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 March 31, 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
------
PART I. Financial Information
Item 1. Financial Statements
Condensed Consolidated Balance Sheets - March 31, 2002 (Unaudited)
and December 31, 2001 3
Condensed Consolidated Statements of Revenues, Expenses and
Patronage Capital (Unaudited) - Three Months Ended
March 31, 2002 and 2001 4
Condensed Consolidated Statements of Comprehensive Income (Unaudited) -
Three Months Ended March 31, 2002 and 2001 4
Condensed Consolidated Statements of Cash Flows (Unaudited) - Three
Months Ended March 31, 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 7
PART II. Other Information
Item 1. Legal Proceedings 13
Item 6. Exhibits and Reports on Form 8-K 13
Signature 14
2
OLD DOMINION ELECTRIC COOPERATIVE
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
CONDENSED CONSOLIDATED BALANCE SHEETS
March 31, December 31,
2002 2001*
----------------- -----------------
(in thousands)
ASSETS: (unaudited)
- -----------------------------------------------------------------------------
Electric Plant:
In service $ 902,533 $ 899,691
Less accumulated depreciation (346,796) (340,440)
----------- -----------
555,737 559,251
Nuclear fuel, at amortized cost 6,959 8,487
Construction work in progress 160,421 127,270
---------- ----------
Net Electric Plant 723,117 695,008
---------- ----------
Investments:
Nuclear decommissioning trust 60,893 59,700
Lease deposits 136,399 137,265
Other 185,579 159,083
---------- ----------
Total Investments 382,871 356,048
---------- ----------
Current Assets:
Cash and cash equivalents 51,362 77,981
Receivables 69,229 61,097
Fuel, materials and supplies, at average cost 16,625 13,936
Prepayments 1,815 1,783
Deferred energy - 18,244
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Total Current Assets 139,031 173,041
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Deferred Charges 29,940 32,053
----------- -----------
Total Assets $1,274,959 $1,256,150
========== ==========
CAPITALIZATION AND LIABILITIES:
- -----------------------------------------------------------------------------
Capitalization:
Patronage capital $ 228,053 $ 225,538
Accumulated other comprehensive income (128) 398
Long-term debt 625,914 625,232
---------- ----------
Total Capitalization 853,839 851,168
---------- ----------
Current Liabilities:
Long-term debt due within one year 39,927 39,927
Accounts payable 60,206 59,525
Accounts payable - members 36,685 38,223
Accrued expenses 33,914 16,415
----------- -----------
Total Current Liabilities 170,732 154,090
---------- ----------
Deferred Credits and Other Liabilities
Decommissioning reserve 60,893 59,700
Obligations under long-term leases 139,291 140,291
Other 50,204 50,901
---------- -----------
Total Deferred Credits and Other Liabilities 250,388 250,892
---------- ----------
Commitments and Contingencies - -
---------- ----------
Total Capitalization and Liabilities $1,274,959 $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
March 31,
-------------------------------
2002 2001
------------ -------------
(in thousands)
Operating Revenues $132,247 $122,288
-------- --------
Operating Expenses:
Fuel 13,596 13,707
Purchased power 87,902 62,024
Operations and maintenance 8,697 8,537
Administrative and general 4,667 6,567
Depreciation, amortization and
decommissioning 5,841 20,229
Taxes other than income taxes 865 804
-------- --------
Total Operating Expenses 121,568 111,868
-------- --------
Operating Margin 10,679 10,420
Other Income/(Expense), net 805 490
Investment Income 1,454 767
Interest Charges, net (10,422) (9,721)
-------- --------
Net Margin 2,516 1,956
Patronage Capital - Beginning of Period 225,537 224,598
-------- --------
Patronage Capital - End of Period $228,053 $226,554
======== ========
- -------------------------------------------------------------------------------
OLD DOMINION ELECTRIC COOPERATIVE
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
Three Months Ended
March 31,
-------------------------------
2002 2001
------------ -------------
(in thousands)
Net Margin $2,516 $1,956
Other Comprehensive Income:
Unrealized (loss)/gain on investments (526) 913
------ ------
Comprehensive Income $1,990 $2,869
====== ======
- -------------------------------------------------------------------------------
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)
Three Months Ended
March 31,
------------------------------
2002 2001
----------- -------------
(in thousands)
Operating Activities:
Net Margin $ 2,516 $ 1,956
Adjustments to reconcile net margins to net cash provided by
operating activities:
Depreciation, amortization and decommissioning 5,841 20,229
Other non-cash charges 2,463 1,976
