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, 2010

Commission File Number 000-26591

 

 

RGC Resources, Inc.

(Exact name of Registrant as Specified in its Charter)

 

 

 

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

(540) 777-4427

(Registrant’s Telephone Number, Including Area Code)

None

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

 

 

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

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

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

 

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

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

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

 

Class		Outstanding at July 31, 2010
Common Stock, $5 Par Value		2,266,628

 

 

 

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RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

UNAUDITED

 

		June 30, 2010				September 30, 2009
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	14,951,387			$	7,422,360
Accounts receivable (less allowance for uncollectibles of $382,379 and $50,687, respectively)			3,033,087				3,562,837
Note receivable			87,000				87,000
Materials and supplies			563,586				587,815
Gas in storage			10,000,633				16,072,911
Prepaid income taxes			—				1,974,917
Deferred income taxes			3,960,936				3,424,628
Other			1,050,330				985,110
Total current assets			33,646,959				34,117,578
UTILITY PROPERTY:
In service			121,540,689				118,009,532
Accumulated depreciation and amortization			(42,585,080	)			(41,104,408	)
In service, net			78,955,609				76,905,124
Construction work in progress			1,868,367				1,604,046
Utility plant, net			80,823,976				78,509,170
OTHER ASSETS:
Note receivable			1,039,000				1,126,000
Regulatory assets			4,815,894				4,989,347
Other			49,493				59,797
Total other assets			5,904,387				6,175,144
TOTAL ASSETS		$	120,375,322			$	118,801,892

See notes to condensed consolidated financial statements.

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RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

UNAUDITED

 

		June 30, 2010				September 30, 2009
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt		$	15,000,000			$	—
Dividends payable			748,147				716,556
Accounts payable			6,519,096				4,449,735
Customer credit balances			1,432,371				4,204,556
Income taxes payable			22,331				—
Customer deposits			1,663,719				1,601,206
Accrued expenses			1,584,758				2,219,587
Over-recovery of gas costs			4,149,885				5,651,847
Fair value of marked-to-market transactions			3,011,505				2,451,055
Total current liabilities			34,131,812				21,294,542
LONG-TERM DEBT, EXCLUDING CURRENT MATURITIES			13,000,000				28,000,000
DEFERRED CREDITS AND OTHER LIABILITIES:
Asset retirement obligations			2,833,726				2,735,735
Regulatory cost of retirement obligations			7,822,902				7,401,024
Benefit plan liabilities			8,094,113				7,970,074
Deferred income taxes			6,793,889				6,534,621
Deferred investment tax credits			43,408				66,025
Total deferred credits and other liabilities			25,588,038				24,707,479
COMMITMENTS AND CONTINGENCIES (Notes 7 and 9)
STOCKHOLDERS’ EQUITY:
Common stock, $5 par value; authorized, 10,000,000 shares; issued and outstanding 2,265,724 and 2,238,987, respectively			11,328,620				11,194,935
Preferred stock, no par, authorized, 5,000,000 shares; no shares issued and outstanding			—				—
Capital in excess of par value			17,245,973				16,607,897
Retained earnings			22,243,694				19,881,745
Accumulated other comprehensive loss			(3,162,815	)			(2,884,706	)
Total stockholders’ equity			47,655,472				44,799,871
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY		$	120,375,322			$	118,801,892

See notes to condensed consolidated financial statements.

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RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

FOR THE THREE-MONTH AND NINE-MONTH PERIODS ENDED JUNE 30, 2010 AND 2009

UNAUDITED

 

		Three Months Ended June 30,							Nine Months Ended June 30,
		2010				2009			2010				2009
OPERATING REVENUES:
Gas utilities		$	10,050,355			$	10,355,122		$	64,102,256			$	72,550,797
Other			283,946				351,867			1,025,276				901,889
Total operating revenues			10,334,301				10,706,989			65,127,532				73,452,686
COST OF SALES:
Gas utilities			5,471,261				5,514,482			42,738,615				50,579,199
Other			151,731				177,393			515,516				430,017
Total cost of sales			5,622,992				5,691,875			43,254,131				51,009,216
GROSS MARGIN			4,711,309				5,015,114			21,873,401				22,443,470
OTHER OPERATING EXPENSES:
Operations			2,641,717				2,445,330			8,218,518				7,829,924
Maintenance			335,945				447,508			1,061,642				1,234,772
General taxes			312,161				297,202			981,932				927,379
Depreciation and amortization			962,988				1,160,479			2,880,963				3,439,514
Total other operating expenses			4,252,811				4,350,519			13,143,055				13,431,589
OPERATING INCOME			458,498				664,595			8,730,346				9,011,881
OTHER INCOME, Net			16,309				12,686			54,761				68,376
INTEREST EXPENSE			455,551				460,463			1,376,319				1,454,693
INCOME BEFORE INCOME TAXES			19,256				216,818			7,408,788				7,625,564
INCOME TAX EXPENSE			5,790				79,424			2,812,024				2,895,318
NET INCOME			13,466				137,394			4,596,764				4,730,246
OTHER COMPREHENSIVE INCOME (LOSS) NET OF TAX			(437,348	)			699,289			(278,109	)			(747,510	)
COMPREHENSIVE INCOME (LOSS)		$	(423,882	)		$	836,683		$	4,318,655			$	3,982,736
BASIC EARNINGS PER COMMON SHARE		$	0.01			$	0.06		$	2.04			$	2.13
DILUTED EARNINGS PER COMMON SHARE		$	0.01			$	0.06		$	2.03			$	2.12
DIVIDENDS DECLARED PER COMMON SHARE		$	0.33			$	0.32		$	0.99			$	0.96

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, 2010 AND 2009

UNAUDITED

 

