SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-Q
(Mark One)
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
--- SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2002
or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
---- SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
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Commission file number 33-46795
OLD DOMINION ELECTRIC COOPERATIVE
(Exact Name of Registrant as Specified in Its Charter)
VIRGINIA 23-7048405
(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification No.)
4201 Dominion Boulevard, Glen Allen, Virginia 23060
(Address of Principal Executive Offices) (Zip Code)
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(804) 747-0592
(Registrant's Telephone Number, Including Area Code)
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 No X
The Registrant is a membership corporation and has no authorized or outstanding
equity securities.
1
OLD DOMINION ELECTRIC COOPERATIVE
INDEX
Page
Number
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PART I. Financial Information
Item 1. Financial Statements
Condensed Consolidated Balance Sheets - June 30, 2002 (Unaudited)
and December 31, 2001 3
Condensed Consolidated Statements of Revenues, Expenses and
Patronage Capital (Unaudited) - Three and Six Months Ended
June 30, 2002 and 2001 4
Condensed Consolidated Statements of Comprehensive Income (Unaudited) -
Three and Six Months Ended June 30, 2002 and 2001 4
Condensed Consolidated Statements of Cash Flows (Unaudited) - Six
Months Ended June 30, 2002 and 2001 5
Notes to Condensed Consolidated Financial Statements 6
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations 8
PART II. Other Information
Item 1. Legal Proceedings 15
Item 6. Exhibits and Reports on Form 8-K 15
Signature 16
2
OLD DOMINION ELECTRIC COOPERATIVE
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
CONDENSED CONSOLIDATED BALANCE SHEETS
June 30, December 31,
2002 2001*
----------- ------------
(in thousands)
ASSETS: (unaudited)
- ---------------------------------------------------
Electric Plant:
In service $ 916,691 $ 899,691
Less accumulated depreciation (353,113) (340,440)
----------- -----------
563,578 559,251
Nuclear fuel, at amortized cost 5,493 8,487
Construction work in progress 205,660 127,270
----------- -----------
Net Electric Plant 774,731 695,008
----------- -----------
Investments:
Nuclear decommissioning trust 59,989 59,700
Lease deposits 138,822 137,265
Other 141,724 159,083
----------- -----------
Total Investments 340,535 356,048
----------- -----------
Current Assets:
Cash and cash equivalents 53,723 77,981
Receivables 55,830 61,097
Fuel, materials and supplies, at average cost 18,263 13,936
Prepayments 1,813 1,783
Deferred energy - 18,244
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Total Current Assets 129,629 173,041
----------- -----------
Deferred Charges 22,446 32,053
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Total Assets $1,267,341 $1,256,150
========== ==========
CAPITALIZATION AND LIABILITIES:
- ---------------------------------------------------
Capitalization:
Patronage capital $ 230,142 $ 225,538
Accumulated other comprehensive income (15,081) 398
Long-term debt 626,599 625,232
----------- -----------
Total Capitalization 841,660 851,168
----------- -----------
Current Liabilities:
Long-term debt due within one year 39,927 39,927
Accounts payable 59,914 59,525
Accounts payable - members 34,701 38,223
Deferred energy 15,054 -
Accrued expenses 24,827 16,415
----------- -----------
Total Current Liabilities 174,423 154,090
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Deferred Credits and Other Liabilities
Decommissioning reserve 59,989 59,700
Obligations under long-term leases 141,762 140,291
Other 49,507 50,901
----------- -----------
Total Deferred Credits and Other Liabilities 251,258 250,892
----------- -----------
Commitments and Contingencies - -
----------- -----------
Total Capitalization and Liabilities $1,267,341 $1,256,150
=========== ===========
- -------------------------------------------------------------------------------
The accompanying notes are an integral part of the condensed consolidated
financial statements.
* The Condensed Consolidated Balance Sheet at December 31, 2001, has been
taken from the audited financial statements at that date, but does not
include all disclosures required by generally accepted accounting
principles.
