RGC Resources (RGCO) 10-Q 2009 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For Quarterly Period Ended June 30, 2009

Commission File Number 000-26591

RGC Resources, Inc.

(Exact name of Registrant as Specified in its Charter)

VIRGINIA	54-1909697
(State or Other Jurisdiction of Incorporation or Organization)	(I.R.S. Employer Identification No.)
519 Kimball Ave., N.E., Roanoke, VA	24016
(Address of Principal Executive Offices)	(Zip Code)

(540) 777-4427

(Registrant’s Telephone Number, Including Area Code)

None

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ¨    No  ¨

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

Large accelerated filer	¨	Accelerated filer	¨
Non-accelerated filer	¨  (Do not check if a smaller reporting company)	Smaller reporting company	x

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

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

Class	Outstanding at July 31, 2009
Common Stock, $5 Par Value	2,232,525

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

UNAUDITED

	June 30, 2009			September 30, 2008
ASSETS
Current Assets:
Cash and cash equivalents	$	13,354,886		$	875,436
Short-term investments		—			500,000
Accounts receivable - (less allowance for uncollectibles of $477,823 and $63,791, respectively)		3,315,750			5,086,790
Note receivable		87,000			87,000
Materials and supplies		644,946			553,604
Gas in storage		13,480,565			26,122,686
Prepaid income taxes		—			1,479,693
Deferred income taxes		3,625,023			2,187,795
Under-recovery of gas costs		—			1,013,087
Other		927,501			505,761
Total current assets		35,435,671			38,411,852
Utility Property:
In service		116,711,870			113,533,184
Accumulated depreciation and amortization		(41,115,853	)		(39,038,120	)
In service, net		75,596,017			74,495,064
Construction work in progress		1,471,331			1,113,008
Utility plant, net		77,067,348			75,608,072
Other Assets:
Note receivable		1,126,000			1,213,000
Regulatory assets		2,641,439			2,762,241
Other		111,697			132,549
Total other assets		3,879,136			4,107,790
Total Assets	$	116,382,155		$	118,127,714

See notes to condensed consolidated financial statements.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

UNAUDITED

	June 30, 2009			September 30, 2008
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Borrowings under line-of-credit	$	—		$	13,960,000
Dividends payable		713,608			690,538
Accounts payable		5,839,641			8,215,319
Customer credit balances		3,103,269			4,237,043
Income taxes payable		170,025			3,206
Customer deposits		1,596,250			1,522,480
Accrued expenses		1,664,036			2,111,614
Over-recovery of gas costs		6,447,727			—
Fair value of marked-to-market transactions		2,096,781			875,487
Total current liabilities		21,631,337			31,615,687
Long-term Debt		28,000,000			23,000,000
Deferred Credits and Other Liabilities:
Asset retirement obligations		2,704,694			2,608,995
Regulatory cost of retirement obligations		7,469,087			6,843,338
Benefit plan liabilities		5,008,123			4,768,785
Deferred income taxes		5,431,252			5,471,667
Deferred investment tax credits		73,567			96,184
Total deferred credits and other liabilities		20,686,723			19,788,969
Stockholders’ Equity:
Common stock, $5 par value; authorized, 10,000,000 shares; issued and outstanding 2,229,729 and 2,209,471, respectively		11,148,645			11,047,355
Preferred stock, no par, authorized, 5,000,000 shares; no shares issued or outstanding		—			—
Capital in excess of par value		16,415,794			15,990,961
Retained earnings		20,460,337			17,909,134
Accumulated other comprehensive loss		(1,960,681	)		(1,224,392	)
Total stockholders’ equity		46,064,095			43,723,058
Total Liabilities and Stockholders’ Equity	$	116,382,155		$	118,127,714

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

FOR THE THREE-MONTH AND NINE-MONTH PERIODS ENDED JUNE 30, 2009 AND 2008

UNAUDITED

	Three Months Ended June 30,				Nine Months Ended June 30,
	2009		2008		2009			2008
Operating Revenues:
Gas utilities	$	10,355,122	$	19,887,423	$	72,550,797		$	84,791,998
Other		351,867		265,211		901,889			665,922
Total operating revenues		10,706,989		20,152,634		73,452,686			85,457,920
Cost of Sales:
Gas utilities		5,514,482		14,995,978		50,579,199			64,120,353
Other		177,393		101,246		430,017			260,512
Total cost of sales		5,691,875		15,097,224		51,009,216			64,380,865
Gross Margin		5,015,114		5,055,410		22,443,470			21,077,055
Other Operating Expenses:
Operations		2,445,330		2,351,326		7,829,924			7,458,821
Maintenance		447,508		338,556		1,234,772			1,014,965
General taxes		297,202		285,856		927,379			888,698
Depreciation and amortization		1,160,479		1,092,263		3,439,514			3,268,023
Total other operating expenses		4,350,519		4,068,001		13,431,589			12,630,507
Operating Income		664,595		987,409		9,011,881			8,446,548
Other Income, net		12,686		63,866		68,376			124,933
Interest Expense		460,463		490,756		1,454,693			1,573,267
Income from Continuing Operations Before Income Taxes		216,818		560,519		7,625,564			6,998,214
Income Tax Expense from Continuing Operations		79,424		209,141		2,895,318			2,662,219
Income from Continuing Operations		137,394		351,378		4,730,246			4,335,995
Discontinued operations:
Loss from discontinued operations, net of income taxes of ($14,628)		—		—		—			(36,690	)
Net Income		137,394		351,378		4,730,246			4,299,305
Other Comprehensive Income (Loss), net of taxes		699,289		465,890		(747,510	)		(338,988	)
Comprehensive Income	$	836,683	$	817,268	$	3,982,736		$	3,960,317
Basic Earnings Per Common Share:
Income from continuing operations	$	0.06	$	0.16	$	2.13		$	1.97
Discontinued operations		—		—		—			(0.01	)
Net income	$	0.06	$	0.16	$	2.13		$	1.96
Diluted Earnings Per Common Share:
Income from continuing operations	$	0.06	$	0.16	$	2.12		$	1.96
Discontinued operations		—		—		—			(0.01	)
Net income	$	0.06	$	0.16	$	2.12		$	1.95
Dividends Declared Per Common Share	$	0.3200	$	0.3125	$	0.9600		$	0.9375

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, 2009 AND 2008

UNAUDITED

	Nine Months Ended June 30,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income from continuing operations	$	4,730,246		$	4,335,995
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		3,600,313			3,417,212
Cost of removal of utility plant, net		(181,428	)		(153,274	)
Changes in assets and liabilities which used cash, exclusive of changes and noncash transactions shown separately		18,541,805			2,799,318
Net cash provided by continuing operating activities		26,690,936			10,399,251
Net cash used in discontinued operations		—			(240,967	)
Net cash provided by operating activities		26,690,936			10,158,284
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant and nonutility property		(4,281,393	)		(5,010,388	)
Proceeds from disposal of equipment		27,826			9,488
Proceeds from sale of short-term investments		500,000			—
Proceeds from sale of Bluefield Operations		—			3,941,000
Net cash used in continuing investing activities		(3,753,567	)		(1,059,900	)
Net cash used in discontinued investing activities		—			(12,360	)
Net cash used in investing activities		(3,753,567	)		(1,072,260	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		5,000,000			—
Proceeds on collection of note		87,000			—
Net repayments under line-of-credit agreements		(13,960,000	)		(4,808,000	)
Proceeds from issuance of common stock		526,123			612,700
Cash dividends paid		(2,111,042	)		(2,041,427	)
Net cash used in continuing financing activities		(10,457,919	)		(6,236,727	)
Net cash provided by discontinued financing activities		—			365,000
Net cash used in financing activities		(10,457,919	)		(5,871,727	)
NET INCREASE IN CASH AND CASH EQUIVALENTS		12,479,450			3,214,297
BEGINNING CASH AND CASH EQUIVALENTS		875,436			1,408,317
ENDING CASH AND CASH EQUIVALENTS	$	13,354,886		$	4,622,614
SUPPLEMENTAL INFORMATION:
Cash paid during the year for:
Interest	$	1,598,182		$	1,729,647
Income taxes net of refunds		2,269,308			2,229,921

Noncash Transactions:

A note in the amount of $1,300,000 was received as partial payment for the sale of the assets associated with the Bluefield division of Roanoke Gas Company in November 2007.

