Form 10-Q

10-Q 1 d10q.htm FORM 10-Q Form 10-Q

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

QUARTERLY REPORT UNDER SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For Quarter Ended June 30, 2005

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 the number of shares outstanding of each of the issuer’s classes of common stock, as of the close of the period covered by this report.


Class		Outstanding at June 30, 2005
Common Stock, $5 Par Value		2,088,219

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

UNAUDITED


	June 30, 2005			September 30, 2004
ASSETS

Current Assets:
Cash and cash equivalents	$	1,837,570		$	9,461,217
Short-term investments		—			4,991,460
Accounts receivable - (less allowance for uncollectibles of $872,895 and and $38,525, respectively)		7,746,360			5,978,065
Materials and supplies		697,576			731,225
Gas in storage		17,037,342			1,739,024
Prepaid gas service		—			15,923,177
Prepaid income taxes		—			2,278,361
Deferred income taxes		2,830,067			1,818,280
Under-recovery of gas costs		375,876			580,166
Fair value of marked to market transactions		14,639			—
Other		530,118			306,966

Total current assets		31,069,548			43,807,941

Property, Plant And Equipment:
Utility plant in service		106,481,870			102,086,697
Accumulated depreciation and amortization		(34,952,766	)		(34,493,087	)

Utility plant in service, net		71,529,104			67,593,610
Construction work-in-progress		1,363,245			2,405,107

Utility Plant, net		72,892,349			69,998,717

Nonutility property		22,762			794,013
Accumulated depreciation and amortization		(16,269	)		(184,624	)

Nonutility property, net		6,493			609,389

Total property, plant and equipment		72,898,842			70,608,106

Other assets		445,261			556,509

Total Assets	$	104,413,651		$	114,972,556

See notes to condensed consolidated financial statements.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

UNAUDITED


	June 30, 2005		September 30, 2004
LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities:
Current maturities of long-term debt	$	10,000,000	$	19,987
Borrowings under lines of credit		2,596,000		12,742,000
Dividends payable		616,278		9,903,993
Accounts payable		13,984,943		10,740,943
Income taxes payable		488,724		—
Customer deposits		947,919		712,892
Accrued expenses		4,122,912		4,356,680
Refunds from suppliers - due customers		5,195		22,292
Overrecovery of gas costs		4,051,857		2,174,313
Fair value of marked to market transactions		—		73,356

Total current liabilities		36,813,828		40,746,456

Long-term Debt, Excluding Current Maturities		16,000,000		26,000,000

Deferred Credits:
Asset retirement obligations		6,774,496		6,197,549
Deferred income taxes		5,293,798		5,174,829
Deferred investment tax credits		207,324		232,200

Total deferred credits		12,275,618		11,604,578

Stockholders’ Equity:
Common stock, $5 par value; authorized, 10,000,000 shares; issued and outstanding 2,088,219 and 2,065,408 shares, respectively		10,441,095		10,327,040
Preferred stock, no par, authorized, 5,000,000 shares; 0 shares issued and outstanding in 2005 and 2004		—		—
Capital in excess of par value		13,519,956		13,064,566
Retained earnings		15,354,072		13,275,426
Accumulated comprehensive income (loss)		9,082		(45,510	)

Total stockholders’ equity		39,324,205		36,621,522

Total Liabilities and Stockholders’ Equity	$	104,413,651	$	114,972,556

See notes to condensed consolidated financial statements.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

FOR THE THREE-MONTH AND NINE-MONTH PERIODS ENDED JUNE 30, 2005 AND 2004

UNAUDITED


	Three Months Ended June 30,					Nine Months Ended June 30,
	2005		2004			2005			2004
Operating Revenues:
Gas utilities	$	15,637,845	$	13,610,639		$	81,947,596		$	73,340,547
Energy marketing		5,018,639		4,564,126			16,196,375			14,214,447
Other		181,869		58,713			663,281			267,426

Total operating revenues		20,838,353		18,233,478			98,807,252			87,822,420

Cost of Sales:
Gas utilities		10,856,512		9,304,687			61,910,976			54,343,286
Energy marketing		4,955,024		4,507,026			15,868,274			14,019,257
Other		38,698		19,002			269,054			110,562

Total cost of sales		15,850,234		13,830,715			78,048,304			68,473,105

Gross Margin		4,988,119		4,402,763			20,758,948			19,349,315

Other Operating Expenses:
Operations		2,602,906		2,699,193			7,861,944			8,270,350
Maintenance		359,396		387,673			996,903			1,041,432
General taxes		347,839		334,776			1,204,505			1,200,912
Depreciation and amortization		979,946		969,591			3,018,588			2,931,691

Total other operating expenses		4,290,087		4,391,233			13,081,940			13,444,385

Operating Income		698,032		11,530			7,677,008			5,904,930

Other Expenses (Income), net		21,999		(14,677	)		(8,818	)		26,847

Interest Expense		465,107		439,166			1,530,557			1,417,419

Income (Loss) from Continuing Operations Before Income Taxes		210,926		(412,959	)		6,155,269			4,460,664

Income Tax Expense (Benefit) from Continuing Operations		84,155		(137,216	)		2,355,603			1,717,423

Income (Loss) from Continuing Operations		126,771		(275,743	)		3,799,666			2,743,241

Discontinued operations:
Income (loss) from discontinued operations, net of income taxes of $63,515, ($152,792), $73,540 and $932,886, respectively		102,754		(236,921	)		118,973			1,491,750

Net Income (Loss)	$	229,525	$	(512,664	)	$	3,918,639		$	4,234,991

Basic Earnings (Loss) Per Common Share:
Income from continuing operations	$	0.06	$	(0.13	)	$	1.83		$	1.36
Discontinued operations		0.05		(0.12	)		0.06			0.74

Net income (loss)	$	0.11	$	(0.25	)	$	1.89		$	2.10

Diluted Earnings (Loss) Per Common Share:
Income from continuing operations	$	0.06	$	(0.13	)	$	1.82		$	1.35
Discontinued operations		0.05		(0.12	)		0.06			0.73

Net income (loss)	$	0.11	$	(0.25	)	$	1.88		$	2.08

See notes to condensed consolidated financial statements.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

FOR THE THREE-MONTH AND NINE-MONTH PERIODS ENDED JUNE 30, 2005 AND 2004

UNAUDITED


	Three Months Ended June 30,						Nine Months Ended June 30,
	2005			2004			2005		2004
Net Income	$	229,525		$	(512,664	)	$	3,918,639	$	4,234,991

Reclassification of loss transferred to net income		2,029			26,013			24,272		16,717

Unrealized (loss) gain on cash flow hedges		(1,134	)		63,929			30,320		92,102

Other comprehensive income, net of tax		895			89,942			54,592		108,819

Comprehensive Income (Loss)	$	230,420		$	(422,722	)	$	3,973,231	$	4,343,810

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, 2005 AND 2004

UNAUDITED


	Nine Months Ended June 30,
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income from continuing operations	$	3,799,666		$	2,743,241
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation and amortization		3,219,439			3,114,905
Cost of removal of utility plant		(222,174	)		(78,238	)
Loss on disposal of property		29,820			—
Changes in assets and liabilities which provided cash, exclusive of changes and noncash transactions shown separately		5,904,294			9,689,796

