UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For Quarterly Period Ended March 31, 2009
Commission File Number 000-26591
RGC Resources, Inc.
(Exact name of Registrant as Specified in its Charter)
| VIRGINIA | 54-1909697 | |
(State or Other Jurisdiction of Incorporation or Organization) | (I.R.S. Employer Identification No.) | |
| 519 Kimball Ave., N.E., Roanoke, VA | 24016 | |
| (Address of Principal Executive Offices) | (Zip Code) | |
(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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer,” “accelerarted-filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
| Large accelerated filer | ¨ | Accelerated filer | ¨ | |||
| Non-accelerated filer | ¨ (Do not check if a smaller reporting company) | Smaller reporting company | 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 April 30, 2009 | |
| Common Stock, $5 Par Value | 2,224,281 |
RGC RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
UNAUDITED
| ASSETS | March 31, 2009 | September 30, 2008 | ||||||
| Current Assets: | ||||||||
Cash and cash equivalents | $ | 10,509,377 | $ | 875,436 | ||||
Short-term investments | — | 500,000 | ||||||
Accounts receivable - (less allowance for uncollectibles of $495,707 and $63,791, respectively) | 10,628,608 | 5,086,790 | ||||||
Note receivable | 87,000 | 87,000 | ||||||
Materials and supplies | 616,039 | 553,604 | ||||||
Gas in storage | 10,078,162 | 26,122,686 | ||||||
Prepaid income taxes | — | 1,479,693 | ||||||
Deferred income taxes | 4,254,541 | 2,187,795 | ||||||
Under-recovery of gas costs | — | 1,013,087 | ||||||
Other | 1,110,937 | 505,761 | ||||||
Total current assets | 37,284,664 | 38,411,852 | ||||||
| Utility Property: | ||||||||
In service | 115,614,534 | 113,533,184 | ||||||
Accumulated depreciation and amortization | (40,401,439 | ) | (39,038,120 | ) | ||||
In service, net | 75,213,095 | 74,495,064 | ||||||
Construction work in progress | 1,243,202 | 1,113,008 | ||||||
Utility plant, net | 76,456,297 | 75,608,072 | ||||||
| Other Assets: | ||||||||
Note receivable | 1,126,000 | 1,213,000 | ||||||
Regulatory assets | 2,722,934 | 2,762,241 | ||||||
Other | 127,403 | 132,549 | ||||||
Total other assets | 3,976,337 | 4,107,790 | ||||||
Total Assets | $ | 117,717,298 | $ | 118,127,714 | ||||
See notes to condensed consolidated financial statements.
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RGC RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
UNAUDITED
| LIABILITIES AND STOCKHOLDERS’ EQUITY | March 31, 2009 | September 30, 2008 | ||||||
| Current Liabilities: | ||||||||
Borrowings under lines of credit | $ | — | $ | 13,960,000 | ||||
Dividends payable | 711,770 | 690,538 | ||||||
Accounts payable | 6,572,434 | 8,215,319 | ||||||
Customer credit balances | 2,457,418 | 4,237,043 | ||||||
Income taxes payable | 277,674 | 3,206 | ||||||
Customer deposits | 1,730,578 | 1,522,480 | ||||||
Accrued expenses | 1,531,788 | 2,111,614 | ||||||
Over-recovery of gas costs | 6,968,326 | — | ||||||
Fair value of marked to market transactions | 3,205,853 | 875,487 | ||||||
Total current liabilities | 23,455,841 | 31,615,687 | ||||||
Long-term Debt | 28,000,000 | 23,000,000 | ||||||
| Deferred Credits and Other Liabilities: | ||||||||
Asset retirement obligations | 2,674,128 | 2,608,995 | ||||||
Regulatory cost of retirement obligations | 7,273,999 | 6,843,338 | ||||||
Benefit plan liabilities | 5,023,289 | 4,768,785 | ||||||
Deferred income taxes | 5,440,045 | 5,471,667 | ||||||
Deferred investment tax credits | 81,106 | 96,184 | ||||||
Total deferred credits and other liabilities | 20,492,567 | 19,788,969 | ||||||
| Stockholders’ Equity: | ||||||||
Common stock, $5 par value; authorized, 10,000,000 shares; issued and outstanding 2,223,106 and 2,209,471, respectively | 11,115,530 | 11,047,355 | ||||||
Preferred stock, no par, authorized, 5,000,000 shares; no shares issued and outstanding | — | — | ||||||
Capital in excess of par value | 16,276,779 | 15,990,961 | ||||||
Retained earnings | 21,036,551 | 17,909,134 | ||||||
Accumulated other comprehensive loss | (2,659,970 | ) | (1,224,392 | ) | ||||
Total stockholders’ equity | 45,768,890 | 43,723,058 | ||||||
Total Liabilities and Stockholders’ Equity | $ | 117,717,298 | $ | 118,127,714 | ||||
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RGC RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
FOR THE THREE-MONTH AND SIX-MONTH PERIODS ENDED MARCH 31, 2009 AND 2008
UNAUDITED
| Three Months Ended March 31, | Six Months Ended March 31, | ||||||||||||||
| 2009 | 2008 | 2009 | 2008 | ||||||||||||
Operating Revenues: | |||||||||||||||
Gas utilities | $ | 34,003,752 | $ | 39,349,932 | $ | 62,195,675 | $ | 64,904,575 | |||||||
Other | 282,750 | 214,446 | 550,022 | 400,711 | |||||||||||
Total operating revenues | 34,286,502 | 39,564,378 | 62,745,697 | 65,305,286 | |||||||||||
Cost of Sales: | |||||||||||||||
Gas utilities | 24,821,377 | 30,827,646 | 45,064,717 | 49,124,375 | |||||||||||
Other | 132,806 | 83,916 | 252,624 | 159,266 | |||||||||||
Total cost of sales | 24,954,183 | 30,911,562 | 45,317,341 | 49,283,641 | |||||||||||
Gross Margin | 9,332,319 | 8,652,816 | 17,428,356 | 16,021,645 | |||||||||||
Other Operating Expenses: | |||||||||||||||
Operations | 2,779,088 | 2,508,872 | 5,384,594 | 5,107,495 | |||||||||||
Maintenance | 385,334 | 325,252 | 787,264 | 676,409 | |||||||||||
General taxes | 322,292 | 311,430 | 630,177 | 602,842 | |||||||||||
Depreciation and amortization | 1,140,517 | 1,092,262 | 2,279,035 | 2,175,760 | |||||||||||
Total other operating expenses | 4,627,231 | 4,237,816 | 9,081,070 | 8,562,506 | |||||||||||
Operating Income | 4,705,088 | 4,415,000 | 8,347,286 | 7,459,139 | |||||||||||
Other Income, net | 21,883 | 16,737 | 55,690 | 61,067 | |||||||||||
Interest Expense | 462,910 | 518,029 | 994,230 | 1,082,511 | |||||||||||
Income from Continuing Operations Before Income Taxes | 4,264,061 | 3,913,708 | 7,408,746 | 6,437,695 | |||||||||||
Income Tax Expense from Continuing Operations | 1,620,368 | 1,495,099 | 2,815,894 | 2,453,078 | |||||||||||
Income from Continuing Operations | 2,643,693 | 2,418,609 | 4,592,852 | 3,984,617 | |||||||||||
Discontinued operations: | |||||||||||||||
Loss from discontinued operations, net of income taxes of ($14,628) | — | — | — | (36,690 | ) | ||||||||||
Net Income | 2,643,693 | 2,418,609 | 4,592,852 | 3,947,927 | |||||||||||
Other Comprehensive Income (Loss), Net of taxes | 173,330 | (447,040 | ) | (1,446,799 | ) | (804,878 | ) | ||||||||
Comprehensive Income | $ | 2,817,023 | $ | 1,971,569 | $ | 3,146,053 | $ | 3,143,049 | |||||||
Basic Earnings Per Common Share: | |||||||||||||||
Income from continuing operations | $ | 1.19 | $ | 1.10 | $ | 2.07 | $ | 1.82 | |||||||
Discontinued operations | — | — | — | (0.02 | ) | ||||||||||
Net income | $ | 1.19 | $ | 1.10 | $ | 2.07 | $ | 1.80 | |||||||
Diluted Earnings Per Common Share: | |||||||||||||||
Income from continuing operations | $ | 1.19 | $ | 1.10 | $ | 2.07 | $ | 1.81 | |||||||
Discontinued operations | — | — | — | (0.02 | ) | ||||||||||
Net income | $ | 1.19 | $ | 1.10 | $ | 2.07 | $ | 1.79 | |||||||
Dividends Declared Per Common Share | $ | 0.3200 | $ | 0.3125 | $ | 0.6400 | $ | 0.6250 | |||||||
See notes to condensed consolidated financial statements.
