Edgar Filing: RGC RESOURCES INC

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RGCO - 2014.03.31 - 10Q - Q2

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For Quarterly Period Ended March 31, 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.

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 April 30, 2014
Common Stock, $5 Par Value		4,717,221

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

UNAUDITED



	March 31, 2014			September 30, 2013
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	3,771,024		$	2,846,224
Accounts receivable (less allowance for uncollectibles of $325,668 and $68,539, respectively)	12,785,071			3,729,106
Materials and supplies	819,288			760,781
Gas in storage	1,994,712			10,316,240
Prepaid income taxes	—			836,966
Deferred income taxes	3,331,583			2,852,073
Other	1,382,565			866,646
Total current assets	24,084,243			22,208,036
UTILITY PROPERTY:
In service	148,909,617			144,388,721
Accumulated depreciation and amortization	(49,809,021		)	(48,653,487		)
In service, net	99,100,596			95,735,234
Construction work in progress	3,747,395			2,001,315
Utility plant, net	102,847,991			97,736,549
OTHER ASSETS:
Regulatory assets	4,439,672			4,474,111
Other	71,170			108,005
Total other assets	4,510,842			4,582,116
TOTAL ASSETS	$	131,443,076		$	124,526,701

See notes to condensed consolidated financial statements.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

UNAUDITED



	March 31, 2014			September 30, 2013
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt	$	1,600,000		$	—
Note payable	15,000,000			15,000,000
Dividends payable	872,686			847,736
Accounts payable	6,879,173			5,723,107
Customer credit balances	385,505			1,277,515
Income taxes payable	884,617			—
Customer deposits	1,624,021			1,476,451
Accrued expenses	2,947,992			2,118,182
Over-recovery of gas costs	2,124,648			1,027,303
Fair value of marked-to-market transactions	1,556,872			1,986,695
Total current liabilities	33,875,514			29,456,989
LONG-TERM DEBT	11,400,000			13,000,000
DEFERRED CREDITS AND OTHER LIABILITIES:
Asset retirement obligations	4,624,217			4,525,355
Regulatory cost of retirement obligations	8,498,605			8,180,173
Benefit plan liabilities	5,550,113			5,582,073
Deferred income taxes and investment tax credits	14,691,802			14,279,689
Total deferred credits and other liabilities	33,364,737			32,567,290
STOCKHOLDERS’ EQUITY:
Common stock, $5 par value; authorized 10,000,000 shares; issued and outstanding 4,716,904 and 4,709,326, respectively	23,584,520			23,546,630
Preferred stock, no par, authorized 5,000,000 shares; no shares issued and outstanding	—			—
Capital in excess of par value	8,161,363			8,003,787
Retained earnings	22,928,533			20,103,239
Accumulated other comprehensive loss	(1,871,591		)	(2,151,234		)
Total stockholders’ equity	52,802,825			49,502,422
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	131,443,076		$	124,526,701

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

FOR THE THREE-MONTH AND SIX-MONTH PERIODS ENDED MARCH 31, 2014 AND 2013

UNAUDITED



	Three Months Ended March 31,						Six Months Ended March 31,
	2014			2013			2014			2013
OPERATING REVENUES:
Gas utilities	$	32,469,907		$	23,776,730		$	52,230,894		$	42,235,469
Other	230,058			398,908			480,265			686,761
Total operating revenues	32,699,965			24,175,638			52,711,159			42,922,230
COST OF SALES:
Gas utilities	22,430,550			14,345,478			34,102,544			24,995,939
Other	108,290			244,433			244,498			404,081
Total cost of sales	22,538,840			14,589,911			34,347,042			25,400,020
GROSS MARGIN	10,161,125			9,585,727			18,364,117			17,522,210
OTHER OPERATING EXPENSES:
Operations and maintenance	3,424,140			3,253,269			6,767,490			6,758,112
General taxes	417,164			398,638			805,361			759,715
Depreciation and amortization	1,198,799			1,120,472			2,397,598			2,240,944
Total other operating expenses	5,040,103			4,772,379			9,970,449			9,758,771
OPERATING INCOME	5,121,022			4,813,348			8,393,668			7,763,439
OTHER INCOME (EXPENSE), Net	(45,756		)	(575		)	(70,891		)	16,467
INTEREST EXPENSE	455,657			454,853			920,110			914,314
INCOME BEFORE INCOME TAXES	4,619,609			4,357,920			7,402,667			6,865,592
INCOME TAX EXPENSE	1,772,814			1,659,213			2,833,084			2,612,732
NET INCOME	$	2,846,795		$	2,698,707		$	4,569,583		$	4,252,860
BASIC EARNINGS PER COMMON SHARE	$	0.60		$	0.57		$	0.97		$	0.91
DILUTED EARNINGS PER COMMON SHARE	$	0.60		$	0.57		$	0.97		$	0.91
DIVIDENDS DECLARED PER COMMON SHARE	$	0.185		$	0.180		$	0.370		$	1.360

