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 period ended December 31, 2006
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 latest practicable date.
Class
Outstanding at January 31, 2007
RGC RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
UNAUDITED
ASSETS
Current Assets:
Cash and cash equivalents
Accounts receivable - (less allowance for uncollectibles of $504,365 and $34,980, respectively)
Materials and supplies
Gas in storage
Prepaid income taxes
Deferred income taxes
Under-recovery of gas costs
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.
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Borrowings under lines of credit
Dividends payable
Accounts payable
Customer credit balances
Income taxes payable
Customer deposits
Accrued expenses
Refunds from suppliers - due customers
Over-recovery of gas costs
Fair value of marked to market transactions
Total current liabilities
Long-term Debt, Excluding Current Maturities
Deferred Credits and Other Liabilities:
Asset retirement obligations
Regulatory cost of retirement obligations
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 2,151,805 and 2,138,595 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, 2006 AND 2005
Operating Revenues:
Gas utilities
Total operating revenues
Cost of Sales:
Total cost of sales
Gross Margin
Other Operating Expenses:
Operations
Maintenance
General taxes
Depreciation and amortization
Total other operating expenses
Operating Income
Other 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 $42,730
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 (gain) 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, 2006 AND 2005
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
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
BEGINNING CASH AND CASH EQUIVALENTS
ENDING CASH AND CASH EQUIVALENTS
SUPPLEMENTAL INFORMATION:
Cash paid (received) during the year for:
Interest
Income taxes net of refunds
CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months EndedDecember 31,
2005
Discontinued Operations:
Revenues
Pretax Operating Income
Income Tax Expense
Discontinued Operations
With the sale of the operations of Highland Energy and corresponding reclassification of its operations to discontinued operations, Resources has only one reportable segment as defined under SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information.
The Company has historically entered into futures, swaps and caps for the purpose of hedging the price of natural gas in order to provide price stability during the winter months. As of December 31, 2006, the Company had outstanding derivative swap arrangements for the purchase of natural gas. The fair value of these instruments is recorded in the balance sheet with the offsetting entry to overrecovery or underrecovery of gas costs. Net income and other comprehensive income are not affected by the change in market value as any prudently incurred cost or benefit received from these instruments is recoverable or refunded through the regulated natural gas purchased gas adjustment (PGA) mechanism.
The Company 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, 2006
Unrealized losses
Income tax benefit
Net unrealized losses
Transfer of realized gains to income
Income tax expense
Net transfer of realized gains to income
Net other comprehensive loss
Accumulated comprehensive loss
Three Months Ended December 31, 2005
Unrealized (losses) gains
Income tax benefit (expense)
Net unrealized (losses) gains
Transfer of realized losses to income
Net transfer of realized losses to income
Net other comprehensive (loss) income
Weighted average common shares
Effect of dilutive securities:
Options to purchase common stock
Diluted average common shares
Components of net periodic pension cost:
Service cost
Interest cost
Expected return on plan assets
Recognized loss
Net periodic pension cost
Components of post-retirement benefit cost:
Amortization of unrecognized transition obligation
Net periodic post-retirement benefit cost
The Company contributed $400,000 to its pension plan for the quarter ended December 31, 2006. The Company expects to make a total contribution of approximately $600,000 to its pension plan and $700,000 to its postretirement benefit plan during the fiscal year ending September 30, 2007.
In June 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes – an Interpretation of FASB Statement No. 109. This statement clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements
in accordance with FASB Statement No. 109, Accounting for Income Taxes. This Interpretation prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The recognition threshold is based upon whether it is more-likely-than-not that a tax position taken by an enterprise will be sustained upon examination. The measurement attribute of a more-likely-than-not tax position is measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement. The effective date of this statement is for fiscal years beginning after December 15, 2006. The Company has not completed its evaluation of this statement but does not anticipate the adoption to have a material impact on the Company’s financial position or results of operations.
