RGC RESOURCES INC - 10-Q Quarterly Report

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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 March 31, 2004

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 March 31, 2004
Common Stock, $5 Par Value		2,025,528

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

UNAUDITED


	March 31, 2004			September 30, 2003
ASSETS
Current Assets:
Cash and cash equivalents	$	1,499,138		$	135,998
Accounts receivable - (less allowance for uncollectibles of $1,241,065 and and $318,899, respectively)		16,246,029			6,183,162
Inventories		2,224,344			2,559,306
Prepaid gas service		55,889			14,782,752
Prepaid income taxes		—			1,079,802
Deferred income taxes		2,821,091			1,605,509
Under-recovery of gas costs		476,099			790,126
Other		618,613			541,322

Total current assets		23,941,203			27,677,977

Property, Plant And Equipment:
Utility plant in service		98,759,238			96,385,022
Accumulated depreciation and amortization		(34,282,157	)		(33,136,643	)

Utility plant in service, net		64,477,081			63,248,379
Construction work in progress		2,366,982			1,992,222

Utility Plant, Net		66,844,063			65,240,601

Nonutility property		21,189,561			20,793,278
Accumulated depreciation and amortization		(9,260,742	)		(8,832,823	)

Nonutility property, net		11,928,819			11,960,455

Total property, plant and equipment		78,772,882			77,201,056

Other Assets:
Goodwill		298,314			298,314
Other assets		702,798			769,754

Total other assets		1,001,112			1,068,068

Total Assets	$	103,715,197		$	105,947,101

See notes to condensed consolidated financial statements.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

UNAUDITED


	March 31, 2004			September 30, 2003
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	33,557		$	1,032,372
Borrowings under lines of credit		3,905,000			12,992,000
Dividends payable		597,990			571,458
Accounts payable		7,336,039			9,289,899
Income taxes payable		2,323,094			—
Customer deposits		730,491			477,465
Accrued expenses		4,859,947			4,798,106
Refunds from suppliers - due customers		24,841			42,320
Overrecovery of gas costs		3,620,173			1,172,585
Fair value of marked to market transactions		218,687			319,264

Total current liabilities		23,649,819			30,695,469

Long-term Debt, Excluding Current Maturities		30,202,907			30,219,987

Deferred Credits:
Asset retirement obligations		5,943,346			5,449,702
Deferred income taxes		5,707,137			5,457,991
Deferred investment tax credits		249,754			266,338

Total deferred credits		11,900,237			11,174,031

Stockholders’ Equity:
Common stock, $5 par value; authorized, 10,000,000 shares; issued and outstanding 2,025,528 and 2,003,232 shares, respectively		10,127,640			10,016,160
Preferred stock, no par, authorized, 5,000,000 shares; 0 shares issued and outstanding in both 2004 and 2003		—			—
Capital in excess of par value		12,376,245			11,977,084
Retained earnings		15,594,022			12,018,920
Accumulated comprehensive loss		(135,673	)		(154,550	)

Total stockholders’ equity		37,962,234			33,857,614

Total Liabilities and Stockholders’ Equity	$	103,715,197		$	105,947,101

See notes to condensed consolidated financial statements.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

FOR THE THREE-MONTH AND SIX-MONTH PERIODS ENDED MARCH 31, 2004 AND 2003

UNAUDITED


	Three Months Ended March 31,				Six Months Ended March 31,
	2004		2003		2004		2003
Operating Revenues:
Gas utilities	$	34,497,420	$	30,192,554	$	59,729,908	$	51,285,821
Propane operations		7,368,558		7,502,674		11,736,173		11,952,450
Energy marketing		5,156,908		3,288,209		9,650,321		6,004,771
Other		106,061		239,133		313,317		435,655

Total operating revenues		47,128,947		41,222,570		81,429,719		69,678,697

Cost of Sales:
Gas utilities		26,406,106		22,562,747		45,038,599		37,494,240
Propane operations		3,914,738		3,594,521		6,299,757		5,699,044
Energy marketing		5,075,244		3,216,684		9,512,231		5,860,315
Other		41,650		137,646		130,350		248,329

Total cost of sales		35,437,738		29,511,598		60,980,937		49,301,928

Operating Margin		11,691,209		11,710,972		20,448,782		20,376,769

Other Operating Expenses:
Operations		3,778,584		3,756,994		7,210,433		7,167,896
Maintenance		346,362		408,581		700,433		769,487
General taxes		550,182		497,746		1,020,645		956,822
Depreciation and amortization		1,346,060		1,316,132		2,715,578		2,651,661

Total other operating expenses		6,021,188		5,979,453		11,647,089		11,545,866

Operating Income		5,670,021		5,731,519		8,801,693		8,830,903
Other Expenses, net		45,828		68,742		44,947		108,051
Interest Expense		523,808		551,284		1,068,774		1,105,860

Income Before Income Taxes		5,100,385		5,111,493		7,687,972		7,616,992
Income Tax Expense		1,952,133		1,970,540		2,940,317		2,937,902

Net Income	$	3,148,252	$	3,140,953	$	4,747,655	$	4,679,090

Basic Earnings Per Common Share	$	1.56	$	1.59	$	2.36	$	2.37

Diluted Earnings Per Common Share	$	1.55	$	1.59	$	2.34	$	2.37

See notes to condensed consolidated financial statements.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