Amortization of lease obligations 2,467 2,362
Interest on lease deposits (2,419) (2,313)
Change in current assets 754 (12,638)
Change in current liabilities 23,279 24,661
Deferred charges and credits 1,851 10
--------- ---------
Net Cash Provided by Operating Activities 36,752 36,243
--------- ---------
Financing Activities:
Principal payments and purchases of long-term debt - (1,587)
Obligations under long-term leases (181) (179)
--------- ---------
Net Cash Used for Financing Activities (181) (1,766)
--------- ---------
Investing Activities:
Lease deposits and other investments (27,023) (1,079)
Electric plant additions (35,997) (16,173)
Decommissioning fund deposits (170) (170)
--------- ---------
Net Cash Used for Investing Activities (63,190) (17,422)
--------- ---------
Net Change in Cash and Cash Equivalents (26,619) 17,055
Cash and Cash Equivalents - Beginning of Period 77,981 20,259
--------- ---------
Cash and Cash Equivalents - End of Period $ 51,362 $ 37,314
========= =========
- -------------------------------------------------------------------------------
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 March 31, 2002, and our consolidated
results of operations, comprehensive income, and cash flows for the three
months ended March 31, 2002 and 2001. The consolidated results of
operations for the three months ended March 31, 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 March 31, 2001,
depreciation, amortization and decommissioning included $14.3 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 our formulary rate we charged our members
in 2001, which we will use to partially offset the increases in the demand
component of the formulary rate beginning April 1, 2002.
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 with respect to us
beginning 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 adverse
effect on results of our operations due to our current and future 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
and will be effective for us in the second quarter of 2002. The revised
guidance is not expected to have a material effect on our financial
statements.
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 believe that, due to fraudulent behavior on EPMI's part, no
such payment is due. 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.
6. TEC Trading, Inc. ("TEC Trading"), which is owned by our member
distribution cooperatives, was formed for the primary purpose 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 March 31, 2002,
there were no amounts outstanding under the guarantee.
6
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 management to make estimates and
assumptions that affect the amounts reported therein. These estimates and
assumptions are based on information available as of the date of the financial
statements and 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.
Accounting for Decommissioning Costs. We accrue decommissioning costs over
the expected service life of 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
expected to be $91.3 million, based on a site-specific study performed by
Virginia Electric and Power Company ("Virginia Power") in 1998. A new cost
estimate will be completed in 2002.
7
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. 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 over or under collects all of our energy costs, we
refund or collect the difference through a fuel factor adjustment. Of these
components, only the base energy rate is a fixed rate that requires FERC
approval prior to adjustment.
The formulary rate identifies the costs that we can collect through the
demand rate and the fuel factor adjustment, but not the actual amounts to be
collected. Our costs to be collected under the components of 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 adequately recover our energy costs.
We revise the fuel factor adjustment accordingly.
Our member revenues by formulary rate component, energy sales to our
members, and average member cost per megawatt-hour ("MWh") for the three months
ended March 31, 2002 and 2001, were as follows:
Three Months Ended
March 31,
----------------------------
2002 2001
----------- ----------
Member revenues (in thousands)
Demand................................. $ 54,734 $ 60,599
Base energy rate....................... 43,326 44,106
Fuel factor adjustment................. 33,781 14,535
---------- ----------
Total member revenues............... $ 131,841 $ 119,240
========== ==========
Sales (in MWh)............................ 2,398,999 2,460,548
Average member cost (in MWh)(1)........... $ 54.96 $ 48.46
------------------------
(1) Our average member cost is based on the blended cost of power from all
of our sources.
