SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
QUARTERLY REPORT UNDER SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For Quarter Ended June 30, 2003
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Commission File Number 000-26591
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RGC Resources, Inc.
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(Exact name of Registrant as Specified in its Charter)
VIRGINIA 54-1909697
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(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification No.)
519 Kimball Ave., N.E., Roanoke, VA 24016
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(Address of Principal Executive Offices) (Zip Code)
(540) 777-4427
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(Registrant's Telephone Number, Including Area Code)
None
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(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
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Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the close of the period covered by this report.
Class Outstanding at June 30, 2003
- ------------------------------ ----------------------------------
Common Stock, $5 Par Value 1,993,741
RGC RESOURCES, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
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UNAUDITED
June 30, September 30,
ASSETS 2003 2002
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Current Assets:
Cash and cash equivalents $ 413,473 $ 288,030
Accounts receivable - (less allowance for
uncollectibles of $1,426,307 and
and $155,062, respectively) 8,011,169 4,460,867
Inventories 2,026,504 2,172,808
Prepaid gas service 7,733,877 9,372,493
Prepaid income taxes - 1,189,154
Deferred income taxes 2,435,086 2,579,879
Under-recovery of gas costs 516,149 -
Unrealized gains on marked to market transactions - 1,779,891
Other 588,535 453,804
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Total current assets 21,724,793 22,296,926
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Property, Plant And Equipment:
Utility plant in service 95,227,988 89,504,217
Accumulated depreciation and amortization (38,337,045) (34,386,639)
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Utility plant in service, net 56,890,943 55,117,578
Construction work-in-progress 1,424,505 1,810,520
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Utility Plant, Net 58,315,448 56,928,098
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Nonutility property 21,097,090 19,869,186
Accumulated depreciation and amortization (8,855,643) (7,659,087)
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Nonutility property, net 12,241,447 12,210,099
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Total property, plant and equipment 70,556,895 69,138,197
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Other Assets
Goodwill 298,314 298,314
Other assets 973,952 668,018
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Total other assets 1,272,266 966,332
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Total Assets $ 93,553,954 $ 92,401,455
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See notes to condensed consolidated financial statements.
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RGC RESOURCES, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
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UNAUDITED
June 30, September 30,
LIABILITIES AND STOCKHOLDERS' EQUITY 2003 2002
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Current Liabilities:
Current maturities of long-term debt $ 2,156,795 $ 105,127
Borrowings under lines of credit 4,934,000 8,991,000
Dividends payable 568,522 559,069
Accounts payable 8,586,613 7,897,084
Income taxes payable 1,840,445 -
Customer deposits 483,776 543,891
Accrued expenses 4,797,914 3,961,174
Refunds from suppliers - due customers 43,837 51,889
Overrecovery of gas costs 1,738,326 1,742,905
Unrealized losses on marked to market transactions 306,631 -
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Total current liabilities 25,456,859 23,852,139
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Long-term Debt, Excluding Current Maturities 28,228,299 30,377,358
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Deferred Credits:
Deferred income taxes 4,805,217 5,802,417
Deferred investment tax credits 275,614 300,544
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Total deferred credits 5,080,831 6,102,961
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Stockholders' Equity:
Common stock, $5par value; authorized,
10,000,000 shares; issued and outstanding
1,993,741 and 1,960,418 shares, respectively 9,968,705 9,802,090
Preferred stock, no par, authorized, 5,000,000
shares; 0 shares issued and outstanding
in 2003 and 2002 - -
Capital in excess of par value 11,830,821 11,374,173
Retained earnings 13,178,673 10,758,491
Accumulated comprehensive income (loss) (190,234) 134,243
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Total stockholders' equity 34,787,965 32,068,997
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Total Liabilities and Stockholders' Equity $ 93,553,954 $ 92,401,455
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See notes to condensed consolidated financial statements.
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2
RGC RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
FOR THE THREE-MONTH AND NINE-MONTH PERIODS ENDED JUNE 30, 2003 AND 2002
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UNAUDITED
Three Months Ended Nine Months Ended
June 30, June 30,
2003 2002 2003 2002
------------------ -------------- -------------- --------------
Operating Revenues:
Gas utilities $ 14,327,991 $ 9,948,942 $ 65,613,812 $ 50,096,760
Propane operations 1,460,672 1,560,298 13,413,122 9,427,237
Energy marketing 3,410,302 2,514,448 9,415,073 8,745,299
Other 93,216 151,664 528,871 505,044
------------------ -------------- -------------- --------------
Total operating revenues 19,292,181 14,175,352 88,970,878 68,774,340
------------------ -------------- -------------- --------------
Cost of Sales:
Gas utilities 10,226,117 6,177,527 47,720,357 34,117,294
Propane operations 824,410 839,495 6,523,454 4,832,260
Energy marketing 3,328,528 2,474,678 9,188,843 8,513,369
Other 52,411 81,567 300,740 267,995
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Total cost of sales 14,431,466 9,573,267 63,733,394 47,730,918
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Operating Margin 4,860,715 4,602,085 25,237,484 21,043,422
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Other Operating Expenses:
Other Operations 3,106,355 2,626,062 10,274,251 8,419,998
Maintenance 438,439 286,321 1,207,926 969,782
General taxes 373,158 338,812 1,329,980 1,181,333
Depreciation and amortization 1,318,669 1,291,181 3,970,330 3,917,920
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Total other operating expenses 5,236,621 4,542,376 16,782,487 14,489,033
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Operating Income (Loss) (375,906) 59,709 8,454,997 6,554,389
Other Expenses, net 14,308 62,519 122,359 114,864
Interest Expense 521,099 469,646 1,626,959 1,545,117
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Income (Loss) Before Income Taxes (911,313) (472,456) 6,705,679 4,894,408
Income Tax Expense (Benefit) (348,906) (174,723) 2,588,996 1,880,920
------------------ -------------- -------------- --------------
Net Income (Loss) $ (562,407) $ (297,733) $ 4,116,683 $ 3,013,488
================== ============== ============== ==============
Basic Earnings (Loss) Per Common Share $ (0.28) $ (0.15) $ 2.08 $ 1.56
================== ============== ============== ==============
Diluted Earnings (Loss) Per Common Share $ (0.28) $ (0.15) $ 2.08 $ 1.56
================== ============== ============== ==============
See notes to condensed consolidated financial statements.
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3
CASH DIVIDENDS PER COMMON SHARE $ 0.285 $ 0.285 $ 0.855 $ 0.855
================== ============== ============== ==============
Weighted Average Number Of Shares 1,990,223 1,950,538 1,978,760 1,933,070
Total Avg. No. of Common and Common
Equivalent Shares 1,990,223 1,950,538 1,982,452 1,936,326
4
RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
FOR THE THREE-MONTH AND NINE-MONTH PERIODS ENDED JUNE 30, 2003 AND 2002
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UNAUDITED
Three Months Ended Nine Months Ended
June 30, June 30,
2003 2002 2003 2002
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Net Income $ (562,407) $ (297,733) $ 4,116,683 $ 3,013,488
Reclassification of loss (income) transferred to net income 22,709 (1,954) (241,703) 109,200
Unrealized gain (loss) on derivative financial instruments (62,215) (91,946) (82,775) (21,384)
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Other comprehensive income (loss), net of tax (39,506) (93,900) (324,478) 87,816
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Comprehensive income (loss) $ (601,913) $ (391,633) $ 3,792,205 $ 3,101,304
=============== ============ ============ ==============
See notes to condensed consolidated financial statements.
