SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
QUARTERLY REPORT UNDER SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For Quarter Ended June 30, 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 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 June 30, 2005
RGC RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
UNAUDITED
June 30,
2005
ASSETS
Current Assets:
Cash and cash equivalents
Short-term investments
Accounts receivable - (less allowance for uncollectibles of $872,895 and and $38,525, respectively)
Materials and supplies
Gas in storage
Prepaid gas service
Prepaid income taxes
Deferred income taxes
Under-recovery of gas costs
Fair value of marked to market transactions
Other
Total current assets
Property, Plant And Equipment:
Utility plant in service
Accumulated depreciation and amortization
Utility plant in service, net
Construction work-in-progress
Utility Plant, net
Nonutility property
Nonutility property, net
Total property, plant and equipment
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
Income taxes payable
Customer deposits
Accrued expenses
Refunds from suppliers - due customers
Overrecovery of gas costs
Total current liabilities
Long-term Debt, Excluding Current Maturities
Deferred Credits:
Asset retirement obligations
Deferred investment tax credits
Total deferred credits
Stockholders’ Equity:
Common stock, $5 par value; authorized, 10,000,000 shares; issued and outstanding 2,088,219 and 2,065,408 shares, respectively
Preferred stock, no par, authorized, 5,000,000 shares; 0 shares issued and outstanding in 2005 and 2004
Capital in excess of par value
Retained earnings
Accumulated comprehensive income (loss)
Total stockholders’ equity
Total Liabilities and Stockholders’ Equity
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
FOR THE THREE-MONTH AND NINE-MONTH PERIODS ENDED JUNE 30, 2005 AND 2004
Three Months Ended
Nine Months Ended
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 (Loss) from Continuing Operations Before Income Taxes
Income Tax Expense (Benefit) from Continuing Operations
Income (Loss) from Continuing Operations
Discontinued operations:
Income (loss) from discontinued operations, net of income taxes of $63,515, ($152,792), $73,540 and $932,886, respectively
Net Income (Loss)
Basic Earnings (Loss) Per Common Share:
Income from continuing operations
Discontinued operations
Net income (loss)
Diluted Earnings (Loss) Per Common Share:
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net Income
Reclassification of loss transferred to net income
Unrealized (loss) gain on cash flow hedges
Other comprehensive income, net of tax
Comprehensive Income (Loss)
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE NINE-MONTH PERIODS
ENDED JUNE 30, 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
Loss on disposal of property
Changes in assets and liabilities which provided cash, exclusive of changes and noncash transactions shown separately
Net cash provided by continuing operating activities
Net cash provided by (used in) discontinued operations
Net cash provided by operating activities
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant and nonutility property
Proceeds from disposal of equipment
Sale of short-term investments
Net cash flows used in continuing investing activities
Net cash provided by (used in) investing activities of discontinued operations
Net cash provided by (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 repayments under lines of credit
Cash dividends paid
Proceeds from issuance of stock
Net cash used in financing activities
NET DECREASE IN CASH AND CASH EQUIVALENTS
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
CASH AND CASH EQUIVALENTS AT END OF PERIOD
SUPPLEMENTAL INFORMATION:
Interest paid
Income taxes paid, net
CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
agreement. Roanoke Gas Company has completed the refund to its customers of $175,663 in excess revenues and accrued interest associated with the higher rates placed into effect in October 2004. The Company had provided for the expected refund in prior quarters.
Beginning
Available
Line of Credit
Mar 31, 2005
Jul 16, 2005
Sep 16, 2005
Nov 16, 2005
Feb 16, 2006
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. At June 30, 2005, the Company had $2,596,000 outstanding under its line of credit agreements.
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 limited utilization of Company personnel for billing, propane delivery and related services to Acquiror for the term of one year with an option for an additional year. On April 1, 2005, the Acquiror notified the Company that it will terminate portions of the agreement at the end of the contract period on July 12, 2005, and the parties agreed to extend the other portions of the agreement for office facilities, storage space and computer systems on a monthly basis but not beyond September 30, 2005. Prior to the end of the original contract period, the Acquiror had notified the Company of its intent not to extend the remaining portions of the agreement and to allow the
contract to expire in July 2005 with the exception of a one year lease agreement for access to the storage yard in Bluefield, West Virginia. For the nine months ended June 30, 2005, the Company realized approximately $450,000 in other revenues and $278,000 in other margin attributable to this agreement.
