Edgar Filing: RGC RESOURCES INC

June 30, 2007

Previously
Reported

As Restated

Balance Sheet

Current deferred income taxes

Retained earnings

Amendment #1 to Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q/A

(Amendment No. 1)

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For Quarterly Period Ended June 30, 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, including 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 July 31, 2007
Common Stock, $5 Par Value		2,171,005

Explanatory Note

On October 16, 2007, RGC Resources, Inc. (the “Company”) concluded that it should amend and restate the Company’s quarterly report on Form 10-Q for the three months and nine months ended June 30, 2007. This Form 10-Q/A is being filed to correct the income tax expense estimate included in discontinued operations associated with the pending sale of Bluefield Gas Company (“Bluefield”) stock.

On February 16, 2007, Resources entered into a Purchase and Sale Agreement with ANGD, LLC for the sale of the capital stock of Bluefield at a sales price substantially equal to the book value of Bluefield’s net assets on the date of closing. At June 30, when these operations were reclassified as discontinued operations, the gain or loss on the sale of the stock and the corresponding estimate of income tax expense on the transaction were not deemed to be significant. During the Company’s subsequent year-end tax planning and review process, management determined that income tax expense included in discontinued operations may be understated by as much as $580,000 based on the current estimate of tax basis of the Bluefield stock. For further information, see Note 6 to the condensed financial statements.

The Company is filing this Form 10-Q/A, which amends and restates the condensed financial statements and other information of the Company, including Management’s Discussion and Analysis, and updates management’s evaluation of disclosure controls and procedures and internal control over financial reporting. All other information is unchanged and reflects the disclosures made at the time of the original filing. In addition, currently dated certifications from the Company’s Chief Executive Officer and Chief Financial Officer have been included as exhibits to this Form 10-Q/A.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

UNAUDITED


	June 30, 2007			September 30, 2006
	(As restated)
ASSETS
Current Assets:
Cash and cash equivalents	$	4,792,399		$	1,490,141
Accounts receivable - (less allowance for uncollectibles of $463,137 and $26,584, respectively)		4,834,605			4,558,458
Intercompany receivable		—			—
Materials and supplies		603,959			553,773
Gas in storage		15,392,402			19,932,064
Assets available for sale		11,927,386			13,726,791
Prepaid income taxes		761,213			879,957
Deferred income taxes		1,307,961			2,654,548
Fair value of marked to market transactions		423,887			—
Other		601,014			392,564

Total current assets		40,644,826			44,188,296

Utility Property:
In service		107,051,309			102,822,594
Accumulated depreciation and amortization		(36,447,270	)		(34,447,514	)

In service, net		70,604,039			68,375,080
Construction work in progress		1,402,580			1,702,416

Utility Plant, Net		72,006,619			70,077,496

Other assets		379,451			396,780

Total Assets	$	113,030,896		$	114,662,572

See notes to condensed consolidated financial statements.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

UNAUDITED


	June 30, 2007		September 30, 2006
	(As restated)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Borrowings under lines of credit	$	88,000	$	3,353,000
Dividends payable		662,156		643,067
Accounts payable		10,831,838		8,328,365
Customer credit balances		2,711,033		4,027,668
Income taxes payable		3,206		—
Customer deposits		1,481,320		1,245,508
Accrued expenses		3,402,619		3,484,476
Liabilities of assets available for sale		6,701,949		8,252,463
Over-recovery of gas costs		1,512,356		2,112,256
Fair value of marked to market transactions		—		1,486,699

Total current liabilities		27,394,477		32,933,502

Long-term Debt, Excluding Current Maturities		28,000,000		28,000,000

Deferred Credits and Other Liabilities:
Asset retirement obligations		2,484,543		2,404,839
Regulatory cost of retirement obligations		5,816,851		5,319,198
Deferred income taxes		5,563,673		5,351,746
Deferred investment tax credits		135,550		158,419

Total deferred credits and other liabilities		14,000,617		13,234,202

Stockholders’ Equity:
Common stock, $5 par value; authorized, 10,000,000 shares; issued and outstanding 2,170,138 and 2,138,595 shares, respectively		10,850,690		10,692,975
Preferred stock, no par, authorized, 5,000,000 shares; no shares issued and outstanding		—		—
Capital in excess of par value		15,162,925		14,521,812
Retained earnings		17,359,208		15,282,909
Accumulated other comprehensive income (loss)		262,979		(2,828	)

Total stockholders’ equity		43,635,802		40,494,868

Total Liabilities and Stockholders’ Equity	$	113,030,896	$	114,662,572

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

FOR THE THREE-MONTH AND NINE-MONTH PERIODS ENDED JUNE 30, 2007 AND 2006

UNAUDITED


	Three Months Ended June 30,						Nine Months Ended June 30,
	2007			2006			2007			2006
	(As restated)						(As restated)
Operating Revenues:
Gas utilities	$	15,001,023		$	11,258,506		$	78,648,958		$	82,856,760
Other		130,352			236,542			472,174			510,841

Total operating revenues		15,131,375			11,495,048			79,121,132			83,367,601

Cost of Sales:
Gas utilities		10,132,586			6,920,851			58,164,503			64,084,538
Other		51,511			186,733			225,801			298,439