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5
RGC RESOURCES, INC. AND SUBSIDIARIES
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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE NINE-MONTH PERIOD
ENDED JUNE 30, 2003 AND 2002
UNAUDITED
Nine Months Ended
June 30,
2003 2002
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CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ 4,116,683 $ 3,013,488
Adjustments to reconcile net earnings to net cash
provided by operating activities:
Depreciation and amortization 4,138,294 4,037,383
(Gain) Loss on disposal of property (36,005) 42,757
Deferred taxes and investment tax credits (877,337) 75,383
Changes in assets and liabilities which provided
(used) cash, exclusive of changes and noncash
transactions shown separately 3,522,971 7,557,764
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Net cash provided by operating activities 10,864,606 14,726,775
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CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant and nonutility property (5,752,908) (6,255,968)
Cost of removal of utility plant, net (26,014) (40,516)
Proceeds from disposal of equipment 257,935 70,901
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Net cash used in investing activities (5,520,987) (6,225,583)
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CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt 8,000,000 -
Retirement of long-term debt and capital leases (97,391) (795,838)
Net borrowings (repayments) under lines of credit (12,057,000) (7,460,000)
Cash dividends paid (1,687,048) (1,638,633)
Net proceeds from issuance of stock 623,263 779,051
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Net cash provided by (used in) financing activities (5,218,176) (9,115,420)
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NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS 125,443 (614,228)
CASH AND CASH EQUIVALENTS AT
BEGINNING OF PERIOD 288,030 885,678
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CASH AND CASH EQUIVALENTS AT
END OF PERIOD $ 413,473 $ 271,450
============= =============
SUPPLEMENTAL INFORMATION:
Interest paid $ 1,787,736 $ 1,740,637
Income taxes paid, net $ 234,687 $ 399,123
See notes to condensed consolidated financial statements.
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6
RGC RESOURCES, INC. AND SUBSIDIARIES
CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
UNAUDITED
1. In the opinion of management, the accompanying unaudited condensed
consolidated financial statements contain all adjustments necessary to
present fairly RGC Resources, Inc.'s financial position as of June 30,
2003, the results of its operations for the three months and nine months
ended June 30, 2003 and 2002 and its cash flows for the nine months ended
June 30, 2003. Because of seasonal and other factors, the results of
operations for the nine months ended June 30, 2003 are not indicative of
the results to be expected for the fiscal year ending September 30, 2003.
Quarterly earnings are affected by the highly seasonal nature of the
business as variations in weather conditions generally result in greater
earnings during the winter months.
2. The condensed consolidated 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.
3. On January 27, 2003, a break occurred on a natural gas main located in the
Company's Bluefield, WV service territory due to a ground shift
attributable to much colder than normal temperatures. As a result of the
leak and its subsequent repair, service to approximately 4,300 customers
was interrupted for periods ranging from several hours to 4 days. The final
cost attributed to this incident amounted to $296,956 for the repair of the
gas line and the reestablishment of service to its customers.
The Company has received authorization from the staff of the West Virginia
Public Service Commission (PSC) to defer the costs associated with the West
Virginia portion of the outage as a regulatory asset and apply for the
recovery of these costs through future rate filings. The Company has
applied Statement of Financial Accounting Standards No. 71, "Accounting for
the Effects of Certain Types of Regulation," in recording a regulatory
asset in the amount of $229,076. The Company currently has a rate filing
pending and anticipates placing new billing rates into effect beginning in
December 2003 to recover these costs over future periods. Subsequent to the
end of the quarter, the Company negotiated a settlement with the Public
Service Commission Staff regarding the full recovery of these costs over
future periods. However, a final rate order has not yet been received from
the PSC authorizing the Company to recover these costs. The Company does
not anticipate having a problem in receiving a favorable final rate order.
The costs attributable to the Virginia portion of the gas outage were
expensed during the prior two quarters. Due to the dollar amount, the
Company elected not to file for special rate relief on these costs. The
total expense allocated to the Virginia operations was $67,880.
4. 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 key market risks that RGC Resources,
Inc. would seek to hedge include the price of natural gas and propane gas
and the cost of borrowed funds.
7
RGC RESOURCES, INC. AND SUBSIDIARIES
CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
UNAUDITED
The Company has historically entered into futures, swaps and caps for the
purpose of hedging the price of propane in order to provide price stability
during the winter months. During the quarter ended June 30, 2003, the
Company entered into price cap arrangements due to the uncertainty of
energy prices in the coming heating season. The price caps will provide for
protection for increasing prices and allow the Company to benefit from
reduction in energy prices. The Company's hedging activities are in
accordance with its established risk management policies. The hedges
qualify as cash flow hedges; therefore, changes in the fair value are
reported in Other Comprehensive Income. No portion of the hedges were
ineffective during the three months and nine months ended June 30, 2003 and
2002.
The Company also had entered into price cap arrangements for the purchase
of natural gas for the purpose of providing price stability during the
winter months. The fair value of these instruments is recorded in the
balance sheet with the offsetting entry to under-recovery of gas costs. Net
income and other comprehensive income are not affected by the change in
market value as any cost incurred or benefit received from these
instruments is recoverable or refunded through the regulated natural gas
purchased gas adjustment (PGA) mechanism. Both the Virginia State
Corporation Commission (SCC) and the West Virginia Public Service
Commission (PSC) currently allow for full recovery of prudent costs
associated with natural gas purchases, and any additional costs or benefits
associated with the settlement of these instruments will be passed through
to customers when realized.
The Company also entered into an interest rate swap related to the
$8,000,000 note issued in November 2002. The swap essentially converted the
three-year floating rate note into fixed rate debt with a 4.18 percent
interest rate. The swap qualifies as a cash flow hedge with changes in fair
value reported in Other Comprehensive Income.
