PG&E 2007 Annual Report Download - page 103

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NOTE 3: REGULATORY
ASSETS, LIABILITIES, AND
BALANCING ACCOUNTS
REGULATORY ASSETS
As discussed in Note 2, PG&E Corporation and the Utility
account for the fi nancial effects of regulation in accordance
with SFAS No. 71. Long-term regulatory assets are comprised
of the following:
Balance at December 31,
(in millions) 2007 2006
Energy recovery bond regulatory asset $1,833 $2,170
Utility retained generation regulatory assets 947 1,018
Regulatory assets for deferred income tax 732 599
Environmental compliance costs 328 303
Unamortized loss, net of gain,
on reacquired debt 269 295
Regulatory assets associated with plan
of reorganization 122 147
Contract termination costs 96 120
Scheduling coordinator costs 90 111
Other 42 139
Total regulatory assets $4,459 $4,902
The energy recovery bond (“ERB”) regulatory asset repre-
sents the refi nancing of the settlement regulatory asset estab-
lished under the December 19, 2003 settlement agreement
among PG&E Corporation, the Utility, and the CPUC to
resolve the Utility’s proceeding under Chapter 11 of the U.S.
Bankruptcy Code (the “Chapter 11 Settlement Agreement”).
During 2007, the Utility recorded amortization of the ERB
regulatory asset of approximately $337 million. The Utility
expects to fully recover this asset by the end of 2012.
As a result of the Chapter 11 Settlement Agreement, the
Utility recognized a one-time non-cash gain of $1.2 billion
in 2004 for regulatory assets related to the recovery of
previously incurred costs associated with retained generation
facilities. The individual components of these regulatory
assets are amortized over their respective lives, with a weighted
average life of approximately 16 years. During 2007, the
Utility recorded amortization of the Utility’s retained
generation regulatory assets of approximately $71 million.
The regulatory assets for deferred income tax represent
deferred income tax benefi ts passed through to customers
and are offset by deferred income tax liabilities. Tax ben-
efi ts to customers have been passed through as the CPUC
requires utilities under its jurisdiction to follow the “fl ow
through” method of passing certain tax benefi ts to custom-
ers. The “fl ow through” method ignores the effect of deferred
taxes on rates. Based on current regulatory ratemaking and
income tax laws, the Utility expects to recover deferred
income taxes related to regulatory assets over periods ranging
from 1 to 40 years.
Environmental compliance costs represent the portion
of estimated environmental remediation liabilities that the
Utility expects to recover in future rates as actual remedia-
tion costs are incurred. The Utility expects to recover these
costs over periods ranging from 1 to 30 years.
Unamortized loss, net of gain, on reacquired debt repre-
sents costs related to debt reacquired or redeemed prior to
maturity with associated discount and debt issuance costs.
These costs are expected to be recovered over the remaining
original amortization period of the reacquired debt over
periods ranging from 1 to 19 years.
Regulatory assets associated with the Utility’s Chapter 11
Settlement Agreement include costs incurred in fi nancing the
Utility’s reorganization under Chapter 11 and costs to over-
see the environmental enhancement projects of the Pacifi c
Forest and Watershed Stewardship Council, an entity that
was established pursuant to the Utility’s plan of reorganiza-
tion. The Utility expects to recover these costs over periods
ranging from 5 to 30 years.
Contract termination costs represent amounts that the
Utility incurred in terminating a 30-year power purchase
agreement. This regulatory asset will be amortized and
collected in rates on a straight-line basis until the end of
September 2014, the power purchase agreement’s original
termination date.
The regulatory asset related to scheduling coordinator
(“SC”) costs represents costs that the Utility incurred begin-
ning in 1998 in its capacity as an SC for its then existing
wholesale transmission customers. The Utility expects to
fully recover the SC costs by 2009.
Finally, as of December 31, 2007, “Other” is primarily
related to timing differences between the recognition of
ARO in accordance with GAAP and the amounts recognized
for ratemaking purposes. At December 31, 2006, “Other” is
primarily related to price risk management contracts entered
into by the Utility to procure electricity and natural gas to
reduce commodity price risks, which are accounted for as
derivatives under SFAS No. 133. The costs and proceeds of
these derivative instruments are recovered or refunded in
regulated rates charged to customers.