UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Date of Report (Date of earliest event reported) October 9, 2002
OLD DOMINION ELECTRIC COOPERATIVE
(Exact name of registrant as specified in its charter)
VIRGINIA (State of jurisdiction of incorporation) | | 33-46795 (Commission File Number) | | 23-7048405 (IRS Employer Identification No.) |
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4201 Dominion Boulevard, Glen Allen, Virginia (Address of principal executive offices) | | 23060 (Zip code) |
(804) 747-0592
(Registrant’s telephone number, including area code)
OLD DOMINION ELECTRIC COOPERATIVE
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| Item 5. | | | | 3 |
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| Item 7. | | | | 5 |
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Item 5. Other Events and Regulation FD Disclosure
Existing Generating Facilities
Impact of Drought on Operation of North Anna and Clover
Drought conditions have existed in central Virginia for several years. Our generating facilities require significant water resources to generate steam for the production of energy and for cooling purposes. If drought conditions persist, the operation of our generating facilities in this region may be affected.
The North Anna Nuclear Power Station, a two unit nuclear power facility in which we own an 11.6% undivided interest, obtains its water from Lake Anna. The lake is considered to have a normal water level of 250 feet above sea level. In August 2002, the operator of the North Anna facility, Virginia Electric and Power Company (“Virginia Power”), notified the Nuclear Regulatory Commission that the water level of Lake Anna was four feet below normal. Currently, neither of the units at North Anna are designed to operate if the water level of Lake Anna falls six feet below normal. To mitigate the potential effects of the drought, the operator is in the process of installing intake pump shaft extensions that will allow both units to continue to operate until the water level falls more than eight feet below the normal level. Even with these modifications, the operator has stated that the units may reduce or suspend operations if the current drought continues past the summer of 2003.
The Clover facility, a two unit coal-fired electric generating facility in which we have a 50% undivided interest, draws water for its operations from the Roanoke River, which also has experienced reduced water levels as a result of drought conditions. At times, the Clover facility also may draw water for its operations from a man-made reservoir that the facility maintains as a safeguard. At full capacity, the reservoir can satisfy the Clover facility’s water requirements for approximately 30 days. When feasible, Virginia Power, the operator of the facility, replenishes the reservoir to maintain it at full capacity with available water from the Roanoke River. On October 7, 2002, the reservoir had sufficient capacity to permit the facility to continue normal operations for 23 days if no water was drawn from the river.
The Virginia Department of Environmental Quality has granted its consent for the Clover facility to draw water at lower than permitted river flows until completion of a study of the water needs of aquatic resources in the river. We expect the study to be completed in October 2003. If the current drought conditions continue and water in the reservoir is depleted, operation of one or both of the units at the Clover facility may be reduced or suspended, even with the ability to draw water at this lower level. Additional measures to ensure continued operation of the Clover facility at full or partial capacity are being pursued, including application for a special allotment of water from the Roanoke River under emergency powers delegated to the Virginia Department of Environmental Quality by the Governor of Virginia as a result of the drought conditions.
Replacement of Reactor Vessel Heads at North Anna
In October 2001, Virginia Power, the operator of North Anna, found small deposits of crystallized boric acid on the reactor vessel head of unit 1. The reactor vessel head is a 7-inch thick, multi-ton steel cap on the unit’s pressurized water reactor. If water seeps from the reactor, it forms crystallized boric acid on the outside of the reactor. The operator removed the mildly acidic deposits from the reactor vessel head, no further repairs were deemed necessary and the unit was returned to service the same month.
On October 28, 2001, the operator began an outage of unit 2 to inspect it for similar deposits. Deposits of crystallized boric acid also were found on top of the unit 2 reactor vessel head. The source of the water seepage was determined to be minor cracks in the weld material of 3 of the 65 penetration nozzles on the reactor vessel head. The operator repaired the cracked welds in accordance with Nuclear Regulatory Commission-accepted repair procedures. Unit 2 was returned to service on December 15, 2001.
In August 2002, the operator announced that the reactor vessel heads for both units at North Anna would be replaced with new reactor vessel heads. Our portion of the approximately $92.7 million estimated replacement cost for both reactor vessel heads is approximately $10.8 million.
