Edgar Filing: RGC RESOURCES INC

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For Quarterly Period Ended March 31, 2010

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,” “accelerarted-filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

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


Class		Outstanding at April 30, 2010
Common Stock, $5 Par Value		2,259,602

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

UNAUDITED


	March 31, 2010			September 30, 2009
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	15,480,867		$	7,422,360
Accounts receivable (less allowance for uncollectibles of $434,526 and and $50,687, respectively)		9,416,735			3,562,837
Note receivable		87,000			87,000
Materials and supplies		507,426			587,815
Gas in storage		5,349,715			16,072,911
Prepaid income taxes		—			1,974,917
Deferred income taxes		4,346,690			3,424,628
Other		1,269,516			985,110


Total current assets		36,457,949			34,117,578


UTILITY PROPERTY:
In service		120,286,035			118,009,532
Accumulated depreciation and amortization		(42,209,080	)		(41,104,408	)

In service, net		78,076,955			76,905,124
Construction work in progress		2,101,059			1,604,046


Utility plant, net		80,178,014			78,509,170


OTHER ASSETS:
Note receivable		1,039,000			1,126,000
Regulatory assets		4,873,712			4,989,347
Other		48,029			59,797


Total other assets		5,960,741			6,175,144


TOTAL ASSETS	$	122,596,704		$	118,801,892

See notes to condensed consolidated financial statements.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

UNAUDITED


	March 31, 2010			September 30, 2009
LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES:
Current maturities of long-term debt	$	15,000,000		$	—
Dividends payable		745,669			716,556
Accounts payable		6,046,964			4,449,735
Customer credit balances		885,406			4,204,556
Income taxes payable		1,182,765			—
Customer deposits		1,808,708			1,601,206
Accrued expenses		1,556,497			2,219,587
Over-recovery of gas costs		6,181,810			5,651,847
Fair value of marked-to-market transactions		2,269,168			2,451,055


Total current liabilities		35,676,987			21,294,542


LONG-TERM DEBT, EXCLUDING CURRENT MATURITIES		13,000,000			28,000,000


DEFERRED CREDITS AND OTHER LIABILITIES:
Asset retirement obligations		2,805,707			2,735,735
Regulatory cost of retirement obligations		7,675,369			7,401,024
Benefit plan liabilities		8,186,100			7,970,074
Deferred income taxes		6,609,476			6,534,621
Deferred investment tax credits		50,947			66,025


Total deferred credits and other liabilities		25,327,599			24,707,479


COMMITMENTS AND CONTINGENCIES (Notes 7 and 9)

STOCKHOLDERS’ EQUITY:
Common stock, $5 par value; authorized, 10,000,000 shares; issued and outstanding 2,258,288 and 2,238,987, respectively		11,291,440			11,194,935
Preferred stock, no par, authorized, 5,000,000 shares; no shares issued and outstanding		—			—
Capital in excess of par value		17,047,770			16,607,897
Retained earnings		22,978,375			19,881,745
Accumulated other comprehensive loss		(2,725,467	)		(2,884,706	)


Total stockholders’ equity		48,592,118			44,799,871


TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	122,596,704		$	118,801,892

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

FOR THE THREE-MONTH AND SIX-MONTH PERIODS ENDED MARCH 31, 2010 AND 2009

UNAUDITED


	Three Months Ended March 31,					Six Months Ended March 31,
	2010			2009		2010		2009
OPERATING REVENUES:
Gas utilities	$	31,242,734		$	34,003,752	$	54,051,901	$	62,195,675
Other		397,587			282,750		741,330		550,022

Total operating revenues		31,640,321			34,286,502		54,793,231		62,745,697


COST OF SALES:
Gas utilities		22,085,000			24,821,377		37,267,354		45,064,717
Other		186,228			132,806		363,785		252,624

Total cost of sales		22,271,228			24,954,183		37,631,139		45,317,341


GROSS MARGIN		9,369,093			9,332,319		17,162,092		17,428,356


OTHER OPERATING EXPENSES:
Operations		2,821,444			2,779,088		5,576,801		5,384,594
Maintenance		364,977			385,334		725,697		787,264
General taxes		345,065			322,292		669,771		630,177
Depreciation and amortization		958,987			1,140,517		1,917,975		2,279,035


Total other operating expenses		4,490,473			4,627,231		8,890,244		9,081,070


OPERATING INCOME		4,878,620			4,705,088		8,271,848		8,347,286

OTHER INCOME, Net		15,985			21,883		38,452		55,690

INTEREST EXPENSE		455,871			462,910		920,768		994,230


INCOME BEFORE INCOME TAXES		4,438,734			4,264,061		7,389,532		7,408,746

INCOME TAX EXPENSE		1,685,716			1,620,368		2,806,234		2,815,894


NET INCOME		2,753,018			2,643,693		4,583,298		4,592,852


OTHER COMPREHENSIVE INCOME (LOSS) NET OF TAX		(138,169	)		173,330		159,239		(1,446,799	)


COMPREHENSIVE INCOME	$	2,614,849		$	2,817,023	$	4,742,537	$	3,146,053


BASIC EARNINGS PER COMMON SHARE	$	1.22		$	1.19	$	2.04	$	2.07


DILUTED EARNINGS PER COMMON SHARE	$	1.22		$	1.19	$	2.03	$	2.07


DIVIDENDS DECLARED PER COMMON SHARE	$	0.33		$	0.32	$	0.66	$	0.64

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, 2010 AND 2009

UNAUDITED


	Six Months Ended March 31,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	4,583,298		$	4,592,852
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		1,990,591			2,394,901
Cost of removal of utility plant, net		(146,127	)		(115,899	)
Changes in assets and liabilities which used cash, exclusive of changes and noncash transactions shown separately		5,699,951			14,872,111


Net cash provided by operating activities		12,127,713			21,743,965


CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant and nonutility property		(3,235,029	)		(2,719,571	)
Proceeds from disposal of equipment		—			27,826
Proceeds from sale of short-term investments		—			500,000