See notes to condensed consolidated financial statements.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

UNAUDITED

1. Basis of Presentation

In the opinion of management, the accompanying unaudited condensed consolidated financial statements contain all adjustments (consisting of only normal recurring accruals) necessary to present fairly RGC Resources, Inc.’s financial position as of June 30, 2009 and the results of its operations for the three months and nine months ended June 30, 2009 and 2008 and its cash flows for the nine months ended June 30, 2009 and 2008. The results of operations for the three months and nine months ended June 30, 2009 are not indicative of the results to be expected for the fiscal year ending September 30, 2009 as quarterly earnings are affected by the highly seasonal nature of the business and weather conditions generally result in greater earnings during the winter months.

The condensed consolidated interim financial statements and condensed notes are presented as permitted by Form 10-Q and do not contain certain information included in the Company’s annual consolidated financial statements and notes thereto. The condensed consolidated financial statements and condensed notes should be read in conjunction with the financial statements and notes contained in the Company’s Form 10-K. The September 30, 2008 balance sheet was included in the Company’s Form 10-K.

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

2. Discontinued Operations

Effective as of October 31, 2007, Resources closed on the sale of the stock of Bluefield Gas Company (“Bluefield”) to ANGD, LLC, and Roanoke Gas Company completed the sale of its natural gas distribution assets located in the Town of Bluefield and the County of Tazewell, Virginia (“Bluefield division of Roanoke Gas”) to Appalachian Natural Gas Company, a subsidiary of ANGD, LLC. The sale of both the stock and the assets was essentially at book value and included the receipt of a $1,300,000 note from ANGD to partially finance the transaction. The note has a 5-year term with a 15-year amortization schedule with annual principal payments and quarterly interest payments at a rate of 10%.

RGC RESOURCES, INC. AND SUBSIDIARIES

The components of discontinued operations are summarized below:

	Nine Months Ended June 30, 2008
Bluefield Operations
Total Revenues	$	457,777
Pretax Operating Loss		(105,216	)
Continuing Costs		53,898
Income Tax		14,628
Discontinued Operations	$	(36,690	)

3. Rates and Regulatory Matters

On November 1, 2008, Roanoke Gas Company placed into effect new base rates that provide for approximately $1,198,000 in additional annual revenues. The Company received a final order from the State Corporation Commission (“SCC”) on June 10, 2009 providing for approximately $1,198,000 in additional annual revenues effective November 1, 2008.

The SCC requires the Company to conduct a depreciation study every five years to evaluate and update the composite depreciation rates applied to the Company’s utility property. The composite rates are comprised of two components, one based on the average remaining service life and one based on the cost of retiring the asset from service. The Company completed an updated depreciation study and submitted it to the SCC for approval on July 1, 2009. The study resulted in a new composite weighted average depreciation rate of 3.31% compared to 4.13% currently in place. Once approved, the new depreciation rates will be effective retroactive to October 1, 2008. Total annual depreciation expense is expected to decrease by approximately $900,000 for the current and future years if the filed rates are approved as submitted.

4. Debt

On October 31, 2008, the Company issued a $5,000,000 variable rate note at LIBOR plus 125 basis points due December 1, 2015. This note refinanced a first mortgage note that matured in July and had since been funded through the Company’s line of credit. Simultaneous with the execution of the variable rate note, the Company entered into an interest rate swap to convert the variable rate note into a fixed rate debt with a 5.79% effective interest rate. This note along with the other debt instruments of the Company contain various covenant provisions including minimum interest charge coverage ratio, limitations on debt as a percentage of total capitalization and a provision limiting the amount of retained earnings available for dividends. The Company was in compliance with these provisions at June 30, 2009.

RGC RESOURCES, INC. AND SUBSIDIARIES

5. Derivatives and Hedging

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

The Company has historically entered into futures, swaps and caps for the purpose of hedging the price of natural gas in order to provide price stability during the winter months. At June 30, 2009, the Company had collar agreements outstanding for the winter period to hedge 800,000 decatherms of natural gas. As the current value of the derivatives fall between the floor and ceiling prices of the collar agreements, there is no fair value reflected in the financial statements at June 30, 2009. If the fair value of these instruments had fallen below the floor or risen above the ceiling price of the collar, the fair value would be recorded in the balance sheet under the caption “Fair value of marked to market transactions” with the offsetting entry to either under-recovery of gas costs or over-recovery of gas costs. Net income and other comprehensive income would not be affected by the change in market value as any cost incurred or benefit received from these instruments is recoverable or refunded through the PGA as the Virginia Commission allows for full recovery of prudent costs associated with natural gas purchases.

The Company has two interest rate swaps associated with its variable rate notes. The first swap relates to the $15,000,000 note issued in November 2005. This swap essentially converts the floating rate note based upon LIBOR into fixed rate debt with a 5.74% interest rate. The second swap relates to the $5,000,000 variable rate note issued in October 2008. This swap converts the variable rate note based on LIBOR into a fixed rate debt with a 5.79% effective interest rate. Both swaps qualify as cash flow hedges with changes in fair value reported in other comprehensive income. No portions of interest rate swaps were deemed ineffective.

The table below reflects the fair values of the derivative instruments and their corresponding classification in the consolidated balance sheets under the current liabilities caption of “Fair value of marked to market transactions” as of June 30, 2009 and September 30, 2008:

Fair Value of Derivative Instruments

	June 30, 2009		September 30, 2008
Derivatives designated as hedging instruments:
Interest rate swaps	$	2,096,781	$	837,637
Natural gas collar arrangement		—		37,850
Total derivatives designated as hedging instruments	$	2,096,781	$	875,487

The table in Note 6 below reflects the effect on income and other comprehensive income of the Company’s cash flow hedges.

RGC RESOURCES, INC. AND SUBSIDIARIES

Based on the current interest rate environment, approximately $900,000 of the fair value on the interest rate hedges will be reclassified from other comprehensive loss into interest expense on the income statement over the next 12 months. Changes in LIBOR rates during that period could significantly change the estimated amount to be reclassified to income as well as the fair value of the interest rate hedges.

