in non-gas rates of approximately $450,000. Any rate increase associated with the filing is expected to become effective in November 2007.

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 composed of a combination of replacing aging bare steel and cast iron pipe with new plastic or coated steel pipe and expansion of its natural gas system to meet the demands of customer growth. Total capital expenditures from continuing operations were $3,420,291 and $3,356,760 for the six-month periods ended March 31, 2007 and 2006, respectively. The Company’s total capital budget for the current year is nearly $6,000,000. It is anticipated that future capital expenditures will be funded with the combination of operating cash flow, sale of Company equity securities through the Dividend Reinvestment and Stock Purchase Plan and issuance of debt.

The level of borrowing under the Company’s line-of-credit agreements can fluctuate significantly due to the time of the year, changes in the wholesale price of energy and weather outside the normal temperature ranges. As the wholesale price of natural gas increases, short-

RGC RESOURCES, INC. AND SUBSIDIARIES

ITEM 2 - MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

term debt generally increases because the payment to the Company’s energy suppliers is due before the Company can recover its costs through the monthly billing of its customers. In addition, colder weather requires the Company to purchase greater volumes of natural gas, the cost of which is recovered from customers on a delayed basis. As discussed under the “Results of Operations” section above, several factors combined to reduce borrowings under the lines-of-credit below both expected and historical levels. The continuation of these reduced levels of borrowing is not expected, and borrowing levels should return to higher levels next winter.

On March 20, 2007, the Company renewed its line-of-credit agreements. The new agreements maintain the same variable interest rates based upon 30-day LIBOR and continue the multi-tier level for borrowing limits to accommodate the Company’s seasonal borrowing demands. These lines-of-credit expire March 31, 2008, unless extended. The Company anticipates being able to extend or replace the lines-of-credit upon expiration.

Stockholders equity increased by $3,465,321 for the six months ended March 31, 2007, primarily due to earnings and proceeds from stock issued under the Dividend Reinvestment and Stock Purchase Plan (“DRIP”). The activity is summarized below:

Net income	$	4,278,219
Dividends		(1,316,697	)
DRIP		428,524
Restricted stock and stock options		109,775
Net comprehensive income		(34,500	)
Increase in stockholders’ equity	$	3,465,321

At March 31, 2007, the Company’s consolidated long-term capitalization was 59 percent equity and 41 percent debt.

RGC RESOURCES, INC. AND SUBSIDIARIES

ITEM 3 – QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is exposed to market risks associated with interest rates and commodity prices. Interest rate risk is related to the Company’s outstanding long-term and short-term debt. Commodity price risk is experienced by the Company’s regulated natural gas operations and energy marketing business. The Company’s risk management policy, as authorized by the Company’s Board of Directors, allows management to enter into derivatives for the purpose of managing commodity and financial market risks of its business operations.

Interest Rate Risk

The Company is exposed to market risk related to changes in interest rates associated with its borrowing activities. At March 31, 2007, the Company had $1,981,000 outstanding under its lines of credit at a weighted-average interest rate of 6.02% and $2,000,000 outstanding on an intermediate-term variable-rate note for Bluefield Gas. A hypothetical 100 basis point increase in market interest rates applicable to the Company’s variable rate debt during the period would have resulted in an increase in quarterly interest expense of approximately $19,000. The Company also has a $15,000,000 intermediate term variable rate note that is currently being hedged by a fixed rate interest swap. The balance of the long-term debt is at fixed rates.

Commodity Price Risk

The Company manages the price risk associated with purchases of natural gas by using a combination of fixed price contracts, gas storage injections and derivative commodity instruments including futures, price caps, swaps and collars. During the quarter, the Company used both storage gas and derivative swap arrangements for the purpose of hedging the price of natural gas. Under the Company’s regulated natural gas operations, any cost incurred or benefit received from the derivative arrangements is recoverable or refunded through the regulated natural gas purchased gas adjustment (PGA) mechanism. Both the Virginia SCC and the West Virginia PSC currently allow for full recovery of prudent costs associated with natural gas purchases, and any additional costs or benefits associated with the settlement of the derivative contract will be passed through to customers when realized. As of March 31, 2007, all natural gas derivative contracts had been settled.

