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 Quarter Ended December 31, 2005
Commission File Number 000-26591
RGC Resources, Inc.
(Exact name of Registrant as Specified in its Charter)
(State or Other Jurisdiction of
Incorporation or Organization)
(I.R.S. Employer
Identification No.)
(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 close of the period covered by this report.
Class
Outstanding at December 31, 2005
RGC RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
Current Assets:
Cash and cash equivalents
Accounts receivable - (less allowance for uncollectibles of $519,672 and and $284,008, respectively)
Materials and supplies
Gas in storage
Prepaid income taxes
Deferred income taxes
Under-recovery of gas costs
Fair value of marked-to-market transactions
Other
Total current assets
Utility Property:
In service
Accumulated depreciation and amortization
In service, net
Construction work in progress
Utility Plant, Net
Nonutility Property:
Nonutility property
Nonutility property, net
Other assets
Total Assets
See notes to condensed consolidated financial statements.
UNAUDITED
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Borrowings under lines of credit
Dividends payable
Accounts payable
Customer deposits
Accrued expenses
Refunds from suppliers - due customers
Fair value of marked to market transactions
Total current liabilities
Long-term Debt, Excluding Current Maturities
Deferred Credits and Other Liabilities:
Asset retirement obligations
Deferred investment tax credits
Total deferred credits and other liabilities
Stockholders’ Equity:
Common stock, $5 par value; authorized, 10,000,000 shares; issued and outstanding 2,106,741 and 2,098,935 shares, respectively
Preferred stock, no par, authorized, 5,000,000 shares; 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, 2005 AND 2004
Operating Revenues:
Gas utilities
Energy marketing
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 Expenses (Income), net
Interest Expense
Income from Continuing Operations Before Income Taxes
Income Tax Expense from Continuing Operations
Income from Continuing Operations
Discontinued operations:
Income from discontinued operations, net of income taxes of $5,013
Net Income
Basic Earnings Per Common Share:
Income from continuing operations
Discontinued operations
Net income
Diluted Earnings Per Common Share:
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Reclassification of loss transferred to net income
Minimum pension liability
Unrealized (loss) gain on cash flow hedges
Other comprehensive income (loss), net of tax
Comprehensive Income
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE THREE-MONTH PERIODS
ENDED DECEMBER 31, 2005 AND 2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income from continuing operations
Adjustments to reconcile net earnings 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 provided by discontinued operations
Net cash used in operating activities
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant and nonutility property
Proceeds from disposal of utility and nonutility property
Net cash used in investing activities
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt
Retirement of long-term debt and capital leases
Net borrowings under line-of-credit agreements
Proceeds from issuance of common stock
Cash dividends paid
Net cash provided by (used in) financing activities
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
CASH AND CASH EQUIVALENTS AT END OF YEAR
SUPPLEMENTAL INFORMATION:
Cash paid (received) during the year for:
Interest
Income taxes net of refunds
6
CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS UNAUDITED
up to $20,000,000 through February 15, 2006 and $16,000,000 through March 31, 2006. The increase in the line-of-credit was requested by the Company to meet short-term funding needs associated with higher gas costs. The total available limits under all lines-of-credit agreements for the remaining term are $30,000,000. The line-of-credit agreements will expire March 31, 2006, unless extended. The Company anticipates being able to extend or replace the credit lines upon expiration.
Concurrent with the sale of assets, the Company entered into an agreement with Acquiror by which the Company would continue to provide the use of office, warehouse and storage space, and computer systems and office equipment and the utilization of Company personnel for billing, propane delivery and related services for the term of one year with an option for an additional year. This agreement expired in July 2005 with the exception of a one-year lease agreement for access to the storage yard in Bluefield, West Virginia.
The asset purchase agreement did not include land and buildings owned by Diversified. Acquiror leased 10 parcels of real estate consisting of bulk storage facilities and office space from Diversified with an option to purchase such parcels. Prior to the end of June 2005, the Acquiror executed the option to purchase the real estate and closed on all 10 parcels. The operations associated with the real estate for the quarter ended December 31, 2004 were reclassified as Discontinued Operations in accordance with the provisions of SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets.
