SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
___________
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, 2001
or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
--- SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to __________
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)
__________
(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.
OLD DOMINION ELECTRIC COOPERATIVE
INDEX
Page
Number
------
PART I. Financial Information
Item 1. Financial Statements
Condensed Consolidated Balance Sheets - June 30, 2001 (Unaudited)
and December 31, 2000 3
Condensed Consolidated Statements of Revenues, Expenses and
Patronage Capital (Unaudited) - Three and Six Months Ended
June 30, 2001 and 2000 4
Condensed Consolidated Statements of Comprehensive Income (Unaudited) -
Three and Six Months Ended June 30, 2001 and 2000 4
Condensed Consolidated Statements of Cash Flows (Unaudited) - Six
Months Ended June 30, 2001 and 2000 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
OLD DOMINION ELECTRIC COOPERATIVE
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
CONDENSED CONSOLIDATED BALANCE SHEETS
June 30, December 31,
2001 2000
----------------- -----------------
(in thousands)
ASSETS: (unaudited) (*)
- -------------------------------------------------------------------------
Electric Plant:
In service $ 899,957 $ 900,290
Less accumulated depreciation (334,267) (304,588)
----------------- -----------------
565,690 595,702
Nuclear fuel, at amortized cost 2,962 5,598
Construction work in progress 80,389 47,598
----------------- -----------------
Net Electric Plant 649,041 648,898
----------------- -----------------
Investments:
Nuclear decommissioning trust fund 60,374 60,530
Lease deposits 132,754 131,364
Other 57,545 54,836
----------------- -----------------
Total Investments 250,673 246,730
----------------- -----------------
Current Assets:
Cash and cash equivalents 32,046 20,259
Receivables 44,500 46,769
Fuel, materials and supplies, at average cost 10,904 10,236
Prepayments 1,898 1,508
Deferred energy 21,085 15,376
----------------- -----------------
Total Current Assets 110,433 94,148
----------------- -----------------
Deferred Charges: 22,804 20,796
----------------- -----------------
Total Assets $ 1,032,951 $ 1,010,572
================= =================
CAPITALIZATION AND LIABILITIES:
- -------------------------------------------------------------------------
Capitalization:
Patronage capital $ 220,994 $ 224,598
Accumulated other comprehensive income 642 (256)
Long-term debt 447,564 449,823
----------------- -----------------
Total Capitalization 669,200 674,165
----------------- -----------------
Current Liabilities:
Long-term debt due within one year 30,488 30,488
Accounts payable 31,039 29,091
Accounts payable - Members 45,222 20,912
Accrued expenses 6,877 6,849
----------------- -----------------
Total Current Liabilities 113,626 87,340
----------------- -----------------
Deferred Credits and Other Liabilities:
Decommissioning reserve 60,374 60,530
Obligations under long-term leases 135,772 134,463
Other 53,979 54,074
----------------- -----------------
Total Deferred Credits and Other Liabilities 250,125 249,067
----------------- -----------------
Commitments and Contingencies - -
----------------- -----------------
Total Capitalization and Liabilities $ 1,032,951 $ 1,010,572
================= =================
- -------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of the consolidated financial
statements.
(*) The Consolidated Balance Sheet at December 31, 2000, 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,
------------------------------------ ---------------------------------------
2001 2000 2001 2000
---------------- ---------------- ----------------- -----------------
(in thousands)
Operating Revenues $ 111,933 $ 95,349 $ 234,221 $ 200,234
-------------- ------------------ ----------------- -----------------
Operating Expenses:
Fuel 14,046 11,558 27,753 23,317
Purchased power 61,404 39,972 123,428 80,976
Operations and maintenance 8,767 9,068 17,304 17,594
Administrative and general 4,888 5,278 11,455 9,394
Depreciation, amortization, and
decommissioning 11,429 15,653 31,658 40,826
Taxes other than income taxes 783 2,536 1,587 4,496
-------------- ------------------ ----------------- -----------------
Total Operating Expenses 101,317 84,065 213,185 176,603
-------------- ------------------ ----------------- -----------------
Operating Margin 10,616 11,284 21,036 23,631
Other Income/(Expense), net 192 (245) 682 (713)
Investment Income 700 1,359 1,467 2,452
Interest Charges, net (9,568) (10,318) (19,289) (21,116)
-------------- ------------------ ----------------- -----------------
Net Margin 1,940 2,080 3,896 4,254
Patronage Capital-Beginning of Period 226,554 218,543 224,598 216,369
Payment of Capital Credits (7,500) - (7,500) -
-------------- ------------------ ----------------- -----------------
Patronage Capital-End of Period $ 220,994 $ 220,623 $ 220,994 $ 220,623
============== ================== ================= =================
- ------------------------------------------------------------------------------------------------------------------------
OLD DOMINION ELECTRIC COOPERATIVE
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
------------------------------- ---------------------------------------
2001 2000 2001 2000
------------ --------------- ----------------- -----------------
(in thousands)
Net Margin $ 1,940 $ 2,080 $ 3,896 $ 4,254
Other comprehensive income:
Unrealized (loss)/gain on investments (15) 132 898 165
------------ --------------- ----------------- -----------------
Comprehensive income $ 1,925 $ 2,212 $ 4,794 $ 4,419
============ =============== ================= =================
- -----------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of the consolidated financial
statements.