3
OLD DOMINION ELECTRIC COOPERATIVE
CONDENSED CONSOLIDATED STATEMENTS OF REVENUES,
EXPENSES AND PATRONAGE CAPITAL (UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
------------------- ------------------
2002 2001 2002 2001
-------- -------- -------- --------
(in thousands)
Operating Revenues $112,985 $111,933 $245,232 $234,221
-------- -------- -------- --------
Operating Expenses:
Fuel 12,269 14,046 25,865 27,753
Purchased power 72,151 61,404 160,053 123,428
Operations and maintenance 8,197 8,767 16,894 17,304
Administrative and general 6,065 4,888 10,732 11,455
Depreciation, amortization and
decommissioning 2,058 11,429 7,899 31,658
Taxes other than income taxes 842 783 1,707 1,587
-------- -------- -------- --------
Total Operating Expenses 101,582 101,317 223,150 213,185
-------- -------- -------- --------
Operating Margin 11,403 10,616 22,082 21,036
Other (Expense)/Income, net (73) 192 732 682
Investment Income 552 700 2,006 1,467
Interest Charges, net (9,793) (9,568) (20,215) (19,289)
-------- -------- -------- --------
Net Margin 2,089 1,940 4,605 3,896
Patronage Capital - Beginning of Period 228,053 226,554 225,537 224,598
Payment of Capital Credits - (7,500) - (7,500)
-------- -------- -------- --------
Patronage Capital - End of Period $230,142 $220,994 $230,142 $220,994
======== ======== ======== ========
- --------------------------------------------------------------------------------
OLD DOMINION ELECTRIC COOPERATIVE
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
----------------- ------------------
2002 2001 2002 2001
-------- ------ --------- ------
(in thousands)
Net Margin $ 2,089 $1,940 $ 4,605 $3,896
Other Comprehensive Income:
Unrealized gain/(loss) on investments 32 (15) (494) 898
Cumulative effect of accounting change
on derivative contracts (15,944) - (15,944) -
Unrealized gain on derivative contracts 959 - 959 -
-------- ------ -------- ------
Comprehensive Income $(12,864) $1,925 $(10,874) $4,794
======== ====== ======== ======
- ------------------------------------------------------------------------
The accompanying notes are an integral part of the condensed consolidated
financial statements.
4
OLD DOMINION ELECTRIC COOPERATIVE
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOW (UNAUDITED)
Six Months Ended
June 30,
------------------
2002 2001
------- --------
(in thousands)
Operating Activities:
Net Margin $ 4,605 $ 3,896
Adjustments to reconcile net margins to net cash provided
by operating activities:
Depreciation, amortization and decommissioning 11,701 30,358
Other non-cash charges 4,866 4,051
Amortization of lease obligations 4,938 4,729
Interest on lease deposits (4,844) (4,629)
Change in current assets 19,154 (4,498)
Change in current liabilities 20,333 18,786
Deferred charges and credits (5,899) (827)
------- -------
Net Cash Provided by Operating Activities 54,854 51,866
------- -------
Financing Activities:
Principal payments and purchases of long-term debt - (3,572)
Obligations under long-term leases (181) (180)
------- -------
Net Cash Used for Financing Activities (181) (3,752)
------- -------
Investing Activities:
Lease deposits and other investments 16,865 (1,811)
Electric plant additions (95,456) (34,176)
Decommissioning fund deposits (340) (340)
------- -------
Net Cash Used for Investing Activities (78,931) (36,327)
------- -------
Net Change in Cash and Cash Equivalents (24,258) 11,787
Cash and Cash Equivalents - Beginning of Period 77,981 20,259
------- -------
Cash and Cash Equivalents - End of Period $53,723 $32,046
======= =======
- ------------------------------------------------------------------------------
The accompanying notes are an integral part of the condensed consolidated
financial statements.
5
OLD DOMINION ELECTRIC COOPERATIVE
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. In the opinion of our management, the accompanying unaudited condensed
consolidated financial statements contain all adjustments, which include
only normal recurring adjustments, necessary for a fair statement of our
consolidated financial position as of June 30, 2002, and our consolidated
results of operations, comprehensive income, and cash flows for the three
and six months ended June 30, 2002 and 2001. The consolidated results of
operations for the three and six months ended June 30, 2002, are not
necessarily indicative of the results to be expected for the entire year.
These financial statements should be read in conjunction with the financial
statements and notes thereto included in our 2001 Annual Report on Form
10-K filed with the Securities and Exchange Commission.
2. We ceased recording accelerated depreciation on our generation assets under
our Strategic Plan Initiative effective June 1, 2001. At June 30, 2001,
depreciation, amortization and decommissioning included $18.5 million of
accelerated depreciation. Also effective June 1, 2001, our board of
directors authorized a revenue deferral plan for the period June 1, 2001
through December 31, 2002. Under this plan, we collected $11.4 million
through the demand component of the formulary rate we charged our members
in 2001, which we are using to partially offset the increases in the demand
component of the formulary rate beginning April 1, 2002. At June 30, 2002,
the remaining balance in deferred revenue was $7.6 million.