See notes to condensed consolidated financial statements.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

FOR THE THREE-MONTH AND SIX-MONTH PERIODS ENDED MARCH 31, 2014 AND 2013

UNAUDITED



	Three Months Ended March 31,				Six Months Ended March 31,
	2014		2013		2014		2013
NET INCOME	$	2,846,795	$	2,698,707	$	4,569,583	$	4,252,860
Other comprehensive income, net of tax:
Interest rate SWAPs	132,267		103,348		266,663		249,554
Defined benefit plans	6,490		41,410		12,980		82,820
OTHER COMPREHENSIVE INCOME, NET OF TAX	138,757		144,758		279,643		332,374
COMPREHENSIVE INCOME	$	2,985,552	$	2,843,465	$	4,849,226	$	4,585,234

See notes to condensed consolidated financial statements.

RGC RESOURCES, INC. AND SUBSIDIARIES

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

ENDED MARCH 31, 2014 AND 2013

UNAUDITED



	Six Months Ended March 31,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	4,569,583		$	4,252,860
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	2,494,521			2,328,636
Cost of removal of utility plant, net	(201,371		)	(220,341		)
Stock option grants	50,208			—
Changes in assets and liabilities which used cash, exclusive of changes and noncash transactions shown separately	2,781,248			5,978,680
Net cash provided by operating activities	9,694,189			12,339,835
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant and nonutility property	(7,203,480		)	(4,441,536		)
Proceeds from disposal of equipment	8,172			2,966
Net cash used in investing activities	(7,195,308		)	(4,438,570		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from collection of notes	—			1,047,385
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 (7,578 and 34,888 shares, respectively)	145,258			661,006
Cash dividends paid	(1,719,339		)	(6,338,604		)
Net cash used in financing activities	(1,574,081		)	(4,630,213		)
NET INCREASE IN CASH AND CASH EQUIVALENTS	924,800			3,271,052
BEGINNING CASH AND CASH EQUIVALENTS	2,846,224			8,909,871
ENDING CASH AND CASH EQUIVALENTS	$	3,771,024		$	12,180,923
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid	$	899,845		$	892,765
Income taxes paid (refunded), net	1,350,000			(27,924		)

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 Resources financial position as of March 31, 2014 and the results of its operations and comprehensive income for the three months and six months ended March 31, 2014 and 2013 and its cash flows for the six months ended March 31, 2014 and 2013. The results of operations for the three months and six months ended March 31, 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 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, 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 5 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.

RGC RESOURCES, INC. AND SUBSIDIARIES


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. A hearing was held on March 25, 2014 approving the stipulation and a final order by the SCC is pending. The Company has recorded a provision for refund, including interest associated with customer billings, for the difference between the rates placed into effect on November 1, 2013 and the amount agreed to in the stipulation. Refunds to customers will be completed after the receipt of the final order.