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. This statement defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value methods. This statement does not require any new fair value measurements. Instead, it provides for increased consistency and comparability in fair value measurements and for expanded disclosure surrounding the fair value measurements. This statement is effective for fiscal years beginning after November 15, 2007.
In September 2006, the FASB issued SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – an amendment of FASB Statements No. 87, 88, 106, and 132R. This statement requires employers who sponsor one or more single-employer defined benefit plans to recognize the overfunded or underfunded position of such plan(s) as an asset or liability in its balance sheet and to recognize changes in that funded status in the year in which the changes occur through comprehensive income. This statement also requires the measurement of the defined benefit plan assets and obligations as of the date of the employer’s balance sheet date and additional disclosures in the financial statement footnotes. The effective date of this statement is for fiscal years ending after December 15, 2006. The requirement to measure plan assets and benefit obligations as of the fiscal year end balance sheet date is effective for fiscal years ending after December 15, 2008. The Company has not completed its evaluation of this statement and has not yet determined the full impact on the Company’s financial position or results of operations in light of the current regulatory environment and the application of SFAS No. 71. In the absence of the considerations of SFAS No. 71 and using the most recent actuarial valuation as of June 30, 2006, the effect on the December 31, 2006 balance sheet would have been to increase accrued postretirement benefits and accumulated comprehensive loss by approximately $4,200,000 and $2,600,000, respectively, and decrease deferred income tax liability by approximately $1,700,000. The Company does not expect the adoption of this statement to adversely affect the results of operations or cash flows on a going forward basis.
ITEM 2 - MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Forward-Looking Statements
From time to time, RGC Resources, Inc. (“Resources” or the “Company”) may publish forward-looking statements relating to such matters as anticipated financial performance, business prospects, technological developments, new products, research and development activities and similar matters. The Private Securities Litigation Reform Act of 1995 provides a safe harbor for forward-looking statements. In order to comply with the terms of the safe harbor, the Company notes that a variety of factors could cause the Company’s actual results and experience to differ materially from the anticipated results or other expectations expressed in the Company’s forward-looking statements. The risks and uncertainties that may affect the operations, performance, development and results of the Company’s business include the following: (i) failure to earn on a consistent basis an adequate return on invested capital; (ii) ability to retain and attract professional and technical employees; (iii) 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 regulatory oversight and compliance requirements due to financial, environmental, safety and system integrity laws and regulations; (xiii) failure to obtain timely rate relief for increasing operating or gas costs from regulatory authorities; (xiv) ability to raise debt or equity capital; (xv) impact of terrorism; (xvi) volatility in actuarially determined benefit costs; (xvii) impact of natural disasters on production and distribution facilities and the related effect on supply availability and price; and (xviii) new accounting standards issued by the Financial Accounting Standards Board, which could change the accounting treatment for certain transactions. All of these factors are difficult to predict and many are beyond the Company’s control. Accordingly, while the Company believes its forward-looking statements to be reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from them will be realized. When used in the Company’s documents or news releases, the words, “anticipate,” “believe,” “intend,” “plan,” “estimate,” “expect,” “objective,” “projection,” “forecast”, “budget” or similar words or future or conditional verbs such as “will,” “would,” “should,” “could” or “may” are intended to identify forward-looking statements.
Forward-looking statements reflect the Company’s current expectations only as of the date they are made. The Company assumes no duty to update these statements should expectations change or actual results differ from current expectations except as required by applicable laws and regulations.
Overview
Resources is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately 61,100 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 certain unregulated natural gas related services through Roanoke Gas Company and information system services to software providers in the utility industry through RGC Ventures, Inc. of Virginia, which operates as Application Resources. Such operations represent less than one percent of total revenues and income of Resources.
Winter weather conditions and volatility in natural gas prices both have a direct influence on the quantity of natural gas sales to the Company’s customers and management believes each factor has the potential to significantly impact earnings. A majority of natural gas sales are for space heating during the winter season. Consequently, during warmer than normal winters, customers may significantly reduce their purchase of natural gas. Furthermore, rising natural gas commodity prices could also affect customer usage through conservation or use of alternative fuels.