FOR THE THREE-MONTH AND SIX-MONTH PERIODS ENDED MARCH 31, 2004 AND 2003

UNAUDITED


	Three Months Ended March 31,						Six Months Ended March 31,
	2004			2003			2004			2003
Net Income	$	3,148,252		$	3,140,953		$	4,747,655		$	4,679,090
Reclassification of gain transferred to net income		(28,946	)		(190,640	)		(9,296	)		(264,412	)
Unrealized gain (loss) on cash flow hedges		(12,056	)		62,478			28,173			(20,560	)

Other comprehensive income (loss), net of tax		(41,002	)		(128,162	)		18,877			(284,972	)

Comprehensive Income	$	3,107,250		$	3,012,791		$	4,766,532		$	4,394,118

See notes to condensed consolidated financial statements.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE SIX-MONTH

PERIODS ENDED MARCH 31, 2004 AND 2003

UNAUDITED


	Six Months Ended March 31,
	2004			2003
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	4,747,655		$	4,679,090
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation and amortization		2,836,648			2,763,638
Gain on disposal of property		(25,114	)		(32,961	)
Deferred taxes and investment tax credits		(983,020	)		(754,746	)
Changes in assets and liabilities which provided cash, exclusive of changes and noncash transactions shown separately		9,414,963			3,154,686

Net cash provided by operating activities		15,991,132			9,809,707

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant and nonutility property		(3,950,035	)		(4,171,626	)
Cost of removal of utility plant, net		(31,858	)		(10,054	)
Proceeds from disposal of equipment		92,177			313,102

Net cash used in investing activities		(3,889,716	)		(3,868,578	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		2,000,000			8,000,000
Retirement of long-term debt and capital leases		(2,140,895	)		(64,793	)
Net (repayments) under lines of credit		(9,962,000	)		(12,957,000	)
Cash dividends paid		(1,146,022	)		(1,121,508	)
Proceeds from issuance of stock		510,641			409,397

Net cash (used in) financing activities		(10,738,276	)		(5,733,904	)

NET INCREASE IN CASH AND CASH EQUIVALENTS		1,363,140			207,225
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		135,998			288,030

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	1,499,138		$	495,255

SUPPLEMENTAL INFORMATION:
Interest paid	$	1,126,780		$	1,118,733
Income taxes paid (refunded), net	$	531,991		$	(250,067	)

Noncash transactions:

The Company executed a $2,000,000 intermediate term note in October 2003, which resulted in the reclassification of $1,125,000 from current maturities of long-term debt and $875,000 from borrowings under lines of credit to long-term debt on the September 30, 2003, balance sheet as the Company met the requirements for making the reclassification.

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 March 31, 2004 and the results of its operations for the three months and six months ended March 31, 2004 and 2003 and its cash flows for the six months ended March 31, 2004. Because of seasonal and other factors, the results of operations for the three months and six months ended March 31, 2004 are not indicative of the results to be expected for the fiscal year ending September 30, 2004. 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.

On October 16, 2003, Roanoke Gas Company placed into effect rates providing for $1.8 million in additional non gas revenues subject to refund. On March 15, 2004, the Virginia State Corporation Commission (SCC) issued their final order on Roanoke Gas Company’s expedited rate case allowing for an annual increase in revenues of $1.54 million. Effective with April billings, Roanoke Gas Company adjusted its rates and began refunding excess billings above the final rate award. Since the implementation of the new rates in October, the Company had recorded an estimated monthly provision for refund pending the receipt of a final order. Based upon the final award, a total of $191,579 in rate refund and accrued interest was included in accrued expenses on the Balance Sheet.

Effective April 1, 2004, the Company and Wachovia Bank renewed the Company’s line-of-credit agreements. The new agreements maintained the same variable interest rates based upon 30 day LIBOR; however, the Company agreed to establish a five-tier level for borrowing limits to accommodate its seasonal borrowing demands. Generally, the Company’s borrowing needs are at their lowest in Spring, increase during the Summer and Fall due to gas prepayments 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. Effective April 1, 2004, the Company’s total available lines of credit were set at $11,000,000. On July 16, 2004, the total available lines of credit increase to $15,000,000. On September 16, 2004, the total available lines of credit increase to $23,000,000. On November 16, 2004, the total lines of credit increase to $27,000,000. And on February 16, 2005, the total lines of credit reduce to $22,000,000. The line-of-credit agreements will expire March 31, 2005, unless extended. The Company anticipates being able to extend or replace the credit lines upon expiration. At March 31, 2004, the Company had $3,905,000 outstanding under its line of credit agreements.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

UNAUDITED

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

The Company has historically entered into futures, swaps and caps for the purpose of hedging the price of propane in order to provide price stability during the winter months. During 2003, the Company had entered into propane price cap arrangements due to the uncertainty of energy prices during the current heating season. The price caps provide protection against increasing prices and allow the Company to benefit from reductions in energy prices. The price caps qualify as cash flow hedges; therefore, changes in the fair value are reported in other comprehensive income. No portion of the hedges were ineffective during the three months and six months ended March 31, 2004 and 2003.

