PG&E 2007 Annual Report Download - page 116

114
Derivative instruments may be designated as cash fl ow
hedges when they hedge variable price risk associated with
the purchase of commodities. Cash fl ow hedges are presented
on a net basis by counterparty.
The table below represents the portion of the derivative
balances that were designated as cash fl ow hedges:
Cash Flow Hedges
December 31, December 31,
(in millions) 2007 2006
Current Assets — Prepaid expenses
and other(1) $ (2) $ 3
Other Noncurrent Assets — Other 33 8
Current Liabilities — Other 19 25
Noncurrent Liabilities — Other 3 —
(1) $2 million of the cash fl ow hedges in a liability position at December 31,
2007 relate to counterparties for which the total net derivatives position
is a current asset.
The Utility also has derivative instruments for the
physical delivery of commodities transacted in the normal
course of business as well as non-fi nancial assets that are
not exchange-traded. These derivative instruments are eligible
for the normal purchase and sales and non-exchange traded
contract exceptions under SFAS No. 133, and are not refl ected
on the Consolidated Balance Sheets. They are recorded and
recognized in income using accrual accounting. Therefore,
expenses are recognized in cost of electricity and cost of
natural gas as incurred.
Net realized gains or losses on derivative instruments
are included in various items on PG&E Corporation’s and
the Utility’s Consolidated Statements of Income, including
cost of electricity and cost of natural gas. Cash infl ows and
outfl ows associated with the settlement of price risk man-
agement activities are recognized in operating cash fl ows
on PG&E Corporation’s and the Utility’s Consolidated
Statements of Cash Flows.
The dividend participation rights associated with PG&E
Corporation’s Convertible Subordinated Notes are recorded
at fair value in PG&E Corporation’s Consolidated Financial
Statements in accordance with SFAS No. 133. (See Note 4
above for discussion of the Convertible Subordinated Notes.)
NOTE 13: NUCLEAR
DECOMMISSIONING
The Utility’s nuclear power facilities consist of two units
at Diablo Canyon (“Diablo Canyon Unit 1” and “Diablo
Canyon Unit 2”) and the retired facility at Humboldt Bay
(“Humboldt Bay Unit 3”). Nuclear decommissioning requires
the safe removal of nuclear facilities from service and the
reduction of residual radioactivity to a level that permits
termination of the Nuclear Regulatory Commission (“NRC”)
license and release of the property for unrestricted use. The
Utility makes contributions to trust funds (described below)
to provide for the eventual decommissioning of each nuclear
unit. In the Utility’s 2005 Nuclear Decommissioning Cost
Triennial Proceeding (“NDCTP”), used to determine the level
of Utility trust contributions and related revenue require-
ment, the CPUC assumed that the eventual decommission-
ing of Diablo Canyon Unit 1 would be scheduled to begin
in 2024 and be completed in 2044; that decommissioning of
Diablo Canyon Unit 2 would be scheduled to begin in 2025
and be completed in 2041; and that decommissioning of
Humboldt Bay Unit 3 would be scheduled to begin in 2009
and be completed in 2015.
As presented in the Utility’s NDCTP, the estimated nuclear
decommissioning cost for Diablo Canyon Units 1 and 2 and
Humboldt Bay Unit 3 is approximately $2.19 billion in 2007
dollars (or approximately $5.42 billion in future dollars).
These estimates are based on the 2005 decommissioning cost
studies, prepared in accordance with CPUC requirements.
The Utility’s revenue requirements for nuclear decommis-
sioning costs (i.e., the revenue requirements used by the
Utility to make contributions to the decommissioning trust
funds) are recovered from customers through a non-bypassable
charge that the Utility expects will continue until those
costs are fully recovered. The decommissioning cost estimates
are based on the plant location and cost characteristics for
the Utility’s nuclear power plants. Actual decommissioning
costs may vary from these estimates as a result of changes
in assumptions such as decommissioning dates, regulatory
requirements, technology, and costs of labor, materials
and equipment.
The estimated nuclear decommissioning cost described
above is used for regulatory purposes. However, under
GAAP requirements, the decommissioning cost estimate
is calculated using a different method in accordance with
SFAS No. 143. Under GAAP, the Utility adjusts its nuclear
decommissioning obligation to refl ect the fair value
of decommissioning its nuclear power facilities and records
this as an asset retirement obligation on its Consolidated