RGC Resources (RGCO) 10-Q 2014 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For Quarterly Period Ended June 30, 2014

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.

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

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 31, 2014
Common Stock, $5 Par Value	4,718,697

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

UNAUDITED

	June 30, 2014			September 30, 2013
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1,970,954		$	2,846,224
Accounts receivable (less allowance for uncollectibles of $349,203 and $68,539, respectively)	3,624,028			3,729,106
Materials and supplies	795,858			760,781
Gas in storage	6,701,262			10,316,240
Prepaid income taxes	—			836,966
Deferred income taxes	2,695,493			2,852,073
Other	1,053,140			866,646
Total current assets	16,840,735			22,208,036
UTILITY PROPERTY:
In service	151,543,437			144,388,721
Accumulated depreciation and amortization	(50,286,470		)	(48,653,487		)
In service, net	101,256,967			95,735,234
Construction work in progress	4,171,355			2,001,315
Utility plant, net	105,428,322			97,736,549
OTHER ASSETS:
Regulatory assets	4,423,578			4,474,111
Other	157,422			108,005
Total other assets	4,581,000			4,582,116
TOTAL ASSETS	$	126,850,057		$	124,526,701

See notes to condensed consolidated financial statements.

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RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

UNAUDITED

	June 30, 2014			September 30, 2013
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Note payable	$	—		$	15,000,000
Dividends payable	873,009			847,736
Accounts payable	5,022,795			5,723,107
Customer credit balances	778,793			1,277,515
Income taxes payable	112,989			—
Customer deposits	1,494,478			1,476,451
Accrued expenses	1,816,123			2,118,182
Over-recovery of gas costs	1,356,457			1,027,303
Fair value of marked-to-market transactions	1,341,733			1,986,695
Total current liabilities	12,796,377			29,456,989
LONG-TERM DEBT	28,000,000			13,000,000
DEFERRED CREDITS AND OTHER LIABILITIES:
Asset retirement obligations	4,676,732			4,525,355
Regulatory cost of retirement obligations	8,625,162			8,180,173
Benefit plan liabilities	5,584,133			5,582,073
Deferred income taxes and investment tax credits	14,755,671			14,279,689
Total deferred credits and other liabilities	33,641,698			32,567,290
STOCKHOLDERS’ EQUITY:
Common stock, $5 par value; authorized 10,000,000 shares; issued and outstanding 4,718,650 and 4,709,326, respectively	23,593,250			23,546,630
Preferred stock, no par, authorized 5,000,000 shares; no shares issued and outstanding	—			—
Capital in excess of par value	8,211,643			8,003,787
Retained earnings	22,338,718			20,103,239
Accumulated other comprehensive loss	(1,731,629		)	(2,151,234		)
Total stockholders’ equity	52,411,982			49,502,422
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	126,850,057		$	124,526,701

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RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

FOR THE THREE-MONTH AND NINE-MONTH PERIODS ENDED JUNE 30, 2014 AND 2013

UNAUDITED

	Three Months Ended June 30,						Nine Months Ended June 30,
	2014			2013			2014			2013
OPERATING REVENUES:
Gas utilities	$	11,659,272		$	10,823,853		$	63,890,166		$	53,059,322
Other	365,545			213,455			845,810			900,216
Total operating revenues	12,024,817			11,037,308			64,735,976			53,959,538
COST OF SALES:
Gas utilities	6,112,396			5,647,842			40,214,940			30,643,781
Other	190,870			160,439			435,368			564,520
Total cost of sales	6,303,266			5,808,281			40,650,308			31,208,301
GROSS MARGIN	5,721,551			5,229,027			24,085,668			22,751,237
OTHER OPERATING EXPENSES:
Operations and maintenance	3,190,706			3,091,433			9,958,196			9,849,545
General taxes	391,355			371,301			1,196,716			1,131,016
Depreciation and amortization	1,198,799			1,120,472			3,596,397			3,361,416
Total other operating expenses	4,780,860			4,583,206			14,751,309			14,341,977
OPERATING INCOME	940,691			645,821			9,334,359			8,409,260
OTHER INCOME (EXPENSE), Net	(22,043		)	(11,662		)	(92,934		)	4,805
INTEREST EXPENSE	456,761			456,103			1,376,871			1,370,417
INCOME BEFORE INCOME TAXES	461,887			178,056			7,864,554			7,043,648
INCOME TAX EXPENSE	178,693			67,953			3,011,777			2,680,685
NET INCOME	$	283,194		$	110,103		$	4,852,777		$	4,362,963
BASIC EARNINGS PER COMMON SHARE	$	0.06		$	0.02		$	1.03		$	0.93
DILUTED EARNINGS PER COMMON SHARE	$	0.06		$	0.02		$	1.03		$	0.93
DIVIDENDS DECLARED PER COMMON SHARE	$	0.185		$	0.180		$	0.555		$	1.540

See notes to condensed consolidated financial statements.

