PG&E 2010 Annual Report Download - page 34

$105 million decrease driven by lower depreciation rates
and a $110 million decrease related to lower capital
expenditures and other rate base adjustments. About $49
million of the $110 million reduction is related to the
treatment of nuclear fuel and fuel oil inventory balances.
Under the settlement agreement, the Utility agreed to
continue recovering carrying costs on these balances at
short-term interest rates (estimated to be $1 million per
year based on current rates) through the energy resource
recovery balancing account (“ERRA”), in accordance with
the current regulatory treatment of these costs, rather
than as part of the authorized GRC rate base. Another
$20 million of the reduction relates to costs to implement
the California Independent System Operator’s Market
Redesign and Technology Update (“MRTU”). Consistent
with the settlement agreement, the Utility plans to seek
recovery of MRTU-related costs through the ERRA or
other proceedings.
In summary, the settlement agreement proposes revenue
requirements of $3.2 billion for electric distribution (as
compared to $3.5 billion included in the GRC
application), $1.1 billion for natural gas distribution (as
compared to $1.3 billion included in the GRC
application), and $1.7 billion for electric generation
operations (as compared to $1.8 billion included in the
GRC application).
AttritionYearRevenues
The settlement agreement proposes an attrition increase of
$180 million to the authorized 2011 revenues in 2012 and
an additional increase of $185 million in 2013. On a
comparable basis, the Utility had requested an attrition
mechanism estimated to provide increases of
approximately $262 million in 2012 and approximately
$334 million in 2013.
Balancing Accounts
The settlement agreement proposes to establish a new
“one-way” balancing account for the Utility to recover up
to approximately $20 million per year for costs associated
with the Utility’s natural gas distribution integrity
management program. If these costs are not spent during
the GRC period, the unspent funds must be refunded to
customers. However, customers would not be required to
pay for costs in excess of the annual $20 million cost cap.
The proposed decision also would allow the Utility to
remove $113 million in forecast meter reading costs from
the requested GRC revenue requirements. Instead, the
Utility would record actual meter reading costs up to an
annual cap of $76 million in a new “one-way” meter
reading balancing account. With the exception of this
proposed new “one-way” balancing account and the
proposed meter reading balancing account discussed above,
the settlement agreement proposes to retain the existing
balancing account structure without any substantial
changes.
Capital Additionsand Rate Base
The settlement agreement is consistent with capital
expenditures for 2011 through 2013 averaging $2.2 billion
to $2.3 billion per year for the portions of the Utility’s
business addressed in the GRC. Proposed capital
expenditures are lower than the amount included in the
Utility’s GRC application, which averaged $2.7 billion per
year, based on a lower forecast for new customer
connections and lower capital expenditures for
hydroelectric generation facilities, information technology
systems, and fleet replacement. The ultimate amounts of
capital expenditures will depend on a number of factors,
including the level of operations and maintenance,
administrative and general, and other costs.
The settlement agreement proposes a 2011 annual
average rate base of $16.6 billion for the portions of the
Utility’s business reviewed in the GRC compared with the
Utility’s request of $17.2 billion. The $0.6 billion
difference is based on the capital expenditure reductions
described above, the removal of MRTU-related capital
expenditures, the continued funding of nuclear fuel and
fuel oil inventory through the ERRA proceeding rather
than through rate base, and the adjustment of deferred
taxes to reflect the Utility’s updated estimate of the impact
of 2009 bonus depreciation.
Electric TransmissionOwnerRate Cases
On July 28, 2010, the Utility filed an application with the
FERC requesting an annual retail transmission revenue
requirement of $1.0 billion. The proposed rates represent
an increase of $150 million over current authorized
revenue requirements. On September 30, 2010, the FERC
accepted the Utility’s filing and permitted the proposed
rates to become effective on March 1, 2011, subject to
refund based on a final decision to be issued by the FERC.
Hearings in the case have been halted while the Utility and
other parties engage in settlement negotiations. Any
settlement agreement that the parties may reach will be
subject to the FERC’s approval. If a settlement is not
reached, the FERC will hold hearings and issue a decision
after the conclusion of hearings. The Utility will begin
collecting the proposed rates on March 1, 2011, and record
a reserve for the amount the Utility estimates will be
subject to refund.
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