Total cost of sales		10,184,097			7,107,584			58,390,304			64,382,977

Gross Margin		4,947,278			4,387,464			20,730,828			18,984,624

Other Operating Expenses:
Operations		2,530,592			2,407,054			7,983,804			7,851,331
Maintenance		341,989			293,743			924,091			929,531
General taxes		283,381			269,458			848,937			845,789
Depreciation and amortization		1,026,432			959,712			3,078,860			2,895,135

Total other operating expenses		4,182,394			3,929,967			12,835,692			12,521,786

Operating Income		764,884			457,497			7,895,136			6,462,838
Other Income, net		(71,292	)		(41,260	)		(72,606	)		(27,818	)
Interest Expense		458,679			448,393			1,465,524			1,547,036

Income from Continuing Operations Before Income Taxes		377,497			50,364			6,502,218			4,943,620
Income Tax Expense from Continuing Operations		140,977			24,237			2,468,010			1,888,328

Income from Continuing Operations		236,520			26,127			4,034,208			3,055,292
Discontinued operations:
Income (loss) from discontinued operations, net of income taxes of $650,317, ($58,254), $955,133 and $305,543, respectively		(459,586	)		(83,086	)		20,945			497,005

Net Income (Loss)		(223,066	)		(56,959	)		4,055,153			3,552,297
Other Comprehensive Income, net of tax		300,307			319,045			265,807			752,910

Comprehensive Income	$	77,241		$	262,086		$	4,320,960		$	4,305,207

Basic Earnings (Loss) Per Common Share:
Income from continuing operations	$	0.11		$	0.01		$	1.87		$	1.44
Discontinued operations		(0.21	)		(0.04	)		0.01			0.24

Net income (loss)	$	(0.10	)	$	(0.03	)	$	1.88		$	1.68

Diluted Earnings (Loss) Per Common Share:
Income from continuing operations	$	0.11		$	0.01		$	1.86		$	1.44
Discontinued operations		(0.21	)		(0.04	)		0.01			0.23

Net income (loss)	$	(0.10	)	$	(0.03	)	$	1.87		$	1.67

See notes to condensed consolidated financial statements.

RGC RESOURCES, INC. AND SUBSIDIARIES

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

ENDED JUNE 30, 2007 AND 2006

UNAUDITED


	Nine Months Ended June 30,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income from continuing operations	$	4,034,208		$	3,055,292
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation and amortization		3,248,629			3,058,422
Cost of removal of utility plant, net		(218,873	)		(174,097	)
Changes in assets and liabilities which provided cash, exclusive of changes and noncash transactions shown separately		5,909,101			8,707,528

Net cash provided by continuing operating activities		12,973,065			14,647,145
Net cash provided by discontinued operations		1,192,047			506,836

Net cash provided by operating activities		14,165,112			15,153,981


CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant and nonutility property		(4,557,706	)		(5,109,452	)
Proceeds from disposal of utility property		—			3,416

Net cash used in continuing investing activities		(4,557,706	)		(5,106,036	)
Net cash used in discontinued investing activities		(342,211	)		(378,959	)

Net cash used in investing activities		(4,899,917	)		(5,484,995	)


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		(3,265,000	)		(8,025,000	)
Proceeds from issuance of common stock		798,828			798,311
Cash dividends paid		(1,959,765	)		(1,888,427	)

Net cash used in continuing financing activities		(4,425,937	)		(5,115,116	)
Net cash used in discontinued financing activities		(1,537,000	)		(960,000	)

Net cash used in financing activities		(5,962,937	)		(6,075,116	)


NET INCREASE IN CASH AND CASH EQUIVALENTS		3,302,258			3,593,870

CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		1,490,141			1,349,518


CASH AND CASH EQUIVALENTS AT END OF YEAR	$	4,792,399		$	4,943,388


SUPPLEMENTAL INFORMATION:
Cash paid during the year for:
Interest	$	2,039,238		$	1,956,651
Income taxes net of refunds		1,952,794			1,897,415

See notes to condensed consolidated financial statements.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS UNAUDITED

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 June 30, 2007 and the results of its operations for the three months and nine months ended June 30, 2007 and 2006 and its cash flows for the nine months ended June 30, 2007 and 2006. The results of operations for the three months and nine months ended June 30, 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.

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 as discussed below, utility property, nonutility property, accrued expenses and refunds from suppliers-due customers.

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.

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 Gas”), a wholly owned subsidiary of Resources, to ANGD. The sales price will be 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 (or its designee) 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.

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

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS UNAUDITED

of Tazewell, Virginia, (“Bluefield division of Roanoke Gas Company”) to Appalachian, which is a wholly owned subsidiary of ANGD. 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 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.

Bluefield Gas and the Bluefield division of Roanoke Gas Company (“Bluefield Operations”) represent approximately 4,600 of Resources 60,200 customers and approximately $11,900,000 of the consolidated assets and $6,700,000 of the consolidated liabilities of the Company as reflected below.