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, the Acquiror executed the option to purchase the real estate and closed on all 10 parcels. The Company realized a net gain on the sale of real estate of approximately $153,000. The operations associated with the real estate and corresponding gain have been classified as Discontinued Operations in accordance with the provisions of SFAS No. 144 Accounting for the Impairment or Disposal of Long-Lived Assets. The components of Discontinued Operations for the three-month and nine-month periods ended June 30, 2005 and 2004 are as follows:
Pretax Operating Income (Loss)
Gain on Sale of Property
Income Tax (Expense) Benefit
Discontinued Operations
Resources used the proceeds from the sale of the propane assets to provide shareholders with a special $4.50 per share dividend, retire corporate debt and invest equity capital into its natural gas operations.
The discontinued operations presented in the income statement for the three months and nine months ended June 30, 2004 reflect revenues and costs of the propane operations, net of income tax. Certain costs that represent allocations of shared costs from the Company and its subsidiaries to the propane operations were retained in the continuing operations section.
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 June 30, 2005, the Company had no outstanding derivative arrangements for the purchase of natural gas. 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 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 $8,000,000 note issued in November 2002. The swap essentially converted the three-year floating rate note into fixed rate debt with a 4.18 percent interest rate. The swap qualifies as a cash flow hedge with changes in fair value reported in other comprehensive income.
Prior to the sale of the propane operations in July 2004, the Company also entered into swaps and price caps to hedge the price risk of propane gas.
A summary of the derivative activity is provided below:
Unrealized losses on derivatives
Income tax benefit
Net unrealized losses
Transfer of realized losses to income
Net transfer of realized losses to income
Net other comprehensive income
Unrealized gains on derivatives
Income tax expense
Net unrealized gains
Accumulated comprehensive income
Transfer of realized losses/(gains) to income
Income tax (benefit)/expense
Net transfer of realized losses/(gains) to income
Accumulated comprehensive loss
Weighted average common shares
Effect of dilutive securities:
Options to purchase common stock
Diluted average common shares
Operating revenues
Gross margin
Operations, maintenance and general taxes
Operating income
Other expense (income), net
Interest expense
Income before income taxes
Gross additions to long-lived assets
Operating income (loss)
Other income, net
Income (loss) before income taxes
Other (income) expenses, net
Total assets
If options had been granted, a reconciliation of net income and earnings per share would be presented to reflect the fair value recognition provisions of FASB Statement No. 123, Accounting for Stock-Based Compensation, to options granted 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
June 30, 2004 balances have been restated to reflect the removal of costs attributable to the discontinued operations of Highland Propane. Net periodic pension cost and net periodic post-retirement benefit cost included in discontinued operations were $24,196 and $23,603 for the three months ended June 30, 2004 and $72,588 and $70,809 for the nine months ended June 30, 2004, respectively. Total expected employer funding contributions during the fiscal year ending September 30, 2005 are $750,000 for the pension plan and $800,000 for the post retirement plan.
In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment, a revision of SFAS No. 123, Accounting for Stock-Based Compensation. This statement eliminates the alternative to use Accounting Principles Board’s Opinion No. 25, Accounting for Stock Issued to Employees, intrinsic value method of accounting that was previously allowed under Statement 123. This statement 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 effective date of this statement has been extended to correspond with fiscal years beginning after June 15, 2005. The Company does not expect the adoption of this statement to have a material impact on the Company’s financial position or results of operations.
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 are conditional on a future event. FIN No. 47 provides clarification when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. The effective date of this interpretation is no later than the end of fiscal years ending after December 31, 2005. 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.
In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections – a replacement of APB Opinion No. 20 and FASB Statement No. 3. This statement applies to all voluntary changes in accounting principle by requiring retrospective application of the change in accounting principle to all prior period financial statements presented. Retrospective application is defined as the application of a different accounting principle to prior accounting periods as if that principle had always been used. Previously, such changes were reflected in the current financial statements as a cumulative effect of change in
accounting principle. The intent of the statement is to improve financial reporting by improving comparability of financial statements between periods. The effective date of this statement is for fiscal years beginning after December 15, 2005. This statement does not have a current effect on the Company’s financial statements but will affect the Company’s future reporting of changes in accounting principles, if any.
