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 December 31, 2007
Commission File Number 000-26591
RGC Resources, Inc.
(Exact name of Registrant as Specified in its Charter)
(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 is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer” and “large accelerarted-filer” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ¨ Accelerated filer ¨ Non-accelerated filer 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 January 31, 2008
Common Stock, $5 Par Value
RGC RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
UNAUDITED
ASSETS
Current Assets:
Cash and cash equivalents
Accounts receivable - (less allowance for uncollectibles of $242,222 and $46,710, respectively)
Materials and supplies
Gas in storage
Assets available for sale
Prepaid income taxes
Deferred income taxes
Other
Total current assets
Utility Property:
In service
Accumulated depreciation and amortization
In service, net
Construction work in progress
Utility plant, net
Other Assets:
Note receivable
Total other assets
Total Assets
See notes to condensed consolidated financial statements.
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt
Borrowings under lines of credit
Dividends payable
Accounts payable
Customer credit balances
Income taxes payable
Customer deposits
Accrued expenses
Liabilities of assets available for sale
Over-recovery of gas costs
Fair value of marked to market transactions
Total current liabilities
Long-term Debt, Excluding Current Maturities
Deferred Credits and Other Liabilities:
Asset retirement obligations
Regulatory cost of retirement obligations
Benefit plan liabilities
Deferred investment tax credits
Total deferred credits and other liabilities
Stockholders’ Equity:
Common stock, $5 par value; authorized,10,000,000 shares; issued and outstanding2,194,048 and 2,186,143, respectively
Preferred stock, no par, authorized, 5,000,000shares; no shares issued and outstanding
Capital in excess of par value
Retained earnings
Accumulated other comprehensive loss
Total stockholders’ equity
Total Liabilities and Stockholders’ Equity
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
FOR THE THREE-MONTH PERIODS ENDED DECEMBER 31, 2007 AND 2006
Operating Revenues:
Gas utilities
Total operating revenues
Cost of Sales:
Total cost of sales
Gross Margin
Other Operating Expenses:
Operations
Maintenance
General taxes
Depreciation and amortization
Total other operating expenses
Operating Income
Other Income, net
Interest Expense
Income from Continuing Operations Before Income Taxes
Income Tax Expense from Continuing Operations
Income from Continuing Operations
Discontinued operations:
Income (loss) from discontinued operations, net of income taxesof ($14,628) and $108,882
Net Income
Other Comprehensive Loss, Net of taxes
Comprehensive Income
Basic Earnings Per Common Share:
Income from continuing operations
Discontinued operations
Net income
Diluted Earnings Per Common Share:
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE THREE-MONTH PERIODS
ENDED DECEMBER 31, 2007 AND 2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Adjustments to reconcile net income to net cash provided by operating activities:
Cost of removal of utility plant, net
Changes in assets and liabilities which used cash, exclusive of changes and noncash transactions shown separately
Net cash used in continuing operating activities
Net cash used in discontinued operations
Net cash used in operating activities
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant and nonutility property
Proceeds from sale of Bluefield Operations
Net cash provided by (used in) continuing investing activities
Net cash used in discontinued investing activities
Net cash provided by (used in) investing activities
CASH FLOWS FROM FINANCING ACTIVITIES:
Net borrowings under line-of-credit agreements
Proceeds from issuance of common stock
Cash dividends paid
Net cash provided by continuing financing activities
Net cash provided by discontinued financing activities
Net cash provided by financing activities
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
BEGINNING CASH AND CASH EQUIVALENTS
ENDING CASH AND CASH EQUIVALENTS
SUPPLEMENTAL INFORMATION:
Cash paid (received) during the year for:
Interest
Income taxes net of refunds
Noncash Transactions:
A note in the amount of $1,300,000 was received as partial payment for the sale of the assets associated with the Bluefield division of Roanoke Gas Company.
CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Bluefield and the Bluefield division of Roanoke Gas (“Bluefield Operations”) represent approximately 4,600 of Resources 61,200 customers. The results of operations of both Bluefield Gas and the Bluefield division of Roanoke Gas Company up to the effective date of the sale are reflected as discontinued operations.