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RGC RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE SIX-MONTH PERIODS
ENDED MARCH 31, 2009 AND 2008
UNAUDITED
| Six Months Ended March 31, | ||||||||
| 2009 | 2008 | |||||||
| CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||||
Income from continuing operations | $ | 4,592,852 | $ | 3,984,617 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||
Depreciation and amortization | 2,394,901 | 2,278,220 | ||||||
Cost of removal of utility plant, net | (115,899 | ) | (115,390 | ) | ||||
Changes in assets and liabilities which used cash, exclusive of changes and noncash transactions shown separately | 14,872,111 | 6,130,227 | ||||||
Net cash provided by continuing operating activities | 21,743,965 | 12,277,674 | ||||||
Net cash used in discontinued operations | — | (240,967 | ) | |||||
Net cash provided by operating activities | 21,743,965 | 12,036,707 | ||||||
| CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||
Additions to utility plant and nonutility property | (2,719,571 | ) | (3,293,881 | ) | ||||
Proceeds from disposal of equipment | 27,826 | — | ||||||
Proceeds from sale of short-term investments | 500,000 | — | ||||||
Proceeds from sale of Bluefield Operations | — | 3,941,000 | ||||||
Net cash provided by (used in) continuing investing activities | (2,191,745 | ) | 647,119 | |||||
Net cash used in discontinued investing activities | — | (12,360 | ) | |||||
Net cash provided by (used in) investing activities | (2,191,745 | ) | 634,759 | |||||
| CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||
Proceeds from issuance of long-term debt | 5,000,000 | — | ||||||
Proceeds on collection of note | 87,000 | — | ||||||
Net repayments under line-of-credit agreements | (13,960,000 | ) | (4,808,000 | ) | ||||
Proceeds from issuance of common stock | 353,993 | 432,021 | ||||||
Cash dividends paid | (1,399,272 | ) | (1,353,078 | ) | ||||
Net cash used in continuing financing activities | (9,918,279 | ) | (5,729,057 | ) | ||||
Net cash provided by discontinued financing activities | — | 365,000 | ||||||
Net cash used in financing activities | (9,918,279 | ) | (5,364,057 | ) | ||||
NET INCREASE IN CASH AND CASH EQUIVALENTS | 9,633,941 | 7,307,409 | ||||||
BEGINNING CASH AND CASH EQUIVALENTS | 875,436 | 1,408,317 | ||||||
ENDING CASH AND CASH EQUIVALENTS | $ | 10,509,377 | $ | 8,715,726 | ||||
| SUPPLEMENTAL INFORMATION: | ||||||||
Cash paid during the year for: | ||||||||
Interest | $ | 989,877 | $ | 1,186,998 | ||||
Income taxes net of refunds | 2,269,308 | 1,212,921 | ||||||
Noncash Transactions:
A note in the amount of $1,300,000 was received as partial payment for the sale of the assets associated with the Bluefield division of Roanoke Gas Company in November 2007.
See notes to condensed consolidated financial statements.
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RGC RESOURCES, INC. AND SUBSIDIARIES
CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS UNAUDITED
| 1. | Basis of Presentation |
In the opinion of management, the accompanying unaudited condensed consolidated financial statements contain all adjustments (consisting of only normal recurring accruals) necessary to present fairly RGC Resources, Inc.’s financial position as of March 31, 2009 and the results of its operations for the three months and six months ended March 31, 2009 and 2008 and its cash flows for the six months ended March 31, 2009 and 2008. The results of operations for the three months and six months ended March 31, 2009 are not indicative of the results to be expected for the fiscal year ending September 30, 2009 as quarterly earnings are affected by the highly seasonal nature of the business and weather conditions generally result in greater earnings during the winter months.
The condensed consolidated interim financial statements and condensed notes are presented as permitted by Form 10-Q and do not contain certain information included in the Company’s annual consolidated financial statements and notes thereto. The condensed consolidated financial statements and condensed notes should be read in conjunction with the financial statements and notes contained in the Company’s Form 10-K. The September 30, 2008 balance sheet was included in the Company’s Form 10-K.
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
| 2. | Discontinued Operations |
Effective as of October 31, 2007, Resources closed on the sale of the stock of Bluefield Gas Company (“Bluefield”) to ANGD, LLC, and Roanoke Gas Company completed the sale of its natural gas distribution assets located in the Town of Bluefield and the County of Tazewell, Virginia (“Bluefield division of Roanoke Gas”) to Appalachian Natural Gas Company, a subsidiary of ANGD, LLC. The sale of both the stock and the assets was essentially at book value and included the receipt of a $1,300,000 note from ANGD to partially finance the transaction. The note has a 5-year term with a 15-year amortization schedule with annual principal payments and quarterly interest payments at a rate of 10%.
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RGC RESOURCES, INC. AND SUBSIDIARIES
The components of discontinued operations are summarized below:
| Six Months Ended | ||||
| March 31, 2008 | ||||
Bluefield Operations | ||||
Total Revenues | $ | 457,777 | ||
Pretax Operating Income | (105,216 | ) | ||
Continuing Costs | 53,898 | |||
Income Tax Expense | 14,628 | |||
Discontinued Operations | $ | (36,690 | ) | |
| 3. | Debt |
On March 23, 2009, the Company and Wachovia Bank renewed its line of credit agreement. The new agreement increased the variable interest rate to 30 day LIBOR plus 100 basis points and includes an availability fee equal to 15 basis points applied to the difference between the face amount of the note and the average outstanding balance during the period. The Company maintained the multi-tiered borrowing limits to accommodate the Company’s seasonal borrowing demands and to minimize its borrowing costs. Effective April 1, 2009, the Company’s total available limits during the term of the line-of-credit agreement range from $1,000,000 to $18,000,000.
The line-of-credit agreement will expire March 31, 2010, unless extended. The Company anticipates being able to extend or replace the credit line upon expiration. At March 31, 2009, the Company had no outstanding balance under its line-of-credit agreement.
| 4. | Rates and Regulatory Matters |
On November 1, 2008, Roanoke Gas Company placed into effect new base rates that provide for approximately $1,198,000 in additional annual revenues. On March 5, 2009, the Company reached a stipulated agreement with the Virginia State Corporation Commission (“SCC”) staff for a non-gas rate award for the total of the $1,198,000 in additional annual revenues requested. This stipulated agreement is subject to approval by the SCC Commissioners; however, the Company does not expect the final order from the SCC to differ from the stipulated agreement.
| 5. | Derivatives and Hedging |
The Company’s risk management policy allows management to enter into derivatives for the purpose of managing commodity and financial market risks of its business operations. The Company’s risk management policy specifically prohibits the use of derivatives for speculative purposes. The key market risks that the Company would seek to hedge include the price of natural gas and the cost of borrowed funds.
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RGC RESOURCES, INC. AND SUBSIDIARIES
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 March 31, 2009, the Company had settled all outstanding derivative collar arrangements for the purchase of natural gas. Net income and other comprehensive income were not affected by the change in market value as any prudently incurred cost or benefit received from these instruments was recoverable or refunded through the regulated natural gas purchased gas adjustment (“PGA”) mechanism.