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RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

FOR THE THREE-MONTH AND NINE-MONTH PERIODS ENDED JUNE 30, 2014 AND 2013

UNAUDITED

	Three Months Ended June 30,				Nine Months Ended June 30,
	2014		2013		2014		2013
NET INCOME	$	283,194	$	110,103	$	4,852,777	$	4,362,963
Other comprehensive income, net of tax:
Interest rate SWAPs	133,472		219,381		400,135		468,935
Defined benefit plans	6,490		41,409		19,470		124,229
OTHER COMPREHENSIVE INCOME, NET OF TAX	139,962		260,790		419,605		593,164
COMPREHENSIVE INCOME	$	423,156	$	370,893	$	5,272,382	$	4,956,127

See notes to condensed consolidated financial statements.

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RGC RESOURCES, INC. AND SUBSIDIARIES

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

ENDED JUNE 30, 2014 AND 2013

UNAUDITED

	Nine Months Ended June 30,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	4,852,777		$	4,362,963
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	3,741,781			3,492,954
Cost of removal of utility plant, net	(328,744		)	(361,219		)
Stock option grants	75,310			42,420
Changes in assets and liabilities which used cash, exclusive of changes and noncash transactions shown separately	3,968,568			6,580,050
Net cash provided by operating activities	12,309,692			14,117,168
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant and nonutility property	(10,781,425		)	(6,883,039		)
Proceeds from disposal of equipment	9,322			15,552
Net cash used in investing activities	(10,772,103		)	(6,867,487		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from collection of notes	—			1,095,077
Borrowings under line-of-credit agreement	13,893,656			4,354,402
Repayments under line-of-credit agreement	(13,893,656		)	(4,354,402		)
Proceeds from issuance of stock (9,324 and 36,781 shares, respectively)	179,166			698,878
Cash dividends paid	(2,592,025		)	(7,185,662		)
Net cash used in financing activities	(2,412,859		)	(5,391,707		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(875,270		)	1,857,974
BEGINNING CASH AND CASH EQUIVALENTS	2,846,224			8,909,871
ENDING CASH AND CASH EQUIVALENTS	$	1,970,954		$	10,767,845
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid	$	1,503,380		$	1,496,299
Income taxes paid	1,686,000			372,076

See notes to condensed consolidated financial statements.

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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 Resources financial position as of June 30, 2014 and the results of its operations and comprehensive income for the three months and nine months ended June 30, 2014 and 2013 and its cash flows for the nine months ended June 30, 2014 and 2013. The results of operations for the three months and nine months ended June 30, 2014 are not indicative of the results to be expected for the fiscal year ending September 30, 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, 2013 balance sheet was included in the Company’s audited financial statements included in 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, 2013. Newly adopted and newly issued accounting standards are discussed below.

Recently 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. 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 6 below.

Recently Issued Accounting Standards

In May 2014, the FASB issued guidance under FASB ASC No. 606 - Revenue from Contracts with Customers that affects any entity that enters into contracts with customers for the transfer of goods or services or transfer of non-financial assets. This guidance will supersede the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. The core principle of the new guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve that core principle, an entity should apply these steps: (1) identify the contract with the customer, (2) identify the performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to the performance obligations in the contract, and (5) recognize revenue when, or as, the entity satisfies the performance obligation. The new guidance is effective for the Company for the annual reporting period ended September 30, 2018 and interim periods within that annual period. Early application is not permitted. Management has not completed

6

its evaluation of the new guidance. However, the Company does not currently expect the new guidance to have a material effect on its financial position, results of operations or cash flows.

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 or 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, 2013, Roanoke Gas Company placed into effect new base rates, subject to refund, that would provide for approximately $1,664,000 in additional annual non-gas revenues. On March 17, 2014, the Company reached a stipulated agreement with the SCC staff that would provide $887,062 in annual non-gas revenues. On May 9, 2014, the SCC issued its final order approving the increase in annual non-gas revenues agreed to in the stipulation. During June 2014, the Company completed its refund to its customers for the difference between the rates placed into effect on November 1 and the final rates approved by the SCC.

On June 4, 2014, the Company filed an application with the SCC requesting approval to extend its authority to incur short-term indebtedness of up to $30,000,000 and to issue up to $60,000,000 in long-term debt securities. The short-term indebtedness authority will allow the Company to continue to access its line-of-credit to provide seasonal funding of its working capital needs as well as provide temporary bridge financing for its capital expenditures. The application also included the Company's plan to refinance its current debt obligations with lower interest rate debt and provide the Company with future long-term financing options. On June 25, 2014, the SCC issued an order granting the approval of the Company's request including its plan to refinance its current debt obligations.

3. Short-Term Debt

The Company and Wells Fargo Bank entered into a new unsecured line-of-credit agreement dated March 31, 2014. The new agreement maintains the same variable interest rate based on 30-day LIBOR plus 100 basis points and availability fee of 15 basis points as the prior agreement. The new agreement also includes multi-tiered borrowing limits to accommodate seasonal borrowing demands and minimize borrowing costs. The Company’s total available borrowing limits during the term of the line-of-credit agreement range from $1,000,000 to $19,000,000. The line-of-credit agreement will expire March 31, 2015, unless extended. The Company anticipates being able to extend or replace the credit line upon expiration. As of June 30, 2014, the Company had no outstanding balance under its line-of-credit agreement.