		Nine Months Ended June 30,
		2010				2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	4,596,764			$	4,730,246
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			2,989,830				3,600,313
Cost of removal of utility plant, net			(218,367	)			(181,428	)
Changes in assets and liabilities which used cash, exclusive of changes and noncash transactions shown separately			6,070,841				18,541,805
Net cash provided by operating activities			13,439,068				26,690,936
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant and nonutility property			(4,575,843	)			(4,281,393	)
Proceeds from disposal of equipment			10,265				27,826
Proceeds from sale of short-term investments			—				500,000
Net cash used in investing activities			(4,565,578	)			(3,753,567	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt			—				5,000,000
Proceeds on collection of note			87,000				87,000
Net repayments under line-of-credit agreement			—				(13,960,000	)
Proceeds from issuance of stock (26,737 and 20,258 shares, respectively)			771,761				526,123
Cash dividends paid			(2,203,224	)			(2,111,042	)
Net cash used in financing activities			(1,344,463	)			(10,457,919	)
NET INCREASE IN CASH AND CASH EQUIVALENTS			7,529,027				12,479,450
BEGINNING CASH AND CASH EQUIVALENTS			7,422,360				875,436
ENDING CASH AND CASH EQUIVALENTS		$	14,951,387			$	13,354,886
SUPPLEMENTAL INFORMATION:
Cash paid during the period for:
Interest		$	1,509,863			$	1,598,182
Income taxes net of refunds			919,000				2,269,308

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

In the opinion of management, the accompanying unaudited condensed consolidated financial statements contain all adjustments (consisting of only normal recurring accruals) necessary to present fairly RGC Resources, Inc.’s financial position as of June 30, 2010 and the results of its operations for the three months and nine months ended June 30, 2010 and 2009 and its cash flows for the nine months ended June 30, 2010 and 2009. The results of operations for the three months and nine months ended June 30, 2010 are not indicative of the results to be expected for the fiscal year ending September 30, 2010 as quarterly earnings are affected by the highly seasonal nature of the business and weather conditions generally result in greater earnings during the winter months.

The condensed consolidated interim financial statements and condensed notes are presented as permitted by Form 10-Q and do not contain certain information included in the Company’s annual consolidated financial statements and notes thereto. The condensed consolidated financial statements and condensed notes should be read in conjunction with the financial statements and notes contained in the Company’s Form 10-K. The September 30, 2009 balance sheet was included in the Company’s Form 10-K.

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

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

2. Rates and Regulatory Matters

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

In the fourth quarter of fiscal 2009, the Company implemented new depreciation rates related to an updated depreciation study that the SCC requires the Company to conduct every five years. The new rates were approved by the SCC and made effective retroactive to October 1, 2008; however the full impact of the change in depreciation estimate for the year was recorded in the fourth quarter. As a result of the updated depreciation study, the Company’s overall composite weighted average depreciation rate declined from 4.12% to 3.31% of total

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RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

UNAUDITED

 

depreciable assets. If the change in depreciation rates had been reflected in the first quarter of fiscal 2009, the impact to the Statement of Income and Comprehensive Income for the three-months and nine-months ended June 30, 2009 would have been to reduce depreciation expense by $234,550 and $681,650, increase net income by $145,515 and $422,896 and increase earnings per share by $0.07 and $0.19, respectively.

3. Derivatives and Hedging

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

The Company enters into collars, swaps and caps for the purpose of hedging the price of natural gas in order to provide price stability during the winter months. The fair value of these instruments is recorded in the balance sheet with the offsetting entry to either under-recovery of gas costs or over-recovery of gas costs. Net income and other comprehensive income are not affected by the change in market value as any cost incurred or benefit received from these instruments is recoverable or refunded to customers through the purchased gas adjustment clause (“PGA”) included as part of the Company’s billing rate. Pursuant to the provisions of the Company’s PGA, the SCC provides the Company with a method of passing along increases or decreases in natural gas costs incurred by regulated operations, including gains and losses on natural gas derivative hedging instruments, to its customers. On a quarterly basis, the Company files a PGA rate adjustment request to the SCC to adjust the gas cost component of its rates either up or down depending on projected price and activity. Once administrative approval is received, the Company adjusts the gas cost component of its rates to reflect the approved amount. As actual costs will differ from the projections used in establishing the PGA rate, the Company may either over-recover or under-recover its actual gas costs during the period. Any difference between actual costs incurred and costs recovered through the application of the PGA is reflected as a regulatory asset or liability. At the end of the deferral period, the balance of the net deferred charge or credit is amortized over an ensuing 12-month period as amounts are reflected in customer billings.

At June 30, 2010, the Company has collar agreements outstanding for the 2010-11 winter heating season to hedge 800,000 decatherms of natural gas. As the current value of the derivatives fall between the floor and ceiling prices of the collar agreements, there is no fair value reflected in the financial statements at June 30, 2010.

The Company has two interest rate swaps associated with its variable rate notes. The first swap relates to the $15,000,000 note issued in November 2005. This swap essentially converts the floating rate note based upon LIBOR into fixed rate debt with a 5.74% effective interest rate. The second swap relates to the $5,000,000 variable rate note issued in October 2008. This swap converts the variable rate note based on LIBOR into a fixed rate debt with a

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RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

UNAUDITED

 

5.79% effective interest rate. Both swaps mature on December 1, 2015 and qualify as cash flow hedges with changes in fair value reported in other comprehensive income. No portions of interest rate swaps were deemed ineffective during the periods presented.

The table below reflects the fair values of the derivative instruments and their corresponding classification in the consolidated balance sheets under the current liabilities caption of “Fair value of marked-to-market transactions” as of June 30, 2010 and September 30, 2009:

 

		June 30, 2010			September 30, 2009
Derivatives designated as hedging instruments:
Interest rate swaps		$	3,011,505		$	2,451,055
Natural gas collar arrangement			—			—
Total derivatives designated as hedging instruments		$	3,011,505		$	2,451,055

The table in Note 4 below reflects the effect on income and other comprehensive income of the Company’s cash flow hedges.