ITEM 2 - MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 59,000 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 several 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. These operations have been classified as discontinued operations in the prior year financial statements.
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. The risk of warm winter weather has been partially mitigated due to the inclusion of a weather normalization adjustment (“WNA”) factor as part of Roanoke Gas Company’s rate structure. The WNA operates 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 were more than 6 percent below the 30-year average, the Company would add a surcharge to firm customer bills (those customers not subject to service interruption) equal to the equivalent margin lost below the approximate 6 percent deficiency. Likewise, if the number of heating-degree days were more than 6 percent above the 30-year average, the Company would credit firm 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. The Company realized approximately $445,000 in additional revenues for the weather band period ended March 31, 2005 as the heating-degree days for the period April 2004 through March 2005 were approximately 12 percent less than the 30-year average. In addition, management has concerns regarding the cost and time required for complying with regulations regarding internal controls promulgated pursuant to Section 404 of the Sarbanes-Oxley Act of 2002.
For the quarter ended June 30, 2005, high energy prices remained the primary concern for management. Continued increases in natural gas prices may lead consumers to reduce consumption through conservation or possible fuel switching to alternate, lower cost energy sources. In spite of the continuing high energy prices, the Company was able to experience improved operating results from continuing operations over the same quarter last year. Implementation of increased base rates in October combined with a rate design that provides timely recovery of the carrying costs associated with the greater investment in natural gas inventories have contributed to the improved results.
Results of Operations
Consolidated net income (loss) for the three-month and nine-month periods ended June 30, 2005 was $229,525 and $3,918,639, respectively, compared to $(512,664) and $4,234,991 for the same periods last year. Net income (loss) from continuing and discontinued operations is as follows:
Continuing Operations
Increase/(Decrease)
Percentage
Gas Utilities
Energy Marketing
Total Operating Revenues
Total operating revenues from continuing operations for the three months ended June 30, 2005 increased by $2,604,875, or 14 percent, compared to the same period last year, primarily due to
higher gas costs, the implementation of base rate increases and the services agreement associated with the sale of Highland Propane. The total average unit cost of natural gas increased by 11 percent over the same quarter last year. Total regulated natural gas delivered volumes increased by 1 percent, while energy marketing sales volumes declined by 7 percent. Other revenues increased by $123,156 due to revenues generated under the services agreement with the Acquiror (as defined below) of the assets of Highland Propane Company to provide billing, facility and other services. The revenues attributed to the services agreement will cease by fiscal year end, because the Acquiror has notified the Company that it will terminate the contract at the end of the contract period on July 12, 2005. Only nominal activity and revenues will occur subsequent to contract termination.
Total Gross Margin
Total gross margin increased by $585,356, or 13 percent, for the quarter ended June 30, 2005 over the same period last year. Regulated natural gas margins increased by $475,381, or 11 percent, even though total delivered volume (tariff and transporting) increased by only 1 percent. Tariff sales, primarily consisting of residential and commercial usage, increased by 5 percent primarily due to certain industrial transportation customers switching to tariff sales. Residential and commercial usage reflected a 2 percent increase over last year associated with a cooler Spring quarter. In consideration of the small rise in total delivered natural gas volumes, the majority of the increase in the regulated natural gas margins is attributable to the implementation of increased non gas cost base rates effective October 23, 2004 combined with the rate design which provides timely recovery of the financing costs (“carrying costs”) related to the higher dollar investments in natural gas inventories. Both Roanoke Gas Company and Bluefield Gas Company placed increased rates into effect during the first quarter. 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 $114,000 in additional customer base charges, which is a flat monthly fee billed to each natural gas customer. Carrying cost revenues increased by approximately $214,000 due to a much higher level of investment in storage gas inventory compared to prepaid gas service for the same period last year due to the combination of higher prices and warmer weather reducing the withdrawal rates from storage. The balance of the increase in regulated natural gas margin is attributable to the volumetric portion of the rate increase.
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 and prepaid gas balances resulting from reductions in gas costs. During the first quarter, 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 $214,000 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.
The energy marketing division margin increased by $6,515, or 11 percent, even though total sales volume decreased by 51,297 dekatherms, or 7 percent. The Company was able to make up the volume shortfall with a small increase in unit margin per dekatherm. Other margins increased by $103,460 due to the services agreement with the Acquiror of the assets of Highland Propane Company to provide billing, facility and other services, as discussed above.