4
OLD DOMINION ELECTRIC COOPERATIVE
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Six Months Ended
June 30,
--------------------------------------
2001 2000
---------------- -----------------
(in thousands)
Operating Activities:
Net margin $ 3,896 $ 4,254
Adjustments to reconcile net margin to net cash
provided by operating activities:
Depreciation, amortization, and decommissioning 30,358 40,826
Other noncash charges 4,051 4,081
Amortization of lease obligation 4,729 4,535
Interest on lease deposits (4,629) (4,431)
Change in current assets (4,498) (7,837)
Change in current liabilities 18,786 5,987
Deferred charges and other (827) (2,049)
---------------- -----------------
Net Cash Provided by Operating Activities 51,866 45,366
---------------- -----------------
Financing Activities:
Reductions of long-term debt (3,572) (32,985)
Obligations under long-term leases (180) (177)
---------------- -----------------
Net Cash Used in Financing Activities (3,752) (33,162)
---------------- -----------------
Investing Activities:
Lease deposits and other investments (1,811) 392
Electric plant additions (34,176) (6,488)
Decommissioning fund deposits (340) (340)
---------------- -----------------
Net Cash Used in Investing Activities (36,327) (6,436)
---------------- -----------------
Net Change in Cash and Cash Equivalents 11,787 5,768
Cash and Cash Equivalents - Beginning of Period 20,259 25,088
---------------- -----------------
Cash and Cash Equivalents - End of Period $ 32,046 $ 30,856
================ =================
- -------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of the consolidated financial
statements.
5
OLD DOMINION ELECTRIC COOPERATIVE
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. In the opinion of the management of Old Dominion Electric Cooperative (Old
Dominion), the accompanying unaudited condensed consolidated financial
statements contain all adjustments, which include only normal recurring
adjustments, necessary for a fair statement of Old Dominion's consolidated
financial position as of June 30, 2001, and its consolidated results of
operations, comprehensive income, and cash flows for the three and six months
ended June 30, 2001 and 2000. The consolidated results of operations for the
three and six months ended June 30, 2001, 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 Old Dominion's 2000 Annual Report on Form 10-K filed with the
Securities and Exchange Commission.
2. In 1997, we adopted certain strategic objectives designed to mitigate the
effects of transition to a competitive electric market, which became known as
our Strategic Plan Initiative. As part of our Strategic Plan Initiative, our
board of directors unanimously approved a resolution to record accelerated
depreciation on our generation assets from January 1, 1999 through December
31, 2003, and to recover the additional expense through rates pursuant to our
formulary rate. During the first half of 2001, we recorded additional
depreciation of $18.1 million ($$4.2 million in the second quarter) as
compared to $26.2 million in the first half of 2000 ($8.3 million in the
second quarter).
To date we have collected $160.3 million through our Strategic Plan
Initiative and have purchased $86.1 million of our outstanding debt ($3.6
million in the first half of 2001).
Based on current market projections, we believe that the $160.3 million
accumulated through the Strategic Plan Initiative since 1998 and held as cash
or investments or already applied to reduce our indebtedness is sufficient to
reduce our costs to a level which would enable the member distribution
cooperatives' rates for power to their customers to be at or below projected
market rates by January 1, 2004. As a result, we ceased recording
accelerated depreciation of our generating facilities effective June 1, 2001.
At the same time, our board of directors authorized a revenue deferral plan
for the period June 1, 2001 through December 31, 2002. Under this plan we
estimate that we will collect approximately $9.1 million through our demand
rate in 2001, which we will use to partially offset the increases in our
demand rate we expect in 2002. At June 30, 2001, we had deferred $1.3
million, which is included in other assets and depreciation, amortization and
decommissioning expense.
3. Effective January 1, 2001, Old Dominion adopted Statement of Financial
Accounting Standards No. 133, "Accounting for Derivative Instruments and
Hedging Activities" (SFAS 133), as amended by Statement of Financial
Accounting Standards No. 138 (SFAS 138), "Accounting for Certain Derivative
Instruments and Certain Hedging Activities." The adoption of these
accounting standards did not have a significant effect on Old Dominion's
financial statements.
4. In June 2001, we formed TEC Trading, Inc. (TEC) with $7.5 million of capital
and immediately distributed the stock of TEC as a patronage distribution to
our member distribution cooperatives on the same date. TEC is now owned by
our member distribution cooperatives to market energy in excess of their
needs, manage the members' exposure to changes in fuel prices and take
advantage of other energy trading opportunities, which may become available
in the market. In addition, to facilitate TEC's ability to sell
6
energy to the market, we have agreed to guarantee a maximum of $42.5 million
of TEC's delivery and payment obligations associated with its energy trades.
Our guarantee of TEC's obligations will enable it to maintain credit support
sufficient to meet its delivery and payment obligations associated with its
energy trades.
5. Certain reclassifications have been made to the accompanying prior year's
consolidated financial statements to conform to the current year's
presentation.
7
OLD DOMINION ELECTRIC COOPERATIVE
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Caution Regarding Forward Looking Statements
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.