During a scheduled refueling outage in September 2002, an inspection of North Anna unit 2 uncovered additional deposits of crystallized boric acid. The unit outage has been extended until a new reactor vessel head is installed. On October 7, 2002, the operator announced that the new reactor vessel head for unit 2 is expected to be installed in the fourth quarter of 2002. We expect North Anna unit 2 to be back in operation during the first quarter of 2003.
Currently, North Anna unit 1 is not scheduled to be taken off-line prior to its next refueling outage scheduled in the first quarter of 2003. The new reactor vessel head for unit 1 is expected to be installed in the third quarter of 2004 during a scheduled refueling outage.
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Additional Costs Related to Possible Outages
When either unit of North Anna or Clover is required to reduce or suspend operations for any reason, we have the option to purchase replacement energy from Virginia Power. The price of any replacement energy equals the average price of energy produced at predetermined Virginia Power-owned combustion turbine facilities. These costs currently are higher than the price of energy that we otherwise could purchase in the market. As a result, we likely would replace energy previously expected to be provided by North Anna or Clover with purchases of energy in the market which we expect would cost more than energy generated by North Anna or Clover.
We cannot predict whether or how long the facilities would be required to reduce or suspend operations as a result of any necessary inspections, repair and replacement of the reactor vessel heads at North Anna or drought conditions or the additional cost to us of any replacement energy purchased as a result of any reduction or suspension in operations. The amount of the additional costs would depend upon how long and the extent to which the facilities were not able to operate as planned, the time of year the outages occurred and market prices for energy at that time. We would recover these additional costs that we incur as a result of the purchase of replacement energy from our members under our formulary rate accepted by the Federal Energy Regulatory Commission. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations–Factors Affecting Results-Formulary Rate” in Item 7 of our annual report on Form 10-K, as amended, for the year ended December 31, 2001.
Introduction of Retail Competition in Virginia
Under Virginia’s electric utility restructuring legislation, each of our Virginia member distribution cooperatives must provide its retail consumers the opportunity to purchase electricity from an alternative supplier by January 1, 2004. On July 1, 2002, Northern Virginia Electric Cooperative became the first of our Virginia member distribution cooperatives to formally begin offering its customers the option to purchase electricity from an alternative supplier. To date, no alternative supplier has registered to serve Northern Virginia Electric Cooperative’s customers. As a result, Northern Virginia Electric Cooperative continues to supply power to all consumers in its certificated service territory. As contemplated by Virginia’s restructuring legislation, Northern Virginia Electric Cooperative remains the exclusive provider of electricity distribution services to consumers in its certificated service territory.
With Northern Virginia Electric Cooperative providing the option to its customers to purchase electricity from an alternative supplier, approximately 46% of the customers of our member distribution cooperatives currently can choose an alternative power supplier. As of September 30, 2002, no customers of our member distribution cooperatives were purchasing power from an alternative supplier.
Combustion Turbine Facilities
As part of our long-term power supply strategy, we have been developing three combustion turbine facilities in Cecil County, Maryland and Louisa County and Fauquier County, Virginia to help meet our members’ future power supply requirements. These facilities are known as Rock Springs, Louisa and Marsh Run, respectively. See “Old Dominion Electric Cooperative-Power Supply Resources-Combustion Turbine Facilities” in Item 1 of our annual report on Form 10-K, as amended, for the year ended December 31, 2001.
Rock Springs
We formed a wholly owned subsidiary to own and develop our interest in Rock Springs. We have decided to dissolve that subsidiary and take direct ownership of the interest in Rock Springs. The dissolution will have no effect on the development or construction of the facility or the expected availability of the facility by its expected commercial operation date in mid-2003. The cost to develop and construct the Rock Springs facility currently is estimated to be $149 million.