Net cash provided by continuing operating activities		12,731,045			15,469,704
Net cash provided by (used in) discontinued operations		(34,174	)		2,743,967

Net cash provided by operating activities		12,696,871			18,213,671

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant and nonutility property		(5,406,850	)		(5,288,047	)
Proceeds from disposal of equipment		87,412			27,661
Sale of short-term investments		4,991,460			—

Net cash flows used in continuing investing activities		(327,978	)		(5,260,386	)
Net cash provided by (used in) investing activities of discontinued operations		731,711			(863,181	)

Net cash provided by (used in) investing activities		403,733			(6,123,567	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		—			2,000,000
Retirement of long-term debt and capital leases		(19,987	)		(2,149,060	)
Net repayments under lines of credit		(10,146,000	)		(10,935,000	)
Cash dividends paid		(11,127,709	)		(1,744,013	)
Proceeds from issuance of stock		569,445			721,305

Net cash used in financing activities		(20,724,251	)		(12,106,768	)

NET DECREASE IN CASH AND CASH EQUIVALENTS		(7,623,647	)		(16,664	)

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		9,461,217			135,998

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	1,837,570		$	119,334

SUPPLEMENTAL INFORMATION:
Interest paid	$	1,644,286		$	1,736,335
Income taxes paid, net		613,157			1,922,991

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 necessary to present fairly RGC Resources, Inc.’s financial position as of June 30, 2005 and the results of its operations for the three months and nine months ended June 30, 2005 and 2004 and its cash flows for the nine months ended June 30, 2005. Because of seasonal and other factors, the results of operations for the three months and nine months ended June 30, 2005 are not indicative of the results to be expected for the fiscal year ending September 30, 2005. Quarterly earnings are affected by the highly seasonal nature of the business as variations in weather conditions generally result in greater earnings during the winter months.

The condensed consolidated 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 gas in storage.

In 2003, Roanoke Gas Company received regulatory approval to implement a weather normalization adjustment (“WNA”) factor 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 fell within approximately 6 percent above or below the 30-year average, no adjustments would be made. However, if the number of heating-degree days were more than 6 percent below the 30-year average, the Company would add a surcharge to customer bills equal to the equivalent margin lost beyond the approximate 6 percent heating-degree day deficiency. Likewise, if the number of heating-degree days were more than 6 percent above the 30-year average, the Company would credit customer bills equal to the excess margin realized above the 6 percent heating-degree day excess. The measurement period in determining the weather band extends from April through March. The total heating-degree days for the period April 2004 through March 2005 were approximately 12 percent less than the 30-year average. The Company recorded approximately $445,000 in additional revenues to reflect the impact of the WNA for the difference in margin realized for weather between 12 percent and 6 percent warmer than the 30-year average. On May 1, 2005, Roanoke Gas Company received approval for the WNA rate factors to be used in billing the surcharge to its customers, and the WNA was billed during the May billing cycle.

On October 23, 2004, Roanoke Gas Company placed into effect rates providing for $1.135 million in additional annual non-gas revenues subject to refund. In March 2005, Roanoke Gas Company reached a stipulated agreement with the SCC staff for a rate award of $856,859. Roanoke Gas received approval from an SCC Hearing Examiner to implement rates designed to collect $856,859 in additional annual non-gas revenues beginning April 1, 2005. On April 28, 2005, the SCC issued a final rate order approving the stipulated

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

UNAUDITED

agreement. Roanoke Gas Company has completed the refund to its customers of $175,663 in excess revenues and accrued interest associated with the higher rates placed into effect in October 2004. The Company had provided for the expected refund in prior quarters.

On March 29, 2005, 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 five-tier level for borrowing limits to accommodate the Company’s seasonal borrowing demands. Generally, the Company’s borrowing needs are at their lowest in Spring, increase during the Summer and Fall due to gas storage purchases and construction and reach their maximum levels in Winter. The five-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. Available limits under the line of credit agreements are as follows:


Beginning	Available Line of Credit
Mar 31, 2005	$	11,000,000
Jul 16, 2005		16,000,000
Sep 16, 2005		25,000,000
Nov 16, 2005		26,000,000
Feb 16, 2006		22,000,000

The line-of-credit agreements will expire March 31, 2006, unless extended. The Company anticipates being able to extend or replace the credit lines upon expiration. At June 30, 2005, the Company had $2,596,000 outstanding under its line of credit agreements.

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

Concurrent with the sale of assets, the Company entered into an agreement with Acquiror by which the Company would continue to provide the use of office, warehouse and storage space, and computer systems and office equipment and the limited utilization of Company personnel for billing, propane delivery and related services to Acquiror for the term of one year with an option for an additional year. On April 1, 2005, the Acquiror notified the Company that it will terminate portions of the agreement at the end of the contract period on July 12, 2005, and the parties agreed to extend the other portions of the agreement for office facilities, storage space and computer systems on a monthly basis but not beyond September 30, 2005. Prior to the end of the original contract period, the Acquiror had notified the Company of its intent not to extend the remaining portions of the agreement and to allow the

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

UNAUDITED

contract to expire in July 2005 with the exception of a one year lease agreement for access to the storage yard in Bluefield, West Virginia. For the nine months ended June 30, 2005, the Company realized approximately $450,000 in other revenues and $278,000 in other margin attributable to this agreement.

The asset purchase agreement did not include land and buildings owned by Diversified. Acquiror leased 10 parcels of real estate consisting of bulk storage facilities and office space from Diversified with an option to purchase such parcels. Prior to the end of June, the Acquiror executed the option to purchase the real estate and closed on all 10 parcels. The Company realized a net gain on the sale of real estate of approximately $153,000. The operations associated with the real estate and corresponding gain have been classified as Discontinued Operations in accordance with the provisions of SFAS No. 144 Accounting for the Impairment or Disposal of Long-Lived Assets. The components of Discontinued Operations for the three-month and nine-month periods ended June 30, 2005 and 2004 are as follows:


	Three Months Ended June 30,						Nine Months Ended June 30,
	2005			2004			2005			2004
Discontinued Operations:

Pretax Operating Income (Loss)	$	13,122		$	(389,713	)	$	39,366		$	2,424,636
Gain on Sale of Property		153,147			—			153,147			—
Income Tax (Expense) Benefit		(63,515	)		152,792			(73,540	)		(932,886	)

Discontinued Operations	$	102,754		$	(236,921	)	$	118,973		$	1,491,750

Resources used the proceeds from the sale of the propane assets to provide shareholders with a special $4.50 per share dividend, retire corporate debt and invest equity capital into its natural gas operations.

The discontinued operations presented in the income statement for the three months and nine months ended June 30, 2004 reflect revenues and costs of the propane operations, net of income tax. Certain costs that represent allocations of shared costs from the Company and its subsidiaries to the propane operations were retained in the continuing operations section.

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

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

UNAUDITED

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 June 30, 2005, the Company had no outstanding derivative 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 SCC and the West Virginia Public Service Commission (PSC) currently allow for full recovery of prudent costs associated with natural gas purchases, and any additional costs or benefits associated with the settlement of these instruments will be passed through to customers when realized.

