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,~~December 31, 2013

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 ý 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 ý 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.

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

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~~January 31, ~~2013~~2014
Common Stock, $5 Par Value		~~4,707,730~~4,711,367

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

UNAUDITED


	June 30, 2013			September 30, 2012			December 31, 2013			September 30, 2013
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	10,767,845		$	8,909,871		$	496,919		$	2,846,224
Accounts receivable (less allowance for uncollectibles of $269,252 and $65,219, respectively)	4,365,785			3,617,925
Notes receivable	47,692			1,142,770
Accounts receivable (less allowance for uncollectibles of $200,177 and $68,539, respectively)							11,471,453			3,729,106
Materials and supplies	716,562			613,548			760,849			760,781
Gas in storage	7,286,144			9,466,095			7,590,916			10,316,240
Prepaid income taxes	—			2,072,687			—			836,966
Deferred income taxes	3,535,564			2,371,609			3,323,476			2,852,073
Under-recovery of gas costs	—			687,194
Other	856,526			1,365,615			1,558,124			866,646
Total current assets	27,576,118			30,247,314			25,201,737			22,208,036
UTILITY PROPERTY:
In service	140,962,333			135,912,571			147,422,697			144,388,721
Accumulated depreciation and amortization	(48,283,746		)	(46,563,520		)	(49,271,616		)	(48,653,487		)
In service, net	92,678,587			89,349,051			98,151,081			95,735,234
Construction work in progress	2,397,955			1,481,041			2,629,496			2,001,315
Utility plant, net	95,076,542			90,830,092			100,780,577			97,736,549
OTHER ASSETS:
Regulatory assets	8,511,266			8,542,048			4,453,267			4,474,111
Other	76,170			136,884			87,841			108,005
Total other assets	8,587,436			8,678,932			4,541,108			4,582,116
TOTAL ASSETS	$	131,240,096		$	129,756,338		$	130,523,422		$	124,526,701

See notes to condensed consolidated financial statements.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

UNAUDITED


	June 30, 2013			September 30, 2012			December 31, 2013			September 30, 2013
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt							$	1,600,000		$	—
Borrowings under line-of-credit							3,814,386			—
Note payable	$	15,000,000		$	15,000,000		15,000,000			15,000,000
Dividends payable	847,391			817,462			871,602			847,736
Accounts payable	6,366,201			4,756,460			5,306,336			5,723,107
Customer credit balances	570,166			2,382,089			1,286,907			1,277,515
Income taxes payable	466,212			—			479,071			—
Customer deposits	1,501,659			1,567,501			1,576,645			1,476,451
Accrued expenses	1,666,324			2,102,165			1,661,338			2,118,182
Over-recovery of gas costs	2,453,887			—			2,287,585			1,027,303
Fair value of marked-to-market transactions	2,160,857			2,916,718			1,770,067			1,986,695
Total current liabilities	31,032,697			29,542,395			35,653,937			29,456,989
LONG-TERM DEBT	13,000,000			13,000,000			11,400,000			13,000,000
DEFERRED CREDITS AND OTHER LIABILITIES:
Asset retirement obligations	4,337,339			4,251,295			4,571,846			4,525,355
Regulatory cost of retirement obligations	8,240,424			7,828,157			8,360,137			8,180,173
Benefit plan liabilities	12,257,959			12,541,251			5,416,093			5,582,073
Deferred income taxes	13,201,558			11,898,178			14,580,684			14,276,596
Deferred investment tax credits	5,355			12,132			834			3,093
Total deferred credits and other liabilities	38,042,635			36,531,013			32,929,594			32,567,290
STOCKHOLDERS’ EQUITY:
Common stock, $5 par value; authorized 10,000,000 shares; issued and outstanding 4,707,348 and 4,670,567, respectively	23,536,740			23,352,835
Common stock, $5 par value; authorized 10,000,000 shares; issued and outstanding 4,711,047 and 4,709,326, respectively							23,555,235			23,546,630
Preferred stock, no par, authorized 5,000,000 shares; no shares issued and outstanding	—			—			—			—
Capital in excess of par value	7,933,059			7,375,666			8,040,579			8,003,787
Retained earnings	21,051,886			23,904,514			20,954,425			20,103,239
Accumulated other comprehensive loss	(3,356,921		)	(3,950,085		)	(2,010,348		)	(2,151,234		)
Total stockholders’ equity	49,164,764			50,682,930			50,539,891			49,502,422
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	131,240,096		$	129,756,338		$	130,523,422		$	124,526,701

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

FOR THE THREE-MONTH ~~AND NINE-MONTH~~ PERIODS ENDED ~~JUNE 30,~~DECEMBER 31, 2013 AND 2012

UNAUDITED


	Three Months Ended June 30,					Nine Months Ended June 30,				Three Months Ended December 31,
	2013			2012		2013		2012		2013			2012
OPERATING REVENUES:
Gas utilities	$	10,823,853		$	9,422,220	$	53,059,322	$	48,617,001	$	19,760,987		$	18,458,739
Other	213,455			257,522		900,216		852,144		250,207			287,853
Total operating revenues	11,037,308			9,679,742		53,959,538		49,469,145		20,011,194			18,746,592
COST OF SALES:
Gas utilities	5,647,842			4,543,936		30,643,781		26,793,998		11,671,994			10,650,461
Other	160,439			160,428		564,520		451,620		136,208			159,648
Total cost of sales	5,808,281			4,704,364		31,208,301		27,245,618		11,808,202			10,810,109
GROSS MARGIN	5,229,027			4,975,378		22,751,237		22,223,527		8,202,992			7,936,483
OTHER OPERATING EXPENSES:
Operations and maintenance	3,091,433			3,045,010		9,849,545		9,606,730		3,343,350			3,504,843
General taxes	371,301			336,393		1,131,016		1,040,125		388,197			361,077
Depreciation and amortization	1,120,472			1,063,484		3,361,416		3,182,065		1,198,799			1,120,472
Total other operating expenses	4,583,206			4,444,887		14,341,977		13,828,920		4,930,346			4,986,392
OPERATING INCOME	645,821			530,491		8,409,260		8,394,607		3,272,646			2,950,091
OTHER INCOME (EXPENSE), Net	(11,662		)	17,025		4,805		33,184		(25,135		)	17,042
INTEREST EXPENSE	456,103			456,313		1,370,417		1,372,022		464,453			459,461
INCOME BEFORE INCOME TAXES	178,056			91,203		7,043,648		7,055,769		2,783,058			2,507,672
INCOME TAX EXPENSE	67,953			38,905		2,680,685		2,685,252		1,060,270			953,519
NET INCOME	$	110,103		$	52,298	$	4,362,963	$	4,370,517	$	1,722,788		$	1,554,153
BASIC EARNINGS PER COMMON SHARE	$	0.02		$	0.01	$	0.93	$	0.94	$	0.37		$	0.33
DILUTED EARNINGS PER COMMON SHARE	$	0.02		$	0.01	$	0.93	$	0.94	$	0.37		$	0.33
DIVIDENDS DECLARED PER COMMON SHARE	$	0.180		$	0.175	$	1.540	$	0.525	$	0.185		$	1.180

See notes to condensed consolidated financial statements.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

FOR THE THREE-MONTH ~~AND NINE-MONTH~~ PERIODS ENDED ~~JUNE 30,~~DECEMBER 31, 2013 AND 2012

UNAUDITED


	Three Months Ended June 30,				Nine Months Ended June 30,				Three Months Ended December 31,
	2013		2012		2013		2012		2013		2012
NET INCOME	$	110,103	$	52,298	$	4,362,963	$	4,370,517	$	1,722,788	$	1,554,153
Other comprehensive income, net of tax:
Interest rate SWAPs	219,381		5,920		468,935		183,191		134,396		146,206
Defined benefit plans	41,409		38,345		124,229		115,035		6,490		41,410
OTHER COMPREHENSIVE INCOME, NET OF TAX	260,790		44,265		593,164		298,226		140,886		187,616
COMPREHENSIVE INCOME	$	370,893	$	96,563	$	4,956,127	$	4,668,743	$	1,863,674	$	1,741,769

See notes to condensed consolidated financial statements.