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. Under the modification, the Company sought to include two unique projects; 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, in the 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 received SCC approval to implement SAVE Rider rates effective January 1, 2014 to begin recovering the costs related to the pipeline replacement, installation of a new LNG boil off compressor and modifications to the 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 to customers the excess earned from weather that is more than 3% colder than the 30-year average. As of March 31, 2014, the total heating degree days (an industry measure by which the average daily temperature falls below 65 degrees Fahrenheit) for the current WNA period of April 2013 through March 2014 were approximately 10% more than the 30-year average. As the number of heating degree days fell outside the 3% weather band, the Company accrued a refund of approximately $719,000 for the difference in margin realized for weather that was between 10% and 3% colder than the 30-year average. The Company expects to refund the excess margin during its May billing cycle. There was no WNA recognized for the prior WNA period extending from April 2012 through March 2013 as total heating degree days were within the 3% weather band. The Company had accrued an estimated WNA of $182,000 as of December 31, 2012 as weather for the nine-month period was more than 3% warmer than normal. However, this accrual was reversed in the quarter ended March 31, 2013. The Company applied the provisions of FASB ASC No. 980, Regulated Operations, in recording the WNA.


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 maintained the same variable interest rate based on 30 day LIBOR plus 100 basis points and availability fee of 15 basis points as the expiring agreement. 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 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 March 31, 2014, the Company had no outstanding balance under its line-of-credit agreement.

The Company also executed an unsecured promissory note dated March 31, 2014 in the amount of $15,000,000. This note essentially extends the maturity date of the prior note to March 31, 2015 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.

RGC RESOURCES, INC. AND SUBSIDIARIES


4.	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.

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 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 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 March 31, 2014 and September 30, 2013:



	March 31, 2014		September 30, 2013
Derivatives designated as hedging instruments:
Interest rate swaps	$	1,556,872	$	1,986,695

The table in Note 5 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 $942,000 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 expense as well as the fair value of the interest rate hedges.


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
Three Months Ended March 31, 2014
Interest rate swaps:
Unrealized losses	$	(23,831	)	$	9,047		$	(14,784	)
Transfer of realized losses to interest expense	237,026			(89,975		)	147,051
Net interest rate SWAPs	213,195			(80,928		)	132,267
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	$	223,656		$	(84,899	)	$	138,757
Three Months Ended March 31, 2013
Interest rate swaps:
Unrealized losses	$	(67,899	)	$	25,774		$	(42,125	)
Transfer of realized losses to interest expense	234,483			(89,010		)	145,473
Net interest rate SWAPs	166,584			(63,236		)	103,348
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	$	233,331		$	(88,573	)	$	144,758

RGC RESOURCES, INC. AND SUBSIDIARIES




	Before-Tax Amount			Tax (Expense) or Benefit			Net-of-Tax Amount
Six Months Ended March 31, 2014
Interest rate swaps:
Unrealized losses	$	(48,919	)	$	18,570		$	(30,349	)
Transfer of realized losses to interest expense	478,742			(181,730		)	297,012
Net interest rate SWAPs	429,823			(163,160		)	266,663
Defined benefit plans:
Amortization of actuarial losses	20,922			(7,942		)	12,980
Amortization of transition obligation	—			—			—
Net defined benefit plans	20,922			(7,942		)	12,980
Other comprehensive income	$	450,745		$	(171,102	)	$	279,643
Six Months Ended March 31, 2013
Interest rate swaps:
Unrealized losses	$	(70,517	)	$	26,768		$	(43,749	)
Transfer of realized losses to interest expense	472,765			(179,462		)	293,303
Net interest rate SWAPs	402,248			(152,694		)	249,554
Defined benefit plans:
Amortization of actuarial losses	109,946			(41,736		)	68,210
Amortization of transition obligation	23,548			(8,938		)	14,610
Net defined benefit plans	133,494			(50,674		)	82,820
Other comprehensive income	$	535,742		$	(203,368	)	$	332,374

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	266,663			12,980			279,643
Balance at March 31, 2014	$	(965,883	)	$	(905,708	)	$	(1,871,591	)


6.	Earnings Per Share

Basic earnings per common share for the three months and six months ended March 31, 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:

RGC RESOURCES, INC. AND SUBSIDIARIES



	Three Months Ended March 31,				Six Months Ended March 31,
	2014		2013		2014		2013
Net Income	$	2,846,795	$	2,698,707	$	4,569,583	$	4,252,860
Weighted average common shares	4,713,567		4,701,866		4,712,000		4,689,722
Effect of dilutive securities:
Options to purchase common stock	416		—		258		—
Diluted average common shares	4,713,983		4,701,866		4,712,258		4,689,722
Earnings Per Share of Common Stock:
Basic	$	0.60	$	0.57	$	0.97	$	0.91
Diluted	$	0.60	$	0.57	$	0.97	$	0.91


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.