The table below reflects volume activity and heating degree-days.
Regulated Natural Gas (DTH)
Tariff Sales
Transportation
Total
Highland Energy (DTH)
Heating Degree Days (Unofficial)
Operations expenses decreased by $96,287, or 4 percent, for the three-month period ended June 30, 2005 compared to the same period last year. The decrease is primarily due to reductions in bad debt expense. Improvement in bad debt expense is due to a variety of factors including: improvement in customer delinquencies, increased level of customer deposits to provide protection against default and the effect on a new rate structure for Bluefield Gas implemented in the first quarter. The new rate structure provides that the portion of bad debts associated with gas cost be included as a component of gas costs, thereby allowing direct recovery through the Purchased Gas Adjustment (PGA) mechanism. Operations expenses were also reduced by the
actuarial impact of Medicare Part D on post-retirement medical costs offset by increases in labor costs. Maintenance expenses declined $28,277, or 7 percent, due to a greater level of work associated with leak repairs in the prior year.
General taxes increased $13,063, or 4 percent, primarily due to higher business and occupation (B&O) taxes, a revenue sensitive tax, related to higher revenues in the West Virginia natural gas operations and higher payroll taxes.
Other expense, net, increased by $36,676 due to a $30,000 loss on the sale and disposal of the propane air plant by Roanoke Gas.
Interest expense increased by $25,941, or 6 percent, as the Federal Reserve’s monetary policy has led to increasing interest rates on the Company’s variable rate debt. The Company’s total debt position during the quarter remained nearly unchanged compared to last year. The effect of rising interest rates has increased the overall average rate on total Company debt by 25 basis points over the same period last year.
Income tax expense increased by $221,371, which corresponds to the pre-tax income for the current quarter as compared to a pre-tax loss for the same quarter last year.
Total operating revenues from continuing operations for the nine months ended June 30, 2005 increased by $10,984,832, or 13 percent, compared to the same period last year, due to the same reasons provided for the quarter: higher gas costs and implementation of base rate increases more than offsetting reductions related to lower sales volumes related to the warmer winter weather. Revenues were also supplemented by the billing of approximately $445,000 in additional revenue associated with the WNA. Although total tariff sales of the gas utilities declined by 4 percent, the average unit cost of natural gas delivered to customers increased by 19 percent. Energy marketing revenues increased due to the effects of rising gas costs, even though sales volumes were down by 4 percent. Other revenues increased by $395,855 due to revenues generated under the services agreement with the Acquiror of the assets of Highland Propane Company to provide billing, facility and other services, as discussed above.
Total gross margin increased by $1,409,633, or 7 percent, for the nine-month period ended June 30, 2005 over the same period last year. Regulated natural gas margins increased by $1,039,359, or 5 percent, even though total delivered volume (tariff and transporting) decreased by 368,670 dekatherms, or 4 percent. The increase in the regulated natural gas margin was attributable to rate increases placed into effect during the first quarter for both Roanoke Gas and Bluefield Gas, approximately $455,000 in additional carrying cost revenues associated with the higher level of investment in storage gas inventory and prepaid gas service compared to the same period last year and approximately $445,000 in additional revenues associated with the WNA, all of which more than offset the effect of the reduction in sales volumes. The energy marketing division margin increased by $132,911, even though total sales volume decreased by 95,317 dekatherms, or 4 percent. The increase in margin was attributable to the sale of 100,000 dekatherm natural gas strip for $143,000 profit. The 100,000 dekatherm 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. Other margins increased by $237,363 due to the services agreement with the Acquiror of the assets of Highland Propane Company to provide billing, facility and other services.
Operations expenses decreased by $408,406 or 5 percent for the nine-month period ended June 30, 2005 compared to the same period last year. The decrease is primarily due to reductions in employee benefit costs including medical insurance due to lower claim activity in the first quarter, post-retirement medical costs due to the actuarial impact of Medicare Part D and reductions in bad debt expense. The Company has 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. Beginning in January 2005, the Company switched to fully insured coverage to provide a more predictable expense trend, which is more conducive to receiving recovery of these costs in a regulated environment. Maintenance expenses declined $44,529, or 4 percent, due to a greater level of work associated with leak repairs in the prior year. General taxes remained comparable to last year experiencing a slight increase of less than 1 percent.