We are developing Rock Springs jointly as co-owners with CED Rock Springs, Inc. As part of the agreements for the joint development of the project, we agreed to purchase capacity and energy from CED Rock Springs, Inc. out of the first combustion turbine unit at the facility, which will be owned by CED Rock Springs, Inc. Due to delays in the anticipated commercial operation date of this unit, the facility will not be available to provide the capacity and energy originally contemplated. In substitution, we anticipate entering into a new agreement with an affiliate of CED Rock Springs, Inc., Consolidated Edison Energy, Inc., to provide us a similar amount of capacity and energy at equivalent pricing.
On July 11, 2002, our subsidiary and CED Rock Springs, Inc. entered into an operation and maintenance agreement with CED Operating Co., L.P., another affiliate of CED Rock Springs, Inc. CED Operating Co., L.P. will provide to the owners the services necessary for the safe transition from construction to operation of the facility and supply all services, goods and materials required to operate the facility. Upon dissolution of our subsidiary we will receive and assume all of the benefits and obligations of our subsidiary under the operation and maintenance agreement.
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Louisa
On June 26, 2002, our wholly owned subsidiary owning our interest in the Louisa facility entered into a contract with Kamtech, Inc. for the engineering, procurement and construction of the Louisa facility, including the installation of the five combustion turbines to be located at the site. Construction of the facility has commenced and we currently expect the facility to begin commercial operations in mid-2003. The cost to develop and construct Louisa currently is estimated to be $239 million.
Marsh Run
Initially, we planned that the Marsh Run facility would consist of four 168 megawatt (net capacity rating) electric generating units, for a total of 672 megawatts. In 2000, we entered into an agreement with General Electric Company for the purchase of three of the four units. In September 2002, we determined that Marsh Run initially would be developed with the three General Electric units only. We may construct the fourth unit at the facility at a later time. The reduction of one unit at the facility will correspondingly reduce the anticipated (net) capacity of the facility by 168 megawatts, to 504 megawatts, and the cost to develop and construct the facility by approximately $65.2 million. The cost to develop and construct Marsh Run currently is estimated to be $200 million and all three units are expected to begin commercial operation in mid-2004.
Amendment of Indenture
We are considering seeking amendments to our Indenture of Trust and Deed of Mortgage, dated as of May 1, 1992, as supplemented, amended and restated from time to time, to change the definition of interest charges to more closely reflect the way interest charges are calculated under our formulary rate accepted by the Federal Energy Regulatory Commission. This formulary rate is the basis for our charges to our member distribution cooperatives. The indenture requires the calculation of interest charges for purposes of a covenant regarding the establishment of rates and a coverage test for purposes of issuing additional indebtedness.
Fuel Factor Adjustment
Our formulary rate consists of three components: a demand rate, a base energy rate and a fuel factor adjustment rate. The base energy rate recovers our energy costs, which are primarily our variable costs such as fuel and energy costs under our power purchase contracts with third parties. Because the base energy rate is fixed, we revise the fuel factor adjustment rate to minimize any under-or over-collection of energy costs. Our deferred energy balance represents the net accumulation of any previous under or over collection of energy costs. After considering our current deferred energy balance, which represented a $5.5 million over-collection of costs as of August 31, 2002, and the level of our anticipated costs over the next six months, on October 8, 2002, we reduced our fuel factor adjustment rate by 26.7% effective October 1, 2002. This reduction resulted in a 9.4% decrease in our average energy rate (consisting of our base energy rate and our fuel factor adjustment). The reduction is intended to maintain our deferred energy balance at its current level until the next scheduled review of our fuel factor adjustment rate in the spring of 2003. After the reduction, the resulting fuel factor adjustment rate was still greater than the fuel factor adjustment rate that was in effect on January 1, 2001.