3. In June 2001, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards ("SFAS") No. 143 "Accounting for Asset
Retirement Obligations" which will be effective for us beginning January 1,
2003. The standard requires entities to record at fair value an asset
retirement obligation in the period in which it is incurred. When the
liability is initially recorded, the entity capitalizes the costs by
increasing the carrying amount of the related long-lived asset. Over time,
the liability is accreted to its present value each period, and the
capitalized asset is depreciated over the useful life of the long-lived
asset. We do not believe that this statement will have a material effect on
results of our operations due to our ability to recover decommissioning
costs through rate adjustments.
4. In December 2001, certain interpretative guidance related to SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities," was
revised. This revised interpretive guidance became effective for us
beginning April 1, 2002. Under the new guidance, certain energy option
contracts, which previously qualified for the normal purchases and sales
exception under SFAS No. 133, were required to be recorded at market value.
We entered into the energy option contracts to hedge the variability of
cash flows associated with changes in the market prices of energy. At June
30, 2002, we have recorded a net unrealized loss in accumulated other
comprehensive income of approximately $15.0 million associated with the
effective portion of the change in fair value of the option contracts
designated as cash flow hedges. There was no hedge ineffectiveness during
the three and six month periods ended June 30, 2002.
Based on the balance at June 30, 2002, we expect to reclassify
approximately $15.0 million of net unrealized losses from accumulated other
comprehensive income to operating expense over the period of the contracts.
The actual amounts that will be reclassified to operating expense will vary
from this amount as a result of changes in market prices.
At June 30, 2002, accrued expenses include an $8.4 million derivative
liability relative to these contracts.
5. On May 9, 2001, we entered into a Master Power Purchase and Sales Agreement
with Enron Power Marketing, Inc. ("EPMI"). Pursuant to transactions entered
into under this agreement, EPMI was obligated to deliver power to us
through December 31, 2003. Following its filing for bankruptcy protection
on December 2, 2001, EPMI ceased scheduling deliveries of power under the
agreement beginning December 15, 2001. We then terminated the agreement.
While the terms of the agreement call for us to make a termination payment
to EPMI, we have disputed
6
that obligation due to fraudulent behavior on EPMI's part. If it is
ultimately determined that we owe any amounts to EPMI, such amounts are not
expected to have a material impact on our financial position, results of
operations, or cash flow due to our ability to collect such amounts through
rates. We are currently in discussions with EPMI.
6. TEC Trading, Inc. ("TEC Trading"), a corporation owned by our member
distribution cooperatives, was formed for the primary purposes of
purchasing power from us to sell in the market, acquiring natural gas to
supply our three combustion turbine facilities, and taking advantage of
other power-related trading opportunities in the market, which will help
lower our member distribution cooperatives' costs. To fully participate in
power-related markets, TEC Trading will be required to maintain credit
support sufficient to meet delivery and payment obligations associated with
power trades. To assist TEC Trading in providing this credit support, we
have agreed to guarantee up to $42.5 million of TEC Trading's delivery and
payment obligations associated with its power trades. At June 30, 2002, we
had a $0.5 million guarantee outstanding.
7
OLD DOMINION ELECTRIC COOPERATIVE
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management's Discussion and Analysis of Financial Condition and Results of
Operations contains 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 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 energy, federal and state legislative and regulatory actions and legal and
administrative proceedings, changes in and compliance with environmental laws
and policies, weather conditions, the cost of commodities used in our industry,
and unanticipated changes in operating expenses and capital expenditures. Our
actual results may vary materially from those discussed in the forward-looking
statements as a result of these and other factors. 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.
Critical Accounting Policies
The preparation of our financial statements in conformity with generally
accepted accounting principles requires that our management make estimates and
assumptions that affect the amounts reported in our financial statements. We
base these estimates and assumptions on information available as of the date of
the financial statements and they are not necessarily indicative of the results
to be expected for the year. We consider the following accounting policies to be
critical accounting policies due to the estimation involved in each.
Accounting for Rate Regulation. We are a rate regulated entity and as such
are subject to the accounting requirements of SFAS No. 71, "Accounting for
Certain Types of Regulation." In accordance with SFAS No. 71, certain expenses
and revenues normally reflected in income are deferred on the balance sheet and
are recognized in income consistent with their recovery in rates. We have
deferred certain expenses and revenues on our balance sheet based on rate action
by our board of directors and approval by the Federal Energy Regulatory
Commission ("FERC"), which we are recognizing in income concurrent with their
recovery in rates.