The components of discontinued operations are summarized below:
Bluefield Gas
Total Revenues
Pretax Operating Income
Continuing Costs
Income Tax Expense
Discontinued Operations
The carrying amounts of the major classes of assets and liabilities subject to the purchase agreements as of September 30, 2007 are as follows:
Assets:
Accounts receivable, net
Other current assets
Net utility plant
Other assets
Liabilities:
Accounts payable and customer credit balances
Other current liabilities
Non current liabilities
Concurrent with the completion of the sale of the Bluefield Operations, the Company and ANGD executed a services agreement whereby Resources and Roanoke will provide certain customer billing, gas control, regulatory and other administrative services for Bluefield and Appalachian on mutually agreeable terms. The term of this agreement is expected to be of a short duration and the corresponding service fees will not be significant.
The Company has historically entered into futures, swaps and caps for the purpose of hedging the price of natural gas in order to provide price stability during the winter months. As of December 31, 2007, the Company had outstanding derivative collar arrangements for the purchase of natural gas. The fair value of these instruments is recorded in the balance sheet with the offsetting entry to overrecovery or underrecovery of gas costs. Net income and other comprehensive income are not affected by the change in market value as any prudently incurred cost or benefit received from these instruments is recoverable or refunded through the regulated natural gas purchased gas adjustment (“PGA”) mechanism.
The Company entered into an interest rate swap related to the $15,000,000 note issued in November 2005. The swap essentially converted the floating rate note based upon LIBOR into fixed rate debt with a 5.74 percent interest rate. The swap qualifies as a cash flow hedge with changes in fair value reported in other comprehensive income.
A summary of other comprehensive income including the effect financial instrument activity and SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, had on comprehensive income and accumulated comprehensive loss is provided below:
Unrealized losses
Income tax benefit
Net unrealized losses
Transfer of realized losses to income
Net transfer of realized losses to income
Net other comprehensive loss
Accumulated comprehensive loss
Transfer of realized gains to income
Income tax expense
Weighted average common shares
Effect of dilutive securities:
Options to purchase common stock
Diluted average common shares
Components of net periodic pension cost:
Service cost
Interest cost
Expected return on plan assets
Recognized loss
Net periodic pension cost
Components of post-retirement benefit cost:
Amortization of unrecognized transition obligation
Net periodic post-retirement benefit cost
The Company contributed $300,000 to its pension plan for the quarter ended December 31, 2007. The Company expects to make a total contribution of approximately $600,000 to its pension plan and $600,000 to its post-retirement benefit plan during the fiscal year ending September 30, 2008.
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. This statement defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value methods. This statement does not require any new fair value measurements. Instead, it provides for increased consistency and comparability in fair value measurements and for expanded disclosure surrounding the fair value measurements. This statement is effective for fiscal years beginning after November 15, 2007. The Company does not anticipate the adoption of this statement to have a material impact on its financial position, results of operations or cash flows.
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities. This statement permits, but does not require, entities to choose to measure selected financial assets and liabilities at fair value. Although SFAS No. 159 does not eliminate the fair value disclosure requirements included in other accounting standards, it does provide for additional presentation and disclosures designed to facilitate comparisons between companies that choose different measurement attributes for similar assets and liabilities. The effective date of this statement is for fiscal years beginning after November 15, 2007. The Company has not completed its evaluation of this statement, nor determined the potential effect on its financial position, results of operations or cash flows.
ITEM 2 - MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Forward-Looking Statements
From time to time, 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. 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 the following: (i) failure to earn on a consistent basis an adequate return on invested capital; (ii) ability to retain and attract professional and technical employees; (iii) the potential loss of large-volume industrial customers to alternate fuels, facility closings or production changes; (iv) volatility in the price and availability of natural gas; (v) uncertainty in the projected rate of growth of natural gas requirements 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 and/or colder weather; (ix) developments in electricity and natural gas deregulation and associated industry restructuring; (x) variations in winter heating degree-days from normal; (xi) changes in environmental requirements, pipeline operating requirements and cost of compliance; (xii) impact of potential increased regulatory oversight and compliance requirements due to financial, environmental, safety and system integrity laws and regulations; (xiii) failure to obtain timely rate relief for increasing operating or gas costs from regulatory authorities; (xiv) ability to raise debt or equity capital; (xv) impact of terrorism; (xvi) volatility in actuarially determined benefit costs; (xvii) impact of natural disasters on production and distribution facilities and the related effect on supply availability and price; and (xviii) new accounting standards issued by the Financial Accounting Standards Board, 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” or similar words or future or conditional verbs such as “will,” “would,” “should,” “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 earnings presented herein should not be considered as reflective of the Company’s consolidated financial results for the fiscal year ending September 30, 2008. The total revenues and margins realized during the first three months reflect higher billings due to the weather sensitive nature of the gas business. Improvement or decline in earnings depends primarily on weather conditions during the remaining winter months, energy costs 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 56,600 residential, commercial and industrial customers in Roanoke, Virginia and the surrounding areas through its Roanoke Gas Company (“Roanoke Gas”) subsidiary. Natural gas service is provided at rates and for the terms and conditions set forth by the State Corporation Commission (“SCC”).