The Company has two interest rate swaps associated with their variable rate notes. The first swap relates to the $15,000,000 note issued in November 2005. This swap essentially converts the floating rate note based upon LIBOR into fixed rate debt with a 5.74% interest rate. The second swap relates to the $5,000,000 variable rate note issued in October 2008. This swap converts the variable rate note based on LIBOR into a fixed rate debt with a 5.79% effective interest rate. Both swaps qualify as cash flow hedges with changes in fair value reported in other comprehensive income. No portions of interest rate swaps were deemed ineffective.
The table below reflects the fair values of the derivative instruments and their corresponding classification in the consolidated balance sheets under the current liabilities caption of “Fair value of marked to market transactions” as of March 31, 2009 and September 30, 2008:
Fair Value of Derivative Instruments
| March 31, 2009 | September 30, 2008 | |||||
Derivatives designated as hedging instruments: | ||||||
Interest rate swaps | $ | 3,205,853 | $ | 837,637 | ||
Natural gas collar arrangement | — | 37,850 | ||||
Total derivatives designated as hedging instruments | $ | 3,205,853 | $ | 875,487 | ||
The table in Note 6 below reflects the effect on income and other comprehensive income of the Company’s cash flow hedge.
Based on the current interest rate environment, approximately $840,000 of the fair value on the interest rate hedges will be reclassified from other comprehensive loss and into interest expense on the income statement over the next 12 months. Changes in LIBOR rates during that period could significantly change the estimated amount to be reclassified to income as well as the fair value of the interest rate hedges.
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RGC RESOURCES, INC. AND SUBSIDIARIES
| 6. | Comprehensive Income |
A summary of other comprehensive income and loss (“OCI”) is provided below:
| Three Months Ended March 31, | Six Months Ended March 31, | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
Interest Rate SWAPs | ||||||||||||||||
Unrealized gains (losses) reflected in OCI | $ | 61,379 | $ | (781,418 | ) | $ | (2,671,626 | ) | $ | (1,375,675 | ) | |||||
Income tax | (23,299 | ) | 296,626 | 1,014,150 | 522,206 | |||||||||||
Net unrealized gains (losses) reflected in OCI | 38,080 | (484,792 | ) | (1,657,476 | ) | (853,469 | ) | |||||||||
Transfer of realized losses from OCI to interest expense | 199,919 | 49,046 | 303,410 | 54,711 | ||||||||||||
Income tax | (75,890 | ) | (18,618 | ) | (115,175 | ) | (20,768 | ) | ||||||||
Net transfer of realized losses from OCI to interest expense | 124,029 | 30,428 | 188,235 | 33,943 | ||||||||||||
Defined Benefit Plans | ||||||||||||||||
Transfer of realized losses to income | 6,313 | — | 12,626 | — | ||||||||||||
Income tax | (2,396 | ) | — | (4,792 | ) | — | ||||||||||
Net transfer of realized losses to income | 3,917 | — | 7,834 | — | ||||||||||||
Amortization of transition obligation | 11,773 | 11,806 | 23,546 | 23,612 | ||||||||||||
Income tax | (4,469 | ) | (4,482 | ) | (8,938 | ) | (8,964 | ) | ||||||||
Net amortization of transition obligation | 7,304 | 7,324 | 14,608 | 14,648 | ||||||||||||
Net other comprehensive income (loss) | $ | 173,330 | $ | (447,040 | ) | $ | (1,446,799 | ) | $ | (804,878 | ) | |||||
Change in measurement date - SFAS No. 158 | — | — | 11,221 | — | ||||||||||||
Accumulated comprehensive loss - beginning of period | (2,833,300 | ) | (833,093 | ) | (1,224,392 | ) | (475,255 | ) | ||||||||
Accumulated comprehensive loss - end of period | $ | (2,659,970 | ) | $ | (1,280,133 | ) | $ | (2,659,970 | ) | $ | (1,280,133 | ) | ||||
| 7. | Weighted Average Shares |
Basic earnings per common share for the three months and six months ended March 31, 2009 and 2008 are calculated by dividing net income by the weighted average common shares outstanding during the period. Diluted earnings per common share for the three months and
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RGC RESOURCES, INC. AND SUBSIDIARIES
six months ended March 31, 2009 and 2008 are calculated by dividing net income by the weighted average common shares outstanding during the period plus dilutive potential common shares. Dilutive potential common shares are calculated in accordance with the treasury stock method, which assumes that proceeds from the exercise of all options are used to repurchase common stock at market value. The amount of shares remaining after the proceeds are exhausted represents the potentially dilutive effect of the securities. A reconciliation of the weighted average common shares and the diluted average common shares is provided below:
| Three Months Ended March 31, | Six Months Ended March 31, | |||||||
| 2009 | 2008 | 2009 | 2008 | |||||
Weighted average common shares | 2,219,068 | 2,198,624 | 2,215,733 | 2,195,048 | ||||
Effect of dilutive securities: | ||||||||
Options to purchase common stock | 7,088 | 9,519 | 7,424 | 10,147 | ||||
Diluted average common shares | 2,226,156 | 2,208,143 | 2,223,157 | 2,205,195 | ||||
During the quarter ended March 31, 2009, 2,000 shares of common stock were issued upon exercise of options under the Company’s Key Employee Stock Option Plan. The options had an exercise price of $20.875.
| 8. | Commitments and Concentrations |
Roanoke Gas currently holds the only franchises and/or certificates of public convenience and necessity to distribute natural gas in its service area. These franchises are effective through January 1, 2016. Certificates of public convenience and necessity in Virginia are exclusive and are intended for perpetual duration. Due to the nature of the natural gas distribution business, the Company has entered into agreements with both suppliers and pipelines to contract for natural gas commodity purchases, storage capacity and pipeline delivery capacity. The Company obtains most of its regulated natural gas supply from the asset management contract between Roanoke Gas and the asset manager. The Company uses an asset manager to assist in optimizing the use of its transportation, storage rights, and gas supply to provide a secure and reliable source of natural gas to its customers. Roanoke Gas is served directly by two primary pipelines. These two pipelines deliver 100% of the natural gas supplied to the Company’s customers. Depending on weather conditions and the level of customer demand, failure of one or both of these transmission pipelines could have a major adverse impact on the Company.
| 9. | Employee Benefit Plans |
The Company has both a defined benefit pension plan (the “pension plan”) and a post- retirement benefit plan (the “post-retirement plan”). The pension plan covers substantially all of the Company’s employees and provides retirement income based on years of service and
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RGC RESOURCES, INC. AND SUBSIDIARIES
employee compensation. The post-retirement plan provides certain healthcare and supplemental life insurance benefits to retired employees who meet specific age and service requirements. Net pension plan and post-retirement plan expense recorded by the Company is detailed as follows:
| Three Months Ended March 31, | Six Months Ended March 31, | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
Components of net periodic pension cost: | ||||||||||||||||
Service cost | $ | 100,906 | $ | 107,365 | $ | 201,812 | $ | 214,730 | ||||||||
Interest cost | 211,725 | 192,377 | 423,450 | 384,754 | ||||||||||||
Expected return on plan assets | (215,537 | ) | (205,345 | ) | (431,074 | ) | (410,690 | ) | ||||||||
Recognized loss | 17,647 | — | 35,294 | — | ||||||||||||
Net periodic pension cost | $ | 114,741 | $ | 94,397 | $ | 229,482 | $ | 188,794 | ||||||||
| Three Months Ended March 31, | Six Months Ended March 31, | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
Components of post-retirement benefit cost: | ||||||||||||||||
Service cost | $ | 30,914 | $ | 35,082 | $ | 61,828 | $ | 70,164 | ||||||||
Interest cost | 126,005 | 127,848 | 252,010 | 255,696 | ||||||||||||
Expected return on plan assets | (69,179 | ) | (71,626 | ) | (138,358 | ) | (143,252 | ) | ||||||||
Amortization of unrecognized transition obligation | 47,223 | 47,223 | 94,446 | 94,446 | ||||||||||||
Net post-retirement benefit cost | $ | 134,963 | $ | 138,527 | $ | 269,926 | $ | 277,054 | ||||||||
The Company contributed $300,000 to its pension plan for the six-month period ended March 31, 2009. The Company currently expects to make a total contribution of at least $700,000 to its pension plan and $600,000 to its post-retirement benefit plan during the fiscal year ending September 30, 2009. The Company will continue to evaluate its pension funding in light of the negative asset performance in 2008. Any further funding changes will not be determined until the completion of the current year plan actuarial valuation report.