A summary of the derivative and financial instrument activity is provided
below:
THREE MONTHS ENDED JUNE 30, 2003 Propane Interest Rate Natural Gas
Derivatives Swap Derivative Total
---------------- -------------- ------------ ------------
Unrealized gains/(losses) on derivatives $ 959 $ (101,225) $ - $ (100,266)
Income tax (expense)/benefit (374) 38,425 - 38,051
---------------- -------------- ------------ ------------
Net unrealized gains/(losses) 585 (62,800) - (62,215)
Transfer of realized losses/(gains) to income (959) 37,549 - 36,590
Income tax benefit/expense 374 (14,255) - (13,881)
---------------- -------------- ------------ ------------
Net transfer of realized losses/(gains) to income (585) 23,294 - 22,709
Net other comprehensive income/(loss) $ - $ (39,506) $ - $ (39,506)
8
RGC RESOURCES, INC. AND SUBSIDIARIES
CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
UNAUDITED
THREE MONTHS ENDED JUNE 30, 2002 Propane Interest Rate Natural Gas
Derivatives Swap Derivative Total
---------------- -------------- ------------ ------------
Unrealized gains/(losses) on derivatives $ (150,608) $ - $ - $ (150,608)
Income tax (expense)/benefit 58,662 - - 58,662
---------------- -------------- ------------ ------------
Net unrealized gains/(losses) (91,946) - - (91,946)
Transfer of realized losses/(gains) to income (3,200) - - (3,200)
Income tax benefit/expense 1,246 - - 1,246
---------------- -------------- ------------ ------------
Net transfer of realized losses/(gains) to income (1,954) - - (1,954)
Net other comprehensive income/(loss) $ (93,900) $ - $ - $ (93,900)
NINE MONTHS ENDED JUNE 30, 2003 Propane Interest Rate Natural Gas
Derivatives Swap Derivative Total
---------------- -------------- ------------ ------------
Unrealized gains/(losses) on derivatives $ 251,293 $ (380,705) $ - $ (129,412)
Income tax (expense)/benefit (97,879) 144,516 - 46,637
---------------- -------------- ------------ ------------
Net unrealized gains/(losses) 153,414 (236,189) - (82,775)
Transfer of realized losses/(gains) to income (471,184) 74,074 - (397,110)
Income tax benefit/expense 183,526 (28,119) - 155,407
---------------- -------------- ------------ ------------
Net transfer of realized losses/(gains) to income (287,658) 45,955 - (241,703)
Net other comprehensive income/(loss) $ (134,244) $ (190,234) $ - $ (324,478)
Unrealized loss on marked to market transactions - $ (306,631) - $ (306,631)
Accumulated comprehensive income/(loss) - $ (190,234) - $ (190,234)
9
RGC RESOURCES, INC. AND SUBSIDIARIES
CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
UNAUDITED
NINE MONTHS ENDED JUNE 30, 2002 Propane Interest Rate Natural Gas
Derivatives Swap Derivative Total
---------------- -------------- ------------ ------------
Unrealized gains/(losses) on derivatives $ (35,028) $ - $ - $ (35,028)
Income tax (expense)/benefit 13,644 - - 13,644
---------------- -------------- ------------ ------------
Net unrealized gains/(losses) (21,384) - - (21,384)
Transfer of realized losses/(gains) to income 178,870 - - 178,870
Income tax benefit/expense (69,670) - - (69,670)
---------------- -------------- ------------ ------------
Net transfer of realized losses/(gains) to income 109,200 - - 109,200
Net other comprehensive income/(loss) $ 87,816 $ - $ - $ 87,816
Unrealized gain on marked to market transactions $ 21,231 - $ 998,750 $ 1,019,981
Accumulated comprehensive income/(loss) $ 12,962 - - $ 12,962
5. Basic earnings per common share are based on the weighted average number of
shares outstanding during each period. The weighted average number of
shares outstanding for the three-month and nine-month periods ended June
30, 2003 were 1,990,223 and 1,978,760 compared to 1,950,538 and 1,933,070
for the same periods last year. The weighted average number of shares
outstanding assuming dilution were 1,990,223 and 1,982,452 for the
three-month and nine-month periods ended June 30, 2003 compared to
1,950,538 and 1,936,326 for the same periods last year. The difference
between the weighted average number of shares for the calculation of basic
and diluted earnings per share relates to the dilutive effect associated
with the assumed issuance of stock options as calculated using the Treasury
Stock method.
6. RGC Resources, Inc.'s reportable segments are included in the following
table. The segments are comprised of natural gas, propane and energy
marketing. Other is composed of the heating and air conditioning business,
mapping services, information system services and certain corporate
eliminations.
10
RGC RESOURCES, INC. AND SUBSIDIARIES
CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
UNAUDITED
Energy
Natural Gas Propane Marketing Other Total
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FOR THE THREE MONTHS ENDED JUNE 30, 2003
Operating revenues $14,327,991 $1,460,672 $3,410,302 $ 93,216 $19,292,181
Operating margin 4,101,874 636,262 81,774 40,805 4,860,715
Income (Loss) before income taxes (365,513) (654,102) 70,443 37,859 (911,313)
FOR THE THREE MONTHS ENDED JUNE 30, 2002
Operating revenues $9,948,942 $1,560,298 $2,514,448 $151,664 $14,175,352
Operating margin 3,771,415 720,803 39,770 70,097 4,602,085
Income (Loss) before income taxes (32,241) (367,742) 32,897 (105,370) (472,456)
FOR THE NINE MONTHS ENDED JUNE 30, 2003
Operating revenues $65,613,812 $13,413,122 $9,415,073 $528,871 $88,970,878
Operating margin 17,893,455 6,889,668 226,230 228,131 25,237,484
Income before income taxes 3,988,785 2,305,389 192,084 219,421 6,705,679
As of June 30, 2003:
Total assets $77,501,491 $13,680,944 $1,804,303 $567,216 $93,553,954
FOR THE NINE MONTHS ENDED JUNE 30, 2002
Operating revenues $50,096,760 $9,427,237 $8,745,299 $505,044 $68,774,340
Operating margin 15,979,466 4,594,977 231,930 237,049 21,043,422
Income before income taxes 4,290,655 602,770 208,628 (207,645) 4,894,408
As of June 30, 2002:
Total assets $68,002,571 $14,293,665 $1,568,239 $794,110 $84,658,585
7. The Company has a Key Employee Stock Option Plan (the "Plan"), which is
intended to provide the Company's executive officers with long-term
(ten-year) incentives and rewards tied to the price of the Company's common
stock. The Company applies the recognition and measurement principles of
APB Opinion No. 25, ACCOUNTING FOR STOCK ISSUED TO EMPLOYEES, and related
Interpretations in accounting for this Plan. No stock-based employee
compensation expense is reflected in net income as all options granted
under the Plan had an exercise price equal to the market value of the
underlying common stock on the date of the grant. The following table
illustrates the effect on net income and earnings per share if the Company
had applied the fair value recognition provisions of FASB Statement No.
123, ACCOUNTING FOR STOCK-BASED COMPENSATION, to the options granted under
the Plan.