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

Prior to the sale of the propane operations in July 2004, the Company also entered into swaps and price caps to hedge the price risk of propane gas.

A summary of the derivative activity is provided below:


	Propane Derivatives		Interest Rate Swap			Total
Three Months Ended June 30, 2005

Unrealized losses on derivatives	$	—	$	(1,829	)	$	(1,829	)
Income tax benefit		—		695			695

Net unrealized losses		—		(1,134	)		(1,134	)

Transfer of realized losses to income		—		3,271			3,271
Income tax benefit		—		(1,242	)		(1,242	)

Net transfer of realized losses to income		—		2,029			2,029

Net other comprehensive income	$	—	$	895		$	895

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

UNAUDITED


	Propane Derivatives		Interest Rate Swap			Total
Three Months Ended June 30, 2004

Unrealized gains on derivatives	$	—	$	103,045		$	103,045
Income tax expense		—		(39,116	)		(39,116	)

Net unrealized gains		—		63,929			63,929

Transfer of realized losses to income		—		41,929			41,929
Income tax benefit		—		(15,916	)		(15,916	)

Net transfer of realized losses to income		—		26,013			26,013

Net other comprehensive income	$	—	$	89,942		$	89,942

	Propane Derivatives		Interest Rate Swap			Total
Nine Months Ended June 30, 2005

Unrealized gains on derivatives	$	—	$	48,871		$	48,871
Income tax expense		—		(18,551	)		(18,551	)

Net unrealized gains		—		30,320			30,320

Transfer of realized losses to income		—		39,124			39,124
Income tax benefit		—		(14,852	)		(14,852	)

Net transfer of realized losses to income		—		24,272			24,272

Net other comprehensive income	$	—	$	54,592		$	54,592

Fair value of marked to market transactions		—	$	14,639		$	14,639

Accumulated comprehensive income		—	$	9,082		$	9,082

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

UNAUDITED


	Propane Derivatives			Interest Rate Swap			Total
Nine Months Ended June 30, 2004

Unrealized gains on derivatives	$	99,747		$	50,302		$	150,049
Income tax expense		(38,852	)		(19,095	)		(57,947	)

Net unrealized gains		60,895			31,207			92,102

Transfer of realized losses/(gains) to income		(99,747	)		125,099			25,352
Income tax (benefit)/expense		38,852			(47,487	)		(8,635	)

Net transfer of realized losses/(gains) to income		(60,895	)		77,612			16,717

Net other comprehensive income	$	—		$	108,819		$	108,819

Fair value of marked to market transactions		—		$	(73,713	)	$	(73,713	)

Accumulated comprehensive loss		—		$	(45,731	)	$	(45,731	)

Basic earnings per common share for the three months and nine months ended June 30, 2005 and 2004 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, 2005 and 2004 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 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,
	2005	2004	2005	2004
Weighted average common shares	2,085,029	2,031,334	2,074,957	2,020,865

Effect of dilutive securities:
Options to purchase common stock	13,654	—	13,300	13,325

Diluted average common shares	2,098,683	2,031,334	2,088,257	2,034,190

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

UNAUDITED

10.	RGC Resources, Inc.’s reportable segments are included in the following table. The segments are comprised of gas utilities and energy marketing. Other is composed of appliance services, information system services and certain corporate eliminations.


	Gas Utilities			Energy Marketing		Segment Total			Other			Consolidated Total
For the Three Months Ended June 30, 2005
Operating revenues	$	15,637,845		$	5,018,639	$	20,656,484		$	181,869		$	20,838,353
Gross margin		4,781,333			63,615		4,844,948			143,171			4,988,119
Operations, maintenance and general taxes		3,241,606			14,063		3,255,669			54,472			3,310,141
Depreciation and amortization		979,098			—		979,098			848			979,946

Operating income		560,629			49,552		610,181			87,851			698,032
Other expense (income), net		30,229			—		30,229			(8,230	)		21,999
Interest expense		464,766			—		464,766			341			465,107
Income before income taxes		65,634			49,552		115,186			95,740			210,926

Gross additions to long-lived assets		1,703,121			—		1,703,121			—			1,703,121

For the Three Months Ended June 30, 2004
Operating revenues	$	13,610,639		$	4,564,126	$	18,174,765		$	58,713		$	18,233,478
Gross margin		4,305,952			57,100		4,363,052			39,711			4,402,763
Operations, maintenance and general taxes		3,406,886			11,887		3,418,773			2,869			3,421,642
Depreciation and amortization		969,140			—		969,140			451			969,591

Operating income (loss)		(70,074	)		45,213		(24,861	)		36,391			11,530
Other income, net		(14,677	)		—		(14,677	)		—			(14,677	)
Interest expense		439,166			—		439,166						439,166
Income (loss) before income taxes		(494,563	)		45,213		(449,350	)		36,391			(412,959	)

Gross additions to long-lived assets		2,109,805			—		2,109,805			2,544			2,112,349

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

UNAUDITED


For the Nine Months Ended June 30, 2005
Operating revenues	$	81,947,596	$	16,196,375	$	98,143,971	$	663,281		$	98,807,252
Gross margin		20,036,620		328,101		20,364,721		394,227			20,758,948
Operations, maintenance and general taxes		9,861,744		42,358		9,904,102		159,250			10,063,352
Depreciation and amortization		3,016,047		—		3,016,047		2,541			3,018,588

Operating income		7,158,829		285,743		7,444,572		232,436			7,677,008
Other (income) expenses, net		38,087		—		38,087		(46,905	)		(8,818	)
Interest expense		1,529,509		—		1,529,509		1,048			1,530,557
Income before income taxes		5,591,233		285,743		5,876,976		278,293			6,155,269

Gross additions to long-lived assets		5,406,850		—		5,406,850		—			5,406,850

As of June 30, 2005:
Total assets		100,511,464		1,919,981		102,431,445		1,982,206			104,413,651

For the Nine Months Ended June 30, 2004
Operating revenues	$	73,340,547	$	14,214,447	$	87,554,994	$	267,426		$	87,822,420
Gross margin		18,997,261		195,190		19,192,451		156,864			19,349,315
Operations, maintenance and general taxes		10,468,698		36,038		10,504,736		7,958			10,512,694
Depreciation and amortization		2,931,240		—		2,931,240		451			2,931,691

Operating income		5,597,323		159,152		5,756,475		148,455			5,904,930
Other (income) expenses, net		26,847		—		26,847		—			26,847
Interest expense		1,417,419		—		1,417,419		—			1,417,419
Income before income taxes		4,153,057		159,152		4,312,209		148,455			4,460,664

Gross additions to long-lived assets		5,277,207		—		5,277,207		10,840			5,288,047

As of June 30, 2004:
Total assets		86,327,043		3,850,536		90,177,579		10,003,774	*		100,181,353

*	Other included $12,499,981 in assets of the discontinued propane operations.

11.