Margin Stabilization Plan. Our board of directors established a Margin
Stabilization Plan in 1984. This plan allows us to review our actual cost of
service and power sales as of year end and adjust revenues from our member
distribution cooperatives to meet our financial coverage requirements. Our
formulary rate allows us to recover and refund amounts under the Margin
Stabilization Plan. We record all adjustments, whether increases or decreases,
in the year affected and allocate any adjustments to our member distribution
cooperatives based on power sales during that year. We collect these increases
from our member distribution cooperatives, or offset decreases against amounts
owed by our member distribution cooperatives to us, in the succeeding year.
Accounting for Decommissioning Costs. We accrue decommissioning costs over
the expected service life of the North Anna Power Station ("North Anna") and
make periodic deposits in a trust fund, such that the fund balance will equal
our estimated decommissioning cost at the time of decommissioning. The present
value of our future decommissioning cost is credited to the decommissioning
reserve; increases are charged to our members through their rates. Our estimated
cost to decommission North Anna is $91.3 million, based on a site-specific study
performed by Virginia Electric and Power Company ("Virginia Power") in 1998.
Virginia Power expects to complete a new cost estimate in 2002.
8
Results of Operations
Operating Revenues
Sales to Members. Our operating revenues are derived from power sales to
our members and to non-members. Revenues from sales to members are a function of
our member distribution cooperatives' consumers' requirement for power and our
formulary rate for sales of power to our member distribution cooperatives. The
formulary rate has three components: a demand rate, a base energy rate, and a
fuel factor adjustment rate. The demand rate is designed to recover all of our
capacity-related costs, which are primarily fixed costs, such as depreciation
expense, interest expense, administrative and general expenses, capacity costs
under power purchase contracts with third parties, capacity-related transmission
costs, and our margin requirement. The base energy rate recovers energy costs,
which are primarily variable costs, such as nuclear and coal fuel costs and the
energy costs under our power purchase contracts with third parties. To the
extent the base energy rate either over or under collects all of our energy
costs, we refund or collect the difference through a fuel factor adjustment
rate. Of these components, only the base energy rate is a fixed rate that
requires FERC approval prior to adjustment.
The formulary rate includes a fixed base energy rate and identifies the
types of costs that we can collect through the demand rate and the fuel factor
adjustment rate, but not the actual amounts to be collected. The actual amounts
to be collected under the formulary rate typically change each year.
Specifically, the demand rate is revised automatically to recover the costs
contained in our annual budget and any revision made by the board of directors
to our annual budget. In addition, we review our energy costs at least every six
months to determine whether the base energy rate and the fuel factor adjustment
rate adequately recover our energy costs. Because the base energy rate does not
change, we revise the fuel factor adjustment rate accordingly to minimize any
under or over collection of energy costs. Our deferred energy balance represents
the net accumulation of any previous under or over collections of energy costs.
Our member revenues by formulary rate component, energy sales to our
members, and average member cost per megawatt-hour ("MWh") for the three and six
months ended June 30, 2002 and 2001, were as follows:
Three Months Ended Six Months Ended
June 30, June 30,
--------------------- ----------------------
2002 2001 2002 2001
-------- --------- ---------- ----------
Member Revenues (in thousands)
Demand rate $ 49,733 $ 45,498 $104,467 $106,097
Base energy rate 40,614 37,343 83,940 81,449
Fuel factor adjustment rate 21,563 29,158 55,344 43,693
-------- -------- -------- --------
Total Member Revenues $111,910 $111,999 $243,751 $231,239
======== ======== ======== ========
Sales (in MWh) 2,290,271 2,065,651 4,689,270 4,526,199
Average Member Cost ($ per MWh)(1) $48.86 $54.22 $51.98 $51.09
--------------------
(1) Our average member cost is based on the blended cost of power from all
of our sources.
9
Changes in our member revenues attributed to growth in sales volume and changes
in our average rates for demand and energy (including our base energy rate and
fuel factor adjustment rate) for the three and six months ended June 30, 2002 as
compared to 2001, were as follows:
Three Months Six Months
Ended June 30, Ended June 30,
2002 Compared to 2001 2002 Compared to 2001
--------------------- ----------------------
(in thousands)
Change in member revenues due to change in:
Demand sales volume $ 7,029 $10,209
Energy sales volume 6,098 4,844
-------- -------
Total sales volume 13,127 15,053
-------- -------
Demand rate (2,794) (11,839)
Energy rate (10,422) 9,298
-------- -------
Total rates (13,216) (2,541)
-------- -------
Total change in member revenues $ (89) $12,512
======== =======
We increased our fuel factor adjustment rate April 1, 2001, to recover
energy costs that we previously incurred but did not fully recover under the
base energy rate and existing fuel factor adjustment rate and to recover future
energy costs that we expected to be more expensive than we originally budgeted.