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

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RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

UNAUDITED

 

4. Comprehensive Income

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

 

		Three Months Ended June 30,								Nine Months Ended June 30,
		2010				2009				2010				2009
Interest Rate SWAPs
Unrealized gains (losses)		$	(975,783	)		$	889,631			$	(1,266,654	)		$	(1,781,995	)
Income tax			370,407				(337,704	)			480,823				676,446
Net unrealized gains (losses)			(605,376	)			551,927				(785,831	)			(1,105,549	)
Transfer of realized losses to interest expense			233,446				219,441				706,204				522,851
Income tax			(88,616	)			(83,300	)			(268,076	)			(198,475	)
Net transfer of realized losses to interest expense			144,830				136,141				438,128				324,376
Defined Benefit Plans
Amortization of actuarial loss transferred to income			25,619				6,313				76,857				18,939
Income tax			(9,725	)			(2,396	)			(29,175	)			(7,188	)
Net transfer of realized losses to income			15,894				3,917				47,682				11,751
Amortization of transition obligation			11,773				11,773				35,319				35,319
Income tax			(4,469	)			(4,469	)			(13,407	)			(13,407	)
Net amortization of transition obligation			7,304				7,304				21,912				21,912
Net other comprehensive income (loss)		$	(437,348	)		$	699,289			$	(278,109	)		$	(747,510	)
Change in measurement date			—				—				—				11,221
Accumulated comprehensive loss - beginning of period			(2,725,467	)			(2,659,970	)			(2,884,706	)			(1,224,392	)
Accumulated comprehensive loss - end of period		$	(3,162,815	)		$	(1,960,681	)		$	(3,162,815	)		$	(1,960,681	)

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RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

UNAUDITED

 

The components of accumulated comprehensive loss as of June 30, 2010 and 2009:

 

		June 30
		2010				2009
Interest rate swaps		$	(1,868,338	)		$	(1,300,843	)
Pension plan			(915,365	)			(356,833	)
Postretirement benefit plan			(379,112	)			(303,005	)
Total accumulated comprehensive loss		$	(3,162,815	)		$	(1,960,681	)

5. Weighted Average Shares

Basic earnings per common share for the three months and nine months ended June 30, 2010 and 2009 are calculated by dividing net income by the weighted average common shares outstanding during the period. Diluted earnings per common share for the three months and nine months ended June 30, 2010 are calculated by dividing net income by the weighted average common shares outstanding during the period plus dilutive potential common shares. Dilutive potential common shares are calculated in accordance with the treasury stock method, which assumes that proceeds from the exercise of all stock options are used to repurchase common stock at market value. The amount of shares remaining after the proceeds are exhausted represents the potentially dilutive effect of the securities. There were no anti-dilutive securities in the respective periods. A reconciliation of the weighted average common shares and the diluted average common shares is provided below:

 

		Three Months Ended June 30,				Nine Months Ended June 30,
		2010		2009		2010		2009
Weighted average common shares		2,263,119		2,227,469		2,252,447		2,219,632
Effect of dilutive securities:
Options to purchase common stock		6,384		7,279		7,272		7,380
Diluted average common shares		2,269,503		2,234,748		2,259,719		2,227,012

6. 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

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RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

UNAUDITED

 

gas supply from an asset manager. The Company uses an asset manager to assist in optimizing the use of its transportation, storage rights, and gas supply in order to provide a secure and reliable source of natural gas to its customers. The Company also has storage and pipeline capacity contracts to store and deliver natural gas to the Company’s distribution system. The Company is served directly by two primary pipelines. These two pipelines deliver 100% of the natural gas supplied to the Company’s customers. Depending on weather conditions and the level of customer demand, failure of one or both of these transmission pipelines could have a major adverse impact on the Company.

In July 2010, the Company received notice that it had been named as a defendant in two civil lawsuits associated with an explosion and fire at a West Virginia residence in November 2009. The suits claimed that the fire was due to the ignition of propane within the residence. This residence was served by a propane tank installation at the time the assets of the Company’s propane subsidiary, Highland Propane, were sold to Inergy Propane, LLC (“Inergy”) in 2004. Inergy retained the name Highland Propane and assumed ownership and responsibility for all propane tanks including the tank located at the residence identified in the suits. No damage amounts are specified in the suits; however, both property damage and bodily injury are claimed in the suits. The Company has not recorded a liability for the lawsuits as management does not believe the likelihood of a negative outcome to the Company is probable nor is the amount of potential damages readily determinable. In addition, if the outcome of the lawsuits were adverse to the Company, management believes that any such damages would be covered by the Company’s insurance.

Except to the extent, if any, described above, the Company is not a party to any material pending legal proceedings.

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RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

UNAUDITED

 

7. Employee Benefit Plans

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

 

		Three Months Ended June 30,								Nine Months Ended June 30,
		2010				2009				2010				2009
Components of net periodic pension cost:
Service cost		$	112,215			$	100,906			$	336,645			$	302,718
Interest cost			213,411				211,725				640,233				635,175
Expected return on plan assets			(204,657	)			(215,537	)			(613,971	)			(646,611	)
Recognized loss			68,778				17,647				206,334				52,941
Net periodic pension cost		$	189,747			$	114,741			$	569,241			$	344,223
		Three Months Ended June 30,								Nine Months Ended June 30,
		2010				2009				2010				2009
Components of postretirement benefit cost:
Service cost		$	39,946			$	30,914			$	119,838			$	92,742
Interest cost			128,359				126,005				385,077				378,015
Expected return on plan assets			(81,263	)			(69,179	)			(243,789	)			(207,537	)
Amortization of transition obligation			47,223				47,223				141,669				141,669
Recognized loss			17,134				—				51,402				—
Net postretirement benefit cost		$	151,399			$	134,963			$	454,197			$	404,889

The Company contributed $500,000 to its pension plan for the nine-month period ended June 30, 2010. The Company currently expects to make a total contribution of approximately $800,000 to its pension plan and $600,000 to its postretirement benefit plan during the fiscal year ending September 30, 2010. The Company will continue to evaluate its benefit plan funding levels throughout the year and modify its funding plan if necessary.

8. Environmental Matters

Both Roanoke Gas Company and Bluefield Gas Company, a previously owned subsidiary of the Company, operated manufactured gas plants (MGPs) as a source of fuel for lighting and heating until the early 1950s. A by-product of operating MGPs was coal tar, and the potential exists for on-site tar waste contaminants at the former plant sites. Should the Company eventually be required to remediate either site, the Company will pursue all prudent and reasonable means to recover any related costs, including insurance claims and regulatory approval for rate case recognition of expenses associated with any work required. While the Company sold the stock of Bluefield Gas Company to ANGD, LLC in 2007, it retained ownership of the former MGP site and entered into an Indemnification and Cost Sharing Agreement with ANGD to seek recovery of any remediation costs through rates and

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RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

UNAUDITED

 

under any applicable insurance policies or from any third party for reimbursement to the Company for 25% of any such costs to the extent they are not otherwise recovered. If the Company incurs costs associated with a required clean-up of the Roanoke Gas Company MGP site, the Company anticipates recording a regulatory asset for such clean-up costs to be recovered in future rates.