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, 2006, heating degree-days (an industry measure by which the average daily temperature falls below 65 degrees Fahrenheit) were 10 percent less than the same period last year and 15 percent lower than the 30-year normal.
The Company has been able to mitigate a portion of the risk associated with warmer than normal winter weather by the inclusion of a weather normalization adjustment (“WNA”) factor as part of Roanoke Gas Company’s rate structure, which allowed the company to recover revenues equivalent to the margin that would be realized at approximately 6 percent warmer than the 30-year normal. The Company recorded approximately $328,600 in additional revenues to reflect the estimated impact of the WNA for the difference in margin realized for weather between 16 percent and 6 percent warmer than the 30-year average. The final surcharge or refund to customers will be dependent on the weather during the second quarter. Accordingly, the accrued revenues related to the surcharge may be adjusted up or down from the amount reflected in the December 31, 2006 financial statements. The Company did not accrue additional revenues during the quarter ended December 31, 2005 as the number of heating degree days were approximately 6 percent less than the 30-year average, and therefore, within the weather band range in which no adjustment is made. 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.
Management also has concerns regarding the volatility of natural gas prices and the potential for reduced sales in response to increasing prices. Rising natural gas prices may influence the level of sales due to conservation efforts by customers or may result in switching to an alternative fuel. In addition, increasing prices may increase the level of bad debts due to customers’ inability to afford the higher prices. Although current natural gas prices are well below the prices that occurred in the fall of 2005 following damage to natural gas production and transportation facilities from Hurricanes Katrina and Rita, the Company remains concerned about the potential lingering effects that high prices may have on customers’ ongoing conservation efforts. The Company directly experienced the effect of customers’ energy conservation efforts during the last fiscal year’s winter heating season; however, the carryover effect, if any, of conservation practices in the current heating season has not been determined due to the effect of much warmer weather on energy consumption.
Results of Operations
Consolidated net income for the three-month period ended December 31, 2006 was $1,685,515 compared to $1,452,182 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
Heating Degree Days
(Unofficial)
The table below reflects operating revenues.
Operating Revenues
Gas Utilities
Total Operating Revenues
Total operating revenues from continuing operations for the three months ended December 31, 2006 decreased by $13,926,313, or 32 percent, compared to the same period last year, due to the effect that much warmer weather had on both energy consumption and natural gas commodity prices. The total average unit cost of natural gas declined by 33 percent. Total regulated natural gas delivered volumes decreased by 9 percent as the total number of heating degree-days declined by 10 percent from the same period last year. Other revenues increased by 41 percent due to revenues related to other non-regulated natural gas related services.
Total Operating Margin
Total gross margin increased by $421,934, or 5 percent, for the quarter ended December 31, 2006 over the same period last year. Regulated natural gas margins increased by $435,025, or 6 percent, even though total delivered volume (tariff and transporting) decreased by 313,654 decatherms, or 9 percent. The regulated operations realized an increase in margin due to the recording of approximately $328,600 in WNA revenues, as discussed above, and the implementation of non-gas rate increases during the quarter. The WNA adjustment essentially increased the regulated margins for Roanoke Gas Company to a position equivalent to margins that would have been realized if the weather had been approximately 6 percent warmer than the 30-year normal. As a result, the WNA negated a majority of the effect that weather had on the gross margin between periods. In addition, both Roanoke Gas Company and Bluefield Gas Company placed increased rates into effect during the quarter ended December 31, 2006. 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. These rate increases more than made up for the remaining margin shortfall from last year and provided for the overall increase in regulated margins. The Company realized approximately $107,000 in additional margin from customer base charges, which is a flat monthly fee billed to each natural gas customer, and approximately $338,000 associated with increase in the volumetric price of natural gas. Carrying cost revenues, as explained below, decreased by approximately $16,000 due to changes implemented as part of the new rates placed into effect for Bluefield Gas.