Three Months EndedDecember 31,
2004
Discontinued Operations:
Pretax Operating Income
Income Tax Expense
Discontinued Operations
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. During the quarter ended December 31, 2005, the Company entered into swap and price cap 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 cost incurred or benefit received from these instruments is recoverable or refunded through the regulated natural gas purchased gas adjustment (PGA) mechanism. Both the Virginia State Corporation Commission (SCC) and the West Virginia Public Service Commission (PSC) currently allow for full recovery of prudent costs associated with natural gas purchases, and any additional costs or benefits associated with the settlement of these instruments will be passed through to customers when realized.
The Company also 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 and derivative activity is provided below:
Three Months Ended December 31, 2005
Unrealized (losses) gains
Income tax benefit (expense)
Net unrealized (losses) gains
Transfer of realized losses to income
Income tax benefit
Net transfer of realized losses to income
Net other comprehensive (loss) income
Unrealized (loss) gain on marked to market transactions
Accumulated comprehensive loss
Three Months Ended December 31, 2004
Unrealized gains
Income tax expense
Net unrealized gains
Net other comprehensive income
Unrealized loss on marked to market transactions
Weighted average common shares
Effect of dilutive securities:
Options to purchase common stock
Diluted average common shares
For the Three Months Ended December 31, 2005
Operating revenues
Gross margin
Operations, maintenance and general taxes
Operating income
Other (income) expenses, net
Interest expense
Income before income taxes
As of December 31, 2005
Total assets
Gross additions to long-lived assets
For the Three Months Ended December 31, 2004
As of December 31, 2004
reflected in net income as all options granted under the Plan had an exercise price equal to the market value of the underlying common stock on the date of the grant. On October 1, 2005, the Company adopted SFAS No. 123R, Share-Based Payment, a revision of SFAS No. 123, Accounting for Stock-Based Compensation. This statement eliminates the alternative to use APB’s Opinion No. 25 intrinsic value method of accounting that was previously allowed under Statement 123. SFAS No. 123R requires entities to recognize the cost of employee services received in exchange for awards of equity instruments on the grant-date fair value of those awards. The Company has adopted the provisions of this statement using the modified prospective application. Under the modified prospective application, only new grants and grants that have been modified, cancelled or have not yet vested as of the effective date of the statement require the recognition of compensation cost. All awards granted and vested prior to the effective date remain under the provisions of APB Opinion No. 25, Accounting for Stock Issued to Employees. No options have been granted under the Plan during the current and prior fiscal year and all outstanding options are fully vested at December 31, 2005. As of December 31, 2005, 2,000 options were available for grant under the Plan.
Components of net periodic pension cost:
Service cost
Interest cost
Expected return on plan assets
Recognized loss
Net periodic pension cost
Components of net periodic benefit costs:
Amortization of unrecognized transition obligation
Net periodic benefit cost
The Company contributed $350,000 to its pension plan for the quarter ended December 31, 2005. The Company expects to make a total contribution of approximately $800,000 to its pension plan and $700,000 to its postretirement benefit plan during the fiscal year ending September 30, 2006.
and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003, the Company elected to defer accounting for the effects of the Medicare Act and the accounting for certain provisions of the Medicare Act. In May 2004, the FASB issued definitive accounting guidance for the Medicare Act in FASB Staff Position (“FSP”) 106-2. The Company elected the prospective method of recording the effects of this FSP; therefore, it was effective for the Company in the fourth quarter of fiscal 2004. FSP 106-2 results in the recognition of lower other postretirement employment benefit costs to reflect prescription drug-related federal subsidies to be received under the Medicare Act.
Subsequent to September 30, 2005, the Company has further evaluated its options as it relates to the application of Medicare Part D. Beginning in January 2006, the Company has dropped drug coverage under its medical plan for Medicare eligible retirees. In its place, the Company will provide eligible retirees with a reimbursement of premiums paid to a qualified prescription drug provider (“PDP”) whereby the PDP will provide the retiree with prescription drug coverage. Under the PDP, retirees have the ability to obtain drug coverage comparable to the coverage previously provided under the medical plan. This plan change will result in the Company’s medical plan not being actuarially equivalent to Medicare Part D. However, the change in the plan is not expected to have a material impact on the accumulated postretirement benefit obligation and future expense due to the expected cost reductions under the revised plan as compared to the reductions attributable to the subsidy provisions available to actuarially equivalent plans.