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' customers' requirements for power and our
formulary rate for sales of power to our member distribution cooperatives. Our
formulary rate is based on our cost of service in meeting these requirements.
Our member revenues by formulary rate component, energy sales to our members and
average member cost per megawatthour for the three and six month periods ended
June 30, 2001 and 2000, were as follows:
Three Months Ended Six Months Ended
June 30, June 30,
-------------------------- ---------------------------
2001 2000 2001 2000
---------- ----------- ---------- -----------
Member Revenues (in thousands)
Demand $ 45,498 $53,513 $106,097 $119,003
Energy 37,343 36,186 81,449 77,079
Fuel factor adjustment 29,158 (607) 43,693 (2,339)
--------- --------- --------- ---------
Total Member Revenues $111,999 $89,092 $231,239 $193,743
======== ======= ======== ========
Sales (in MWh) 2,065,651 2,026,301 4,526,199 4,314,945
Average Member Cost (in MWh) $54.22 $43.97 $51.09 $44.90
Three factors significantly affect our member distribution cooperatives'
consumers' requirements for power:
o growth in the number of consumers,
o growth in consumers' requirements for power, and
o seasonal weather fluctuations.
8
Weather affects the demand for electricity. Although the exact amount of
sales attributable to weather conditions cannot be quantified, extreme
temperatures tend to increase demand for energy to run heating and air
conditioning systems. Mild weather generally reduces demand since heating and
air conditioning systems are needed less. Other factors affecting our
distribution cooperative members' customers' demand for energy include the
amount, size and usage of electronics, machinery and expansion of operations
among their commercial and industrial customers.
Changes in our member revenues attributed to growth in sales volume and
changes in our rates for demand and energy (including our base energy rate and
our fuel factor adjustment) for the three and six month periods ended June 30,
2001 as compared with the three and six month periods ended June 30, 2000, were
as follows:
Three Months Six Months
Ended June 30, Ended June 30,
2001 Compared to 2000 2001 Compared to 2000
---------------------- ----------------------
Change in member revenues (in thousands)
due to change in:
Demand sales volume $ (1,310) $ 3,004
Energy sales volume 691 3,659
-------- --------
Total sales volume (619) 6,663
-------- --------
Demand rate (6,702) (15,910)
Energy rate 30,228 46,743
------- ------
Total rates 23,526 30,833
------- ------
Total change in member revenues $22,907 $37,496
======= =======
Total member revenues for the second quarter and first six months of 2001
increased $22.9 million and $37.5 million, or 25.7% and 19.4%, respectively,
over the same periods in 2000 primarily as a result of an increase in our
average energy rate.
Our average energy rate for the three and six months ended June 30, 2001,
increased 83.3% and 59.6%, respectively, over the same periods in 2000 as a
result of increasing our fuel factor adjustment effective April 1, 2001. 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. 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. These higher energy costs relate to, among other items,
coal purchases and short-term power purchases.
The increase in our energy costs was partially offset by a 13.4% decrease
in the average demand rate for the six month period ended June 30, 2001 as
compared to 2000, which resulted from three separate reductions in the demand
rate. We reduced the demand rate by approximately 1.3% effective January 1,
2001, as a result of the elimination of the gross receipts tax, which had
applied to providers of electricity in Virginia. We reduced the demand rate
approximately 20.0% in April 2001 to recover evenly the remaining amounts then
anticipated to be collected under the Strategic Plan Initiative. Finally, in
response to new projected power prices, effective June 1, 2001, we stopped
recovering accelerated depreciation under the Strategic Plan Initiative, which
had the effect of amending our budget and automatically reducing our demand rate
by the terms of the formulary rate and the wholesale power contracts with the
member distribution cooperatives. See "Strategic Plan Initiative." At the same
time our board of directors authorized a revenue deferral plan for the period
June 1, 2001 through December 31, 2002. Under this plan, we estimate that we
will collect as deferred revenue approximately $9.1 million through the demand
rate in 2001. We will use these additional amounts to partially offset the
increase in the demand rate we expect in 2002. The net effect of these two
actions by our board of directors was a decrease in our demand rate of
approximately 5.0% effective June 1, 2001.
9
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 the Pennsylvania-New
Jersey-Maryland Interconnection LLC ("PJM") power pool. Excess generated 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 second quarter and first six months of 2001
decreased $6.3 million and $3.5 million, respectively, over the same periods in
2000 primarily as a result of lower sales of energy to PJM. During the first six
months of 2001, we purchased the majority of the energy for our member
distribution cooperatives located on the Delmarva Peninsula under an energy
contract that matched those members' need for power. During the same period in
2000 we purchased fixed amounts of power to meet our peak needs and sold the
amounts not needed by those members to PJM.
Operating Expenses
We have an 11.6% undivided ownership interest in the North Anna Nuclear
Power Station ("North Anna") and a 50% undivided ownership interest in Clover.