In addition, the Company has historically entered into futures, swaps and caps for the purpose of hedging the price of natural gas in order to provide price stability during the winter months. During 2003, the Company had entered into both price caps and swap arrangements for the purchase of natural gas. The fair value of these instruments is recorded in the balance sheet with the offsetting entry to over-recovery or under-recovery of gas costs. Net income and other comprehensive income are not affected by the change in market value as any cost incurred or benefit received from these instruments is recoverable or refunded through the regulated natural gas purchased gas adjustment (PGA) mechanism. Both the Virginia State Corporation Commission (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.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

UNAUDITED

A summary of the derivative activity is provided below:


Three Months Ended March 31, 2004	Propane Derivatives			Interest Rate Swap			Total

Unrealized gains/(losses) on derivatives	$	52,665		$	(71,256	)	$	(18,591	)
Income tax (expense)/benefit		(20,513	)		27,048			6,535

Net unrealized gains/(losses)		32,152			(44,208	)		(12,056	)

Transfer of realized losses/(gains) to income		(90,045	)		41,950			(48,095	)
Income tax benefit/expense		35,073			(15,924	)		19,149

Net transfer of realized losses/(gains) to income		(54,972	)		26,026			(28,946	)

Net other comprehensive loss	$	(22,820	)	$	(18,182	)	$	(41,002	)

Three Months Ended March 31, 2003	Propane Derivatives			Interest Rate Swap			Total

Unrealized gains/(losses) on derivatives	$	169,835		$	(66,420	)	$	103,415
Income tax (expense)/benefit		(66,150	)		25,213			(40,937	)

Net unrealized gains/(losses)		103,685			(41,207	)		62,478

Transfer of realized losses/(gains) to income		(349,385	)		36,525			(312,860	)
Income tax benefit/expense		136,085			(13,865	)		122,220

Net transfer of realized losses/(gains) to income		(213,300	)		22,660			(190,640	)

Net other comprehensive loss	$	(109,615	)	$	(18,547	)	$	(128,162	)

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

UNAUDITED


Six Months Ended March 31, 2004	Propane Derivatives			Interest Rate Swap			Total
Unrealized gains/(losses) on derivatives	$	99,747		$	(52,743	)	$	47,004
Income tax (expense)/benefit		(38,852	)		20,021			(18,831	)

Net unrealized gains/(losses)		60,895			(32,722	)		28,173

Transfer of realized losses/(gains) to income		(99,747	)		83,170			(16,577	)
Income tax benefit/expense		38,852			(31,571	)		7,281

Net transfer of realized losses/(gains) to income		(60,895	)		51,599			(9,296	)

Net other comprehensive income	$	—		$	18,877		$	18,877

Fair value of marked to market transactions		—		$	(218,687	)	$	(218,687	)

Accumulated comprehensive loss		—		$	(135,673	)	$	(135,673	)

Six Months Ended March 31, 2003	Propane Derivatives			Interest Rate Swap			Total
Unrealized gains/(losses) on derivatives	$	250,334		$	(279,480	)	$	(29,146	)
Income tax (expense)/benefit		(97,505	)		106,091			8,586

Net unrealized gains/(losses)		152,829			(173,389	)		(20,560	)

Transfer of realized losses/(gains) to income		(470,225	)		36,525			(433,700	)
Income tax benefit/expense		183,153			(13,865	)		169,288


Net transfer of realized losses/(gains) to income		(287,072	)		22,660			(264,412	)

Net other comprehensive loss	$	(134,243	)	$	(150,729	)	$	(284,972	)

Fair value of marked to market transactions		—		$	(242,955	)	$	(242,955	)

Accumulated comprehensive loss		—		$	(150,729	)	$	(150,729	)

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

UNAUDITED

Basic earnings per common share are based on the weighted average number of shares outstanding during each period. The weighted average number of shares outstanding for the three-month and six-month periods ended March 31, 2004 were 2,021,131 and 2,015,659 compared to 1,978,541 and 1,973,028 for the same periods last year. The weighted average number of shares outstanding assuming dilution were 2,034,666 and 2,028,266 for the three-month and six month periods ended March 31, 2004 compared to 1,981,605 and 1,974,852 for the same periods last year. The difference between the weighted average number of shares for the calculation of basic and diluted earnings per share relates to the dilutive effect associated with the assumed issuance of stock options as calculated using the Treasury Stock method.

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


	Natural Gas	Propane	Energy Marketing	Other	Total
For the Three Months Ended March 31, 2004
Operating revenues	34,497,420	7,368,558	5,156,908	106,061	47,128,947
Operating margin	8,091,314	3,453,820	81,664	64,411	11,691,209
Income before income taxes	3,171,587	1,798,883	68,520	61,395	5,100,385
Gross additions to long-lived assets	1,904,497	325,003	—	8,169	2,237,669
For the Three Months Ended March 31, 2003
Operating revenues	30,192,554	7,502,674	3,288,209	239,133	41,222,570
Operating margin	7,629,807	3,908,153	71,525	101,487	11,710,972
Income before income taxes	2,771,784	2,184,209	58,608	96,892	5,111,493
Gross additions to long-lived assets	1,723,179	556,598	—	—	2,279,777
For the Six Months Ended March 31, 2004
Operating revenues	59,729,908	11,736,173	9,650,321	313,317	81,429,719
Operating margin	14,691,309	5,436,416	138,090	182,967	20,448,782
Income before income taxes	5,123,525	2,272,630	113,939	177,878	7,687,972
Gross additions to long-lived assets	3,167,402	774,337	—	8,296	3,950,035
As of March 31, 2004:
Total assets	85,226,277	15,212,692	2,477,036	799,192	103,715,197
For the Six Months Ended March 31, 2003
Operating revenues	51,285,821	11,952,450	6,004,771	435,655	69,678,697
Operating margin	13,791,581	6,253,406	144,456	187,326	20,376,769
Income before income taxes	4,354,298	2,959,491	121,641	181,562	7,616,992
Gross additions to long-lived assets	2,823,645	1,347,981	—	—	4,171,626
As of March 31, 2003:
Total assets	80,794,794	15,916,118	2,012,405	542,961	99,266,278

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

UNAUDITED

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. The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of FASB Statement No. 123, Accounting for Stock-Based Compensation, to the options granted under the Plan.


