UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For Quarter Ended June 30, 2006
Commission File Number 000-26591
RGC Resources, Inc.
(Exact name of Registrant as Specified in its Charter)
(540) 777-4427
(Registrant’s Telephone Number, Including Area Code)
None
(Former Name, Former Address and Former Fiscal Year, if Changed Since Last Report)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer” and “large accelerarted-filer” in Rule 12b-2 of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act) Yes ¨ No x
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
Class
Outstanding at July 31, 2006
Common Stock, $5 Par Value
RGC RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
UNAUDITED
June 30,
2006
September 30,
2005
ASSETS
Current Assets:
Cash and cash equivalents
Accounts receivable - (less allowance for uncollectibles of $1,033,540 and and $284,008, respectively)
Materials and supplies
Gas in storage
Prepaid income taxes
Deferred income taxes
Under-recovery of gas costs
Fair value of marked-to-market transactions
Other
Total current assets
Utility Property:
In service
Accumulated depreciation and amortization
In service, net
Construction work in progress
Utility plant, net
Nonutility Property:
Nonutility property
Nonutility property, net
Other assets
Total Assets
See notes to condensed consolidated financial statements.
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Borrowings under lines of credit
Dividends payable
Accounts payable
Customer deposits
Accrued expenses
Refunds from suppliers - due customers
Over-recovery of gas costs
Total current liabilities
Long-term Debt, Excluding Current Maturities
Deferred Credits and Other Liabilities
Asset retirement obligations
Deferred investment tax credits
Total deferred credits and other liabilities
Stockholders’ Equity:
Common stock, $5 par value; authorized,10,000,000 shares; issued and outstanding2,130,573 and 2,098,935 shares, respectively
Preferred stock, no par, authorized, 5,000,000 shares; no shares issued and outstanding
Capital in excess of par value
Retained earnings
Accumulated other comprehensive income (loss)
Total stockholders’ equity
Total Liabilities and Stockholders’ Equity
CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
FOR THE THREE-MONTH AND NINE-MONTH PERIODS ENDED JUNE 30, 2006 AND 2005
Three Months Ended
Nine Months Ended
Operating Revenues:
Gas utilities
Total operating revenues
Cost of Sales:
Total cost of sales
Gross Margin
Other Operating Expenses:
Operations
Maintenance
General taxes
Depreciation and amortization
Total other operating expenses
Operating Income
Other (Income) Expenses, net
Interest Expense
Income from Continuing Operations Before Income Taxes
Income Tax Expense from Continuing Operations
Income from Continuing Operations
Discontinued operations:
(Loss) Income from discontinued operations, net of income taxes of ($40,416), $87,555, $54,083 and $197,598, respectively
Net Income (Loss)
Other Comprehensive Income, Net of Tax
Comprehensive Income
Basic Earnings Per Common Share:
Income from continuing operations
Discontinued operations
Net income
Diluted Earnings Per Common Share:
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE NINE-MONTH PERIODS
ENDED JUNE 30, 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
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 discontinued operations
Net cash provided by operating activities
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant and nonutility property
Proceeds from disposal of utility and nonutility property
Proceeds from sale of short-term investments
Net cash used in continuing investing activities
Net cash provided by investing activities of discontinued operations
Net cash (used in) provided by 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 line-of-credit agreements
Proceeds from issuance of common stock
Cash dividends paid
Net cash used in financing activities
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
CASH AND CASH EQUIVALENTS AT END OF YEAR
SUPPLEMENTAL INFORMATION:
Cash paid during the year for:
Interest
Income taxes net of refunds
CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The Board of Directors approved the plan to sell the assets and operations of Highland Energy for several reasons. Competition from other energy marketing companies has put increasing downward pressure on already low margins. Significantly rising energy prices over the last few years have increased concern over credit risk of customers and increasing the margin on these sales to an acceptable level for the increased credit risk would likely negatively impact the ability to be competitive. The Board and company management believed the developing risk-return relationship of the energy marketing operations warranted exiting the business and monitizing the remaining value of existing customer service contracts.
Highland Energy and Resources agreed with Atmos for a period of three years ending July 1, 2009 to not sell any natural gas for consumption by an existing Highland Energy customer at any facility serviced under the assigned contracts with the exception of tariff gas sales by a public utility affiliate.