4. Long-Term Debt

On July 31, 2014, Roanoke Gas Company entered into a private placement agreement with a third party to refinance the Company's short-term and long-term debt at a fixed interest rate of 4.26% for a term of 20 years. The total borrowing under the new agreement is $30,500,000. The Company will use the proceeds to retire its $13,000,000 in long-term debt, including current maturities, as well as its $15,000,000 note payable. The remaining funds will be used to settle the estimated early redemption premiums associated with the Company's fixed rate long-term debt and swap agreements. As a result of this refinancing, the Company reclassified the $1,600,000 in current maturities of long-term debt and the $15,000,000 in note payable to long-term debt as of June 30, 2014. As discussed in Note 2, the Company received SCC approval for the proposed refinancing, which will allow the Company to defer, as a regulatory asset, the early redemption premiums associated with retiring the current debt and interest rate swaps and amortize these costs over the life of the new debt as an effective interest rate adjustment.

The Company expects to execute the new note and retire the existing debt in September 2014.

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.

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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, 2015. 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 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, 2014 and September 30, 2013:

	June 30, 2014		September 30, 2013
Derivatives designated as hedging instruments:
Interest rate swaps	$	1,341,733	$	1,986,695

The table in Note 6 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 $940,000 of the fair value on the interest rate hedges would be reclassified from other comprehensive loss into interest expense on the income statement over the next 12 months. However, as discussed in Note 4, management anticipates retiring the Company's current outstanding debt and their corresponding interest rate swaps during the quarter ended September 30, 2014.

6. Comprehensive Income

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

	Before-Tax Amount			Tax (Expense) or Benefit			Net-of-Tax Amount
Three Months Ended June 30, 2014
Interest rate swaps:
Unrealized losses	$	(24,711	)	$	9,380		$	(15,331	)
Transfer of realized losses to interest expense	239,850			(91,047		)	148,803
Net interest rate SWAPs	215,139			(81,667		)	133,472
Defined benefit plans:
Amortization of actuarial losses	10,461			(3,971		)	6,490
Amortization of transition obligation	—			—			—
Net defined benefit plans	10,461			(3,971		)	6,490
Other comprehensive income	$	225,600		$	(85,638	)	$	139,962
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

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RGC RESOURCES, INC. AND SUBSIDIARIES

	Before-Tax Amount			Tax (Expense) or Benefit			Net-of-Tax Amount
Nine Months Ended June 30, 2014
Interest rate swaps:
Unrealized losses	$	(73,630	)	$	27,950		$	(45,680	)
Transfer of realized losses to interest expense	718,592			(272,777		)	445,815
Net interest rate SWAPs	644,962			(244,827		)	400,135
Defined benefit plans:
Amortization of actuarial losses	31,383			(11,913		)	19,470
Amortization of transition obligation	—			—			—
Net defined benefit plans	31,383			(11,913		)	19,470
Other comprehensive income	$	676,345		$	(256,740	)	$	419,605
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

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.

Composition of Other Accumulated Comprehensive Income (Loss)

	Interest Rate SWAPS			Defined Benefit Plans			Accumulated Other Comprehensive Income (Loss)
Balance at September 30, 2013	$	(1,232,546	)	$	(918,688	)	$	(2,151,234	)
Other comprehensive income	400,135			19,470			419,605
Balance at June 30, 2014	$	(832,411	)	$	(899,218	)	$	(1,731,629	)

7. Earnings Per Share

Basic earnings per common share for the three months and nine months ended June 30, 2014 and 2013 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 potential dilutive common shares. A reconciliation of basic and diluted earnings per share is presented below:

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RGC RESOURCES, INC. AND SUBSIDIARIES

	Three Months Ended				Nine Months Ended
	June 30,				June 30,
	2014		2013		2014		2013
Net Income	$	283,194	$	110,103	$	4,852,777	$	4,362,963
Weighted average common shares	4,718,068		4,706,721		4,714,023		4,695,388
Effect of dilutive securities:
Options to purchase common stock	830		1,599		432		37
Diluted average common shares	4,718,898		4,708,320		4,714,455		4,695,425
Earnings Per Share of Common Stock:
Basic	$	0.06	$	0.02	$	1.03	$	0.93
Diluted	$	0.06	$	0.02	$	1.03	$	0.93

8. 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. 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 health care 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						Nine Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
Components of net periodic pension cost:
Service cost	$	138,323		$	158,723		$	414,969		$	476,169
Interest cost	255,076			236,562			765,228			709,686
Expected return on plan assets	(328,089		)	(296,197		)	(984,267		)	(888,591		)
Recognized loss	34,099			144,566			102,297			433,698
Net periodic pension cost	$	99,409		$	243,654		$	298,227		$	730,962