6. Comprehensive Income

A summary of other comprehensive income and loss (“OCI”) is provided below:

	Three Months Ended June 30,						Nine Months Ended June 30,
	2009			2008			2009			2008
Interest Rate SWAPs
Unrealized gains (losses) reflected in OCI	$	889,631		$	657,805		$	(1,781,995	)	$	(717,870	)
Income tax		(337,704	)		(249,703	)		676,446			272,503
Net unrealized gains (losses) reflected in OCI		551,927			408,102			(1,105,549	)		(445,367	)
Transfer of realized losses from OCI to interest expense		219,441			81,341			522,851			136,052
Income tax		(83,300	)		(30,877	)		(198,475	)		(51,645	)
Net transfer of realized losses from OCI to interest expense		136,141			50,464			324,376			84,407
Defined Benefit Plans
Transfer of realized losses to income		6,313			—			18,939			—
Income tax		(2,396	)		—			(7,188	)		—
Net transfer of realized losses to income		3,917			—			11,751			—
Amortization of transition obligation		11,773			11,806			35,319			35,418
Income tax		(4,469	)		(4,482	)		(13,407	)		(13,446	)
Net amortization of transition obligation		7,304			7,324			21,912			21,972
Net other comprehensive income (loss)	$	699,289		$	465,890		$	(747,510	)	$	(338,988	)
Change in measurement date - SFAS No. 158		—			—			11,221			—
Accumulated comprehensive loss - beginning of period		(2,659,970	)		(1,280,133	)		(1,224,392	)		(475,255	)
Accumulated comprehensive loss - end of period	$	(1,960,681	)	$	(814,243	)	$	(1,960,681	)	$	(814,243	)

RGC RESOURCES, INC. AND SUBSIDIARIES

7. Weighted Average Shares

Basic earnings per common share for the three months and nine months ended June 30, 2009 and 2008 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, 2009 and 2008 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,
	2009	2008	2009	2008
Weighted average common shares	2,227,469	2,205,733	2,219,632	2,198,597
Effect of dilutive securities:
Options to purchase common stock	7,279	9,691	7,380	10,018
Diluted average common shares	2,234,748	2,215,424	2,227,012	2,208,615

During the quarter ended June 30, 2009, 1,000 shares of common stock were issued upon exercise of options under the Company’s Key Employee Stock Option Plan. The options had an exercise price of $20.875.

8. Commitments and Concentrations

Roanoke Gas currently holds the only franchises and/or certificates of public convenience and necessity to distribute natural gas in its service area. These franchises are effective through January 1, 2016. Certificates of public convenience and necessity in Virginia are exclusive and are intended for perpetual duration. Due to the nature of the natural gas distribution business, the Company has entered into agreements with both suppliers and pipelines for natural gas commodity purchases, storage capacity and pipeline delivery capacity. The Company obtains most of its regulated natural gas supply from the asset manager. The Company uses an asset manager to assist in optimizing the use of its transportation, storage rights, and gas supply to provide a secure and reliable source of natural gas to its customers. Roanoke Gas is served directly by two primary pipelines. These two pipelines deliver 100% of the natural gas supplied to the Company’s customers. Depending on weather conditions and the level of customer demand, failure of one or both of these transmission pipelines could have a major adverse impact on the Company.

RGC RESOURCES, INC. AND SUBSIDIARIES

9. Employee Benefit Plans

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

	Three Months Ended June 30,						Nine Months Ended June 30,
	2009			2008			2009			2008
Components of net periodic pension cost:
Service cost	$	100,906		$	107,365		$	302,718		$	322,095
Interest cost		211,725			192,377			635,175			577,131
Expected return on plan assets		(215,537	)		(205,345	)		(646,611	)		(616,035	)
Recognized loss		17,647			—			52,941			—
Net periodic pension cost	$	114,741		$	94,397		$	344,223		$	283,191
	Three Months Ended June 30,						Nine Months Ended June 30,
	2009			2008			2009			2008
Components of post-retirement benefit cost:
Service cost	$	30,914		$	35,082		$	92,742		$	105,246
Interest cost		126,005			127,848			378,015			383,544
Expected return on plan assets		(69,179	)		(71,626	)		(207,537	)		(214,878	)
Amortization of unrecognized transition obligation		47,223			47,223			141,669			141,669
Net post-retirement benefit cost	$	134,963		$	138,527		$	404,889		$	415,581

The Company contributed $500,000 to its pension plan for the nine-month period ended June 30, 2009. The Company currently expects to make a total contribution of approximately $700,000 to its pension plan and $600,000 to its post-retirement benefit plan during the fiscal year ending September 30, 2009. The Company will continue to evaluate its pension funding in light of the negative asset performance in 2008.

10. Environmental Matters

Both Roanoke Gas Company and Bluefield Gas Company operated manufactured gas plants (MGPs) as a source of fuel for lighting and heating until the late 1940s or early 1950s. A by-

RGC RESOURCES, INC. AND SUBSIDIARIES

product of operating MGPs was coal tar, and the potential exists for on-site tar waste contaminants at the former plant 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. While the Company sold the stock of Bluefield Gas Company to ANGD, LLC, it retained ownership of the former MGP site and entered into an Indemnification and Cost Sharing Agreement with ANGD to seek rate recovery of any remediation costs through rate recovery and under any applicable insurance policies or from any third party for reimbursement to the Company for 25% of any such costs to the extent they are not otherwise recovered. If the Company incurs costs associated with a required clean-up of the Roanoke Gas Company MGP site, the Company anticipates recording a regulatory asset for such clean-up costs to be recovered in future rates.

11. Newly Adopted Accounting Standards

On October 1, 2008, the Company adopted the change in measurement date provision of SFAS No. 158,Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132R. SFAS No. 158 requires an employer to measure the funded status of each plan as of the Company’s fiscal year end. The Company previously used a June 30 measurement date for its benefit plans. The change in measurement date eliminated the three month lag in recognizing expense between the measurement date and the end of the Company’s fiscal year. The Company recorded a reduction to retained earnings, net of tax, of $44,931 for the effect of the change in measurement date on unregulated operations and a regulatory asset in the amount of $177,284 for the portion attributable to the regulated operations of Roanoke Gas Company. The Company has begun a three year amortization of the regulatory asset, consistent with the Company’s latest rate filing and order.

In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements. This statement defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value methods. This statement does not require any new fair value measurements. Instead, it provides for increased consistency and comparability in fair value measurements and for expanded disclosure surrounding the fair value measurements. In February 2008, the FASB issued FASB Staff Position No. 157-2,Effective Date of FASB Statement No. 157, which delays the effective date of SFAS No. 157 for one year for nonfinancial assets and liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually.) The Company adopted the provisions of SFAS No. 157 effective October 1, 2008. Adoption of SFAS No. 157 had no material impact on the Company’s financial position, results of operations or cash flows. The disclosures required by SFAS No. 157 are included in Note 13.

In March 2008, the FASB issued SFAS No. 161,Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133. The purpose of this statement is to enhance the current disclosure framework of SFAS No. 133 by requiring entities to disclose (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under Statement 133 and its related

RGC RESOURCES, INC. AND SUBSIDIARIES

interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flow. The Company adopted the provisions of SFAS No. 161 effective for the quarter ended March 31, 2009. Adoption of SFAS No. 161 had no material impact on the Company’s financial position, results of operations or cash flows. The disclosures required by SFAS No. 161 are included in Notes 5 and 6.