8
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) for the three months ended March 31, 2002 as compared to
2001 were as follows:
Three Months
Ended March 31,
2002 compared to 2001
---------------------
(in thousands)
Change in member revenues due to change in:
Sales:
Demand sales volume............................. $ 872
Energy sales volume............................. (1,040)
-------
Total change in sales volume................. (168)
-------
Rates:
Demand rate..................................... (6,737)
Energy rate..................................... 19,506
-------
Total change in rate......................... 12,769
-------
Total change in member revenues.............. $12,601
=======
Total member revenues for the first quarter of 2002 increased $12.6
million, or 10.6%, over the same period in 2001 primarily as a result of an
increase in our average energy rate offset by a decrease in our demand rate,
both of which became effective April 1, 2001. Our average energy rate (including
our base energy rate and our fuel factor adjustment) for the three months ended
March 31, 2002, increased 33.9% over the same period in 2001 as a result of
changes in our fuel factor adjustment. The base energy rate is a fixed rate in
our formulary rate and did not change. We increased our fuel factor adjustment
for two reasons. First, our energy costs were higher than we projected and we
needed to recover energy costs that we previously incurred but did not fully
recover under the base energy rate and existing fuel factor adjustment. These
higher energy costs relate to, among other items, short-term power purchases and
coal purchases. Second, we increased the fuel factor adjustment to a level that,
combined with the base energy rate, we anticipated would adequately recover
future energy costs that we expect to be more expensive than we originally
budgeted.
On April 9, 2002, our board of directors approved an increase in our demand
rate of approximately 6.0% effective April 1, 2002 to recover increases in our
demand related costs. Concurrent with the increase in our demand rate we reduced
our fuel factor adjustment rate approximately 31.5% effective April 1, 2002. We
reduced our fuel factor adjustment rate because we have fully collected the
$18.2 million deferred energy balance that we had at December 31, 2001.
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 Electric
and Power Company ("Virginia Power") pursuant to the requirements of the Clover
Operating Agreement. Non-member revenues for the first quarter of 2002 decreased
$2.6 million as compared to the same period in 2001 primarily as a result of
lower 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 months ended March 31, 2002
and 2001, was as follows:
9
Three Months Ended
March 31,
--------------------------------------
2002 2001
---------------- -----------------
(in MWh)
Generated:
Clover......................................... 695,132 27.9% 813,540 31.7%
North Anna..................................... 465,997 18.7 386,134 15.0
--------- ----- --------- -----
Total generated............................. 1,161,129 46.6 1,199,674 46.7
--------- ----- --------- -----
Purchased:
Virginia area.................................. 737,433 29.6 727,747 28.3
Delmarva area.................................. 554,416 22.3 576,769 22.5
Other.......................................... 37,842 1.5 63,499 2.5
--------- ----- --------- -----
Total purchased............................. 1,329,691 53.4 1,368,015 53.3
--------- ----- --------- -----
Total available energy.................. 2,490,820 100.0% 2,567,689 100.0%
========= ===== ========= =====
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
first quarter of 2002 and 2001 as a percentage of the maximum dependable
capacity rating of the facilities was as follows:
North Anna Clover
----------------------- -----------------------
Three Months Ended Three Months Ended
March 31, March 31,
----------------------- -----------------------
2002 2001 2002 2001
--------- --------- --------- ---------
Unit 1......................... 101.3% 100.9% 59.9% 77.4%
Unit 2......................... 100.7 66.3 87.5 95.3
Combined....................... 101.0 83.6 73.7 86.4
North Anna. There were no maintenance outages at North Anna during the
first three months of 2002. During the first three months of 2001, there were no
maintenance outages on North Anna Unit 1. North Anna Unit 2 began a scheduled
refueling outage on March 11, 2001, and was returned to service on April 10,
2001, four days ahead of schedule.
Clover. Clover Unit 1 was removed from service on March 1, 2002, for a
scheduled 54-day maintenance outage. The unit also experienced two minor
unscheduled outages during the first quarter of 2002. Clover Unit 2 experienced
only minor unscheduled outages during the first quarter of 2002. However, on
February 16, 2002, the unit load 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.