RGC RESOURCES, INC. AND SUBSIDIARIES

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

ENDED ~~JUNE 30,~~DECEMBER 31, 2013 AND 2012

UNAUDITED


	Nine Months Ended June 30,						Three Months Ended December 31,
	2013			2012			2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	4,362,963		$	4,370,517		$	1,722,788		$	1,554,153
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	3,492,954			3,302,626			1,247,260			1,164,319
Cost of removal of utility plant, net	(361,219		)	(303,546		)	(82,487		)	(94,933		)
Stock option grants	42,420			—			12,552			—
Changes in assets and liabilities which used cash, exclusive of changes and noncash transactions shown separately	6,580,050			8,495,593			(4,169,485		)	(4,800,752		)
Net cash provided by operating activities	14,117,168			15,865,190
Net cash used in operating activities							(1,269,372		)	(2,177,213		)
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant and nonutility property	(6,883,039		)	(6,492,885		)	(4,083,171		)	(2,494,277		)
Proceeds from disposal of equipment	15,552			14,250			3,743			720
Net cash used in investing activities	(6,867,487		)	(6,478,635		)	(4,079,428		)	(2,493,557		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds on collection of notes	1,095,077			230,078
Proceeds from collection of notes							—			47,693
Borrowings under line-of-credit agreement	4,354,402			—			8,797,079			4,354,402
Repayments under line-of-credit agreement	(4,354,402		)	—			(4,982,693		)	(3,075,186		)
Proceeds from issuance of stock (36,781 and 35,019 shares, respectively)	698,878			591,517
Proceeds from issuance of stock (1,721 and 27,720 shares, respectively)							32,845			530,352
Cash dividends paid	(7,185,662		)	(2,410,771		)	(847,736		)	(5,492,800		)
Net cash used in financing activities	(5,391,707		)	(1,589,176		)
NET INCREASE IN CASH AND CASH EQUIVALENTS	1,857,974			7,797,379
Net cash provided by (used in) financing activities							2,999,495			(3,635,539		)
NET DECREASE IN CASH AND CASH EQUIVALENTS							(2,349,305		)	(8,306,309		)
BEGINNING CASH AND CASH EQUIVALENTS	8,909,871			7,951,429			2,846,224			8,909,871
ENDING CASH AND CASH EQUIVALENTS	$	10,767,845		$	15,748,808		$	496,919		$	603,562
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid	$	1,496,299		$	1,486,815		$	603,458		$	613,658
Income taxes paid	372,076			525,225
Income taxes refunded, net							—			(145,924		)

SUPPLEMENTAL INFORMATION - NON-CASH TRANSACTION:

The Company’s $15,000,000 note due March 31, 2013 was refinanced with the issuance of a $15,000,000 one-year term note dated March 31, 2013.

See notes to condensed consolidated financial statements.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

UNAUDITED


1.	Basis of Presentation

RGC Resources, Inc. is an energy services company primarily engaged in the sale and distribution of natural gas. The consolidated financial statements include the accounts of RGC Resources, Inc. and its wholly owned subsidiaries (“Resources” or the “Company”); Roanoke Gas Company; Diversified Energy Company; and RGC Ventures of Virginia, Inc.

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,~~December 31, 2013 and the results of its operations and comprehensive income for the three months ~~and nine months~~ ended ~~June 30,~~December 31, 2013 and 2012 and its cash flows for the ~~nine~~three months ended ~~June 30,~~December 31, 2013 and 2012. The results of operations for the three months ~~and nine months~~ ended ~~June 30,~~December 31, 2013 are not indicative of the results to be expected for the fiscal year ending September 30, ~~2013~~2014 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 unaudited condensed consolidated interim financial statements and condensed notes are presented as permitted under the rules and regulations of the Securities and Exchange Commission. Pursuant to those rules, certain information and note disclosures normally included in the annual financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted, although the Company believes that the disclosures made are adequate to make the information not misleading. Therefore, 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, ~~2012~~2013 balance sheet was included in the Company’s audited financial statements on 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’s significant accounting policies are described in Note 1 to the consolidated financial statements in Form 10-K for the year ended September 30, ~~2012.~~2013. Newly adopted and newly issued accounting standards are discussed below.

Recently ~~Issued~~Adopted Accounting Standards

In June 2011, the FASB issued guidance under FASB ASC No. 220 – Comprehensive Income that defines the presentation of Comprehensive Income in the financial statements. According to the guidance, an entity may present a single continuous statement of comprehensive income or two separate statements – a statement of income and a statement of other comprehensive income that immediately follows the statement of income. In either presentation, the entity is required to present on the face of the financial statement the components of other comprehensive income including the reclassification adjustment for items that are reclassified from other comprehensive income to net income. In December 2011, the FASB issued additional guidance under FASB ASC No. 220 that deferred the effective date of earlier guidance with regard to the presentation of reclassifications of items out of accumulated other comprehensive income. All other provisions of the original guidance remain in effect. ~~The new~~These requirements have been included in the Consolidated Statements of Comprehensive Income presented in the Company’s financial statements.

In February 2013, the FASB issued additional guidance regarding the reporting of amounts reclassified out of accumulated other comprehensive income. Under the new provisions, an entity must present the effects on the line items of net income of significant amounts reclassified out of accumulated other comprehensive income. The disclosures required under this guidance are provided in Note 65 below.

Recently Issued Accounting Standards

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


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; and accounting and depreciation.

On November 1, ~~2012,~~2013, Roanoke Gas Company placed into effect new base rates, subject to refund, that provided for approximately $~~1,840,000~~1,664,000 in additional annual non-gas revenues. The amount of the final rate award may be more or less than the amount reflected in the financial statements and will not be known until the SCC issues its order. The Company has recorded an estimated reserve that management believes may be refundable to customers. The public hearing on the request for this rate increase is scheduled for March 25, 2014, with a final order expected sometime after that date.

On ~~March 21,~~August 16, 2013, the Company ~~reached~~filed an application for a ~~stipulated~~

~~RGC RESOURCES, INC. AND SUBSIDIARIES~~

~~agreement with~~modification to the SAVE (Steps to Advance Virginia's Energy) Plan and Rider. The original SAVE Plan and Rider were approved by the SCC ~~staff~~through an order issued on August 29, 2012. The original SAVE Plan was designed to facilitate the accelerated replacement of aging natural gas infrastructure assets by providing a mechanism for ~~a non-gas rate award in the amount of~~ ~~$649,639. On April 1, 2013, the Hearing Examiner issued his report accepting the stipulated agreement between~~ the Company to recover the related depreciation and ~~SCC staff providing~~expenses and return on rate base of the additional capital investment without the filing of a formal application for a ~~$649,639~~an increase in non-gas ~~revenues while maintaining a~~ ~~9.75%~~ ~~authorized return on equity. On April 16, 2013,~~base rates. Under the ~~SCC issued its final order approving~~original filing, the ~~increase~~SAVE Plan primarily covered replacement of the Company's bare steel and cast iron natural gas distribution pipe. Under the modification, the Company sought to include two unique projects; the replacement of the boil off compressor at the Company's liquified natural gas (LNG) plant and modifications to the natural gas transfer station located in ~~annual non-gas revenues agreed to~~Gala, VA in the ~~stipulation. During May~~2014 SAVE Plan year. These replacements will enhance the safety and reliability of the Company's gas distribution system. On December 9, 2013, the Company ~~completed its refund for~~received SCC approval to implement SAVE Rider rates effective January 1, 2014 to begin recovering the ~~difference between~~costs related to the ~~rates placed into effect on November 1~~pipeline replacement, installation of a new LNG boil off compressor and modifications to the ~~final rates approved by the SCC.~~natural gas transfer station.

Roanoke Gas Company has in place a weather normalization adjustment mechanism (“WNA”) based on a weather measurement band around the most recent 30-year temperature average. The WNA provides for a weather band of 3% above or below the 30-year temperature average whereby the Company would recover from its customers the lost margin (excluding gas costs) from the impact of weather that is more than 3% warmer than the 30-year average or refund customers the excess earned from weather that is more than 3% colder than the 30-year average. AtAs of December 31, 2013, the ~~end of the most recent WNA period, April 2012 through March 2013,~~ total heating degree days (an industry measure by which the average daily temperature falls below 65 degrees Fahrenheit) for the current WNA period fell within the 3% weather band ~~and~~ thereby ~~did~~ not ~~trigger the WNA~~triggering an accrual for ~~that period.~~WNA. The Company ~~recorded~~accrued approximately $~~1,747,000~~182,000 in WNA revenues for ~~WNA period~~the quarter ended ~~March~~December 31, 2012 as total heating degree days were approximately ~~22%~~8% less than the ~~30-year~~30 year average. The Company applied the provisions of FASB ASC No. 980, Regulated Operations, in recording the asset and revenue for the WNA.