In April 2009, the FASB issued FASB Staff Position No. FAS 107-1 and APB 28-1 (FSP 107-1),Interim Disclosures about Fair Value of Financial Instruments. FSP 107-1 applies the required disclosures of FASB No. 107,Disclosures about Fair Value of Financial Instruments, to interim financial statements of publicly traded companies. Under FSP 107-1, companies shall disclose for interim and annual reporting periods the fair value of all financial instruments for which it is practicable to estimate that value, the method and significant assumptions used to estimate the fair value of financial instruments, and a description of any changes in methods and significant assumptions that occurred during the period. The Company adopted this FSP for the quarter ended June 30, 2009. Adoption of FSP 107-1 had no material impact on the Company’s financial position, results of operations or cash flows. The disclosures required under this FSP are included in Note 13 below.

In May 2009, the FASB issued SFAS No. 165,Subsequent Events.This statement establishes general standards of accounting for and disclosure of events that occur subsequent to the balance sheet date but before financial statements are issued. The statement defines (1) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions for potential recognition or disclosure in the financial statements; (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and (3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. Under SFAS No. 165, a public reporting entity shall evaluate subsequent events through the date the financial statements are issued. The Company adopted SFAS No. 165 for the quarter ended June 30, 2009. Adoption of SFAS No. 165 had no material impact on the Company’s financial position, results of operations or cash flows. The Company evaluated subsequent events through August 14, 2009.

12. Recently Issued Accounting Standards Pending Adoption

In December 2008, the FASB issued FASB Staff Position No 132(R)-1, (FSP 132(R)-1),Employers’ Disclosures about Postretirement Benefit Plan Assets. As the title indicates, the objective of FSP 132(R)-1 is to improve disclosures about plan assets in employers’ defined benefit pension or other post-retirement plans by providing users of financial statements with an understanding of: (a) How investment allocation decisions are made, including the factors that are pertinent to an understanding of investment policies and strategies; (b) The major categories of plan assets; (c) The inputs and valuation techniques used to measure the fair value of plan assets; (d) The effect of fair value measurements using significant unobservable inputs on changes in plan assets for the period; and (e) Significant concentrations of risk within plan assets. The FSP is effective for fiscal years ending after December 15, 2009. Although the Company has not completed its evaluation, management does not anticipate this FSP to have a material impact on its financial position, results of operations or cash flows.

RGC RESOURCES, INC. AND SUBSIDIARIES

In June 2009, the FASB issued SFAS No. 168,The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles – a replacement of FASB Statement No. 162. This statement establishes the Codification as the source of authoritative U.S. accounting and reporting standards recognized by the FASB for use in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. The Codification was the result of a project of FASB to organize and simplify all authoritative GAAP literature into one source. This statement is effective for interim reporting and annual periods ending after September 15, 2009. Accordingly, the Company will adopt SFAS No. 168 during the quarter ended September 30, 2009. The Company does not anticipate this FSP to have a material impact on its financial position, results of operations or cash flows.

Other accounting standards that have been issued or proposed by the FASB or other standard –setting bodies are not expected to have a material impact on the Company’s financial position, results of operations and cash flows.

13. Fair Value Measurements

Effective October 1, 2008, the Company adopted SFAS No. 157 for financial assets and liabilities that are measured and reported on a fair value basis. SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. SFAS No. 157 also establishes a fair value hierarchy that prioritizes each input to the valuation method used to measure fair value into one of the following three broad levels:

Level 1 – Unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date.

Level 2 – Inputs other than quoted prices in Level 1 that are either for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability, or inputs that are derived principally from or corroborated by observable market data by correlation or other means.

Level 3 – Unobservable inputs for the asset or liability where there is little, if any, market activity for the asset or liability at the measurement date.

The fair value hierarchy gives the highest priority to unadjusted quoted prices in active markets (Level 1) and the lowest priority to unobservable inputs (Level 3).

The Company also adopted FSP 107-1 during the current quarter. FSP 107-1 applies the annual fair value disclosure requirements of FASB No. 107 to interim periods.

RGC RESOURCES, INC. AND SUBSIDIARIES

The following table summarizes the Company’s financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements by level within the fair value hierarchy as of June 30, 2009:

			Fair Value Measurements
	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Liabilities:
Interest rate swaps	$	2,096,781	$	—	$	2,096,781	$	—
Total	$	2,096,781	$	—	$	2,096,781	$	—

The following table summarizes the fair value of the Company’s financial assets and liabilities that are not adjusted to fair value in the financial statements. The carrying value of cash and cash equivalents, accounts receivable, accounts payable, customer credit balances and customer deposits are a reasonable estimate of fair value due to the short-term nature of these financial instruments.

					Fair Value Measurements
	Carrying Amount		Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Assets:
Note receivable	$	1,213,000	$	1,172,090	$	—	$	—	$	1,172,090
Liabilities:
Long-term debt		28,000,000		29,239,826		—		—		29,239,826

The fair value of the note receivable is estimated by discounting future cash flows based on a range of rates for similar investments adjusted for management’s expectation of credit and other risks. The fair value of long-term debt is estimated by discounting the future cash flows of the fixed rate debt at rates extrapolated based on current market conditions. The variable rate long-term debt has interest rate swaps that effectively convert such debt to fixed rate. The values of the swap agreements are included in the first table above.

RGC RESOURCES, INC. AND SUBSIDIARIES

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

Forward-Looking Statements

This report contains forward-looking statements that relate to future transactions, events or expectations. In addition, RGC Resources, Inc. (“Resources” or the “Company”) may publish forward-looking statements relating to such matters as anticipated financial performance, business prospects, technological developments, new products, research and development activities and similar matters. These statements are based on management’s current expectations and information available at the time of such statements and are believed to be reasonable and are made in good faith. The Private Securities Litigation Reform Act of 1995 provides a safe harbor for forward-looking statements. In order to comply with the terms of the safe harbor, the Company notes that a variety of factors could cause the Company’s actual results and experience to differ materially from the anticipated results or other expectations expressed in the Company’s forward-looking statements. The risks and uncertainties that may affect the operations, performance, development and results of the Company’s business include, but are not limited to, the following: (i) failure to earn on a consistent basis an adequate return on invested capital; (ii) ability to retain and attract professional and technical employees; (iii) the potential loss of large-volume industrial customers to alternate fuels, facility closings or production changes; (iv) volatility in the price and availability of natural gas; (v) uncertainty in the demand for natural gas 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, difficult economic conditions and/or colder weather; (ix) variations in winter heating degree-days from the 30-year average on which the Company’s billing rates are set; (x) impact of potential climate change legislation regarding limitations on carbon dioxide emissions; (xi) impact of potential increased regulatory oversight and compliance requirements due to financial, environmental, safety and system integrity laws and regulations; (xii) failure to obtain timely rate relief for increasing operating or gas costs from regulatory authorities; (xiii) capital market conditions and the availability of debt and equity financing; (xiv) impact of potential increases in corporate income tax rates and other taxes; (xv) volatility in actuarially determined benefit costs and plan asset performance; (xvi) effect of natural disasters on production and distribution facilities and the related effect on supply availability and price; and (xvii) changes in accounting regulations and practices, which could change the accounting treatment for certain transactions. All of these factors are difficult to predict and many are beyond the Company’s control. Accordingly, while the Company believes its forward-looking statements to be reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from them will be realized. When used in the Company’s documents or news releases, the words, “anticipate,” “believe,” “intend,” “plan,” “estimate,” “expect,” “objective,” “projection,” “forecast”, “budget”, “assume”, “indicate” or similar words or future or conditional verbs such as “will,” “would,” “should,” “can”, “could” or “may” are intended to identify forward-looking statements.