Generating facilities, particularly nuclear generating facilities 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 generating facilities, 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 from 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 three and six month periods ended June 30, 2001
and 2000 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,
-------------------- ----------------------------------------------------------------
2001 2000 2001 2000 2001 2000 2001 2000
------ ------ ------ ------- --------- ------ ------ -------
Unit 1 100.6% 87.5% 100.8% 79.4% 87.5% 75.2% 83.0% 83.6%
Unit 2 86.9 99.9 76.7 101.2 71.6 89.6 83.8 87.2
Combined 93.8 93.7 88.8 90.3 79.6 82.4 83.4 85.4
North Anna. As of June 30, 2001, North Anna Unit 1 had been online for 415
consecutive days. Prior to that North Anna Unit 1 had run for 522 consecutive
days before it began a scheduled refueling outage on March 12, 2000. Unit 1 was
returned to service on April 8, 2000.
North Anna Unit 2 began a scheduled refueling outage on March 11, 2001,
after 340 days of being online, and was returned to service on April 10, 2001.
Unit 2 experienced only minor unscheduled outages during the first six months of
2000.
Clover. During the first six months of 2001, Clover Unit 1 was off-line for
13 days for a scheduled maintenance outage and had been online for 276
consecutive days prior to that. The Unit was off-line 15 days during the second
quarter of 2000 for a scheduled maintenance outage and also experienced minor
unscheduled outages during the first half of 2000.
Clover Unit 2 was off-line for 15 days during the first half of 2001 for a
scheduled maintenance outage after being online for 241 consecutive days. Clover
Unit 2 experienced only minor outages during the first half of 2000.
In addition to power generated at Clover and North Anna, we purchase power
from Virginia Power, Public Service Electric & Gas Company, Conectiv Energy,
Pennsylvania Power & Light, and others. Our energy supply for the three and six
month periods ended June 30, 2001 and 2000, was as follows:
10
Three Months Ended Six Months Ended
June 30, June 30,
----------------------------------------- ------------------------------------
2001 2000 2001 2000
------------------ ------------------- ----------------- -------------------
(MWh) (MWh) (MWh) (MWh)
Clover 743,644 32.2% 793,408 37.2% 1,579,313 33.6% 1,629,077 36.0%
North Anna 429,247 18.6 425,029 19.9 823,708 17.5 819,490 18.1
--------- ---- --------- ---- --------- ---- --------- ----
1,172,891 50.8 1,218,437 57.1 2,403,021 51.1 2,448,567 54.1
--------- ---- --------- ---- --------- ---- --------- ----
Purchased Power:
Virginia Area 596,587 25.9 403,639 18.9 1,169,411 24.9 976,463 21.6
Delmarva Area 488,819 21.2 462,220 21.7 1,013,804 21.6 987,205 21.8
Other 49,511 2.1 48,052 2.3 112,110 2.4 110,652 2.5
--------- ----- ---------- ----- --------- ----- --------- ----
1,134,917 49.2 913,911 42.9 2,295,325 48.9 2,074,320 45.9
--------- ----- ---------- ----- --------- ----- --------- -----
Total Available Energy 2,307,808 100.0% 2,132,348 100.0% 4,698,346 100.0% 4,522,887 100.0%
========= ===== ========= ===== ========= ===== ========== =====
Market forces influence the structure of new power supply contracts. Within
PJM, our contracts reflect the need to have capacity (either owned generation or
purchase contracts) to meet load. For supplying energy , we purchase energy from
the market or utilize the PJM power pool when economical. In Virginia, demand
and energy requirements contracts are provided principally by Virginia Power,
American Electric Power-Virginia, and Allegheny Power System, although energy
may be displaced under the Interconnection and Operating Agreement with Virginia
Power.
Aggregate operating expenses for the second quarter and first six months
of 2001 increased $17.5 million and $36.6 million, or 20.5% and 20.7%,
respectively over the same periods in 2000, primarily as a result of an increase
in the amount of energy sold and an increase in energy costs. Our average cost
of purchased power rose 23.7% and 37.8% in the second quarter and first six
months of 2001, respectively, as compared to the same periods in 2000 mainly
because of rising energy prices. We have secured the majority of our energy
needs for 2002 and 2003 at fixed prices that are below those that we paid during
the first half of 2001. The average cost of fuel increased 26.2% and 21.3% in
the second quarter and first six months of 2001, respectively, as compared to
the second quarter and first six months of 2000 because of the higher price of
coal and a fuel inventory adjustment.
Administrative and general expenses increased in the first half of 2001 as
compared to the first half of 2000 primarily because of an increase in
engineering consulting and legal fees related to pre-construction activities for
the combustion turbine facilities. See "Liquidity and Capital Resources--
Investing Activities." Administrative and general expenses in the second quarter
of 2001 did not change significantly from the second quarter of 2000.
The increases in our operating expenses generally caused by higher energy
costs, which we recover through our base energy rate and fuel factor adjustment,
were partially offset by decreases in two cost components of our demand rate.
First, depreciation, amortization and decommissioning decreased as compared to
the first six months of 2000, primarily due to a $7.7 million decrease in the
amount of accelerated depreciation recorded on generation assets in accordance
with our Strategic Plan Initiative. See "Strategic Plan Initiative." Accelerated
depreciation for the six months ended June 30, 2001 and 2000, was $18.5 million
and $26.2 million, respectively. Second, taxes, other than income taxes,
decreased in the second quarter and first six months of 2001 as compared to the
same periods in 2000 since we are no longer subject to the Virginia gross
receipts tax as of January 1, 2001.