Resources also provided regulated sale and distribution of natural gas to Bluefield, West Virginia, the Town of Bluefield, Virginia and surrounding areas through its Bluefield Gas Company (“Bluefield”) subsidiary and the Bluefield division of Roanoke Gas (collectively called “Bluefield Operations”). Effective as of October 31, 2007, Resources closed on the sale of the stock of Bluefield to ANGD, LLC and Roanoke Gas completed the sale of the assets of its Bluefield division to Appalachian Natural Gas Company (“Appalachian”), a subsidiary of ANGD, LLC. The Bluefield Operations represented approximately 8% of the customers of Resources. The corresponding activities of the Bluefield Operations up to the effective date of the sale have been classified as discontinued operations. See “Discontinued Operations” section below and Note 5 above for more information on these transactions.
Resources also provides certain unregulated natural gas related services through Roanoke Gas Company and information system services to software providers in the utility industry through RGC Ventures, Inc. of Virginia, which operates as Application Resources. Such operations represent less than 1% of total revenues and income of Resources.
Winter weather conditions and volatility in natural gas prices both have a direct influence on the quantity of natural gas sales to the Company’s customers and management believes each factor has the potential to significantly impact earnings. A majority of natural gas sales are for space heating during the winter season. Consequently, during warmer than normal winters, customers may significantly reduce their purchase of natural gas. Furthermore, significant increases in natural gas commodity prices could also affect customer usage through conservation or use of alternative fuels.
Because the SCC authorizes billing rates for the natural gas operations based upon normal weather, warmer than normal weather may result in the Company failing to earn its authorized rate of return. The Company has been able to mitigate a portion of the risk associated with warmer than normal winter weather by the inclusion of a weather normalization adjustment (“WNA”) factor as part of its rate structure, which allows the Company to recover revenues equivalent to the margin that would be realized at approximately 6 percent warmer than the 30-year normal. The Company recorded approximately $315,000 in additional revenues to reflect the estimated impact of the WNA for the difference in margin realized for weather between 14% and 6% warmer than the 30-year average. The final surcharge or refund to customers will be dependent on the weather during the second quarter. Accordingly, the accrued revenues related to the WNA may be adjusted up or down from the amount included in the December 31, 2007 financial statements. The Company accrued approximately $313,000 in additional revenues during the quarter ended December 31, 2006 as the number of heating degree days were approximately 16% fewer than the 30-year average.
Management also has concerns regarding the volatility of natural gas prices and the potential for reduced sales in response to increasing prices. Rising natural gas prices may influence the level of sales due to conservation efforts by customers or may result in customers switching to an alternative fuel. In addition, increasing prices may lead to a higher level of bad debts due to customers’ inability to afford the higher prices. Minimal hurricane activity during 2007, a warmer than normal early fall season and adequate storage supplies have contributed to stable natural gas prices; however, extended periods of colder than normal weather or supply disruptions could result in increasing natural gas commodity prices. The Company has an approved rate structure in place that mitigates the impact of financing costs of inventory related to rising natural gas prices. Under this rate structure, Roanoke Gas accrues revenue to cover the financing costs or “carrying costs” related to the level of investment in natural gas inventory. 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 the financing costs would be less. The Company recognized approximately $629,000 and $603,000 in carrying cost revenues for the three months ended December 31, 2007 and 2006, respectively.
Results of Operations
Consolidated net income (loss) from continuing and discontinued operations is as follows:
Continuing Operations
The table below reflects volume activity and heating degree-days.
Delivered Volumes
Regulated Natural Gas (DTH)
Tariff Sales
Transportation
Total
Heating Degree Days
(Unofficial)
The table below reflects operating revenues.