Both Roanoke Gas and Bluefield Gas had approved rate structures in place during the quarter that allowed each company to accrue revenue to cover the financing costs related to the level of investment in natural gas inventory. During this time of rising gas costs and rising inventory levels, both companies recognized revenues to offset the higher financing costs. Conversely, the companies would have passed along savings to customers if financing costs had decreased due to lower inventory gas balances resulting from reductions in gas costs or volumes. As a result of an order by the West Virginia PSC in Bluefield Gas Company’s 2006 rate case, Bluefield ended its separate calculation of carrying cost revenue in November 2006. These revenues are now included as part of the base non-gas rates and will only be adjusted as a result of future rate case filings. The net effect of the change in the rate structure for Bluefield Gas’ carrying cost accounted for the most of the $16,000 decline in these revenues; however, these revenues are now included as part of volumetric sales and margins. Other margins are comparable to last year.
Operations expenses were down slightly from the same period last year, declining by $34,209, or 1 percent. Decreases in bad debt and employee benefit expenses offset higher expenses associated with an increase in professional services, contracted services and operations labor. Bad debt expense declined by nearly $82,000 due to a 32 percent reduction in revenues. Employee benefit expenses decreased by $87,000 due to reductions in pension and other post employment benefit costs attributable to an increase in the discount rate used to determine the actuarial expense for the current year. Professional services increased by $20,000 primarily related to additional fees associated with the Company’s prior auditors providing their consent to the fiscal 2006 year end financial statements. Contracted services and labor increased approximately $94,000 related to timing of distribution pipeline leak surveys and related operations tasks. Maintenance expenses decreased $45,137, or 12 percent, from the same period last year. The decrease in maintenance primarily related to timing of repairs of pipeline leaks in the Company’s distribution system determined through leak surveys. During the current quarter, resources were directed to conducting the annual leak surveys, which may lead to a reallocation of those resources in the next quarters related to any discovered leaks requiring repair.
General taxes decreased $29,940, or 7 percent, for the three-month period ended December 31, 2006 compared to the same period last year primarily due to lower business and occupation (B&O) taxes, a revenue sensitive tax, related to reduced revenues in the West Virginia natural gas operations. Depreciation expense increased $58,424, or 5 percent, due to the growth in utility plant associated with extending service to new customers and replacing cast iron and bare steel pipe. Net other expense (income) changed by $7,195 due to higher level of investment earnings.
Interest expense decreased slightly by $4,022, or 1 percent, as reductions in borrowings under the Company’s line-of-credit agreements offset the impact of higher interest rates on variable rate debt. The combination of reduced sales volumes and significantly lower commodity prices for natural gas reduced the overall average borrowing requirements for the quarter by nearly $4,500,000, while the effective average interest rate on the Company’s line-of-credit increased from 4.7 percent last year to 5.9 percent for the current period.
Income tax expense increased by $180,844, which corresponds to the increase in pre-tax income on continuing operations for the quarter. The effective tax rate for the quarter was 38.1 percent compared to 38.2 percent for the same period last year.
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, 2007. 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.
In July 2006, the Company entered into an asset purchase and sale agreement for the sale of the assets relating to its Highland Energy gas marketing business. The assets sold included the gas supply contracts between Highland Energy and its customers and related business records. The purchase price for the assets sold by Highland Energy was valued at up to $414,270 with $233,216 received and recognized at the August 2006 closing. The remaining $181,054 will be received on the first anniversary of the close subject to certain retention and sales levels realized by the acquiring entity. The balance received by the Company will be adjusted downward on a customer by customer basis by a prescribed amount to the extent (i) the customer pursuant to an assigned contract is no longer a customer on the anniversary date and such customer was not a customer for two or more months during the preceding 12 month period, or (ii) the customer reduces its average natural gas consumption by more than 20 percent from current annualized levels. The operations associated with the energy marketing operations were reclassified as Discontinued Operations in accordance with the provisions of SFAS No. 144, Accounting for the Impairment and Disposal of Long-Lived Assets.