11
RGC RESOURCES, INC. AND SUBSIDIARIES
CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
UNAUDITED
3 Months Ended 9 Months Ended
June 30 June 30
-------------------------------- ---------------------------------
2003 2002 2003 2002
-------------- -------------- --------------- ---------------
Net income (loss), as reported $ (562,407) $ (297,733) $4,116,683 $3,013,488
Deduct: Total stock-based employee
compensation expense determined
under fair value method for all awards,
net of tax (7,611) (8,741) (15,221) (17,481)
-------------- -------------- --------------- ---------------
Pro forma net income $ (570,018) $ (306,474) $4,101,462 $2,996,007
============== ============== =============== ===============
Earnings per share:
Basic and diluted - as reported $(0.28) $(0.15) $ 2.08 $ 1.56
============== ============== =============== ===============
Basic and diluted - pro forma $(0.29) $(0.16) $ 2.07 $ 1.55
============== ============== =============== ===============
Weighted Average Shares 1,990,223 1,950,538 1,978,760 1,933,070
Diluted Average Shares 1,990,223 1,950,538 1,982,452 1,936,326
8. 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.
12
RGC RESOURCES, INC. AND SUBSIDIARIES
CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
UNAUDITED
9. The Company adopted Statement of Financial Accounting Standards (SFAS) No.
142, GOODWILL AND OTHER INTANGIBLE ASSETS, on October 1, 2002. SFAS No. 142
requires that goodwill no longer be amortized over an estimated useful
life. Instead, goodwill balances will be subject to an annual fair-value-
based impairment assessment. The Company completed its evaluation of the
new standard and determined that no impairment existed as of the date of
adoption. The following table reflects the impact of removing the goodwill
amortization on prior year net income.
Three Months Ended Nine Months Ended
June 30 June 30
2003 2002 2003 2002
---------------- --------------- ---------------- ----------------
Net Income (loss) $(562,407) $(297,733) $ 4,116,683 $ 3,013,488
Add: Goodwill amortization,
as reported net of tax 0 2,763 0 8,288
---------------- --------------- ---------------- ----------------
Adjusted Net Income $(562,407) $(294,970) $ 4,116,683 $ 3,021,776
================ =============== ================ ================
Basic and diluted earnings per share $ (0.28) $ (0.15) $ 2.08 $ 1.56
Goodwill amortization 0.00 0.00 0.00 0.00
---------------- --------------- ---------------- ----------------
Adjusted basic and diluted earnings
per share $ (0.28) $ (0.15) $ 2.08 $ 1.56
================ =============== ================ ================
The Company also adopted SFAS No. 143, ACCOUNTING FOR ASSET RETIREMENT
OBLIGATIONS, on October 1, 2002. SFAS No. 143 requires the reporting at
fair value of a legal obligation associated with the retirement of tangible
long-lived assets that result from acquisition, construction or
development. Management has determined that the Company has no material
legal obligations for the retirement of its assets. However, the Company
provides a provision, as part of its depreciation expense, for the ultimate
cost of asset retirements and removal. Removal costs are not a legal
obligation as defined by SFAS No. 143 but rather the result of cost-based
regulation and therefore accounted for under the provisions of SFAS No. 71,
ACCOUNTING FOR THE EFFECTS OF CERTAIN TYPES OF REGULATION. The accumulated
depreciation amount reflected on the Company's Balance Sheet at June 30,
2003 contains approximately $5.2 million of accumulated provisions for
retirement costs.
13
RGC RESOURCES, INC. AND SUBSIDIARIES
ITEM 2 - MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
GENERAL
RGC Resources, Inc. is an energy services company primarily engaged in the
regulated sale and distribution of natural gas to approximately 57,800
residential, commercial and industrial customers in Roanoke, Virginia and
Bluefield, Virginia and West Virginia and the surrounding areas through its
Roanoke Gas Company and Bluefield Gas Company subsidiaries. Natural gas service
is provided at rates and for the terms and conditions set forth by the State
Corporation Commission in Virginia and the Public Service Commission in West
Virginia.
RGC Resources, Inc. also provides unregulated energy products through
Diversified Energy Company, which operates as Highland Propane Company and
Highland Energy Company. Highland Propane sells and distributes propane to
approximately 18,600 customers in western Virginia and southern West Virginia.
Highland Energy brokers natural gas to several industrial transportation
customers of Roanoke Gas Company and Bluefield Gas Company. Propane sales have
become a more significant portion of the consolidated operation with an annual
growth rate that far exceeds the growth in natural gas customers.
RGC Resources, Inc. also provides information system services to software
providers in the utility industry through RGC Ventures, Inc. of Virginia, which
operates as Application Resources.
Management views warm winter weather; energy conservation, fuel switching and
bad debts due to high energy prices; and competition from alternative fuels each
as factors that could have a significant impact on the Company's earnings.
For the quarter ended June 30, 2003, the Company again faced rising energy
prices, which resulted in increasing customer account delinquencies requiring
significant increases in the provision for bad debts over the same period last
year. In addition, the Company experienced some customer resistance to higher
prices in its propane operations as propane deliveries declined from last year's
levels.
RESULTS OF OPERATIONS
Consolidated net income (loss) for the three-month and nine-month periods ended
June 30, 2003 were $(562,407) and $4,116,683, respectively, compared to
$(297,733) and $3,013,488 for the same periods last year.
Total operating revenues for the three months ended June 30, 2003 increased by
$5,116,829, or 36 percent, compared to the same period last year, primarily due
to increasing gas costs. The average cost of natural gas and propane increased
by 43 percent and 23 percent, respectively. Sales activity was mixed with total
regulated natural gas deliveries increasing by more than 5 percent, while
propane deliveries declined by nearly 20 percent. The total number of
heating-degree days (an industry measure by which the average daily temperature
falls below 65 degrees Fahrenheit) increased by more than 7 percent over the
same period last year. Energy marketing volumes declined by nearly 8 percent due
in part to the economy and to certain transporting customers opting to purchase
their gas supply directly from the Company's regulated natural gas operations.
Other revenues decreased by 39 percent due to the absence of a one-time
contracting job that generated $48,675 in revenues through June of last year.
14
RGC RESOURCES, INC. AND SUBSIDIARIES
ITEM 2 - MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Total operating margin increased by $258,630, or 6 percent, for the quarter
ended June 30, 2003 over the same period last year. Regulated natural gas
margins increased by $330,459, or 9 percent, on a total delivered volume (tariff
and transporting) increase of 102,160 dekatherms, or 5 percent. The regulated
natural gas margins are composed of two components: volumetric sales and base
charge. The increase in volumetric margin was nearly 11 percent associated with
increased volumes, primarily in the higher margin residential and commercial
customer classes. The base charge, which is a flat monthly fee billed to each
natural gas customer, increased by more than 6 percent due to the implementation
of increased base charge rates placed into effect in December 2002 and to
customer growth. Propane margins decreased by $84,541, or 11 percent, on a
284,051, or 20 percent, gallon decline in deliveries from the same period last
year. The decrease in volumes is attributable to customers' concerns over the
higher propane prices precipitating energy conservation efforts and/or the delay
of purchases until prices decline. Subsequently, the Company began its annual
summer fill program in late June, and the response has been positive with early
July deliveries exceeding budget and prior year levels. The energy marketing
division margin increased by $42,004 even though total sales volume declined by
48,187 dekatherms, or 8 percent. The decline in sales volumes was associated
with certain transporting customers opting to purchase their gas supply directly
from the Company's regulated natural gas operations and one industrial customer
switching to an alternative fuel during the quarter. The decline in volumes was
offset by increases in the price charged to customers. Other margins decreased
by $29,292, or 42 percent, due to the completion of a one-time contracting job
for another utility that began in May 2002 and was completed in October 2002.