The Company has a Key Employee Stock Option Plan (the “Plan”), which is intended to provide the Company’s executive officers with long-term (ten-year) incentives and rewards tied to the price of the Company’s common stock. The Company applies the recognition and measurement principles of APB Opinion No. 25, Accounting for Stock Issued to Employees, and related Interpretations in accounting for this Plan. No stock-based employee compensation expense is reflected in net income as all options granted under the Plan had an exercise price equal to the market value of the underlying common stock on the date of the grant. No options have been granted under the Plan during the current and prior fiscal year.

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CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

UNAUDITED

If options had been granted, a reconciliation of net income and earnings per share would be presented to reflect the fair value recognition provisions of FASB Statement No. 123, Accounting for Stock-Based Compensation, to options granted under the Plan.

12.

Effective November 1, 2004, Roanoke Gas Company and Bluefield Gas Company (the Companies) each entered into a new asset management agreement with a third party. Each contract is a three-year agreement with terms similar to the agreements that expired in October 2004 whereby the third party has assumed the management of the Companies’ firm transportation and storage agreements. The new contracts call for the Companies to retain ownership of its storage gas rather than having the asset manager own the gas as specified under the previous contract. As a result of the new contracts, the balance sheet at June 30, 2005 includes a line item called “gas in storage” that is composed of the underground storage gas previously owned by the asset manager. The gas in storage line item replaces the prepaid gas service under the prior contract, which represented the Companies’ right to receive an equal amount of gas in the future as provided by those agreements.

13.

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 June 30,						Nine Months Ended June 30,
	2005			2004			2005			2004
Components of net periodic pension cost:

Service cost	$	81,856		$	78,004		$	245,568		$	234,012
Interest cost		157,931			135,818			473,793			407,454
Expected return on plan assets		(142,970	)		(112,885	)		(428,910	)		(338,655	)
Recognized loss		15,599			27,399			46,797			82,197

Net periodic pension cost	$	112,416		$	128,336		$	337,248		$	385,008

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CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

UNAUDITED


	Three Months Ended June 30,						Nine Months Ended June 30,
	2005			2004			2005			2004
Components of net periodic benefit costs:

Service cost	$	32,243		$	45,020		$	96,729		$	135,060
Interest cost		111,067			122,141			333,201			366,423
Expected return on plan assets		(46,453	)		(30,031	)		(139,359	)		(90,093	)
Amortization of unrecognized transition obligation		59,325			55,172			177,975			165,516
Recognized loss		—			25,205			—			75,615

Net periodic benefit cost	$	156,182		$	217,507		$	468,546		$	652,521

June 30, 2004 balances have been restated to reflect the removal of costs attributable to the discontinued operations of Highland Propane. Net periodic pension cost and net periodic post-retirement benefit cost included in discontinued operations were $24,196 and $23,603 for the three months ended June 30, 2004 and $72,588 and $70,809 for the nine months ended June 30, 2004, respectively. Total expected employer funding contributions during the fiscal year ending September 30, 2005 are $750,000 for the pension plan and $800,000 for the post retirement plan.

14.

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.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

UNAUDITED

15.

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

In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment, a revision of SFAS No. 123, Accounting for Stock-Based Compensation. This statement eliminates the alternative to use Accounting Principles Board’s Opinion No. 25, Accounting for Stock Issued to Employees, intrinsic value method of accounting that was previously allowed under Statement 123. This statement requires entities to recognize the cost of employee services received in exchange for awards of equity instruments on the grant-date fair value of those awards. The effective date of this statement has been extended to correspond with fiscal years beginning after June 15, 2005. The Company does not expect the adoption of this statement to have a material impact on the Company’s financial position or results of operations.

In March 2005, the FASB issued FASB Interpretation (“FIN”) No. 47, Accounting for Conditional Asset Retirement Obligations – an Interpretation of FASB Statement No. 143. Diverse accounting practices had developed with respect to the timing of liability recognition of legal obligations associated with the retirement of a tangible long-lived asset when the timing and/or method of settlement of the obligation are conditional on a future event. FIN No. 47 provides clarification when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. The effective date of this interpretation is no later than the end of fiscal years ending after December 31, 2005. The Company has not completed its evaluation of this interpretation and has not yet determined the impact on the Company’s financial position or results of operations.

In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections – a replacement of APB Opinion No. 20 and FASB Statement No. 3. This statement applies to all voluntary changes in accounting principle by requiring retrospective application of the change in accounting principle to all prior period financial statements presented. Retrospective application is defined as the application of a different accounting principle to prior accounting periods as if that principle had always been used. Previously, such changes were reflected in the current financial statements as a cumulative effect of change in

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

UNAUDITED

accounting principle. The intent of the statement is to improve financial reporting by improving comparability of financial statements between periods. The effective date of this statement is for fiscal years beginning after December 15, 2005. This statement does not have a current effect on the Company’s financial statements but will affect the Company’s future reporting of changes in accounting principles, if any.

RGC RESOURCES, INC. AND SUBSIDIARIES

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

General

RGC Resources, Inc. (“Resources” or the “Company”) is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately 59,000 residential, commercial and industrial customers in Roanoke, Virginia and Bluefield, Virginia and West Virginia and the surrounding areas through its Roanoke Gas Company and Bluefield Gas Company subsidiaries. Natural gas service is provided at rates and for the terms and conditions set forth by the State Corporation Commission (SCC) in Virginia and the Public Service Commission (PSC) in West Virginia.

Resources also provides unregulated energy products through Diversified Energy Company, which operates as Highland Energy Company. Highland Energy brokers natural gas to several industrial transportation customers of Roanoke Gas Company and Bluefield Gas Company. In addition to an energy marketing company, Diversified Energy Company operated an unregulated propane operation under the name of Highland Propane Company. In July 2004, Resources sold the propane operations. These operations have been classified as discontinued operations in the prior year financial statements.

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

Management views warm winter weather; energy conservation, fuel switching and bad debts due to high energy prices; and competition from alternative fuels each as factors that could have a significant impact on the Company’s earnings. The risk of warm winter weather has been partially mitigated due to the inclusion of a weather normalization adjustment (“WNA”) factor as part of Roanoke Gas Company’s rate structure. The WNA operates 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 fall within approximately 6 percent above or below the 30-year average, no adjustments are made. However, if the number of heating degree-days were more than 6 percent below the 30-year average, the Company would add a surcharge to firm customer bills (those customers not subject to service interruption) equal to the equivalent margin lost below the approximate 6 percent deficiency. Likewise, if the number of heating-degree days were more than 6 percent above the 30-year average, the Company would credit firm customer bills equal to the excess margin realized above the 6 percent heating degree-days. The measurement period in determining the weather band extends from April through March with any adjustment to be made to customer bills in late Spring. The Company realized approximately $445,000 in additional revenues for the weather band period ended March 31, 2005 as the heating-degree days for the period April 2004 through March 2005 were approximately 12 percent less than the 30-year average. In addition, management has concerns regarding the cost and time required for complying with regulations regarding internal controls promulgated pursuant to Section 404 of the Sarbanes-Oxley Act of 2002.