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 operations in West Virginia are significantly disproportionate to the size of the operation. The regulatory environment in West Virginia 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 (“PSC”) for the sale of Bluefield Gas and the Virginia State Corporation Commission (“SCC”) 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 will close or neither will 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…” Although the Company has not received final approval for either transaction from the respective commissions, the Company has reached a stipulated agreement regarding the sales transaction and a pending request for increased non-gas rates with the West Virginia PSC staff and the West Virginia Consumer Advocate Division. Although an agreement has been reached with two of the key parties in the cases, final approval from the PSC is not assured; however, Company management does believe that such an agreement makes the ultimate approval of the sale probable. Furthermore, Company management believes that the SCC will likely approve the sale of the Bluefield division of Roanoke Gas Company. As a result, the Company believes that the pending sales transactions meet the definition of

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS UNAUDITED

probable as required by SFAS No. 144, and the results of operations of both Bluefield Gas and the Bluefield division of Roanoke Gas Company are reflected as 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 purchase price was deferred as realization of those revenues was subject to certain provisions. As these provisions had been achieved as of June 30, 2007, the Company recorded $160,000 revenue in final settlement of the sales contract as part of discontinued operations.

The components of discontinued operations from each of these transactions is reflected below:


	Three Months Ended June 30,						Nine Months Ended June 30,
	2007			2006			2007			2006
Bluefield Gas
Total Revenues	$	1,653,605		$	1,464,409		$	10,268,630		$	11,969,209

Gain on Sale of Assets		—			—			—			—
Pretax Operating Income		(179,427	)		(216,285	)		252,752			134,699
Continuing Costs		209,996			181,415			563,164			525,374
Income Tax Expense		(589,735	)		17,838			(894,551	)		(251,460	)

Discontinued Operations	$	(559,166	)	$	(17,032	)	$	(78,635	)	$	408,613

Highland Energy
Revenues	$	—		$	4,603,741		$	—		$	20,771,453

Gain on Sale of Assets		160,162			—			160,162			—
Pretax Operating Income		—			(125,599	)		—			94,227
Continuing Costs		—			19,129			—			48,248
Income Tax Expense		(60,582	)		40,416			(60,582	)		(54,083	)

Discontinued Operations	$	99,580		$	(66,054	)	$	99,580		$	88,392

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS UNAUDITED


Total
Revenues	$	1,653,605		$	6,068,150		$	10,268,630		$	32,740,662

Gain on Sale of Assets		160,162			—			160,162			—
Pretax Operating Income		(179,427	)		(341,884	)		252,752			228,926
Continuing Costs		209,996			200,544			563,164			573,622
Income Tax Expense		(650,317	)		58,254			(955,133	)		(305,543	)

Discontinued Operations	$	(459,586	)	$	(83,086	)	$	20,945		$	497,005

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


	June 30, 2007		September 30, 2006
Assets:
Accounts receivable	$	555,534	$	658,551
Gas in storage		2,204,948		3,399,639
Other current assets		47,801		619,862
Net utility plant		9,061,407		8,962,113
Other assets		57,696		86,626

Total assets	$	11,927,386	$	13,726,791

Liabilities:
Accounts payable	$	1,177,390	$	1,122,978
Accrued expenses		258,536		217,054
Other current liabilities		2,112,722		3,818,416
Non current liabilities		3,153,301		3,094,015

Total liabilities	$	6,701,949	$	8,252,463

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.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS UNAUDITED

As discussed above, on February 16, 2007, Resources entered into a Purchase and Sale Agreement with ANGD, LLC for the sale of the capital stock of Bluefield Gas at a sales price substantially equal to the book value of Bluefield’s net assets on the date of closing. At June 30, when these operations were reclassified as discontinued operations, the gain or loss on the sale of the stock and corresponding estimate of income tax expense on the transaction were not deemed to be significant. During the Company’s subsequent year end tax planning and review process, management determined that income tax expense included in discontinued operations may be understated by as much as $580,000 based on the current estimate of the tax basis of the Bluefield Gas stock.

The effects of this restatement on the Company’s balance sheet as of June 30, 2007 and statement of income for the three month and nine month periods then ended are summarized below:


	Three Months Ended June 30, 2007					Nine Months Ended June 30, 2007
	Previously Reported		As Restated			Previously Reported		As Restated
Statement of Income
Income from continuing operations	$	236,520	$	236,520		$	4,034,208	$	4,034,208
Discontinued operations		120,414		(459,586	)		600,945		20,945
Net Income (loss)		356,934		(223,066	)		4,635,153		4,055,153
Comprehensive income		657,241		77,241			4,900,960		4,320,960
Basic Earnings Per Common Share
Income from continuing operations	$	0.11	$	0.11		$	1.87	$	1.87
Discontinued operations		0.05		(0.21	)		0.28		0.01
Net Income		0.16		(0.10	)		2.15		1.88
Diluted Earnings Per Common Share
Income from continuing operations	$	0.11	$	0.11		$	1.86	$	1.86
Discontinued operations		0.05		(0.21	)		0.28		0.01
Net Income		0.16		(0.10	)		2.14		1.87

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS UNAUDITED

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) falls within the weather band, no adjustment is made. However, if the number of heating-degree days is below the weather band, the Company will add a surcharge to customer bills equal to the equivalent margin lost beyond the weather band deficiency. Conversely, if the number of heating-degree days is above the weather band, the Company will 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. The total 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 $439,000 in additional revenues in continuing operations during the first two quarters 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. Roanoke Gas Company received approval for the WNA rate factors to be used in billing the surcharge to its customers and the WNA tariff was billed during the May billing cycle. 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 statement for the nine-month period ended June 30, 2006 included approximately $316,000 in additional revenues attributable to the WNA.