| 10. | Environmental Matters |
Both Roanoke Gas Company and Bluefield Gas Company operated manufactured gas plants (MGPs) as a source of fuel for lighting and heating until the late 1940s or early 1950s. A by-product of operating MGPs was coal tar, and the potential exists for on-site tar waste contaminants at the former plant sites. Should the Company eventually be required to remediate either site, the Company will pursue all prudent and reasonable means to recover
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RGC RESOURCES, INC. AND SUBSIDIARIES
any related costs, including insurance claims and regulatory approval for rate case recognition of expenses associated with any work required. While the Company sold the stock of Bluefield Gas Company to ANGD, LLC, it retained ownership of the former MGP site and entered into an Indemnification and Cost Sharing Agreement with ANGD to seek rate recovery of any remediation costs through rate recovery and under any applicable insurance policies or from any third party for reimbursement to the Company for 25% of any such costs to the extent they are not otherwise recovered. If the Company incurs costs associated with a required clean-up of the Roanoke Gas Company MGP site, the Company anticipates recording a regulatory asset for such clean-up costs to be recovered in future rates.
| 11. | Newly Adopted Accounting Standards |
On October 1, 2008, the Company adopted the change in measurement date provision of SFAS No. 158,Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132R. SFAS No. 158 requires an employer to measure the funded status of each plan as of the Company’s fiscal year end. The Company previously used a June 30 measurement date for its benefit plans. The change in measurement date eliminated the three month lag in recognizing expense between the measurement date and the end of the Company’s fiscal year. The Company recorded a reduction to retained earnings, net of tax, of $44,931 for the effect of the change in measurement date on unregulated operations and a regulatory asset in the amount of $177,284 for the portion attributable to the regulated operations of Roanoke Gas Company. The Company has requested SFAS No. 71 treatment to defer this amount and provide for a three year amortization in the current rate filing before the SCC.
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. In February 2008, the FASB issued FASB Staff Position No. 157-2,Effective Date of FASB Statement No. 157, which delays the effective date of SFAS No. 157 for one year for nonfinancial assets and liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually.) The Company adopted the provisions of SFAS No. 157 effective October 1, 2008. Adoption of SFAS No. 157 had no material impact on the Company’s financial position, results of operations or cash flows. The disclosures required by SFAS No. 157 are included in Note 12.
In February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities.This statement permits, but does not require, entities to choose to measure selected financial assets and liabilities at fair value. Although SFAS No. 159 does not eliminate the fair value disclosure requirements included in other accounting standards, it does provide for additional presentation and disclosures designed to facilitate comparisons between companies that choose different measurement attributes for similar assets and liabilities. SFAS No. 159 was effective October 1, 2008. The Company has not elected to apply the fair value option to any of its financial assets or liabilities.
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RGC RESOURCES, INC. AND SUBSIDIARIES
In March 2008, the FASB issued SFAS No. 161,Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133. The purpose of this statement is to enhance the current disclosure framework of SFAS No. 133 by requiring entities to disclose (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flow. The Company adopted the provisions of SFAS No. 161 effective for the quarter ended March 31, 2009. Adoption of SFAS No. 161 had no material impact on the Company’s financial position, results of operations or cash flows. The disclosures required by SFAS No. 161 are included in Notes 5 and 6.
| 12. | Recently Issued Accounting Standards Pending Adoption |
In December 2008, the FASB issued FASB Staff Position No 132(R)-1, (FSP 132(R)-1),Employers’ Disclosures about Postretirement Benefit Plan Assets. As the title indicates, the objective of FSP 132(R)-1 is to improve disclosures about plan assets in employers’ defined benefit pension or other post-retirement plans by providing users of financial statements with an understanding of: (a) How investment allocation decisions are made, including the factors that are pertinent to an understanding of investment policies and strategies; (b) The major categories of plan assets; (c) The inputs and valuation techniques used to measure the fair value of plan assets; (d) The effect of fair value measurements using significant unobservable inputs on changes in plan assets for the period; and (e) Significant concentrations of risk within plan assets. The FSP is effective for fiscal years ending after December 15, 2009. Although the Company has not completed its evaluation, management does not anticipate this FSP to have a material impact on its financial position, results of operations or cash flows.
In April 2009, the FASB issued FASB Staff Position No. FAS 107-1 and APB 28-1 (FSP 107-1),Interim Disclosures about Fair Value of Financial Instruments. FSP 107-1 applies the required disclosures of FASB No. 107,Disclosures about Fair Value of Financial Instruments, to interim financial statements of publicly traded companies. Under FSP 107-1, companies shall disclose for interim and annual reporting periods the fair value of all financial instruments for which it is practicable to estimate that value, the method and significant assumptions used to estimate the fair value of financial instruments, and a description of any changes in methods and significant assumptions that occurred during the period. This FSP is effective for interim reporting periods ending after June 15, 2009. Accordingly, the Company will adopt FSP 107-1 during the quarter ended June 30, 2009. The Company does not anticipate this FSP to have a material impact on its financial position, results of operations or cash flows.
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Other accounting standards that have been issued or proposed by the FASB or other standard –setting bodies are not expected to have a material impact on the Company’s financial position, results of operations and cash flows.
| 13. | Fair Value Measurements |
Effective October 1, 2008, the Company adopted SFAS No. 157 for financial assets and liabilities that are measured and reported on a fair value basis. SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. SFAS No. 157 also establishes a fair value hierarchy that prioritizes each input to the valuation method used to measure fair value into one of the following three broad levels:
Level 1 – Unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date.
Level 2 – Inputs other than quoted prices in Level 1 that are either for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability, or inputs that are derived principally from or corroborated by observable market data by correlation or other means.
Level 3 – Unobservable inputs for the asset or liability where there is little, if any, market activity for the asset or liability at the measurement date.
The fair value hierarchy gives the highest priority to unadjusted quoted prices in active markets (Level 1) and the lowest priority to unobservable inputs (Level 3). The following table summarizes the Company’s financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements by level within the fair value hierarchy as of March 31, 2009:
| Fair Value Measurements | ||||||||||||
| Fair Value | Quoted Prices in Active Markets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | |||||||||
Liabilities: | ||||||||||||
Interest rate swaps | $ | 3,205,853 | $ | — | $ | 3,205,853 | $ | — | ||||
Total | $ | 3,205,853 | $ | — | $ | 3,205,853 | $ | — | ||||
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ITEM 2 - MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Forward-Looking Statements
This report contains forward-looking statements that relate to future transactions, events or expectations. In addition, 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. These statements are based on management’s current expectations and information available at the time of such statements and are believed to be reasonable and are made in good faith. 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, but are not limited to, the following: (i) failure to earn on a consistent basis an adequate return on invested capital; (ii) ability to retain and attract professional and technical employees; (iii) the potential loss of large-volume industrial customers to alternate fuels, facility closings or production changes; (iv) volatility in the price and availability of natural gas; (v) uncertainty in the demand for natural gas 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, difficult economic conditions and/or colder weather; (ix) variations in winter heating degree-days from the 30-year average on which the Company’s billing rates are set; (x) impact of potential climate change legislation regarding limitations on carbon dioxide emissions; (xi) impact of potential increased regulatory oversight and compliance requirements due to financial, environmental, safety and system integrity laws and regulations; (xii) failure to obtain timely rate relief for increasing operating or gas costs from regulatory authorities; (xiii) capital market conditions and the availability of debt and equity financing; (xiv) impact of terrorism; (xv) volatility in actuarially determined benefit costs and plan asset performance; (xvi) effect of natural disasters on production and distribution facilities and the related effect on supply availability and price; and (xvii) changes in accounting regulations and practices, 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”, “assume”, “indicate” or similar words or future or conditional verbs such as “will,” “would,” “should,” “can”, “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.