Critical Accounting Policies
The consolidated financial statements of Resources are prepared in accordance with accounting principles generally accepted in the United States of America. The amounts of assets, liabilities, revenues and expenses reported in the Company’s financial statements are affected by accounting policies, estimates and judgments that are necessary to comply with generally accepted accounting principles. Estimates used in the financial statements are derived from prior experience, statistical analysis and professional judgments. Actual results could differ from the estimates, which would affect the related amounts reported in the Company’s financial statements. The following policies and estimates are important to understanding certain key components of the financial statements.
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 approximately 6 percent warmer than normal or approximately 6 percent colder than normal over a 12 month period. Without the WNA, the Company’s operating revenues and gross margins would have been reduced by approximately $328,600 for the quarter ended December 31, 2006.
The Company bills its regulated natural gas customers on a monthly cycle. The billing cycle periods for most customers do not coincide with the accounting periods used for financial
reporting. The Company accrues estimated revenue for natural gas delivered to customers not yet billed during the accounting period. Determination of unbilled revenue relies on the use of estimates and current and historical data. The financial statements included unbilled revenues of $5,525,460 and $1,565,727 at December 31, 2006 and September 30, 2006, respectively. 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 and life insurance plan (“postretirement plan”) to eligible employees. The expenses and liabilities associated with these plans are determined through actuarial means requiring the use of estimates and assumptions. In regard to the pension plan, these factors include assumptions regarding discount rate, expected long-term rate of return on plan assets, compensation increases and life expectancies, among others. Similarly, the postretirement plan also requires the estimation of many of the same factors as the pension plan in addition to assumptions regarding rate of medical inflation and Medicare availability. Actual results may differ materially from the results expected from the actuarial assumptions due to changing economic conditions, volatility in interest rates and changes in life expectancy 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 may hedge certain risks incurred in the normal operation of business through the use of derivative instruments. The Company applies the requirements of Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, which requires the recognition of all derivative instruments as assets or liabilities in the Company’s balance sheet at fair value. In most instances, fair value is based upon quoted futures prices for the natural gas commodities and interest rate futures for interest rate swaps. Changes in the commodity and futures markets will impact the estimates of fair value in the future. Furthermore, the actual market value at the point of realization of the derivative may be significantly different from the values used in determining fair value in prior financial statements.
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).
If any portion of the current regulated operations ceased to meet the criteria for application of the provisions of SFAS No. 71, the Company would remove the corresponding regulatory asset or liabilities from the consolidated balance sheets and reflect them within the consolidated statement of income for the period in which the discontinuance occurred.
Asset Management
Both Roanoke Gas Company and Bluefield Gas Company use a third party as an asset manager to manage its pipeline transportation and storage rights and gas supply inventories and deliveries. In return for being able to utilize the excess capacities of the transportation and storage rights, the third party pays both Roanoke Gas Company and Bluefield Gas Company a monthly utilization fee, which is used to reduce the cost of gas for their customers. The current agreements expire October 31, 2007.
Energy Costs
Natural gas prices have decreased significantly from last year’s record high commodity prices. The December closing price for NYMEX (New York Mercantile Exchange) January 2007 deliveries was $5.838 as compared to December 2005 closing price for January 2006 deliveries of $11.431. A combination of strong storage levels entering the heating season, much warmer than normal weather, the absence of damaging hurricane activity in the Gulf of Mexico and falling crude oil prices have contributed to the much lower prices. Natural gas futures indicate that prices should remain at levels lower than the previous year for the balance of the heating season barring any unforeseen circumstances or prolonged colder than normal weather.
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 14, 2006, Roanoke Gas Company filed an application with the Virginia SCC for an expedited increase in non-gas rates to provide approximately $1,700,000 in additional revenues. The requested rates were placed into effect on October 23, 2006 and are subject to refund for any differences between the implemented rates and the final rates approved by the SCC. A SCC rate order is expected in the spring of 2007.