We reduced our fuel factor adjustment rate effective April 1, 2002, because the
fuel factor adjustment rate, which had been in effect since April 1, 2001, had
adequately recovered our deferred energy balance at December 31, 2001 (an $18.2
million under collection of energy costs) and had resulted in a $4.1 million
over collection of energy costs at March 31, 2002. The resulting fuel factor
adjustment rate was still greater than the fuel factor adjustment rate that was
in effect on January 1, 2001.
Total member revenues for the second quarter of 2002 were unchanged from
the same period in 2001. Increases in member revenues generated by 16.5% and
10.9% increases in demand and energy sales volumes, respectively, were offset by
a decrease in our average energy rate. Our average energy rate (including our
base energy rate and our fuel factor adjustment rate) for the three months ended
June 30, 2002, decreased 15.7% over the same period in 2001 as a result of a
reduction in our fuel factor adjustment rate.
Total member revenues for the first six months of 2002 increased $12.5
million, or 5.4%, as compared to the same period in 2001 primarily because of an
increase in demand and energy sales and a higher average fuel factor adjustment
rate. The increase in member revenues was partially offset by a 6.1% decrease in
the average demand rate, which largely resulted from reductions in our demand
rate April 1, 2001 and June 1, 2001. Effective April 1, 2002, we increased our
demand rate because of anticipated higher demand costs, primarily transmission
costs.
Sales to Non-Members. Sales to non-members represent sales of excess
purchased energy and sales of excess generated energy from the Clover Power
Station ("Clover"). Excess purchased energy is sold to Pennsylvania-New
Jersey-Maryland Interconnection, LLC ("PJM") under its rates for providing
energy imbalance service. Excess energy from Clover is sold to Virginia Power
pursuant to the Clover Operating Agreement. Non-member revenues increased $1.1
million in the second quarter of 2002 and decreased $1.5 million in the first
half of 2002 as compared to the same periods in 2001 primarily as a result of
sales of energy to PJM.
Operating Expenses
We supply our member distribution cooperatives' power requirements,
consisting of capacity requirements and energy requirements, through (1) our
owned or leased interests in electric generating facilities, a 50% interest in
Clover and an 11.6% interest in North Anna, and (2) power purchases from third
parties through power purchase contracts and forward, short-term, and spot
market energy purchases. Our energy supply for the three and six months ended
June 30, 2002 and 2001, was as follows:
10
Three Months Ended Six Months Ended
June 30, June 30,
-------------------------------------- ------------------------------------
2002 2001 2002 2001
----------------- ----------------- ---------------- ----------------
(MWh) (MWh) (MWh) (MWh)
Generated:
Clover 615,293 26.8% 743,644 32.2% 1,310,425 27.4% 1,579,313 33.6%
North Anna 469,330 20.4 429,247 18.6 935,327 19.5 823,708 17.5
--------- ----- --------- ----- --------- ----- --------- ----
Total generated 1,084,623 47.2 1,172,891 50.8 2,245,752 46.9 2,403,021 51.1
--------- ----- --------- ----- --------- ----- --------- ----
Purchased:
Virginia Area 678,991 29.5 596,587 25.9 1,416,424 29.6 1,169,411 24.9
Delmarva Area 504,888 21.9 488,819 21.2 1,059,304 22.1 1,013,804 21.6
Other 31,427 1.4 49,511 2.1 69,268 1.4 112,110 2.4
--------- ----- --------- ----- --------- ----- --------- -----
Total purchased 1,215,306 52.8 1,134,917 49.2 2,544,996 53.1 2,295,325 48.9
--------- ----- --------- ----- --------- ----- --------- -----
Total Available Energy 2,299,929 100.0% 2,307,808 100.0% 4,790,748 100.0% 4,698,346 100.0%
========= ===== ========= ===== ========= ===== ========= =====
Generated. Generating facilities, particularly nuclear power plants such as
North Anna, generally have relatively high fixed costs. Nuclear facilities
operate with relatively low variable costs due to lower fuel costs and
technological efficiencies. Owners of nuclear and other power plants incur the
embedded fixed costs of these facilities whether or not the units operate. When
either North Anna or Clover is off-line, we must purchase replacement energy
from either Virginia Power, which is more costly, or the market, which may be
more or less costly. As a result, our operating expenses, and consequently our
rates to our member distribution cooperatives, are significantly affected by the
operations of North Anna and Clover. The output of North Anna and Clover for the
second quarter and first six months of 2002 and 2001 as a percentage of the
maximum dependable capacity rating of the facilities was as follows:
North Anna Clover
------------------------------ ----------------------------
Three Six Three Six
Months Ended Months Ended Months Ended Months Ended
June 30, June 30, June 30, June 30,
------------- ------------- -------------- -------------
2002 2001 2002 2001 2002 2001 2002 2001
----- ----- ----- ----- ---- ---- ---- ----
Unit 1 101.0% 100.6% 101.1% 100.8% 52.8% 87.5% 56.6% 83.0%
Unit 2 100.2 86.9 100.4 76.7 75.0 71.6 81.6 83.8
Combined 100.6 93.8 100.8 88.8 63.9 79.6 69.1 83.4
North Anna. There were no maintenance outages at either of the North Anna
units during the first six months of 2002. During the first six months of 2001,
North Anna Unit 2 underwent a 30-day scheduled refueling outage. Unit 1 was not
off-line during the first six months of 2001.