RGC RESOURCES, INC. AND SUBSIDIARIES

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

For the quarter ended June 30, 2005, high energy prices remained the primary concern for management. Continued increases in natural gas prices may lead consumers to reduce consumption through conservation or possible fuel switching to alternate, lower cost energy sources. In spite of the continuing high energy prices, the Company was able to experience improved operating results from continuing operations over the same quarter last year. Implementation of increased base rates in October combined with a rate design that provides timely recovery of the carrying costs associated with the greater investment in natural gas inventories have contributed to the improved results.

Results of Operations

Consolidated net income (loss) for the three-month and nine-month periods ended June 30, 2005 was $229,525 and $3,918,639, respectively, compared to $(512,664) and $4,234,991 for the same periods last year. Net income (loss) from continuing and discontinued operations is as follows:


	Three Months Ended June 30,					Nine Months Ended June 30,
	2005		2004			2005		2004
Net Income (Loss)

Continuing Operations	$	126,771	$	(275,743	)	$	3,799,666	$	2,743,241
Discontinued Operations		102,754		(236,921	)		118,973		1,491,750

Net Income (Loss)	$	229,525	$	(512,664	)	$	3,918,639	$	4,234,991

Continuing Operations


	Three Months Ended June 30,				Increase/ (Decrease)		Percentage
	2005		2004		Increase/ (Decrease)		Percentage
Operating Revenues

Gas Utilities	$	15,637,845	$	13,610,639	$	2,027,206	15	%
Energy Marketing		5,018,639		4,564,126		454,513	10	%
Other		181,869		58,713		123,156	210	%

Total Operating Revenues	$	20,838,353	$	18,233,478	$	2,604,875	14	%

Total operating revenues from continuing operations for the three months ended June 30, 2005 increased by $2,604,875, or 14 percent, compared to the same period last year, primarily due to

RGC RESOURCES, INC. AND SUBSIDIARIES

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

higher gas costs, the implementation of base rate increases and the services agreement associated with the sale of Highland Propane. The total average unit cost of natural gas increased by 11 percent over the same quarter last year. Total regulated natural gas delivered volumes increased by 1 percent, while energy marketing sales volumes declined by 7 percent. Other revenues increased by $123,156 due to revenues generated under the services agreement with the Acquiror (as defined below) of the assets of Highland Propane Company to provide billing, facility and other services. The revenues attributed to the services agreement will cease by fiscal year end, because the Acquiror has notified the Company that it will terminate the contract at the end of the contract period on July 12, 2005. Only nominal activity and revenues will occur subsequent to contract termination.


	Three Months Ended June 30,				Increase/ (Decrease)		Percentage
	2005		2004		Increase/ (Decrease)		Percentage
Gross Margin

Gas Utilities	$	4,781,333	$	4,305,952	$	475,381	11	%
Energy Marketing		63,615		57,100		6,515	11	%
Other		143,171		39,711		103,460	261	%

Total Gross Margin	$	4,988,119	$	4,402,763	$	585,356	13	%

Total gross margin increased by $585,356, or 13 percent, for the quarter ended June 30, 2005 over the same period last year. Regulated natural gas margins increased by $475,381, or 11 percent, even though total delivered volume (tariff and transporting) increased by only 1 percent. Tariff sales, primarily consisting of residential and commercial usage, increased by 5 percent primarily due to certain industrial transportation customers switching to tariff sales. Residential and commercial usage reflected a 2 percent increase over last year associated with a cooler Spring quarter. In consideration of the small rise in total delivered natural gas volumes, the majority of the increase in the regulated natural gas margins is attributable to the implementation of increased non gas cost base rates effective October 23, 2004 combined with the rate design which provides timely recovery of the financing costs (“carrying costs”) related to the higher dollar investments in natural gas inventories. Both Roanoke Gas Company and Bluefield Gas Company placed increased rates into effect during the first quarter. Roanoke Gas Company’s rates were placed into effect subject to refund pending a final order from the Virginia SCC. Bluefield Gas Company’s rates were placed into effect in accordance with a final rate order issued by the West Virginia PSC. As a result of the rate increases, the Company realized approximately $114,000 in additional customer base charges, which is a flat monthly fee billed to each natural gas customer. Carrying cost revenues increased by approximately $214,000 due to a much higher level of investment in storage gas inventory compared to prepaid gas service for the same period last year due to the combination of higher prices and warmer weather reducing the withdrawal rates from storage. The balance of the increase in regulated natural gas margin is attributable to the volumetric portion of the rate increase.

RGC RESOURCES, INC. AND SUBSIDIARIES

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

Beginning in April 2003, the SCC approved a rate structure that would allow Roanoke Gas Company to recover financing costs related to the level of investment in inventory and prepaid gas service. Therefore, during times of rising gas costs, Roanoke Gas would be able to recognize a greater level of revenues to offset the higher financing costs; conversely, Roanoke Gas will pass along savings to customers if financing costs decrease due to lower inventory and prepaid gas balances resulting from reductions in gas costs. During the first quarter, Bluefield Gas Company implemented a similar rate structure as part of its new rates. The net effect of increased storage gas levels and the implementation of the carrying cost revenue component for Bluefield Gas resulted in the approximately $214,000 increase in revenues and margin. During periods of declining gas costs and storage gas levels, the Company would experience a reduction in revenues and margins as well.

The energy marketing division margin increased by $6,515, or 11 percent, even though total sales volume decreased by 51,297 dekatherms, or 7 percent. The Company was able to make up the volume shortfall with a small increase in unit margin per dekatherm. Other margins increased by $103,460 due to the services agreement with the Acquiror of the assets of Highland Propane Company to provide billing, facility and other services, as discussed above.

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


	Three Months Ended June 30,		Increase/ (Decrease)		Percentage
	2005	2004	Increase/ (Decrease)		Percentage
Delivered Volumes

Regulated Natural Gas (DTH)
Tariff Sales	1,201,008	1,142,415	58,593		5	%
Transportation	787,107	828,296	(41,189	)	-5	%

Total	1,988,115	1,970,711	17,404		1	%

Highland Energy (DTH)	665,875	717,172	(51,297	)	-7	%

Heating Degree Days (Unofficial)	371	269	102		38	%

Operations expenses decreased by $96,287, or 4 percent, for the three-month period ended June 30, 2005 compared to the same period last year. The decrease is primarily due to reductions in bad debt expense. Improvement in bad debt expense is due to a variety of factors including: improvement in customer delinquencies, increased level of customer deposits to provide protection against default and the effect on a new rate structure for Bluefield Gas implemented in the first quarter. The new rate structure provides that the portion of bad debts associated with gas cost be included as a component of gas costs, thereby allowing direct recovery through the Purchased Gas Adjustment (PGA) mechanism. Operations expenses were also reduced by the

RGC RESOURCES, INC. AND SUBSIDIARIES

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

actuarial impact of Medicare Part D on post-retirement medical costs offset by increases in labor costs. Maintenance expenses declined $28,277, or 7 percent, due to a greater level of work associated with leak repairs in the prior year.

General taxes increased $13,063, or 4 percent, primarily due to higher business and occupation (B&O) taxes, a revenue sensitive tax, related to higher revenues in the West Virginia natural gas operations and higher payroll taxes.

Other expense, net, increased by $36,676 due to a $30,000 loss on the sale and disposal of the propane air plant by Roanoke Gas.