In March 2005, the FASB issued FASB Interpretation (“FIN”) No. 47, Accounting for Conditional Asset Retirement Obligations – an Interpretation of FASB Statement No. 143. Diverse accounting practices had developed with respect to the timing of liability recognition of legal obligations associated with the retirement of a tangible long-lived asset when the timing and/or method of settlement of the obligation is conditional on a future event. FIN No. 47 provided clarification when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. This interpretation is effective for the Company September 30, 2006. The Company has not completed its evaluation of this interpretation and has not yet determined the impact on the Company’s financial position or results of operations.
ITEM 2 - MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Forward-Looking Statements
From time to time, 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) increasing expenses and labor costs and labor availability; (iii) price competition from alternative fuels; (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 governmental oversight and compliance costs due to the Sarbanes-Oxley law; (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 uncertainties in the Middle East and related terrorism issues; and (xvi) 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” 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. We assume no duty to update these statements should expectations change or actual results differ from current expectations.
General
RGC Resources, Inc. (“Resources” or the “Company”) is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately 60,800 residential, commercial and industrial customers in Roanoke, Virginia and Bluefield, Virginia and West Virginia and the surrounding areas through its Roanoke Gas Company and Bluefield Gas
Company subsidiaries. Natural gas service is provided at rates and for the terms and conditions set forth by the State Corporation Commission (SCC) in Virginia and the Public Service Commission (PSC) in West Virginia.
Resources also provides unregulated energy products through Diversified Energy Company, which operates as Highland Energy Company. Highland Energy brokers natural gas to certain industrial transportation customers of Roanoke Gas Company and Bluefield Gas Company. In addition to an energy marketing company, Diversified Energy Company operated an unregulated propane operation under the name of Highland Propane Company. In July 2004, Resources sold the propane operations.
Resources also provides information system services to software providers in the utility industry through RGC Ventures, Inc. of Virginia, which operates as Application Resources.
Management views warm winter weather; energy conservation, fuel switching and bad debts due to high energy prices; and competition from alternative fuels each as factors that could have a significant impact on the Company’s earnings.
For the quarter ended December 31, 2005, the combination of high energy prices and warmer weather continued to be the primary concern of management, as both factors impact energy consumption. The high energy prices appear to be affecting natural gas consumption by industrial customers. Both volumes delivered under transportation agreements and Highland Energy have declined from last year in part due to energy prices. The high natural gas prices do not appear to have had a noticeable affect on residential and commercial sales volumes thus far.
Because the respective regulatory commissions in Virginia and West Virginia authorize billing rates for each of 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. For the quarter ended December 31, 2005, heating degree-days (an industry measure by which the average daily temperature falls below 65 degrees Fahrenheit) were 9 percent more than the same period last year but 5 percent lower than the 30-year normal.
The Company’s financial risk exposure to significantly warmer winter weather is partially mitigated by the provisions of a weather normalization adjustment factor (“WNA”) for Roanoke Gas Company based on a weather occurrence band around the most recent 30-year temperature average. The weather band provides approximately a 6 percent range around normal weather, whereby if the number of heating-degree days fall within approximately 6 percent above or below the 30-year average, no adjustments are made. However, if the number of heating degree-days is more than 6 percent below the 30-year average, the Company would add a surcharge to customer bills equal to the equivalent margin lost below the approximate 6 percent deficiency. Likewise, if the number of heating degree-days is more than 6 percent above the 30-year average, the Company would credit customer bills equal to the excess margin realized above the 6 percent heating degree-days. The measurement period in determining the weather band extends from April through March with any adjustment to be made to customer bills in late
spring. As of December 31, 2005, heating degree-days for the period April 2005 through December 2005 were approximately 6 percent less than the 30-year average. As the number of heating-degree days fell within the 6 percent weather band for the previous nine months, the Company has not recorded any additional revenues attributable to the WNA during the current period. In December 2004, the Company recorded approximately $350,000 in additional revenues to reflect the estimated impact of the WNA for the difference in margin realized for weather between 18 percent and 6 percent warmer than the 30-year average. Any impact to the customer and the Company either through a surcharge or credit to customer bills will be dependent upon the weather during the next quarter.