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RGC RESOURCES, INC. AND SUBSIDIARIES

	Three Months Ended						Nine Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
Components of postretirement benefit cost:
Service cost	$	42,159		$	53,283		$	126,477		$	159,849
Interest cost	150,671			132,962			452,013			398,884
Expected return on plan assets	(124,119		)	(113,096		)	(372,357		)	(339,288		)
Amortization of unrecognized transition obligation	—			47,223			—			141,671
Recognized loss	22,379			60,437			67,137			181,311
Net postretirement benefit cost	$	91,090		$	180,809		$	273,270		$	542,427

The Company contributed $400,000 to its pension plan during the nine-month period ended June 30, 2014. The Company currently expects to contribute at least an additional $150,000 to its pension plan and $500,000 to its postretirement benefit plan prior to the end of its fiscal year.

10. 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, 2014 and September 30, 2013:

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RGC RESOURCES, INC. AND SUBSIDIARIES

			Fair Value Measurements - June 30, 2014
	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Liabilities:
Natural gas purchases	$	278,955	$	—	$	278,955	$	—
Interest rate swaps	1,341,733		—		1,341,733		—
Total	$	1,620,688	$	—	$	1,620,688	$	—
			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)
Liabilities:
Natural gas purchases	$	1,177,521	$	—	$	1,177,521	$	—
Interest rate swaps	1,986,695		—		1,986,695		—
Total	$	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, 2014 and September 30, 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.

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 required 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, 2014 and September 30, 2013.

			Fair Value Measurements - June 30, 2014
	Carrying Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Liabilities:
Long-term debt	$	28,000,000	$	—	$	—	$	28,589,751
Total	$	28,000,000	$	—	$	—	$	28,589,751
			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)
Liabilities:
Note payable	$	15,000,000	$	—	$	—	$	14,976,818
Long-term debt	13,000,000		—		—		13,762,952
Total	$	28,000,000	$	—	$	—	$	28,739,770

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RGC RESOURCES, INC. AND SUBSIDIARIES

The fair value of long-term debt is estimated by discounting the future cash flows of the debt based on current market rates and corresponding interest rate spread.

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, 2014 and September 30, 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. Stock Options

On December 6, 2013, the Board of Directors granted 17,000 options to certain officers of the Company. In accordance with the Key Employee Stock Option Plan, the grant price of $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.

Fair value at the grant date was $4.43 per option as calculated using the Black-Scholes option pricing model. Compensation expense was recognized over the vesting period. Total compensation expense recognized through June 30, 2014 was $75,310.

12. 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.

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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 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, 2014. The total revenues and margins realized during the first nine months reflect higher billings due to the weather sensitive nature of the gas business. Improvement or decline in earnings for the balance of the fiscal year will depend primarily on non-weather sensitive natural gas consumption and the level of operating and maintenance costs incurred.

Overview

Resources is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately 58,700 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 would bill its customers for the lost margin (excluding gas costs) for the impact of weather that was more than 3% warmer than normal or refund customers the excess margin earned for weather that was more than 3% colder than normal. The annual WNA

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period extends from April to March. For the just completed WNA period ended March 31, 2014, the total number of heating degree days (an industry measure by which the average daily temperature falls below 65 degrees Fahrenheit) were approximately 10% higher than the 30-year normal. As a result, the Company refunded approximately $707,000 to customers for the additional margin realized for weather between 3% and 10% colder than the 30-year normal. There was no WNA recorded during the prior WNA period ended March 31, 2013 as weather during that WNA period fell within the 3% weather band. Effective with the new WNA period that began April 1, 2014, the SCC approved the removal of the 3% weather band and now will base the WNA strictly on the 30-year average.

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,” 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 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. Although the average unit price of gas in storage during the first nine months of the current fiscal year was $0.62 per decatherm higher than for the same period last year, a 22% reduction in the average inventory levels during the same period resulted in a reduction of approximately $28,000 in carrying cost revenues for the quarter and $65,000 for the nine-month period compared to the same periods last year. Inventory levels declined from last year primarily due to the colder weather during the winter months and an increase in storage withdrawals by the new asset manager.

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, 2014:

Net income increased by $173,091 for the quarter ended June 30, 2014 compared to the same period last year. Implementation of a non-gas rate increase, higher commercial and industrial consumption and SAVE Plan revenues 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,
	2014		2013		Increase (Decrease)			Percentage
Operating Revenues
Gas Utilities	$	11,659,272	$	10,823,853	$	835,419		8	%
Other	365,545		213,455		152,090			71	%
Total Operating Revenues	$	12,024,817	$	11,037,308	$	987,509		9	%
Delivered Volumes
Regulated Natural Gas (DTH)
Residential and Commercial	829,132		807,465		21,667			3	%
Transportation and Interruptible	701,577		680,957		20,620			3	%
Total Delivered Volumes	1,530,709		1,488,422		42,287			3	%
Heating Degree Days (Unofficial)	314		360		(46		)	(13	)%

Total operating revenues for the three months ended June 30, 2014, compared to the same period last year, increased primarily due to a combination of higher natural gas costs, a 3% increase in total natural gas deliveries and the implementation of a non-gas rate increase.