The purchase price for the assets sold by Highland Energy is valued at up to $414,270. Atmos will pay Highland Energy the sum of $233,216 at closing. The remaining $181,054 will be paid by Atmos to Highland Energy on the first annual anniversary of the closing provided that the remaining balance to be paid will be adjusted downward on a customer by customer basis by a prescribed amount to the extent (i) the customer pursuant an assigned contract is no longer a customer on the anniversary date and such customer was not a customer for two of the preceding twelve months, or (ii) the customer reduces their average natural gas consumption by more than 20 percent from current annualized levels.
As a result of the sale of the assets of Highland Energy, the Company recognized a loss of approximately $147,000 in June’s discontinued operations related to basis intended for future gas deliveries. Basis is defined as the transportation cost component of the gas purchase agreements necessary for pipeline utilization to transport customer gas purchases from supplier to the distribution company’s pipeline. The loss reflects the difference in the cost of such basis in excess of the net realizable value that Highland Energy would expect to receive for resale of the acquired basis as a result of recent declines in natural gas and natural gas basis prices.
Discontinued operations for the prior year also includes the lease income and sale from 10 parcels of real estate owned by Diversified’s propane operations.
The operations associated with both the energy marketing and the real estate activities were reclassified as Discontinued Operations in accordance with the provisions of SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. A summary of the components of discontinued operations is presented below.
Lease and sale of real estate
Energy marketing operations
Income taxes
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. Therefore, the Company is no longer required to separately disclose the information required under this standard.
Beginning
Jul 16, 2006
Sep 16, 2006
Nov 16, 2006
Feb 16, 2007
The line-of-credit agreements will expire March 31, 2007, unless extended. The Company anticipates being able to extend or replace the credit lines upon expiration. At June 30, 2006, the Company had $2,677,000 outstanding under its line of credit agreements.
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, 2006, 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 Virginia State Corporation Commission (SCC) and the West Virginia Public Service Commission (PSC) currently allow for full recovery of prudent costs associated with natural gas purchases, and any additional costs or benefits associated with the settlement of these instruments will be passed through to customers when realized.
The Company also entered into an interest rate swap related to the $15,000,000 note issued in November 2005. The swap essentially converted the floating rate note based upon LIBOR into fixed rate debt with a 5.74 percent interest rate. The swap qualifies as a cash flow hedge with changes in fair value reported in other comprehensive income.
A summary of other comprehensive income and derivative activity is provided below:
Three Months Ended June 30, 2006
Unrealized gains
Income tax expense
Net unrealized gains
Transfer of realized losses to income
Income tax benefit
Net transfer of realized losses to income
Net other comprehensive income
Three Months Ended June 30, 2005
Unrealized losses
Net unrealized losses
Nine Months Ended June 30, 2006
Fair value of marked to market transactions
Accumulated comprehensive income (loss)
Nine Months Ended June 30, 2005
Accumulated comprehensive 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 (gain) loss
Net periodic pension cost
Components of post-retirement benefit costs:
Amortization of unrecognized transition obligation
Recognized loss
Net periodic benefit cost
The Company contributed $575,000 to its pension plan for the nine-month period ended June 30, 2006. The Company expects to make a total contribution of approximately $800,000 to its pension plan and $700,000 to its post-retirement benefit plan during the fiscal year ending September 30, 2006.
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.
Subsequent to September 30, 2005, the Company has further evaluated its options as it relates to the application of Medicare Part D. Beginning in January 2006, the Company has dropped drug coverage under its medical plan for Medicare eligible retirees. In its place, the Company will provide eligible retirees with a reimbursement of premiums paid to a qualified prescription drug provider (“PDP”) whereby the PDP will provide the retiree with prescription drug coverage. Under the PDP, retirees have the ability to obtain drug coverage comparable to the coverage previously provided under the medical plan. This plan change will result in the Company’s medical plan not being actuarially equivalent to Medicare Part D. However, the change in the plan is not expected to have a material impact on the accumulated post-retirement benefit obligation and future expense due to the expected cost reductions under the revised plan as compared to the reductions attributable to the subsidy provisions available to actuarially equivalent plans.
In March 2005, the FASB issued FASB Interpretation (“FIN”) No. 47, Accounting for Conditional Asset Retirement Obligations – an Interpretation of FASB Statement No. 143. Diverse accounting practices had developed with respect to the timing of liability recognition of legal obligations associated with the retirement of a tangible long-lived asset when the timing and/or method of settlement of the obligation is conditional on a future event. FIN No. 47 provided clarification when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. This interpretation is effective for the Company September 30, 2006. The Company has not completed its evaluation of this interpretation and has not yet determined the impact on the Company’s financial position or results of operations.