Results of Operations
Consolidated net income for the three-month period ended December 31, 2005 was $1,452,182 compared to $1,625,395 for the same period last year. Net income from continuing and discontinued operations is as follows:
Continuing Operations
The table below reflects volume activity and heating degree-days.
Increase/
(Decrease)
Delivered Volumes
Regulated Natural Gas (DTH)
Tariff Sales
Transportation
Total
Highland Energy (DTH)
Heating Degree Days (Unofficial)
The table below reflects operating revenues.
Percentage
Operating Revenues
Gas Utilities
Energy Marketing
Total Operating Revenues
Total operating revenues from continuing operations for the three months ended December 31, 2005 increased by $18,111,647, or 52 percent, compared to the same period last year, primarily due to higher gas costs, colder weather and implementation of base rate increases. The total average unit cost of natural gas increased by 55 percent. Total regulated natural gas delivered volumes increased by 2 percent, while energy marketing sales volumes declined by 9 percent. The total number of heating degree-days increased by 9 percent over the same period last year. Other revenues decreased by 28 percent due to the elimination of the services agreement with the Acquiror of Highland Propane Company to provide billing, facility and other services.
Total Gross Margin
Total gross margin increased by $565,347, or 8 percent, for the quarter ended December 31, 2005 over the same period last year. Regulated natural gas margins increased by $636,839, or 9 percent, as total delivered volume (tariff and transporting) increased by 69,000 decatherms, or 2 percent. Tariff sales, primarily consisting of residential and commercial usage reflected an increase of 6 percent due to the 9 percent increase in heating degree-days over the same period last year. Transporting volumes, which generally correlate more with economic conditions rather than weather, reflected a reduction of 9 percent from the same period last year. This reduction in transporting volumes appears to be related to a combination of price sensitivity and other economic factors. One industrial customer has converted a portion of its processes to utilize coal as a means to reduce energy costs. A few customers temporarily reduced natural gas consumption by using backup supplies of heating oil and propane. In addition, one customer ceased operations.
The Company realized an increase in regulated natural gas margins due to non-gas cost rate increases and the recovery of the financing costs (“carrying costs”) related to higher dollar investments in storage gas inventories. Both Roanoke Gas Company and Bluefield Gas Company placed increased rates into effect during the quarter ended December 31, 2005. Roanoke Gas Company’s rates were placed into effect subject to refund pending a final order from the Virginia SCC. Bluefield Gas Company’s rates were placed into effect in accordance with a final rate order issued by the West Virginia PSC. As a result of the rate increases, the Company realized approximately $123,000 in additional customer base charges, which is a flat monthly fee billed to each natural gas customer, and approximately $150,000 associated with increase in the volumetric price of natural gas. Carrying cost revenues increased by approximately $158,000 due to a much higher level of investment in storage gas inventory compared to the same period last year due to higher prices.
Beginning in April 2003, the SCC approved a rate structure that would allow Roanoke Gas Company to recover financing costs related to the level of investment in inventory and prepaid gas service. Therefore, during times of rising gas costs, Roanoke Gas would be able to recognize a greater level of revenues to offset the higher financing costs; conversely, Roanoke Gas will pass along savings to customers if financing costs decrease due to lower inventory gas balances resulting from reductions in gas costs. During the quarter ended December 31, 2004, Bluefield Gas Company implemented a similar rate structure as part of its new rates. The net effect of increased storage gas levels and the implementation of the carrying cost revenue component for Bluefield Gas resulted in the approximately $158,000 increase in revenues and margin. During periods of declining gas costs and storage gas levels, the Company would experience a reduction in revenues and margins as well.
Energy marketing margins decreased by $78,319 as total sales volume decreased by 66,536 decatherms, or 9 percent, compared to the same period last year. The reduction in the energy marketing volumes corresponds to the reductions experienced in transportation volumes under the regulated operations. The decline in margin was attributable to the sale of a natural gas strip for $143,000 profit in October 2004. The natural gas strip (a commitment to purchase volumes in the future for a fixed price) was not needed to meet the needs of Highland Energy’s customers; therefore, the Company was able to take advantage of market conditions at the time and realize a gain on the transaction. This was a non-recurring transaction and is not expected to be replicated in the future. Excluding the profit on the sale of the decatherm strip last year, energy marketing margins reflected an increase of $64,681 attributable to our increasing the margin spread to offset the greater risks associated with much higher energy prices. Other margins are comparable to last year.