The table below reflects volume activity and heating degree-days.
Quarter Quarter
Ended Ended Increase/
Delivered Volumes 6/30/03 6/30/02 (Decrease) Percentage
---------------- ---------------- ---------------- -----------------
Regulated Natural Gas (DTH)
Tariff Sales 1,328,962 1,145,555 183,407 16%
Transportation 652,162 733,409 (81,247) -11%
---------------- ---------------- ----------------
Total 1,981,124 1,878,964 102,160 5%
Propane (Gallons) 1,143,682 1,427,733 (284,051) -20%
Highland Energy (DTH) 581,433 629,620 (48,187) -8%
Heating Degree Days 389 362 27 7%
(Unofficial)
15
RGC RESOURCES, INC. AND SUBSIDIARIES
ITEM 2 - MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Operations expenses increased by $480,293, or 18 percent, for the three-month
period ended June 30, 2003 compared to the same period last year. The rise in
operations expenses related to increases in bad debt expense, corporate
insurance and a reduction in capitalized overheads. Bad debt expense accounted
for more than half of the increase in operations expenses, or $255,776, due to
the combined effects of the colder winter, which increased energy usage, and
higher energy prices. As a result of these two factors, total revenues increased
by 36 percent for the quarter and 30 percent for the nine months ended June 30,
2003; thereby resulting in more account balances becoming delinquent and subject
to write-off. Furthermore, last year's bad debt reserve requirements were less
than the Company's historical averages due to the warm winter and much lower
energy costs. The Company is focusing its efforts on collecting the delinquent
accounts and improving the overall service disconnect and collection processes.
Management expects bad debt expense to remain at a level higher than last year
due to higher energy prices. In March 2002, the Company established a regulatory
asset in the amount of $316,966 that provided for the deferral of a portion of
bad debt expense incurred in 2001. The Company applied Statement of Financial
Accounting Standards No. 71, ACCOUNTING FOR THE EFFECTS OF CERTAIN TYPES OF
REGULATION, in recording the regulatory asset. Beginning December 2002, the
Company began amortizing the regulatory asset in conjunction with the
implementation of new rates approved by the State Corporation Commission of
Virginia, which included a provision for recovery of the amortized expense.
Total amortization of the regulatory asset amounted to $26,414 during the
current quarter. Much of the remaining increase in operations expenses related
to higher corporate property and liability insurance due to the tight insurance
markets and reduction in labor and capitalized corporate overheads due to the
reduction in construction expenditures due to the wet weather limiting
construction activities. Employee benefit costs returned to a level comparable
to last year as reduced medical claims activity offset continued increases in
pension plan and post-retirement medical plan expenses due to the actuarial
impact of reductions in interest rates and performance of plan assets during the
prolonged stock market decline. Maintenance expenses increased by $152,118, or
53 percent, as the Company continued its focus on repairing pipeline leaks and
performing additional system maintenance as a result of the cold winter. In
addition, the improved earnings results through the first nine months of the
current year provided the Company with the resources to perform additional
maintenance improvements to the general office and operations buildings.
General taxes increased $34,346, or 10 percent, for the three-month period ended
June 30, 2003 compared to the same period last year primarily due to increased
business and occupation (B&O) taxes, a revenue sensitive tax, related to the
West Virginia natural gas operations, higher net payroll tax expense related to
a reduction in capitalized taxes corresponding with a reduction in capitalized
labor and increased property taxes associated with increases in the taxable
property.
Interest charges increased by $51,453, or nearly 11 percent, as the Company's
average total debt position during the current quarter increased by more than 15
percent over the same period last year. The increase in average total debt for
the quarter was attributable to capital expenditures and the funding of higher
accounts receivable balances and prepaid gas service related to higher energy
prices. The overall average interest rate on total debt decreased from 6.32
percent to 6.12 percent. The decline in the overall average interest rate was
attributed to the 22 percent decline in the Company's average short-term
line-of-credit rates as a result of the Federal Reserve's continuing reductions
in interest rates.
Income tax benefit increased by $174,183, which corresponds to the 93 percent
increase in pre-tax loss for the quarter.
16
RGC RESOURCES, INC. AND SUBSIDIARIES
ITEM 2 - MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
For the nine-month period ended June 30, 2003, total operating margin increased
$4,194,062, or 20 percent, over the same period last year. Regulated natural gas
margin increased $1,913,989, or 12 percent, as total natural gas deliveries rose
by 1,352,192 DTH, or 15 percent, over the same period last year, on weather that
had 23 percent more heating degree days. The components of the regulated natural
gas margin - base charge and volumetric margin - increased by 5 percent and 16
percent, respectively. The increase in base charge was attributed to the
increased base charge rates placed into effect in December 2002, and the
increase in volumetric margin relates to the increase in volumes delivered due
to the colder Winter. Propane margins increased $2,294,691, or 50 percent, as
total gallons delivered grew by 21 percent. Several factors contributed to the
increase in propane margins. The colder winter generated the increase in gallons
delivered and provided for higher unit margins due to the impact that weather
had on the sales mix between heating (higher margin) and production (lower
margin.) The remainder of the increase is attributed to the benefits realized on
propane derivative contracts and fixed price contracts. The propane derivative
contracts contributed $471,184 in additional margin during the current period as
compared to a $178,870 reduction in the prior period margin due to realized
losses under derivative contracts. Management considers the improvement in
margin attributable to the derivative instruments to be a one-time event that is
unlikely to be replicated in the near future. Energy marketing margins declined
$5,700, or 2 percent, on an 8 percent reduction in volumes as prior year results
reflect the one-time benefit from the sale of a fixed price purchase contract
for $78,600. Other margins decreased by $8,918, or 4 percent, as the reduced
margins associated with the work performed for another utility last year more
than offset profit on the sale of more than 400 propane tanks to propane
customers. The sale of tanks resulted from the Company's efforts to improve
profitability on its under performing accounts by implementing additional tank
rent or selling the propane tank to the customer. This process has resulted in
the loss of some customers; however, as these customers were not profitable,
their departure should not have a negative impact on the overall performance of
the propane operations. For the affected customers that remain customers,
management expects their profitability to improve.
The table below reflects volume activity and heating degree-days.