Net cash used in investing activities		(3,235,029	)		(2,191,745	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		—			5,000,000
Proceeds on collection of note		87,000			87,000
Net repayments under line-of-credit agreement		—			(13,960,000	)
Proceeds from issuance of stock (19,301 and 13,635 shares, respectively)		536,378			353,993
Cash dividends paid		(1,457,555	)		(1,399,272	)


Net cash used in financing activities		(834,177	)		(9,918,279	)


NET INCREASE IN CASH AND CASH EQUIVALENTS		8,058,507			9,633,941

BEGINNING CASH AND CASH EQUIVALENTS		7,422,360			875,436


ENDING CASH AND CASH EQUIVALENTS	$	15,480,867		$	10,509,377


SUPPLEMENTAL INFORMATION:
Cash paid during the year for:
Interest	$	907,505		$	989,877
Income taxes net of refunds		583,000			2,269,308

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 March 31, 2010 and the results of its operations for the three months and six months ended March 31, 2010 and 2009 and its cash flows for the six months ended March 31, 2010 and 2009. The results of operations for the three months and six months ended March 31, 2010 are not indicative of the results to be expected for the fiscal year ending September 30, 2010 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, 2009 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.

The Company has evaluated subsequent events through the date the financials statements were issued. There were no items not otherwise disclosed which would have materially impacted the Company’s condensed consolidated financial statements.

2. Rates and Regulatory Matters

The State Corporation Commission of Virginia (“SCC”) exercises regulatory authority over the natural gas operations of Roanoke Gas. Such regulation encompasses terms, conditions, and rates to be charged to customers for natural gas service, safety standards, extension of service, accounting and depreciation.

Since 2003, Roanoke Gas Company has had in place a weather normalization adjustment tariff (“WNA”) based on a weather measurement band around the most recent 30-year temperature average. As the non-gas portion of the Company’s billing rates are established based on the 30-year temperature average of the service area, financial performance can be impacted by significant temperature variations. The WNA mitigates the risk of temperature variability by providing the Company with the ability to surcharge customers for lost margin

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

UNAUDITED

for weather that is more than 3% warmer than the 30-year average. Conversely, the Company would refund any margin earned as a result of weather being more than 3% colder than the 30-year average. The annual WNA measurement period extends from April to March. For the WNA period ended March 31, 2010, the number of heating degree days fell within the 3% range of the 30-year average resulting in no provision for WNA during the current period. For the quarter ended December 31, 2009, the Company recorded an estimated WNA of approximately $145,000 in additional margin to reflect the impact of weather being approximately 6% warmer than the 30-year average; however, the colder weather in January and February 2010 caused the weather for the WNA period to fall within the weather band, resulting in the reversal of the December WNA accrual.

In the fourth quarter of fiscal 2009, the Company implemented new depreciation rates related to an updated depreciation study that the SCC requires the Company to conduct every five years. The new rates were approved by the SCC and made effective retroactive to October 1, 2008; however the full impact of the change in depreciation estimate for the year was recorded in the fourth quarter. As a result of the updated depreciation study, the Company’s overall composite weighted average depreciation rate declined from 4.12% to 3.31% of total depreciable assets. If the change in depreciation rates had been reflected in the first quarter of fiscal 2009, the impact to the Statement of Income and Comprehensive Income for the three-months and six-months ended March 31, 2009 would have been to reduce depreciation expense by $224,550 and $447,100, increase net income by $139,311 and $277,381 and increase earnings per share by $0.06 and $0.13, respectively.

3. Debt

On March 29, 2010, the Company and Wachovia Bank renewed its line of credit agreement. The new agreement maintained the same variable interest rate of 30 day LIBOR plus 100 basis points and the availability fee equal to 15 basis points applied to the difference between the face amount of the note and the average outstanding balance during the period. The Company continued the multi-tiered borrowing limits to accommodate the Company’s seasonal borrowing demands and to minimize its borrowing costs. Effective April 1, 2010, the Company’s total available limits during the term of the line-of-credit agreement range from $1,000,000 to $13,000,000.

The line-of-credit agreement will expire March 31, 2011, unless extended. The Company anticipates being able to extend or replace the credit line upon expiration. At March 31, 2010, the Company had no outstanding balance under its line-of-credit agreement.

4. 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.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

UNAUDITED

The Company enters into collars, swaps and caps for the purpose of hedging the price of natural gas in order to provide price stability during the winter months. The fair value of these instruments is recorded in the balance sheet with the offsetting entry to either under-recovery of gas costs or over-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 to customers through the purchased gas adjustment clause (“PGA”) included as part of the Company’s billing rate. At March 31, 2010, the Company has collar agreements outstanding for the balance of 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 March 31, 2010.

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% effective 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 mature on December 1, 2015 and qualify as cash flow hedges with changes in fair value reported in other comprehensive income. No portions of interest rate swaps were deemed ineffective during the periods presented.

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 March 31, 2010 and September 30, 2009:


	March 31, 2010		September 30, 2009

Derivatives designated as hedging instruments:

Interest rate swaps	$	2,269,168	$	2,451,055
Natural gas collar arrangement		—		—


Total derivatives designated as hedging instruments	$	2,269,168	$	2,451,055

The table in Note 5 below reflects the effect on income and other comprehensive income of the Company’s cash flow hedges.