Operating Revenues
Gas Utilities
Total Operating Revenues
Total operating revenues from continuing operations for the three months ended December 31, 2007 compared to the same period last year decreased due to reductions in sales volumes associated with 5% fewer heating degree-days during the period. Natural gas commodity prices remained consistent with last year’s prices, as both periods were much warmer than the 30-year normal. Other revenues declined due to the composition of services provided under the Company’s unregulated operations.
Total Operating Margin
Regulated natural gas margins from gas utilities increased slightly over the same period last year as reductions in sales volumes were more than offset by the implementation of a non-gas cost rate increase. The decline in tariff sales (consisting primarily of residential and commercial volumes) corresponded to the reduction in heating degree-days. The decline in transportation volumes related to reduced production activity for certain larger industrial customers. The Company placed increased rates into effect during the first quarter. These rates were placed into effect subject to refund pending a final order from the SCC. As a result of the higher rates, the Company realized approximately $100,000 in additional margin from customer base charges, which is a flat monthly fee billed to each natural gas customer. The total volumetric margin declined by approximately $31,000 as the effect of the rate increase only partially offset the effect of lower sales volumes. Carrying cost revenues, as explained below, increased by approximately $26,000 due to higher average investment in natural gas storage during the period. The components of the gas utility margin increase are summarized below:
Net Margin Increase
Customer Base Charge including rate increase
WNA
Carrying Cost
Volumetric (rate and volume)
Other margins increased over last year primarily due to the composition of services related to temporary work performed in the unregulated operations of Roanoke Gas.
Operations expenses decreased by $84,454, or 3%, compared to the same period last year. Reductions in bad debt expense, operations labor and contractor expenses combined with higher capitalized overheads accounted for most of the decline. Improvement in customer accounts receivable aged balances and a greater level of customer deposits have helped to reduce bad debt expense by approximately $43,000. Increased level of capital expenditures due to the focus on distribution system renewal projects have reduced operations labor and contractor expenses and increased the level of overheads capitalized by approximately $40,000. Maintenance expenses increased $44,210, or 14%, over the same period last year. The increase in maintenance primarily relates to timing of repairs of pipeline leaks in the Company’s distribution system determined through leak surveys completed in the prior fiscal year.
General taxes increased by $24,505, or 9%, due to higher payroll and property taxes. Depreciation expense increased $59,784, or 6%, on a corresponding increase in utility plant associated with extending service to new customers and replacing cast iron and bare steel pipe. Other income, net increased by $43,414 due to a higher level of investment earnings attributable to the net proceeds and note received from the sale of the Bluefield Operations.
Interest expense increased by $39,012, or 7%, primarily due to higher average debt outstanding from continuing operations during the current quarter compared to the same period last year. Reductions in the effective average interest rate from 5.8% to 5.4% on the Company’s line-of-credit arrangements partially offset the increase attributable to the higher average debt. The current economic environment combined with the Federal Reserves efforts to stimulate the economy should result in lower interest rates on the Company’s line-of-credit arrangements during the second quarter and possibly longer.
Income tax expense increased by $31,397, which corresponds to the increase in pre-tax income of continuing operations for the quarter.
As discussed above in Note 5 of the financial statements, effective as of October 31, 2007, Resources closed on the sale of the stock of Bluefield Gas Company to ANGD, LLC, and Roanoke Gas Company completed the sale of its natural gas distribution assets located in the Town of Bluefield and the County of Tazewell, Virginia (“Bluefield division of Roanoke Gas”) to Appalachian Natural Gas Company (“Appalachian”), a subsidiary of ANGD, LLC. Bluefield and the Bluefield division of Roanoke Gas (“Bluefield Operations”) represented approximately 4,600 of Resources 61,200 customers. The results of operations of both Bluefield Gas and the Bluefield division of Roanoke Gas Company up to the effective date of the sale are reflected as discontinued operations.
The Bluefield Operations absorbed approximately $773,000 and $732,000 in fiscal 2007 and 2006, respectively, in costs allocated from Resources and Roanoke Gas that have continued after the sale. The Company expected to recover a portion of these costs through a services agreement with ANGD and through current and future non-gas cost rate filings. The Company also expects to reduce a portion of the costs through normal staff attrition. Based on current estimates, revenue from the services agreement will not be as much as originally projected as ANGD is expected to exercise its option to terminate or significantly reduce the services under the agreement earlier than originally anticipated. The new non-gas cost rate increase placed into effect in November, subject to refund, includes these retained costs net of the original estimates of revenues from the services agreement. The ultimate determination of the rate award to recover these costs will not be known until the final order is received later this year. Future non-gas rate filings are expected to include a return on equity from the infusion of the net proceeds received from the sale of Bluefield stock.