Operations expenses increased by $482,082, or 20 percent, for the three-month period ended December 31, 2005 compared to the same period last year. The increase is primarily due to higher bad debt expense and employee benefit costs. Gross bad debt expense increased by approximately $125,000, or 74 percent. This increase related to the 52 percent increase in total revenue over the same period last year. In addition, the significant increase in gas costs is
expected to result in a more than proportionate increase in customer delinquencies and bad debts. Employee benefit costs increased due to higher health care, pension and postretirement benefit expenses. The Company had been self-insured for medical insurance purposes for the past several years with stop/loss coverage only for extremely high claim activity. The self-insurance program generated volatility in expense due to fluctuating claim levels. During the quarter ended December 31, 2004, claims expense was unusually low. Beginning in January 2005, the Company switched to fully insured coverage to provide a more predictable expense trend, which will reduce volatility between reporting periods but resulted in approximately $165,000 in higher costs. The Company also experienced an increase of approximately $125,000 attributable to its pension and postretirement medical plan due to the actuarial effect of reducing the discount rate used in expense and liability calculations as well as the adoption of new mortality tables in its most recent valuation. Maintenance expenses increased $69,668, or 22 percent, over the same period last year. The increase in maintenance primarily related to timing of repairs of pipeline leaks in the Company’s distribution system determined through leak surveys.
General taxes increased $73,071, or 19 percent, for the three-month period ended December 31, 2005 compared to the same period last year primarily due to increased business and occupation (B&O) taxes, a revenue sensitive tax, related to higher revenues in the West Virginia natural gas operations, as well as a greater level of payroll and property taxes.
Net other expense (income) increased by $39,227 due to reduction in investment earnings realized during the prior fiscal year on the proceeds from the sale of Highland Propane prior to the payment of the special dividend on December 8, 2004. The Company paid a one-time special dividend of $4.50 per share to distribute the gain realized on the sale of Highland Propane.
Interest expense increased by $124,069, or 23 percent, as the Federal Reserve’s monetary policy has led to increasing interest rates on the Company’s variable rate debt combined with $1,700,000 increase in the Company’s average total outstanding debt. The effective average interest rate on the Company’s outstanding lines-of-credit balances increased from 2.7 percent last year to 4.8 percent for the current period.
Income tax expense decreased by $103,204, which corresponds to the decrease in pre-tax income on continuing operations for the quarter. The effective tax rate for the quarter was 38.2 percent.
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, 2006. 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.
On July 12, 2004, Resources sold the propane assets of its subsidiary, Diversified Energy Company, d/b/a Highland Propane Company (“Diversified”), for approximately $28,500,000 in cash to Inergy Propane, LLC (“Acquiror”). The sale of assets encompassed all propane plant assets (with the exception of a limited number of specific assets being retained by Diversified), the name “Highland Propane,” customer accounts receivable, propane gas inventory and inventory of propane related materials. The Company realized a gain of approximately $9,500,000 on the sale of assets, net of income taxes.
Critical Accounting Policies
The consolidated financial statements of RGC Resources, Inc. 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.
Revenue recognition –Regulated utility sales and transportation revenues are based upon rates approved by the SCC for Roanoke Gas Company and the PSC for Bluefield Gas Company. The non-gas cost component of rates may not be changed without a formal rate increase application and corresponding authorization by the appropriate regulatory commission; however, the gas cost component of rates may be adjusted periodically through the PGA mechanism with approval from the respective commission. Roanoke Gas Company also has a WNA, which is designed to
partially offset the impact of weather that is either more than 6 percent warmer than normal or 6 percent colder than normal over a 12 month period. Under the Company’s unregulated energy marketing operations, revenues are recognized when the natural gas is delivered based on the contracted or market price.