3.	Short-Term Debt

The Company ~~and Wells Fargo Bank entered into a new~~has an unsecured line-of-credit agreement dated March 31, 2013. The ~~new~~ agreement ~~maintained the same~~has a variable interest rate ofbased on 30 day LIBOR plus 100 basis points and ~~the~~an availability fee of ~~the prior line-of-credit agreement.~~15 basis points. The ~~Company continued the~~agreement also includes multi-tiered borrowing limits to accommodate seasonal borrowing demands and to minimize borrowing costs. The Company’s total available borrowing limits during the remaining term of the line-of-credit agreement range from $1,000,000 to $~~7,000,000~~8,000,000.

The line-of-credit agreement will expire March 31, 2014, unless extended. The Company anticipates being able to extend or replace the credit line upon expiration. ~~At quarter end,~~As of December 31, 2013, the Company had no$3,814,386 outstanding balance under its line-of-credit agreement.

The Company also ~~executed~~has an unsecured promissory note ~~dated March 31, 2013~~ in the amount of $15,000,000. This note essentially extends the maturity date of the prior note to March 31, 2014 and retains all other terms and conditions provided for in the original promissory note. The Company anticipates being able to renew this note on comparable terms as currently in place until such time the note co-terminates with the corresponding interest rate swap.


4.	~~Financing Receivables~~

Financing receivables represent a contractual right to receive money either on demand or on fixed or determinable dates and are recognized as assets on the entity’s balance sheet. The Company has two primary types of financing receivables: trade accounts receivable, resulting from the sale of natural gas and other services to its customers, and notes receivable. Trade accounts receivable are short-term in nature and a provision for uncollectible balances is included in the financial statements. The Company’s notes receivable represents the balance on a 24 month note from a customer related to the payment for relocating a portion of a natural gas distribution main. Management evaluates the status of the note each reporting period to make an assessment on the collectability of the outstanding balance. In its most recent evaluation, management concluded that the balance of the note continued to be fully collectible and no loss reserve was required. The note would be considered past due if either the interest or principal installment were outstanding for more than 30 days after its contractual due date. The Company also had a note receivable related to the sale of its Bluefield, Virginia natural gas distribution assets in October 2007. The ~~$865,000~~ ~~balance on this note, which was due on November 1, 2013, was paid in full on February 1, 2013.~~


5.	Derivatives and Hedging

The Company’s risk management policy allows management to enter into derivatives for the purpose of managing the 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

The Company has two interest rate swaps associated with its variable rate notes. The first swap relates to the $15,000,000 term note originally issued in November 2005 and most recently renewed as a one year term loan due March 31, 2014 as described in Note 3. 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

~~RGC RESOURCES, INC. AND SUBSIDIARIES~~

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 portion of either interest rate swap was deemed ineffective during the periods presented.

The table below reflects the fair values of the derivative instruments and their corresponding classification in the condensed consolidated balance sheets under the current liabilities caption of “Fair value of marked-to-market transactions” as of ~~June 30,~~December 31, 2013 and September 30, ~~2012:~~2013:


	June 30, 2013		September 30, 2012		December 31, 2013		September 30, 2013
Derivatives designated as hedging instruments:
Interest rate swaps	$	2,160,857	$	2,916,718	$	1,770,067	$	1,986,695

The table in Note 65 reflects the effect on income and other comprehensive income of the Company’s cash flow hedges.

Based on the current interest rate environment, management estimates that approximately $~~930,000~~935,000 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.


6.5.	Comprehensive Income

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


	Before-Tax Amount			Tax (Expense) or Benefit			Net-of-Tax Amount			Before-Tax Amount			Tax (Expense) or Benefit			Net-of-Tax Amount
Three Months Ended June 30, 2013
Interest rate swaps:
Unrealized gains	$	116,014		$	(44,039	)	$	71,975
Transfer of realized losses to interest expense	237,598			(90,192		)	147,406
Net interest rate SWAPs	353,612			(134,231		)	219,381
Defined benefit plans:
Amortization of actuarial losses	54,973			(20,868		)	34,105
Amortization of transition obligation	11,773			(4,469		)	7,304
Net defined benefit plans	66,746			(25,337		)	41,409
Other comprehensive income	$	420,358		$	(159,568	)	$	260,790
Three Months Ended June 30, 2012
Three Months Ended December 31, 2013
Interest rate swaps:
Unrealized losses	$	(224,189	)	$	85,102		$	(139,087	)	$	(25,088	)	$	9,523		$	(15,565	)
Transfer of realized losses to interest expense	233,731			(88,724		)	145,007			241,716			(91,755		)	149,961
Net interest rate SWAPs	9,542			(3,622		)	5,920			216,628			(82,232		)	134,396
Defined benefit plans:
Amortization of actuarial losses	50,034			(18,993		)	31,041			10,461			(3,971		)	6,490
Amortization of transition obligation	11,773			(4,469		)	7,304			—			—			—
Net defined benefit plans	61,807			(23,462		)	38,345			10,461			(3,971		)	6,490
Other comprehensive income	$	71,349		$	(27,084	)	$	44,265		$	227,089		$	(86,203	)	$	140,886
Three Months Ended December 31, 2012
Interest rate swaps:
Unrealized losses										$	(2,618	)	$	994		$	(1,624	)
Transfer of realized losses to interest expense										238,282			(90,452		)	147,830
Net interest rate SWAPs										235,664			(89,458		)	146,206
Defined benefit plans:
Amortization of actuarial losses										54,973			(20,868		)	34,105
Amortization of transition obligation										11,774			(4,469		)	7,305
Net defined benefit plans										66,747			(25,337		)	41,410
Other comprehensive income										$	302,411		$	(114,795	)	$	187,616

~~RGC RESOURCES, INC. AND SUBSIDIARIES~~

Before-Tax
Amount

Tax
(Expense)
or Benefit

Net-of-Tax
Amount
Nine Months Ended June 30, 2013
Interest rate swaps:
Unrealized gains $ 45,497
$ (17,271 ) $ 28,226
Transfer of realized losses to interest expense 710,363
(269,654 ) 440,709
Net interest rate SWAPs 755,860
(286,925 ) 468,935
Defined benefit plans:
Amortization of actuarial losses 164,919
(62,604 ) 102,315
Amortization of transition obligation 35,321
(13,407 ) 21,914
Net defined benefit plans 200,240
(76,011 ) 124,229
Other comprehensive income $ 956,100
$ (362,936 ) $ 593,164
Nine Months Ended June 30, 2012
Interest rate swaps:
Unrealized losses $ (407,642 ) $ 154,741
$ (252,901 )
Transfer of realized losses to interest expense 702,921
(266,829 ) 436,092
Net interest rate SWAPs 295,279
(112,088 ) 183,191
Defined benefit plans:
Amortization of actuarial losses 150,102
(56,979 ) 93,123
Amortization of transition obligation 35,319
(13,407 ) 21,912
Net defined benefit plans 185,421
(70,386 ) 115,035
Other comprehensive income $ 480,700
$ (182,474 ) $ 298,226

The amortization of actuarial losses and transition obligation is included as a component of net periodic pension and postretirement benefit cost and is included in operations and maintenance expense.