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RGC RESOURCES, INC. AND SUBSIDIARIES
The three-month and six-month earnings presented herein should not be considered as reflective of the Company’s consolidated financial results for the fiscal year ending September 30, 2009. The total revenues and margins realized during the first six months reflect higher billings due to the weather sensitive nature of the gas business. Improvement or decline in earnings will depend primarily on the level of operating and maintenance costs and, to a lesser extent, weather.
Overview
Resources is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately 57,000 residential, commercial and industrial customers in Roanoke, Virginia and the surrounding areas through its Roanoke Gas Company (“Roanoke Gas”) subsidiary. Natural gas service is provided at rates and for the terms and conditions set forth by the Virginia State Corporation Commission (“SCC”).
Resources also provided regulated sale and distribution of natural gas to Bluefield, West Virginia, the Town of Bluefield, Virginia and surrounding areas through its Bluefield Gas Company (“Bluefield”) subsidiary and the Bluefield division of Roanoke Gas (collectively called “Bluefield Operations”). Effective as of October 31, 2007, Resources closed on the sale of the stock of Bluefield to ANGD, LLC and Roanoke Gas completed the sale of the assets of its Bluefield division to Appalachian Natural Gas Company, a subsidiary of ANGD, LLC. The corresponding activities of the Bluefield Operations up to the effective date of the sale have been classified as discontinued operations. See Note 2 above for more information on these transactions.
Resources also provides certain unregulated 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 2% of total revenues and margin 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 (normal means average heating degree-days for a specified period) winters, customers may significantly reduce their consumption of natural gas. Furthermore, significant increases in natural gas commodity prices can affect customer usage by encouraging conservation or use of alternative fuels.
Because the SCC authorizes billing rates for the utility operations of Roanoke Gas based on normal weather, warmer than normal weather may result in the Company failing to earn its authorized rate of return. The Company has been able to mitigate a portion of the risk associated with warmer than normal winter weather by the inclusion of a weather normalization adjustment (“WNA”) factor as part of its rate structure, which allows the Company to recover revenues equivalent to the margin that would be realized at approximately 6% warmer than the 30-year normal. For the current WNA period ending March 31, 2009, the Company did not record a WNA adjustment as the number of heating degree-days (an industry measure by which the average daily temperature falls below 65 degrees Fahrenheit) fell within the 6% weather band
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RGC RESOURCES, INC. AND SUBSIDIARIES
during the measurement period running from April through March. The Company recorded approximately $40,000 and $355,000 in additional revenues for the three-month and six-month periods ended March 31, 2008 to reflect the impact of the WNA.
The current economic environment has had a negative impact on the local economy as construction activity has significantly slowed and industrial activity has declined. Natural gas consumption by the Company’s industrial and transportation customers has declined by more than 18% from the same quarter last year. Most of the decline appears to be related to reduced production activities by these customers and should improve when the economy recovers. One industrial customer announced plans to close its operations which will result in the loss of approximately 65,000 decatherms, or $80,000 in margin, annually. Furthermore, with the current difficulties in the economy and the growing job losses, the Company may begin to experience a greater level of customer payment delays and rising bad debt expense. Bad debt expense has increased for the three-month and six-month periods ended March 31, 2009. Much of the increase is related to a greater level of billed volumes, while a portion of the higher expense is due to increases in past due balances. Currently, the higher level of past-due balances is not considered significant; however, management continues to closely monitor accounts receivable activity and intends to take action to mitigate the impact to the Company and its customers if the level of customer delinquencies continues to increase.
Volatility in natural gas prices also presents issues for the Company. The commodity price of natural gas has declined from its peak of more than $13.00 per decatherm last summer to under $4.00 a decatherm in March. Currently, futures prices for natural gas on the NYMEX (New York Mercantile Exchange) range between $3.75 and $6.00 per decatherm over the next 12 months. If natural gas prices remain at these levels, both the Company and its customers should benefit by having relative stability in pricing. A strong economic recovery that spurs demand for natural gas, causes supply availability problems and/or other issues could escalate natural gas prices and negatively affect the Company by making natural gas a less attractive energy source.
The Company has an approved rate structure in place that mitigates the impact of financing costs of its natural gas inventory in relation to price volatility. Under this rate structure, Roanoke Gas accrues revenue to cover the financing costs or “carrying costs” related to the level of investment in natural gas inventory. During times of rising gas costs and rising inventory levels, the Company recognizes revenues to offset higher financing costs associated with higher inventory balances. Conversely, during times of decreasing inventory costs and lower inventory balances, the Company recognizes less carrying cost revenue as the financing costs would be less. The Company recognized approximately $581,000 and $1,445,000 in carrying cost revenues for the three-month and six-month periods ended March 31, 2009, compared to approximately $463,000 and $1,091,000 for the same periods last year. The increase in carrying cost revenues was primarily attributable to the higher per decatherm price of gas in storage due to steep increases in the commodity price of natural gas during last summer’s storage injections when gas prices peaked at more than $13.00 a decatherm. If natural gas prices remain at the lower levels as indicated by the NYMEX futures prices discussed above, the per decatherm value of natural gas will decline as storage balances begin to refill. Although the lower prices will enhance appeal of natural gas as an energy choice, reduced natural gas inventory values will lead to a significant decline in the amount of carrying cost revenues included in natural gas margins over the balance of the current fiscal year and into next year.
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Results of Operations
Consolidated net income (loss) from continuing and discontinued operations is as follows:
| Three Months Ended March 31, | Six Months Ended March 31, | ||||||||||||
| 2009 | 2008 | 2009 | 2008 | ||||||||||
Net Income | |||||||||||||
Continuing Operations | $ | 2,643,693 | $ | 2,418,609 | $ | 4,592,852 | $ | 3,984,617 | |||||
Discontinued Operations | — | — | — | (36,690 | ) | ||||||||
Net Income | $ | 2,643,693 | $ | 2,418,609 | $ | 4,592,852 | $ | 3,947,927 | |||||
Continuing Operations
Three Months Ended March 31, 2009:
The table below reflects operating revenues, volume activity and heating degree-days.
| Three Months Ended March 31, | Increase/ (Decrease) | Percentage | |||||||||||
| 2009 | 2008 | ||||||||||||
Operating Revenues | |||||||||||||
Gas Utilities | $ | 34,003,752 | $ | 39,349,932 | $ | (5,346,180 | ) | -14 | % | ||||
Other | 282,750 | 214,446 | 68,304 | 32 | % | ||||||||
Total Operating Revenues | $ | 34,286,502 | $ | 39,564,378 | $ | (5,277,876 | ) | -13 | % | ||||
Delivered Volumes | |||||||||||||
Regulated Natural Gas (DTH) | |||||||||||||
Tariff Sales | 3,160,666 | 3,086,442 | 74,224 | 2 | % | ||||||||
Transportation | 636,516 | 765,372 | (128,856 | ) | -17 | % | |||||||
Total Delivered Volumes | 3,797,182 | 3,851,814 | (54,632 | ) | -1 | % | |||||||
Heating Degree Days (Unofficial) | 2,052 | 1,995 | 57 | 3 | % | ||||||||
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RGC RESOURCES, INC. AND SUBSIDIARIES
Total operating revenues for the three months ended March 31, 2009 compared to the same period last year decreased due to significantly lower natural gas prices. Most of the reduction is attributable to the reduction of revenue through the Company’s purchased gas cost adjustment (“PGA”). The SCC allows the Company to recover prudently incurred gas costs through the gas cost component of its billing rate. Any amount billed to customers in excess of actual gas costs is deferred as an over-collection of gas costs to be refunded to customers, while any excess cost of natural gas not recovered by the gas cost component of its billing rate is accrued as an under-collection of gas costs to be collected from customers. As natural gas prices declined at a faster rate than the Company’s gas cost factor in its billing rate, the Company reduced revenue by the amount of the over-collection and increased its liability to customers on the balance sheet.