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

RGC RESOURCES, INC. AND SUBSIDIARIES

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, 2009. 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 fiscal year will depend primarily on the level of operating and maintenance costs, and to a lesser extent, weather.

Overview

Resources is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately 56,100 residential, commercial and industrial customers in Roanoke, Virginia and the surrounding areas through its Roanoke Gas Company (“Roanoke Gas”) subsidiary. Natural gas service is provided at rates and for terms and conditions set by the Virginia State Corporation Commission (“SCC”).

Resources also provided regulated sale and distribution of natural gas to Bluefield, West Virginia, the Town of Bluefield, Virginia and surrounding areas through its Bluefield Gas Company (“Bluefield”) subsidiary and the Bluefield division of Roanoke Gas (collectively called “Bluefield Operations”). Effective as of October 31, 2007, Resources closed on the sale of the stock of Bluefield to ANGD, LLC and Roanoke Gas completed the sale of the assets of its Bluefield division to Appalachian Natural Gas Company, a subsidiary of ANGD, LLC. The corresponding activities of the Bluefield Operations up to the effective date of the sale have been classified as discontinued operations. See Note 2 above for more information on these transactions.

Resources also provides certain unregulated services through Roanoke Gas Company and information system services to software providers in the utility industry through RGC Ventures, Inc. of Virginia, which operates as Application Resources. Such operations represent less than 3% of total revenues and margin of Resources on an annual basis.

Winter weather conditions and volatility in natural gas prices both have a direct influence on the quantity of natural gas sales to the Company’s customers and management believes each factor has the potential to significantly impact earnings. A majority of natural gas sales are for heating during the winter season. Consequently, during warmer than normal (normal means average heating degree-days for a specified period) winters, customers may significantly reduce their consumption of natural gas. Furthermore, significant increases in natural gas commodity prices can affect customer usage by encouraging conservation or use of alternative fuels.

Because the SCC authorizes billing rates for the utility operations of Roanoke Gas based on normal weather, warmer than normal weather may result in the Company failing to earn its authorized rate of return. The Company has been able to mitigate a portion of the risk associated with warmer than normal winter weather by the inclusion of a weather normalization adjustment (“WNA”) factor as part of its rate structure, which allows the Company to recover revenues equivalent to the margin that would be realized at approximately 6% warmer than the 30-year normal or refund revenues for any margin realized for weather greater the 6% colder than the 30-year

RGC RESOURCES, INC. AND SUBSIDIARIES

normal. For the WNA period ending March 31, 2009, the Company did not record a WNA adjustment as the number of heating degree-days (an industry measure by which the average daily temperature falls below 65 degrees Fahrenheit) fell within the 6% weather band during the measurement period running from April through March. The Company recorded approximately $363,000 in additional revenues for the nine-month period ended June 30, 2008 to reflect the impact of the WNA.

The current economic environment has had a negative impact on the local economy as construction activity has slowed significantly and industrial activity has declined. Natural gas consumption by the Company’s industrial and transportation customers has declined by more than 14% from the same quarter last year and by nearly 12% year to date. Much of the decline appears to be related to reduced production activities by these customers and is expected to improve when the economy recovers. However, one industrial customer has closed its operations, which will result in the loss of approximately 65,000 decatherms, or $80,000 in margin, annually. A prolonged economic downturn could result in additional closings or lead to further reductions in industrial activity. Growing job losses may lead to an increase in customer payment delays and higher bad debt expense. Fortunately, low natural gas commodity prices have reduced customer billings during the current period, which contributed to a reduction in bad debt expense for the quarter. The current level of past due balances is at approximately the same level as last year. However, if economic conditions and employment levels continue to deteriorate over the succeeding months, customer delinquencies and bad debts will likely increase. Management continues to closely monitor accounts receivable activity.

Volatility in natural gas prices presents other issues for the Company. The commodity price of natural gas has declined from its peak of more than $13.00 per decatherm last summer to under $4.00 a decatherm in June. Futures prices for natural gas on the NYMEX (New York Mercantile Exchange) range between $4.00 and $7.00 per decatherm over the next 12 months. If natural gas prices remain at these levels, both the Company and its customers should benefit from relative stability in prices. A strong economic recovery that increases demand for natural gas could escalate natural gas prices and make natural gas a less attractive energy source.

The Company has an approved rate structure in place that mitigates the impact of financing costs of its natural gas inventory. Under this rate structure, Roanoke Gas recognizes revenue for the financing costs or “carrying costs” of its investment in natural gas inventory. The carrying cost revenue factor applied to inventory is based on the Company’s weighted average cost of capital including interest rates on short-term and long-term debt and the Company’s authorized return on equity. During times of rising gas costs and rising inventory levels, the Company recognizes revenues to offset higher financing costs associated with higher inventory balances. Conversely, during times of decreasing inventory costs and lower inventory balances, the Company recognizes less carrying cost revenue as financing costs are lower. The Company recognized approximately $379,000 and $1,825,000 in carrying cost revenues for the three-month and nine-month periods ended June 30, 2009, compared to approximately $453,000 and $1,544,000 for the same periods last year. The decline in carrying cost revenues for the quarter was primarily attributable to the much lower cost of natural gas delivered into storage in April, May and June of this year compared to the same period last year. The average price of natural gas delivered to storage during the current quarter was approximately $3.79 per decatherm compared to $11.89 per decatherm for the same period last year. As the NYMEX futures prices for the next several

RGC RESOURCES, INC. AND SUBSIDIARIES

months indicate much lower prices than last year, carrying cost revenues should continue to decline during the fourth quarter and into next year when compared to the prior periods as lower priced gas is used to refill storage levels.

In the short run, as investment in natural gas inventories increases so does the level of borrowing under the Company’s line-of-credit. However, as the carrying cost factor used in determining the carrying cost revenues is based on the Company’s weighted average cost of capital, carrying cost revenues do not directly correspond with the short-term incremental financing costs. Therefore, when inventory balances decline due to a reduction in commodity prices, net income will decline as carrying cost revenues decrease by a greater amount than short-term financing costs. The inverse occurs when inventory costs increase.

Results of Operations

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

	Three Months Ended June 30,				Nine Months Ended June 30,
	2009		2008		2009		2008
Net Income
Continuing Operations	$	137,394	$	351,378	$	4,730,246	$	4,335,995
Discontinued Operations		—		—		—		(36,690	)
Net Income	$	137,394	$	351,378	$	4,730,246	$	4,299,305

RGC RESOURCES, INC. AND SUBSIDIARIES

Continuing Operations

Three Months Ended June 30, 2009:

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

	Three Months Ended June 30,				Increase/ (Decrease)			Percentage
	2009		2008
Operating Revenues
Gas Utilities	$	10,355,122	$	19,887,423	$	(9,532,301	)	-48	%
Other		351,867		265,211		86,656		33	%
Total Operating Revenues	$	10,706,989	$	20,152,634	$	(9,445,645	)	-47	%
Delivered Volumes
Regulated Natural Gas (DTH)
Tariff Sales		820,708		868,078		(47,370	)	-5	%
Transportation		568,219		652,066		(83,847	)	-13	%
Total		1,388,927		1,520,144		(131,217	)	-9	%
Heating Degree Days (Unofficial)		336		325		11		3	%

Total operating revenues for the three months ended June 30, 2009 compared to the same period last year decreased due to significantly lower natural gas prices and to a lesser extent a reduction in delivered natural gas volumes. During the same quarter last year, natural gas commodity prices increased rapidly and peaked at more than $13.00 per decatherm in early July. However, a combination of weaker demand from the current economic environment and a strong natural gas supply has resulted in much lower commodity prices this year and significantly lower billing rates. The decline in volumes corresponds to less demand from some industrial, large commercial and transportation customers due to the current economy.