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, current and historical data. As of December 31, 2005, the financial statements included unbilled revenue of $10,082,333. The Company also accrues a provision for rate refund during periods in which the Company has implemented new billing rates pending the results of a final review and hearing on the increases by the corresponding state regulatory body. The Company’s estimated refund provision is based upon historical experience, discussions with the regulatory body 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 plan (“postretirement plan”) to eligible employees. The expenses and liabilities associated with these plans are determined through actuarial means requiring the estimation of certain assumptions and factors. 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 medical plan also requires the estimation of many of the same factors as the pension plan in addition to assumptions regarding future medical costs 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 to name a few. 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 hedges 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.
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 an unregulated 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).
Asset Management
Effective November 1, 2004, Roanoke Gas Company and Bluefield Gas Company (the Companies) each entered into a new asset management agreement with a third party. Each contract is a three-year agreement with terms similar to the agreements that expired in October 2004 whereby the third party has assumed the management of the Companies’ firm transportation and storage agreements. The new contracts call for the Companies to retain ownership of their storage gas rather than having the asset manager own the gas as specified under the previous contract.
Energy Costs
Natural gas prices increased significantly during the quarter, primarily due to the catastrophic effects of hurricanes Katrina and Rita. The two storms caused extensive damage to offshore natural gas drilling rigs and temporarily shut down gas processing facilities due to coastal flooding. A strong worldwide economy and the resulting demand for energy also contributed to price increases by raising the price of competing fuels such as heating oil and propane. Natural gas prices for January delivery reached a new high of $15.78 per decatherm on December 13, 2005. However, the advent of warmer weather in the later part of December and January and the resumption of most Gulf of Mexico production resulted in January prices at the end of December trading below $11.00 per decatherm. While prices appear to be declining from the very recent highs, the U.S. Energy Information Administration expects prices to remain higher than historical levels for the remainder of the year.
Even though natural gas prices remain at high levels in relation to historical prices for the reasons discussed above, management believes that it has planned for adequate supplies to fulfill projected customer needs. The Company uses various hedging mechanisms, including summer storage injections and financial instruments, to mitigate volatility in energy prices.
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 for the regulated operations, 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 15, 2005, Roanoke Gas Company filed an application with the Virginia SCC for an expedited increase in non-gas rates of $2,000,781, or 2.2 percent. The requested increase is based on a 10.1 percent return on equity, which was the level approved in the Company’s last non-expedited rate case. The requested rates were placed into effect on October 23, 2005 and are subject to refund pending the final order by the SCC.
On January 19, 2006, Bluefield Gas Company filed an application with the West Virginia PSC for an increase in non-gas rates of $198,841, or 1.7 percent. The requested increase is based on a 10.5 percent return on equity. Any rate increase associated with the filing is expected to become effective in November 2006.
Environmental Issues
Both Roanoke Gas Company and Bluefield Gas Company, subsidiaries of RGC Resources, Inc., operated manufactured gas plants (MGPs) as a source of fuel for lighting and heating until the early 1950’s. A by-product of operating MGPs was coal tar, and the potential exists for on-site tar waste contaminants at the former plant sites. The extent of contaminants at these sites, if any, is unknown at this time. An analysis at the Bluefield Gas Company site indicates some soil contamination. The Company, with concurrence of legal counsel, does not believe any events have occurred requiring regulatory reporting. Further, the Company has not received any notices of violation or liabilities associated with environmental regulations related to the MGP sites and is not aware of any off-site contamination or pollution as a result of prior operations. Therefore, the Company has no plans for subsurface remediation at the MGP 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. A stipulated rate case agreement between the Company and the West Virginia Public Service Commission recognized the Company’s right to defer MGP clean-up costs, should any be incurred, and to seek rate relief for such costs. If the Company eventually incurs costs associated with a required clean-up of either MGP site, the Company anticipates recording a regulatory asset for such clean-up costs to be recovered in future rates. Based on anticipated regulatory actions and current practices, management believes that any costs incurred related to this matter will not have a material effect on the Company’s financial condition or results of operations.
Capital Resources and Liquidity
Due to the capital intensive nature of Resources’ utility and energy businesses, as well as the related weather sensitivity, Resources’ 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 $1,603,750 and $2,054,243 for the three-month periods ended December 31, 2005 and 2004, respectively. The Company’s total capital budget for the current year is approximately $7,410,000. 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.