RGC RESOURCES, INC. AND SUBSIDIARIES

Composition of Other Accumulated Comprehensive Income (Loss)

Interest Rate
SWAPS

Defined Benefit
Plans

Accumulated
Other
Comprehensive
Income (Loss)
Balance September 30, 2012 $ (1,809,531 ) $ (2,140,554 ) $ (3,950,085 )
Other comprehensive income 468,935
124,229
593,164
Balance June 30, 2013 $ (1,340,596 ) $ (2,016,325 ) $ (3,356,921 )



	Interest Rate SWAPS			Defined Benefit Plans			Accumulated Other Comprehensive Income (Loss)
Balance September 30, 2013	$	(1,232,546	)	$	(918,688	)	$	(2,151,234	)
Other comprehensive income	134,396			6,490			140,886
Balance December 31, 2013	$	(1,098,150	)	$	(912,198	)	$	(2,010,348	)


7.6.	Earnings Per Share

Basic earnings per common share for the three ~~and nine~~ months ended ~~June 30,~~December 31, 2013 and 2012 were calculated by dividing net income by the weighted average common shares outstanding during the period. Diluted earnings per common share were calculated by dividing net income by the weighted average common shares outstanding during the period plus dilutive potential common shares. A reconciliation of basic and diluted earnings per share is presented below:

~~RGC RESOURCES, INC. AND SUBSIDIARIES~~


	Three Months Ended June 30,				Nine Months Ended June 30,				Three Months Ended December 31,
	2013		2012		2013		2012		2013		2012
Net Income	$	110,103	$	52,298	$	4,362,963	$	4,370,517	$	1,722,788	$	1,554,153
Weighted average common shares	4,706,721		4,654,311		4,695,388		4,641,082		4,710,467		4,677,841
Effect of dilutive securities:
Options to purchase common stock	1,599		2,572		37		4,460		132		—
Diluted average common shares	4,708,320		4,656,883		4,695,425		4,645,542		4,710,599		4,677,841
Earnings Per Share of Common Stock:
Basic	$	0.02	$	0.01	$	0.93	$	0.94	$	0.37	$	0.33
Diluted	$	0.02	$	0.01	$	0.93	$	0.94	$	0.37	$	0.33


8.7.	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 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. Roanoke Gas is served directly by two primary pipelines. These two pipelines deliver all 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.


9.8.	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
June 30, Nine Months Ended
June 30,
2013 2012 2013 2012
Components of net periodic pension cost:
Service cost $ 158,723
$ 130,425
$ 476,169
$ 391,275
Interest cost 236,562
238,299
709,686
714,897
Expected return on plan assets (296,197 ) (239,795 ) (888,591 ) (719,385 )
Recognized loss 144,566
118,854
433,698
356,562
Net periodic pension cost $ 243,654
$ 247,783
$ 730,962
$ 743,349

Three Months Ended
June 30, Nine Months Ended
June 30,
2013 2012 2013 2012
Components of postretirement benefit cost:
Service cost $ 53,283
$ 48,944
$ 159,849
$ 146,832
Interest cost 132,962
148,090
398,884
444,270
Expected return on plan assets (113,096 ) (91,840 ) (339,288 ) (275,520 )
Amortization of transition obligation 47,223
47,223
141,671
141,669
Recognized loss 60,437
59,847
181,311
179,541
Net postretirement benefit cost $ 180,809
$ 212,264
$ 542,427
$ 636,792

RGC RESOURCES, INC. AND SUBSIDIARIES



	Three Months Ended December 31,
	2013			2012
Components of net periodic pension cost:
Service cost	$	138,323		$	158,723
Interest cost	255,076			236,562
Expected return on plan assets	(328,089		)	(296,197		)
Recognized loss	34,099			144,566
Net periodic pension cost	$	99,409		$	243,654



	Three Months Ended December 31,
	2013			2012
Components of postretirement benefit cost:
Service cost	$	42,159		$	53,283
Interest cost	150,671			132,961
Expected return on plan assets	(124,119		)	(113,096		)
Amortization of unrecognized transition obligation	—			47,224
Recognized loss	22,379			60,437
Net postretirement benefit cost	$	91,090		$	180,809

The Company contributed $~~800,000~~300,000 to its pension plan during the ~~nine-month~~three-month period ended ~~June 30,~~December 31, 2013. The Company currently expects to make additional contributions of approximately $~~300,000~~200,000 to its pension plan and $~~850,000~~500,000 to its postretirement benefit plan prior to the end of its fiscal year.


~~10.~~9.	Fair Value Measurements

FASB ASC No. 820, Fair Value Measurements and Disclosures, established a fair value hierarchy that prioritizes each input to the valuation method used to measure fair value of financial and nonfinancial assets and liabilities that are measured and reported on a fair value basis 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 following table summarizes the Company’s financial assets and liabilities that are measured at fair value on a recurring basis as required by existing guidance and the fair value measurements by level within the fair value hierarchy as of ~~June 30,~~December 31, 2013 and September 30, ~~2012:~~2013:

RGC RESOURCES, INC. AND SUBSIDIARIES


			Fair Value Measurements - June 30, 2013								Fair Value Measurements - December 31, 2013
	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Liabilities:
Natural gas purchases	$	2,037,627	$	—	$	2,037,627	$	—	$	537,880	$	—	$	537,880	$	—
Interest rate swaps	2,160,857		—		2,160,857		—		1,770,067		—		1,770,067		—
Total	$	4,198,484	$	—	$	4,198,484	$	—	$	2,307,947	$	—	$	2,307,947	$	—

			Fair Value Measurements - September 30, 2012								Fair Value Measurements - September 30, 2013
	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Liabilities:
Natural gas purchases	$	1,065,243	$	—	$	1,065,243	$	—	$	1,177,521	$	—	$	1,177,521	$	—
Interest rate swaps	2,916,718		—		2,916,718		—		1,986,695		—		1,986,695		—
Total	$	3,981,961	$	—	$	3,981,961	$	—	$	3,164,216	$	—	$	3,164,216	$	—

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 weighted average first of the month index prices corresponding to the month of the scheduled payment. At ~~June 30,~~December 31, 2013 and September 30, ~~2012,~~2013, the Company had recorded in accounts payable 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 using the counterparty’s proprietary models and certain assumptions regarding past, present and future market conditions.

~~RGC RESOURCES, INC. AND SUBSIDIARIES~~

The Company’s nonfinancial assets and 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 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. 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 ~~June 30,~~December 31, 2013 and September 30, ~~2012.~~2013.

RGC RESOURCES, INC. AND SUBSIDIARIES


			Fair Value Measurements - June 30, 2013								Fair Value Measurements - December 31, 2013
	Carrying Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Carrying Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Assets:
Notes receivable	$	47,692	$	—	$	—	$	47,466
Total	$	47,692	$	—	$	—	$	47,466
Liabilities:
Note payable	$	15,000,000	$	—	$	—	$	14,965,270	$	15,000,000	$	—	$	—	$	14,988,394
Current maturities of long-term debt									1,600,000		—		—		1,744,545
Long-term debt	13,000,000		—		—		13,795,319		11,400,000		—		—		11,978,181
Total	$	28,000,000	$	—	$	—	$	28,760,589	$	28,000,000	$	—	$	—	$	28,711,120

			Fair Value Measurements - September 30, 2012								Fair Value Measurements - September 30, 2013
	Carrying Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Carrying Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Assets:
Notes receivable	$	1,142,770	$	—	$	—	$	1,152,896
Total	$	1,142,770	$	—	$	—	$	1,152,896
Liabilities:
Note payable	$	15,000,000	$	—	$	—	$	14,976,818	$	15,000,000	$	—	$	—	$	14,976,818
Long-term debt	13,000,000		—		—		14,310,450		13,000,000		—		—		13,762,952
Total	$	28,000,000	$	—	$	—	$	29,287,268	$	28,000,000	$	—	$	—	$	28,739,770

The fair value of the notes receivable are 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 the note payable is estimated by using the interest rate under the Company’s line-of-credit agreement which renewed at the same time as the term note. Both the line-of-credit and term note have a term of one year. 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 a fixed rate. The values of the swap agreements are included in the first table above.

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 ~~June 30,~~December 31, 2013 and September 30, ~~2012,~~2013, 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.

~~11.~~10. Stock Options

On ~~April 1,~~December 6, 2013, the Board of Directors granted ~~21,000~~17,000 options to certain officers of the Company. In accordance with the Key Employee Stock Option Plan, the grant price of $~~19.01~~18.95 was the closing price of the Company's stock on the grant date. The options become exercisable six months from the grant date and expire after ten years from the date of issuance.

~~RGC RESOURCES, INC. AND SUBSIDIARIES~~

Fair value at the grant date was $~~4.04~~4.43 per option as calculated using the Black-Scholes option pricing model. Compensation expense will be recognized over the six months vesting period. Total compensation expense recognized through ~~June 30,~~December 31, 2013 was $~~42,420~~12,552.