Non-Operating Income and Expenses
Investment Income. Investment income decreased in the second quarter and
first six months of 2001, as compared to the same periods in 2000 primarily
because of aggregate payments of $62.4 million made on combustion turbine
generators over the past year of which $22.9 million was paid in the first six
months of 2001.
Interest. Interest on long-term debt decreased in the second quarter and
first six months of 2001 because of the purchase of $33.3 million of our
outstanding debt and $28.5 million in debt principal payments in 2000.
Additionally, we purchased $3.6 million of our outstanding debt in the first
half of 2001 ($2.0 million in the second quarter).
11
Net Margin. Our net margin, which is a function of our interest expense,
decreased in the second quarter and first six months of 2001 as compared to the
same periods in 2000, because our interest expense was lower as a result of debt
principal payments and purchases of our outstanding debt in accordance with our
Strategic Plan Initiative.
Liquidity and Capital Resources
Operations. Historically, our operating cash flows have been sufficient to
meet our short and long-term capital expenditures relating to the operation of
North Anna and Clover, our debt service requirements and our ordinary business
operations. As of the six months ended June 30, 2001, our operating cash has
been sufficient to meet all of our cash requirements, including all costs
related to the development and construction of the combustion turbine
facilities.
Financing activities. Pursuant to our Strategic Plan Initiative, we
collected approximately $160.3 million to reduce our outstanding indebtedness.
See "Strategic Plan Initiative." Of this amount, we have spent $89.2 million
(including premiums and discounts) to purchase our outstanding debt. These debt
purchases resulted in principal retirements of $3.6 million during the first six
months of 2001 and $33.3 million and $49.3 million in 2000 and 1999,
respectively. We intend to use the remaining $71.1 million to purchase
additional outstanding debt from time to time in the most economical method
before 2004.
Investing activities. Our investing activities for the first six months of
2001 consisted primarily of the purchase of generators for our combustion
turbine facilities.
We are developing three combustion turbine facilities to meet the capacity
needs of our member distribution cooperatives. Each of these facilities is being
developed in a separate wholly owned subsidiary formed in 2001 and each
subsidiary has purchased our rights in the facility to be owned by it. To date,
we have financed the development and construction of the facilities through
internally generated funds by making the funds available to the subsidiaries
through loans evidenced by promissory notes.
Strategic Plan Initiative
In the late 1990's, the possibility of retail competition and projected
lower market power rates caused us to focus on reducing our costs. Specifically,
we sought to lower our costs so that our member distribution cooperatives could
set rates for power at or below market rates for power by the time competition
for retail customers began in Virginia in 2004. Our efforts to meet this
objective became known as the "Strategic Plan Initiative." Because estimates of
future market rates for power constantly change, we have monitored and
periodically evaluated our methods and progress in achieving the goal of the
Strategic Plan Initiative to identify and implement any appropriate changes. Our
actions to reduce costs pursuant to the Strategic Plan Initiative have included:
o restructuring our power purchase contracts with neighboring utilities
to reduce the term of the contracts or reduce the price of the capacity
or energy purchased under the contract,
o accelerating amortization of regulatory assets relating to North Anna and
other items,
o accelerating depreciation of our generating facilities, and
o reducing our indebtedness by purchasing our outstanding bonds.
During the first half of 2001, we recorded additional depreciation of $18.1
million as compared to $26.2 million in the first half of 2000. To date we have
collected $160.3 million and purchased $86.1 million of our outstanding debt,
including $3.6 million in the first half of 2001.
Our projections of the future market price of power are a key factor in
determining our progress in meeting the Strategic Plan Initiative's objective.
Beginning in 1999, our projections of market prices for power began to rise
significantly. Based on current market projections, we
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believe that the $160.3 million accumulated through the Strategic Plan
Initiative since 1998 and held as cash or investments or already applied to
reduce our indebtedness is sufficient to reduce our costs to a level which would
enable the member distribution cooperatives' rates for power to their customers
to be at or below projected market rates by January 1, 2004. As a result, we
have ceased recording accelerated depreciation of our generating facilities
effective June 1, 2001.
Based on our projections and today's market price for power, we currently
do not anticipate the need to collect any additional funds under the Strategic
Plan Initiative. Market prices for power can change significantly, however, due
to several factors that we cannot control or predict. These include, among
others, the price of fuel (such as natural gas), the implementation of
restructuring legislation, the amount of new generating facilities constructed
by competitors and the availability of transmission capacity into the service
territories of our member distribution cooperatives. For these reasons, we
cannot predict whether the member distribution cooperatives' rates for power to
their customers will be at or below market rates by January 1, 2004. We will
continue to evaluate the various factors that impact our costs and the projected
market price of power in 2004 and take additional action as appropriate to meet
the objective of the Strategic Plan Initiative.
Competition and Changing Regulations
Virginia, Maryland and Delaware have enacted legislation that restructures
the electric utility industry and changes the manner in which electricity may be
sold to customers. The individual restructuring plans adopted by Virginia,
Maryland and Delaware contain similar components.