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. The Company had settled all outstanding natural gas derivative arrangements in the prior quarter and had not entered into any new agreements during the current quarter.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS UNAUDITED

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 June 30, 2007	Interest Rate Swap			Minimum Pension Liability			Total
Unrealized gains	$	494,292		$	—		$	494,292
Income tax expense		(187,633	)		—			(187,633	)

Net unrealized gains		306,659			—			306,659
Transfer of realized gains to income		(10,238	)		—			(10,238	)
Income tax expense		3,886			—			3,886

Net transfer of realized losses to income		(6,352	)		—			(6,352	)
Net other comprehensive income	$	300,307		$	—		$	300,307

Three Months Ended June 30, 2006	Interest Rate Swap			Minimum Pension Liability			Total
Unrealized gains	$	315,566		$	196,227		$	511,793
Income tax expense		(119,789	)		(74,566	)		(194,355	)

Net unrealized gains		195,777			121,661			317,438
Transfer of realized losses to income		2,590			—			2,590
Income tax benefit		(983	)		—			(983	)

Net transfer of realized losses to income		1,607			—			1,607
Net other comprehensive income	$	197,384		$	121,661		$	319,045

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CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS UNAUDITED


Nine Months Ended June 30, 2007	Interest Rate Swap			Minimum Pension Liability			Total
Unrealized gains	$	459,265		$	—		$	459,265
Income tax expense		(174,337	)		—			(174,337	)

Net unrealized gains		284,928			—			284,928
Transfer of realized losses to income		(30,819	)		—			(30,819	)
Income tax benefit		11,698			—			11,698

Net transfer of realized losses to income		(19,121	)		—			(19,121	)
Net other comprehensive income	$	265,807		$	—		$	265,807
Fair value of marked to market transactions	$	423,887			—		$	423,887
Accumulated comprehensive income	$	262,979			—		$	262,979

Nine Months Ended June 30, 2006	Interest Rate Swap			Minimum Pension Liability			Total
Unrealized gains	$	602,555		$	588,681		$	1,191,236
Income tax expense		(228,730	)		(223,699	)		(452,429	)

Net unrealized gains		373,825			364,982			738,807
Transfer of realized losses to income		22,731			—			22,731
Income tax benefit		(8,628	)		—			(8,628	)

Net transfer of realized losses to income		14,103			—			14,103
Net other comprehensive income	$	387,928		$	364,982		$	752,910
Fair value of marked to market transactions	$	638,892			—		$	638,892
Accumulated comprehensive income (loss)	$	396,369			(23,930	)	$	372,439

Basic earnings per common share for the three months and nine months ended June 30, 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 nine months ended June 30, 2007 and 2006 are calculated by dividing net income by the weighted average common shares outstanding during the period plus dilutive potential common shares. Dilutive potential common shares are calculated in accordance with the treasury stock method, which assumes that proceeds from the exercise of all options are used

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS UNAUDITED

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 June 30,		Nine Months Ended June 30,
	2007	2006	2007	2006
Weighted average common shares	2,167,655	2,127,188	2,157,712	2,115,060
Effect of dilutive securities:
Options to purchase common stock	—	—	10,452	10,455

Diluted average common shares	2,167,655	2,127,188	2,168,164	2,125,515

10.

The Company has both a defined benefit pension plan (the “pension plan”) and a post- retirement benefit 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 June 30,						Nine Months Ended June 30,
	2007			2006			2007			2006
Components of net periodic pension cost:
Service cost	$	101,227		$	119,320		$	303,681		$	357,960
Interest cost		185,228			173,896			555,684			521,688
Expected return on plan assets		(172,816	)		(157,068	)		(518,448	)		(471,204	)
Recognized (gain) loss		18,050			60,077			54,150			180,231

Net periodic pension cost	$	131,689		$	196,225		$	395,067		$	588,675

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CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS UNAUDITED


	Three Months Ended June 30,						Nine Months Ended June 30,
	2007			2006			2007			2006
Components of post-retirement benefit cost:
Service cost	$	36,923		$	39,621		$	110,769		$	124,922
Interest cost		125,461			116,673			376,383			364,694
Expected return on plan assets		(59,724	)		(52,842	)		(179,172	)		(162,185	)
Amortization of unrecognized transition obligation		47,223			46,119			141,669			154,878
Recognized loss		2,472			18,153			7,416			60,818

Net post-retirement benefit cost	$	152,355		$	167,724		$	457,065		$	543,127

The Company contributed $600,000 to its pension plan for the nine-month period ended June 30, 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.

11.