~~12.~~11.	Subsequent Events

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

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 those set forth in the following discussion and within Item 1A “Risk Factors” of the Company’s ~~2012~~2013 Annual Report on Form 10-K. 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.

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, ~~2013.~~2014. The total revenues and margins realized during the first ~~nine~~three 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 ~~non-weather sensitive industrial consumption~~weather conditions during the remaining winter months, energy costs, 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 ~~58,300~~59,300 residential, commercial and industrial customers in Roanoke, Virginia and the surrounding localities 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 and its other subsidiaries. Such unregulated operations represent less than 3% of total revenues and margin of Resources on an annual basis.

The Company’s utility operations are regulated by the SCC, which oversees the terms, conditions, and rates to be charged to customers for natural gas service, safety standards, extension of service, accounting and depreciation. The Company is also subject to federal regulation from the Department of Transportation in regard to the construction, operation, maintenance, safety and integrity of its transmission and distribution pipelines. The Federal Energy Regulatory Commission regulates the prices for the transportation and delivery of natural gas to the Company’s distribution system and underground storage services. The Company is also subject to other regulations which are not necessarily industry specific.

The SCC authorizes the rates and fees that the Company charges its customers for regulated natural gas service. The Company has in place certain approved rate mechanisms that reduce some of the volatility in earnings associated with variations in winter weather and the cost of natural gas.

Roanoke Gas has in place a weather normalization adjustment mechanism (“WNA”) based on a weather measurement band around the most recent 30-year temperature average (“normal"). 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. Therefore, the WNA provides the Company with a level of earnings protection when weather is significantly warmer than normal and provides its customers with price protection when the weather is significantly colder than normal. The WNA mechanism provides for a weather band of 3% above and below the 30-year normal, whereby the Company

RGC RESOURCES, INC. AND SUBSIDIARIES

would bill its customers for the lost margin (excluding gas costs) for the impact of weather that was more than 3% warmer than

~~RGC RESOURCES, INC. AND SUBSIDIARIES~~

normal or refund customers the excess margin earned for weather that was more than 3% colder than normal. The annual WNA period extends from April to March. AtFor the ~~end of the most recent~~nine-month WNA period ended ~~March~~December 31, 2013, the total number of heating degree days fell within the 3% weather band and thereby did not trigger a WNA accrual. Whether or not the WNA mechanism ~~for the period. Weather~~is utilized during the ~~corresponding WNA period for~~current year will be dependent on weather during the second fiscal quarter. The total number of heating degree days during the prior year ~~was significantly warmer~~WNA period were approximately 8% less than ~~normal, and the Company recorded $1,740,000 in additional revenues to reflect the impact of the WNA for weather that was 22% above~~ the 30-year ~~average.~~average resulting in an estimated accrual of $182,000 during the quarter ended December 31, 2012. Although the WNA mechanism provides the Company with a method to recover margin not realized for warmer weather above the 3% weather band, the statistical models used in determining the WNA amount do not provide for a precise recovery of lost margin and therefore will vary in their results based not only on the magnitude of weather variation during the total WNA period but also on the variation for each month.

The Company also 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”,~~costs,” of its investment in natural gas inventory. The carrying cost revenue factor applied to the cost of inventory is based on the Company’s ~~weighted average~~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 gas costs and lower inventory balances, the Company recognizes less inventory carrying cost ("ICC") revenue as financing costs are lower. In addition, ICC revenues are impacted by the changes in the weighting of the components that are used to determine the weighted average cost of capital. As a result of a lower weighted-average cost of capital factor and lower storage levels due to colder weather, ICC revenues decreased by ~~$49,000 for the quarter and $293,000 for the nine-month period compared to~~$31,000 from the same ~~periods~~period last year. This decrease in ICC revenue resulted from the decline in the average value of inventory during the period in combination with an SCC mandated revision to the ICC calculation model which shifted a portion of revenue previously included as part of the ICC revenue into the Company's non-gas base rates. Management estimates this methodology change will reduce annual ICC revenues by approximately $120,000, as those revenues are now included in the customer base charge and volumetric rate.

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

Results of Operations

Three Months Ended ~~June 30,~~December 31, 2013:

Net income increased by ~~$57,805~~$168,635 for the quarter ended ~~June 30,~~December 31, 2013 compared to the same period last year. Implementation of a non-gas rate increase and colder weather ~~more than offset higher expenses.~~were the primary factors in the earnings improvement.

The tables below reflect operating revenues, volume activity and heating degree-days.


	Three Months Ended June 30,									Three Months Ended December 31,
	2013		2012		Increase (Decrease)			Percentage		2013		2012		Increase (Decrease)			Percentage
Operating Revenues
Gas Utilities	$	10,823,853	$	9,422,220	$	1,401,633		15	%	$	19,760,987	$	18,458,739	$	1,302,248		7	%
Other	213,455		257,522		(44,067		)	(17	)%	250,207		287,853		(37,646		)	(13	)%
Total Operating Revenues	$	11,037,308	$	9,679,742	$	1,357,566		14	%	$	20,011,194	$	18,746,592	$	1,264,602		7	%
Delivered Volumes
Regulated Natural Gas (DTH)
Residential and Commercial	807,465		688,798		118,667			17	%	2,071,123		2,007,151		63,972			3	%
Transportation and Interruptible	680,957		688,744		(7,787		)	(1	)%	850,382		736,060		114,322			16	%
Total Delivered Volumes	1,488,422		1,377,542		110,880			8	%	2,921,505		2,743,211		178,294			6	%
Heating Degree Days (Unofficial)	360		260		100			38	%	1,533		1,478		55			4	%

Total operating revenues for the three months ended ~~June 30,~~December 31, 2013, compared to the same period last year, increased primarily due to ~~an 8%~~a 6% increase in total natural gas deliveries associated with a ~~38%~~4% increase in heating degree days.

RGC RESOURCES, INC. AND SUBSIDIARIES


	Three Months Ended June 30,									Three Months Ended December 31,
	2013		2012		Increase (Decrease)			Percentage		2013		2012		Increase (Decrease)			Percentage
Gross Margin
Gas Utilities	$	5,176,011	$	4,878,284	$	297,727		6	%	$	8,088,993	$	7,808,278	$	280,715		4	%
Other	53,016		97,094		(44,078		)	(45	)%	113,999		128,205		(14,206		)	(11	)%
Total Gross Margin	$	5,229,027	$	4,975,378	$	253,649		5	%	$	8,202,992	$	7,936,483	$	266,509		3	%

Regulated natural gas margins from utility operations increased from the same period last year primarily as a result of the combination of higher natural gas deliveries and the implementation of a non-gas rate increase ~~higher delivered volumes and the implementation of a SAVE rider more than offsetting a reduction in inventory carrying cost revenues. The increased natural gas base rates were~~ effective ~~for service rendered on and after~~ November 1, 2012 and were designed to provide $649,639 in additional annual non-gas revenues, split between the customer base charge component and volumetric components, as provided for in the final order issued by the SCC. The increase in delivered volumes is attributable to cooler spring weather compared to the same period last year.2013. Residential and commercial volumes increased by ~~17%~~3%, which corresponds to the 4% increase in the number of heating degree days during the period. The impact of the increased volumes was mitigated by the recognition of $182,000 in WNA revenues in the prior year. As discussed in further detail above, WNA revenues offset some of the effects of the prior year's warmer weather while ~~industrial~~no WNA accrual was reflected in the current period. Industrial and transportation volumes, which tend to be less weather sensitive, were nearly unchanged. The Company also recognized $69,094 in SAVE Plan revenues as discussed in further detail under the Regulatory section below. Although the average natural gas inventory storage balances declinedincreased by ~~4% during the quarter, inventory carrying cost revenues declined by 24%~~16% due to ~~a change in calculation methodology as discussed above.~~improved economic activity.

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

Net Margin Increase – Gas Utilities


Customer Base Charge	$	78,511		$	73,032
Carrying Cost	(49,292		)	(31,154		)
Volumetric	204,609			416,864
SAVE Plan	69,094
WNA				(181,731		)
Other Gas Revenues	(5,195		)	3,704
Total	$	297,727		$	280,715

Other margins declined by ~~$44,078~~$14,206 from the same period last year primarily due to ~~cost over-runs~~earnings on ~~work related to~~ a one-time contract ~~that was~~ completed in ~~June and reductions in~~ the ~~level of work performed under another contract. More than half~~third quarter last year. Much of the "Other" revenues and margins are subject to variations in the level of activity and generally are associated with service contracts that have a limited duration or are subject to renewal on an annual or semi-annual basis. Current service contracts extend through the remainder of the fiscal year; however, any continuation beyond fiscal ~~2013~~2014 is uncertain.