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RGC RESOURCES, INC. AND SUBSIDIARIES

	Three Months Ended June 30,
	2014		2013		Increase (Decrease)		Percentage
Gross Margin
Gas Utilities	$	5,546,876	$	5,176,011	$	370,865	7	%
Other	174,675		53,016		121,659		229	%
Total Gross Margin	$	5,721,551	$	5,229,027	$	492,524	9	%

Regulated natural gas margins from utility operations increased from the same period last year primarily as a result of the combination of the implementation of a non-gas rate increase effective November 1, 2013, higher delivered volumes and increased SAVE Plan revenues. The increased natural gas base rates were effective for service rendered on and after November 1, 2013 and were designed to provide $887,062 in additional annual non-gas revenues, split nearly in half between the customer base charge component and volumetric components, as provided in the final order issued by the SCC. Although total heating degree days for the quarter declined by 46, total natural gas deliveries increased 3% primarily due to higher commercial and industrial consumption. The effect of the warmer quarter on natural gas deliveries was minimal as a heating degree day during the spring does not have nearly the same impact as a heating degree day during the winter and late fall. The Company also implemented a new SAVE Plan rider beginning January 1, 2014. The current SAVE Plan rider, which allows the Company to recover on a prospective basis the related depreciation, expenses and return on rate base on the additional capital investment without the formal non-gas rate increase application process, is nearly twice the amount as last year's rider due to the addition of two large, unique projects in addition to the ongoing pipeline renewal program. More information on the SAVE Plan is provided under the regulatory section below. Carrying cost revenues declined for the quarter as the average inventory balance during the period was about 14% below the same period last year. WNA revenues for the quarter reflect the difference between the estimated refund to customers as determined last quarter and the actual refund made to customers during the June billing cycle.

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

Net Margin Increase – Gas Utilities

Customer Base Charge	$	184,139
Carrying Cost	(27,785		)
SAVE Plan	71,558
Volumetric	123,330
WNA	11,761
Other Gas Revenues	7,862
Total	$	370,865

Other margins increased by $121,659 from the same period last year primarily due to an increased level of work performed under one of the non-gas contracts. This contract is subject to variability in the level of activity from period to period and is subject to renewal at six month intervals. In addition, the prior year included a loss related to cost over-runs on a one-time contract. As noted above, 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 2014 is uncertain.

Operation and maintenance expenses increased by $99,273, or 3%, as higher labor, contracted services and corporate insurance expense more than offset reductions in employee benefit costs and a greater capitalization of overheads. Total labor and contracted services increased by $373,000 related to an increase in Company personnel and for work related to an SCC mandated meter set inspection and remediation program and corrosion survey. The meter inspection program requires the Company to inspect, on a three-year cycle, all meter installations and to remediate issues discovered as a result of those inspections. The first round of inspections will be completed by the end of 2015 and remediation of issues found will be ongoing during this time. Corporate property and liability insurance increased by $25,000 due to higher premiums and increased general liability limits. Employee benefit expenses declined by $156,000, due entirely to lower pension and postretirement benefit costs partially offset by higher medical insurance premiums. 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 during the current fiscal year. In addition, the Company also

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capitalized $133,000 more in corporate overheads due to significantly higher capital expenditures related to the Company's pipeline renewal program during the quarter as well as overheads capitalized due to greater production levels of LNG. Total capital expenditures increased by nearly $1.1 million for the quarter. The remaining differences were related to various minor fluctuations in other expenses.

General taxes increased by $20,054, or 5%, primarily due to higher property taxes associated with increases in utility property and higher payroll taxes associated with an increase in Company employees.

Depreciation expense increased by $78,327, or 7%, on a corresponding increase in utility plant investment.

Other expense, net, increased by $10,381 primarily due to an increase in other miscellaneous expenses.

Income tax expense increased by $110,740, which corresponds to the increase in pre-tax income for the quarter. The effective tax rate was 39% and 38% for the three months ended June 30, 2014 and 2013, respectively.

Nine Months Ended June 30, 2014:

Net income increased by $489,814 for the nine-months ended June 30, 2014, compared to the same period last year, primarily due to the implementation of a non-gas rate increase, colder weather and SAVE Plan revenues.