9. Newly Adopted Accounting Standards

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (FASB ASC No. 820). FASB ASC No. 820 defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value methods. No new fair value measurements are required. Instead, it provides for increased consistency and comparability in fair value measurements and for expanded disclosure surrounding the fair value measurements. Disclosures regarding nonfinancial assets and liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis, were delayed for one year. The Company adopted the fair value provisions of FASB ASC No. 820 effective October 1, 2008 and the provisions regarding nonfinancial assets and liabilities effective October 1, 2009. The adoption had no material impact on the Company’s financial position, results of operations or cash flows. The disclosures required by FASB ASC No. 820 are included in Note 11.

In January 2010, the FASB issued Accounting Standards Update (“ASU”) 2010-06, Fair Value Measurements and Disclosures – Improving Disclosures about Fair Value Measurements. This ASU improves disclosures regarding fair value under FASB ASC No. 820 including (1) requiring an entity to disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers; (2) in the reconciliation for fair value measurements using significant unobservable inputs (Level 3), a reporting entity should present separately information about purchases, sales, issuances and settlements; and (3) providing clarification that a reporting entity should provide disclosures about the valuation techniques and inputs used to measure fair value for both recurring and non-recurring fair value measurements. The Company adopted ASU 2010-06 effective with its March 31, 2010 reporting date. The disclosures related to Level 3 fair value measurements are not effective until fiscal years beginning after December 31, 2010 and for interim periods within those fiscal years.

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

10. Recently Issued Accounting Standards Pending Adoption

In December 2008, the FASB issued FASB Staff Position No 132(R)-1, (FSP 132(R)-1), Employers’ Disclosures about Postretirement Benefit Plan Assets (FASB ASC No. 715).

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RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

UNAUDITED

 

FASB’s objective of these changes is to improve disclosures about plan assets in employers’ defined benefit pension or other post-retirement plans by providing users of financial statements with an understanding of: (a) How investment allocation decisions are made, including the factors that are pertinent to an understanding of investment policies and strategies; (b) The major categories of plan assets; (c) The inputs and valuation techniques used to measure the fair value of plan assets; (d) The effect of fair value measurements using significant unobservable inputs on changes in plan assets for the period; and (e) Significant concentrations of risk within plan assets. The new disclosure requirements under FASB ASC No. 715 are effective for fiscal years ending after December 15, 2009. Management does not anticipate these changes to have a material impact on its financial position, results of operations or cash flows.

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

11. 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).

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RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

UNAUDITED

 

The following tables summarizes the Company’s financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements by level within the fair value hierarchy as of June 30, 2010 and September 30, 2009:

 

		Fair Value Measurements - June 30, 2010
		Fair Value			Quoted Prices in Active Markets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Liabilities:
Natural gas purchases		$	2,512,309		$	—		$	2,512,309		$	—
Interest rate swaps			3,011,505			—			3,011,505			—
Total		$	5,523,814		$	—		$	5,523,814		$	—
		Fair Value Measurements - September 30, 2009
		Fair Value			Quoted Prices in Active Markets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Liabilities:
Accounts payable		$	1,146,734		$	—		$	1,146,734		$	—
Interest rate swaps			2,451,055			—			2,451,055			—
Total		$	3,597,789		$	—		$	3,597,789		$	—

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

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

The following table summarizes the fair value of the Company’s financial assets and liabilities that are not adjusted to fair value in the financial statements as of June 30, 2010

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RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

UNAUDITED

 

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

 

		June 30, 2010						September 30, 2009
		Carrying Amount			Fair Value			Carrying Amount			Fair Value
Assets:
Note receivable		$	1,126,000		$	1,122,438		$	1,213,000		$	1,173,749
Liabilities:
Long-term debt		$	28,000,000		$	29,280,915		$	28,000,000		$	29,382,055

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

The note receivable is a five year note with a fifteen year amortization as partial payment for the sale of the Bluefield, Virginia natural gas distribution assets to ANGD, LLC in October 2007. The fair value of the note receivable is estimated by discounting future cash flows based on a range of rates for similar investments adjusted for management’s expectation of credit and other risks. The fair value of long-term debt is estimated by discounting the future cash flows of the fixed rate debt at rates extrapolated based on current market conditions. The variable rate long-term debt has interest rate swaps that effectively convert such debt to fixed rate. The values of the swap agreements are included in the first table above.

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, 2010 and September 30, 2009, no single customer accounted for more than 5% of the total accounts receivable balance. The Company maintains certain credit standards with its customers and requires a customer deposit if such evaluation warrants. The Company is also exposed to credit risk of nonperformance by the counterparty on its commodity-based collar agreements. The Company uses financially sound institutions to mitigate the risk of nonperformance on these contracts.

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RGC RESOURCES, INC. AND SUBSIDIARIES

 

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

Forward-Looking Statements

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

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RGC RESOURCES, INC. AND SUBSIDIARIES

 

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, 2010. 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 weather conditions, improvement or deterioration in the local economic environment and the level of operating and maintenance costs incurred during the remainder of the year.

Overview

Resources is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately 56,900 residential, commercial and industrial customers in Roanoke, Virginia and the surrounding areas through its Roanoke Gas Company (“Roanoke Gas”) subsidiary. Natural gas service is provided at rates and for terms and conditions set by the Virginia State Corporation Commission (“SCC”).

Resources also provides certain unregulated services through Roanoke Gas. Such unregulated operations represent less than 3% of total revenues and margin of Resources on an annual basis.

The Company experienced a reduction of approximately $124,000 in net income for the quarter ended June 30, 2010 compared to the same period last year. A combination of a decrease in natural gas deliveries due to a fewer heating degree days (an industry measure by which the average daily temperature falls below 65 degrees Fahrenheit), lower inventory carrying cost revenues, higher operation expenses and lower depreciation expense associated with updated depreciation rates were the most significant items contributing to the results for the current period.