	3 Months Ended March 31					6 Months Ended March 31
	2004		2003			2004		2003
Net income, as reported	$	3,148,252	$	3,140,953		$	4,747,655	$	4,679,090
Deduct: Total stock-based employee compensation expense determined under fair value method for all awards, net of tax		—		(15,221	)		—		(15,221	)

Pro forma net income	$	3,148,252	$	3,125,732		$	4,747,655	$	4,663,869

Earnings per share:
Basic - as reported	$	1.56	$	1.59		$	2.36	$	2.37

Basic - pro forma	$	1.56	$	1.58		$	2.36	$	2.36

Diluted - as reported	$	1.55	$	1.59		$	2.34	$	2.37

Diluted - pro forma	$	1.55	$	1.58		$	2.34	$	2.36

Weighted Average Shares		2,021,131		1,978,541			2,015,659		1,973,028
Diluted Average Shares		2,034,666		1,981,605			2,028,266		1,974,852

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

UNAUDITED

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


	Three Months Ended March 31						Six Months Ended March 31
	2004			2003			2004			2003
Components of net periodic pension cost:
Service cost	$	95,397		$	75,217		$	190,794		$	150,434
Interest cost		153,347			150,569			306,694			301,138
Expected return on plan assets		(127,100	)		(127,535	)		(254,200	)		(255,070	)
Amortization of unrecognized transition obligation		—			283			—			566
Recognized loss		30,888			5,856			61,776			11,712

Net periodic pension cost	$	152,532		$	104,390		$	305,064		$	208,780


	Three Months Ended March 31						Six Months Ended March 31
	2004			2003			2004			2003
Components of net periodic postretirement benefit cost:
Service cost	$	50,414		$	42,877		$	100,828		$	85,754
Interest cost		136,776			138,855			273,552			277,710
Expected return on plan assets		(33,630	)		(30,410	)		(67,260	)		(60,820	)
Amortization of unrecognized transition obligation		59,325			59,325			118,650			118,650
Recognized loss		28,225			14,977			56,450			29,954

Net periodic benefit cost	$	241,110		$	225,624		$	482,220		$	451,248

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

UNAUDITED

The pension plan and post retirement plan liabilities are included in accrued expenses on the Balance Sheet. Total estimated employer funding contributions during the fiscal year ended September 30, 2004 are $800,000 for the defined benefit plan and $750,000 for post retirement benefits.

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.

10.

The Company adopted SFAS No. 143, Accounting for Asset Retirement Obligations, on October 1, 2002. SFAS No. 143 requires the reporting at fair value of a legal obligation associated with the retirement of tangible long-lived assets that result from acquisition, construction or development. Management has determined that the Company has no material legal obligations for the retirement of its assets. However, the Company provides a provision, as part of its depreciation expense, for the ultimate cost of asset retirements and removal. Removal costs are not a legal obligation as defined by SFAS No. 143 but rather the result of cost-based regulation and therefore accounted for under the provisions of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. Upon adoption of SFAS No. 143, the Company classified removal costs that do not have an associated legal retirement obligation as a regulatory liability, in accordance with regulatory treatment.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

UNAUDITED

The Company also adopted SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, on October 1, 2002. The adoption of the standard had no material impact on the Company’s financial position or results of operations.

On January 12, 2004, the Financial Accounting Standards Board issued FASB Staff Position (FSP) 106-1, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003. This FASB Staff Position was issued in response to the new law that introduces a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. In accordance with FSP 106-1, the Company is disclosing the existence of the Act and indicating its intention to elect to defer the accounting for the Act due to the inability to accurately assess the impact to the Company and the absence of sufficient guidance on accounting for this Act. As such, the accumulated postretirement benefit obligation and net periodic postretirement benefit cost included in the condensed financial statements and accompanying notes do not reflect the effects of the Act on the Company’s postretirement benefit plan. Furthermore, when guidance is issued related to accounting for the federal subsidy, the information currently included in the financial statements could change. The Company is currently evaluating the need to amend its medical and postretirement benefit plan in order to maximize any benefits offered from the new Act.

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

General

RGC Resources, Inc. is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately 59,800 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.

RGC Resources, Inc. also provides unregulated energy products through Diversified Energy Company, which operates as Highland Propane Company and Highland Energy Company. Highland Propane sells and distributes propane to approximately 18,500 customers in western Virginia and southern West Virginia. Highland Energy brokers natural gas to several industrial transportation customers of Roanoke Gas Company and Bluefield Gas Company. Propane sales have become a more significant portion of the consolidated operation with a historical growth rate that exceeds the growth in natural gas customers.

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

Management views warm winter weather; energy conservation, fuel switching and bad debts due to high energy prices; and competition from alternative fuels each as factors that could have a significant impact on the Company’s earnings.

For the quarter ended March 31, 2004, rising energy prices continued to be a primary concern for management as higher prices have reduced consumption through customer conservation and increased concerns of the effect of competition from alternative energy sources. In addition, warmer weather has led to reduced deliveries of both natural gas and propane as compared to the same period last year.

Results of Operations

Consolidated net income for the three-month period and six-month periods ended March 31, 2004 was $3,148,252 and $4,747,655, respectively, compared to $3,140,953 and $4,679,090 for the same period last year.