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 this period could significantly change the amount estimated to be reclassified to income as well as the fair value of the interest rate hedges.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

UNAUDITED

5. Comprehensive Income

A summary of other comprehensive income and loss is provided below:


	Three Months Ended March 31,						Six Months Ended March 31,
	2010			2009			2010			2009

Interest Rate SWAPs

Unrealized gains (losses)	$	(494,445	)	$	61,379		$	(290,871	)	$	(2,671,626	)
Income tax		187,692			(23,299	)		110,416			1,014,150


Net unrealized gains (losses)		(306,753	)		38,080			(180,455	)		(1,657,476	)


Transfer of realized losses to interest expense		234,343			199,919			472,758			303,410
Income tax		(88,957	)		(75,890	)		(179,460	)		(115,175	)


Net transfer of realized losses to interest expense		145,386			124,029			293,298			188,235


Defined Benefit Plans

Transfer of realized losses to income		25,619			6,313			51,238			12,626
Income tax		(9,725	)		(2,396	)		(19,450	)		(4,792	)


Net transfer of realized losses to income		15,894			3,917			31,788			7,834


Amortization of transition obligation		11,773			11,773			23,546			23,546
Income tax		(4,469	)		(4,469	)		(8,938	)		(8,938	)


Net amortization of transition obligation		7,304			7,304			14,608			14,608


Net other comprehensive income (loss)	$	(138,169	)	$	173,330		$	159,239		$	(1,446,799	)


Change in measurement date		—			—			—			11,221


Accumulated comprehensive loss - beginning of period		(2,587,298	)		(2,833,300	)		(2,884,706	)		(1,224,392	)


Accumulated comprehensive loss - end of period	$	(2,725,467	)	$	(2,659,970	)	$	(2,725,467	)	$	(2,659,970	)

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

UNAUDITED

The components of accumulated comprehensive loss as of March 31, 2010 and 2009:


	March 31
	2010			2009

Interest rate swaps	$	(1,407,792	)	$	(1,988,911	)
Pension plan		(928,509	)		(360,750	)
Postretirement benefit plan		(389,166	)		(310,309	)


Total accumulated comprehensive loss	$	(2,725,467	)	$	(2,659,970	)

6. Weighted Average Shares

Basic earnings per common share for the three months and six months ended March 31, 2010 and 2009 are calculated by dividing net income by the weighted average common shares outstanding during the period. Diluted earnings per common share for the three months and six months ended March 31, 2010 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 stock 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. There were no anti-dilutive securities in the respective periods. A reconciliation of the weighted average common shares and the diluted average common shares is provided below:


	Three Months Ended March 31,		Six Months Ended March 31,
	2010	2009	2010	2009

Weighted average common shares	2,251,922	2,219,068	2,247,111	2,215,733

Effect of dilutive securities:
Options to purchase common stock	7,719	7,088	7,665	7,424


Diluted average common shares	2,259,641	2,226,156	2,254,776	2,223,157

7. Commitments and Contingencies

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

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

UNAUDITED

gas supply from an asset manager. The Company uses an asset manager to assist in optimizing the use of its transportation, storage rights, and gas supply in order to provide a secure and reliable source of natural gas to its customers. The Company also has storage and pipeline capacity contracts to store and deliver natural gas to the Company’s distribution system. The Company 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.

The Company is not a party to any material pending legal proceedings.

8. Employee Benefit Plans

The Company has both a defined benefit pension plan (the “pension plan”) and a postretirement benefit plan (the “postretirement 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 postretirement plan provides certain healthcare and supplemental life insurance benefits to retired employees who meet specific age and service requirements. Net pension plan and postretirement plan expense recorded by the Company is detailed as follows:


	Three Months Ended March 31,						Six Months Ended March 31,
	2010			2009			2010			2009
Components of net periodic pension cost:

Service cost	$	112,215		$	100,906		$	224,430		$	201,812
Interest cost		213,411			211,725			426,822			423,450
Expected return on plan assets		(204,657	)		(215,537	)		(409,314	)		(431,074	)
Recognized loss		68,778			17,647			137,556			35,294


Net periodic pension cost	$	189,747		$	114,741		$	379,494		$	229,482


	Three Months Ended March 31,						Six Months Ended March 31,
	2010			2009			2010			2009
Components of postretirement benefit cost:

Service cost	$	39,946		$	30,914		$	79,892		$	61,828
Interest cost		128,359			126,005			256,718			252,010
Expected return on plan assets		(81,263	)		(69,179	)		(162,526	)		(138,358	)
Amortization of transition obligation		47,223			47,223			94,446			94,446
Recognized loss		17,134			—			34,268			—


Net postretirement benefit cost	$	151,399		$	134,963		$	302,798		$	269,926

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

UNAUDITED

The Company contributed $200,000 to its pension plan for the six-month period ended March 31, 2010. The Company currently expects to make a total contribution of approximately $800,000 to its pension plan and $600,000 to its postretirement benefit plan during the fiscal year ending September 30, 2010. The Company will continue to evaluate its benefit plan funding levels throughout the year.

9. Environmental Matters

Both Roanoke Gas Company and Bluefield Gas Company, a previously owned subsidiary of the Company, operated manufactured gas plants (MGPs) as a source of fuel for lighting and heating until the late 1940s or early 1950s. A by-product of operating MGPs was coal tar, and the potential exists for on-site tar waste contaminants at the former plant sites. 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 in 2007, it retained ownership of the former MGP site and entered into an Indemnification and Cost Sharing Agreement with ANGD to seek recovery of any remediation costs through rates 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.

10. Newly Adopted Accounting Standards

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (FASB ASC No. 820). FASB ASC No. 820 defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value methods. No new fair value measurements are required. Instead, it provides for increased consistency and comparability in fair value measurements and for expanded disclosure surrounding the fair value measurements. Disclosures regarding nonfinancial assets and liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis, were delayed for one year. The Company adopted the fair value provisions of FASB ASC No. 820 effective October 1, 2008 and the provisions regarding nonfinancial assets and liabilities effective October 1, 2009. The adoption had no material impact on the Company’s financial position, results of operations or cash flows. The disclosures required by FASB ASC No. 820 are included in Note 12.