Y-T-D Y-T-D Increase/
Delivered Volumes 6/30/03 6/30/02 (Decrease) Percentage
---------------- ---------------- ---------------- -----------------
Regulated Natural Gas (DTH)
Tariff Sales 8,458,517 7,016,090 1,442,427 21%
Transportation 2,145,684 2,235,919 (90,235) -4%
---------------- ---------------- ----------------
Total 10,604,201 9,252,009 1,352,192 15%
Propane (Gallons) 9,227,234 7,610,998 1,616,236 21%
Highland Energy (DTH) 1,700,036 1,850,943 (150,907) -8%
Heating Degree Days 4,305 3,494 811 23%
(Unofficial)
17
RGC RESOURCES, INC. AND SUBSIDIARIES
ITEM 2 - MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Other operations expenses increased by $1,854,253 or 22 percent for the
nine-month period ended June 30, 2003 compared to the same period last year. The
increased operations expenses related to increases in bad debt expense, labor,
employee benefit costs and corporate insurance. Bad debt expense increased
$425,532, or 92 percent, due to the combined effects of the colder winter, which
increased energy usage, and higher energy prices. As discussed above, the prior
year results reflect an expense reduction of $316,966 related to the deferral of
incurred bad debt expense, while the current year reflects an amortization of
$61,632 for which rates are in effect to recover these costs. Employee benefit
costs increased $431,924 primarily due to much higher claims experience under
the Company's medical plan and higher pension and post-retirement medical
expenses attributable to changes in actuarial assumptions and performance of
plan assets. Labor costs associated with operations increased $235,881 due to
the increased demands that the colder winter placed on operation of the natural
gas system and increased levels of propane delivery. Corporate property and
liability insurance expense increased $110,490 due to much higher premiums
associated with insurance carriers raising the cost of coverage to recover from
the losses attributed to the September 11 terrorist attacks and the corporate
accounting and finance irregularities of the past two years. Maintenance expense
increased $238,144, or 25 percent, as the Company continued its focus on
repairing pipeline leaks and performing additional system maintenance as a
result of the cold winter.
General taxes increased $148,647, or 13 percent, for the nine-month period ended
June 30, 2003 compared to the same period last year as a result higher West
Virginia B&O taxes which are revenue sensitive, greater payroll taxes and
increased level of property taxes.
Depreciation increased $52,410, or 1 percent, on increased investment in utility
property partially offset by reduced levels of capital spending in propane
operations.
Interest charges increased by $81,842, or 5 percent, as a result of an increase
of 8 percent in the average borrowing levels during the period. The average
overall interest rate declined from 5.64 percent to 5.54 percent from the same
period last year due to reductions in the interest rates under the Company's
line-of-credit agreements.
Income tax expense increased $708,076, or 38 percent, due to a 37 percent
increase in pretax income.
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, 2003. The total revenues and margins during the
first nine months reflect higher billings due to the weather sensitive nature of
the gas business. Due to the seasonal nature of the Company's energy business,
the final quarter of the fiscal year tends to generate losses. Any improvement
or decline in earnings depends primarily on the level of operating and
maintenance costs during the remaining months.
GAS LINE BREAK
On January 27, 2003, a break occurred on a natural gas main located in the
Company's Bluefield, WV service territory due to a ground shift attributed to
much colder than normal temperatures. As a result of the leak and its subsequent
repair, service to approximately 4,300 customers was interrupted for periods
ranging from several hours to 4 days. The Company was able to restore service
due to assistance provided by five other natural gas distribution companies.
Over 75 service technicians worked extended shifts around the clock. The final
cost attributed to this incident amounted to $296,956 for the repair of the gas
line and the reestablishment of service to its customers.
18
RGC RESOURCES, INC. AND SUBSIDIARIES
ITEM 2 - MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The Company has received authorization from the staff of the West Virginia
Public Service Commission (PSC) to defer the costs associated with the West
Virginia portion of the outage as a regulatory asset and apply for recovery of
these costs through future rate filings. The Company has applied Statement of
Financial Accounting Standards No. 71, ACCOUNTING FOR THE EFFECTS OF CERTAIN
TYPES OF REGULATION, in recording a regulatory asset in the amount of $229,076.
The Company currently has a rate filing pending and anticipates placing new
billing rates into effect beginning in December 2003 to recover these costs over
future periods. Subsequent to the end of the quarter, the Company negotiated a
settlement with the Public Service Commission Staff regarding the full recovery
of these costs over future periods. However, a final rate order has not yet been
received from the PSC authorizing the Company to recover these costs. The
Company does not anticipate having a problem in receiving a favorable final rate
order.
The costs attributable to the Virginia portion of the gas outage were expensed
during the prior two quarters. Due to the dollar amount, the Company elected not
to file for special rate relief on these costs. The total expense allocated to
the Virginia operations was $67,880.
CRITICAL ACCOUNTING POLICIES
The consolidated financial statements of RGC Resources, Inc. are prepared in
accordance with accounting principles generally accepted in the United States of
America. The amounts of assets, liabilities, revenues and expenses reported in
the Company's financial statements are affected by estimates and judgments that
are necessary to comply with generally accepted accounting principles. Estimates
used in the financial statements are derived from prior experience, statistical
analysis and professional judgments. Actual results could differ from the
estimates, which would affect the related amounts reported in the Company's
financial statements. Although, estimates and judgments are applied in arriving
at many of the reported amounts in the financial statements including provisions
for employee medical insurance, projected useful lives of capital assets and
goodwill valuation, the following items may involve a greater degree of
judgment.
Revenue recognition - The Company bills natural gas customers on a monthly cycle
basis; however, the billing cycle periods for most customers do not coincide
with the accounting periods used for financial reporting. The Company accrues
estimated revenue for natural gas delivered to customers not yet billed during
the accounting period. Determination of unbilled revenue relies on the use of
estimates, current and historical data.
Bad debt reserves - The Company evaluates the collectibility of its accounts
receivable balances based upon a variety of factors including loss history,
level of delinquent account balances and general economic climate.
Retirement plans - The Company offers a defined benefit pension plan and a
post-retirement medical plan to eligible employees. The expenses and liabilities
associated with these plans are determined through actuarial means requiring the
estimation of certain assumptions and factors. In regard to the pension plan,
these factors include assumptions regarding discount rate, expected long-term
rate of return on plan assets, compensation increases and life expectancies,
among others. Similarly, the post-retirement medical plan also requires the
estimation of many of the same factors as the pension plan in addition to
assumptions regarding rate of medical inflation and medicare availability.
Actual results may differ materially from the results expected from the
actuarial assumptions due to changing economic conditions, volitility 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.
19
RGC RESOURCES, INC. AND SUBSIDIARIES
ITEM 2 - MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
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 commodities of
propane and natural gas. Changes in the commodity and futures markets will
impact the estimates of fair value in the future. Furthermore, the actual market
value at the point of realization of the derivative may be significantly
different from the futures value used in determining fair value in prior
financial statements.
Regulatory accounting - The Company's regulated operations follow the accounting
and reporting requirements of Statement of Financial Accounting Standards No.