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 late 1940s or early 1950s. 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 right of Bluefield Gas Company 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 Company to ANGD, LLC, and retaining ownership of the former MPG site, an indemnification and cost sharing agreement that is part of the sales agreement obligates Bluefield Gas Company to seek rate recovery of any remediation costs not recovered through other means and to share in any such costs to the extent they are not recovered through rates. The former Bluefield Gas Company MPG site is currently in active use as a propane bulk storage and distribution facility under lease to a propane distributor. If the Company eventually incurs costs associated with a required clean-up of the Roanoke Gas Company MGP site, the Company anticipates recording a regulatory asset for such clean-up costs to be

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CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS UNAUDITED

recovered in future rates. Based on anticipated regulatory actions and current practices, management believes that any costs incurred related to this matter will not have a material effect on the Company’s financial condition or results of operations.

12.

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 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

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CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS UNAUDITED

as of June 30, 2006, the effect on the June 30, 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.

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 by Bluefield Gas Company within the state of West Virginia, all such taxes encompassed by this EITF are recorded at net and not gross. As discussed above, the Bluefield Gas operations have been reclassified to discontinued operations.

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.

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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.

The three-month and nine-month earnings presented herein should not be considered as reflective of the Company’s consolidated financial results for the fiscal year ending September

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

30, 2007. The total revenues and margins realized during the first nine 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.

Overview

Resources is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately 60,200 residential, commercial and industrial customers in Roanoke, Virginia and Bluefield, Virginia and West Virginia and the surrounding areas through its Roanoke Gas Company (“Roanoke Gas”) and Bluefield Gas Company (“Bluefield Gas”) 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.

On February 16, 2007, Resources entered into a Purchase and Sale Agreement with 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’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. Resources management believes that both of these agreements will be approved by the respective commissions and the sale will be completed. As such, these two operations have been reclassified as discontinued operations. See “Discontinued Operations” section below and Note 5 for more information on these transactions.

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 SCC authorizes billing rates for 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. 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

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

(“WNA”) factor as part of Roanoke Gas’ 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 $439,000 in additional revenues for the nine-month period ended June 30, 2007. In the prior fiscal year, the Company recorded approximately $316,000 in additional revenues for the nine-month period ended June 30, 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 lead to a higher level of bad debts due to 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 current year, 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 stabilized. 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 significant damage to natural gas production facilities.

Results of Operations

Consolidated net income (loss) from continuing and discontinued operations is as follows:


	Three Months Ended June 30,						Nine Months Ended June 30,
	2007			2006			2007		2006
Net Income
Continuing Operations	$	236,520		$	26,127		$	4,034,208	$	3,055,292
Discontinued Operations		(459,586	)		(83,086	)		20,945		497,005

Net Income (Loss)	$	(223,066	)	$	(56,959	)	$	4,055,153	$	3,552,297

RGC RESOURCES, INC. AND SUBSIDIARIES

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

Continuing Operations

Three Months Ended June 30, 2007:

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


	Three Months Ended June 30,		Increase/ (Decrease)		Percentage
	2007	2006	Increase/ (Decrease)		Percentage
Delivered Volumes
Regulated Natural Gas (DTH)
Tariff Sales	995,678	861,186	134,492		16	%
Transportation	623,258	652,665	(29,407	)	-5	%

Total	1,618,936	1,513,851	105,085		7	%
Heating Degree Days (Unofficial)	384	279	105		38	%

The table below reflects operating revenues.


	Three Months Ended June 30,				Increase/ (Decrease)			Percentage
	2007		2006		Increase/ (Decrease)			Percentage
Operating Revenues
Gas Utilities	$	15,001,023	$	11,258,506	$	3,742,517		33	%
Other		130,352		236,542		(106,190	)	-45	%

Total Operating Revenues	$	15,131,375	$	11,495,048	$	3,636,327		32	%

Total operating revenues from continuing operations for the three months ended June 30, 2007 compared to the same period last year increased due to higher natural gas commodity prices, increased sales volumes due to a colder spring and the implementation of a non-gas cost rate increase in October. The total average unit cost of natural gas for the quarter increased by more than 26 percent compared to the same period last year. Total regulated natural gas delivered volumes increased by 7 percent as the total number of heating degree-days increased by 105, or 38 percent, from the same period last year. Other revenues declined due to the services provided under the Company’s master meter services program last year.

RGC RESOURCES, INC. AND SUBSIDIARIES

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


	Three Months Ended June 30,				Increase/ (Decrease)		Percentage
	2007		2006		Increase/ (Decrease)		Percentage
Gross Margin
Gas Utilities	$	4,868,437	$	4,337,655	$	530,782	12	%
Other		78,841		49,809		29,032	58	%

Total Gross Margin	$	4,947,278	$	4,387,464	$	559,814	13	%

Regulated natural gas margins from gas utilities increased due to a 7 percent increase in total delivered natural gas volumes (both tariff and transporting) and the implementation of a non-gas cost rate increase. 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 38 percent while total tariff volumes (most of which are weather dependent) increased by 16 percent. The relationship between heating degree-days and sales volumes is not high during the spring months as it is during the winter months due to the much greater proportion of base load volumes (non weather sensitive sales) to total volumes in the spring and summer as compared to the winter months. In addition, Roanoke 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. See Regulatory Affairs section for more information regarding the rate award. As a result of these rate awards and the increase in total natural gas deliveries, the Company realized approximately $127,000 in additional margin from customer base charges, which is a flat monthly fee billed to each natural gas customer, and approximately $431,000 associated with increase in the volumetric margin of natural gas. Carrying cost revenues, as explained below, decreased by approximately $45,000 due to lower average investment in natural gas storage during the period. The components of the gas utility margin increase are summarized below:

Net Margin Increase


Customer Base Charge including rate increase	$	127,418
WNA		22,862
Carrying Cost		(44,920	)
Volumetric (rate and volume increase)		430,539
Other		(5,117	)

Total	$	530,782

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.