Interest expense increased by $25,941, or 6 percent, as the Federal Reserve’s monetary policy has led to increasing interest rates on the Company’s variable rate debt. The Company’s total debt position during the quarter remained nearly unchanged compared to last year. The effect of rising interest rates has increased the overall average rate on total Company debt by 25 basis points over the same period last year.

Income tax expense increased by $221,371, which corresponds to the pre-tax income for the current quarter as compared to a pre-tax loss for the same quarter last year.


	Nine Months Ended June 30,				Increase/ (Decrease)		Percentage
	2005		2004		Increase/ (Decrease)		Percentage
Operating Revenues
Gas Utilities	$	81,947,596	$	73,340,547	$	8,607,049	12	%
Energy Marketing		16,196,375		14,214,447		1,981,928	14	%
Other		663,281		267,426		395,855	148	%

Total Operating Revenues	$	98,807,252	$	87,822,420	$	10,984,832	13	%

Total operating revenues from continuing operations for the nine months ended June 30, 2005 increased by $10,984,832, or 13 percent, compared to the same period last year, due to the same reasons provided for the quarter: higher gas costs and implementation of base rate increases more than offsetting reductions related to lower sales volumes related to the warmer winter weather. Revenues were also supplemented by the billing of approximately $445,000 in additional revenue associated with the WNA. Although total tariff sales of the gas utilities declined by 4 percent, the average unit cost of natural gas delivered to customers increased by 19 percent. Energy marketing revenues increased due to the effects of rising gas costs, even though sales volumes were down by 4 percent. Other revenues increased by $395,855 due to revenues generated under the services agreement with the Acquiror of the assets of Highland Propane Company to provide billing, facility and other services, as discussed above.

RGC RESOURCES, INC. AND SUBSIDIARIES

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


	Nine Months Ended June 30,				Increase/ (Decrease)		Percentage
	2005		2004		Increase/ (Decrease)		Percentage
Gross Margin
Gas Utilities	$	20,036,620	$	18,997,261	$	1,039,359	5	%
Energy Marketing		328,101		195,190		132,911	68	%
Other		394,227		156,864		237,363	151	%

Total Gross Margin	$	20,758,948	$	19,349,315	$	1,409,633	7	%

Total gross margin increased by $1,409,633, or 7 percent, for the nine-month period ended June 30, 2005 over the same period last year. Regulated natural gas margins increased by $1,039,359, or 5 percent, even though total delivered volume (tariff and transporting) decreased by 368,670 dekatherms, or 4 percent. The increase in the regulated natural gas margin was attributable to rate increases placed into effect during the first quarter for both Roanoke Gas and Bluefield Gas, approximately $455,000 in additional carrying cost revenues associated with the higher level of investment in storage gas inventory and prepaid gas service compared to the same period last year and approximately $445,000 in additional revenues associated with the WNA, all of which more than offset the effect of the reduction in sales volumes. The energy marketing division margin increased by $132,911, even though total sales volume decreased by 95,317 dekatherms, or 4 percent. The increase in margin was attributable to the sale of 100,000 dekatherm natural gas strip for $143,000 profit. The 100,000 dekatherm strip (a commitment to purchase volumes in the future for a fixed price) was not needed to meet the needs of Highland Energy’s customers; therefore, the Company was able to take advantage of market conditions at the time and realize a gain on the transaction. This was a non-recurring transaction and is not expected to be replicated in the future. Other margins increased by $237,363 due to the services agreement with the Acquiror of the assets of Highland Propane Company to provide billing, facility and other services.

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

RGC RESOURCES, INC. AND SUBSIDIARIES

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


	Nine Months Ended June 30,		Increase/ (Decrease)		Percentage
	2005	2004	Increase/ (Decrease)		Percentage
Delivered Volumes

Regulated Natural Gas (DTH)
Tariff Sales	7,472,527	7,787,407	(314,880	)	-4	%
Transportation	2,542,953	2,596,743	(53,790	)	-2	%

Total	10,015,480	10,384,150	(368,670	)	-4	%

Highland Energy (DTH)	2,136,758	2,232,075	(95,317	)	-4	%

Heating Degree Days (Unofficial)	3,783	3,920	(137	)	-3	%

Operations expenses decreased by $408,406 or 5 percent for the nine-month period ended June 30, 2005 compared to the same period last year. The decrease is primarily due to reductions in employee benefit costs including medical insurance due to lower claim activity in the first quarter, post-retirement medical costs due to the actuarial impact of Medicare Part D and reductions in bad debt expense. The Company has been self-insured for medical insurance purposes for the past several years with stop/loss coverage only for extremely high claim activity. The self-insurance program generated volatility in expense due to fluctuating claim levels. Beginning in January 2005, the Company switched to fully insured coverage to provide a more predictable expense trend, which is more conducive to receiving recovery of these costs in a regulated environment. Maintenance expenses declined $44,529, or 4 percent, due to a greater level of work associated with leak repairs in the prior year. General taxes remained comparable to last year experiencing a slight increase of less than 1 percent.

Other expense (income), net decreased by $35,665 due to investment earnings realized on the proceeds from the sale of Highland Propane prior to the payment of the special dividend on December 8, 2004. The Company paid a one-time special dividend of $4.50 per share to distribute the gain realized on the sale of Highland Propane.

Interest expense increased by $113,138, or 8 percent, even though the Company’s average total debt position during the current quarter decreased by $400,000 from the same period last year. The increase in interest expense is attributable to rising rates on the Company’s variable rate debt. The effective average interest rate on the Company’s outstanding lines of credit balances increased from 1.70% last year to 2.96% this year.

Income tax expense increased by $638,180, which corresponds to the increase in pre-tax income on continuing operations. The effective tax rate decreased slightly from 38.5 percent to 38.3 percent for the current period.

RGC RESOURCES, INC. AND SUBSIDIARIES

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

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 30, 2005. 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.

Discontinued Operations

Concurrent with the sale of assets, the Company entered into an agreement with Acquiror by which the Company will continue to provide the use of office, warehouse and storage space, and computer systems and office equipment and the limited utilization of Company personnel for billing, propane delivery and related services to Acquiror for the term of one year with an option for an additional year. On April 1, 2005, the Acquiror notified the Company that it will terminate portions of the agreement at the end of the contract period on July 12, 2005, and the parties agreed to extend the other portions of the agreement for office facilities, storage space and computer systems on a monthly basis but not beyond September 30, 2005. Prior to the end of the original contract period, the Acquiror notified the Company of its intent not to extend the remaining portions of the agreement and allow the contract to expire in July 2005 with the exception of a one year extension for access to the storage yard in Bluefield, West Virginia. For the nine months ended June 30, 2005, the Company realized approximately $450,000 in other revenues and $278,000 in other margin attributable to this agreement. The $278,000 margin covered approximately $169,000 in recurring operating and maintenance expenses allocated from Resources and the regulated natural gas operations. Management anticipates that it will be able to recover most, if not all, of these previously allocated costs through future rate relief.