71, ACCOUNTING FOR THE EFFECTS OF CERTAIN TYPES OF REGULATION. The economic
effects of regulation can result in a regulated company deferring costs that
have been or are expected to be recovered from customers in a period different
from the period in which the costs would be charged to expense by an unregulated
enterprise. When this results, costs are deferred as assets in the consolidated
balance sheet (regulatory assets) and recorded as expenses when such amounts are
reflected in rates. Additionally, regulators can impose liabilities upon a
regulated company for the amounts previously collected from customers and for
current collection in rates of costs that are expected to be incurred in the
future (regulatory liabilities).
ASSET MANAGEMENT
Effective November 1, 2001, Roanoke Gas Company and Bluefield Gas Company (the
Gas Companies) entered into a contract with a third party, Duke Energy Trading
and Marketing (Duke Energy), to provide future gas supply needs. Duke Energy has
also assumed the management and financial obligation of the Gas Companies' firm
transportation and storage agreements. In connection with the agreement, the Gas
Companies exchanged gas in storage at November 1, 2001 for the right to receive
an equal amount of gas in the future as provided by the agreement. As a result
of this arrangement, natural gas inventories on the balance sheet are replaced
with a new classification called "prepaid gas service." This contract expires on
October 31, 2004.
ENERGY COSTS
Energy prices during the quarter ended June 30, 2003 continued to remain at
levels higher than the same period last year. Low natural gas and propane
storage levels due to the cold winter weather and declining production from
existing natural gas fields led to the higher prices. The Chairman of the
Federal Reserve has stated that there is a need for renewed interest in imported
liquefied natural gas (LNG.) Increasing supply from LNG imports would help
moderate natural gas prices.
However, LNG facility development will take time. In the interim, more drilling
and well completions are necessary to alleviate any short-term constraints. On
the positive side, the higher energy prices have encouraged more natural gas
development. Baker Hughes reports that in June 2003, 910 natural gas rigs were
in operation in the United States resulting in an increase of 206 rigs over last
year.
20
RGC RESOURCES, INC. AND SUBSIDIARIES
ITEM 2 - MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
If Energy Information Administration projections are correct, natural gas and
propane prices are expected to remain at higher levels in the foreseeable
future. To lessen the impact of price volatility, Roanoke Gas Company, Bluefield
Gas Company and Highland Propane Company use a variety of hedging mechanisms.
Summer storage injections, financial instruments and fixed price contacts were
utilized during the past winter period and provided the Company with much lower
energy costs than would have been incurred through spot market purchases alone.
The Company has entered into similar arrangements for the coming year; although,
management does not expect the same level of benefit as realized during the
current year.
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. The unregulated propane and
energy marketing operations are able to more rapidly adjust pricing structures
to compensate for increasing costs. However, due to the competitive nature of
these unregulated markets, there can be no assurance that the Company can adjust
its pricing to sufficiently recover cost increases without negatively affecting
sales and competitive position.
Although rising energy prices are recoverable through the PGA mechanism for the
regulated operations, high energy prices may have a negative impact on earnings
through increases in bad debt expense and higher interest costs because the
delay in recovering higher gas costs requires borrowing to temporarily fund
receivables from customers, LNG (liquefied natural gas) and prepaid gas service
levels. As discussed below, the implementation of a new rate structure will
provide the Company a level of protection against the impact that rising energy
prices may have on bad debts and carrying costs on LNG storage and prepaid gas
service by allowing for immediate recovery of these costs. However, the new rate
structure will not protect the Company from increased rate of bad debts or
increases in interest rates.
REGULATORY AFFAIRS
In late July 2003, the management of Bluefield Gas Company (Bluefield) met with
the Public Service Commission Staff (Staff) to discuss a settlement of the
issues in the base rate case filed in February. At the meeting, Bluefield and
Staff agreed to an annual increase in non-gas rates of $112,000 to become
effective with bills rendered on and after December 4, 2003. The Staff and
Bluefield both agreed that the appropriate recovery method for the incremental
cost associated with the restoration of service resulting from the main line
rupture as discussed above is through an incremental $0.05 per MCF charge which
will be collected through customers' bills until the total cost has been
recovered. However, a final rate order has not yet been received from the PSC
authorizing Bluefield to recover these costs. Bluefield does not anticipate
having a problem in receiving a favorable final rate order.
Roanoke Gas Company is currently preparing a request for a non-gas rate increase
in Virginia to be filed with the State Corporation Commission of Virginia. This
case is planned to be filed in September pursuant to the Commission's rules for
expedited rate applications. New rates associated with this filing are
anticipated to be placed into effect in November 2003 subject to refund.
21
RGC RESOURCES, INC. AND SUBSIDIARIES
ITEM 2 - MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
In late December 2002, the Virginia State Corporation Commission approved a
joint stipulation filed by all parties associated with the Roanoke Gas Company
rate case. This final order approved a weather normalization adjustment
mechanism, to begin next winter, which will help stabilize the Company's
earnings from significant variations in weather. The weather normalization
adjustment mechanism would not have impacted the current year's financial
results as the mechanism is only triggered when weather is outside the band of 6
percent warmer or colder than the 30 year normal. For the nine-month period
ended June 30, 2003, the weather was approximately 4.2 percent colder than the
30 year normal. The order also provided for a change in the definition of gas
cost to include the gas cost component of bad debts and the carrying cost of
prepaid gas service and LNG storage. These provisions, which went into effect on
April 1, 2003, will reduce the earnings impact of rising gas costs on bad debts,
prepaid gas service and LNG storage.
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
The Company's primary capital needs are for the funding of its continuing
construction program and the seasonal funding of its accounts receivable, LNG
storage and gas prepayment requirements under the asset management contract. The
Company's construction program is composed of a combination of replacing old
bare steel and cast iron pipe with new plastic or coated steel pipe and
expansion of natural gas and propane service to new customers. Total capital
expenditures were $1,581,282 and $5,752,908 for the three-month and nine-month
periods ended June 30, 2003, respectively, compared to $1,867,977 and $6,255,968
for the same periods last year.
22
RGC RESOURCES, INC. AND SUBSIDIARIES
ITEM 2 - MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The Company also funds seasonal levels of gas prepayments, LNG storage and
accounts receivables. From April through October, the Company prepays its asset
manager for the right to receive additional natural gas in the colder winter
months. This gas prepayment replaces the old underground natural gas storage
that was used prior to the asset management contract. Furthermore, a majority of
the Company's sales and billings occur during the winter months. As a result,
accounts receivable balances increase during these months and decrease during
the summer months. Due to the much colder Winter and higher energy costs,
accounts receivable balances at June 30, 2003 were well above the levels at June
30, 2002.
The level of borrowing under the Company's line of credit agreements can
fluctuate significantly due to 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.