In January 2010, the FASB issued Accounting Standards Update (“ASU”) 2010-06, Fair Value Measurements and Disclosures – Improving Disclosures about Fair Value Measurements. This ASU improves disclosures regarding fair value under FASB ASC No. 820 including (1) requiring an entity to disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

UNAUDITED

for the transfers, (2) in the reconciliation for fair value measurements using significant unobservable inputs (Level 3), a reporting entity should present separately information about purchases, sales, issuances and settlements and (3) providing clarification that a reporting entity should provide disclosures about the valuation techniques and inputs used to measure fair value for both recurring and non-recurring fair value measurements. The Company adopted ASU 2010-06 effective with its March 31, 2010 reporting date. The disclosures related to Level 3 fair value measurements are not effective until fiscal years beginning after December 31, 2010 and for interim periods within those fiscal years.

In February 2010, the FASB issued Accounting Standards Update (“ASU”) 2010-09, Subsequent Events – Amendment to Certain Recognition and Disclosure Requirements. This ASU amends FASB ASC No. 855 by removing the requirement to disclose the date through which subsequent events have been evaluated for an SEC filer. This ASU is effective upon issuance.

11. 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 (FASB ASC No. 715). FASB’s objective of these changes 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 new disclosure requirements under FASB ASC No. 715 are effective for fiscal years ending after December 15, 2009. Management does not anticipate these changes 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 currently applicable to the Company or are not expected to have a significant impact on the Company’s financial position, results of operations and cash flows.

12. Fair Value Measurements

Effective October 1, 2008, the Company adopted FASB ASC No. 820, Fair Value Measurements and Disclosures, for financial and nonfinancial assets and liabilities that are measured and reported on a fair value basis. FASB ASC No. 820 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. FASB ASC No. 820 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.

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UNAUDITED

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 following tables 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 March 31, 2010 and September 30, 2009:


			Fair Value Measurements – March 31, 2010
	Fair Value		Quoted Prices In Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)

Liabilities:
Natural gas purchases	$	1,900,476	$	—	$	1,900,476	$	—
Interest rate swaps		2,269,168		—		2,269,168		—


Total	$	4,169,644	$	—	$	4,169,644	$	—


			Fair Value Measurements – September 30, 2009
	Fair Value		Quoted Prices In Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)

Liabilities:
Natural gas purchases	$	1,146,734	$	—	$	1,146,734	$	—
Interest rate swaps		2,451,055		—		2,451,055		—


Total	$	3,597,789	$	—	$	3,597,789	$	—

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

UNAUDITED

Under the asset management contract, a timing difference can exist between the payment for natural gas purchases and the actual receipt of such purchases. Payments are made based on a predetermined monthly volume with the price based on the actual first of the month index prices corresponding to the month of the scheduled payment. At March 31, 2010 and September 30, 2009, the Company had a liability in accounts payable reflecting the estimated fair value of the liability valued at the corresponding first of month index prices for which the liability is expected to be settled. The fair value of the interest rate swaps, included in the line item “Fair value of marked-to-market transactions”, is determined by the financial institutions issuing those instruments. The valuation is a mathematical approximation of market value as of the balance sheet date using the counterparty’s proprietary models and certain assumptions regarding past, present and future market conditions.

The Company’s nonfinancial assets and nonfinancial liabilities that are measured at fair value on a nonrecurring basis consist of its asset retirement obligations. The asset retirement obligations are measured at fair value at initial recognition based on expected future cash flows to settle the obligation.

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 as of March 31, 2010 and September 30, 2009. The carrying value of cash and cash equivalents, accounts receivable, accounts payable (with the exception of the timing difference under the asset management contract), customer credit balances and customer deposits is a reasonable estimate of fair value due to the short-term nature of these financial instruments.


	March 31, 2010				September 30, 2009
	Carrying Amount		Fair Value		Carrying Amount		Fair Value

Assets:
Note receivable	$	1,126,000	$	1,088,453	$	1,213,000	$	1,173,749

Liabilities:
Long-term debt	$	28,000,000	$	28,986,491	$	28,000,000	$	29,382,055

Note receivable is composed of $87,000 in current assets and $1,039,000 in other assets. Long-term debt includes current maturities of long-term debt of $15,000,000.

The note receivable is a five year note with a fifteen year amortization as partial payment for the sale of the Bluefield, Virginia natural gas distribution assets to ANGD, LLC in October 2007. 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.

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CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

UNAUDITED

FASB ASC 825, Financial Instruments, requires disclosures regarding concentrations of credit risk from financial instruments. Cash equivalents are investments in high-grade, short-term securities (original maturity less than three months), placed with financially sound institutions. Accounts receivable are from a diverse group of customers including individuals and small and large companies in various industries. As of March 31, 2010 and September 30, 2009, no single customer accounted for more than 5% of the total accounts receivable balance. The Company maintains certain credit standards with its customers and requires a customer deposit if such evaluation warrants. The Company is also exposed to credit risk of nonperformance by the counterparty on its commodity-based collar agreements. The Company uses financially sound institutions to mitigate the risk of nonperformance on these contracts.

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) access to capital markets and the availability of debt and equity financing to support capital expenditures; (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 weather conditions and other 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 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, 2010. The total revenues and margins realized during the first six months reflect higher billings due to the weather sensitive nature of the gas business. Improvement or decline in earnings for the balance of the fiscal year will depend primarily on weather conditions during early spring, improvement or deterioration in the local economic environment and the level of operating and maintenance costs incurred during the remainder of the year.

Overview

Resources is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately 57,600 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 provides certain unregulated services through Roanoke Gas. Such unregulated operations represent less than 3% of total revenues and margin of Resources on an annual basis.

The Company experienced an increase of approximately $110,000 in net income for the quarter ended March 31, 2010 compared to the same period last year. A combination of increased natural gas deliveries due to a greater number of heating degree days (an industry measure by which the average daily temperature falls below 65 degrees Fahrenheit), much lower natural gas commodity prices, reversal of the Weather Normalization Adjustment accrual and updated depreciation rates were the most significant items contributing to the results for the current period.