Operation and maintenance expenses ~~increased~~decreased by ~~$46,423,~~$161,493, or 2%5%, as significant reductions in employee benefit costs combined with a greater capitalization of overheads more than offset higher ~~bad debt~~labor and contract service costs. Employee benefit costs declined by $204,000 due entirely to lower pension and postretirement benefit costs. An increase in the discount rates used to measure both plans' liabilities, combined with strong returns of both plans' assets, resulted in a significant improvement in funded status with a corresponding reduction in expense ~~stock option expense, contracted services and~~during the current fiscal year. In addition, the Company also capitalized $116,000 more in corporate ~~insurance premiums offset increases in capitalized overheads. Bad debt expense increased by $69,000~~overheads due to significantly higher ~~billings. The Company recognized $42,000 in expense~~capital expenditures related to the ~~granting of stock options as discussed in Note 11. Corporate property and liability insurance~~Company's pipeline renewal program during the quarter. Total capital expenditures increased by ~~$19,000 due to higher premiums~~nearly $1.6 million for the quarter. Total labor and ~~increased general liability coverage limits. Contracted~~contracted services increased ~~$93,000 due~~by $136,000 related to ~~network services support~~an increase in Company personnel and ~~additional costs~~for work related to an SCC mandated meter ~~setinspection~~set inspection and remediation program. ~~These increased costs were partially offset by an increase in overheads capitalized related~~This program requires the Company to ~~LNG (liqufied natural gas) production~~inspect, on a three-year cycle, all meter installations and ~~higher level~~remediate any issues discovered as a result of ~~capital spending.~~those inspections. The remaining differences in operation and maintenance expenses were related to various other minor fluctuations in other expenses.

General taxes increased by ~~$34,908,~~$27,120, or ~~10%~~8%, primarily due to higher property taxes associated with increases in utility ~~property.~~property and higher payroll taxes associated with an increase in Company employees.

Depreciation expense increased by ~~$56,988,~~$78,327, or 5%7%, on a corresponding increase in utility plant investment primarily due to the distribution pipeline replacement program.

Other income (expense), net, moved from an income position to a net expense position due to the payoff of the note receivable from ANGD, LLC on February 1, ~~2013 as discussed in Note 4.~~2013.

Interest expense ~~was virtually unchanged as~~increased by $4,992, or 1%, due to an increase in the ~~Company’s total debt position remained at the $28,000,000 level during the quarter.~~Company's line-of-credit usage.

~~RGC RESOURCES, INC. AND SUBSIDIARIES~~

Income tax expense increased by ~~$29,048,~~$106,751, which corresponds to the increase in pre-tax income for the quarter. The effective tax rate was 38% for ~~the current period and 43% for the same period last year.~~

~~Nine Months Ended June 30, 2013:~~

Net income was nearly unchanged, decreasing by $7,554 for the nine months ended June 30, 2013 compared to the same period last year. Higher operation and maintenance expenses and depreciation offset implementation of a non-gas rate increase.

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

Nine Months Ended
June 30,

2013 2012 Increase Percentage
Operating Revenues
Gas Utilities $ 53,059,322
$ 48,617,001
$ 4,442,321
9 %
Other 900,216
852,144
48,072
6 %
Total Operating Revenues $ 53,959,538
$ 49,469,145
$ 4,490,393
9 %
Delivered Volumes
Regulated Natural Gas (DTH)
Residential and Commercial 6,017,373
4,878,019
1,139,354
23 %
Transportation and Interruptible 2,232,204
2,218,950
13,254
1 %
Total Delivered Volumes 8,249,577
7,096,969
1,152,608
16 %
Heating Degree Days (Unofficial) 3,967
3,155
812
26 %

Total operating revenues for the nine months ended June 30, 2013 compared to the same period last year increased due to significant increases in delivered volumes partially offset by lower cost of natural gas, reduced inventory carrying cost revenues and the absence of WNA revenues. Total natural gas deliveries rose by 16% due to a 26% increase in heating degree days. In addition, natural gas commodity prices resulted in a 7% per unit reduction in the cost of natural gas reflected in cost of sales. Prior year revenues also included $1,747,000 in WNA revenues to offset the effects of lost margin due to warmer weather as discussed above. Other revenues increased by 6%.

Nine Months Ended
June 30,

Increase/
(Decrease)

2013 2012 Percentage
Gross Margin
Gas Utilities $ 22,415,541
$ 21,823,003
$ 592,538
3 %
Other 335,696
400,524
(64,828 ) (16 )%
Total Gross Margin $ 22,751,237
$ 22,223,527
$ 527,710
2 %

Regulated natural gas margins from utility operations increased by $592,538, or 3%, over the same period last year due to the net effects of the following items. Residential and commercial volumes (which tend to be more weather sensitive than transportation and industrial volumes) increased by 23%, corresponding to a 26% increase in the number of heating degree days for the period. Industrial volumes were nearly unchanged from the same period last year. The margin increase generated by the higher residential and commercial volume activity, however, was mostly offset by the $1,747,000 in WNA revenues recorded last year due to much warmer weather. The implementation of the non-gas rate increase effective November 1, 2012 and the SAVE Plan revenues beginning January 1, 2013 provided for higher margins, while margins attributable to ICC revenue declined due to lower average gas in storage during the period and a change in the ICC revenue calculation model. The components of the regulated net margin increase are summarized below:

both periods.

RGC RESOURCES, INC. AND SUBSIDIARIES

~~Net Margin Increase – Gas Utilities~~

Customer Base Charge $ 191,215
WNA (1,746,827 )
Carrying Cost (293,101 )
Volumetric 2,315,979
SAVE Plan 138,351
Other Gas Revenues (13,079 )
Total $ 592,538

~~Other margins declined by $64,828 primarily due to reductions in the level of other services contract work during the period.~~

Operation and maintenance expenses increased by $242,815 or 3%, for the nine-month period ended June 30, 2013 compared to the same period last year. Higher labor, contracted services, bad debts, stock option expense and corporate insurance costs more than offset increases in capitalized overheads. Labor and contracted services increased by $293,000 primarily due to timing of leak surveys and pipeline right-of-way clearing, which were completed in the first quarter, costs related to an SCC mandated meter installation inspection and remediation program and network services support and training. Bad debt expense increased $56,000 due to higher gross customer billings. The Company recognized $42,000 in expense related to the granting of stock options. Corporate property and liability insurance increased by $67,000 due to higher premiums and increased general liability coverage limits. These higher costs were partially offset by greater capitalization of overheads due to higher level of capital expenditures and increased LNG production.

General taxes increased $90,891, or 9%, for the nine-month period ended June 30, 2013 compared to the same period last year primarily related to higher property taxes associated with increases in utility property.

~~Depreciation expense increased by $179,351, or 6%, corresponding to the increase in utility plant investment.~~

~~Other income (expense), net declined by $28,379 due to the reduction in interest income from the payoff of the ANGD note in February 2013.~~

~~Interest expense remained nearly unchanged as borrowing under the Company’s line-of-credit was minimal during the period.~~

~~Income tax expense declined by $4,567, or less than 1%, which corresponds to the 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. There have been no changes to the critical accounting policies as reflected in the Company’s Annual Report on Form 10-K for the year ended September 30, ~~2012.~~2013.

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. In October 2013, Roanoke Gas executed a new agreement with a new asset manager under terms similar to the expiring contract. The ~~current~~new agreement expires in October 2013. The Company is currently evaluating bid responses from asset managers for a new contract. The Company expects to complete its evaluation and make its final selection during its fiscal fourth quarter.March 2017.

Regulatory

On November 1, ~~2012,~~2013, Roanoke Gas Company placed into effect new base rates, subject to refund, that provide for approximately ~~$1,840,000~~$1,664,000 in additional annual non-gas revenues. The Company has recorded an estimated reserve that management believes, based on the information available at the time, may be refundable to customers. The amount of the final rate award may be more or less than the amount reflected in the financial statements and will not be known until the Commission issues its order. The public hearing on the request for this rate increase is scheduled for March 25, 2014, with a final order expected sometime after that date.