The restructuring laws of Virginia, Maryland and Delaware generally
deregulate the power component of electric service, permitting all retail
customers to purchase power from the supplier of their choice. Transmission and
distribution of power will remain regulated services. The Virginia restructuring
legislation provides for retail choice for power services to be phased in
between January 1, 2002 and January 1, 2004 in accordance with a schedule
developed by the Virginia State Corporation Commission. Our member distribution
cooperatives providing electric services in Delaware and Maryland offered their
customers a right to choose their power suppliers on April 1, 2001 and July 1,
2001, respectively.
The restructuring laws of Virginia, Maryland and Delaware each designate
our member distribution cooperatives, at least initially, to be the default
provider of power for all customers located in their certificated service
territory who are not able or do not affirmatively select an alternative power
supplier. Generally, the new legislation also provides that the incumbent
electric utility still has the exclusive right to provide distribution services
in its certificated territory. Member distribution cooperatives in Virginia,
Maryland and Delaware also may exclusively provide metering and most billing
services to all customers located in their certificated service territories.
The new legislation in all three states requires our member distribution
cooperatives to cap the bundled rates that it can charge customers in its
certificated service territory during a specified transition period. These
capped rates are then unbundled, or itemized, into power, transmission and
distribution components and, in some cases, a competitive transition charge to
recover costs which would have been recovered under the cost of service rates
but which are unlikely to be recovered under competitive markets rates.
Other Matters
In June 2001, we formed TEC Trading, Inc. ("TEC") with $7.5 million of
capital and immediately distributed the stock of TEC as a patronage distribution
to our member distribution cooperatives on the same date. TEC is now owned by
our member distribution cooperatives to market energy in excess of their needs,
manage the members' exposure to changes in fuel prices and take advantage of
other energy trading opportunities, which may become available in the market. In
addition, to facilitate TEC's ability to sell our excess energy to the market,
we have agreed to guarantee a maximum of $42.5 million of TEC's delivery and
payment obligations associated with its energy trades. Our guarantee of TEC's
obligations will enable it to maintain credit support sufficient to meet its
delivery and payment obligations associated with its energy trades.
Effective June 1, 2001, the board of directors authorized a revenue
deferral plan for the period June 1, 2001 through December 31, 2002. Under this
plan, we estimate that we will collect approximately $9.1 million through our
demand rate, which we will use to reduce the increases in the demand rate we
expect in 2002. At June 30, 2001, we had deferred $1.3 million, which is
included in other assets and depreciation expense.
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supplier of their choice. In other words, the incumbent electric utility no
longer has the exclusive right to provide generated electricity to retail
customers located in its certificated service territory. Each of these states
has implemented a schedule by which each incumbent electric utility will provide
its customers with the opportunity to purchase electricity from licensed
generation suppliers. Transmission and distribution of electricity will remain
regulated services, with transmission principally regulated by the Federal
Energy Regulatory Commission.
Capped Rates and Stranded Costs. One consequence of the transition to
competition is that electric utilities may incur stranded costs. Stranded costs
are generally described as the difference between what an electric utility would
have recovered under a regulated cost of recovery and what that electric utility
will recover under a competitive market.
To address stranded costs and to facilitate the change to retail competition,
the new legislation in all three states requires the incumbent utility to "cap"
the rates that it can charge the customers in its certificated service territory
during a specified transition period These "capped rates" are then unbundled,
or separated, into generation, transmission and distribution components and the
incumbent electric utility may collect a competitive transition charge (commonly
referred to as a "wires charge") from those customers that choose an alternative
power supplier during the specified transition period. Basically, the wires
charge is the difference between the incumbent electric utilities' unbundled
generation component and the projected market price for electricity, as
determined by the respective state public service commission.
Distribution and Default Service Provider. Generally, the new legislation
also provides that the incumbent electric utility still has the exclusive right
to provide distribution services in its certificated territory. Moreover, a
customer who is either unable or has not selected an alternative power supplier
will receive generation service from its "default" provider. The restructuring
laws of Virginia, Maryland and Delaware each designate the member distribution
cooperatives, at least initially, to be the default provider of electricity for
all customers located in their certificated service territory who do not
affirmatively select a competitive electric supplier. Cooperatives in Virginia,
Maryland and Delaware may exclusively provide metering and most billing services
to all customers located in their certificated service territory.
All of the customers of our Delaware and Maryland member distribution
cooperatives are now free to choose an alternative electric supplier. Demand
sales to these customers account for approximately 21% of our demand sales to
our member distribution cooperatives. By January 1, 2004, approximately 99.7%
of our member distribution cooperatives' customers will be free to choose an
alternative generation supplier. No timetable currently exists for permitting
consumers to select their provider of power in West Virginia. Demand sales to
these West Virginia customers account for approximately 0.3 % of our demand
sales to our member distribution cooperatives.
Virginia
Retail Choice for Electric Service. The Virginia restructuring legislation
provides for retail choice for electric services to be phased in between January
1, 2002 and January 1, 2004 in accordance with a schedule developed by the
Virginia State Corporation Commission ("VSCC"). The member distribution
cooperatives in Virginia may each set their own schedule for the phase-in of
competition between January 1, 2002 and January 1, 2004. Our Virginia member
distribution cooperatives are in the process of preparing their schedules for
the phase-in of retail competition.