Total operating revenues for the three months ended March 31, 2004 increased by $5,906,377, or 14 percent, compared to the same period last year, due to increasing gas costs and implementation of base rate increases. The average unit cost of natural gas and propane delivered to customers increased by 25 percent and 14 percent, respectively. Sales volumes declined for both the natural gas and propane activity with total regulated natural gas deliveries decreasing by 2 percent, while propane deliveries declined by 4 percent. The total number of

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

heating degree-days (an industry measure by which the average daily temperature falls below 65 degrees Fahrenheit) declined by 4 percent from the same period last year. Energy marketing volumes, on the other hand, increased by 45 percent due in part to the recovering economy and to sales to several customers who had purchased natural gas from other sources in the prior year. Other revenues declined 56 percent due the sale of nearly 400 propane tanks to low volume customers in the prior year not repeated in the current year.


	Quarter Ended 3/31/04	Quarter Ended 3/31/03	Increase/ (Decrease)		Percentage
Operating Revenues
Gas Utilities	34,497,420	30,192,554	4,304,866		14	%
Propane Operations	7,368,558	7,502,674	(134,116	)	-2	%
Energy Marketing	5,156,908	3,288,209	1,868,699		57	%
Other	106,061	239,133	(133,072	)	-56	%

Total Operating Revenues	47,128,947	41,222,570	5,906,377		14	%

Total operating margin was nearly equal to the same period last year with a decline of less than 1 percent for the quarter ended March 31, 2004. Regulated natural gas margins increased by $461,507, or 6 percent, even though total delivered volume (tariff and transporting) decreased by 83,613 dekatherms, or 2 percent. Tariff sales, primarily consisting of residential and commercial usage, declined 6 percent due to the 4 percent decline in heating degree-days from the same period last year. The larger percentage decline in volume as compared to the percentage decline in degree-days is an indication of possible conservation and fuel switching on the part of customers in reaction to the high energy prices. Transporting volumes, consisting of transportation services for natural gas purchased from other than the regulated utilities, generally correlate more with economic conditions rather than weather. As such, transportation volumes provided a strong increase of 23 percent, reflecting continued improvement in the economy and increased industrial production. Even though high energy prices do not appear to have affected the demand for delivery of transportation gas, continued high prices could result in some customers seeking lower cost alternative fuel sources depending upon the competitive relationships between natural gas and other energy sources. Although total natural gas delivered volumes declined, regulated natural gas margins increased due to a non gas cost rate increase effective October 16, 2003 for Roanoke Gas Company and the implementation of a new billing rate structure in April 2003 which allowed Roanoke Gas Company to recover the specific costs associated with financing its investment in gas inventory and prepaid gas service. Both Roanoke Gas Company and Bluefield Gas Company placed increased rates into effect during the quarter ended December 31, 2003. Roanoke Gas Company’s rates were placed into effect subject to refund pending a final order from the Virginia SCC. Management has received the final order on the Roanoke Gas rate case and began refunding overcollections to customers in the April billing

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

cycle. The revenues and margins included in the income statement reflect the provision for refund. 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 $147,000 in additional customer base charges, which is a flat monthly fee billed to each natural gas customer, and approximately $590,000 associated with increase in the volumetric price of natural gas. More information regarding the rate increase may be found under the Regulatory Affairs section below.

Furthermore, prior to April 2003, billing rates for Roanoke Gas Company customers included a component to recover the financing costs of natural gas inventory and prepaid gas service based upon historical inventory levels and historical interest rates and the allowed rate of return on equity. Therefore, when costs increased, the Company had to absorb the higher financing costs without immediate rate relief. The new rate structure provides for a different recovery mechanism, which also results in different timing of revenue recognition. The Company is able to recover higher financing costs related to increased inventory and prepaid gas balances arising from higher gas costs; conversely, the Company will pass along savings to customers if financing costs decrease due to lower inventory and prepaid gas balances resulting from reductions in gas costs. The new rate structure resulted in the recognition of additional revenue related to the recovery of these financing costs during fiscal 2003. Under the new rate structure, the revenue associated with the calculated carrying cost is accrued based upon gas inventory and prepaid gas levels, primarily during the summer and fall as gas is being injected into storage. Under the previous rate structure, the majority of the revenue was recorded in winter and early spring when customers were billed for higher levels of gas consumption. As a result of the new rate structure, the Company recorded approximately $210,000 less revenue and margin related to the carrying costs during the current quarter. The $210,000 is composed of approximately $270,000 related to a reduction in revenue due to timing differences while a $60,000 increase in revenues was associated with recovery of financing costs on higher cost inventory and prepaid gas balances.


	Quarter Ended 3/31/04	Quarter Ended 3/31/03	Increase/ (Decrease)		Percentage
Operating Margin
Gas Utilities	8,091,314	7,629,807	461,507		6	%
Propane Operations	3,453,820	3,908,153	(454,333	)	-12	%
Energy Marketing	81,664	71,525	10,139		14	%
Other	64,411	101,487	(37,076	)	-37	%

Total Operating Margin	11,691,209	11,710,972	(19,763	)	0	%

Propane margins decreased by $454,333, or 12 percent, on a 201,377, or 4 percent, gallon decline in deliveries from the same period last year. The decrease in margin is attributable to

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

reduced volumes related to warmer weather and the realization of $349,385 in derivative gain during the quarter ended March 31, 2003 compared to a derivative gain of only $90,045 during the current quarter. High propane prices and competition also contributed to the decline in margin due to price resistance and conservation from customers. The energy marketing division margin increased by $10,139, or 14 percent, as total sales volume increased by 239,048 dekatherms, or 45 percent. The increase in sales volumes was associated with improving economic conditions and the sales to a few customers supplied by other markets in the prior year. The decline in unit margin was expected as the current unit margins for the energy marketing operations reflect current and long-term market expectations due to higher energy prices and competition. Other margins decreased by $37,076, or 37 percent, due to the sale of propane tanks as discussed above.