ITEM 4 – CONTROLS AND PROCEDURES

Based on their evaluation of the Company’s disclosure controls and procedures (as defined by Rule 13a-15(e) under the Securities Exchange Act of 1934) as of March 31, 2007, the Company’s Chief Executive Officer and principal financial officer have concluded that these disclosure controls and procedures are effective. Management routinely reviews the Company’s internal controls over financial reporting and from time to time makes changes intended to enhance the effectiveness of internal controls over financial reporting. There has been no change during the quarter ended March 31, 2007, in the Company’s internal control over financial reporting or in other factors that has materially affected, or is reasonably likely to materially affect, this internal control over financial reporting.

RGC RESOURCES, INC. AND SUBSIDIARIES

Part II – Other Information

ITEM 2 – UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Pursuant to the RGC Resources Restricted Stock Plan for Outside Directors (the “Restricted Stock Plan”), 40% of the monthly retainer fee of each non-employee director of the Company is paid in shares of unregistered common stock and is subject to vesting and transferability restrictions (“restricted stock”). A participant can, subject to approval of Directors of the Company (the “Board”), elect to receive up to 100% of his retainer fee in restricted stock. The number of shares of restricted stock is calculated each month based on the closing sales price of the Company’s common stock on the Nasdaq-NMS on the first day of the month. The shares of restricted stock are issued in reliance on Section 3(a)(11) and Section 4(2) exemptions under the Securities Act of 1933 (the “Act”) and will vest only in the case of the participant’s death, disability, retirement or in the event of a change in control of the Company. Shares of restricted stock will be forfeited to the Company upon (i) the participant’s voluntary resignation during his term on the Board or (ii) removal for cause. During the quarter ended March 31, 2007, the Company issued a total of 812.934 shares of restricted stock pursuant to the Restricted Stock Plan as follows:

Investment Date	Price		Number of Shares
1/2/2007	$	25.350	277.944
2/1/2007	$	25.730	273.839
3/1/2007	$	26.980	261.151

On January 2 and March 1, 2007, the Company issued a total of 212.000 shares of its common stock to certain employees and management personnel as rewards for performance and service. The 212.000 shares were not issued in a transaction constituting a “sale” within the meaning of section 2(3) of the Act.

ITEM 4 – SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

On January 29, 2007, the Company held its Annual Meeting of Shareholders to elect three directors and to ratify the selection of independent auditors.

Shareholders elected all nominees for Class A directors as listed below to serve a three year term expiring at the Annual Meeting of Shareholders to be held in 2010.

Director	Shares For	Shares Withheld	Shares Not Voted
Abney S. Boxley, III	1,724,840	44,384	380,166
S. Frank Smith	1,759,572	9,652	380,166
John B. Williamson, III	1,757,872	11,352	380,166

RGC RESOURCES, INC. AND SUBSIDIARIES

J. Allen Layman, Nancy H. Agee and Raymond D. Smoot, Jr. continue to serve as Class B directors until the Annual Meeting of Shareholders to be held in 2008. Frank T. Ellett, Maryellen F. Goodlatte and George W. Logan continue to serve as Class C directors until the Annual Meeting of Shareholders to be held in 2009.

Shareholders approved the selection by the Board of Directors of the firm Brown Edwards & Company, LLP as independent auditors for the fiscal year ending September 30, 2007, by the following vote.

Shares For	Shares Against	Shares Abstaining	Shares Not Voted
1,757,676	5,161	6,387	380,166

ITEM 6 – EXHIBITS

Number	Description
10.1	Purchase and Sale Agreement by and between RGC Resources, Inc. as Seller and ANGD, LLC as Buyer dated February 16, 2007.
10.2	Asset Purchase and Sale Agreement by and between Roanoke Gas Company as Seller and Appalachian Natural Gas Distribution Company as Buyer dated February 16, 2007.
31.1	Rule 13a–14(a)/15d–14(a) Certification of Principal Executive Officer.
31.2	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer.
32.1	Section 1350 Certification of Principal Executive Officer.
32.2	Section 1350 Certification of Principal Financial Officer.

RGC RESOURCES, INC. AND SUBSIDIARIES

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned there unto duly authorized.

		RGC Resources, Inc.
Date: May 10, 2007	By:	/s/ Howard T. Lyon
		Howard T. Lyon
		Vice-President, Treasurer and Controller (Principal Financial Officer)