On ~~March 21,~~August 16, 2013, the Company ~~reached a stipulated~~

~~RGC RESOURCES, INC. AND SUBSIDIARIES~~

~~agreement with the SCC staff~~filed an application for a ~~non-gas rate award in~~modification to the amount of $649,639 in additional annual non-gas revenues. On April 16, 2013, the SCC issued its final order approving the increase in annual non-gas revenues agreed to in the stipulation. During May 2013, the Company completed its refund, including interest, for the difference between the rates placed into effect on November 1 and those approved in the final order.

~~Beginning in January 2013, the Company started billing a separate rider on customer bills related to its~~ SAVE (Steps to Advance ~~Virginia’s~~Virginia's Energy) ~~Plan.~~Plan and Rider. The ~~SCC approved the Company’s~~original SAVE Plan ~~application~~and Rider were approved by the SCC through an order issued on ~~July 25,~~August 29, 2012. The original SAVE ~~plan is~~Plan was designed to facilitate the accelerated replacement of aging natural gas infrastructure assets by providing a mechanism for the Company ~~with a means~~ to recover the related depreciation and ~~related~~ expenses and return on rate base of the additional capital investment without the filing of a formal application for an increase in non-gas base rates. ~~The~~Under the original filing, the SAVE Plan ~~provides~~primarily covered replacement of the Company's bare steel and cast iron natural gas distribution pipe. The Company began billing this rider to customers in January 2013 and stopped billing at the end of October 2013 as a result of the current rate case, which incorporates all SAVE Plan investment to date in the revenue requirements used to determine the final rate award. Under the modification, the Company ~~with a more timely mechanism for~~sought to include two unique projects in the 2014 SAVE Plan year: the replacement of the boil off compressor at the Company's liquefied natural gas (LNG) plant and modifications to the natural gas transfer station located in Gala, VA. These replacements will enhance the safety and reliability of the Company's gas distribution system. On December 9, 2013, the Company received SCC approval to implement SAVE Rider rates effective January 1, 2014 to begin recovering the ~~cost~~costs related to the pipeline replacement, installation of ~~its renewal program. Previously,~~a new LNG boil off compressor and modifications to the natural gas transfer station.

The Company's provision for depreciation is based on composite straight-line rates as determined by depreciation studies required to be performed on the regulated utility assets of Roanoke Gas Company every five years. As the last depreciation study was completed five years ago, the Company ~~could only recover these costs~~is currently in the process of conducting a new depreciation study that will be implemented in the current year. The results of the study and ~~earn a return on rate base on a prospective basis after filing~~the effect to the financial statements have not yet been determined. When the study is completed and ~~implementing a non-gas rate increase. The~~approval is obtained from the SCC, the Company ~~has billed its customers $69,094 and $138,351 in SAVE Plan revenues~~will implement the new rates for the ~~quarter and year-to-date, respectively.~~current fiscal year.

In ~~the second quarter,~~2013, the SCC issued new inspection protocols for meter sets that require all meter sets to be inspected once every three years, on a continuous ~~cycle, beginning in May 2013.~~cycle. The Company ~~began the process in its fiscal third quarter and expects expenses to increase when~~has fully implemented the inspection and remediation ~~process is fully implemented in fiscal 2014.~~program. The Company ~~plans to seek full~~sought recovery of these ~~expenses through an~~anticipated inspection costs in its expedited rate case. As a result of these increased costs and other factors, the Company filed notice with the SCC on July 16, 2013 of its intent to file an expedited rate case. The amount of increase in non-gas rates to be requested has not yet been determined.

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,

RGC RESOURCES, INC. AND SUBSIDIARIES

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”).

Cash and cash equivalents ~~increased~~decreased by ~~$1,857,974~~$2,349,305 for the ~~nine-month~~three-month period ended ~~June 30,~~December 31, 2013 compared to a ~~$7,797,379 increase~~$8,306,309 decrease for the same period last year. The significant reduction in cash flow last year was primarily due to the special $1.00 per share dividend paid by the Company on December 17, 2012, ~~and, to a lesser extent, to less~~which used available cash, ~~generated by operations and higher~~while the current year reflected an increased level of capital expenditures related to the ~~Company’s~~Company's pipeline renewal ~~program.~~program partially offset by increased line-of-credit activity. The following table summarizes the sources and uses of cash:

Nine Months Ended
June 30,
2013 2012
Cash Flow Summary Nine Months Ended:
Provided by operating activities $ 14,117,168
$ 15,865,190
Used in investing activities (6,867,487 ) (6,478,635 )
Used in financing activities (5,391,707 ) (1,589,176 )
Increase in cash and cash equivalents $ 1,857,974
$ 7,797,379



	Three Months Ended December 31,
	2013			2012
Cash Flow Summary Three Months Ended:
Used in operating activities	$	(1,269,372	)	$	(2,177,213	)
Used in investing activities	(4,079,428		)	(2,493,557		)
Provided by (used in) financing activities	2,999,495			(3,635,539		)
Decrease in cash and cash equivalents	$	(2,349,305	)	$	(8,306,309	)

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 increases in natural gas storage levels, rising customer receivable balances and construction activity.

For the ~~nine~~three months ended ~~June 30,~~December 31, 2013, cash flow ~~provided by~~used in operations decreased by ~~$1,748,022~~$907,841 from the prior year primarily due to an increase in over-collection of gas costs and a ~~smaller~~greater reduction in storage ~~inventory balances~~gas levels partially offset by reductions in accounts payable balances. Over-collection of gas costs increased by nearly $1.3 million for the quarter compared to approximately $400,000 increase during the same quarter last year. In addition, the Company withdrew more gas from storage to meet customer demand during the current ~~nine-month period~~quarter. Total storage volumes declined by 689,901 decatherms during the current quarter compared to only 73,773 decatherms for the ~~prior~~same quarter last year. ~~For the past several years, natural gas commodity prices have trended down with prices leveling off during the 2012 summer storage fill months.~~ As a result, the ~~average price~~level of commodity purchases during the quarter declined thereby reducing the level of accounts payable as compared to the same period last year. The cash generated from the greater use of gas in storage ~~declined from $4.90 per decatherm at September 30, 2011~~was used to ~~$3.50 per decatherm at September 30, 2012. The current price of gas in storage increased slightly to approximately $4.00. Therefore,~~reduce the ~~cash generated from the change in inventory balances during the current year was related~~

~~RGC RESOURCES, INC. AND SUBSIDIARIES~~

~~to the reduction in storage volumes, while last year the change in inventory balance was due to both a decline in the volume and the price of gas in storage.~~accounts payable levels.

Investing activities are generally composed of expenditures under the Company’s construction program, which primarily involves replacing aging bare steel and cast iron pipe with new plastic or coated steel pipe, improvements to the LNG plant, and to a lesser degree, expanding its natural gas system to meet the demands of customer growth. Cash flows used in investing activities increased by ~~$388,852~~$1,585,871 due to an increased level of capital expenditures. ~~Total capital expenditures were $6,883,039 and $6,492,885 for the nine-month periods ended June 30, 2013 and 2012, respectively. The increase in capital expenditures is attributable~~In addition to the ~~continued focus by~~ongoing pipeline replacement program during the quarter, the Company ~~on its~~also had expenditures related to extending service to two industrial customers, renovations to the corporate office building and system software upgrades. Capital expenditures are expected to continue at an increased level through the remainder of the current year as projects related to replacing the LNG boil off compressor and replacing the Gala, Va transfer station will be completed in addition to the ongoing pipeline ~~renewal~~replacement program. ~~Current year capital expenditures would have been higher if not for prolonged periods of rain which limited construction activity.~~ The ~~Company’s current plan includes a four to six year time horizon~~Company currently expects to finish replacing the remaining bare steel and cast iron pipe within its natural gas distribution ~~system.~~system over the next four years. In order to meet this goal, the Company ~~expects~~anticipates capital expenditures towill remain at elevated levels for the next few years. The depreciation add back to operating cash flows and net income is expected to provide ~~approximately 50%~~a portion of the funding for the ~~current year’s~~next few year's projected capital expenditures, with the balance of funding ~~dependent on other sources including net income, available cash and~~likely coming from 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~~Financing activities moved from a $3,635,539 use of cash in ~~financing activities increased by $3,802,531, from $1,589,176~~the prior year period to ~~$5,391,707, primarily due~~a $2,999,495 source of cash in the current period. The primary drivers for the difference relate to the prior year's special $1.00 per share dividend paid by the Company on December 17, ~~2012.~~2012 and increased utilization of the line-of-credit during the current year. The special dividend totaled $4,675,337, of which $425,630 was returned to the Company under the DRIP plan to purchase 21,951 shares of stock. Most of the remaining difference relates to net proceeds ~~received~~ from the ~~$865,000 payoff of the balance of the ANGD note in February. The Company accessed its~~ line-of-credit ~~in November 2012~~used to provide ~~temporary financing during~~working capital. The Company's net borrowing under the ~~winter season.~~line-of-credit was $3,814,386 for the current quarter compared to $1,279,216 for the prior quarter. The Company has been able to finance operations with its