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


	Quarter Ended 3/31/04	Quarter Ended 3/31/03	Increase/ (Decrease)		Percentage
Delivered Volumes
Regulated Natural Gas (DTH)
Tariff Sales	3,917,879	4,168,623	(250,744	)	-6	%
Transportation	908,246	741,115	167,131		23	%

Total	4,826,125	4,909,738	(83,613	)	-2	%
Propane (Gallons)	4,532,689	4,734,066	(201,377	)	-4	%
Highland Energy (DTH)	773,786	534,738	239,048		45	%
Heating Degree-Days (Unofficial)	2,164	2,260	(96	)	-4	%

Operations expenses increased by $21,590, or less than one percent, for the three-month period ended March 31, 2004 compared to the same period last year. Maintenance expenses declined $62,219, or 15 percent, from the same period last year as the number of leak repairs during the quarter declined in addition to timing of work performed on corrosion maintenance.

General taxes increased $52,436, or 11 percent, for the three-month period ended March 31, 2004 compared to the same period last year 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.

Depreciation expense increased 29,928, or 2 percent on a 7 percent increase in gross plant. The increase in depreciation expense was smaller than expected due to the implementation of new

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

depreciation rates for Roanoke Gas Company effective January 1, 2004. A depreciation study was completed and the new rates were approved by the State Corporation Commission of Virginia (SCC). These new depreciation rates will result in approximately $100,000 less depreciation expense on an annual basis, based on current plant account balances.

Interest expense decreased by $27,476, or nearly 5 percent, even though the Company’s average total debt position during the current quarter increased by 8 percent over the same period last year. The increase in average total debt for the quarter was attributable to capital budget expenditures and the funding of higher accounts receivable balances and prepaid gas service related to higher energy prices. The overall average interest rate on total debt decreased from 5.52 percent to 4.86 percent. The decline in the overall average interest rate was attributed to the 15 percent decline in the Company’s average short-term line-of-credit rates as a result of the current interest rate environment and lower interest rates on the variable rate portion of the Company’s long-term debt.

Income tax expense decreased by $18,407, which corresponds to a decrease in pre-tax income for the quarter.

For the six-month period ended March 31, 2004, total operating margin increased $72,013, or less than 1 percent, over the same period last year. Regulated natural gas margin increased $899,728 or 7 percent, on a more than 2 percent decline in total natural gas deliveries from the same period last year. Total tariff sales, primarily comprised of weather sensitive residential and commercial customers, declined by 7 percent attributable to weather that had 7 percent fewer heating degree days. Transportation sales deliveries, composed of large industrial customers, rose by more than 18 percent due to increased economic activity. The increase in the regulated natural gas margin was attributable to the rate increases placed into effect in the first quarter for both Roanoke Gas and Bluefield Gas. The total annual effect of the rate increase is approximately $1.7 million in additional margin with most of the increase attributable to the volumetric side and therefore realized during the winter months.


	Y-T-D 3/31/04	Y-T-D 3/31/03	Increase/ (Decrease)		Percentage
Operating Margin
Gas Utilities	14,691,309	13,791,581	899,728		7	%
Propane Operations	5,436,416	6,253,406	(816,990	)	-13	%
Energy Marketing	138,090	144,456	(6,366	)	-4	%
Other	182,967	187,326	(4,359	)	-2	%

Total Operating Margin	20,448,782	20,376,769	72,013		0	%

Propane margins declined $816,990, or 13 percent, as total gallons delivered dropped by 6 percent. Warmer winter weather caused the decline in sales volume and margin, while lower derivative gains contributed to the decline in margin. Propane operations realized a derivative

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

gain of $99,747 associated with derivative financial instruments during the current period; however, for the same period last year, propane operations realized a derivative gain of $470,225 on similar instruments. The consistently high energy prices have made it more difficult to realize gains on derivative hedge contracts, and, while management intends to continue using such instruments for the purposes of providing price stability, benefits similar to those realized last year are not anticipated to continue in the future. Energy marketing margins declined $6,366, or 4 percent, on a 35 percent increase in volumes. The increase in sales volumes was associated with improving economic conditions and the return of a few customers from other marketers. The Company’s current and long-term market expectations are that the current unit margins will continue to be pressured by higher energy prices and competition. Other margins decreased by $4,359, or 2 percent, due to the gains associated with the sale of propane tanks in the prior year.

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


	Y-T-D 3/31/04	Y-T-D 3/31/03	Increase/ (Decrease)		Percentage
Delivered Volumes
Regulated Natural Gas (DTH)
Tariff Sales	6,644,992	7,129,555	(484,563	)	-7	%
Transportation	1,768,447	1,493,522	274,925		18	%

Total	8,413,439	8,623,077	(209,638	)	-2	%
Propane (Gallons)	7,594,952	8,083,552	(488,600	)	-6	%
Highland Energy (DTH)	1,514,903	1,118,603	396,300		35	%
Heating Degree-Days (Unofficial)	3,651	3,934	(283	)	-7	%

Other operations expenses increased by $42,537 or 1 percent for the six-month period ended March 31, 2004 compared to the same period last year. Maintenance expense decreased $69,054, or 9 percent, as the number of leak repairs during the quarter declined in addition to timing of work performed on corrosion maintenance.

General taxes increased $63,823, or 7 percent, for the six-month period ended March 31, 2004 compared to the same period last year primarily as a result of higher West Virginia B&O taxes, a revenue sensitive tax, associated with increased revenues for Bluefield Gas. Depreciation increased $63,917, or 2 percent, on increased investment in gross plant partially offset by a net reduction in the depreciation rates for Roanoke Gas Company as discussed above.