| Three Months Ended March 31, | Increase/ (Decrease) | Percentage | ||||||||||
| Gross Margin | 2009 | 2008 | ||||||||||
Gas Utilities | $ | 9,182,375 | $ | 8,522,286 | $ | 660,089 | 8 | % | ||||
Other | 149,944 | 130,530 | 19,414 | 15 | % | |||||||
Total Gross Margin | $ | 9,332,319 | $ | 8,652,816 | $ | 679,503 | 8 | % | ||||
Regulated natural gas margins from utility operations increased over the same period last year due to the implementation of a non-gas base rate increase and higher inventory carrying cost revenues more than offsetting reductions in delivered natural gas volumes. Tariff sales (consisting primarily of residential and commercial volumes) increased slightly on approximately the same number of heating degree days, while transportation volumes, which generally correspond to production activities of certain larger industrial customers, declined significantly due to the current unfavorable economic environment. The Company placed increased non-gas base rates into effect in November. These rates were placed into effect subject to refund pending a final order from the SCC. As a result of the higher rates, the Company realized approximately $166,000 in additional margin from customer base charges, which is a flat monthly fee billed to each natural gas customer. The total volumetric margin increased by approximately $423,000 primarily due to the effect of the rate increase. Carrying cost revenues, as explained above, increased by approximately $118,000 due to a higher average investment in natural gas storage during the period.
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RGC RESOURCES, INC. AND SUBSIDIARIES
The components of the gas utility margin increase are summarized below:
| Net Margin Increase | ||||
Customer Base Charge including rate increase | $ | 165,891 | ||
WNA | (40,238 | ) | ||
Carrying Cost | 117,988 | |||
Volumetric including rate increase and volume | 422,680 | |||
Other | (6,232 | ) | ||
Total | $ | 660,089 | ||
Other margins increased by $19,414 over last year primarily due to an increase in contract services as part of the unregulated operations.
Operations expenses increased by $270,215, or 11%, compared to the same period last year, resulting from higher bad debt expense, employee benefit costs and contractor and operations labor and a reduction in capitalized overheads. Bad debt expense increased by $32,000 due to higher gross billings and increases in past due balances. Contractor and company labor increased approximately $83,000 due to reduced capital activity and normal salary adjustments. Total employee benefit costs increased by approximately $65,000 over the same period last year due to increases in pension and post-retirement medical costs and higher health insurance premiums. Reductions in capital expenditures for extending natural gas due to declines in residential and commercial development resulted in a $45,000 reduction in the level of capitalized overheads. The remaining difference is attributable to minor increases in other operating expense categories. Maintenance expenses increased by $60,082, or 18%, primarily due to the timing of repairs of pipeline leaks in the Company’s distribution system determined through annual leak surveys.
General taxes increased by $10,862, or 3%, related to higher property taxes associated with increased investment in utility plant and higher payroll taxes. Depreciation expense increased $48,256, or 4%, on a corresponding increase in utility plant associated with replacing cast iron and bare steel pipe and extending service to new customers Other income, net, increased by $5,146 due to lower level of miscellaneous deductions.
Interest expense declined by $55,119, or 11%, even though total average debt outstanding during the period increased by more than $750,000. The reduction in interest is due to a combination of significantly lower interest rates on the Company’s line-of-credit and the retirement of the $5,000,000 first mortgage note, which was replaced by a lower interest rate note. The interest rate on the Company’s line-of-credit arrangement is based on LIBOR and the effective average rate for the quarter was 0.9% compared to 4.4% for the same period last year.
Income tax expense increased by $125,269, or 9%, which corresponds to the increase in pre-tax income from continuing operations for the quarter. The effective tax rate was 38% for both periods.
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RGC RESOURCES, INC. AND SUBSIDIARIES
Six Months Ended March 31, 2009:
The table below reflects operating revenues, volume activity and heating degree-days.
| Six Months Ended March 31, | Increase/ (Decrease) | Percentage | |||||||||||
| 2009 | 2008 | ||||||||||||
Operating Revenues | |||||||||||||
Gas Utilities | $ | 62,195,675 | $ | 64,904,575 | $ | (2,708,900 | ) | -4 | % | ||||
Other | 550,022 | 400,711 | 149,311 | 37 | % | ||||||||
Total Operating Revenues | $ | 62,745,697 | $ | 65,305,286 | $ | (2,559,589 | ) | -4 | % | ||||
Delivered Volumes | |||||||||||||
Regulated Natural Gas (DTH) | |||||||||||||
Tariff Sales | 5,458,174 | 5,087,458 | 370,716 | 7 | % | ||||||||
Transportation | 1,339,174 | 1,472,575 | (133,401 | ) | -9 | % | |||||||
Total Delivered Volumes | 6,797,348 | 6,560,033 | 237,315 | 4 | % | ||||||||
Heating Degree Days (Unofficial) | 3,560 | 3,286 | 274 | 8 | % | ||||||||
Total operating revenues from continuing operations for the six months ended March 31, 2009 compared to the same period last year decreased due to reductions in the price of natural gas more than offsetting a greater level of natural gas sales volumes and the implementation of a non-gas cost rate increase. The average commodity price of gas delivered declined by more than 14% from last year. Total tariff natural gas sales volumes increased by 7% on an 8% rise in the number of heating degree-days. Transportation volumes declined by 9% due to the current economic climate. Other revenues increased by 37% related primarily to contract services.
| Six Months Ended March 31, | Increase/ (Decrease) | Percentage | ||||||||||
| Gross Margin | 2009 | 2008 | ||||||||||
Gas Utilities | $ | 17,130,958 | $ | 15,780,200 | $ | 1,350,758 | 9 | % | ||||
Other | 297,398 | 241,445 | 55,953 | 23 | % | |||||||
Total Gross Margin | $ | 17,428,356 | $ | 16,021,645 | $ | 1,406,711 | 9 | % | ||||
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Regulated natural gas margins increased due to a combination of 4% higher delivered volumes, the implementation of a non-gas cost rate increase and higher carrying cost revenues more than offsetting the absence of WNA revenues. More than half of the increased margin was attributable to the non-gas cost rate increase which is expected to provide nearly $1.2 million in additional annual revenues and margin. The 7% increase in the higher margin tariff sales more than offset the absence of the WNA revenue. For the WNA period ended March 31, 2009, the weather was approximately 5% warmer than the 30 year average, while the same period last year reflected a 12% warmer than normal temperatures. The prior year WNA revenues reduced the effect of the 12% warmer than normal temperatures to approximately 6% level. Carrying cost revenues increased by approximately $354,000 due to a higher average investment in natural gas storage during the period. The components of the regulated margin increase are summarized below:
| Net Margin Increase | ||||
Customer Base Charge including rate increase | $ | 283,031 | ||
WNA | (355,347 | ) | ||
Carrying Cost | 353,980 | |||
Volumetric including rate increase and volume | 1,088,983 | |||
Other | (19,889 | ) | ||
Total | $ | 1,350,758 | ||
Operations expenses increased by $277,099, or 5%, for the six-month period ended March 31, 2009 compared to the same period last year due to higher bad debt expense, employee benefit costs and contractor and operations labor and a reduction in capitalized overheads partially offset by reductions in professional services. Bad debt expense increased by $65,000 due to higher gross billings and increases in past due balances, while a lower level of capital activity and the timing of annual leak survey work performed on the Company’s natural gas distribution system resulted in increases to operations labor and contractor expense and reduced the amount of allocated overheads from operations to capital accounting by approximately $238,000. Total employee benefit costs increased by approximately $60,000 over the same period last year due to increases in pension and post-retirement medical costs and higher health insurance premiums. Professional services declined by $84,000 attributable to a modest reduction in accounting and legal fees combined with a reduction in costs related to the transfer of benefit plan and actuarial services to a lower cost provider in the second quarter of last year. Maintenance expenses increased $110,855, or 16%, due to timing of pipeline leak repairs of the Company’s distribution system determined through annual leak surveys.