ITEM 2 - MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Forward-Looking Statements
From time to time, the Company may publish forward-looking statements relating to such matters as anticipated financial performance, business prospects, technological developments, new products, research and development activities and similar matters. The Private Securities Litigation Reform Act of 1995 provides a safe harbor for forward-looking statements. In order to comply with the terms of the safe harbor, the Company notes that a variety of factors could cause the Company’s actual results and experience to differ materially from the anticipated results or other expectations expressed in the Company’s forward-looking statements. The risks and uncertainties that may affect the operations, performance, development and results of the Company’s business include the following: (i) failure to earn on a consistent basis an adequate return on invested capital; (ii) increasing expenses and labor costs and labor availability; (iii) price competition from alternative fuels; (iv) volatility in the price and availability of natural gas; (v) uncertainty in the projected rate of growth of natural gas requirements in the Company’s service area; (vi) general economic conditions both locally and nationally; (vii) increases in interest rates; (viii) volatility in actuarially determined benefit costs; (ix) increased customer delinquencies and conservation efforts resulting from high fuel costs and/or colder weather; (x) developments in electricity and natural gas deregulation and associated industry restructuring; (xi) variations in winter heating degree-days from normal; (xii) changes in environmental requirements, pipeline operating requirements and cost of compliance; (xiii) impact of potential increased governmental oversight and compliance costs due to the Sarbanes-Oxley Act; (xiv) failure to obtain timely rate relief for increasing operating or gas costs from regulatory authorities; (xv) ability to raise debt or equity capital; (xvi) impact of uncertainties in the Middle East and related terrorism issues; and (xvii) 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. The Company assumes no duty to update these statements should expectations change or actual results differ from current expectations.
General
RGC Resources, Inc. (“Resources” or the “Company”) is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately 59,300 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.
Since 1994, the Company also provided unregulated energy products through Diversified Energy Company, which operates as Highland Energy Company. Highland Energy brokers natural gas to certain industrial transportation customers of Roanoke Gas Company and Bluefield Gas Company. On July 10, 2006, Diversified Energy Company entered into an asset purchase agreement for the sale of its energy marketing operations. These operations as such are classified as discontinued operations. Please see the Discontinued Operations section below for further discussion. 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.
Management views warm winter weather; energy conservation, fuel switching and bad debts due to high energy prices; and competition from alternative fuels each as factors that could have a significant impact on the Company’s earnings.
For the quarter ended June 30, 2006, high energy prices, warmer than normal weather and competition from alternative energy sources were key concerns of management. Natural gas sales for the months of April and May appeared to be affected by both warmer weather and a continuation of the conservation trend experienced during the second quarter. Residential and commercial sales volumes declined by 18 percent from the same quarter last year, while heating degree-days (an industry measure by which the average daily temperature falls below 65 degrees Fahrenheit) declined by 25 percent. In addition, transportation sales (volumes delivered through the Company’s distribution pipeline but with the gas commodity purchased from someone other than Roanoke Gas or Bluefield Gas) continued to experience reductions from last year’s delivered natural gas volumes as discussed below.
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. However, the Company’s financial risk exposure to significantly warmer winter weather is partially mitigated by the provisions of a weather normalization adjustment (“WNA”) tariff for Roanoke Gas Company based on a weather occurrence band around the most recent 30-year temperature average. The weather band provides approximately a 6 percent range around normal weather, whereby if the number of heating-degree days falls within approximately 6 percent above or below the 30-year average, no adjustment is made. However, if the number of heating-degree days is more than 6 percent below the 30-year average, the Company’s WNA tariff adds a surcharge to customer bills equal to the equivalent margin lost beyond the approximate 6 percent heating-degree day deficiency. Likewise, if the number of heating-degree days is more than 6 percent above the 30-year average, the Company credits customer bills equal to the excess margin realized above the 6 percent heating-degree day excess. The measurement period in
determining the weather band extends from April through March. The heating-degree days for the period April 2005 through March 2006 were approximately 11 percent less than the 30-year average. The Company recorded approximately $327,000 in additional revenues in the prior quarter to reflect the impact of the WNA tariff for the difference in margin realized for weather between 11 percent and 6 percent warmer than the 30-year average. For the measurement period of April 2004 through March 2005, the heating-degree days were approximately 12 percent less than the 30-year average. As a result, the income statement for the nine-month period ended June 30, 2005 includes approximately $445,000 in additional revenues related to the application of the WNA tariff. On May 3, 2006, Roanoke Gas Company received approval for the WNA rate factors and billed its customers during the May billing cycle.