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 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 March 31,						Six Months Ended March 31,
	2014			2013			2014			2013
Components of net periodic pension cost:
Service cost	$	138,323		$	158,723		$	276,646		$	317,446
Interest cost	255,076			236,562			510,152			473,124
Expected return on plan assets	(328,089		)	(296,197		)	(656,178		)	(592,394		)
Recognized loss	34,099			144,566			68,198			289,132
Net periodic pension cost	$	99,409		$	243,654		$	198,818		$	487,308



	Three Months Ended March 31,						Six Months Ended March 31,
	2014			2013			2014			2013
Components of postretirement benefit cost:
Service cost	$	42,159		$	53,283		$	84,318		$	106,566
Interest cost	150,671			132,961			301,342			265,922
Expected return on plan assets	(124,119		)	(113,096		)	(248,238		)	(226,192		)
Amortization of unrecognized transition obligation	—			47,224			—			94,448
Recognized loss	22,379			60,437			44,758			120,874
Net postretirement benefit cost	$	91,090		$	180,809		$	182,180		$	361,618

RGC RESOURCES, INC. AND SUBSIDIARIES

The Company contributed $300,000 to its pension plan during the six-month period ended March 31, 2014. The Company currently expects to make additional contributions of approximately $200,000 to its pension plan and $500,000 to its postretirement benefit plan prior to the end of its fiscal year.


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 March 31, 2014 and September 30, 2013:



			Fair Value Measurements - March 31, 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	$	576,923	$	—	$	576,923	$	—
Interest rate swaps	1,556,872		—		1,556,872		—
Total	$	2,133,795	$	—	$	2,133,795	$	—

			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 March 31, 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.

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 March 31, 2014 and September 30, 2013.



			Fair Value Measurements - March 31, 2014
	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	$	—	$	—	$	14,953,751
Current maturities of long-term debt	1,600,000		—		—		1,739,400
Long-term debt	11,400,000		—		—		11,957,602
Total	$	28,000,000	$	—	$	—	$	28,650,753

			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

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 March 31, 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.

10. 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 will be recognized over the six months vesting period. Total compensation expense recognized through March 31, 2014 was $50,208.

RGC RESOURCES, INC. AND SUBSIDIARIES

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 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 six-month earnings presented herein should not be considered as reflective of the Company’s consolidated financial results for the fiscal year ending September 30, 2014. The total revenues and margins realized during the first six months reflect higher billings due to the weather sensitive nature of the gas business. Improvement or decline in earnings for the balance of the fiscal year will depend primarily on weather conditions during the remaining spring months, energy costs, improvement or deterioration in the local economic environment and the level of operating and maintenance costs 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 59,700 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

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. 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 more than 10% higher than the 30-year normal. As a result, the Company recorded a refund of approximately $719,000 for the period to reflect the impact of the WNA for the additional margin realized for weather between 3% and 10% colder than the 30-year normal. There was no WNA recorded for the period ended March 31, 2013 as weather during that WNA period fell within the 3% weather band; however, the quarter ended March 31, 2013 did include the reversal of $182,000 WNA accrual recorded in December when the weather was nearly 8% warmer than normal and outside the 3% weather band.

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 six months of the current fiscal year was $0.57 per decatherm higher than for the same period last year, a 23% reduction in the average inventory levels during the same period resulted in a reduction of approximately $6,000 in carrying cost revenues for the quarter and $37,000 for the six month period compared to the same periods last year. Inventory levels declined from last year primarily due to the colder weather during the first six months of the year and a change 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 March 31, 2014:

Net income increased by $148,088 for the quarter ended March 31, 2014 compared to the same period last year. Implementation of a non-gas rate increase and colder weather were the primary factors in the earnings improvement.