Winter weather conditions, natural gas prices, and the economic environment have a direct influence on the quantity of natural gas sales and deliveries to the Company’s customers. As a majority of natural gas sales are used for heating purposes, an increase or decrease in heating degree days will generally impact natural gas consumption. For the quarter, total natural gas deliveries decreased by 6% as residential and commercial sales declined due to warmer weather. Transportation and industrial sales increased by 5% representing an improvement in industrial activity over last year.

The commodity price of natural gas has declined from its peak of more than $13.00 per decatherm in the summer of 2008 to under $4.00 per decatherm last summer and has ranged between $4.00 and $6.50 over the current fiscal year. The current commodity price of natural gas has allowed the Company’s volumetric billing rates to remain at their lowest level since 2003. During the summer of 2008, the Company purchased natural gas for storage at an average price of $11.00 per decatherm compared to $4.00 per decatherm last year and $4.50 so far this year. As natural gas prices have declined, the per decatherm value of natural gas in storage has declined as well, resulting in a continuing decline in carrying cost revenues.

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RGC RESOURCES, INC. AND SUBSIDIARIES

 

The Company has an approved rate structure in place that mitigates the impact of financing costs of its natural gas inventory. Under this rate structure, Roanoke Gas recognizes revenue for the financing costs or “carrying costs” of its investment in natural gas inventory. The carrying cost revenue factor applied to inventory is based on the Company’s weighted average cost of capital including interest rates on short-term and long-term debt and the Company’s authorized return on equity. During times of rising gas costs and rising inventory levels, the Company recognizes revenues to offset higher financing costs associated with higher inventory balances. Conversely, during times of decreasing inventory costs and lower inventory balances, the Company recognizes less carrying cost revenue as financing costs are lower. As a result of the much lower price of natural gas in storage during the current year compared to the same period last year, the Company recognized approximately $119,000 and $715,000 less carrying cost revenues for the three-month and nine-month periods ended June 30, 2010 than for the same periods during the prior year. The decline in carrying cost revenues is expected to continue through the fourth quarter of this fiscal year.

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

Results of Operations

Three Months Ended June 30, 2010:

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

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RGC RESOURCES, INC. AND SUBSIDIARIES

 

		Three Months Ended June 30,						Increase/
		2010			2009			(Decrease)				Percentage
Operating Revenues
Gas Utility		$	10,050,355		$	10,355,122		$	(304,767	)		-3	%
Other			283,946			351,867			(67,921	)		-19	%
Total Operating Revenues		$	10,334,301		$	10,706,989		$	(372,688	)		-3	%
Delivered Volumes
Regulated Natural Gas (DTH)
Residential and Commercial			688,971			801,663			(112,692	)		-14	%
Transportation and Interruptible			616,652			587,264			29,388			5	%
Total Delivered Volumes			1,305,623			1,388,927			(83,304	)		-6	%
Heating Degree Days (Unofficial)			219			336			(117	)		-35	%

Total operating revenues for the three months ended June 30, 2010 compared to the same period last year decreased due to a combination of lower natural gas deliveries and a decline in inventory carrying cost revenues.

 

		Three Months Ended June 30,						Increase/
		2010			2009			(Decrease)				Percentage
Gross Margin
Gas Utility		$	4,579,094		$	4,840,640		$	(261,546	)		-5	%
Other			132,215			174,474			(42,259	)		-24	%
Total Gross Margin		$	4,711,309		$	5,015,114		$	(303,805	)		-6	%

Regulated natural gas margins from utility operations declined from the same period last year primarily due to the reduction in delivered natural gas volumes and carrying cost revenues. Residential and commercial volumes decreased by 14% from last year’s levels as a result of the warmer weather as reflected in the 35% reduction in heating degree days. Industrial usage, as represented in the transportation and interruptible categories, increased by 5% during the quarter due to increases in usage by a few of the larger customers. The Company realized approximately $28,000 in additional margin from the growth in customer base charges, which is a flat monthly fee billed to each natural gas customer. As discussed above, carrying cost revenues associated with natural gas inventories declined from last year’s levels corresponding with the sharp decline of the cost of gas in storage. Carrying cost revenues declined by approximately $119,000 for the quarter.

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RGC RESOURCES, INC. AND SUBSIDIARIES

 

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

 

Net Margin Decrease
Customer Base Charge		$	28,447
Carrying Cost			(118,639	)
Volumetric			(178,775	)
Other			7,421
Total		$	(261,546	)

Other margins decreased by $42,259 from last year primarily due to a reduction in contract services in unregulated operations as demand for these services declined for the quarter. These contract services account for approximately 70% of other margins and are subject to annual renewals and bid processes. Therefore, there can be no guarantee that the revenues and margins for these services will continue in the future.

Operations expenses increased by $196,387, or 8%, over the same period last year, primarily as a result of higher employee benefit costs and contracted services. Total employee benefit costs increased by approximately $135,000 over the same period last year due to a $91,000 increase in pension and postretirement medical costs related to the amortization of a higher actuarial loss and $22,000 in higher health insurance premiums. Professional services increased by approximately $40,000 due to higher legal costs related to preparation for union contract negotiations and network systems consulting.

Maintenance expenses decreased by $111,563, or 25%, primarily due to a reduction of the number of distribution system leaks repaired during the period and a reduction in the level of general facility maintenance projects. The number of distribution system leaks has declined over time as the Company has renewed a significant portion of its bare steel and cast iron pipe. Although the number of leak repairs has declined for the period, the number of leaks pending repair has increased over last year. Some of these leaks will be repaired while others are located in areas where the pipeline will be replaced. The Company continues to monitor system leaks prior to their repair to ensure safety standards are met. In addition, the prior year included certain planned maintenance projects for the corporate office and other support operations.

General taxes increased by $14,959, or 5%, related to higher property taxes associated with increased investment in utility plant.

Depreciation expense decreased by $197,491, or 17%, due to the implementation of new depreciation rates as a result of an updated depreciation study approved and implemented in the fourth quarter of last year. If the new rates were reflected in the first quarter of last year, depreciation expense for the quarter would have been $234,550 less. See note 2 above for more information regarding the change in depreciation rates.