Clover. Clover Unit 1 was removed from service on March 1, 2002, for a
scheduled maintenance outage and was returned to service on May 2, 2002. The
unit also experienced minor unscheduled outages during the first half of 2002.
On February 16, 2002, the load on Clover Unit 2 was reduced to 125 MW due to a
forced draft fan motor failure. The unit was returned to full load operations on
March 2, 2002. Clover Unit 2 was removed from service April 20, 2002, for a
scheduled maintenance outage and was returned to service on May 3, 2002. During
the first six months of 2001, Clover Unit 1 was off-line 13 days and Clover Unit
2 was off-line 15 days for scheduled maintenance outages.
Purchased. Load requirements and market forces influence the structure of
our new power supply contracts. Within PJM, our contracts reflect the need to
have capacity (either owned generation facilities or rights to the capacity of a
generating facility under power contracts) to meet our member distribution
cooperatives' capacity requirements. To meet our member distribution
cooperatives' energy requirements on the Delmarva Peninsula, we purchase energy
from the market or utilize the PJM power pool when economical. In Virginia,
capacity and energy requirements are provided principally by Virginia Power,
American Electric Power - Virginia, and Allegheny Power Resources.
11
The major components of our operating expenses for the three and six months
ended June 30, 2002 and 2001, were as follows:
Three Months Ended Six Months Ended
June 30, June 30,
--------------------- -------------------
2002 2001 2002 2001
-------- -------- -------- --------
(in thousands)
Fuel $ 12,269 $ 14,046 $ 25,865 $ 27,753
Purchased power (including deferred energy) 72,151 61,404 160,053 123,428
Operations and maintenance 8,197 8,767 16,894 17,304
Administrative and general 6,065 4,888 10,732 11,455
Depreciation, amortization and decommissioning 2,058 11,429 7,899 31,658
Taxes, other than income taxes 842 783 1,707 1,587
-------- -------- -------- --------
Total operating expenses $101,582 $101,317 $223,150 $213,185
======== ======== ======== ========
Aggregate operating expenses for the second quarter and first six months of
2002 increased $0.3 million, or 0.3%, and $10.0 million, or 4.7%, respectively,
over the same periods in 2001 primarily because of an increase in purchased
power expenses. The cost of purchased power during the second quarter and first
half of 2002, excluding deferred energy, decreased $27.1 million, or 35.2%, and
$2.4 million, or 1.9%, respectively, over the same periods in 2001 because of a
decrease in the average cost of demand and energy purchased. However, as a
result of changes in the amount of deferred energy expensed as a component of
purchased power, our total purchased power expenses rose 17.5% and 29.7% in the
second quarter and first six months of 2002, respectively, as compared to the
same periods in 2001. The amount of deferred energy expensed through purchased
power is a function of our fuel factor adjustment rate and the cost of energy
purchased. The increase in purchased power was partially offset by a decrease in
depreciation, amortization and decommissioning expense because we stopped
recording accelerated depreciation in accordance with our Strategic Plan
Initiative effective June 1, 2001 and we began reversing the $11.4 million of
deferred revenue recorded in 2001 beginning April 1, 2002. At June 30, 2002, the
remaining deferred revenue balance was $7.6 million.
Other Items
Investment Income. Investment income decreased $0.1 million, or 21.1%, and
$0.5 million, or 36.7%, in the second quarter and first half of 2002,
respectively, as compared to the same periods in 2001 because we liquidated
certain investments to fund construction expenses.