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



	Three Months Ended March 31,
	2014		2013		Increase (Decrease)			Percentage
Operating Revenues
Gas Utilities	$	32,469,907	$	23,776,730	$	8,693,177		37	%
Other	230,058		398,908		(168,850		)	(42	)%
Total Operating Revenues	$	32,699,965	$	24,175,638	$	8,524,327		35	%
Delivered Volumes
Regulated Natural Gas (DTH)
Residential and Commercial	3,597,750		3,202,757		394,993			12	%
Transportation and Interruptible	837,640		815,187		22,453			3	%
Total Delivered Volumes	4,435,390		4,017,944		417,446			10	%
Heating Degree Days (Unofficial)	2,485		2,129		356			17	%

Total operating revenues for the three months ended March 31, 2014, compared to the same period last year, increased primarily due to a 10% increase in total natural gas deliveries associated with a 17% increase in heating degree days and higher natural gas costs.

RGC RESOURCES, INC. AND SUBSIDIARIES



	Three Months Ended March 31,
	2014		2013		Increase (Decrease)			Percentage
Gross Margin
Gas Utilities	$	10,039,357	$	9,431,252	$	608,105		6	%
Other	121,768		154,475		(32,707		)	(21	)%
Total Gross Margin	$	10,161,125	$	9,585,727	$	575,398		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 12%, which corresponds to the 17% increase in the number of heating degree days during the period. As discussed above, the impact of the increased volumes was mitigated by the accrual of an estimated WNA refund of $719,000 during the current quarter to account for the excess margin realized due to weather that was between 3% and 10% colder than the 30-year average. The increased non-gas base rates were effective for service rendered on and after November 1, 2013. The stipulated agreement with the SCC staff and the final order received from the Commission provide for an increase in annual non-gas revenues of $887,062 split nearly in half between customer base charge and volumetric rates. 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 projects in addition to the ongoing pipeline renewal program. More information on the SAVE Plan is provided under the regulatory section below. Industrial and transportation volumes, which tend to be less weather sensitive, increased by 3%.

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

Net Margin Increase – Gas Utilities



Customer Base Charge	$	240,153
Carrying Cost	(6,010		)
SAVE Plan	38,826
Volumetric	872,092
WNA	(536,969		)
Other Gas Revenues	13
Total	$	608,105

Other margins declined by $32,707 from the same period last year primarily due to earnings on a one-time contract completed in the 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 2014 is uncertain.

Operation and maintenance expenses increased by $170,871, or 5%, as higher labor, contracted services, bad debt, corporate insurance and stock option expense more than offset reductions in employee benefit costs and a greater capitalization of overheads. Total labor and contracted services increased by $213,000 related to an increase in Company personnel and for work related to 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. Bad debt expense increased by $55,000 for the quarter due to a 37% increase in gross natural gas revenues. Corporate property and liability insurance increased by $28,000 due to higher premiums and increased general liability limits. The Company also recognized $38,000 in expense related to the granting of stock options in December 2013. Employee benefit expenses declined by $160,000 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 during the current fiscal year. In addition, the Company also capitalized $69,000 more in corporate overheads due to significantly higher capital expenditures related to the Company's pipeline renewal program during the quarter. Total capital expenditures increased by nearly $1.2 million for the

RGC RESOURCES, INC. AND SUBSIDIARIES

quarter. The remaining differences in operation and maintenance expenses were related to various minor fluctuations in other expenses.

General taxes increased by $18,526, 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 $45,181 primarily due to the payoff of the note receivable from ANGD, LLC on February 1, 2013. Interest expense was nearly unchanged from the same period last year.

Income tax expense increased by $113,601, which corresponds to the increase in pre-tax income for the quarter. The effective tax rate was 38% for both periods.

Six Months Ended March 31, 2014:

Net income increased by $316,723 for the six-months ended March 31, 2014, compared to the same period last year, primarily due to the implementation of a non-gas rate increase and colder weather during the period.