Summary Financial Data
The summary financial data below present selected historical information relating to our financial condition and results of operations. The financial data for the five years ended December 31, 2001, are derived from our audited consolidated financial statements. The financial data for the six-month periods ended June 30, 2002 and 2001 are derived from our unaudited condensed consolidated financial statements. The unaudited financial statements include all adjustments, consisting of normal recurring adjustments, which we consider necessary for a fair presentation of our financial position and results of operations for these periods. You should read the information contained in this table together with our financial statements, the related notes to the financial statements and the discussion of this information contained in our periodic reports filed with the Securities and Exchange Commission.
| | | Six Months Ended June 30,
| | | Years Ended December 31,
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| | | 2002
| | | 2001
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| | | 1999
| | | 1998
| | | 1997
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Operating revenues Operating expenses Operating margin Net margin | | $ | 245,673 (223,153 22,520 5,043 | ) | | $ | 234,221 (213,185 21,036 3,896 | ) | | $ | 487,287 (442,392 44,895 8,440 | ) | | $ | 422,031 (377,335 44,696 8,229 | ) | | $ | 390,060 (336,735 53,325 9,839 | ) | | $ | 364,221 (298,026 66,195 12,094 | ) | | $ | 358,505 (286,169 72,336 12,799 | ) |
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Net electric plant Total assets Patronage capital Long-term debt Total capitalization | | $ | 774,731 1,267,341 230,580 626,599 842,098 | | | $ | 649,041 1,032,951 220,994 447,564 669,200 | | | $ | 695,008 1,256,150 225,538 625,232 851,168 | | | $ | 648,898 1,010,572 224,598 449,823 674,165 | | | $ | 699,531 1,050,512 216,369 509,606 723,659 | | | $ | 766,966 1,126,544 206,530 584,630 791,857 | | | $ | 811,084 1,130,256 197,552 605,878 803,774 | |
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Ratio of earnings to fixed charges¹ Margins for interest ratio² Equity ratio³ | | | 1.00 1.20 26.9 | % | | | 1.15 1.20 33.1 | % | | | 1.14 1.20 26.5 | % | | | 1.16 1.20 33.3 | % | | | 1.16 1.20 29.8 | % | | | 1.17 1.20 26.1 | % | | | 1.17 1.20 24.6 | % |
| ¹ | | We calculate the ratio of earnings to fixed charges by dividing our earnings (net margin plus fixed charges reduced by interest capitalized during the period) by our fixed charges. Our fixed charges consist of all of our interest costs, whether expensed or capitalized, amortization of debt issue costs and discount or premium related to our indebtedness, and the interest portion of our rent expense. We do not take the ratio of earnings to fixed charges into account in setting our rates. Our ratio of earnings to fixed charges is less than that of many utilities because we operate on a not-for-profit basis and establish rates to collect sufficient revenue to pay expenses plus required reserves. |
| ² | | We calculate the margins for interest ratio by dividing our margins for interest by our interest charges. See “Selected Financial Data” in Item 6 of our annual report on Form 10-K, as amended, for the year ended December 31, 2001 for a description of the calculation of margins for interest and interest charges under the indenture. |
| ³ | | Our equity ratio equals patronage capital divided by the sum of our long-term indebtedness and patronage capital. Patronage capital consists of our aggregate net margins that we have not distributed to our members. |
FORWARD-LOOKING STATEMENTS
This report may contain forward-looking statements regarding matters that could have an impact on our business, financial condition and future operations. These statements, based on our expectations and estimates, are not guarantees of future performance and are subject to risks, uncertainties, and other factors that could cause actual events or results to differ materially from those expressed in the forward-looking statements. These risks, uncertainties, and other factors include, but are not limited to, general business conditions, increased competition in the electric utility industry, changes in our tax status, demand for power, federal and state legislative and regulatory actions and legal and administrative proceedings, and unanticipated changes in operating expenses and capital expenditures. Any forward-looking statement speaks only as of the date on which the statement is made, and we undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which the statement is made even if new information becomes available or other events occur in the future.
Item 7. FinancialStatements and Exhibits
(a) Financial Statements of Business Acquired
Not applicable
(b) Pro Forma Financial Information
Not applicable
(c) Exhibits
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| 99. | | Member Financial and Statistical Information |
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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 hereunto duly authorized.
OLD DOMINION ELECTRIC COOPERATIVE Registrant |
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| By: | | /s/ DANIEL M. WALKER
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| | | Daniel M. Walker Senior Vice President of Accounting and Finance (Chief Financial Officer) |
Date: October 9, 2002
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Exhibit Number
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| 99 | | Member Financial and Statistical Information | | 8 |
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