RGC RESOURCES, INC. AND SUBSIDIARIES

operating cash flow without needing to access its line-of-credit over the last few years as cash flows have been positively affected by declining natural gas prices resulting in lower natural gas storage balances and accounts receivable in addition to accelerated and bonus tax depreciation deductions which have limited federal corporate income tax payments. However, with natural gas prices ~~appearing~~beginning to ~~have leveled off~~increase, the apparent end to bonus tax depreciation and ~~an increasing focus on the Company’s pipeline replacement program,~~ongoing higher levels of capital expenditures, the Company expects to ~~utilize~~increase utilization of its line-of-credit ~~more often in the future~~ to provide funding for its operations.

~~Effective March 31, 2013, the Company entered into a new line-of-credit agreement.~~ 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 seasonal borrowing demands and minimize overall borrowing costs with available limits ranging from $1,000,000 to $7,000,000 during the term of the agreement. TheCompany's line-of-credit agreement will expire on March 31, 2014, unless extended. The Company anticipates being able to extend or replace ~~the~~its current line-of-credit agreement upon expiration; however, there is no guarantee that the line-of-credit will be extended or replaced ~~under the same or equivalent~~on terms comparable to those currently in place.

~~Effective~~The Company's $15,000,000 unsecured variable rate note is scheduled to mature on March 31, ~~2013,~~2014. Based on discussions with the ~~Company also executed an unsecured term note in~~current lender, the amount of $15,000,000. This term note essentially extends the maturity date of the prior term note to March 31, 2014 and retains all other terms and conditions provided for in the original promissory note. The Company anticipates being able to ~~renew~~extend this note prior to its maturity on a yearly basis under terms comparable ~~terms as~~to those currently in place until such time the corresponding swap on the note ~~co-terminates with the corresponding interest rate swap~~matures on November 30, 2015.

At ~~June 30,~~December 31, 2013, the Company’s consolidated capitalization, including ~~notes~~the note payable and line-of-credit, was ~~64%~~61% equity and ~~36%~~39% debt.

RGC RESOURCES, INC. AND SUBSIDIARIES

ITEM 3 – QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is exposed to market risks associated with interest rates and commodity prices. Interest rate risk is related to the Company’s outstanding long-term and short-term debt. Commodity price risk is experienced by the Company’s regulated natural gas operations. The Company’s risk management policy, as authorized by the Company’s Board of Directors, allows management to enter into derivatives for the purpose of managing commodity and financial market risks of its business operations.

Interest Rate Risk

The Company is exposed to market risk related to changes in interest rates associated with its borrowing activities. At ~~June 30,~~December 31, 2013, the Company had ~~no balances~~$3,814,386 outstanding under its line-of-credit. ~~The Company did, however, access its line-of-credit during the Company's first fiscal quarter to provide temporary working capital funding.~~ A hypothetical 100 basis point increase in market interest rates applicable to the Company’s variable rate debt outstanding during the period would have resulted in an increase in interest expense for the current ~~year~~period of ~~less than $1,000.~~approximately $5,000. The Company also has a $15,000,000 note payable and a $5,000,000 intermediate term variable rate note both of which are currently being hedged by fixed rate interest swaps. The remaining $8,000,000 balance of the long-term debt is at fixed rates.

Commodity Price Risk

The Company manages the price risk associated with purchases of natural gas by using a combination of liquefied natural gas (LNG) storage, underground storage gas, fixed price contracts, spot market purchases and derivative commodity instruments including futures, price caps, swaps and collars.

At ~~June 30,~~December 31, 2013, the Company had no outstanding derivative instruments to hedge the price of natural gas. The Company had ~~1,781,494~~1,839,592 decatherms of gas in storage, including LNG, at an average price of ~~$4.09~~$4.13 per decatherm. The SCC currently allows for full recovery of prudent costs associated with natural gas purchases, and any additional costs or benefits associated with the settlement of the derivative contracts and other price hedging techniques are passed through to customers when realized through the PGA mechanism.

RGC RESOURCES, INC. AND SUBSIDIARIES

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, 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 ~~June 30,~~December 31, 2013, the Company completed an evaluation, under the supervision and with the participation of management, including the chief executive officer and the chief 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 ~~June 30,~~December 31, 2013.

Management routinely reviews the Company’s internal control over financial reporting and makes changes, as necessary, to enhance the effectiveness of the internal controls over financial reporting. There were no changes in the internal controls over financial reporting during the fiscal quarter ended ~~June 30,~~December 31, 2013 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

RGC RESOURCES, INC. AND SUBSIDIARIES

Part II – Other Information

ITEM 1 – LEGAL PROCEEDINGS

No changes.

ITEM 1A – RISK FACTORS

No changes.

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

None.

ITEM 3 – DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4 – MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5 – OTHER INFORMATION

None.

ITEM 6 – EXHIBITS



Number		Description

10.1		Natural Gas Asset Management Agreement by and between Roanoke Gas Company and Sequent Energy Management LP effective November 1, 2013 (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on October 9, 2013).
10.2		First Modification to Promissory Note in the principal amount of $8,000,000 by Roanoke Gas Company in favor of Wells Fargo Bank, N.A. dated December 23, 2013. (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on December 23, 2013).
10.3		Second Amendment to Credit Agreement by and between Roanoke Gas Company and Wells Fargo Bank, N.A. (incorporated by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed on December 23, 2013).
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.
101**		The following materials from the Registrant’s Quarterly Report on Form 10-Q for the quarter ended ~~June 30,~~December 31, 2013, formatted in XBRL (eXtensible Business Reporting Language); (i) Condensed Consolidated Balance Sheets at ~~June 30,~~December 31, 2013 and September 30, ~~2012,~~2013, (ii) Condensed Consolidated Statements of Income for the three months ~~and nine months~~ ended ~~June 30,~~December 31, 2013 and 2012; (iii) Condensed Consolidated Statements of Comprehensive Income for the three months ~~and nine months~~ ended ~~June 30,~~December 31, 2013 and 2012; (iv) Condensed Consolidated Statements of Cash Flows for the ~~nine~~three months ended ~~June 30,~~December 31, 2013 and 2012, and (v) Condensed Notes to Condensed Consolidated Financial Statements.



*	These certifications are being furnished solely to accompany this quarterly report pursuant to 18 U.S.C. Section 1350, and are not being filed for purposes of Section 18 of the Securities Exchange Act of 1934 and are not to be incorporated by reference into any filing of the Registrant, whether made before or after the date hereof, regardless of any general incorporation language in such filing.



**	Pursuant to Rule 406T or Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.

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 9, 2013~~February 6, 2014	By:	/s/ Paul W. Nester
		Paul W. Nester
		Vice President, Treasurer and CFO



	Nine Months Ended June 30,				Increase/ (Decrease)
	2013		2012		Increase/ (Decrease)			Percentage
Gross Margin
Gas Utilities	$	22,415,541	$	21,823,003	$	592,538		3	%
Other	335,696		400,524		(64,828		)	(16	)%
Total Gross Margin	$	22,751,237	$	22,223,527	$	527,710		2	%




Customer Base Charge	$	191,215
WNA	(1,746,827		)
Carrying Cost	(293,101		)
Volumetric	2,315,979
SAVE Plan	138,351
Other Gas Revenues	(13,079		)
Total	$	592,538

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