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



	Six Months Ended March 31,
	2014		2013		Increase (Decrease)			Percentage
Operating Revenues
Gas Utilities	$	52,230,894	$	42,235,469	$	9,995,425		24	%
Other	480,265		686,761		(206,496		)	(30	)%
Total Operating Revenues	$	52,711,159	$	42,922,230	$	9,788,929		23	%
Delivered Volumes
Regulated Natural Gas (DTH)
Residential and Commercial	5,668,873		5,209,908		458,965			9	%
Transportation and Interruptible	1,688,022		1,551,247		136,775			9	%
Total Delivered Volumes	7,356,895		6,761,155		595,740			9	%
Heating Degree Days (Unofficial)	4,018		3,607		411			11	%

Total operating revenues for the six months ended March 31, 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. Total natural gas deliveries rose by 9% due to an 11% increase in heating degree days. In addition, higher natural gas commodity prices resulted in a 25% per unit increase in the cost of natural gas reflected in cost of sales. Other revenues declined by 30% due to the completion of a one-time contract during the third quarter of the prior fiscal year.



	Six Months Ended March 31,
	2014		2013		Increase (Decrease)			Percentage
Gross Margin
Gas Utilities	$	18,128,350	$	17,239,530	$	888,820		5	%
Other	235,767		282,680		(46,913		)	(17	)%
Total Gross Margin	$	18,364,117	$	17,522,210	$	841,907		5	%

RGC RESOURCES, INC. AND SUBSIDIARIES

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

Net Margin Increase – Gas Utilities



Customer Base Charge	$	313,185
Carrying Cost	(37,164		)
SAVE Plan	58,058
Volumetric	1,269,724
WNA	(718,700		)
Other Gas Revenues	3,717
Total	$	888,820

Other margins declined by $46,913 from the same period last year due to earnings on a one-time contract completed in the third quarter last year.

Operation and maintenance expenses were nearly unchanged from last year as higher labor, contracted services, bad debt, corporate insurance and stock option expenses offset reductions in employee benefit costs and a greater capitalization of overheads. Total labor and contracted services increased by $349,000, bad debt expense by $59,000, corporate property and liability insurance premiums by $48,000, and stock option expense by $50,000 for the same reasons as explained above. Employee benefit expenses declined by $364,000 due to lower pension and postretirement benefit costs and capitalized overheads increased by $186,000 as total capital expenditures increased by $2.8 million. The remaining differences in operation and maintenance expenses were related to various other minor fluctuations in other expenses.

General taxes increased by $45,646, 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 $156,654, 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 last year.

Interest expense increased by $5,796, or 1%, due to a greater level of borrowing under the Company's line-of-credit.

Income tax expense increased by $220,352, 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 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 an agreement with a new asset manager under terms similar to the expiring contract. The new agreement expires in March 2017.

RGC RESOURCES, INC. AND SUBSIDIARIES

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. The Company has recorded a provision for rate refund, including interest, for the difference between rates placed into effect on November 1 and those approved in the stipulation. Refunds to customers are scheduled to be completed after the receipt of the final order.

Also included in the final order regarding the non-gas rate increase was a change to the weather normalization adjustment ("WNA") model. The current WNA model 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 model will no longer have a 3% weather band. Instead, any WNA amount, whether warmer or colder, will be based strictly on the 30-year average during the WNA period. 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 current rate case, which incorporated all SAVE Plan investment to date 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.

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 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 the effect to the financial statements have not yet been determined. When the study is completed and approval is obtained from the SCC, the Company will implement the new rates for the current fiscal year.

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.