Other expense (income), net decreased by $35,665 due to investment earnings realized 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 $113,138, or 8 percent, even though the Company’s average total debt position during the current quarter decreased by $400,000 from the same period last year. The increase in interest expense is attributable to rising rates on the Company’s variable rate debt. The effective average interest rate on the Company’s outstanding lines of credit balances increased from 1.70% last year to 2.96% this year.
Income tax expense increased by $638,180, which corresponds to the increase in pre-tax income on continuing operations. The effective tax rate decreased slightly from 38.5 percent to 38.3 percent for the current period.
The three-month and nine-month earnings presented herein should not be considered as reflective of the Company’s consolidated financial results for the fiscal year ending September 30, 2005. The total revenues and margins realized during the first nine months reflect higher billings due to the weather sensitive nature of the gas business. Improvement or decline in earnings for the balance of the year will depend primarily on the level of operating and maintenance costs.
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), including 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.
Concurrent with the sale of assets, the Company entered into an agreement with Acquiror by which the Company will continue to provide the use of office, warehouse and storage space, and computer systems and office equipment and the limited utilization of Company personnel for billing, propane delivery and related services to Acquiror for the term of one year with an option for an additional year. On April 1, 2005, the Acquiror notified the Company that it will terminate portions of the agreement at the end of the contract period on July 12, 2005, and the parties agreed to extend the other portions of the agreement for office facilities, storage space and computer systems on a monthly basis but not beyond September 30, 2005. Prior to the end of the original contract period, the Acquiror notified the Company of its intent not to extend the remaining portions of the agreement and allow the contract to expire in July 2005 with the exception of a one year extension for access to the storage yard in Bluefield, West Virginia. For the nine months ended June 30, 2005, the Company realized approximately $450,000 in other revenues and $278,000 in other margin attributable to this agreement. The $278,000 margin covered approximately $169,000 in recurring operating and maintenance expenses allocated from Resources and the regulated natural gas operations. Management anticipates that it will be able to recover most, if not all, of these previously allocated costs through future rate relief.
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, the Acquiror executed the option to purchase the real estate and closed on all 10 parcels. The Company realized a net gain on the sale of real estate of approximately $153,000. The operations associated with the real estate and the corresponding gain have been classified as Discontinued Operations in accordance with the provisions of SFAS No. 144 Accounting for the Impairment or Disposal of Long-Lived Assets. The components of Discontinued Operations for the three-month and nine-month periods ended June 30, 2005 and 2004 are as follows:
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 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. Although estimates and judgments are applied in arriving at many of the reported amounts in the financial statements including provisions for employee medical insurance, projected useful lives of capital assets and goodwill valuation, the following items may involve a greater degree of judgment.
Revenue recognition – The Company bills natural gas customers on a monthly cycle basis; however, 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. The Company also accrues a provision for rate refund and/or WNA adjustment during periods in which the Company has implemented new billing rates as authorized by the corresponding state regulatory body or during periods in which weather falls outside of the weather normalization band, pending final review and authorization from the state regulatory body.
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 and a post-retirement medical 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 post-retirement medical 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 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. Fair value is based upon quoted futures prices for the natural gas commodities. 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 futures value 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 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. As a result of the new contracts, the balance sheet at June 30, 2005 includes a line item called “gas in storage” that is composed of the underground storage gas previously owned by the asset manager. The gas in storage line item replaces the prepaid gas service under the prior contract, which represented the Companies’ rights to receive an equal amount of gas in the future as provided by those agreements.
Energy Costs
Natural gas commodity prices have continued to remain high and volatile throughout the last heating season and into the summer months. Management considers the key reason for high energy prices to be the accumulated impact of years of inconsistent regulatory policy and the continued failure of Congress to pass and the President to sign meaningful national energy use and resource development legislation. In the absence of such legislation, accessible natural gas reserves may continue to decline. An energy bill that would provide some improvement for natural gas supply development was approved by Congress and signed by the President in early August. The Company uses various hedging mechanisms including summer storage injections and financial instruments to limit weather driven volatility in energy prices. Management determined not to utilize financial hedges during the just completed winter season to the extent it has in prior years because of the unusually large spread between winter futures prices and gas prices leading up to the winter season. Given the high level of natural gas in storage on a national basis, management did not believe the winter futures prices were a reasonable basis for financial price hedging purposes. The wide spread continues in spite of a warmer than normal winter and management has not yet determined it appropriate to utilize financial hedges for the coming winter season.