Winter weather conditions, natural gas prices, and the economic environment have a direct influence on the quantity of natural gas sales and deliveries to the Company’s customers. As a majority of natural gas sales are for heating during the winter season, an increase in heating degree days will generally result in greater natural gas consumption. Total natural gas deliveries increased for the quarter by 9% as residential, commercial and industrial sales all increased due to colder weather and improved production activities in a few of the Company’s largest industrial customers.

During the first quarter, the Company recorded approximately $145,000 in additional revenues to reflect the estimated impact of the WNA mechanism for the difference in margin not realized for the effect of actual weather at 6% warmer than the 30-year average and the top of the WNA weather band at 3% warmer than the 30-year average for the nine-month period ending December 31, 2009. However, the colder weather during the second quarter resulted in the total number of heating degree days during the current WNA period ending March 31, 2010 falling to within the 3% weather band around the 30-year average. As a result, the $145,000 WNA revenue accrual recorded in December was reversed during the current quarter. The prior year

RGC RESOURCES, INC. AND SUBSIDIARIES

did not include a WNA adjustment as the weather for both the quarter and the twelve month WNA period ended March 31, 2009 fell within the weather band for the 30-year average in place at that time.

The commodity price of natural gas has declined from its peak of more than $13.00 per decatherm in the summer of 2008 to under $4.00 per decatherm this past summer and has ranged between $4.00 and $6.50 over the just completed winter heating season. The lower commodity price of natural gas has reduced the gas cost component of the Company’s billing rates making natural gas a lower-cost energy source. During this past summer, the Company purchased natural gas for storage at an average price of $4.00 per decatherm compared to $11.00 per decatherm in fiscal 2008. Although the lower natural gas prices will benefit customers by keeping the Company’s billing rates low, the decline in the total value of gas in storage has resulted in a significant reduction in carrying cost revenues.

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. As a result of the much lower price of natural gas in storage during the current year compared to the same period last year, the Company recognized approximately $257,000 and $597,000 less carrying cost revenues for the three-month and six month periods ended March 31, 2010 than for the same periods during the prior year. Carrying cost revenues are expected to continue to fall below last year’s levels for the balance of the year.

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 incremental short-term 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 decrease. The inverse occurs when inventory costs increase.

RGC RESOURCES, INC. AND SUBSIDIARIES

Results of Operations

Three Months Ended March 31, 2010:

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


	Three Months Ended March 31,				Increase/ (Decrease)			Percentage
	2010		2009		Increase/ (Decrease)			Percentage

Operating Revenues
Gas Utilities	$	31,242,734	$	34,003,752	$	(2,761,018	)	-8	%
Other		397,587		282,750		114,837		41	%


Total Operating Revenues	$	31,640,321	$	34,286,502	$	(2,646,181	)	-8	%


Delivered Volumes
Regulated Natural Gas (DTH)
Residential and Commercial		3,384,178		3,143,990		240,188		8	%
Transportation and Interruptible		748,870		653,192		95,678		15	%


Total Delivered Volumes		4,133,048		3,797,182		335,866		9	%


Heating Degree Days (Unofficial)		2,321		2,052		269		13	%

Total operating revenues for the three months ended March 31, 2010 compared to the same period last year decreased due to significantly lower natural gas prices more than offsetting increases in natural gas deliveries. The per unit cost of natural gas reflected in the cost of sales decreased by 17% compared to last year even though colder weather increased demand for natural gas.


	Three Months Ended March 31,				Increase/ (Decrease)			Percentage
	2010		2009		Increase/ (Decrease)			Percentage
Gross Margin

Gas Utilities	$	9,157,734	$	9,182,375	$	(24,641	)	0	%
Other		211,359		149,944		61,415		41	%


Total Gross Margin	$	9,369,093	$	9,332,319	$	36,774		0	%

Regulated natural gas margins from utility operations remained nearly unchanged from the same period last year as the increase in delivered natural gas volumes was offset by the decline in carrying cost revenues and reversal of the prior quarter WNA accrual. Residential and commercial volumes increased by 8% from last year’s levels. Residential volumes rose by 11% as a result of the colder weather as reflected in the 13% increase in the number of heating degree

RGC RESOURCES, INC. AND SUBSIDIARIES

days. Commercial volumes increased by only 3% as a result of two heavy snows temporarily closing many commercial businesses, a net reduction in commercial customers due to the economy, and the switch of one large commercial customer to transportation service. Industrial usage as represented in the transportation and interruptible categories increased by 15% during the quarter due to increases in production activities of a few of the larger customers and the transfer of a large commercial customer to transportation service. The Company realized approximately $98,000 in additional margin from the growth in customer base charges, which is a flat monthly fee billed to each natural gas customer. As discussed above, carrying cost revenues associated with natural gas inventories declined from last year’s levels corresponding with the sharp decline of the cost of gas in storage. Carrying cost revenues declined by approximately $257,000 for the quarter. The Company also reversed the WNA accrual of $145,000 recorded in December as discussed above.

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

Net Margin Decrease


Customer Base Charge	$	97,968
WNA		(144,821	)
Carrying Cost		(257,110	)
Volumetric		282,843
Other		(3,521	)


Total	$	(24,641	)

Other margins increased by $61,415 over last year primarily due to an increase in contract services in unregulated operations. These contract services represent more than 70% of other margins and are subject to annual renewals. Therefore, there can be no guarantee that the revenues and margins for these services will continue in the future.

Operations expenses increased by $42,356, or 2%, over the same period last year, primarily as a result of higher employee benefit costs. Total employee benefit costs increased by approximately $112,000 over the same period last year due to a $94,000 increase in pension and postretirement medical costs related to the amortization of a higher actuarial loss and $28,000 in higher health insurance premiums. Reductions in contracted and professional services partially offset the increases.

Maintenance expenses decreased by $20,357, or 5%, primarily due to a reduction of the level of pipeline leak repairs.