General taxes increased $27,335, or 5%, for the six-month period ended March 31, 2009 compared to the same period last year. Most of the increase was attributable to higher property taxes related to higher level utility plant combined with an increase in payroll taxes. Depreciation expense increased $103,275, or 5%, due to the growth in utility plant associated
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RGC RESOURCES, INC. AND SUBSIDIARIES
with extending service to new customers and replacing cast iron and bare steel pipe. Other income, net, decreased $5,377 due to reduced investment earnings on the Company’s short-term investments.
Interest expense decreased by $88,281, or 8%, due to significantly lower interest rates on the Company’s line-of-credit and the refinancing of the Company’s $5,000,000 first mortgage note, which matured on July 1, 2008.
Income tax expense increased $362,816, or 15%, which corresponds to the rise in pre-tax income from continuing operations. The effective tax rate was 38.0% compared to 38.1% for the same period last year.
Critical Accounting Policies and Estimates
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 assumptions 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 may differ significantly from these estimates and assumptions.
The Company considers an estimate to be critical if it requires assumptions to be made that were uncertain at the time the estimate was made and changes in the estimate are reasonably likely to occur from period to period. The Company considers the following accounting policies and estimates to be critical.
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(SFAS No. 71). 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 occurs, 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 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, for any reason, the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the Company would remove the regulatory assets or liabilities from the balance sheet related to those portions no longer meeting the criteria and include them in the consolidated statement of income and comprehensive income for the period in which the discontinuance occurred.
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Revenue recognition – Regulated utility sales and transportation revenues are based on rates approved by the SCC. The non-gas cost component of rates may not be changed without a formal rate increase application and corresponding authorization by the SCC; however, the gas cost component of rates may be adjusted periodically through the PGA mechanism with approval from the SCC.
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, weather during the period, and current and historical data. The financial statements included unbilled revenue of $2,956,504 and $5,289,010 as of March 31, 2009 and 2008, respectively.
Allowance for Doubtful Accounts – 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.
Pension and Postretirement Benefits – The Company offers a defined benefit pension plan (“pension plan”) and a post-retirement medical and life insurance plan (“post-retirement plan”) to eligible employees. The expenses and liabilities associated with these plans are based on numerous assumptions and factors, including provisions of the plans, employee demographics, contributions made to the plan, return on plan assets and various actuarial calculations, assumptions and accounting requirements. In regard to the pension plan, specific factors include assumptions regarding the discount rate used in determining future benefit obligations, expected long-term rate of return on plan assets, compensation increases and life expectancies. Similarly, the post-retirement medical plan also requires the estimation of many of the same factors as the pension plan in addition to assumptions regarding the rate of medical inflation and Medicare availability. Actual results may differ materially from the results expected from the actuarial assumptions due to changing economic conditions, volatility in interest rates and changes in life expectancy. Such differences may result in a material impact on the amount of expense recorded in future periods or the value of the obligations on the balance sheet.
Since June 30, 2008, the measurement date used for determining several of the actuarial assumptions as well as determining the market value of the plan assets of both the pension plan and post-retirement medical plan, the economic crisis and the downturn in the stock market have significantly reduced the value of the pension plan assets. If the plan assets do not recover from the losses incurred in 2008, pension expense accruals for future periods are expected to increase sharply. Furthermore, the funded status of the plan has significantly deteriorated, which will result in increasing the Company’s funding requirements in the future. The Company currently has increased its expected funding of the pension plan for the current fiscal year to $700,000 and expects funding to remain at this level or higher for the next few years. The Company expects to contribute approximately $600,000 to the post-retirement medical plan.
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RGC RESOURCES, INC. AND SUBSIDIARIES
Derivatives – The Company may hedge certain risks incurred in its operation 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 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 natural gas commodities and interest rate futures for interest rate swaps. Changes in the commodity and futures markets will impact the estimates of fair value in the future. Furthermore, the actual market value at the point of realization of the derivative may be significantly different from the values used in determining fair value in prior financial statements.
Asset Management
Roanoke Gas uses a third party as an asset manager to manage its pipeline transportation and storage rights and gas supply inventories and deliveries. In return for being able to utilize the excess capacities of the transportation and storage rights, the third party pays Roanoke Gas a monthly utilization fee, which is used to reduce the cost of gas for customers. The current agreement expires in October 2010.
Energy Costs
Energy costs represent the single largest expense of the Company. To help mitigate the impact of potential price volatility, the Company uses various hedging mechanisms, including summer storage injections and financial instruments. Prudently incurred natural gas costs are fully recoverable under the present regulatory PGA mechanism, and increases and decreases in the cost of gas are passed through to the Company’s customers. Since July of last year, the commodity price of natural gas has declined significantly with the current NYMEX price falling below $4.00 a decatherm. The price of natural gas declined at a faster rate than the Company’s PGA factor, which adjusts the billing rate to customers for the cost of natural gas. As a result, the Company moved from an under-collected position at September 30, 2008 to an over-collected position at March 31, 2009. The over-collection will be refunded to customers as part of the PGA factor adjustment based on the September balance.
Although natural gas prices are at their lowest level in recent years, economic recovery, an increased emphasis on reduced carbon emissions and reduced production and exploration activities for natural gas due to the low prices could all place upward pressure on prices in the future. Even though energy costs are recoverable through the PGA mechanism, high energy prices may have a negative impact on earnings through increases in bad debt expense and higher interest costs because the delay in recovering higher gas costs requires borrowing to temporarily fund receivables from customers as well as decreased demand resulting from customer conservation or use of alternative fuels. 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 or decreased demand.
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RGC RESOURCES, INC. AND SUBSIDIARIES
Regulatory Affairs
On November 1, 2008, Roanoke Gas Company placed into effect new base rates that provide for approximately $1,198,000 in additional annual revenues. On March 5, 2009, the Company reached a stipulated agreement with the SCC staff for a non-gas rate award for the total amount requested. Also agreed to in the stipulation was a modification to the WNA mechanism, which would reduce the current weather band from approximately 6% of the 30 year average to a weather band of 3% of the 30 year average. The implementation of this new weather band would further reduce the downside exposure that the Company has to warmer than normal weather. In addition, the new weather band would also limit the upside benefit from colder than normal weather to a 3% level. This stipulated agreement is subject to approval by the SCC Commissioners. A final order is not expected until late spring or early summer.
Capital Resources and Liquidity
Due to the capital intensive nature of the utility business, as well as the related weather sensitivity, the Company’s primary capital needs are the funding of its continuing construction program, the seasonal funding of its natural gas inventories, accounts receivable and payment of dividends. To meet these needs, the Company relies on its operating cash flows, line-of-credit agreement, and capital raised through the Company’s Dividend Reinvestment and Stock Purchase Plan (“DRIP”).
Cash and cash equivalents increased by $9,633,941 for the six month period ended March 31, 2009 compared to a $7,307,409 increase for the same period last year. The following table summarizes the categories of sources and uses of cash:
| Six Months Ended March 31, | ||||||||
| Cash Flow Summary Six Months Ended: | 2009 | 2008 | ||||||
Continuing operations: | ||||||||
Provided by operating activities | $ | 21,735,060 | $ | 12,277,674 | ||||
Provided by (used in) investing activities | (2,182,840 | ) | 647,119 | |||||
Used in financing activities | (9,918,279 | ) | (5,729,057 | ) | ||||
Cash provided by discontinued operations | — | 111,673 | ||||||
Total increase in cash and cash equivalents | $ | 9,633,941 | $ | 7,307,409 | ||||
The seasonal nature of the natural gas business causes operating cash flows to fluctuate significantly during the year as well as from year to year. Factors including weather, energy prices, natural gas storage levels and customer collections all contribute to working capital levels and the related cash flows. Generally, operating cash flows are positive during the second and third quarters as a combination of earnings, declining storage gas levels and collections on
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RGC RESOURCES, INC. AND SUBSIDIARIES
customer accounts all contribute to higher cash levels. During the first and fourth quarters, operating cash flows generally decrease due to the increases in natural gas storage levels, rising customer receivable balances and construction activity. For the six months ended March 31, 2009, cash provided by continuing operations increased by approximately $9,457,000, from $12,278,000 for the six months ended March 31, 2008 to $21,735,000 for the current period. Improvement in net income and significant increase in over-collection of gas costs due to the declining commodity price of natural gas accounted for most of the increase in cash provided by operations.