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, LNG (liquefied natural gas) and storage gas levels. 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
Roanoke Gas Company placed into effect new base rates effective for service rendered on and after October 23, 2004 to provide for approximately $1,135,000 in additional annual non gas revenues. These higher rates were subject to refund pending a final order by the Virginia SCC. In March 2005, Roanoke Gas Company reached a stipulated agreement with the SCC staff for a rate award of $856,859. Roanoke Gas received approval from an SCC Hearing Examiner to implement rates designed to collect $856,859 in additional annual non-gas revenues beginning April 1, 2005. On April 28, 2005, the SCC issued a final rate order approving the stipulated agreement. In the June billing cycle, Roanoke Gas Company refunded $175,663 in excess revenues, and accrued interest, collected above those provided for in the rate order. Management filed a notice of intent in June to inform the SCC of Roanoke Gas Company’s plan to file a new request for rate increase in September.
Bluefield Gas Company settled its rate case pending a final order from the West Virginia PSC which authorized Bluefield Gas to implement a non gas cost rate increase to provide for an $330,000 in additional annual revenues. Management anticipates that these new rates will be placed into effect for gas service rendered on and after November 1, 2005.
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 old bare steel and cast iron pipe with new plastic or coated steel pipe and expansion of natural gas service to new customers. Total capital expenditures from continuing operations were $5,406,850 and $5,288,047 for the nine-month periods ended June 30, 2005 and 2004, respectively. The Company’s total capital budget for the current year is approximately $7,070,000. It is anticipated that these costs and 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 be placed into storage for winter delivery. 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. Amounts are in thousands.
Period Ended
Gas in Storage/Prepaid
Gas Service
Jun 30, 2003
Sep 30, 2003
Dec 31, 2003
Mar 31, 2004
Jun 30, 2004
Sep 30, 2004
Dec 31, 2004
Jun 30, 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.
On March 29, 2005, the Company and Wachovia Bank renewed the Company’s line of credit agreements. The new agreements maintain the same variable interest rates based upon 30-day LIBOR and continue the five-tier level for borrowing limits to accommodate the Company’s seasonal borrowing demands. Generally, the Company’s borrowing needs are at their lowest in Spring, increase during the Summer and Fall due to gas storage purchases and construction and reach their maximum levels in Winter. The five-tier approach will keep the Company’s borrowing costs to a minimum by improving the level of utilization on its line of credit agreements and providing increased credit availability as borrowing requirements increase. Available limits under the line of credit agreements are as follows:
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. At June 30, 2005, the Company had $2,596,000 outstanding under its line of credit agreements.
The Company has $10,000,000 in current maturities of long-term debt that is due in November 2005. Management anticipates refinancing these balances upon maturity.
At June 30, 2005, the Company’s capitalization consisted of 40 percent in long-term debt and 60 percent in common equity.
Labor Relations
Certain operational employees of Roanoke Gas and Bluefield Gas belong to the Paper, Allied-Industrial, Chemical and Energy Workers International Union, AFL-CIO Local No. 2-515. The union contract for Roanoke Gas covering 34 employees expired on July 31, 2005. On August 1, 2005, the union voted upon and approved a new 5-year contract. The Bluefield Gas’ collective bargaining agreement will expire on July 4, 2007.
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) inability to raise debt or equity capital on favorable terms; (xv) impact of uncertainties in the Middle East and related terrorism issues; (xvi) work stoppages associated with labor disputes; (xvii) supply curtailment or disruption due to pipeline failures; 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” 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.
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 June 30, 2005, the Company had $2,596,000 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 June 30, 2005 would have resulted in an increase in quarterly interest expense of approximately $11,500. The Company also has an $8,000,000 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 storage gas arrangements for the purpose of hedging the price of natural gas. The Company currently has no derivative commodity instruments for hedging the price of natural gas. However, if the Company had entered into derivative commodity arrangements, any cost incurred or benefit received from the derivative arrangements would be 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 June 30, 2005, the Company had not entered into any new natural gas derivative instruments during the quarter.
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 June 30, 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 June 30, 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 - CHANGES IN SECURITIES.
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 1993 (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 June 30, 2005, the Company issued a total of 700.800 shares of restricted stock pursuant to the Restricted Stock Plan as follows:
Investment Date
4/1/2005
5/2/2005
6/1/2005
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