General taxes increased by $22,773, or 7%, related to higher property taxes associated with increased investment in utility plant and higher payroll taxes.

Depreciation expense decreased by $181,530, or 16%, due to the implementation of new depreciation rates as a result of an updated depreciation study approved and implemented in the fourth quarter of last year. If the new rates were reflected in the first quarter of last year, depreciation expense for the quarter would have been $224,550 less. See note 2 above for more information regarding the change in depreciation rates.

RGC RESOURCES, INC. AND SUBSIDIARIES

Other income, net, decreased by $5,898 primarily due to lower interest rates on the Company’s short-term cash investments and reduction in the note receivable balance.

Interest expense declined by $7,039, or 2%, due to the absence of borrowing under the Company’s line-of-credit. Total average borrowing outstanding during the quarter declined by approximately $2.7 million from last year’s level attributable to lower cost of gas in storage, low accounts receivable balances and an over-collected position on gas costs.

Income tax expense increased by $65,348, or 4%, which corresponds to the increase in pre-tax income for the quarter. The effective tax rate was 38% for both periods.

Six Months Ended March 31, 2010:

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


	Six Months Ended March 31,				Increase/ (Decrease)			Percentage
	2010		2009		Increase/ (Decrease)			Percentage

Operating Revenues
Gas Utilities	$	54,051,901	$	62,195,675	$	(8,143,774	)	-13	%
Other		741,330		550,022		191,308		35	%


Total Operating Revenues	$	54,793,231	$	62,745,697	$	(7,952,466	)	-13	%


Delivered Volumes
Regulated Natural Gas (DTH)
Residential and Commercial		5,470,411		5,418,402		52,009		1	%
Transportation and Interruptible		1,450,139		1,378,946		71,193		5	%


Total Delivered Volumes		6,920,550		6,797,348		123,202		2	%


Heating Degree Days (Unofficial)		3,808		3,560		248		7	%

Total operating revenues for the six months ended March 31, 2010 compared to the same period last year decreased due to reductions in the price of natural gas more than offsetting a higher level of natural gas sales volumes. The average commodity price of gas delivered declined by more than 18% from last year. Total natural gas deliveries increased by 2% on a 7% rise in the number of heating degree days. Transportation volumes increased 5% due to improvement in production activities. Other revenues increased by 35% related primarily to contract services.

RGC RESOURCES, INC. AND SUBSIDIARIES


	Six Months Ended March 31,				Increase/ (Decrease)			Percentage
	2010		2009		Increase/ (Decrease)			Percentage
Gross Margin

Gas Utilities	$	16,784,547	$	17,130,958	$	(346,411	)	-2	%
Other		377,545		297,398		80,147		27	%


Total Gross Margin	$	17,162,092	$	17,428,356	$	(266,264	)	-2	%

Regulated natural gas margins decreased due to declining carrying cost revenues more than offsetting small increases in natural gas deliveries and higher customer base charge revenues. Residential and commercial volumes increased by only 1%; although, residential sales alone increased by 4%. Commercial sales declined by 3% due to a combination of a larger customer switching to transportation service, weather related closings due to snow, and ongoing effects of the depressed economic environment. Industrial activity as represented by the interruptible and transportation customers appeared to rebound modestly during the second quarter as total deliveries to these customers increased by 5%. Carrying cost revenues decreased by approximately $597,000 due to significantly lower average investment in natural gas storage during the period. The components of the regulated margin decrease are summarized below:

Net Margin Decrease


Customer Base Charge	$	241,235
Carrying Cost		(596,766	)
Volumetric		19,978
Other		(10,858	)


Total	$	(346,411	)

Other margins increased by $80,147 due to an increase in contracted services in unregulated operations.

Operations expenses increased by $192,207, or 4%, for the six-month period ended March 31, 2010 compared to the same period last year due to higher employee benefit costs partially offset by a greater level of capitalized overheads. Total employee benefit costs increased by approximately $265,000 due to medical insurance premiums, pension costs and postretirement medical costs. $63,000 more in general and administrative and employee benefit overheads were capitalized due to a more than $500,000 increase in the level of capital expenditures compared to the same period last year. Maintenance expenses decreased by $61,567, or 8%, due to reductions in the level of pipeline leak repairs on the Company’s distribution system.

General taxes increased $39,594, or 6%, for the six-month period ended March 31, 2010 compared to the same period last year. Most of the increase was attributable to higher property taxes related to a higher level of utility plant combined with an increase in payroll taxes.

RGC RESOURCES, INC. AND SUBSIDIARIES

Depreciation expense decreased by $361,060, or 16%, due to the implementation of new depreciation rates as a result of an updated depreciation study approved and implemented in the fourth quarter of last year. If the new rates were reflected in the first quarter of last year, depreciation expense for the six-month period ended March 31, 2009 would have been $447,100 less.

Other income, net, decreased $17,238 due to reduced investment earnings on the Company’s short-term investments and reduction in the note receivable balance.

Interest expense decreased by $73,462, or 7%, due to the absence of borrowing under the Company’s line-of-credit. Total average borrowing outstanding for the current six month period declined by nearly $6.7 million compared to the same period last year.

Income tax expense decreased $9,660, or less than 1%, which corresponds to the slight decrease in pre-tax income. 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 is material to the financial statements and 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 FASB ASC No. 980, Regulated Operations. 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 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.

RGC RESOURCES, INC. AND SUBSIDIARIES

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 administrative 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 receivable of $2,240,912 and $2,956,504 as of March 31, 2010 and 2009, 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 postretirement medical and life insurance plan (“postretirement 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 postretirement 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.