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

	Nine Months Ended June 30,
	2014		2013		Increase (Decrease)			Percentage
Operating Revenues
Gas Utilities	$	63,890,166	$	53,059,322	$	10,830,844		20	%
Other	845,810		900,216		(54,406		)	(6	)%
Total Operating Revenues	$	64,735,976	$	53,959,538	$	10,776,438		20	%
Delivered Volumes
Regulated Natural Gas (DTH)
Residential and Commercial	6,498,005		6,017,373		480,632			8	%
Transportation and Interruptible	2,389,599		2,232,204		157,395			7	%
Total Delivered Volumes	8,887,604		8,249,577		638,027			8	%
Heating Degree Days (Unofficial)	4,332		3,967		365			9	%

Total operating revenues for the nine months ended June 30, 2014, compared to the same period last year, increased primarily due to an increase in total natural gas deliveries combined with higher natural gas costs and the implementation of a non-gas rate increase. Total natural gas deliveries rose by 8% due to a 9% increase in heating degree days. In addition, higher natural gas commodity prices resulted in a 21% per unit increase in the cost of natural gas reflected in cost of sales. Other revenues declined by 6% due to the completion of a one-time contract during the third quarter of the prior fiscal year more than offsetting an increase in other service contracts.

	Nine Months Ended June 30,
	2014		2013		Increase (Decrease)		Percentage
Gross Margin
Gas Utilities	$	23,675,226	$	22,415,541	$	1,259,685	6	%
Other	410,442		335,696		74,746		22	%
Total Gross Margin	$	24,085,668	$	22,751,237	$	1,334,431	6	%

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 effective November 1, 2013. Residential and commercial volumes increased by 8%, which corresponds to the 9% increase in the number of heating degree days during the period. The margin effect of these increased volumes was significantly lowered by the $707,000 WNA refund, reducing margins to a level comparable to what would be realized at 3% colder than the 30-year normal. Natural gas margins were also positively impacted by the increased non-gas base rates effective November 1, 2013 and the higher SAVE Plan rider.

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Industrial and transportation volumes, which tend to be less weather sensitive, increased by 7% due to stronger economic activity primarily in the first and third quarters.

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

Net Margin Increase – Gas Utilities

Customer Base Charge	$	497,324
Carrying Cost	(64,949		)
SAVE Plan	129,616
Volumetric	1,393,054
WNA	(706,939		)
Other Gas Revenues	11,579
Total	$	1,259,685

Other margins increased by $74,746 from the same period last year due to the combination of greater activity on a non-gas contract for the current year and the loss on a one-time contract realized in the third quarter of the last fiscal year.

Operation and maintenance expenses increased by $108,651, or 1%, as higher labor, contracted services, corporate insurance, bad debt and other expenses offset reductions in employee benefit costs and a greater capitalization of overheads. Total labor and contracted services increased by $646,000, as did corporate property and liability insurance premiums by $73,000 for the same reasons as explained previously. Bad debt expense increased by $57,000 due to a 20% increase in gross revenues. Other expense increases included greater stock option expense of $33,000 and additional expenses related to the remediation of meter installation inspection issues and maintenance of other corporate facilities and infrastructure. Employee benefit expenses declined by $519,000 due to lower pension and postretirement benefit costs, and capitalized overheads increased by $318,000 as total capital expenditures increased by $3.9 million. The remaining differences in operation and maintenance expenses were related to various other minor fluctuations in other expenses.

General taxes increased by $65,700, or 6%, primarily due to higher property taxes associated with increases in utility property and higher payroll taxes associated with an increase in Company employees.

Depreciation expense increased by $234,981 or 7%, on a corresponding increase in utility plant investment.

Other income (expense), net, moved from a net income position to a net expense position primarily due to the payoff of the note receivable from ANGD, LLC in February of last year.

Interest expense increased by $6,454, or 1%, due to a greater level of borrowing under the Company's line-of-credit.

Income tax expense increased by $331,092, which corresponds to the increase in pre-tax income for the period. 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, 2013.

Asset Management

Roanoke Gas uses a third party 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,

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RGC RESOURCES, INC. AND SUBSIDIARIES

Roanoke Gas executed an agreement with a new asset manager under terms similar to the prior contract. The new agreement expires in March 2017.

Regulatory

On November 1, 2013, Roanoke Gas Company placed into effect new base rates, subject to refund, that provide for approximately $1,664,000 in additional annual non-gas revenues. On March 17, 2014, the Company reached a stipulated agreement with the SCC staff that would provide $887,062 in annual non-gas revenues. A hearing was held on March 25, 2014 resulting in the approval of the stipulated agreement. The stipulation provided for a 9.75% authorized return on equity as was previously in place; however, this was below the 10.1% requested by the Company in the rate filing. On May 9, 2014, the SCC issued its final order approving the increase in annual non-gas revenues agreed to in the stipulation. The Company has completed its refund of the revenues collected in excess of the approved rates plus interest to its customers.

Also included in the final order regarding the non-gas rate increase was a change to the WNA model. The current WNA provides the Company with a mechanism to recover lost margin for weather that is more than 3% warmer than normal and to refund customers excess margin attributable to weather that is more than 3% colder than normal during the WNA year which runs from April through March. For weather that falls within the 3% weather band, there is no adjustment. Effective with the WNA period beginning April 1, 2014, the WNA will no longer have a 3% weather band. Instead, any WNA amount, whether warmer or colder, will be based on the weather during the WNA period as compared to the 30-year average. As the authorized billing rates are based on normal weather, the volatility in margin related to fluctuations in weather is essentially removed.