During the first quarter of 2001, Clover Unit 1 was off-line 13 days for a
scheduled maintenance outage. Clover Unit 2 was not off-line during the first
quarter of 2001.
Purchased. Market forces influence the structure of new power supply
contracts that we enter into. 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.
The major components of our operating expenses for the three months ended
March 31, 2002 and 2001, were as follows:
10
Three Months Ended
March 31,
------------------------------
2002 2001
------------ -----------
(in thousands)
Fuel................................................. $ 13,596 $ 13,707
Purchased power...................................... 87,902 62,024
Operations and maintenance........................... 8,697 8,537
Administrative and general........................... 4,667 6,567
Depreciation, amortization and decommissioning....... 5,841 20,229
Taxes, other than income taxes....................... 865 804
-------- --------
Total operating expenses.......................... $121,568 $111,868
======== ========
Aggregate operating expenses for the first quarter of 2002 increased $9.7
million, or 8.7%, over the same period in 2001 because of an increase in
purchased power expenses. The cost of demand and energy purchased during the
first quarter of 2002 decreased $15.3 million, or 21.1%, over the same period in
2001 because of a decrease in the average cost of demand and energy purchased.
However, as a result of increasing our fuel factor adjustment rate to recover
the $18.2 million deferred energy at December 31, 2001, our purchased power
expenses rose 41.7% in the first quarter of 2002 as compared to the same period
in 2001. The increase in purchased power was offset by a decrease in
depreciation, amortization and decommissioning expense because we ceased
recording accelerated depreciation effective June 1, 2001.
Other Items
Investment Income. Investment income increased $0.6 million, or 89.6%, in
the first quarter of 2002 as compared to the same period in 2001 because of an
increase in invested cash and cash equivalents resulting from the proceeds from
the issuance of debt in the third quarter of 2001.
Interest Charges, net. Interest charges, net increased $0.7 million, or
7.2%, in the first quarter of 2002 as compared to the first quarter of 2001
because of interest on the $215.0 million of indebtedness issued in September
2001.
Net Margin. Our net margin, which is a function of our interest charges,
increased $0.6 million, or 28.6%, in the first quarter of 2002 as compared to
the same period 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
March 31, 2002, were caused by increases in construction work in progress,
investments, and accrued expenses. The increase in construction work in progress
of $33.2 million, or 26.0%, is due to payments for construction of our three
combustion turbine facilities. The increase in other investments of $26.5
million, or 16.7%, is due to investing our excess cash. The increase in accrued
expenses of $17.5 million, or 106.6%, is due to accrued interest on our
outstanding indebtedness and a change in our deferred energy balance from an
$18.2 million asset (under-collection of costs) at December 31, 2001, to a $4.1
million liability (over-collection of costs) at March 31, 2002. This change
resulted from increasing our fuel factor adjustment to collect energy costs that
had not been recovered previously through our base energy rate and fuel factor
adjustment.
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 $36.8 million and $36.2 million at
March 31, 2002 and 2001, respectively. Operating activities in the first three
months of 2002 were affected primarily by changes between periods in non-cash
working capital accounts.
11
Financing Activities. At March 31, 2002 and 2001, we had no outstanding
letters of credit.
Investing Activities. Investing activities in the first quarter of 2002
consisted primarily of expenditures for our three combustion turbine facilities
and additions to investments.
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 believe that,
due to fraudulent behavior on EPMI's part, no such payment is due. 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.
During an inspection at North Anna, Virginia Power determined that the
reactor heads on North Anna Units 1 and 2 might need to be replaced. At March
31, 2002, Virginia Power was still evaluating the need to replace the heads.
12
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 March 31, 2002.
13
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: May 13, 2002 /s/Daniel M. Walker
----------------------------------
Daniel M. Walker
Senior Vice President of Accounting and Finance
(Chief Financial Officer)
14
EXHIBIT INDEX
Exhibit Page
Number Description of Exhibit Number
- ------- ---------------------- ------
15