On March 23, 2010, the Patient Protection and Affordable Care Act (PPACA) was signed into law. The PPACA provides for a major overhaul of the nation’s health insurance and health delivery systems with the phase in of various provisions over the next several years. One key provision of the law eliminates the tax deductibility of federal subsidies received by sponsors of postretirement medical plans that provide retiree prescription drug benefits equivalent to Medicare Part D coverage. FASB ASC 740, Income Taxes, requires the immediate recognition of the impact of this change in tax treatment of subsidies. The result of this tax change is to increase income tax expense in the current period by reflecting the full impact of the future loss of the employer’s tax deduction in income tax expense in the current period. Although the Company sponsors a postretirement medical plan, the plan does not meet the equivalency requirements with Medicare Part D and does not receive subsidy payments. Therefore, the Company is not impacted by the change in tax treatment on the federal subsidies.

RGC RESOURCES, INC. AND SUBSIDIARIES

The economic issues and market volatility during the Company’s prior fiscal year resulted in a negative return on the Company’s pension assets that, when combined with a reduction in the discount rate used for determining the benefit liabilities, resulted in an increase in the under-funded position of both plans and an increase in the retirement plan expense during the current year. The deterioration in the funded status of the pension plan has resulted in higher expected funding levels over the next several years. The Company currently expects to fund the pension plan for the current fiscal year at $800,000 and the postretirement medical plan at $600,000. The Company will continue to evaluate its benefit plan funding levels throughout the year in light of the requirements of the Pension Protection Act of 2006 and ongoing investment returns and make adjustments as necessary to avoid benefit restrictions.

Derivatives – The Company may hedge certain risks incurred in its operation through the use of derivative instruments. The Company applies the requirements of FASB ASC No. 815, Derivatives and Hedging, 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. The Company is currently in process of rebidding the contract.

Energy Costs

Energy costs represent the single largest expense of the Company. The Company uses various hedging mechanisms, including summer storage injections and financial instruments to help mitigate the impact of potential price volatility. 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. As discussed above, since the summer of 2008, the commodity price of natural gas has declined significantly with the price falling below $4.00 a decatherm during the summer of 2009 before rebounding. During this time period, 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 of this lag, the Company over-collected on the gas cost component of its rates of approximately $6 million as of December 31, 2009. The Company began refunding the over-collection over a 12 month period as part of the PGA factor adjustment beginning in January 2010.

RGC RESOURCES, INC. AND SUBSIDIARIES

Natural gas prices are currently near the $4.00 per decatherm level and futures indices indicate prices could remain low for the foreseeable future. These low prices are attributable to several factors including the depressed economic environment which limits demand, strong storage levels, adequate production and increased reserve estimates due to new drilling technologies to access natural gas from shale deposits. Continuation of low prices would allow natural gas to remain a viable competitive energy source for heating and production activities. However, a strong economic recovery, an increased use of natural gas for electric generation, or reduced production and exploration activities 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 without the benefit of future rate case filings and rate awards.

Regulatory Affairs

As discussed in more detail in Note 2, the Company implemented, in the fourth quarter of fiscal 2009, new depreciation rates related to an updated depreciation study. The new rates were effective retroactive to October 1, 2008; however the full impact of the change in depreciation estimate for the year was recorded in the fourth quarter. If the change in depreciation rates had been reflected in the first quarter of fiscal 2009, the impact to the Statement of Income and Comprehensive Income for the three-months and six-months ended March 31, 2009 would have been to reduce depreciation expense by $224,550 and $447,100, increase net income by $139,311 and $277,381 and increase earnings per share by $0.06 and $0.13, respectively.

Beginning with the January 2010 billing cycle, the Company began refunding the over-collection of gas costs through reduced billing rates to its customers as approved by the SCC.

The Company continues to evaluate its financial performance and review its revenue requirements in order to determine when to make its next non-gas cost rate filing request.

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, long-term debt and capital raised through the Company’s Dividend Reinvestment and Stock Purchase Plan (“DRIP”).

RGC RESOURCES, INC. AND SUBSIDIARIES

Cash and cash equivalents increased by $8,058,507 for the six-month period ended March 31, 2010 compared to a $9,633,941 increase for the same period last year. The following table summarizes the categories of sources and uses of cash:


	Six Months Ended March 31,
	2010			2009
Cash Flow Summary Six Months Ended:

Provided by operating activities	$	12,127,713		$	21,743,965
Used in investing activities		(3,235,029	)		(2,191,745	)
Used in financing activities		(834,177	)		(9,918,279	)


Increase in cash and cash equivalents	$	8,058,507		$	9,633,941

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 six months ended March 31, 2010, cash provided by operations decreased by approximately $9,616,000, from $21,744,000 for the six months ended March 31, 2009 to $12,128,000 for the current period. The decline in cash provided by operating activities is attributable to the $7,900,000 cash generated from the over-collection of gas costs that occurred during the prior year combined with a greater reduction in the level of gas in storage inventory. Gas in storage is generally at its lowest point at the end of March. The prior year reflected a greater amount of cash generated from the withdrawal of gas in storage due to a higher average price of gas in storage. Due to natural gas price spikes during the summer of 2008 injection period, the average price of gas in storage during the prior winter season was approximately $9.75 per decatherm. As gas prices declined to as low as $4.00 a decatherm during last summer’s storage injection time frame, the cost of gas in storage dropped to around $6.00 per decatherm. The Company is currently in the process of refunding the prior year’s over-collection of gas costs to its customers. Furthermore, based on the natural gas futures prices, the price of gas delivered to storage should be at the same level or lower than the price of gas delivered to storage during the prior year.