	Three Months Ended June 30,				Increase/ (Decrease)			Percentage
	2009		2008
Gross Margin
Gas Utilities	$	4,840,640	$	4,891,445	$	(50,805	)	-1	%
Other		174,474		163,965		10,509		6	%
Total Gross Margin	$	5,015,114	$	5,055,410	$	(40,296	)	-1	%

RGC RESOURCES, INC. AND SUBSIDIARIES

Regulated natural gas margins from utility operations decreased from the same period last year due to a reduction in delivered natural gas volumes and declining carrying cost revenues more than offsetting the implementation of a non-gas base rate increase in November. Tariff sales (consisting primarily of residential and commercial volumes) decreased primarily as a result of declines in commercial sales volumes that appear to be a result of the current unfavorable economic environment, while transportation volumes, which generally correspond to production activities of certain larger industrial customers, also declined significantly for the same reasons. As discussed above, carrying cost revenues associated with natural gas inventories declined from last year’s levels corresponding with the decline of the cost of gas in storage. Carrying cost revenues declined by nearly $74,000 for the quarter and are expected to decline further in the fourth quarter as lower priced gas is delivered into storage. The Company placed increased non-gas base rates into effect in November. As a result of the higher rates, the Company realized approximately $127,000 in additional margin from customer base charges, which is a flat monthly fee billed to each natural gas customer. The total volumetric margin decreased by approximately $93,000 primarily due to lower volumes for the quarter.

The components of the gas utility margin decrease are summarized below:

Net Margin Decrease

Customer Base Charge, including rate increase	$	136,736
WNA		(8,029	)
Carrying Cost		(73,725	)
Volumetric (volume decrease)		(93,429	)
Other		(12,358	)
Total	$	(50,805	)

Other margins increased by $10,509 over last year primarily due to an increase in contract services in unregulated operations.

Operations expenses increased by $94,004, or 4%, over the same period last year, as a result of higher employee benefit costs, professional services and contractor and operations labor, partially offset by a reduction in bad debt expense. Contractor and company labor increased approximately $67,000 due to reduced capital activity and normal compensation adjustments. Total employee benefit costs also increased by approximately $67,000 over the same period last year due to increases in pension costs and higher health insurance premiums. Professional services increased by approximately $37,000 for the quarter primarily due to timing of internal control testing. Bad debt expense decreased by approximately $67,000 due to the significant decline in customer billings associated with much lower gas costs. The remaining difference is attributable to minor variances in other operating expense categories.

Maintenance expenses increased by $108,952, or 32%, primarily due to the repairs of pipeline leaks identified through annual leak surveys and other general facility maintenance.

RGC RESOURCES, INC. AND SUBSIDIARIES

General taxes increased by $11,346, or 4%, related to higher property taxes associated with increased investment in utility plant and higher payroll taxes.

Depreciation expense increased $68,216, or 6%, on a corresponding increase in utility plant associated with replacing cast iron and bare steel pipe and extending service to new customers.

Other income, net, decreased by $51,180 primarily due to lower interest rates on the Company’s short-term cash investments.

Interest expense declined by $30,293, or 6%, due to the retirement of a $5,000,000 first mortgage note at 7.804% last July and the refinancing of the note with a variable rate note and interest rate swap that provides for a fixed interest rate of 5.79%. The remaining reduction is attributable to lower interest rate paid on customer deposits.

Income tax expense decreased by $129,717, or 62%, which corresponds to the decrease in pre-tax income from continuing operations for the quarter. The effective tax rate was 37% for both periods.

Nine Months Ended June 30, 2009:

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

	Nine Months Ended June 30,				Increase/ (Decrease)			Percentage
	2009		2008
Operating Revenues
Gas Utilities	$	72,550,797	$	84,791,998	$	(12,241,201	)	-14	%
Other		901,889		665,922		235,967		35	%
Total Operating Revenues	$	73,452,686	$	85,457,920	$	(12,005,234	)	-14	%
Delivered Volumes
Regulated Natural Gas (DTH)
Tariff Sales		6,278,882		5,955,536		323,346		5	%
Transportation		1,907,393		2,124,641		(217,248	)	-10	%
Total		8,186,275		8,080,177		106,098		1	%
Heating Degree Days (Unofficial)		3,896		3,611		285		8	%

Total operating revenues from continuing operations for the nine months ended June 30, 2009 compared to the same period last year decreased due to reductions in the price of natural gas

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more than offsetting a slight increase in natural gas sales volumes and the implementation of a non-gas cost rate increase. The average commodity price of gas delivered declined by more than 25% from last year. Total tariff natural gas sales volumes increased by 5% on an 8% rise in the number of heating degree-days. Reductions in commercial sales volumes, which management primarily attributes to the current economy, mitigated a portion of the effect of an 8% increase in heating degree days. Transportation volumes declined by 10% due to reduced production activities resulting primarily from the current economic climate. Other revenues increased by 35% related primarily to contract services provided in unregulated operations.

	Nine Months Ended June 30,				Increase/ (Decrease)		Percentage
	2009		2008
Gross Margin
Gas Utilities	$	21,971,598	$	20,671,645	$	1,299,953	6	%
Other		471,872		405,410		66,462	16	%
Total Gross Margin	$	22,443,470	$	21,077,055	$	1,366,415	6	%

Regulated natural gas margins increased due to a combination of 5% increase in the higher margin firm volumes, the implementation of a non-gas cost rate increase and higher carrying cost revenues for the period more than offsetting the absence of WNA revenues. Most of the increased margin was attributable to the non-gas cost rate increase designed to provide approximately $1.2 million in additional annual revenues and margin. The 5% increase in the tariff sales offset the absence of the WNA revenue. Carrying cost revenues increased by approximately $280,000 due to a higher average investment in natural gas storage during the period. The components of the regulated margin increase are summarized below:

Net Margin Increase

Customer Base Charge, including rate increase	$	419,767
WNA		(363,376	)
Carrying Cost		280,255
Volumetric (rate and volume increase)		995,554
Other		(32,247	)
Total	$	1,299,953

Operations expenses increased by $371,103, or 5%, for the nine-month period ended June 30, 2009 compared to the same period last year due to higher employee benefit costs and contractor and operations labor and a reduction in capitalized overheads partially offset by reductions in professional services. A lower level of capital activity and the timing of annual leak survey work performed on the Company’s natural gas distribution system resulted in increases to operations labor and contractor expense and reduced the amount of allocated overheads from operations to capital accounting by approximately $294,000. Total employee benefit costs increased by

RGC RESOURCES, INC. AND SUBSIDIARIES

approximately $126,000 over the same period last year due to increases in pension costs and higher health insurance premiums. Professional services declined by $47,000 primarily due to a reduction in costs related to management’s decision to transfer benefit plan and actuarial services to a lower cost provider.

Maintenance expenses increased $219,807, or 22%, due to timing of pipeline leak repairs of the Company’s distribution system identified through leak surveys.

General taxes increased $38,681, or 4%, for the nine-month period ended June 30, 2009 compared to the same period last year. Most of the increase was attributable to higher property taxes related to higher level utility plant combined with an increase in payroll taxes.