Capped Rates and Stranded Costs. The Virginia restructuring legislation caps
rates for electric service from January 1, 2001 to July 1, 2007. The rates of
our Virginia member distribution cooperatives are capped at the levels that were
in effect on July 1, 1999 (unless the utility petitions the VSCC for an increase
in rates prior to January 1, 2001). Utilities may, however, adjust the capped
rates to recover their fuel costs. Our recent increases in energy rates will be
recovered by our Virginia member distribution cooperatives as increased fuel
cost. Additionally, an incumbent utility may seek an increase in its capped
rates prior to 2004 if it is in financial distress beyond its control.
Between January 1, 2001 and January 1, 2007, our member distribution
cooperatives may collect stranded costs through a wires charge that will be
applied to all customers that choose an alternative power supplier. To establish
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the wires charge, the VSCC currently is conducting regulatory proceedings to (i)
determine the unbundled rate component of generation, transmission and
distribution for each of our Virginia member distribution cooperatives, and (ii)
determine the projected market price for generation. Once the projected market
price for generation is determined, it will be subtracted from the generation
component of the capped rate to determine the applicable wires charge. Our
Virginia member distribution cooperatives are then permitted to collect the
wires charge from their customers that choose an alternative generation supplier
during the capped rate period.
Distribution and Default Service Provider. Under the restructuring
legislation, in addition to remaining the exclusive provider of distribution
services in its certificated service territory, each of our Virginia member
distribution cooperatives will be the default provider of electric services
unless (1) it seeks to become the default service provider in the certificated
service territory of another utility or (2) if after July 1, 2004 the VSCC
determines that a sufficient degree of competition exists in the service
territory and elimination of default service is not contrary to the public
interest. The legislation provides that our member distribution cooperatives'
rates for default service will be the same as the capped rates described above
for the period from January 1, 2002 to July 1, 2007. After July 1, 2007, the
default rates will be based on the member distribution cooperatives' prudently
incurred costs (which will include the amounts paid to us under our wholesale
power contract). Our Virginia member distribution cooperatives also will be the
exclusive provider of metering and most billing services to all customers
located in their certificated service territory.
Maryland
Retail Choice for Electric Service. The Maryland restructuring legislation
requires a three-year phase-in of retail competition beginning with investor-
owned utilities on July 1, 2001. The phase-in is to be completed by July 1,
2003, at which time all customers will be able to choose their generation
supplier.
Our member distribution cooperative in Maryland was required to present to the
Maryland Public Service Commission ("MPSC") a plan where all cooperative
customers would have a choice in their selection of a power supplier by July 1,
2003. Pursuant to a settlement with the MPSC, our sole Maryland member,
Choptank Electric Cooperative ("Choptank"), representing ________% of the energy
we sold to our member distribution cooperatives in 2000, volunteered to offer
choice to all of its customers on July 1, 2001, rather than seek a phase-in of
customer choice. In order for a competitive supplier to provide generation
service to Choptank's customers, the supplier must be qualified by the MPSC and
registered with Choptank. As of July 1, 2001, approximately 30 entities have
obtained permission from the MPSC to provide power in Maryland, but currently,
no alternative generation supplier has registered to serve the customers of
Choptank.
Capped Rates and Stranded Costs. Pursuant to its settlement with the MPSC,
Choptank's rates are capped for a period of four years beginning on July 1, 2001
and ending June 31, 2005. Choptank's capped rates were developed using a
forecast of its cost (including our forecasted rates) for the capped rate
period. The settlement for capped rates provides for minimal rate reductions
for most residential classes, which matched our forecasted rates based on a 1998
study.
Under the settlement, Choptank's capped rates were unbundled into components
for generation, transmission, distribution and competitive transition charges.
The generation component of Choptank's capped rate was determined using our
forecasts based on a 1998 study. The MPSC settlement recognized our efforts to
mitigate stranded costs under the Strategic Plan Initiative. As part of the
settlement, the MPSC approved the collection of a competitive transition or
wires charge based on an amount equal to Choptank's share of our above market
costs as determined under the Strategic Plan Initiative (and other transition
costs). The wires charges cannot be collected during the capped rate period,
unless we have successfully completed the Strategic Plan Initiative prior to
that period.
Beginning in 1999, market prices for power rose significantly from the
projections made in our 1998 study, causing an increase in our forecasted fuel
costs. As a result, the generation component of Choptank's capped rate is less
than the rates that we are currently charging Choptank and our other member
distribution cooperatives. The settlement with the MPSC does not allow Choptank
to automatically recover these increased fuel costs. The settlement does allow
Choptank to petition the MPSC to change the capped rates in the event there are
"extraordinary circumstances" or Choptank is under "financial distress."
Choptank is having discussions with the MPSC regarding its ability to recover
these additional costs.
15
Choptank's capped rate does not impact our ability to pass through our costs
to Choptank. If Choptank's costs are greater than the rate capped by the MPSC,
Choptank must absorb any deficiency. On the other hand, if Choptank's costs are
less than the rate capped by the MPSC, Choptank is allowed to retain the
surplus. We believe that Choptank will be able to make its payments to us
through the combination of revenues derived from the capped rate, reductions in
its other costs and its equity.