Interest expense decreased by $37,086, or 3 percent, even though average borrowing levels for the period increased by more than 10 percent over average borrowing levels for the same period

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

last year. The average overall interest rate declined from 5.29 percent to 4.66 percent from the same period last year due to reductions in the interest rates under the Company’s line-of-credit agreements and the variable rate portion of the Company’s long-term debt. Income tax expense increased $2,415, or less than 1 percent, corresponding to a small increase in pretax income.

The three-month and six-month earnings presented herein should not be considered as reflective of the Company’s consolidated financial results for the fiscal year ending September 30, 2004. The total revenues and margins during the first six months reflect higher billings due to the weather sensitive nature of the gas business. Due to the seasonal nature of the Company’s energy business, the final two quarters of the fiscal year tend to generate losses. Any improvement or decline in earnings depends primarily on weather in the months of April and May and the level of operating and maintenance costs during the remaining months.

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.

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

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

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 commodities of propane and natural gas. Changes in the commodity and futures markets will impact the estimates of fair value in the future. Furthermore, the actual market value at the point of realization of the derivative may be significantly different from the futures value used in determining fair value in prior financial statements.

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

Asset Management

Effective November 1, 2001, Roanoke Gas Company and Bluefield Gas Company (the Companies) entered into a contract with a third party (counter-party) to provide future gas supply needs. The counter-party has also assumed the management and financial obligation of the Company’s firm transportation and storage agreements. In connection with the agreement, the Companies exchanged gas in storage at November 1, 2001 for the right to receive an equal amount of gas in the future as provided by the agreement. As a result of this arrangement, natural gas inventories on the balance sheet are replaced with a new classification called “prepaid gas service.” This contract expires on October 31, 2004. Management is currently in the process of soliciting bids for the replacement of this contract.

Under the asset management agreement, the Companies no longer have title or ownership of the physical asset; instead, the Companies make monthly payments for the right to receive gas in the

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

future. Therefore, a greater risk exists regarding the ultimate realization of the prepayment depending on the ongoing viability of the counter-party. The Companies have attempted to mitigate the risks in the event of a failure to perform or bankruptcy on the part of the counter-party by requiring certain contractual restrictions on inventory and other provisions.

Energy Costs

Natural gas and propane commodity prices have remained at unusually high levels over the last several quarters, and the Company entered this past heating season with its highest embedded prepaid and inventory gas costs. Management perceives a significant reason for high energy prices is 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 will continue to decline. In addition, increased demand for natural gas from electric generation facilities will likely keep natural gas prices at elevated levels. Management believes it was successful in fulfilling customers energy needs for the past winter. However, elevated gas prices and supply management will continue to be challenging. The Company expects to continue to utilize various hedging mechanisms including summer storage injections, financial instruments and fixed price contracts to limit weather driven volatility in energy prices.

Natural gas costs are fully recoverable under the present regulatory Purchased Gas Adjustment (PGA) mechanisms, and increases and decreases in the cost of gas are passed through to the Company’s customers. The unregulated propane and energy marketing operations are able to more rapidly adjust pricing structures to compensate for increasing costs. However, due to the competitive nature of these unregulated markets, there can be no assurance that the Company can adjust its pricing to sufficiently recover cost increases without negatively affecting sales and competitive position.

Although rising energy prices are recoverable through the PGA mechanism for the regulated operations, high energy prices may have a negative impact on earnings through increases in bad debt expense and higher interest costs because the delay in recovering higher gas costs requires borrowing to temporarily fund higher receivables from customers and LNG (liquefied natural gas) inventory and prepaid gas service levels. As discussed in the results of operations, the new rate structure implemented in April 2003 will provide the Company a level of protection against the impact that rising energy prices may have on bad debts and carrying costs on LNG storage and prepaid gas service by allowing for more timely recovery of these costs. However, this new rate structure will not protect the Company from increased rate of bad debts or increases in interest rates.

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

Regulatory Affairs

On October 16, 2003, Roanoke Gas placed into effect rates providing for $1.8 million in additional non gas revenues subject to refund. On March 15, 2004 the SCC issued their final order on Roanoke Gas Company’s expedited rate case allowing for an annual increase in revenues of $1.54 million. Effective with April billings, Roanoke Gas Company adjusted its rates and began refunding excess billings above the final rate award. Since the implementation of the new rates in October, the Company has recorded an estimated monthly provision for refund pending the receipt of a final order. Based upon the final award, a total of $191,579 in rate refund and accrued interest was included in accrued expenses on the Balance Sheet.

In addition, Bluefield Gas Company placed into effect new base rates effective for service rendered on and after December 4, 2003. The case was settled with a final order from the West Virginia PSC approving an increase in annual rates of $112,000 in addition to a provision to recover the deferred expense associated with the restoration of service to customers resulting from the gas line rupture in January 2003. A $0.05 per billing unit is included in Bluefield Gas customers’ billings until the deferred expenses are fully recovered. Bluefield Gas Company filed a new application for increased rates in January 2004 and the audit by the West Virginia Public Service Commission Staff is in progress.

Environmental Issues

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

Capital Resources and Liquidity

The Company’s primary capital needs are for the funding of its continuing construction program and the seasonal funding of its accounts receivable, LNG storage and gas prepayment requirements under the asset management contract. 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 and propane service to new customers. Total capital expenditures were $2,237,669 and $2,279,777 for the three-month periods ended March 31, 2004 and 2003, respectively. The Company’s total capital budget for the current year is approximately $7,200,000. 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.