Results of Operations
Consolidated net income (loss) for the three-month and nine-month periods ended June 30, 2006 was ($56,959) and $3,552,297, respectively, compared to $229,525 and $3,918,639 for the same periods last year. Net income from continuing and discontinued operations is as follows:
Net Income
Continuing Operations
Three Months Ended June 30, 2006:
The table below reflects volume activity and heating degree-days.
Percentage
Delivered Volumes
Regulated Natural Gas (DTH)
Tariff Sales
Transportation
Total
Heating Degree Days
(Unofficial)
Tariff sales, primarily consisting of residential and commercial usage, declined 18 percent due to a decrease in heating degree-days and conservation. Transporting volumes, which generally correlate more with economic conditions rather than weather, reflected a reduction of 16 percent from the same period last year. This reduction in transporting volumes appears to be related to a combination of fuel switching and other economic factors. Over half of the reduction in transporting volumes relates to one industrial customer that has converted a majority of its processes to utilize coal as a means to reduce energy costs. Most of the remaining reduction is related to certain smaller industrial transportation customers closing their operations in the Roanoke area.
The table below reflects operating revenues.
Increase/(Decrease)
Operating Revenues
Gas Utilities
Total Operating Revenues
Total operating revenues from continuing operations for the three months ended June 30, 2006 decreased by $2,860,256 or 18 percent, compared to the same period last year, primarily due to a 17 percent decrease in total delivered natural gas volumes. Natural gas costs continued their decline from first quarter peak levels and have fallen slightly below last year’s levels for the quarter. The decline in sales volume resulted from the 25 percent decline in heating degree-days, reductions in industrial use of natural gas and conservation. Other revenues increased by 30 percent due to services provided under the Company’s master meter services program more than offsetting the services agreement with the Acquiror of Highland Propane Company to provide billing, facility and other services in the prior year.
Increase/
(Decrease)
Total Gross Margin
Total gross margin was nearly the same as the third quarter of fiscal 2005 with a decrease of $58,029, or 1 percent. Regulated natural gas margins were flat with a small increase of $37,682, or 1 percent, even though total delivered volume (tariff and transporting) decreased by 336,487 decatherms, or 17 percent.
Even with the reduction in natural gas deliveries, the Company was still able to realize a slight increase in regulated natural gas margins due to non-gas cost rate increases and the recovery of the financing costs (“carrying costs”) related to higher dollar investments in storage gas inventories. Both Roanoke Gas Company and Bluefield Gas Company placed increased rates into effect during the quarter ended December 31, 2005. Roanoke Gas Company’s rates were placed into effect subject to refund pending a final order from the Virginia SCC. Bluefield Gas Company’s rates were placed into effect in accordance with a final rate order issued by the West Virginia PSC. As a result of the new rates, the Company realized an increase in customer base charges, which is the flat monthly fee billed to each natural gas customer, as well as higher volumetric rates. The components of the gas utility margin increase are summarized below.
Net Margin Increase
Customer Base Charge including rate increase
WNA
Carrying Cost
Volumetric (rate increase and volume decrease)
Both Roanoke Gas and Bluefield Gas have approved rate structures in place that allow each company to accrue revenue to cover the financing costs related to the level of investment in natural gas inventory. Therefore, during times of rising gas costs and/or rising inventory levels, both companies recognize revenues to offset the higher financing costs; conversely, the companies pass along savings to customers if financing costs decrease due to lower inventory gas balances resulting from reductions in gas costs or volumes. The net effect of increased investment of gas in storage resulted in a $89,664 increase in revenues and margin. Due to much
warmer weather during the last two heating seasons, natural gas storage volumes have remained at higher levels than expected. As a result, carrying cost revenues have been at a higher level than would normally be expected. During periods of declining gas costs and storage gas levels, the Company will experience a reduction in revenues and margins as well. Based upon a stipulated agreement with the West Virginia PSC staff, subject to approval by the Commission, Bluefield Gas Company will no longer calculate a separate carrying cost revenue based on natural gas storage balances beginning in November 2006. Instead, these revenues will be included as part of the base non-gas rates and will only be adjusted as a result of rate case filings and not automatically adjusted for the level of inventory and/or the price of natural gas.