Distribution and Default Service Provider. Under the settlement with the
MPSC, in addition to remaining the exclusive provider of distribution services
in its certificated service territory, Choptank will be the default provider of
generation services in the territory. During the capped rate period Choptank
will provide default services at the capped rate. Afterwards, Choptank will
provide default services for generation at a rate no greater than our annualized
rates (including transmission charges). Choptank also will be the exclusive
provider of metering and most billing services to all customers located in their
certificated service territory.
Delaware
Retail Choice for Electric Service. The Delaware restructuring legislation
required a phase-in of retail competition beginning April 1, 2000, and ending
April 1, 2001, for customers of Delaware Electric Cooperative ("DEC"), our
Delaware member. The customers of DEC that were given the option to select
their power supplier during 2000 accounted for less than 1.0% of our total load
sales. As of April 1, 2001, all customers of DEC, representing approximately
11.5% of the energy that we sell to our member distribution cooperatives, have
the option of choosing their power supplier. To date, none of these customers
has changed to an alternative power supplier.
Capped Rates and Stranded Costs. Pursuant to the Delaware restructuring
legislation, rates for DEC's customers are capped at the rates in effect on
April 1, 2000 (subject to a one-time fuel adjustment). Because market prices for
power rose significantly beginning in 1999, our forecasted fuel costs have
increased significantly from the projections made in our 1998 study. As a
result, the generation component of DEC's capped rate is less than the rates
that we are currently charging our member distribution cooperatives. The
Delaware restructuring legislation does not allow DEC to automatically recover
increased fuel costs. The Delaware Public Service Commission ("DPSC") may
change the capped rates in connection with any extraordinary costs that the DPSC
approves.
DEC's capped rate does not impact our ability to pass through our rates to
DEC. If DEC's costs are greater than the rate capped by the DPSC, DEC must
absorb any deficiency. On the other hand, if DEC's costs are less than the rate
capped by the DPSC, DEC is allowed to retain the surplus. We believe that DEC
will be able to make its payments to us through the combination of revenues
derived from the capped rate, reductions in its other costs and its equity.
The restructuring legislation required the DPSC to approve a restructuring and
rate unbundling plan, including any proposed collection of stranded costs. DEC
filed this plan in September 1999. On April 25, 2000, the DPSC issued its final
order which determined that DEC did not have stranded costs and that DEC is not
permitted to collect a wires charge with respect to electricity costs from those
customers that choose an alternative electric supplier during the specified
transition period.
Default and Distribution Service Provider. Under the new law, in addition to
remaining the exclusive provider of distribution services in its certificated
service territory, DEC will remain the default electric provider to its current
customers through March 31, 2005. After that date, DEC may continue as a
default service provider unless the DPSC determines that DEC is unable to
provide default service or its current service is not adequate to meet the
requirements of the public necessity and convenience. DEC also will be the
exclusive provider metering and most billing services to all customers located
in their certificated service territory.
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West Virginia.
On March 11, 2000, the West Virginia legislature adopted a restructuring plan
that implements customer choice on January 1, 2001, or a later date established
by the state regulatory commission. Passage of a second resolution during the
2001 legislative session was necessary for the deregulation plan to proceed.
During the 2001 legislative session, however, lawmakers did not pass the
resolution necessary for the introduction of retail competition. As a result,
the legislation did not become effective. Currently, there is not legislation
pending before the West Virginia legislature establishing retail choice in the
selection of a power supplier.
Other Matters
In March 2001, we purchased a one-sixth interest in ACES Power Marketing LLC
("APM"), an energy trading and risk management company, for $750,000. As part
of our investment, we extended a loan to APM in the amount of $500,000.
Repayment of the loan is due on or prior to February 15, 2002. In addition, APM
has the right to require us to contribute an additional $750,000 to APM as part
of a required capital contribution of all investors. APM will act as agent to
provide wholesale power trading, settlement, modeling, and risk control
execution services related to our power supply portfolio.
In June 2001, we formed TEC Trading, Inc. (TEC) with $7.5 million of capital
and immediately distributed the stock of TEC as a patronage distribution to our
member distribution cooperatives on the same date. TEC is now owned by our
member distribution cooperatives to market energy in excess of their needs,
manage the members' exposure to changes in fuel prices and take advantage of
other energy trading opportunities, which may become available in the market.
In addition, to facilitate TEC's ability to sell our excess energy to the
market, we have agreed to guarantee a maximum of $42.5 million of TEC's delivery
and payment obligations associated with its energy trades. Our guarantee of
TEC's obligations will enable it to maintain credit support sufficient to meet
its delivery and payment obligations associated with its energy trades.
Effective June 1, 2001, the board of directors authorized a revenue deferral
plan for the period June 1, 2001 through December 31, 2002. Under this plan, we
estimate that we will collect approximately $9.1 million through our demand
rate, which we will use to reduce the increases in the demand rate we expect in
2002. At June 30, 2001, we had deferred $1.3 million, which is included in
other assets and depreciation expense.
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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, 2001.
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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 10, 2001 /s/ Daniel M. Walker
-----------------------------------------------
Daniel M. Walker
Senior Vice President of Accounting and Finance
(Chief Financial Officer)
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