Critical Accounting Policies
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 judgments 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 could differ from the estimates, which would affect the related amounts reported in the Company’s financial statements. The following policies and estimates are important to understanding certain key components of the financial statements.
Regulatory accounting – The Company’s regulated operations follow the accounting and reporting requirements of Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation. 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 a nonregulated enterprise. When this results, 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 the 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 any portion of the current regulated operations ceases to meet the criteria for application of the provisions of SFAS No. 71, the Company would remove the corresponding regulatory assets or liabilities from the consolidated balance sheets and reflect them within the consolidated statement of income for the period in which the discontinuance occurred.
Revenue recognition –Regulated utility sales and transportation revenues are based upon 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 approval from the SCC. Roanoke also utilizes a WNA, which is designed to partially offset the impact of weather that is either more than approximately 6 percent warmer than normal or approximately 6 percent colder than normal over a 12 month period. The calculation of the WNA requires the use of estimates. Without the WNA, the Company’s operating revenues and gross margins would have been reduced by approximately $315,000 and $313,000 for the three-month periods ended December 31, 2007 and 2006, respectively.
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 and current and historical data. The financial statements included unbilled revenues of $6,290,944 and $5,095,664 at December 31, 2007 and 2006, respectively. Roanoke also accrues a provision for rate refund during periods in which it has implemented new billing rates pending the results of a final review and hearing on the increases by the SCC. The Company’s estimated refund provision is based upon historical experience, discussions with the SCC and other relevant factors.
Bad debt reserves – 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.
Retirement plans – 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 determined through actuarial means requiring the use of estimates and assumptions. In regard to the pension plan, these factors include assumptions regarding discount rate, expected long-term rate of return on plan assets, compensation increases and life expectancies, among others. Similarly, the postretirement plan also requires the estimation of many of the same factors as the pension plan in addition to assumptions regarding 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.
Derivatives – As discussed in the “Item 3 - Qualitative and Quantitative Disclosures about Market Risk” section below, the Company may hedge certain risks incurred in the normal operation of business through the use of derivative instruments. The Company applies the requirements of Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, which requires the recognition of all derivative instruments as assets or liabilities in the Company’s balance sheet at fair value. In most instances, fair value is based upon quoted futures prices for the 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. In October 2007, Roanoke Gas executed a new 3-year agreement with a new asset manager to provide these services under substantially the same terms.
Energy Costs
A combination of a mild hurricane season, strong natural gas storage levels and a warm fall season have resulted in natural gas commodity prices remaining stable and consistent with last year’s prices. Natural gas futures as of December 31, 2007 indicated likely continued price stability in the near term.
Energy costs represent the single largest expense of the Company. To help mitigate the impact of potential price volatility, the Company uses various hedging mechanisms, including summer storage injections and financial instruments. Prudently incurred natural gas costs are fully recoverable under the present regulatory Purchased Gas Adjustment (“PGA”) mechanisms, and increases and decreases in the cost of gas are passed through to the Company’s customers. Although rising energy prices are recoverable through the PGA mechanism, high energy prices may have a negative impact on earnings through increases in bad debt expense and higher interest costs because the delay in recovering higher gas costs requires borrowing to temporarily fund receivables from customers. The Company’s rate structure provides a level of protection against the impact that rising energy prices may have on bad debts and carrying costs of gas in storage by allowing for more timely recovery of these costs. However, the rate structure will not protect the Company from increased rate of bad debts or increases in interest rates.
Regulatory Affairs
On September 17, 2007, Roanoke filed an application with the Virginia SCC for an expedited increase in non-gas rates to provide approximately $700,000 in additional revenues. The requested rates were placed into effect on November 1, 2007 subject to refund for any differences between the implemented rates and the final rates approved by the SCC. An SCC rate order is expected in the late spring of 2008.
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 and the seasonal funding of its natural gas inventories and accounts receivable. The Company’s construction program is composed of 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. Total capital expenditures from continuing operations were $1,645,376 and $1,711,212 for the three-month periods ended December 31, 2007 and 2006, respectively. Roanoke Gas’ total capital budget for the current year is more than $6,200,000. It is anticipated that future capital expenditures will be funded with the combination of operating cash flow, sale of Company equity securities through the Dividend Reinvestment and Stock Purchase Plan and issuance of debt.