On August 16, 2013, the Company filed an application for a modification to the SAVE (Steps to Advance Virginia's Energy) Plan and Rider. The original SAVE Plan and Rider were approved by the SCC 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 the Company to recover the related depreciation and 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. Under the original filing, the SAVE Plan 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 rate case, which incorporated all SAVE Plan investment in that period in the revenue requirements used to determine the final rate award. Under the modification, the Company 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 costs related to the ongoing pipeline replacement program, installation of a new LNG boil off compressor and modifications to the natural gas transfer station. Due to the projected cost of these two projects, total SAVE revenue is nearly double the amount of last year.

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 at least every five years. As the last depreciation study was completed five years ago, the Company has completed a new depreciation study and has filed the results with the SCC. The study is currently under review by the SCC, and pending their approval, including any changes or adjustments, the Company will implement the new rates in the fourth fiscal quarter retroactive to October 1, 2013.

In 2013, the SCC issued new inspection protocols that require all meter sets to be inspected once every three years, on a continuous cycle. The Company has implemented the inspection and remediation program.

On June 4, 2014, Roanoke Gas filed an application with the SCC requesting approval to extend its authority to incur short-term indebtedness of up to $30,000,000 and to issue up to $60,000,000 in long-term debt securities. The short-term indebtedness authority will allow the Company to continue to access its line-of-credit to provide seasonal funding of its working capital needs as well as provide temporary bridge financing for its capital expenditures. The application also included the Company's plan for long-term financing: the retirement and re-issue of existing long-term debt at favorable interest rates and the long-term financing for future anticipated capital expenditures currently being funded through the Company's line-of-credit. On June 25, 2014, the SCC approved the Company's application.

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-

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

Cash and cash equivalents decreased by $875,270 for the nine-month period ended June 30, 2014 compared to a $1,857,974 increase for the same period last year. The following table summarizes the sources and uses of cash:

	Nine Months Ended June 30,
	2014			2013
Cash Flow Summary Nine Months Ended:
Provided by operating activities	$	12,309,692		$	14,117,168
Used in investing activities	(10,772,103		)	(6,867,487		)
Used in financing activities	(2,412,859		)	(5,391,707		)
Increase (decrease) in cash and cash equivalents	$	(875,270	)	$	1,857,974

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 months ended June 30, 2014, cash flow provided by operations declined by $1,807,476 for the nine months ended June 30, 2014 primarily due to reductions in accounts payable and over-collection of gas costs partially offset by positive cash flows generated from lower storage gas levels, a smaller reduction in customer credit balances and higher net income and depreciation. Accounts payable balances decreased by $0.4 million during the current fiscal year compared to an increase of $1.6 million during the same period last year. The lower accounts payable levels are due to the timing of payments under the asset management agreement. The increased storage withdrawals during this past winter resulted in a closer correlation between the scheduled payments for gas purchases and the actual receipt of those purchases. During the prior year, the scheduled payments lagged the actual receipt of gas thereby resulting in a larger accrual for gas received but not yet paid and a higher payable balance in the prior year. Total storage volumes at June 30, 2014 declined by 413,700 decatherms compared to the same period last year, as the asset manager withdrew more gas from storage due to the colder winter. The greater net withdrawal activity during the current year contributed $1.4 million in additional cash flow due to lower inventory balances. Over-collection of gas costs increased by approximately $0.3 million for the current year compared to approximately $3.1 million increase during the same period last year. In addition, customer deposits and credit balances declined by nearly $0.5 million during the current year compared to $1.9 million in the prior year. The decrease in these balances in the prior year was due to an effort to reduce customer credit balances that had increased as a result of prior warmer winter seasons and lower natural gas prices. The summary of the components of operating cash flow is provided below:

	Nine Months Ended						Increase
	6/30/2014			6/30/2013			(Decrease)
Cash provided by operating activities:
Net income and depreciation	$	8,594,558		$	7,855,917		$	738,641
Gas in storage	3,614,978			2,179,951			1,435,027
Accounts payable	(436,653		)	1,597,353			(2,034,006		)
Over-collection of gas costs	329,154			3,141,081			(2,811,927		)
Customer deposits and credit balances	(480,695		)	(1,877,765		)	1,397,070
Other	688,350			1,220,631			(532,281		)
Total cash provided	$	12,309,692		$	14,117,168		$	(1,807,476	)

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 $3,904,616 due to an increased level of capital expenditures. In addition to the ongoing pipeline

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RGC RESOURCES, INC. AND SUBSIDIARIES

replacement program, the Company also had expenditures related to extending service to two industrial customers, renovations to the corporate office building and system software upgrades. The Company also began two significant infrastructure improvement projects: replacing the LNG boil off compressor and replacing the Gala, Virginia transfer station. Capital expenditures are expected to continue at an increased level through the remainder of the current year as progress continues on the two infrastructure projects along with the ongoing pipeline replacement program. The Company currently expects to finish replacing the remaining bare steel and cast iron pipe within its natural gas distribution system over the next four years. In order to meet this goal, the Company anticipates capital expenditures will remain at elevated levels. Operating cash flows and corporate borrowing are expected to provide the funding for projected capital expenditures over the next few years.