The asset purchase agreement did not include land and buildings owned by Diversified. Acquiror leased 10 parcels of real estate consisting of bulk storage facilities and office space from Diversified with an option to purchase such parcels. Prior to the end of June, the Acquiror executed the option to purchase the real estate and closed on all 10 parcels. The Company realized a net gain on the sale of real estate of approximately $153,000. The operations associated with the real estate and the corresponding gain have been classified as Discontinued Operations in accordance with the provisions of SFAS No. 144 Accounting for the Impairment or Disposal of Long-Lived Assets. The components of Discontinued Operations for the three-month and nine-month periods ended June 30, 2005 and 2004 are as follows:

RGC RESOURCES, INC. AND SUBSIDIARIES

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


	Three Months Ended June 30,						Nine Months Ended June 30,
	2005			2004			2005			2004
Discontinued Operations:
Pretax Operating Income (Loss)	$	13,122		$	(389,713	)	$	39,366		$	2,424,636
Gain on Sale of Property		153,147			—			153,147			—
Income Tax (Expense) Benefit		(63,515	)		152,792			(73,540	)		(932,886	)

Discontinued Operations	$	102,754		$	(236,921	)	$	118,973		$	1,491,750

Critical Accounting Policies

The consolidated financial statements of RGC Resources, Inc. are prepared in accordance with accounting principles generally accepted in the United States of America. The amounts of assets, liabilities, revenues and expenses reported in the Company’s financial statements are affected by estimates and judgments that are necessary to comply with generally accepted accounting principles. Estimates used in the financial statements are derived from prior experience, statistical analysis and professional judgments. Actual results could differ from the estimates, which would affect the related amounts reported in the Company’s financial statements. Although estimates and judgments are applied in arriving at many of the reported amounts in the financial statements including provisions for employee medical insurance, projected useful lives of capital assets and goodwill valuation, the following items may involve a greater degree of judgment.

Revenue recognition – The Company bills natural gas customers on a monthly cycle basis; however, the billing cycle periods for most customers do not coincide with the accounting periods used for financial reporting. The Company accrues estimated revenue for natural gas delivered to customers not yet billed during the accounting period. Determination of unbilled revenue relies on the use of estimates, current and historical data. The Company also accrues a provision for rate refund and/or WNA adjustment during periods in which the Company has implemented new billing rates as authorized by the corresponding state regulatory body or during periods in which weather falls outside of the weather normalization band, pending final review and authorization from the state regulatory body.

RGC RESOURCES, INC. AND SUBSIDIARIES

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

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

Retirement plans – The Company offers a defined benefit pension plan and a post-retirement medical plan to eligible employees. The expenses and liabilities associated with these plans are determined through actuarial means requiring the estimation of certain assumptions and factors. In regard to the pension plan, these factors include assumptions regarding discount rate, expected long-term rate of return on plan assets, compensation increases and life expectancies, among others. Similarly, the post-retirement medical plan also requires the estimation of many of the same factors as the pension plan in addition to assumptions regarding rate of medical inflation and Medicare availability. Actual results may differ materially from the results expected from the actuarial assumptions due to changing economic conditions, volatility in interest rates and changes in life expectancy to name a few. Such differences may result in a material impact on the amount of expense recorded in future periods or the value of the obligations on the balance sheet.

Derivatives – As discussed in the “Item 3 - Qualitative and Quantitative Disclosures about Market Risk” section below, the Company hedges certain risks incurred in the normal operation of business through the use of derivative instruments. The Company applies the requirements of Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, which requires the recognition of all derivative instruments as assets or liabilities in the Company’s balance sheet at fair value. Fair value is based upon quoted futures prices for the natural gas commodities. Changes in the commodity and futures markets will impact the estimates of fair value in the future. Furthermore, the actual market value at the point of realization of the derivative may be significantly different from the futures value used in determining fair value in prior financial statements.

Regulatory accounting – The Company’s regulated operations follow the accounting and reporting requirements of Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation. The economic effects of regulation can result in a regulated company deferring costs that have been or are expected to be recovered from customers in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this results, costs are deferred as assets in the consolidated balance sheet (regulatory assets) and recorded as expenses when such amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for the amounts previously collected from customers and for current collection in rates of costs that are expected to be incurred in the future (regulatory liabilities).

RGC RESOURCES, INC. AND SUBSIDIARIES

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

Asset Management

Effective November 1, 2004, Roanoke Gas Company and Bluefield Gas Company (the Companies) each entered into a new asset management agreement with a third party. Each contract is a three-year agreement with terms similar to the agreements that expired in October whereby the third party has assumed the management of the Companies’ firm transportation and storage agreements. The new contracts call for the Companies to retain ownership of their storage gas rather than having the asset manager own the gas as specified under the previous contract. As a result of the new contracts, the balance sheet at June 30, 2005 includes a line item called “gas in storage” that is composed of the underground storage gas previously owned by the asset manager. The gas in storage line item replaces the prepaid gas service under the prior contract, which represented the Companies’ rights to receive an equal amount of gas in the future as provided by those agreements.

Energy Costs

Natural gas commodity prices have continued to remain high and volatile throughout the last heating season and into the summer months. Management considers the key reason for high energy prices to be the accumulated impact of years of inconsistent regulatory policy and the continued failure of Congress to pass and the President to sign meaningful national energy use and resource development legislation. In the absence of such legislation, accessible natural gas reserves may continue to decline. An energy bill that would provide some improvement for natural gas supply development was approved by Congress and signed by the President in early August. The Company uses various hedging mechanisms including summer storage injections and financial instruments to limit weather driven volatility in energy prices. Management determined not to utilize financial hedges during the just completed winter season to the extent it has in prior years because of the unusually large spread between winter futures prices and gas prices leading up to the winter season. Given the high level of natural gas in storage on a national basis, management did not believe the winter futures prices were a reasonable basis for financial price hedging purposes. The wide spread continues in spite of a warmer than normal winter and management has not yet determined it appropriate to utilize financial hedges for the coming winter season.

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

Although rising energy prices are recoverable through the PGA mechanism for the regulated operations, high energy prices may have a negative impact on earnings through increases in bad debt expense and higher interest costs because the delay in recovering higher gas costs requires borrowing to temporarily fund receivables from customers, LNG (liquefied natural gas) and storage gas levels. The Company’s rate structure provides a level of protection against the

RGC RESOURCES, INC. AND SUBSIDIARIES

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

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

Roanoke Gas Company placed into effect new base rates effective for service rendered on and after October 23, 2004 to provide for approximately $1,135,000 in additional annual non gas revenues. These higher rates were subject to refund pending a final order by the Virginia SCC. In March 2005, Roanoke Gas Company reached a stipulated agreement with the SCC staff for a rate award of $856,859. Roanoke Gas received approval from an SCC Hearing Examiner to implement rates designed to collect $856,859 in additional annual non-gas revenues beginning April 1, 2005. On April 28, 2005, the SCC issued a final rate order approving the stipulated agreement. In the June billing cycle, Roanoke Gas Company refunded $175,663 in excess revenues, and accrued interest, collected above those provided for in the rate order. Management filed a notice of intent in June to inform the SCC of Roanoke Gas Company’s plan to file a new request for rate increase in September.