Capital Resources and Liquidity

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

Cash and cash equivalents increased by $924,800 for the six-month period ended March 31, 2014 compared to a $3,271,052 increase for the same period last year. The following table summarizes the sources and uses of cash:

RGC RESOURCES, INC. AND SUBSIDIARIES



	Six Months Ended March 31,
	2014			2013
Cash Flow Summary Six Months Ended:
Provided by operating activities	$	9,694,189		$	12,339,835
Used in investing activities	(7,195,308		)	(4,438,570		)
Used in financing activities	(1,574,081		)	(4,630,213		)
Increase in cash and cash equivalents	$	924,800		$	3,271,052

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 six months ended March 31, 2014, cash flow provided by operations declined by $2,645,646 from $12,339,835 for the six months ended March 31, 2013 to $9,694,189 for the six months ended March 31, 2014 primarily due to an increase in accounts receivable balances, a smaller increase in over-collection of gas costs and a reduction in accounts payable partially offset by positive cash flows generated from a greater reduction in storage gas levels and higher net income and depreciation. The increase in accounts receivable balances accounted for approximately $600,000 of the reduction in operating cash flow from last year as higher gas prices increased customer bills. Over-collection of gas costs increased by $1.1 million for the current year compared to approximately $4.3 million increase during the same period last year. In addition, accounts payable balances increased by $1.4 million during the current fiscal year compared to an increase of $2.9 million during the same period last year. This smaller increase in accounts payable corresponds with the Company's new asset manager withdrawing more gas from storage to meet customer demand during the current year. Total storage volumes declined by 2,071,760 decatherms during the current year compared to 1,829,970 decatherms for the same period last year. The cash generated from the greater use of gas in storage served to offset purchased volumes in accounts payable.

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 $2,756,738 due to an increased level of capital expenditures. In addition to the ongoing pipeline 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 the next few year's projected capital expenditures.

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 $3,056,132 primarily due to the prior year's special $1.00 per share dividend paid by the Company on December 17, 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 the $1,047,385 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 at March 31, 2014. With natural gas prices beginning to increase, the apparent end to bonus tax depreciation 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 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

RGC RESOURCES, INC. AND SUBSIDIARIES

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.

Effective March 31, 2014, the Company also executed an unsecured variable rate term note in the amount of $15,000,000. This term note essentially extends the maturity date of the prior term note to March 31, 2015 and retains all other terms and conditions provided for in the original promissory note. The Company anticipates being able to extend this note on comparable terms as currently in place until such time the corresponding swap on the note matures on November 30, 2015.

At March 31, 2014, the Company’s consolidated capitalization, including the note payable and line-of-credit, was 65% equity and 35% 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 March 31, 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 debt outstanding during the period would have resulted in an increase in interest expense for the current period of approximately $35,000. 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 March 31, 2014, the Company had no outstanding derivative instruments to hedge the price of natural gas. The Company had 457,733 decatherms of gas in storage, including LNG, at an average price of $4.36 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.

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 March 31, 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 March 31, 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 March 31, 2014 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		Revolving Line of Credit Note in the original principal amount of $19,000,000 by Roanoke Gas Company in favor of Wells Fargo Bank, N.A. dated March 31, 2014 (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on April 2, 2014).
10.2		Promissory Note in the original amount of $15,000,000 by Roanoke Gas Company in favor of Wells Fargo Bank, N.A. dated March 31, 2014 (incorporated by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed on April 2, 2014).
10.3		Third Amendment to Credit Agreement by and between Roanoke Gas Company and Wells Fargo Bank, N.A. dated March 31, 2014 (incorporated by reference to Exhibit 10.3 to the Registrant's Current Report on Form 8-K filed on April 2, 2014).
10.4		Change in Control Agreement between RGC Resources, Inc. and Mr. Carl J. Shockley effective March 31, 2014 (incorporated by reference to Exhibit 10.4 to the Registrant's Current Report on Form 8-K filed on April 2, 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 March 31, 2014, formatted in XBRL (eXtensible Business Reporting Language); (i) Condensed Consolidated Balance Sheets at March 31, 2014 and September 30, 2013, (ii) Condensed Consolidated Statements of Income for the three months and six months ended March 31, 2014 and 2013; (iii) Condensed Consolidated Statements of Comprehensive Income for the three months and six months ended March 31, 2014 and 2013; (iv) Condensed Consolidated Statements of Cash Flows for the six months ended March 31, 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.



**	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: May 8, 2014	By:	/s/ Paul W. Nester
		Paul W. Nester
		Vice President, Treasurer and CFO