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 flows used in financing activities decreased by $2,978,848 primarily due to the prior year's special $1.00 per share dividend paid by the Company on December 17, 2012. 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 the $1,095,077 pay-off of the note receivable during the prior year. The Company increased it's borrowing under the line-of-credit during the current year to meet additional working capital needs during the winter season. Cash flows have been sufficient to pay-off the balance of the line. With natural gas prices remaining at higher levels and ongoing higher levels of capital expenditures, the Company expects to continue to increase utilization of its line-of-credit to provide funding for its operations, including temporary financing of its capital expenditures.

Effective March 31, 2014, the Company entered into a new line-of-credit agreement. The new agreement maintained the same terms and rates as provided for under the prior 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 demand and minimize overall borrowing costs with available limits ranging from $1,000,000 to $19,000,000 during the term of the agreement. The limit is higher than in recent years due to the expected funding needs of the Company's proposed capital budget, which includes the ongoing pipeline renewal program and the projects at the LNG plant and Gala transfer station. The Company's line-of-credit agreement will expire on March 31, 2015, unless extended. The Company anticipates being able to extend or replace its current line-of-credit agreement upon expiration; however, there is no guarantee that the line-of-credit will be extended or replaced on terms comparable to those currently in place.

As discussed in Note 4, the Company entered into an agreement to refinance its debt. The Company currently has an $8,000,000 unsecured note with a 7.66% interest rate and annual installments of $1,600,000 due beginning December 1, 2014. The Company also has a $5,000,000 note due December 1, 2015 with a corresponding swap having an effective interest rate of 5.79% and a $15,000,000 short-term note due March 31, 2015 with a corresponding swap having an effective interest rate of 5.74%. The overall weighted-average interest rate on the Company's current debt is 6.30%. Under the agreement, the Company's interest rate on the new debt will be fixed at 4.26% for the entire term of the note. The Company will borrow $30,500,000 to retire the current $28,000,000 in debt and use the remaining funds to settle the early retirement premiums on the debt and two swap agreements. By entering into the refinancing agreement at this time, the Company was able to secure a fixed interest rate for the term on the new notes, removing the possibility that future interest rates could be higher, and, consequently, increasing overall interest costs. The Company expects to complete the refinancing in September 2014.

In addition to the current refinancing of debt, the Company also obtained approval from the SCC to issue additional long-term debt to finance its projected capital expenditures over the next five years. The Company is currently using its line-of-credit to provide temporary financing of its capital expenditures. This authority to issue additional long-term debt will allow the Company the flexibility to obtain longer-term financing when market conditions and rates are most favorable.

At June 30, 2014, the Company’s consolidated capitalization was 65% equity and 35% debt.

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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, 2014, the Company had no outstanding balance under its line-of-credit; however, it had accessed the line-of-credit during the prior two quarters. A hypothetical 100 basis point increase in market interest rates applicable to the Company’s variable rate line-of-credit outstanding during the period would have resulted in an increase in interest expense for the current period of approximately $6,000. 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, 2014, the Company had no outstanding derivative instruments to hedge the price of natural gas. The Company had 1,367,794 decatherms of gas in storage, including LNG, at an average price of $4.90 per decatherm. The SCC currently allows for full recovery of prudent costs associated with natural gas purchases, as any additional costs or benefits associated with the settlement of derivative contracts and other price hedging techniques are passed through to customers when realized through the PGA mechanism.

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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, 2014, 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, 2014.

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, 2014 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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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	Note Purchase Agreement for 4.26% Senior Guaranteed Notes due September 18, 2034 in the original principal amount of $30,500,000 in favor of The Prudential Insurance Company of America, PAR U Hartford Life & Annuity Comfort Trust and PRUCO Life Insurance Company of New Jersey (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on August 4, 2014).
10.2	Unconditional Parent Guaranty by RGC Resources, Inc. in favor of each of the holders of the notes: The Prudential Insurance Company of America, PAR U Hartford Life & Annuity Comfort Trust and PRUCO Life Insurance Company of New Jersey (incorporated by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed on August 4, 2014).
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, 2014, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets at June 30, 2014 and September 30, 2013, (ii) Condensed Consolidated Statements of Income for the three months and nine months ended June 30, 2014 and 2013; (iii) Condensed Consolidated Statements of Comprehensive Income for the three months and nine months ended June 30, 2014 and 2013; (iv) Condensed Consolidated Statements of Cash Flows for the nine months ended June 30, 2014 and 2013, 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.

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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 7, 2014	By:	/s/ Paul W. Nester
		Paul W. Nester
		Vice President, Treasurer and CFO

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