Interest expense declined by $4,912, or 1%, as the Company’s line-of-credit was not utilized in either quarter.

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RGC RESOURCES, INC. AND SUBSIDIARIES

 

Income tax expense decreased by $73,634, or 93%, which corresponds to the reduction in pre-tax income for the quarter.

Nine Months Ended June 30, 2010:

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

 

		Nine Months Ended June 30,						Increase/
		2010			2009			(Decrease)				Percentage
Operating Revenues
Gas Utilities		$	64,102,256		$	72,550,797		$	(8,448,541	)		-12	%
Other			1,025,276			901,889			123,387			14	%
Total Operating Revenues		$	65,127,532		$	73,452,686		$	(8,325,154	)		-11	%
Delivered Volumes
Regulated Natural Gas (DTH)
Residential and Commercial			6,159,382			6,220,065			(60,683	)		-1	%
Transportation and Interruptible			2,066,791			1,966,210			100,581			5	%
Total Delivered Volumes			8,226,173			8,186,275			39,898			0	%
Heating Degree Days (Unofficial)			4,027			3,896			131			3	%

Total operating revenues for the nine months ended June 30, 2010 compared to the same period last year decreased due to reductions in the price of natural gas. The average commodity price of gas delivered declined by 15% from last year. Total natural gas deliveries were nearly unchanged increasing by less than 1% for the year even though total heating degree days increased by 3%. Transportation and interruptible volumes increased 5% due to improvement in production activities. Other revenues increased by 14% related primarily to the higher level of contract services performed in the prior quarters.

 

		Nine Months Ended June 30,						Increase/
		2010			2009			(Decrease)				Percentage
Gross Margin
Gas Utilities		$	21,363,641		$	21,971,598		$	(607,957	)		-3	%
Other			509,760			471,872			37,888			8	%
Total Gross Margin		$	21,873,401		$	22,443,470		$	(570,069	)		-3	%

Regulated natural gas margins decreased due to declining carrying cost revenues and a small decrease in residential and commercial natural gas deliveries partially offset by higher customer base charge revenues. Although total natural gas deliveries were nearly unchanged from last

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RGC RESOURCES, INC. AND SUBSIDIARIES

 

year, the higher margin residential and commercial volumes decreased by 1% which resulted in a decrease in volumetric margin. Carrying cost revenues decreased by approximately $715,000 due to significantly lower average investment in natural gas storage during the period. The components of the regulated margin decrease are summarized below:

 

Net Margin Decrease
Customer Base Charge		$	269,682
Carrying Cost			(715,405	)
Volumetric			(158,797	)
Other			(3,437	)
Total		$	(607,957	)

Other margins increased by $37,888 due to an increase in contracted services in unregulated operations in the first two quarters.

Operations expenses increased by $388,594, or 5%, for the nine-month period ended June 30, 2010 compared to the same period last year primarily due to higher employee benefit costs. Total employee benefit costs increased by approximately $400,000 due to higher medical insurance premiums, pension costs and postretirement medical costs. Maintenance expenses decreased by $173,130, or 14%, due to reductions in the number of pipeline leak repairs on the Company’s distribution system and a reduction in planned general facility maintenance projects.

General taxes increased $54,553, or 6%, for the nine-month period ended June 30, 2010 compared to the same period last year. Most of the increase was attributable to higher property taxes related to a higher level of utility plant.

Depreciation expense decreased by $558,551, or 16%, due to the implementation of new depreciation rates as a result of an updated depreciation study approved and implemented in the fourth quarter of last year. If the new rates were reflected in the first quarter of last year, depreciation expense for the nine-month period ended June 30, 2009 would have been $681,650 less.

Other income, net, decreased $13,615 due to reduced investment earnings on the Company’s short-term investments and a reduction in the note receivable balance associated with the sale of the Bluefield, Virginia natural gas distribution assets to ANGD, LLC in October 2007. The note has a stated interest rate of 10% with annual installments of $87,000 and a balloon payment of $952,000 due in November 2012.

Interest expense decreased by $78,374, or 5%, due to the absence of borrowing under the Company’s line-of-credit. Total average borrowings outstanding for the current nine month period declined by nearly $4.5 million compared to the same period last year.

Income tax expense decreased $83,294, or 3%, which corresponds to the decrease in pre-tax income. The effective tax rate was 38% for both periods.

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RGC RESOURCES, INC. AND SUBSIDIARIES

 

Critical Accounting Policies and Estimates

The consolidated financial statements of Resources are prepared in accordance with accounting principles generally accepted in the United States of America. The amounts of assets, liabilities, revenues and expenses reported in the Company’s financial statements are affected by accounting policies, estimates and assumptions that are necessary to comply with generally accepted accounting principles. Estimates used in the financial statements are derived from prior experience, statistical analysis and professional judgments. Actual results may differ significantly from these estimates and assumptions.

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

Regulatory accounting – The Company’s regulated operations follow the accounting and reporting requirements of FASB ASC No. 980, Regulated Operations. The economic effects of regulation can result in a regulated company deferring costs that have been or are expected to be recovered from customers in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as assets in the consolidated balance sheet (regulatory assets) and recorded as expenses when such amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for current collection in rates of costs that are expected to be incurred in the future (regulatory liabilities).

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

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

The Company bills its regulated natural gas customers on a monthly cycle. The billing cycle periods for most customers do not coincide with the accounting periods used for financial reporting. The Company accrues estimated revenue for natural gas delivered to customers not yet billed during the accounting period. Determination of unbilled revenue relies on the use of estimates, weather during the period, and current and historical data. The financial statements included unbilled revenue receivable of $916,278 and $990,797 as of June 30, 2010 and 2009, respectively.

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RGC RESOURCES, INC. AND SUBSIDIARIES

 

Allowance for Doubtful Accounts – The Company evaluates the collectibility of its accounts receivable balances based upon a variety of factors including loss history, level of delinquent account balances and general economic climate.