Other margins decreased by $95,711 due to the elimination of the services agreement with the Acquiror of Highland Propane Company to provide billing, facility and other services.
Operations expenses decreased by $25,112, or 1 percent, for the three-month period ended June 30, 2006 compared to the same period last year, as reductions in bad debt expense and a greater level of capitalized overheads more than offset higher employee benefit costs. The combination of the warm winter, energy conservation by customers and stabilizing energy prices all have contributed to reducing bad debt expense by more than $28,000. In addition, an increase in construction activity for the quarter has reduced operating expenses by $89,000 through the capitalization of a greater level of labor, benefits and administrative overhead. The Company experienced an increase of approximately $124,000 attributable to its pension and post-retirement medical plan due to the actuarial effect of reducing the discount rate used in expense and liability calculations as well as the adoption of new mortality tables in its most recent valuation. Maintenance expenses decreased $31,468, or 9 percent, from the same period last year. The decrease in maintenance primarily related to timing of repairs associated with pipeline leaks in the Company’s distribution system determined through leak surveys. The majority of the leaks identified through the survey were repaired during the first two quarters.
General taxes increased $18,382, or 5 percent, for the three-month period ended June 30, 2006 compared to the same period last year primarily due to increased business and occupation (B&O) taxes, a revenue sensitive tax, related to higher revenues in the West Virginia natural gas operations, as well as increased property taxes.
Net other income expense increased by $63,209 due to increase in investment income related to increasing interest rates on the Company’s temporary cash investments.
Interest expense increased by $96,459, or 21 percent, as the result of the combination of the Federal Reserve’s monetary policy, which resulted in higher interest rates on the Company’s variable rate debt, combined with a $4,200,000 increase in the Company’s average total outstanding debt during the quarter. The effective average interest rate on the Company’s outstanding lines-of-credit balances increased from 3.8 percent last year to 5.8 percent for the current period while the effective rate on long-term debt held steady at 6.6 percent.
Income tax expense decreased by $53,716, which corresponds to the reduction in pre-tax income on continuing operations for the quarter. The effective tax rate for the quarter was 41.3 percent.
Nine Months Ended June 30, 2006:
Total operating revenues from continuing operations for the nine months ended June 30, 2006 increased by $12,725,934, or 15 percent, compared to the same period last year, primarily due to higher gas costs during the winter heating season and the implementation of base rate increases more than offsetting reductions related to lower sales volumes associated with warmer weather and energy conservation. Although total tariff sales of the gas utilities declined by 8 percent, the average unit cost of natural gas delivered to customers increased by 29 percent as energy prices spiked in December due to the combination of cold weather and production issues in the Gulf of Mexico attributable to damage caused by hurricanes last year. Other revenues decreased by $113,962, or 17 percent, due to the elimination of the services agreement with the Acquiror of the assets of Highland Propane Company to provide billing, facility and other services.
Total gross margin increased by $1,027,519, or 5 percent, for the nine-month period ended June 30, 2006 over the same period last year. Regulated natural gas margins increased by $1,204,509, or 6 percent, even though total delivered volume (tariff and transporting) decreased by 857,486 decatherms, or 9 percent. The decline in delivered tariff volumes was attributable in part to weather that had 4 percent fewer heating degree-days; however, the greater impact surrounding the decline in volume resulted from customers’ energy conservation presumably in response to high natural gas prices. Transportation sales deliveries, composed of large industrial customers, declined by 11 percent due to energy costs and other economic factors as discussed above. Even though delivered volumes declined, the regulated natural gas margin increased due to non-gas cost rate increases and the recovery of the financing costs (“carrying costs”) related to rising interest rates and higher dollar investments in storage gas inventories. The components of the margin increase are summarized below:
Customer base charge including rate increase
Carrying cost
Other margins decreased by $176,990 due to the elimination of the services agreement with the Acquiror of Highland Propane Company to provide billing, facility and other services.