Bluefield Gas Company settled its rate case pending a final order from the West Virginia PSC which authorized Bluefield Gas to implement a non gas cost rate increase to provide for an $330,000 in additional annual revenues. Management anticipates that these new rates will be placed into effect for gas service rendered on and after November 1, 2005.

Environmental Issues

RGC RESOURCES, INC. AND SUBSIDIARIES

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

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.

Capital Resources and Liquidity

Due to the capital intensive nature of Resources’ utility and energy businesses as well as the related weather sensitivity, Resources’ primary capital needs are the funding of its continuing construction program and the seasonal funding of its natural gas inventories and accounts receivable. The Company’s construction program is composed of a combination of replacing old bare steel and cast iron pipe with new plastic or coated steel pipe and expansion of natural gas service to new customers. Total capital expenditures from continuing operations were $5,406,850 and $5,288,047 for the nine-month periods ended June 30, 2005 and 2004, respectively. The Company’s total capital budget for the current year is approximately $7,070,000. It is anticipated that these costs and 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.

Short-term borrowing, in addition to providing capital project bridge financing, is used to fund seasonal levels of natural gas inventory and accounts receivable. From April through October, the Company purchases natural gas to be placed into storage for winter delivery. Furthermore, a majority of the Company’s sales and billings occur during the winter months resulting in a corresponding increase in accounts receivable. The following table provides a quarterly perspective of the seasonality of the accounts receivable and natural gas inventory. Amounts are in thousands.


	Amounts in (000’s)
Period Ended	Gas in Storage/ Prepaid Gas Service		Accounts Receivable		Total
Jun 30, 2003	$	8,620	$	7,216	$	15,836
Sep 30, 2003		16,162		5,242		21,404
Dec 31, 2003		12,498		17,142		29,640
Mar 31, 2004		1,071		14,274		15,345
Jun 30, 2004		9,059		6,481		15,540
Sep 30, 2004		17,662		5,978		23,640
Dec 31, 2004		17,136		18,938		36,074
Mar 31, 2005		7,800		17,437		25,237
Jun 30, 2005		17,037		7,746		24,783

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

RGC RESOURCES, INC. AND SUBSIDIARIES

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

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.

On March 29, 2005, 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 five-tier level for borrowing limits to accommodate the Company’s seasonal borrowing demands. Generally, the Company’s borrowing needs are at their lowest in Spring, increase during the Summer and Fall due to gas storage purchases and construction and reach their maximum levels in Winter. The five-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. Available limits under the line of credit agreements are as follows:


Beginning	Available Line of Credit
Mar 31, 2005	$	11,000,000
Jul 16, 2005		16,000,000
Sep 16, 2005		25,000,000
Nov 16, 2005		26,000,000
Feb 16, 2006		22,000,000

The line of credit agreements will expire March 31, 2006, unless extended. The Company anticipates being able to extend or replace the credit lines upon expiration. At June 30, 2005, the Company had $2,596,000 outstanding under its line of credit agreements.

The Company has $10,000,000 in current maturities of long-term debt that is due in November 2005. Management anticipates refinancing these balances upon maturity.

At June 30, 2005, the Company’s capitalization consisted of 40 percent in long-term debt and 60 percent in common equity.

Labor Relations

Certain operational employees of Roanoke Gas and Bluefield Gas belong to the Paper, Allied-Industrial, Chemical and Energy Workers International Union, AFL-CIO Local No. 2-515. The union contract for Roanoke Gas covering 34 employees expired on July 31, 2005. On August 1, 2005, the union voted upon and approved a new 5-year contract. The Bluefield Gas’ collective bargaining agreement will expire on July 4, 2007.

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, the Company may publish forward-looking statements relating to such matters as anticipated financial performance, business prospects, technological developments, new products, research and development activities and similar matters. The Private Securities Litigation Reform Act of 1995 provides a safe harbor for forward-looking statements. In order to comply with the terms of the safe harbor, the Company notes that a variety of factors could cause the Company’s actual results and experience to differ materially from the anticipated results or other expectations expressed in the Company’s forward-looking statements. The risks and uncertainties that may affect the operations, performance, development and results of the Company’s business include the following: (i) failure to earn on a consistent basis an adequate return on invested capital; (ii) increasing expenses and labor costs and labor availability; (iii) price competition from alternative fuels; (iv) volatility in the price and availability of natural gas; (v) uncertainty in the projected rate of growth of natural gas requirements in the Company’s service area; (vi) general economic conditions both locally and nationally; (vii) increases in interest rates; (viii) increased customer delinquencies and conservation efforts resulting from high fuel costs and/or colder weather; (ix) developments in electricity and natural gas deregulation and associated industry restructuring; (x) variations in winter heating degree-days from normal; (xi) changes in environmental requirements, pipeline operating requirements and cost of compliance; (xii) impact of potential increased governmental oversight and compliance costs due to the Sarbanes-Oxley law; (xiii) failure to obtain timely rate relief for increasing operating or gas costs from regulatory authorities; (xiv) inability to raise debt or equity capital on favorable terms; (xv) impact of uncertainties in the Middle East and related terrorism issues; (xvi) work stoppages associated with labor disputes; (xvii) supply curtailment or disruption due to pipeline failures; 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” or similar words or future or conditional verbs such as “will,” “would,” “should,” “could” or “may” are intended to identify forward-looking statements.

Forward-looking statements reflect the Company’s current expectations only as of the date they are made. We assume no duty to update these statements should expectations change or actual results differ from current expectations.

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.

The Company is exposed to market risk related to changes in interest rates associated with its borrowing activities. At June 30, 2005, the Company had $2,596,000 outstanding under its lines of credit 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 outstanding at June 30, 2005 would have resulted in an increase in quarterly interest expense of approximately $11,500. The Company also has an $8,000,000 intermediate term variable rate note that is currently being hedged by a fixed rate interest swap.

The 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 storage gas arrangements for the purpose of hedging the price of natural gas. The Company currently has no derivative commodity instruments for hedging the price of natural gas. However, if the Company had entered into derivative commodity arrangements, any cost incurred or benefit received from the derivative arrangements would be recoverable or refunded through the regulated natural gas purchased gas adjustment (PGA) mechanism. Both the Virginia SCC and the West Virginia PSC currently allow for full recovery of prudent costs associated with natural gas purchases, and any additional costs or benefits associated with the settlement of the derivative contract will be passed through to customers when realized. As of June 30, 2005, the Company had not entered into any new natural gas derivative instruments during the quarter.

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 June 30, 2005, the Company’s Chief Executive Officer and principal financial officer have concluded that these disclosure controls and procedures are effective. There has been no change during the quarter ended June 30, 2005, 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.

Part II - Other Information

ITEM 2 - CHANGES IN SECURITIES.

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 1993 (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, 2005, the Company issued a total of 700.800 shares of restricted stock pursuant to the Restricted Stock Plan as follows:


Investment Date	Price		Number of Shares
4/1/2005	$	25.260	242.147
5/2/2005	$	26.410	231.604
6/1/2005	$	26.940	227.049

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

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: August 15, 2005	By:	/s/ Howard T. Lyon
		Howard T. Lyon
		Vice-President, Treasurer and Controller
		(Principal Financial Officer)