RGC RESOURCES, INC. AND SUBSIDIARIES

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

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. Other margins increased over last year primarily due to billings related to temporary work performed in the unregulated operations of Roanoke Gas.

Operations expenses increased by $123,538, or 5 percent, compared to the same period last year. Increases in operations labor and contractor expenses combined with lower capitalized overheads more than offset reductions in bad debt expense and employee benefit costs. Operations labor and contractor expenses increased by $320,000 due to a focus on various operations tasks including the timing of distribution pipeline leak survey work, salary increases, network support functions and performance accruals. The Company also reduced the level of capital activity resulting in a $51,000 reduction of capitalized overheads. Bad debt expense declined by $119,000 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 $70,000 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 balance of the difference is attributable to small reductions in other expenses. Maintenance expenses increased $48,246, or 16 percent, from the same period last year. The increase in maintenance primarily relates to timing of repairs of pipeline leaks in the Company’s distribution system determined through leak surveys.

General taxes increased by $13,923, or 5 percent, due to higher payroll and property taxes. Depreciation expense increased $66,720, or 7 percent, on a corresponding increase in utility plant associated with extending service to new customers and replacing cast iron and bare steel pipe. Other income, net increased by $30,032 due to a higher level of investment earnings.

Interest expense increased by $10,286, or 2 percent, primarily due to increased level of customer deposits and a higher deposit interest rate as annually reset by the SCC. Declines in borrowings under the Company’s line-of-credit arrangements offset the impact of higher interest rates on the variable rate debt. The overall average borrowing requirements for the quarter were nearly unchanged from the same period last year, declining by $80,000, while the effective average interest rate on the Company’s line-of-credit increased from 5.6 percent last year to 6.0 percent for the current period.

Income tax expense increased by $116,740, which corresponds to the increase in pre-tax income on continuing operations for the quarter.

RGC RESOURCES, INC. AND SUBSIDIARIES

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

Nine Months Ended June 30, 2007:

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


	Nine Months Ended June 30,		Increase/ (Decrease)		Percentage
	2007	2006	Increase/ (Decrease)		Percentage
Delivered Volumes
Regulated Natural Gas (DTH)
Tariff Sales	6,242,356	6,052,889	189,467		3	%
Transportation	2,148,347	2,227,196	(78,849	)	-4	%

Total	8,390,703	8,280,085	110,618		1	%
Heating Degree Days (Unofficial)	3,714	3,649	65		2	%

The table below reflects operating revenues.


	Nine Months Ended June 30,				Increase/ (Decrease)			Percentage
	2007		2006		Increase/ (Decrease)			Percentage
Operating Revenues
Gas Utilities	$	78,648,958	$	82,856,760	$	(4,207,802	)	-5	%
Other		472,174		510,841		(38,667	)	-8	%

Total Operating Revenues	$	79,121,132	$	83,367,601	$	(4,246,469	)	-5	%

Total operating revenues from continuing operations for the nine months ended June 30, 2007 compared to the same period last year decreased due to lower gas costs in the first quarter, partially offset by the implementation of non-gas cost rate increases and higher level of natural gas sales. Although total tariff sales of the gas utilities increased slightly by 3 percent, the average unit cost of natural gas delivered to customers decreased for the period by 12 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 decreased by 8 percent due to the reduction in services provided under the Company’s master meter services program last year.

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


	Nine Months Ended June 30,				Increase/ (Decrease)		Percentage
	2007		2006		Increase/ (Decrease)		Percentage
Gross Margin
Gas Utilities	$	20,484,455	$	18,772,222	$	1,712,233	9	%
Other		246,373		212,402		33,971	16	%

Total Gross Margin	$	20,730,828	$	18,984,624	$	1,746,204	9	%

Regulated natural gas margins increased even though total delivered volume (tariff and transporting) remained virtually unchanged from last year’s volumes. A majority of the increase is attributable to the implementation of non-gas cost rate increases and to a much lesser extent, a 3 percent increase in the higher margin tariff sales and a greater level of WNA revenues. The components of the regulated margin increase are summarized below:

Net Margin Increase


Customer Base Charge including rate increase	$	360,346
WNA		122,882
Carrying Cost		(75,808	)
Volumetric (rate and volume increase)		1,312,671
Other		(7,858	)

Total	$	1,712,233

Operations expenses increased by $132,473, or 2 percent, for the nine-month period ended June 30, 2007 compared to the same period last year. Increases in audit fees, contracted services and operations labor more than offset reductions in bad debt expense and employee benefit expenses. Audit fees increased by $54,000 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 statements. Contract services and labor increased approximately $525,000 related to timing of distribution pipeline leak surveys, network support services, other operations projects, salary increases and performance accruals. Bad debt expense declined by $252,000 due to strong collection efforts and improved aging due to the warm heating season and lower energy prices. Employee benefit expenses decreased by $234,000 due to reductions in pension and other post employment benefit costs. Maintenance expenses remained consistent with the same period last year, decreasing by $5,440, or 1 percent.