Operations expenses increased by $522,588, or 7 percent, for the nine-month period ended June 30, 2006 compared to the same period last year. The increase is primarily due to higher bad debt expense and employee benefit costs. Bad debt expense increased by approximately $110,000, or 28 percent. This increase corresponds to the increase in total revenues over the same period last year. The combination of a cold December and rapidly increasing natural gas costs generated concern that customer delinquencies would rise at a more than proportionate rate than sales. However, the combination of a much warmer than normal heating season and a decline in energy
prices over the last two quarters has eased pressure on customer delinquency issues, and although delinquencies are higher than last year, the level is consistent with the increase in sales. Employee benefit costs increased due to higher health care, pension and post-retirement benefit expenses. The Company had been self-insured for medical insurance purposes for the past several years with stop/loss coverage only for extremely high claim activity. The self-insurance program generated volatility in expense due to fluctuating claim levels. During the quarter ended December 31, 2004, claims expense was unusually low. In January 2005, the Company switched to fully insured coverage to provide a more predictable expense trend, which has reduced volatility between reporting periods but resulted in approximately $165,000 in higher cost in the first quarter. The Company also experienced an increase of approximately $329,000 attributable to its pension and post-retirement medical plan due to the actuarial effect of reducing the discount rate used in expense and liability calculations as well as the adoption of new mortality tables in its most recent valuation. Maintenance expenses increased $71,889, or 7 percent, over the same period last year. The increase in maintenance primarily related to repairs of pipeline leaks in the Company’s distribution system determined through leak surveys.
General taxes increased $126,300, or 10 percent, for the nine-month period ended June 30, 2006 compared to the same period last year primarily due to an 18 percent increase in business and occupation taxes, a revenue sensitive tax, related to higher revenues in the West Virginia natural gas operations, as well as increased payroll and property taxes.
Other income, net, increased by $18,949 due to a loss last year related to the retirement and disposal of an old propane air facility.
Interest expense increased by $376,144, or 25 percent, due to the combination of rising interest rates and a $4,000,000 increase in the average total debt outstanding during the period. The effective average interest rate on the Company’s variable rate lines-of-credit balances increased from 3.0 percent last year to 5.0 percent this year.
Income tax expense decreased by $91,757, which corresponds to the decrease in pre-tax income on continuing operations. The effective tax rate remained consistent with the same period last year at 38.2 percent.
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, 2006. The total revenues and margins realized during the first nine months reflect higher billings and margins 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 10, 2006, Diversified Energy Company d/b/a Highland Energy, a wholly owned subsidiary of RGC Resources, Inc. (“Resources” or “Company”), entered into an asset purchase
and sale agreement for the sale of the assets relating to its energy marketing business to Atmos Energy Marketing, LLC (“Atmos”). The assets sold include the gas supply contracts between Highland Energy and its customers and related business records. The date of transfer was set as the date from the first meter read performed for each of the end user customers on or after August 1, 2006.
Discontinued operations for the prior year also includes the lease income and gain on sale of 10 parcels of real estate previously used in Diversified’s propane operations.
Discontinued Operations:
Critical Accounting Policies
The consolidated financial statements of RGC Resources, Inc. are prepared in accordance with accounting principles generally accepted in the United States of America. The amounts of assets, liabilities, revenues and expenses reported in the Company’s financial statements are affected by accounting policies, estimates and judgments that are necessary to comply with generally accepted accounting principles. Estimates used in the financial statements are derived from prior experience, statistical analysis and professional judgments. Actual results could differ from the estimates, which would affect the related amounts reported in the Company’s financial statements. The following policies and estimates are important to understanding certain key components of the financial statements.
Revenue recognition –Regulated utility sales and transportation revenues are based upon rates approved by the SCC for Roanoke Gas Company and the PSC for Bluefield Gas Company. The non-gas cost component of rates may not be changed without a formal rate increase application and corresponding authorization by the appropriate regulatory commission; however, the gas cost component of rates may be adjusted periodically through the PGA mechanism with approval from the respective commission. Roanoke Gas Company also has a WNA, which is designed to partially offset the impact of weather that is either more than 6 percent warmer than normal or 6 percent colder than normal over a 12 month period. Under the Company’s unregulated energy marketing operations, revenues are recognized when the natural gas is delivered based on the contracted or market price.
The Company bills its regulated natural gas customers on a monthly cycle. The billing cycle periods for most customers do not coincide with the accounting periods used for financial reporting. The Company accrues estimated revenue for natural gas delivered to customers not yet billed during the accounting period. Determination of unbilled revenue relies on the use of estimates and current and historical data. As of June 30, 2006, the financial statements included unbilled revenue of $1,286,737. 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 Commission orders, Commission staff reports, historical experience and discussions with the regulatory body and other relevant factors.