Depreciation expense increased $171,491, or 5%, due to the growth in utility plant associated with extending service to new customers and replacing cast iron and bare steel pipe.

Other income, net, decreased $56,557 due to reduced investment earnings on the Company’s short-term investments as a result of significantly lower interest rates.

Interest expense decreased by $118,574, or 8%, due to significantly lower interest rates on the Company’s line-of-credit and the refinancing of the Company’s $5,000,000 first mortgage note, which matured on July 1, 2008.

Income tax expense increased $233,099, or 9%, which corresponds to the rise in pre-tax income from continuing operations. The effective tax rate was 38% for both periods.

Critical Accounting Policies and Estimates

The consolidated financial statements of Resources are prepared in accordance with accounting principles generally accepted in the United States of America. The amounts of assets, liabilities, revenues and expenses reported in the Company’s financial statements are affected by accounting policies, estimates and assumptions 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 may differ significantly from these estimates and assumptions.

The Company considers an estimate to be critical if it requires assumptions to be made that were uncertain at the time the estimate was made and changes in the estimate are reasonably likely to occur from period to period. The Company considers the following accounting policies and estimates to be critical.

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

RGC RESOURCES, INC. AND SUBSIDIARIES

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

If, for any reason, the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the Company would remove the regulatory assets or liabilities from the balance sheet related to those portions no longer meeting the criteria and include them in the consolidated statement of income and comprehensive income for the period in which the discontinuance occurred.

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

The Company bills its regulated natural gas customers on a monthly cycle. The billing cycle periods for most customers do not coincide with the accounting periods used for financial reporting. The Company accrues estimated revenue for natural gas delivered to customers not yet billed during the accounting period. Determination of unbilled revenue relies on the use of estimates, weather during the period, and current and historical data. The financial statements included unbilled revenue of $990,797 and $1,660,046 as of June 30, 2009 and 2008, respectively.

Allowance for Doubtful Accounts – 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.

Pension and Postretirement Benefits – The Company offers a defined benefit pension plan (“pension plan”) and a post-retirement medical and life insurance plan (“post-retirement plan”) to eligible employees. The expenses and liabilities associated with these plans are based on numerous assumptions and factors, including provisions of the plans, employee demographics, contributions made to the plan, return on plan assets and various actuarial calculations, assumptions and accounting requirements. In regard to the pension plan, specific factors include assumptions regarding the discount rate used in determining future benefit obligations, expected long-term rate of return on plan assets, compensation increases and life expectancies. 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 the rate of medical inflation and Medicare availability. Actual results may differ materially from the results expected from the actuarial assumptions due to changing economic conditions, volatility in interest rates and changes in life expectancy. Such differences may result in a material impact on the amount of expense recorded in future periods or the value of the obligations on the balance sheet.

RGC RESOURCES, INC. AND SUBSIDIARIES

During 2008, the economic crisis and the downturn in the stock market significantly reduced the value of the pension plan assets. If the plan assets do not recover from the losses incurred in 2008, pension expense accruals for future periods are expected to increase sharply. Furthermore, the funded status of the plan has significantly deteriorated, which will result in increasing the Company’s funding requirements in the future. The Company currently expects to fund the pension plan for the current fiscal year at $700,000 and expects funding to remain at this level or higher for the next few years. The Company expects to contribute approximately $600,000 to the post-retirement medical plan.

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

Asset Management

Roanoke Gas uses a third party as an asset manager to manage its pipeline transportation and storage rights and gas supply inventories and deliveries. In return for being able to utilize the excess capacities of the transportation and storage rights, the third party pays Roanoke Gas a monthly utilization fee, which is used to reduce the cost of gas for customers. The current agreement expires in October 2010.

Energy Costs

Energy costs represent the single largest expense of the Company. To help mitigate the impact of potential price volatility, the Company uses various hedging mechanisms, including summer storage injections and financial instruments. Prudently incurred natural gas costs are fully recoverable under the present regulatory PGA mechanism, and increases and decreases in the cost of gas are passed through to the Company’s customers. Since July of last year, the commodity price of natural gas has declined significantly with the NYMEX price falling below $4.00 a decatherm during the quarter before rebounding slightly. The price of natural gas declined at a faster rate than the Company’s PGA factor, which adjusts the billing rate to customers for the cost of natural gas. As a result, the Company moved from an under-collected position at September 30, 2008 to an over-collected position at June 30, 2009. The over-collection will be refunded to customers as part of the PGA factor adjustment based on the September balance.

Although natural gas prices are at their lowest level in recent years, economic recovery, an increased emphasis on reduced carbon emissions and reduced production and exploration

RGC RESOURCES, INC. AND SUBSIDIARIES

activities for natural gas due to the low prices could all place upward pressure on prices in the future. Even though energy costs are recoverable through the PGA mechanism, high energy prices may have a negative impact on earnings through decreased demand resulting from customer conservation or use of alternative fuels, increases in bad debt expense and higher interest costs because the delay in recovering higher gas costs requires borrowing to temporarily fund receivables from customers. The Company’s rate structure provides a level of protection against the impact that rising energy prices may have on bad debts and carrying costs of gas in storage by allowing for more timely recovery of these costs. However, the rate structure will not protect the Company from an increased rate of bad debts or increases in interest rates or decreased demand.

Regulatory Affairs

On November 1, 2008, Roanoke Gas Company placed into effect new base rates that provide for approximately $1,198,000 in additional annual revenues. The Company received a final order from the SCC on June 10, 2009 approving the approximately $1,198,000 in additional annual revenues. Also included as part of the final order was an agreement to modify the WNA mechanism, which would reduce the current weather band from approximately 6% of the 30-year average to a weather band of 3% of the 30-year average with the WNA period beginning in April 2009. The implementation of this new weather band will further reduce the downside exposure that the Company has to warmer than normal weather. In addition, the new weather band will also limit the upside benefit from colder than normal weather to a 3% level.

The Company also filed with the SCC on July 1, 2009 the results of a new depreciation study, which is required to be filed every 5 years. The new depreciation study, which is based on average remaining service life, extended the expected life of the Company’s LNG plant, natural gas service lines and computer equipment resulting in a reduction in the overall composite weighted average depreciation rate from 4.13% to 3.31%. The depreciation study is subject to the review and approval by the SCC before the revised depreciation rates may be applied. Once new depreciation rates are approved, depreciation will be adjusted retroactive to October 1, 2008. The Company anticipates receiving approval from the SCC prior to the end of the current fiscal year and will record the full adjustment, estimated to be a decrease in depreciation expense of approximately $900,000 on an annual basis, if the filed rates are approved without modification, in the fourth quarter as a change in estimate.

Capital Resources and Liquidity

Due to the capital intensive nature of the utility business, as well as the related weather sensitivity, the Company’s primary capital needs are the funding of its continuing construction program, the seasonal funding of its natural gas inventories, accounts receivable and payment of dividends. To meet these needs, the Company relies on its operating cash flows, line-of-credit agreement, and capital generated through the Company’s Dividend Reinvestment and Stock Purchase Plan (“DRIP”).