General taxes remained nearly unchanged for the nine-month period ended June 30, 2007 compared to the same period last year. Increases in property taxes offset reductions in payroll taxes resulting in a net increase in general taxes of $3,148, or less than 1 percent change.

RGC RESOURCES, INC. AND SUBSIDIARIES

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

Depreciation expense increased $183,725, 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. Other income, net, increased $44,788 due to a higher level of investment earnings associated with reduced borrowing requirements during the spring and early summer.

Interest expense decreased by $81,512, or 5 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 and improved earnings all contributed to reducing the overall average borrowing requirements for the quarter by nearly $3,700,000, while the effective average interest rate on the Company’s line-of-credit increased from 4.9 percent last year to 5.8 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 anticipates borrowings under its line-of-credit agreements will return to higher levels next year.

Income tax expense increased $579,682, or 31 percent, which corresponds to the rise in pre-tax income on continuing operations. The effective tax rate was 38.0 percent compared to 38.2 percent for the same period last year.

Discontinued Operations

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 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 customers are represented by these sale agreements. The sales price of the Virginia 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 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. Estimated net proceeds from both agreements will be approximately $5,200,000 less the $1,300,000 promissory note received. The Company anticipates using the proceeds from both sales to reduce debt and provide additional capital investment for Roanoke Gas.

The Board of Directors approved the Purchase and Sale Agreements of Bluefield Gas and the Bluefield division of Roanoke Gas for several reasons. The management time and effort

RGC RESOURCES, INC. AND SUBSIDIARIES

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

required to oversee operations in West Virginia are significantly disproportionate to the size of the operation. The regulatory environment in West Virginia hindered the Company’s 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 Gas’ operations and ultimately provide a better return for the Company than could be realized in the Bluefield Gas 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 Gas 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 Gas will provide certain customer billing, gas control, regulatory and administrative services for 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.

If both commissions approve the proposed transaction and the agreements are executed, the sale of Bluefield Gas and the Bluefield Division of Roanoke Gas could result in lower earnings for Resources in the near term. Even though the combined annual losses 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 Gas that will be retained by the Company. A portion of these retained costs will be recovered under the services agreement with ANGD discussed above. In addition, the 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 Bluefield’s net loss 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.

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 as realization of those revenues was subject to certain provisions.

RGC RESOURCES, INC. AND SUBSIDIARIES

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

As these provisions had been met as of June 30, 2007, the Company recorded $160,000 revenue as part of discontinued operations in final settlement of the sales contract. The Company expects to receive payment in August 2007.

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 $439,000 and $316,000 for the nine-month periods ended June 30, 2007 and 2006, respectively.

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 $1,278,635 and $1,462,878 at June 30, 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.

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

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 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 ceases 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.

RGC RESOURCES, INC. AND SUBSIDIARIES

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

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. The Company is currently in the process of reviewing proposals for a new three-year asset management agreement to begin in November 2007.

Energy Costs

Natural gas prices were relatively stable with commodity prices between $7.50 and $8.00 per decatherm for much of the quarter. Prices dropped near the end of the quarter with the NYMEX (New York Mercantile Exchange) closing price at June 30, 2007 under $7.00 a decatherm with prices falling to below $6.00 a decatherm in July. The lack of tropical storm and hurricane activity has been a contributing factor for the reduction in natural gas prices. However, the forecast for 2007 continues to predict 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.

Management believes that it has planned for adequate supplies to fulfill projected customer needs. In addition, 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.

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,

RGC RESOURCES, INC. AND SUBSIDIARIES

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

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. In June 2007, the Company completed the refunding of approximately $53,000 in billings and interest for billings in excess of the final approved rates.

On January 4, 2007, Bluefield filed a new rate application with the PSC for an increase in non-gas rates of approximately $456,000. On February 20, 2007, Bluefield Gas and ANGD filed a Joint Petition for Consent and Approval of the Purchase of the Common Stock of Bluefield Gas Company (“Joint Petition”) requesting the PSC’s consent and approval of the sale of Bluefield Gas stock. On May 10, 2007, the Administrative Law Judge issued a Procedural Order consolidating the cases and establishing a public comment hearing on June 26, 2007 and an evidentiary hearing on July 6, 2007. Prior to the public comment hearing, representatives from Bluefield Gas, ANGD, PSC staff, City of Bluefield and the Consumer Advocate Division of West Virginia (“CAD”) met to discuss settlement negotiations for the combined case. On July 6, 2007, the evidentiary hearing was held in Bluefield and a Stipulation dated July 6, 2007 was submitted and signed by representatives of Bluefield Gas, ANGD, PSC staff and the CAD and set forth several conditions for the sale. The Stipulation provided for a non-gas rate increase providing for additional annual revenues of $323,853 if the sale is not approved and a non-gas rate increase providing for additional annual revenues of $176,242 if the sale is approved. The increased rates would be effective for service rendered on or after November 1, 2007. The Administrative Law Judge’s report is due September 18, 2007.