Bad debt reserves – The Company evaluates the collectibility of its accounts receivable balances based upon a variety of factors including loss history, level of delinquent account balances and general economic climate.
Retirement plans – The Company offers a defined benefit pension plan (“pension plan”) and a postretirement medical plan (“postretirement plan”) to eligible employees. The expenses and liabilities associated with these plans are determined through actuarial means requiring the estimation of certain assumptions and factors. In regard to the pension plan, these factors include assumptions regarding discount rate, expected long-term rate of return on plan assets, compensation increases and life expectancies, among others. Similarly, the postretirement medical plan also requires the estimation of many of the same factors as the pension plan in addition to assumptions regarding future medical costs and Medicare availability. Actual results may differ materially from the results expected from the actuarial assumptions due to changing economic conditions, volatility in interest rates and changes in life expectancy to name a few. Such differences may result in a material impact on the amount of expense recorded in future periods or the value of the obligations on the balance sheet.
Derivatives – As discussed in the “Item 3—Qualitative and Quantitative Disclosures about Market Risk” section below, the Company hedges certain risks incurred in the normal operation of business through the use of derivative instruments. The Company applies the requirements of Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, which requires the recognition of all derivative instruments as assets or liabilities in the Company’s balance sheet at fair value. In most instances, fair value is based upon quoted futures prices for the natural gas commodities and interest rate futures for interest rate swaps. Changes in the commodity and futures markets will impact the estimates of fair value in the future. Furthermore, the actual market value at the point of realization of the derivative may be significantly different from the values used in determining fair value in prior financial statements.
Regulatory accounting – The Company’s regulated operations follow the accounting and reporting requirements of Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation. The economic effects of regulation can result in a regulated company deferring costs that have been or are expected to be recovered from customers in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this results, costs are deferred as assets in the consolidated balance sheet (regulatory assets) and recorded as expenses when such amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for the amounts previously collected from customers and for current collection in rates of costs that are expected to be incurred in the future (regulatory liabilities).
Asset Management
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. 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 commodity prices for the quarter were comparable to those for the previous year. The NYMEX natural gas contract for a decatherm of natural gas settled this quarter averaged $6.785, compared to $6.730 for the same period the previous year.
Even though natural gas prices remain at high levels in relation to historical prices, management believes that it has planned for adequate supplies to fulfill projected customer needs for the upcoming heating season. 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, higher interest costs because the delay in recovering higher gas costs requires borrowing to temporarily fund receivables from customers and reduced energy consumption due to conservation and conversion to alternative fuel sources. The Company’s current 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 does not protect the Company from increased rate of bad debts or increases in interest rates.
Regulatory Affairs
On October 23, 2005, Roanoke Gas Company placed rates into effect providing for approximately $2.0 million in additional annual non-gas revenues subject to refund. In March 2006, Roanoke Gas Company reached a stipulated agreement with the SCC staff for a rate award of $1,663,456. Roanoke Gas received approval from the SCC Hearing Examiner to implement rates designed to collect $1,663,456 in additional annual non-gas revenues beginning April 1, 2006. On April 6, 2006, the SCC issued a final rate order approving the stipulated agreement. Roanoke Gas Company has completed the refund to its customers of $124,310 in excess revenues and accrued interest associated with the higher rates placed into effect in October 2005. The Company had provided for the expected refund in prior quarters. Management filed a notice of intent in July to inform the SCC of Roanoke Gas Company’s plan to file a new request for rate increase in September.
On January 19, 2006, Bluefield Gas Company filed an application with the West Virginia PSC for an increase in non-gas rates of $198,841, or 1.7 percent. On July 6, 2006, the Company jointly filed with West Virginia PSC staff a stipulated agreement proposing a non-gas rate increase of $337,000. The stipulated increase is greater than the amount requested by the Company reflecting the PSC staff’s recommended removal of both the inventory carrying cost and the gas cost component of bad debts from recovery through the PGA mechanism and incorporating these items back into non-gas rates. The result of the change in recovery mechanism to non-gas rates is to put these operating costs on the same basis as all other non-gas operating expenses. The stipulation has not been approved by the West Virginia PSC, but its approval is expected with a likely November 2006 rate implementation.