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

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

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

Derivatives – The Company may hedge certain risks incurred in its operation through the use of derivative instruments. The Company applies the requirements of FASB ASC No. 815, Derivatives and Hedging, which requires the recognition of derivative instruments as assets or

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liabilities in the Company’s balance sheet at fair value. In most instances, fair value is based upon quoted futures prices for natural gas commodities and interest rate futures for interest rate swaps. Changes in the commodity and futures markets will impact the estimates of fair value in the future. Furthermore, the actual market value at the point of realization of the derivative may be significantly different from the values used in determining fair value in prior financial statements.

Asset Management

Roanoke Gas uses a third party as an asset manager to manage its pipeline transportation and storage rights and gas supply inventories and deliveries. In return for being able to utilize the excess capacities of the transportation and storage rights, the third party pays Roanoke Gas a monthly utilization fee, which is used to reduce the cost of gas for customers. The current agreement expires October 31, 2010. The Company is currently evaluating bid responses from asset managers for a new three year contract. The Company expects to complete its evaluation and make its final selection during its fourth quarter.

Energy Costs

Energy costs represent the single largest expense of the Company. The Company uses various hedging mechanisms, including summer storage injections and financial instruments to help mitigate the impact of potential price volatility. Prudently incurred natural gas costs are fully recoverable under the present regulatory PGA mechanism, and increases and decreases in the cost of gas are passed through to the Company’s customers. As discussed above, since the summer of 2008, the commodity price of natural gas has declined significantly with the price falling below $4.00 a decatherm during the summer of 2009 before rebounding. During this time period, the price of natural gas declined at a faster rate than the Company’s PGA factor, which adjusts the billing rate to customers for the cost of natural gas. As a result of this lag, the Company had over-collected approximately $6 million on the gas cost component of its rates as of December 31, 2009. The Company began refunding the over-collection over a 12-month period as part of the PGA factor adjustment beginning in January 2010.

Natural gas prices are currently near the $4.50 per decatherm level and futures indices indicate prices could remain below $6.00 over the next few years. These low prices are attributable to several factors including the depressed economic environment which limits demand, strong storage levels, adequate production and increased reserve estimates. Continuation of low prices would allow natural gas to remain a viable competitive energy source for heating and industrial activities. However, implementation of drilling restrictions due to the oil leak in the Gulf of Mexico and a potentially active hurricane season could adversely affect production activities which could lead to higher natural gas prices.

Even though energy costs are recoverable through the PGA mechanism, higher energy prices may have a negative impact on earnings through decreased demand resulting from customer conservation or use of alternative fuels, increases in bad debt expense and higher interest costs due to increased borrowing to temporarily fund receivables from customers. The Company’s rate structure provides a level of protection against the impact that rising energy prices may have on

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bad debts and carrying costs of gas in storage by allowing for more timely recovery of these costs. However, the rate structure will not protect the Company from an increased rate of bad debts or increases in interest rates or decreased demand without the benefit of future rate case filings and rate awards.

Regulatory Affairs

On July 14, 2010, the Company filed notice with the SCC of its intent to file an expedited rate case based on the test period ended June 30, 2010. The amount of increase in non-gas rates to be requested has not yet been determined.

Capital Resources and Liquidity

Due to the capital intensive nature of the utility business, as well as the related weather sensitivity, the Company’s primary capital needs are the funding of its continuing construction program, the seasonal funding of its natural gas inventories, 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 $7,529,027 for the nine-month period ended June 30, 2010 compared to a $12,479,450 increase for the same period last year. The following table summarizes the categories of sources and uses of cash:

 

		Nine Months Ended June 30,
		2010				2009
Cash Flow Summary Nine Months Ended:
Provided by operating activities		$	13,439,068			$	26,690,936
Used in investing activities			(4,565,578	)			(3,753,567	)
Used in financing activities			(1,344,463	)			(10,457,919	)
Increase in cash and cash equivalents		$	7,529,027			$	12,479,450

The seasonal nature of the natural gas business causes operating cash flows to fluctuate significantly during the year as well as from year to year. Factors including weather, energy prices, natural gas storage levels and customer collections all contribute to working capital levels and the related cash flows. Generally, operating cash flows are positive during the second and third quarters as a combination of earnings, declining storage gas levels and collections on customer accounts all contribute to higher cash levels. During the first and fourth quarters, operating cash flows generally decrease due to the increases in natural gas storage levels, rising customer receivable balances and construction activity. For the nine months ended June 30, 2010, cash provided by operating activities decreased by approximately $13,252,000, from $26,691,000 for the nine months ended June 30, 2009 to $13,439,000 for the current period. The decline in cash provided by operating activities is primarily attributable to the approximately

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RGC RESOURCES, INC. AND SUBSIDIARIES

 

$7,500,000 cash generated from the over-collection of gas costs that occurred during the prior year compared to a net refunding of approximately $1,500,000 of the over-collection during the current year. Furthermore, the prior year reflected a greater amount of cash generated from the withdrawal of gas in storage due to a higher average price of gas in storage. Due to natural gas price spikes during the summer of 2008 injection period, the average price of gas in storage during the prior winter season was approximately $9.75 per decatherm. As gas prices declined to as low as $4.00 a decatherm during last summer’s storage injections, the cost of gas in storage dropped to approximately $6.00 per decatherm at the beginning of the current fiscal year. As of June 30, 2010, the cost of gas in storage declined to nearly $5.00 per decatherm as lower priced gas was delivered into storage. Based on the natural gas futures prices as of July 2010, the price of gas delivered to storage during the balance of the current storage injection cycle should be near the same level as the price of gas delivered to storage during the prior year.

Investing activities are generally composed of expenditures under the Company’s construction program, which involves a combination of replacing aging bare steel and cast iron pipe with new plastic or coated steel pipe, and expansion of its natural gas system to meet the demands of customer growth. Cash flows used in investing activities increased by approximately $812,000 due to a higher level of capital expenditures and the absence of proceeds on the sale of short-term investments. Total capital expenditures were $4,575,843 and $4,281,393 for the nine-month periods ended June 30, 2010 and 2009, respectively, which reflects increased expenditures for pipeline replacement activity and improvements to the liquefied natural gas facility. The Company expects total capital expenditures for the current fiscal year to be higher than last year. Furthermore, the Company anticipates increasing the pace of its distribution pipeline renewal for the balance of the current year and for the next few years. Historically, depreciation cash flow has provided approximately 70% of the annual support for the Company’s capital budget. With the implementation of new depreciation rates as a result of the updated depreciation study, operating cash flow from depreciation will be approximately 20% less than what was provided under the prior depreciation rates. As a result, future capital expenditure funding will be more dependent on borrowing activity and other sources of cash.