Effective April 1, 2003, the Company and Wachovia Bank agreed to extend the
current terms of the Company's line-of-credit agreements to allow sufficient
time to complete the paperwork for the renewals. On April 21, 2003, the Company
completed its renewal of the line-of-credit agreements with Wachovia Bank. The
new agreements maintained the same variable interest rates based upon 30 day
LIBOR; however, the Company agreed to establish a three-tier level for borrowing
limits to accommodate its seasonal borrowing demands. Generally, the Company's
borrowing needs are at their lowest in Spring, increase during the Summer and
Fall due to gas prepayments and construction and reach their maximum levels in
Winter. The three-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 April 21, 2003, the Company's total available lines of credit were set
at $10,500,000. On June 16, 2003, the total available lines of credit increased
to $16,000,000. And on September 16, 2003, the total available lines of credit
increase to $28,000,000. The line-of- credit agreements will expire March 31,
2004, unless extended. The Company anticipates being able to extend or replace
the credit lines upon expiration.
Short-term borrowings, together with internally generated funds and the sale of
Common Stock through the Company's Dividend Reinvestment and Stock Purchase
Plan, have been used to finance construction costs, debt service, dividend
payments and inventories. Total outstanding balances on the Company's
lines-of-credit at June 30, 2003 were $4,934,000 compared to $10,247,000 for the
same period last year.
At June 30, 2003, the Company's capitalization consisted of 47 percent in
long-term debt and 53 percent in common equity.
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
23
RGC RESOURCES, INC. AND SUBSIDIARIES
ITEM 2 - MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
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 and propane; (v)
uncertainty in the projected rate of growth of natural gas and propane
requirements in the Company's service area; (vi) general economic conditions
both locally and nationally; (vii) increases in interest rates; (viii) increased
customer delinquencies and conservation efforts resulting from high fuel costs
and/or colder weather; (ix) developments in electricity and natural gas
deregulation and associated industry restructuring; (x) significant variations
in winter heating degree-days from normal; (xi) changes in environmental
requirements and cost of compliance; (xii) impact of potential increased
governmental oversight due to the financial collapse of Enron; (xiii) cost and
availability of property and liability insurance in the wake of terrorism
concerns and corporate failures; (xiv) ability to raise debt or equity capital
in the wake of recent corporate financial irregularities; (xv) impact of
uncertainties in the Middle East, and (xvi) new accounting standards issued by
the Financial Accounting Standards Board, which could change the accounting
treatment for certain transactions. All of these factors are difficult to
predict and many are beyond the Company's control. Accordingly, while the
Company believes its forward-looking statements to be reasonable, there can be
no assurance that they will approximate actual experience or that the
expectations derived from them will be realized. When used in the Company's
documents or news releases, the words, "anticipate," "believe," "intend,"
"plan," "estimate," "expect," "objective," "projection," "forecast" or similar
words or future or conditional verbs such as "will," "would," "should," "could"
or "may" are intended to identify forward-looking statements.
Forward-looking statements reflect the Company's current expectations only as of
the date they are made. We assume no duty to update these statements should
expectations change or actual results differ from current expectations.
24
RGC RESOURCES, INC. AND SUBSIDIARIES
ITEM 3 - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market risks associated with interest rates and
commodity prices. Interest rate risk is related to the Company's outstanding
long-term and short-term debt. Commodity price risk is experienced by the
Company's regulated natural gas operations, propane operations and energy
marketing business. The Company's risk management policy, as authorized by the
Company's Board of Directors, allows management to enter into derivatives for
the purpose of managing commodity and financial market risks of its business
operations.
The Company is exposed to market risk related to changes in interest rates
associated with its borrowing activities. As of June 30, 2003, the Company had
$4,934,000 outstanding under its lines of credit and $2,500,000 outstanding on
an intermediate-term variable rate note. A hypothetical 10 percent increase in
market interest rates applicable to the Company's variable rate debt outstanding
at June 30, 2003 would have resulted in a decrease in quarterly earnings of
approximately $2,400. The Company also has an $8,000,000 intermediate term
variable rate note that is currently being hedged by a fixed rate interest swap.
The Company manages the price risk associated with purchases of natural gas and
propane by using a combination of fixed price contracts, prepaid gas service
payments and derivative commodity instruments including futures, price caps,
swaps and collars. As of June 30, 2003, the Company has entered into derivative
price cap agreements for the purpose of hedging the price of propane gas. With
respect to propane gas, a hypothetical 10% reduction in the market price of
propane would have no impact on the fair value of the Company's propane gas
derivative contracts.
With respect to the Company's hedging activities for the price of natural gas,
the Company has entered into price cap arrangements for the purchase of natural
gas for November 2003 through March 2004. Any cost incurred or benefit received
from the derivative arrangement is recoverable or refunded through the regulated
natural gas purchased gas adjustment (PGA) mechanism. Both the Virginia State
Corporation Commission and the West Virginia Public Service Commission 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. A
hypothetical 10% reduction in the market price of natural gas would have no
impact on the fair value of the Company's 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, 2003, 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, 2003, 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.
25
Part II - Other Information
ITEM 2 - CHANGES IN SECURITIES.
Pursuant to the RGC Resources Restricted Stock Plan for Outside Directors
(the "Restricted Stock Plan"), 40% of the monthly retainer fee of each
non-employee director of the Company is paid in shares of unregistered
common stock and is subject to vesting and transferability restrictions
("restricted stock"). A participant can, subject to approval of Directors
of the Company (the "Board"), elect to receive up to 100% of his retainer
fee in restricted stock. The number of shares of restricted stock is
calculated each month based on the closing sales price of the Company's
common stock on the Nasdaq-NMS on the first day of the month. The shares of
restricted stock are issued in reliance on section 3(a)(11) and section
4(2) exemptions under the Securities Act of 1993 (the "Act") and will vest
only in the case of the participant's death, disability, retirement or in
the event of a change in control of the Company. Shares of restricted stock
will be forfeited to the Company upon (i) the participant's voluntary
resignation during his term on the Board or (ii) removal for cause. During
the quarter ended June 30, 2003, the Company issued a total of 698.423
shares of restricted stock pursuant to the Restricted Stock Plan as
follows:
INVESTMENT DATE PRICE NUMBER OF SHARES
4/1/2003 $19.540 245.713
5/1/2003 $19.680 243.962
6/1/2003 $23.000 208.748
On April 1, 2003, May 1, 2003 and June 1, 2003, the Company issued a total
of 232.647 shares of its common stock as bonuses to certain employees and
management personnel as rewards for performance. The 232.647 shares were
not issued in a transaction constituting a "sale" within the meaning of
section 2(3) of the Act.
ITEM 6 - EXHIBITS AND REPORTS ON FORM 8-K.
(a) 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
(b) Reports on Form 8-K
On April 30, 2003, the Company filed a current report on
Form 8-K, dated April 30, 2003, furnishing under Items 9 and
12 thereof a press release announcing the financial results
of the second quarter of fiscal year 2003, including the
applicable financial statements.
On August 14, 2003, the Company filed a current report on
Form 8-K, dated August 14, 2003, furnishing under Items 9
and 12 thereof a press release announcing the financial
results of the third quarter of fiscal year 2003, including
the applicable financial statements.
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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: August 14, 2003 By: s/ Howard T. Lyon
Howard T. Lyon
Vice President, Treasurer and
Controller
(Principal Financial Officer)
27