On October 3, 2006, Bluefield Gas Company received a final order from the West Virginia PSC approving a rate increase of more than $300,000, based on normal weather. These new base rates were placed into effect on November 16, 2006. The final order moved the revenue calculations attributable to carrying cost associated with natural gas in storage and the gas cost portion of bad debts from a gas cost component to a non-gas component of rates included in the increase above. As a result, revenue to cover these costs will only be adjusted as a result of future non-gas rate filings and will not automatically be adjusted for the level and/or price on natural gas in storage, the price of natural gas included in bad debts or changes in interest rates. On January 4, 2007, Bluefield Gas Company filed a new rate application with the West Virginia PSC for an increase in non-gas rates of approximately $450,000. Any rate increase associated with the filing is expected to become effective in November 2007.
Capital Resources and Liquidity
Due to the capital intensive nature of Resources’ utility business, 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 $1,806,180 and $1,603,750 for the three-month periods ended December 31, 2006 and 2005, respectively. The Company’s total capital budget for the current year is nearly $6,000,000. It is anticipated that future capital expenditures will be funded with the combination of operating cash flow, sale of Company equity securities through the Dividend Reinvestment and Stock Purchase Plan and issuance of debt.
The level of borrowing under the Company’s line-of-credit agreements can fluctuate significantly due to the time of the year, changes in the wholesale price of energy and weather outside the normal temperature ranges. As the wholesale price of natural gas increases, short-term debt generally increases because the payment to the Company’s energy suppliers is due before the Company can recover its costs through the monthly billing of its customers. In
addition, colder weather requires the Company to purchase greater volumes of natural gas, the cost of which is recovered from customers on a delayed basis.
At December 31, 2006, the Company had available lines-of-credit for its short-term borrowing needs totaling $31,000,000, of which $11,816,000 was outstanding. The interest rates under the lines-of-credit are variable based upon 30 day LIBOR. These lines-of-credit expire March 31, 2007, unless extended. The Company anticipates being able to extend or replace the lines-of-credit upon expiration.
Stockholders equity increased by $1,323,170 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, 2006, the Company’s consolidated long-term capitalization was 58 percent equity and 42 percent debt.
ITEM 3 – QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market risks associated with interest rates and commodity prices. Interest rate risk is related to the Company’s outstanding long-term and short-term debt. Commodity price risk is experienced by the Company’s regulated natural gas operations. The Company’s risk management policy, as authorized by the Company’s Board of Directors, allows management to enter into derivatives for the purpose of managing commodity and financial market risks of its business operations.
Interest Rate Risk
The Company is exposed to market risk related to changes in interest rates associated with its borrowing activities. At December 31, 2006, the Company had $11,816,000 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, 2006 would have resulted in an increase in quarterly interest expense of approximately $35,000. The Company also has a $15,000,000 intermediate term variable rate note that is currently being hedged by a fixed rate interest swap. The balance of the long-term debt is at fixed rates.
Commodity Price Risk
The Company manages the price risk associated with purchases of natural gas by using a combination of fixed price contracts, gas storage injections and derivative commodity instruments including futures, price caps, swaps and collars. During the quarter, the Company used both storage gas and derivative swap 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, 2006, a hypothetical 10% reduction in the market price of natural gas would result in an increase of approximately $291,000 in the marked to market adjustment reflected on the Company’s balance sheet related to the 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, 2006, 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, 2006, 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 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, 2006, the Company issued a total of 820.489 shares of restricted stock pursuant to the Restricted Stock Plan as follows:
Investment Date
10/2/2006
11/1/2006
12/1/2006
ITEM 6 – EXHIBITS.
ExhibitNumber
Description
31.1
31.2
32.1
32.2
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.
Vice-President, Treasurer and Controller
(Principal Financial Officer)