Financing activities generally consist of long-term and short-term borrowings and repayments, issuance of stock and the payment of dividends. As discussed above, the Company uses its line-of-credit arrangement to fund seasonal working capital needs as well as provide temporary financing for capital projects. Cash flow used in financing activities declined by approximately $9,113,000, from $10,458,000 to $1,344,000. The reason for the decline in use of funds corresponds to the absence of borrowing activity for the current year under the Company’s line-of-credit agreement. The prior year reflected the net pay off of $13,960,000 under the line-of-credit. The impact of much lower natural gas prices and their effect on reducing inventory and accounts receivable levels and the level of over-recovery of gas costs generated sufficient levels of cash to avoid accessing the line-of-credit during the current year. Assuming natural gas commodity prices remain in the current range of $4.00 to $5.50 per decatherm over the next 12 months along with the refunding of the over-recovery of gas costs which began in January, the Company expects to return to a borrowing mode using its line-of-credit next winter.

On March 29, 2010, the Company renewed its line-of-credit agreement for Roanoke Gas Company. The new agreement maintained the same terms and rates as provided for under the expiring agreement. The interest rate is based on 30-day LIBOR plus 100 basis points and

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RGC RESOURCES, INC. AND SUBSIDIARIES

 

includes an availability fee of 15 basis points applied to the difference between the face amount of the note and the average outstanding balance during the period. The Company maintained the multi-tiered borrowing limits to accommodate seasonal borrowing demands and minimize the overall borrowing costs. Under the new agreement, the Company’s total available limits range from $1,000,000 to $13,000,000. The line-of-credit agreement will expire March 31, 2011, unless extended. The Company anticipates being able to extend or replace the line-of-credit upon expiration; however, there is no guarantee that the line-of-credit will be extended or replaced on comparable terms as those currently in place.

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

At June 30, 2010, the Company’s consolidated long-term capitalization, including current maturities of long-term debt, was 63% equity and 37% debt.

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RGC RESOURCES, INC. AND SUBSIDIARIES

 

ITEM 3 – QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not required.

ITEM 4 – CONTROLS AND PROCEDURES

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

As of June 30, 2010, the Company completed an evaluation, under the supervision and with the participation of management, including the chief executive officer and the chief financial officer (principal financial officer), of the effectiveness of the design and operation of the Company’s disclosure controls and procedures. Based upon that evaluation, the chief executive officer and chief financial officer concluded that the Company’s disclosure controls and procedures were effective at the reasonable assurance level as of June 30, 2010.

There were not any changes in the internal controls over financial reporting during the fiscal quarter ended June 30, 2010 likely to materially affect the Company’s internal controls over financial reporting.

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RGC RESOURCES, INC. AND SUBSIDIARIES

 

Part II – Other Information

ITEM 1 – LEGAL PROCEEDINGS

In July 2010, the Company received notice that it had been named as a defendant in two civil lawsuits associated with an explosion and fire at a West Virginia residence in November 2009. The suits, filed in the Circuit Court of Kanawha County, West Virginia on June 29, 2010, list Inergy, L.P., RGC Resources, Inc., Inergy Propane, LLC d/b/a Highland Propane Company and Otis Cornell as defendants. In the civil suit 10-C-1067, the plaintiffs are Kelly Wickline and Tiffany Williams. In the civil suit 10-C-1068, the plaintiffs are Terry Patterson, Tacy Patterson, Tera Patterson and Terry Patterson, Jr. The suits claimed that the fire was due to the ignition of propane within the residence. This residence was served by a propane tank installation at the time the assets of the Company’s propane subsidiary, Highland Propane, were sold to Inergy Propane, LLC (“Inergy”) in 2004. Inergy retained the name Highland Propane and assumed ownership and responsibility for all propane tanks including the tank located at the residence identified in the suits. No damage amounts are specified in the suits; however, both property damage and bodily injury are claimed in the suits. The Company has not recorded a liability for the lawsuit as management does not believe the likelihood of a negative outcome to the Company is probable nor is the amount of potential damages readily determinable. In addition, if the outcome of the lawsuits were adverse to the Company, management believes that any such damages would be covered by the Company’s insurance.

ITEM 1A – RISK FACTORS

Not required.

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

Pursuant to the RGC Resources Restricted Stock Plan for Outside Directors (the “Restricted Stock Plan”), 40% of the monthly retainer fee of each non-employee director of the Company is paid in shares of unregistered common stock and is subject to forfeiture and transferability restrictions (“restricted stock”). A participant can, subject to approval of Directors of the Company (the “Board”), elect to receive up to 100% of his or her retainer fee in restricted stock. The number of shares of restricted stock is calculated each month based on the closing sales price of the Company’s common stock on the NASDAQ-OMX on the first day of the month. The shares of restricted stock are issued in reliance on Section 3(a)(11) and Section 4(2) exemptions under the Securities Act of 1933 and will vest only in the case of the participant’s death, disability, retirement or in the event of a change in control of the Company. Shares of restricted stock will be forfeited to the Company upon (i) the participant’s voluntary resignation during his or her term on the Board or (ii) removal for cause. During the quarter ended June 30, 2010, the Company issued a total of 676 shares of restricted stock pursuant to the Restricted Stock Plan as follows:

 

Investment Date		Price			Number of Shares
4/1/2010		$	31.750		222
5/3/2010		$	31.750		222
6/1/2010		$	31.250		226

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RGC RESOURCES, INC. AND SUBSIDIARIES

 

ITEM 3 – DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4 – RESERVED

ITEM 5 – OTHER INFORMATION

None.

ITEM 6 – EXHIBITS

 

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

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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 13, 2010
				By:		/S/    HOWARD T. LYON
						Howard T. Lyon
						Vice-President, Treasurer and CFO
						(principal financial and principal accounting officer)