Simultaneous with the Bluefield Gas filing on February 20, 2007, Roanoke Gas and Appalachian filed a request with the SCC for approval of the transfer of certain assets located in Bluefield, Virginia. The only other party to this proceeding was the SCC; and, on July 23, 2007, the SCC staff issued a report supporting the transfer of those assets. A final decision from the SCC is expected in early fall.

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 $4,557,706 and $5,109,452 for the nine-month periods ended June 30, 2007 and 2006, respectively. Roanoke Gas’ total capital budget for the current year is more than $5,500,000. 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

RGC RESOURCES, INC. AND SUBSIDIARIES

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

outside the normal temperature ranges. As the wholesale price of natural gas increases, short-term debt generally increases because the payment to the Company’s energy suppliers is due before the Company can recover its costs through the monthly billing of its customers. In addition, colder weather requires the Company to purchase greater volumes of natural gas, the cost of which is recovered from customers on a delayed basis. 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. Effective with the execution of the new agreements, the Company’s total available limits under the lines-of-credit including Bluefield Gas which will be terminated at closing are as follows:


Beginning	Total Available Line of Credit		Bluefield Gas Line of Credit		Continuing Operations
April 1, 2007	$	10,000,000	$	4,000,000	$	6,000,000
July 16, 2007		15,000,000		4,000,000		11,000,000
September 16, 2007		23,000,000		6,000,000		17,000,000
November 16, 2007		27,000,000		6,000,000		21,000,000
February 16, 2008		22,000,000		6,000,000		16,000,000

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.

At June 30, 2007, the Company’s consolidated long-term capitalization was 61 percent equity and 39 percent debt exclusive of Bluefield Gas’ $2,000,000 note classified as liabilities of assets available for sale.

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 $88,000 outstanding under its lines of credit from continuing operations at a weighted-average interest rate of 6.02%. Included in the liabilities of assets available for sale are $1,723,000 in lines-of-credit balance 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 would have resulted in an increase in the nine month interest expense from continuing operations of approximately $19,000. The impact on interest expense for the three month period ended June 30, 2007 would have been negligible. 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 did not use or enter into any derivative arrangements for the purpose of hedging the price of natural gas. However, 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. 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 derivative contracts will be passed through to customers when realized. As of June 30, 2007, all natural gas derivative contracts had been settled.

ITEM 4 – CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

In connection with the original filing of the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2007, Company management including the Chief Executive Officer and the Chief Financial Officer evaluated the effectiveness of the Company’s disclosure controls and procedures as of June 30, 2007 as defined by Rule 13a-15(e) under the Securities

RGC RESOURCES, INC. AND SUBSIDIARIES

Act of 1934, as amended. Based on that evaluation, the Company’s Chief Executive Officer and Chief Financial Officer concluded that the disclosure controls and procedures were effective.

As a result of the restatement of the financial statements included in this Form 10-Q/A discussed in Note 6, Company management including the Chief Executive Officer and the Chief Financial Officer reevaluated the effectiveness of the Company’s disclosure controls and procedures. The subsequent evaluation resulted in the identification of a material weakness in internal controls over financial reporting. A material weakness is defined in Section 210.1-02(4) of Regulation S-X as a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. As a result of the material weakness discussed below, management concluded, based on their reevaluation, that as of the end of the period covered by this report, the Company’s disclosure controls and procedures were not effective.

Material Weakness

In connection with the restatement described above, Company management including the Chief Executive Officer and Chief Financial Officer determined that the Company had a material weakness related to the timely evaluation of the income tax consequences or benefits of material non-routine transactions as more fully discussed in Note 6. Although the error was identified by management in connection with other control processes, it was not discovered in sufficient time for the impact to be timely reported in the original filing of Form 10-Q for the quarter ended June 30, 2007.

Changes in Internal Control over Financial Reporting and Plan of Remediation

There has been no change during the quarter ended June 30, 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, the internal control over financial reporting. In regards to the identified material weakness in internal control, the Company has initiated remediation measures that include a more formal evaluation of the income tax implications of material non-routine transactions.

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 June 30, 2007, the Company issued a total of 763.176 shares of restricted stock pursuant to the Restricted Stock Plan as follows:


Investment Date	Price		Number of Shares
4/2/2007	$	28.000	251.637
5/1/2007	$	28.010	251.548
6/1/2007	$	27.100	259.991

On April 2, 2007, the Company issued a total of 2,250.000 shares of its common stock as bonuses to certain employees and management personnel as rewards for performance and service. The 2,250.000 shares were not issued in a transaction constituting a “sale” within the meaning of section 2(3) of the Act.

ITEM 6 – EXHIBITS


Number		Description
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: October 19, 2007	By:	/s/ Howard T. Lyon
	Howard T. Lyon
	Vice-President, Treasurer and Controller
	(Principal Financial Officer)