Environmental Issues
Both Roanoke Gas Company and Bluefield Gas Company, subsidiaries of RGC Resources, Inc., operated manufactured gas plants (MGPs) as a source of fuel for lighting and heating until the early 1950’s. A by-product of operating MGPs was coal tar, and the potential exists for on-site tar waste contaminants at the former plant sites. The extent of contaminants at these sites, if any, is unknown at this time. An analysis at the Bluefield Gas Company site indicates some soil contamination. The Company, with concurrence of legal counsel, does not believe any events have occurred requiring regulatory reporting. Further, the Company has not received any notices of violation or liabilities associated with environmental regulations related to the MGP sites and is not aware of any off-site contamination or pollution as a result of prior operations. Therefore, the Company has no plans for subsurface remediation at the MGP sites. Should the Company eventually be required to remediate either site, the Company will pursue all prudent and reasonable means to recover any related costs, including insurance claims and regulatory approval for rate case recognition of expenses associated with any work required. A stipulated rate case agreement between the Company and the West Virginia Public Service Commission recognized the Company’s right to defer MGP clean-up costs, should any be incurred, and to seek rate relief for such costs. If the Company eventually incurs costs associated with a required clean-up of either MGP site, the Company anticipates recording a regulatory asset for such clean-up costs to be recovered in future rates. Based on anticipated regulatory actions and current practices, management believes that any costs incurred related to this matter will not have a material effect on the Company’s financial condition or results of operations.
Capital Resources and Liquidity
Due to the capital intensive nature of Resources’ utility and energy businesses, as well as the related weather sensitivity, Resources’ primary capital needs are the funding of its continuing construction program and the seasonal funding of its natural gas inventories and accounts receivable. The Company’s construction program is composed of a combination of replacing
aging bare steel and cast iron pipe with new plastic or coated steel pipe and expansion of its natural gas system to meet the demands of customer growth. Total capital expenditures from continuing operations were $5,488,411 and $5,406,850 for the nine-month periods ended June 30, 2006 and 2005, respectively. The Company’s total capital budget for the current year is approximately $7,410,000. It is anticipated that future capital expenditures will be funded with the combination of operating cash flow, sale of Company equity securities through the Dividend Reinvestment and Stock Purchase Plan and issuance of debt.
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 24, 2006, 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 multi-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 multi-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. Effective with the execution of the new agreements, the Company’s total available limits under the lines-of-credit are as follows:
The line-of-credit agreements will expire March 31, 2007, unless extended. The Company anticipates being able to extend or replace the credit lines upon expiration. At June 30, 2006, the Company had $2,677,000 outstanding under its line-of-credit agreements.
In November 2005, Roanoke Gas Company and Bluefield Gas Company each entered into agreements to refinance maturing debt. Roanoke Gas Company entered into an unsecured 5-year variable rate note with provision for annual renewals thereafter in the amount of $15,000,000.
The proceeds of this note were used to refinance the $8,000,000 unsecured note due November 30, 2005 and $4,000,000 in outstanding line-of-credit balance. The remainder of the proceeds was used to call the $3,000,000 collateralized term debenture due in 2016, including a call premium of $206,250. Bluefield Gas Company entered into an unsecured 31-month variable rate note in the amount of $2,000,000. The proceeds from this note were used to refinance the $2,000,000 unsecured note due November 21, 2005. The Company entered into an interest rate swap agreement on the Roanoke Gas note for the purpose of fixing the interest rate over the total term of the note.
Stockholders equity increased by $3,195,159 for the nine months ended June 30, 2006, 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 income
Increase in stockholders’ equity
At June 30, 2006, the Company’s consolidated long-term capitalization was 58 percent equity and 42 percent debt.
ITEM 3 - MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
Interest Rate Risk
The Company is exposed to market risk related to changes in interest rates associated with its borrowing activities. At June 30, 2006, the Company had $2,677,000 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, 2006 would have resulted in an increase in quarterly interest expense of approximately $12,000. 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 storage gas for the purpose of hedging the price of natural gas for heating season use. The Company did not utilize any derivative instruments for the purposes of hedging natural gas during the quarter. If the Company had entered into derivative instruments in its regulated natural gas operations, any cost incurred or benefit received from such 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, 2006, the Company had no 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 June 30, 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 June 30, 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 June 30, 2006, the Company issued a total of 839.917 shares of restricted stock pursuant to the Restricted Stock Plan as follows:
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.
By:
/s/ Howard T. Lyon
Howard T. Lyon
Vice-President, Treasurer and Controller
(Principal Financial Officer)