Entergy 2002 Annual Report Download - page 72

Entergy’s Non-Utility Nuclear business. The liability associated
with the trust funds received from Cajun with the transfer of
Cajun’s 30% share of River Bend is also recorded as a deferred
credit by Entergy Gulf States. The actual decommissioning
costs may vary from the estimates because of regulatory
requirements, changes in technology, and increased costs of
labor, materials, and equipment.
Entergy periodically reviews and updates estimated decom-
missioning costs. Entergy is presently under-recovering
decommissioning costs for ANO 1, Arkansas Nuclear One Unit
2 (ANO 2), Grand Gulf 1, Waterford 3, and the Louisiana-
regulated share of River Bend. Under-recovery for Grand Gulf 1
and Waterford 3 is based on the existence of more recent
estimates reflecting higher costs. Under-recovery of ANO 1,
ANO 2, and River Bend is based on suspension of decommis-
sioning collections under the assumption that the lives of those
plants have been or will be extended.
In June 2001, Entergy Arkansas received notification from the
NRC of approval for a renewed operating license authorizing
operations at ANO 1 through May 2034. In October 2000, the
APSC ordered Entergy Arkansas to reflect 20-year license
extensions in its determination of the ANO 1 and ANO 2
decommissioning revenue requirements for rates to be effective
January 1, 2001. Entergy Arkansas will not make additional
contributions to the trust funds in 2003 for ANO 1 and ANO 2
based on the extension of the ANO 1 license, the assumption
that the ANO 2 license will be extended, and that the existing
decommissioning trust funds, together with their expected
future earnings, will meet the estimated decommissioning costs.
An updated decommissioning cost study for ANO 1 and 2 will
be filed with the APSC in March 2003.
In December 2002, Entergy Gulf States and the LPSC
reached a settlement of the fourth through eighth post-merger
earnings reviews. Among other things, the settlement includes
suspension of collections for decommissioning the Louisiana-
regulated portion of River Bend beginning January 1, 2003
based upon an assumption that the operating license and the
useful life of River Bend will be extended. According to the
settlement agreement, in the event that the NRC formally
notifies Entergy that the decommissioning funding for River
Bend is or would become inadequate, Entergy Gulf States would
be permitted recognition in rates of decommissioning expense
at a level sufficient to address reasonably the NRC’s concern as
expressed in the notification. The decommissioning liability
for the 30% share of River Bend formerly owned by Cajun
was fully funded by a transfer of $132 million to the River
Bend Decommissioning Trust at the completion of Cajun’s
bankruptcy proceedings.
Entergy Louisiana prepared a decommissioning cost
update for Waterford 3 in 1999 and produced a revised
decommissioning cost update of $481.5 million. This cost
update was filed with the LPSC in the third quarter of 2000.
System Energy included updated decommissioning costs
(based on the updated 1994 study) in its 1995 rate increase
filing with FERC. Rates requested in this proceeding were
placed into effect in December 1995, subject to refund. In
July 2000, FERC issued an order approving a lower decommis-
sioning cost than what was requested by System Energy in the
1995 filing. System Energy adjusted its collection to the FERC-
approved level of $341 million in the third quarter of 2001. A
1999 decommissioning cost update of $540.8 million for
System Energy’s 90% share of Grand Gulf 1 has not yet been
filed with FERC.
As part of the Pilgrim, Indian Point 1 and 2, and Vermont
Yankee purchases, the previous owners transferred decommis-
sioning trust funds, along with the liability to decommission the
plants, to Entergy. Entergy believes that the decommissioning
trust funds will be adequate to cover future decommis-
sioning costs for these plants without any additional deposits to
the trusts.
For the Indian Point 3 and FitzPatrick plants purchased in
2000, NYPA retained the decommissioning trusts and the
decommissioning liability. NYPA and Entergy executed decom-
missioning agreements, which specify their decommissioning
obligations. NYPA has the right to require Entergy to assume
the decommissioning liability provided that it assigns the
corresponding decommissioning trust, up to a specified level,
to Entergy. If the decommissioning liability is retained by
NYPA, Entergy will perform the decommissioning of the plants
at a price equal to the lesser of a pre-specified level or the
amount in the decommissioning trusts. Entergy believes that
the amounts available to it under either scenario are sufficient
to cover the future decommissioning costs without any addi-
tional contributions to the trusts.
The provisions of SFAS 143 will also be applicable to the
non-regulated nuclear units beginning in 2003. Refer to Note 1
to the consolidated financial statements for a discussion of the
effect of SFAS 143 on Entergy.
The cumulative liabilities and decommissioning expenses
recorded in 2002 by Entergy were as follows (in millions):
Liabilities 2002 2002 Liabilities
as of Trust Decommissioning as of
Dec. 31, 2001 Earnings Expenses(a) Dec. 31, 2002
ANO 1 & ANO 2 $ 292.8 $17.9 $ – $ 310.7
River Bend 226.8 6.2 4.0 237.0
Waterford 3 111.5 3.4 10.4 125.3
Grand Gulf 1 134.3 4.4 16.1 154.8
Pilgrim 474.1 –(b) 16.1 490.2
Indian Point 1 & 2 435.3 –(b) 21.6 456.9
Vermont Yankee 310.7(c) –(b) 6.0 316.7
Total $1,985.5 $31.9 $74.2 $2,091.6
(a) Includes decommissioning expenses and interest from accretion of the obligations.
(b) Trust earnings on the decommissioning trust funds for Pilgrim, Indian Point
1 & 2, and Vermont Yankee are recorded as income and do not increase the
decommissioning liability.
(c) Added in third quarter of 2002, when the unit was acquired.
In 2000, ANO’s decommissioning expense was $3.8 million.
River Bend’s decommissioning expense was $6.2 million in
both 2001 and 2000, and Waterford 3’s decommissioning
expense was $10.4 million for both years. Grand Gulf 1’s
2001 decommissioning expense, which included the effect
of the FERC-ordered refund, was ($23.8 million); its 2000
70
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS continued