The Company also funds seasonal levels of gas prepayments, LNG storage and accounts receivables. From April through October, the Company prepays its asset manager for the right to receive additional natural gas in the colder winter months. This gas prepayment replaces the old underground natural gas storage that was used prior to the asset management contract. Furthermore, a majority of the Company’s sales and billings occur during the winter months. As a result, accounts receivable balances increase during these months and decrease during the summer months. Total accounts receivable balances were $16,246,029 and $17,123,901 at March 31, 2004 and 2003, respectively.

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

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

extended. The Company anticipates being able to extend or replace the credit lines upon expiration. At March 31, 2004, the Company had $3,905,000 outstanding under its line-of-credit agreements.

At March 31, 2004, the Company’s capitalization consisted of 44 percent in long-term debt and 56 percent in common equity.

Forward-Looking Statements

From time to time, the Company may publish forward-looking statements relating to such matters as anticipated financial performance, business prospects, technological developments, new products, research and development activities and similar matters. The Private Securities Litigation Reform Act of 1995 provides a safe harbor for forward-looking statements. In order to comply with the terms of the safe harbor, the Company notes that a variety of factors could cause the Company’s actual results and experience to differ materially from the anticipated results or other expectations expressed in the Company’s forward-looking statements. The risks and uncertainties that may affect the operations, performance, development and results of the Company’s business include the following: (i) failure to earn on a consistent basis an adequate return on invested capital; (ii) increasing expenses and labor costs and labor availability; (iii) price competition from alternative fuels; (iv) volatility in the price and availability of natural gas and propane; (v) uncertainty in the projected rate of growth of natural gas and propane requirements in the Company’s service area; (vi) general economic conditions both locally and nationally; (vii) increases in interest rates; (viii) increased customer delinquencies and conservation efforts resulting from high fuel costs and/or colder weather; (ix) developments in electricity and natural gas deregulation and associated industry restructuring; (x) variations in winter heating degree-days from normal; (xi) changes in environmental requirements and cost of compliance; (xii) impact of potential increased governmental oversight and compliance costs due to the Sarbanes-Oxley law; (xiii) cost and availability of property and liability insurance in the wake of terrorism concerns and corporate failures; (xiv) ability to raise debt or equity capital in the wake of recent corporate financial irregularities; (xv) impact of uncertainties in the Middle East; (xvi) failure of Congress to pass a comprehensive energy policy could serve to perpetuate high energy prices; and (xvii) 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, propane operations and energy marketing business. The Company’s risk management policy, as authorized by the Company’s Board of Directors, allows management to enter into 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 March 31, 2004, the Company had $3,905,000 outstanding under its lines of credit, $2,500,000 outstanding on an intermediate-term variable rate note for Highland Propane 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 March 31, 2004 would have resulted in an increase in quarterly interest expense of approximately $21,000. The Company also has an $8,000,000 intermediate term variable rate note that is currently being hedged by a fixed rate interest swap.

The Company manages the price risk associated with purchases of natural gas and propane by using a combination of fixed price contracts, prepaid gas service payments and derivative commodity instruments including futures, price caps, swaps and collars. As of March 31, 2004, all propane derivative contracts had been settled.

During the quarter, the Company had both derivative price caps and swap arrangements for the purpose of hedging the price of natural gas. Any cost incurred or benefit received from the derivative arrangement is recoverable or refunded through the regulated natural gas purchased gas adjustment (PGA) mechanism. Both the Virginia SCC and the West Virginia PSC currently allow for full recovery of prudent costs associated with natural gas purchases, and any additional costs or benefits associated with the settlement of the derivative contract will be passed through to customers when realized. As of March 31, 2004, all natural gas derivative contracts had been settled.

ITEM 4 – CONTROLS AND PROCEDURES

Based on their evaluation of the Company’s disclosure controls and procedures (as defined by Rule 13a-15(e) under the Securities Exchange Act of 1934) as of March 31, 2004, 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 March 31, 2004, 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 March 31, 2004, the Company issued a total of 791.916 shares of restricted stock pursuant to the Restricted Stock Plan as follows:


Investment Date	Price	Number of Shares
1/2/2004	$22.600	219.769
2/2/2004	$22.950	271.603
3/1/2004	$23.040	270.544

On February 2, 2004, the Company issued a total of 142 shares of its common stock as bonuses to certain employees as rewards for performance and length of service. The 142 shares were not issued in a transaction constituting a “sale” within the meaning of section 2(3) of the Act.

ITEM 6 – EXHIBITS AND REPORTS ON FORM 8-K.

(a) Exhibits


Number		Description

10 (p)(p)(p)		Promissory note by and between RGC Resources, Inc. and Wachovia Bank, National Association, in the amount of $1,000,000.

10 (q)(q)(q)		Promissory note by and between Roanoke Gas Company and Wachovia Bank, National Association, in the amount of $19,000,000.

Part II – Other Information



10 (r)(r)(r)		Promissory note by and between Bluefield Gas Company and Wachovia Bank, National Association, in the amount of $5,000,000.

10 (s)(s)(s)		Promissory note by and between Highland Propane Company and Wachovia Bank, National Association, in the amount of $2,000,000.

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

(b) Reports on Form 8-K

On February 17, 2004, the Company filed a current report on Form 8-K, dated February 17, 2004, furnishing under Item 12 thereof a press release announcing the financial results for the quarter ended December 31, 2003, including the applicable financial statements.

SIGNATURES

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


	RGC Resources, Inc.

Date: May 13, 2004	By:	/s/ Howard T. Lyon

		Howard T. Lyon Vice-President, Treasurer and Controller (Principal Financial Officer)