Interest Charges, net. Net interest charges increased $0.2 million, or
2.4%, and $0.9 million, or 4.8%, in the second quarter and first six months of
2002 as compared to the same periods in 2001 because of interest on the $215.0
million of indebtedness issued in the third quarter of 2001, offset by interest
capitalized on our combustion turbine construction projects.
Net Margin. Our net margin, which is a function of our interest charges and
our margin requirement, increased $0.1 million, or 7.7%, and $0.7 million, or
18.2%, in the second quarter and first six months of 2002 as compared to the
same periods in 2001, because our interest expense was higher due to our
issuance of indebtedness in 2001.
Financial Condition
The principal changes in our financial condition from December 31, 2001 to
June 30, 2002, were caused by changes in construction work in progress, deferred
energy, and accrued expenses. The increase in construction work in progress of
$78.4 million, or 61.6%, is due to payments for construction of our three
combustion turbine facilities, which are being developed by our subsidiaries.
The change in deferred energy from an $18.2 million under collection of energy
costs to a $15.1 million over collection of energy costs resulted from
increasing our fuel factor adjustment rate. The increase in accrued expenses of
$8.4 million, or 51.2%, is due to the derivative liability of $8.4 million.
12
Liquidity and Capital Resources
Operations. Historically, our operating cash flows have been sufficient to
meet our short- and long-term capital expenditures related to North Anna and
Clover, our debt service requirements, and our ordinary business operations. Our
operating activities provided cash flows of $54.9 million and $51.9 million for
the six month periods ended June 30, 2002 and 2001, respectively. Operating
activities in the first six months of 2002 were affected primarily by the
discontinuance of accelerated depreciation, changes in our fuel factor
adjustment rate, and changes between periods in non-cash working capital
accounts.
Financing Activities. In October 2000, our subsidiaries submitted
applications to Rural Utilities Services ("RUS") for loan guarantees to finance
the entire cost of our three combustion turbine facilities currently under
development or construction. However, in July 2002, RUS determined that it would
not be able to approve our loan guarantee requests and advance funds before
2003. Because we estimate that additional funds will be needed during the fourth
quarter of 2002 to finance the development and construction of the combustion
turbine facilities, we withdrew our RUS applications and will pursue additional
financing through issuances of indebtedness under our indenture.
If funding for the development or construction of the combustion turbine
facilities is needed prior to our next issuance of indebtedness under our
indenture, we will borrow funds under construction-related committed lines of
credit. These lines of credit totaled $115 million at June 30, 2002. Lines of
credit totaling $60 million expired during the second quarter of 2002 and were
subsequently renewed for additional one-year terms. One line of credit in the
amount of $55 million expired July 15, 2002. We are currently negotiating to
reinstate this line of credit in the amount of $50 million. A financial covenant
in our indenture limits our short-term indebtedness to the greater of $100
million and 15% of our total long-term debt and equities. As of June 30, 2002,
this covenant would have limited the aggregate amount we could have drawn under
all our lines of credit, which include an additional $95 million of general
working capital lines of credit, to approximately $128.6 million.
Investing Activities. Investing activities in the second quarter of 2002
consisted primarily of expenditures for our three combustion turbine facilities
and a reduction in investments due to liquidating investments to fund
construction expenses.
Other Matters
On May 9, 2001, we entered into a Master Power Purchase and Sales Agreement
with Enron Power Marketing, Inc. ("EPMI"). Pursuant to transactions entered into
under this agreement, EPMI was obligated to deliver power to us through December
31, 2003. Following its filing for bankruptcy protection on December 2, 2001,
EPMI ceased scheduling deliveries of power under the agreement beginning
December 15, 2001. We then terminated the agreement. While the terms of the
agreement call for us to make a termination payment to EPMI, we have disputed
that obligation due to fraudulent behavior on EPMI's part. If it is ultimately
determined that we owe any amounts to EPMI, such amounts are not expected to
have a material impact on our financial position, results of operations, or cash
flow due to our ability to collect such amounts through rates. We are currently
in discussions with EPMI.
During an inspection at North Anna, Virginia Power determined that the
reactor vessel heads on North Anna Units 1 and 2 need to be replaced. Virginia
Power plans to replace the heads in 2004 at an estimated cost to us of $9.5
million.
Virginia Power plans to upgrade the main turbines on North Anna Units 1 and
2 during scheduled refueling outages in 2005 and 2006. The estimated cost to us
of the turbine upgrade project is approximately $19.8 million. Our expected
share of the capacity increase from the upgrades is 14 MW.