RGC RESOURCES, INC. AND SUBSIDIARIES

Cash and cash equivalents increased by $12,479,450 for the nine-month period ended June 30, 2009 compared to a $3,214,297 increase for the same period last year. The following table summarizes the categories of sources and uses of cash:

	Nine Months Ended June 30,
	2009			2008
Cash Flow Summary Nine Months Ended:
Continuing operations:
Provided by operating activities	$	26,690,936		$	10,399,251
Used in investing activities		(3,753,567	)		(1,059,900	)
Used in financing activities		(10,457,919	)		(6,236,727	)
Cash provided by discontinued operations		—			111,673
Increase in cash and cash equivalents	$	12,479,450		$	3,214,297

The seasonal nature of the natural gas business causes operating cash flows to fluctuate significantly during the year as well as from year to year. Factors including weather, energy prices, natural gas storage levels and customer collections all contribute to working capital levels and the related cash flows. Generally, operating cash flows are positive during the second and third quarters as a combination of earnings, declining storage gas levels and collections on customer accounts all contribute to higher cash levels. During the first and fourth quarters, operating cash flows generally decrease due to the increases in natural gas storage levels, rising customer receivable balances and construction activity. For the nine months ended June 30, 2009, cash provided by continuing operations increased by approximately $16,292,000, from $10,399,000 for the nine months ended June 30, 2008 to $26,691,000 for the current period. The significant increase in over-collection of gas costs combined with reductions in gas in storage, accounts receivable and accounts payable due to the declining commodity price of natural gas accounted for most of the increase in cash provided by operations.

Investing activities are generally composed of expenditures under the Company’s construction program, which involves a combination of replacing aging bare steel and cast iron pipe with new plastic or coated steel pipe and expansion of its natural gas system to meet the demands of customer growth. Cash flows from investing activities declined by approximately $2,694,000 due to the $3,941,000 in net proceeds received from the sale of the Bluefield Operations in 2007 partially offset by reduced capital expenditures and proceeds from the sale of a short-term investment. Total capital expenditures from continuing operations were $4,281,393 and $5,010,388 for the nine-month periods ended June 30, 2009 and 2008, respectively, which reflected reduced expenditures for extending service to new customers due to declines in residential and commercial construction and less pipeline replacement activity. Roanoke Gas’ total capital budget for the current year is more than $6,100,000 but is below the prior year’s level of $6,539,369 due to the expected continued declines in new business development; however, the Company plans to continue its focus on its pipeline renewal program. Operating cash flow from depreciation currently provides approximately 75% of the annual support for the Company’s current capital budget. The Company also relies on its line-of-credit agreement, other operating cash flows, DRIP activity and long-term debt financing to provide the balance of

RGC RESOURCES, INC. AND SUBSIDIARIES

the underlying funding for its capital expenditures. Once the new depreciation rates are placed into effect, depreciation is expected to provide support for approximately 63% of capital expenditures based on the current year budget. As a result future capital expenditure funding will be more dependent on corporate borrowing activity.

Financing activities generally consist of long-term and short-term borrowings and repayments, issuance of stock and the payment of dividends. As discussed above, the Company uses its line-of-credit arrangement to fund seasonal working capital needs as well as provide temporary financing for capital projects. Cash flow used in financing activities increased by $4,221,000 as the $13,960,000 net reduction in the Company’s line-of-credit balance for the nine-month period ended June 30, 2009 was much greater than the $4,808,000 net pay off for the same period last year. The Company entered into a $5,000,000 variable rate note in October 2008 and used the proceeds to refinance a portion of the line-of-credit balance that provided temporary funding for the retirement of a first mortgage note that matured in July 2008. Proceeds from the issuance of common stock decreased as the Company authorized its transfer agent to acquire a portion of the share requirements of the DRIP on the open market rather than issue new shares.

On March 23, 2009, the Company renewed its line-of-credit agreement for Roanoke Gas Company. Although the Company was able to renew the line-of-credit, the current credit markets resulted in the renewal being on terms less favorable than the expiring agreement. The new agreement increased the variable interest rate to 30-day LIBOR plus 100 basis points and imposed an availability fee of 15 basis points applied to the difference between the face amount of the note and the average outstanding balance during the period. In response to the implementation of an availability fee, the bank agreed to adjust the available limits on a monthly basis to accommodate the Company’s seasonal borrowing demands and minimize overall borrowing costs. Under the new agreement, the Company’s total available limits during its term range from $1,000,000 to $18,000,000. The line-of-credit agreement will expire March 31, 2010, unless extended. The Company anticipates being able to extend or replace the line-of-credit upon expiration; however, there is no guarantee that the line-of-credit will be extended or replaced under the same terms currently in place.

At June 30, 2009, the Company’s consolidated long-term capitalization was 62% equity and 38% debt.

RGC RESOURCES, INC. AND SUBSIDIARIES

ITEM 4T – CONTROLS AND PROCEDURES

The Company maintains disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) that are designed to be effective in providing reasonable assurance that information required to be disclosed in reports under the Exchange Act are recorded, processed and summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission (the “SEC”), and that such information is accumulated and communicated to management to allow for timely decisions regarding required disclosure.

In designing and evaluating disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, will be detected. These inherent limitations include the realities that judgments in decision making can be faulty and that breakdowns can occur because of simple error or mistake. The design of any system of controls is based, in part, upon certain assumptions about the likelihood of future events and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions.

As of June 30, 2009, the Company completed an evaluation, under the supervision and with the participation of management, including the chief executive officer and the chief financial officer (principal financial officer), of the effectiveness of the design and operation of our disclosure controls and procedures. Based upon that evaluation, the chief executive officer and chief financial officer concluded that the Company’s disclosure controls and procedures were effective as of June 30, 2009.

There were not any changes in the Company’s internal controls over financial reporting during the fiscal quarter ended June 30, 2009 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

RGC RESOURCES, INC. AND SUBSIDIARIES

Part II – Other Information

ITEM 1 – LEGAL PROCEEDINGS

None.

ITEM 1A – RISK FACTORS

Not required.

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

Pursuant to the RGC Resources Restricted Stock Plan for Outside Directors (the “Restricted Stock Plan”), 40% of the monthly retainer fee of each non-employee director of the Company is paid in shares of unregistered common stock and is subject to vesting and transferability restrictions (“restricted stock”). A participant can, subject to approval of Directors of the Company (the “Board”), elect to receive up to 100% of his or her 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-OMX on the first day of the month. The shares of restricted stock are issued in reliance on Section 3(a)(11) and Section 4(2) exemptions under the Securities Act of 1933 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, 2009, the Company issued a total of 884 shares of restricted stock pursuant to the Restricted Stock Plan as follows:

Investment Date	Price		Number of Shares
4/1/2009	$	25.170	305
5/1/2009	$	27.030	284
6/1/2009	$	26.000	295

ITEM 3 – DEFAULTS UPON SENIOR SECURITIES

None.

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

None

ITEM 5 – OTHER INFORMATION

None

RGC RESOURCES, INC. AND SUBSIDIARIES

ITEM 6 – EXHIBITS

Number	Description
31.1	Rule 13a–14(a)/15d–14(a) Certification of Principal Executive Officer.
31.2	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer.
32.1	Section 1350 Certification of Principal Executive Officer.
32.2	Section 1350 Certification of Principal Financial Officer.

RGC RESOURCES, INC. AND SUBSIDIARIES

SIGNATURES

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

	RGC Resources, Inc.
Date: August 14, 2009	By:	/s/ Howard T. Lyon
		Howard T. Lyon
		Vice-President, Treasurer and CFO
		(principal financial and principal accounting officer)