Investing activities are generally composed of expenditures under the Company’s construction program, which involves 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. Cash flows from investing activities declined by approximately $2,830,000 due to the $3,941,000 in net proceeds received from the sale of the Bluefield Operations in 2007 partially offset by reduced capital expenditures and proceeds from the sale of a short-term investment. Total capital expenditures from continuing operations were $2,719,571 and $3,293,881 for the six-month periods ended March 31, 2009 and 2008, respectively, which reflected reduced expenditures for extending service to new customers due to declines in the residential and commercial construction. Roanoke Gas’ total capital budget for the current year is more than $6,100,000 and is below the prior year’s level of $6,539,369 due to the expected continued declines in new business development; however, the Company plans to continue its focus on its pipeline renewal program. Operating cash flow provided by depreciation is expected to provide 75% of the support for the Company’s current capital budget. The Company also relies on its line-of-credit agreement, other operating cash flows, DRIP activity and long-term debt financing to provide the balance of the underlying funding for its capital expenditures.
Financing activities generally consist of long-term and short-term borrowings and repayments, issuance of stock and the payment of dividends. As discussed above, the Company uses its line-of-credit arrangement to fund seasonal working capital needs as well as provide temporary financing for capital projects. Cash flow used in financing activities increased by $4,189,000 as the $13,960,000 net reduction in the Company’s line-of-credit balance for the six-month period ended March 31, 2009 was much greater than the $4,808,000 net pay off for the same period last year. The Company entered into a $5,000,000 variable rate note in October 2008 and used the proceeds to refinance a portion of the line-of-credit balance that provided temporary funding for the retirement of a first mortgage note that matured in July. Proceeds from the issuance of common stock decreased as the Company authorized its transfer agent to acquire a portion of the share requirements of the DRIP on the open market rather than issue new shares.
On March 23, 2009, the Company renewed its line-of-credit agreement for Roanoke Gas Company. Although the Company was able to renew the line-of-credit, the current issues with the credit markets resulted in the renewal being on terms less favorable than the expiring agreement. The new agreement increased the variable interest rate to 30-day LIBOR plus 100 basis points and imposed an availability fee of 15 basis points applied to the difference between the face amount of the note and the average outstanding balance during the period. In response to the implementation of an availability fee, the Company and Wachovia Bank agreed to expand the multi-tiered borrowing limits to adjust the available limits on a monthly basis to
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RGC RESOURCES, INC. AND SUBSIDIARIES
accommodate the Company’s seasonal borrowing demands and minimize the overall borrowing costs. Under the new agreement, the Company’s total available limits during its term range from $1,000,000 to $18,000,000. The line-of-credit agreement will expire March 31, 2010, unless extended. The Company anticipates being able to extend or replace the line-of-credit upon expiration; however, there is no guarantee that the line-of-credit will be extended or replaced under the same terms currently in place.
At March 31, 2009, the Company’s consolidated long-term capitalization was 62% equity and 38% debt.
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RGC RESOURCES, INC. AND SUBSIDIARIES
ITEM 4T – CONTROLS AND PROCEDURES
The Company maintains disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) that are designed to be effective in providing reasonable assurance that information required to be disclosed in reports under the Exchange Act are recorded, processed and summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission (the “SEC”), and that such information is accumulated and communicated to management to allow for timely decisions regarding required disclosure.
In designing and evaluating disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, will be detected. These inherent limitations include the realities that judgments in decision making can be faulty and that breakdowns can occur because of simple error or mistake. The design of any system of controls is based, in part, upon certain assumptions about the likelihood of future events and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions.
As of March 31, 2009, the Company completed an evaluation, under the supervision and with the participation of management, including the chief executive officer and the chief financial officer (principal financial officer), of the effectiveness of the design and operation of our disclosure controls and procedures. Based upon that evaluation, the chief executive officer and chief financial officer concluded that the Company’s disclosure controls and procedures were effective as of March 31, 2009.
There were not any changes in the Company’s internal controls over financial reporting during the fiscal quarter ended March 31, 2009 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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RGC RESOURCES, INC. AND SUBSIDIARIES
Part II – Other Information
ITEM 1 – LEGAL PROCEEDINGS
None.
ITEM 1A – RISK FACTORS
Not required.
ITEM 2 – UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Pursuant to the RGC Resources Restricted Stock Plan for Outside Directors (the “Restricted Stock Plan”), 40% of the monthly retainer fee of each non-employee director of the Company is paid in shares of unregistered common stock and is subject to vesting and transferability restrictions (“restricted stock”). A participant can, subject to approval of Directors of the Company (the “Board”), elect to receive up to 100% of his or her 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 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 March 31, 2009, the Company issued a total of 885 shares of restricted stock pursuant to the Restricted Stock Plan as follows:
Investment Date | Price | Number of Shares | |||
1/2/2009 | $ | 25.510 | 294 | ||
2/2/2009 | $ | 26.180 | 293 | ||
3/2/2009 | $ | 25.750 | 298 | ||
On February 2 and March 2, 2009, the Company issued a total of 848 shares of its common stock to certain employees and management personnel as rewards for performance and service. The 848 shares were not issued in a transaction constituting a “sale” within the meaning of section 2(a)(3) of the Act.
ITEM 3 – DEFAULTS UPON SENIOR SECURITIES
None.
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RGC RESOURCES, INC. AND SUBSIDIARIES
ITEM 4 – SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
On January 26, 2009, the Company held its Annual Meeting of Shareholders to elect three directors, to ratify the selection of independent auditors and to vote on a shareholder proposal.
Shareholders elected all nominees for Class C directors as listed below to serve a three- year term expiring at the Annual Meeting of Shareholders to be held in 2012.
Director | Shares For | Shares Withheld | Shares Not Voted | |||
Frank T. Ellett | 1,799,971 | 17,032 | 396,558 | |||
Maryellen F. Goodlatte | 1,785,671 | 31,332 | 396,558 | |||
George W. Logan | 1,801,139 | 15,864 | 396,558 |
Abney S. Boxley, III, S. Frank Smith and John B. Williamson, III continue to serve as Class A directors until the Annual Meeting of Shareholders to be held in 2010. Nancy H. Agee, J. Allen Layman and Raymond D. Smoot, Jr. continue to serve as Class B directors until the Annual Meeting of Shareholders to be held in 2011.
Shareholders approved the selection by the Audit Committee of the Board of Directors of the firm Brown Edwards & Company, LLP as independent auditors for the fiscal year ending September 30, 2009, by the following vote.
Shares For | Shares Against | Shares Abstaining | Shares Not Voted | |||
1,801,306 | 8,735 | 6,960 | 396,560 |
Shareholders rejected a shareholder proposal to require that all Directors stand for election annually by the following vote.
Shares | Shares Against | Shares Abstaining | Broker Non Vote | |||
325,260 | 830,405 | 33,738 | 627,600 |
ITEM 5 – OTHER INFORMATION
None
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RGC RESOURCES, INC. AND SUBSIDIARIES
ITEM 6 – EXHIBITS
Number | Description | |
| 31.1 | Rule 13a–14(a)/15d–14(a) Certification of Principal Executive Officer. | |
| 31.2 | Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer. | |
| 32.1 | Section 1350 Certification of Principal Executive Officer. | |
| 32.2 | Section 1350 Certification of Principal Financial Officer. | |
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RGC RESOURCES, INC. AND SUBSIDIARIES
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.
| RGC Resources, Inc. | ||||
| Date: May 14, 2009 | By: | /s/ Howard T. Lyon | ||
| Howard T. Lyon | ||||
| Vice-President, Treasurer and CFO | ||||
| (principal financial and principal accounting officer) | ||||
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