In June 2001, Virginia Power filed applications with the Nuclear Regulatory
Commission ("NRC") to renew the operating licenses for both North Anna units.
The NRC issued a draft environmental impact statement in June 2002 that found
that the continued operation of North Anna would have minimal impact on the
environment if the operating licenses were renewed. The environmental impact
statement was open for public comment until August 1, 2002.
13
On July 17, 2002, we received a Certificate of Convenience and Public
Necessity ("CPCN") from the Virginia State Corporation Commission for our
combustion turbine facility located in Louisa County, Virginia. We expect to
begin construction on the facility in the third quarter of 2002 and to have the
units available for commercial operation in 2003.
In 1998, the Environmental Protection Agency issued a rule addressing
regional transport of ground-level ozone through reductions in nitrogen oxides
("NOx"), commonly known as the NOx State Implementation Plan ("SIP") call. The
NOx SIP call requires emissions reductions to be implemented by May 1, 2004. We
and Virginia Power have evaluated our options for meeting the NOx SIP call as
applicable to Clover and have determined the best alternative to be installation
of additional NOx controls at Clover combined with the purchase of emissions
credits. The estimated cost of these activities to us is expected to be
approximately $8.5 million. We expect to be in full compliance with the NOx SIP
call by May 1, 2003.
In October 1997, we filed with FERC a Section 206 complaint against PSE&G
asserting that our power purchase agreement with PSE&G should be modified to
conform to the restructuring of PJM. Under the PJM structure, we pay for the
transmission of PSE&G power through Conectiv's zonal rate. On May 14, 1998, FERC
ruled in our favor, ordering PSE&G to remove any transmission costs from its
rates for capacity and associated energy sold to us. PSE&G complied with the
FERC order by virtue of a compliance filing submitted to FERC on June 15, 1998.
Still, in 2000, PSE&G filed a petition for review of FERC's orders in the matter
with the United States Court of Appeals for the District of Columbia Circuit.
On July 12, 2002, the Court of Appeals vacated FERC's May 14, 1998 ruling
and remanded the complaint to FERC for further consideration and proceedings. We
intend to vigorously pursue our original complaint with FERC in the remanded
proceeding. Until FERC takes action on the matter on remand, we are aware of no
requirement that we pay for the disputed transmission costs since June 15, 1998.
We estimate these costs to be approximately $23.4 million for the period from
May 14, 1998 through June 30, 2002, and approximately $37.2 million for the
period from May 14, 1998 through the end of the term of the agreement. We cannot
predict the outcome of this proceeding. Any amount we ultimately may be required
to pay to PSE&G with respect to this matter would be recovered from our members
through our formulary rate.
In August 2002, Virginia Power formally notified the Nuclear Regulatory
Commission that, due to drought conditions in Virginia, a dropping water level
in Lake Anna could force Virginia Power to temporarily discontinue operations at
North Anna. The water level of Lake Anna, which supplies cooling water for North
Anna's generators, has fallen below 246 feet above sea level. If the lake falls
to 244 feet above sea level, the plant is required to temporarily discontinue
operations. However, Virginia Power is examining ways to modify its procedures
at North Anna to allow it to keep the reactors operating even if the lake falls
below 244 feet. If North Anna is required to temporarily discontinue operations,
Virginia Power is required to supply us with reserve capacity and energy under
the Interconnection and Operating Agreement.
14
OLD DOMINION ELECTRIC COOPERATIVE
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.
Other than certain legal proceedings arising out of the ordinary
course of business, which management believes will not have a
material adverse impact on the results of operations or financial
condition of Old Dominion, there is no other litigation pending or
threatened against Old Dominion.
Item 6. Exhibits and Reports on Form 8-K.
(b) Reports on Form 8-K.
The Registrant filed no reports on Form 8-K during the quarter
ended June 30, 2002.
15
SIGNATURE
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 thereunto duly authorized.
OLD DOMINION ELECTRIC COOPERATIVE
Registrant
Date: August 13, 2002 /s/Daniel M. Walker
-----------------------------------------------
Daniel M. Walker
Senior Vice President of Accounting and Finance
(Chief Financial Officer)
16
EXHIBIT INDEX
Exhibit Page
Number Description of Exhibit Number
- ------ ---------------------- ------
99.1a Certificate of Principal Executive Officer Pursuant to
18.U.S.C. Section 1350
99.1b Certificate of Principal Financial Officer Pursuant to
18.U.S.C. Section 1350
17