Short-term borrowing, in addition to providing capital project bridge financing, is used to fund seasonal levels of natural gas inventory and accounts receivable. From April through October, the Company purchases natural gas to build inventory for winter delivery when demand is much greater. Furthermore, a majority of the Company’s sales and billings occur during the winter months resulting in a corresponding increase in accounts receivable. The following table provides a quarterly perspective of the seasonality of the accounts receivable and natural gas inventory and the corresponding trend of rising gas costs. Amounts are in thousands.
Period Ended
Dec 31, 2003
Mar 31, 2004
Jun 30, 2004
Sep 30, 2004
Dec 31, 2004
Mar 31, 2005
Jun 30, 2005
Sep 30, 2005
Dec 31, 2005
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, 2005, the Company had available lines-of-credit for its short-term borrowing needs totaling $29,000,000, of which $23,158,000 was outstanding. On January 24, 2006, Roanoke Gas Company entered into a new line-of-credit agreement, which provided for increased borrowing limits of up to $21,000,000 through March 31, 2006. This new agreement replaced a line-of-credit agreement that provided for borrowing limits up to $20,000,000 through February 15, 2006 and $16,000,000 through March 31, 2006 for Roanoke Gas Company. The increase in the line-of-credit was requested by the Company to meet short-term funding needs associated with higher gas costs. The total available limits under all lines-of-credit agreements for the remaining term are $30,000,000. The interest rates under the lines-of-credit are variable based upon 30 day LIBOR. These lines of credit expire March 31, 2006, unless extended. The Company anticipates being able to extend or replace the lines of credit upon expiration.
In November 2005, Roanoke Gas Company and Bluefield Gas Company each entered into agreements to refinance maturing debt. Roanoke Gas Company entered into an unsecured 5-year variable rate note with provision for annual renewals thereafter in the amount of $15,000,000. The proceeds of this note were used to refinance the $8,000,000 unsecured note due November 30, 2005 and $4,000,000 in outstanding line-of-credit balance. The remainder of the proceeds were used to call the $3,000,000 collateralized term debenture due in 2016, including a call premium of $206,250. Bluefield Gas Company entered into an unsecured 31-month variable rate note in the amount of $2,000,000. The proceeds from this note were used to refinance the $2,000,000 unsecured note due November 21, 2005. The Company entered into an interest rate swap agreement on the Roanoke Gas note for the purpose of fixing the interest rate over the total term of the note.
Stockholders equity increased by $922,000 for the quarter, 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, 2005, the Company’s consolidated long-term capitalization was 57 percent equity and 43 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 and energy marketing business. 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.
The Company is exposed to market risk related to changes in interest rates associated with its borrowing activities. At December 31, 2005, the Company had $23,158,000 outstanding under its lines of credit and $2,000,000 outstanding on an intermediate-term variable rate note for Bluefield Gas. A hypothetical 100 basis point increase in market interest rates applicable to the Company’s variable rate debt outstanding at December 31, 2005 would have resulted in an increase in quarterly interest expense of approximately $63,000. 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 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 swap and price cap 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. Both the Virginia SCC and the West Virginia PSC currently allow for full recovery of prudent costs associated with natural gas purchases, and any additional costs or benefits associated with the settlement of the derivative contract will be passed through to customers when realized. As of December 31, 2005, a hypothetical 10% reduction in the market price of natural gas would result in a decrease in fair value of approximately $286,000 for the Company’s outstanding natural gas derivative contracts.
ITEM 4 – 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, 2005, the Company’s Chief Executive Officer and principal financial officer have concluded that these disclosure controls and procedures are effective. There has been no change during the quarter ended December 31, 2005, 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, 2005, the Company issued a total of 745.244 shares of restricted stock pursuant to the Restricted Stock Plan as follows:
Investment Date
10/1/2005
11/1/2005
12/1/2005
On November 1, 2005, the Company issued a total of 55.000 shares of its common stock as recognition to certain employees for length of service. The 55.000 shares were not issued in a transaction constituting a “sale” within the meaning of section 2(3) of the Act.
ITEM 6 – EXHIBITS.
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.
/s/ Howard T. Lyon
Vice-President, Treasurer and Controller
(Principal Financial Officer)