The level of borrowing under the Company’s line-of-credit agreements can fluctuate significantly due to the time of the year, changes in the wholesale price of energy and weather outside the normal temperature ranges. As the wholesale price of natural gas increases, short-term debt generally increases because the payment to the Company’s energy suppliers is due before the Company can recover its costs through the monthly billing of its customers. In addition, colder weather requires the Company to purchase greater volumes of natural gas, the cost of which is recovered from customers on a delayed basis.
At December 31, 2007, the Company had available lines-of-credit for its short-term borrowing needs totaling $21,000,000, of which $8,112,000 was outstanding. The interest rates under the lines-of-credit are variable based upon 30 day LIBOR. These lines-of-credit expire March 31, 2008, unless extended. The Company anticipates being able to extend or replace the lines-of-credit upon expiration.
In July 2008, Roanoke Gas’ $5,000,000 first mortgage notes mature. Management anticipates being able to obtain new financing on terms acceptable to the Company to meet the cash requirements of the maturing note.
As discussed above, the Company and Roanoke Gas closed on the sale of the Bluefield Operations effective as of October 31, 2007. On the date of closing the Company received payment of $9,000,000 and a subordinated note of $1,300,000 based on estimated values as of October 31, 2007. After payoff of Bluefield’s outstanding debt at the date of closing and payment of the estimated income taxes associated with the taxable gain on sale of the stock of Bluefield Gas, the Company’s cash resources increased by approximately $3,300,000. The Company will use the net proceeds to reduce the corporate borrowing requirements under its line-of-credit agreements and to infuse capital in Roanoke Gas to help fund its construction and pipeline renewal programs.
Stockholders equity increased by $701,873 for the three months ended December 31, 2007, primarily due to earnings and proceeds from stock issued under the Dividend Reinvestment and Stock Purchase Plan (“DRIP”). The activity is summarized below:
Dividends
DRIP
Restricted stock and stock options
Net comprehensive loss
Increase in stockholders’ equity
At December 31, 2007, the Company’s consolidated long-term capitalization was 61 percent equity and 39 percent debt.
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 December 31, 2007, the Company had $8,112,000 outstanding under its lines of credit at an interest rate of 5.10%. A hypothetical 100 basis point increase in market interest rates applicable to the Company’s average variable rate debt outstanding would have resulted in an increase in the 3-month interest expense from of approximately $15,000. The Company also has a $15,000,000 intermediate term variable rate note that is currently being hedged by a fixed rate interest swap. The 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 fixed price contracts, gas storage injections and derivative commodity instruments including futures, price caps, swaps and collars. During the quarter, the Company used both storage gas and derivative collar arrangements for the purpose of hedging the price of natural gas. Any cost incurred or benefit received from the derivative arrangements is recoverable or refunded through the regulated natural gas purchased gas adjustment (PGA) mechanism. The SCC currently allows for full recovery of prudent costs associated with natural gas purchases, and any additional costs or benefits associated with the settlement of the derivative contracts will be passed through to customers when realized. As of December 31, 2007, a hypothetical 10% reduction in the market price of natural gas would result in an increase of approximately $362,800 in the balance sheet liability on the Company’s financial statements.
ITEM 4T – CONTROLS AND PROCEDURES
Based on their evaluation of the Company’s disclosure controls and procedures (as defined by Rule 13a-15(e) under the Securities Exchange Act of 1934) as of December 31, 2007, the Company’s Chief Executive Officer and principal financial officer have concluded that these disclosure controls and procedures are effective. Management routinely reviews the Company’s internal controls over financial reporting and from time to time makes changes intended to enhance the effectiveness of internal controls over financial reporting. There has been no change during the quarter ended December 31, 2007, in the Company’s internal control over financial reporting or in other factors that has materially affected, or is reasonably likely to materially affect, this internal control over financial reporting.
Part II – Other Information
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 vesting 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 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-NMS 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 (the “Act”) 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 term on the Board or (ii) removal for cause. During the quarter ended December 31, 2007, the Company issued a total of 802 shares of restricted stock pursuant to the Restricted Stock Plan as follows:
Investment Date
10/1/2007
11/1/2007
12/3/2007
ITEM 6 – EXHIBITS
Number
Description
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.