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 used in investing activities increased by approximately $1,043,000 due to a higher level of capital expenditures and the absence of proceeds on the sale of short-term investments. Total capital expenditures were $3,235,029 and $2,719,571 for the six-month

RGC RESOURCES, INC. AND SUBSIDIARIES

periods ended March 31, 2010 and 2009, respectively, which reflects increased expenditures for pipeline replacement activity and improvements to the liquefied natural gas facility. Roanoke Gas’ total capital budget for the current year is more than $7,500,000. The Company anticipates increasing the pace of its distribution pipeline renewal for the balance of the current year and for the next several years. Historically, depreciation cash flow has provided approximately 70% of the annual support for the Company’s capital budget. With the implementation of new depreciation rates as a result of the updated depreciation study, operating cash flow from depreciation will be approximately 20% less than what was provided under the prior depreciation rates. As a result future capital expenditure funding will be more dependent on 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 declined by approximately $9,084,000, moving from $9,918,000 to $834,000. The reason for the decline in use of funds corresponds to the absence of borrowing activity for the current year under the Company’s line-of-credit agreement. The prior year reflected the net pay off of $13,960,000 under the line-of-credit. The impact of much lower natural gas prices and their effect on reducing inventory and accounts receivable levels and increasing the over-recovery of gas costs have generated sufficient levels of cash to avoid accessing the line-of-credit during the current year. Assuming natural gas commodity prices remain in the current range of $4.00 to $5.50 per decatherm over the next 12 months along with the refunding of the over-recovery of gas costs which began in January, the Company expects to return to a borrowing mode using its line-of-credit next winter.

On March 29, 2010, the Company renewed its line-of-credit agreement for Roanoke Gas Company. The new agreement maintained the same terms and rates as provided for under the expired agreement. The interest rate is based on 30-day LIBOR plus 100 basis points and includes 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. The Company maintained the multi-tiered borrowing limits to accommodate the Company’s seasonal borrowing demands and minimize the overall borrowing costs. Under the new agreement, the Company’s total available limits during its term range from $1,000,000 to $13,000,000. The line-of-credit agreement will expire March 31, 2011, 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.

The Company’s $15,000,000 variable rate note is currently classified as a current liability and is scheduled to mature on December 1, 2010. This note provides for an interest rate of LIBOR plus 69 basis points and has an interest rate swap that essentially converts the note into a fixed rate instrument at a rate of 5.74%. Due to the current economic climate and its effect on the credit markets, the Company has been unable to extend the note by more than one year without incurring a higher interest rate than is currently in place. In addition, the current credit market has increased the interest rate spreads on commercial debt instruments above the levels in place when the note was originally issued. The Company anticipates being able to extend the note on a one year basis on terms comparable to the current note.

RGC RESOURCES, INC. AND SUBSIDIARIES

At March 31, 2010, the Company’s consolidated long-term capitalization, including current maturities of long-term debt, was 63% equity and 37% debt.

RGC RESOURCES, INC. AND SUBSIDIARIES

ITEM 3 – QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not required.

ITEM 4 – 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.

As of March 31, 2010, 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 the Company’s 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 at the reasonable assurance level as of March 31, 2010.

There were not any changes in the Company’s internal controls over financial reporting during the fiscal quarter ended March 31, 2010 that materially affected, or are reasonably likely to materially affect, our internal controls 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 forfeiture 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 or her term on the Board or (ii) removal for cause. During the quarter ended March 31, 2010, the Company issued a total of 676 shares of restricted stock pursuant to the Restricted Stock Plan as follows:


Investment Date	Price		Number of Shares
1/4/2010	$	30.520	223
2/1/2010	$	31.290	225
3/2/2010	$	30.900	228

ITEM 3 – DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4 – RESERVED

ITEM 5 – OTHER INFORMATION

On January 25, 2010, the Company held its Annual Meeting of Shareholders to elect three directors and to ratify the selection of independent auditors.

Shareholders elected all nominees for Class A directors as listed below to serve a three- year term expiring at the Annual Meeting of Shareholders to be held in 2013.

RGC RESOURCES, INC. AND SUBSIDIARIES


Director	Shares For	Shares Withheld	Broker Non Votes

Abney S. Boxley, III	1,112,954	4,911	799,890
S. Frank Smith	1,115,386	2,479	799,890
John B. Williamson, III	1,106,831	11,034	799,890

Nancy H. Agee, J. Allen Layman and Raymond D. Smoot, Jr. continue to serve as Class B directors until the Annual Meeting of Shareholders to be held in 2011. Frank T. Ellett, Maryellen F. Goodlatte and George W. Logan continue to serve as Class C directors until the Annual Meeting of Shareholders to be held in 2012.

Shareholders approved the selection by the Audit Committee of the Board of Directors of the firm Brown Edwards & Company, LLP as independent auditors for the fiscal year ending September 30, 2010, by the following vote.

Shares

For

Shares

Against

Shares

Abstaining

1,918,519

4,485

1,487

ITEM 6 – EXHIBITS


Number		Description

10.1		Promissory Note in the original principal amount of $13,000,000 by Roanoke Gas Company in favor of Wachovia Bank, National Association dated March 29, 2010 (incorporated by reference to Exhibit 10.1 on Form 8-K as filed March 31, 2010.)

10.2		Change in Control Agreement between RGC Resources, Inc. and Dale P. Lee effective May 1, 2010 (incorporated by reference to Exhibit 10.2 on Form 8-K as filed March 31, 2010.)

10.3		Change in Control Agreement between RGC Resources, Inc. and Robert L. Wells, II effective May 1, 2010 (incorporated by reference to Exhibit 10.3 on Form 8-K as filed March 31, 2010.)

RGC RESOURCES, INC. AND SUBSIDIARIES



10.4		Change in Control Agreement between RGC Resources, Inc. and Howard T. Lyon effective May 1, 2010 (incorporated by reference to Exhibit 10.4 on Form 8-K as filed March 31, 2010.)

31.1		Rule 13a–14(a)/15d–14(a) Certification of Principal Executive Officer.

31.2		Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer.

32.1		Section 1350 Certification of Principal Executive Officer.

32.2		Section 1350 Certification of Principal Financial Officer.

RGC RESOURCES, INC. AND SUBSIDIARIES

SIGNATURES

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


	RGC Resources, Inc.

Date: May 13, 2010	By:	/s/ Howard T. Lyon
		Howard T. Lyon
		Vice-President, Treasurer and CFO
		(principal financial and principal accounting officer)