|
|
|
2006
|
|
2005
|
|
2004(1)
|
|
2003
|
|
2002
|
|
|||||
|
(in
millions, except per share amounts)
|
|
|
|
|||||||||||||
|
PG&E
Corporation(2)
For
the Year
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Operating
revenues
|
|
$
|
12,539
|
|
$
|
11,703
|
|
$
|
11,080
|
|
$
|
10,435
|
|
$
|
10,505
|
|
|
Operating
income
|
|
|
2,108
|
|
|
1,970
|
|
|
7,118
|
|
|
2,343
|
|
|
3,954
|
|
|
Income
from continuing operations
|
|
|
991
|
|
|
904
|
|
|
3,820
|
|
|
791
|
|
|
1,723
|
|
|
Earnings
per common share from continuing operations, basic
|
|
|
2.78
|
|
|
2.37
|
|
|
9.16
|
|
|
1.96
|
|
|
4.53
|
|
|
Earnings
per common share from continuing operations, diluted
|
|
|
2.76
|
|
|
2.34
|
|
|
8.97
|
|
|
1.92
|
|
|
4.49
|
|
|
Dividends
declared per common share (3)
|
|
|
1.32
|
|
|
1.23
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
At
Year-End
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Book
value per common share(4)
|
|
$
|
21.24
|
|
$
|
19.94
|
|
$
|
20.90
|
|
$
|
10.16
|
|
$
|
8.92
|
|
|
Common
stock price per share
|
|
|
47.33
|
|
|
37.12
|
|
|
33.28
|
|
|
27.77
|
|
|
13.90
|
|
|
Total
assets
|
|
|
34,803
|
|
|
34,074
|
|
|
34,540
|
|
|
30,175
|
|
|
36,081
|
|
|
Long-term
debt (excluding current portion)
|
|
|
6,697
|
|
|
6,976
|
|
|
7,323
|
|
|
3,314
|
|
|
3,715
|
|
|
Rate
reduction bonds (excluding current portion)
|
|
|
-
|
|
|
290
|
|
|
580
|
|
|
870
|
|
|
1,160
|
|
|
Energy
recovery bonds (excluding current portion)
|
|
|
1,936
|
|
|
2,276
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
Financial
debt subject to compromise
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
5,603
|
|
|
5,605
|
|
|
Preferred
stock of subsidiary with mandatory redemption provisions
|
|
|
-
|
|
|
-
|
|
|
122
|
|
|
137
|
|
|
137
|
|
|
Pacific
Gas and Electric Company
For
the Year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
revenues
|
|
$
|
12,539
|
|
$
|
11,704
|
|
$
|
11,080
|
|
$
|
10,438
|
|
$
|
10,514
|
|
|
Operating
income
|
|
|
2,115
|
|
|
1,970
|
|
|
7,144
|
|
|
2,339
|
|
|
3,913
|
|
|
Income
available for common stock
|
|
|
971
|
|
|
918
|
|
|
3,961
|
|
|
901
|
|
|
1,794
|
|
|
At
Year-End
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
assets
|
|
$
|
34,371
|
|
$
|
33,783
|
|
$
|
34,302
|
|
$
|
29,066
|
|
$
|
27,593
|
|
|
Long-term
debt (excluding current portion)
|
|
|
6,697
|
|
|
6,696
|
|
|
7,043
|
|
|
2,431
|
|
|
2,739
|
|
|
Rate
reduction bonds (excluding current portion)
|
|
|
-
|
|
|
290
|
|
|
580
|
|
|
870
|
|
|
1,160
|
|
|
Energy
recovery bonds (excluding current portion)
|
|
|
1,936
|
|
|
2,276
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
Financial
debt subject to compromise
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
5,603
|
|
|
5,605
|
|
|
Preferred
stock with mandatory redemption provisions
|
|
|
-
|
|
|
-
|
|
|
122
|
|
|
137
|
|
|
137
|
|
|
|
|
|
||||||||||||||
|
|
||||||||||||||||
|
(1) Financial
data reflects the recognition of regulatory assets provided under
the
December 19, 2003 settlement agreement entered into among PG&E
Corporation, Pacific Gas and Electric Company and the California
Public
Utilities Commission to resolve Pacific Gas and Electric Company’s
proceeding under Chapter 11 of the U.S. Bankruptcy Code.
|
||||||||||||||||
|
(2)Matters
relating to discontinued operations are discussed in Management's
Discussion and Analysis of Financial Condition and Results of Operations
and in the Notes to the Consolidated Financial
Statements.
|
||||||||||||||||
|
(3)
The Board of Directors of PG&E Corporation declared a cash dividend of
$0.30 per share per quarter for the first three quarters of 2005.
In the
fourth quarter of 2005, the quarterly cash dividend declared was
increased
to $0.33 per share. See Note 8 of the Notes to the Consolidated
Financial
Statements for further discussion.
|
||||||||||||||||
|
(4) Book
value per common share includes the effect of participating securities.
The dilutive effect of outstanding stock options and restricted
stock are
further disclosed in the Notes to the Consolidated Financial
Statements.
|
||||||||||||||||
|
·
|
The
Outcome of Regulatory Proceedings.
The amount of the Utility’s revenues and the amount of costs the Utility
is authorized to recover from customers are primarily determined
through regulatory
proceedings. The
timing of CPUC and FERC decisions affect when the Utility is able
to
record the authorized revenues. As described above, the FERC’s decision in
2006 to allow the Utility to recover SC costs had a material effect
on
PG&E Corporation’s and the Utility’s results of operations.
The
outcome of various other regulatory proceedings, including the
Utility’s
2007 General Rate Case, or GRC, also will have a material effect.
In the
2007 GRC, the CPUC will determine the amount of the Utility’s authorized
base revenues for the period 2007 through 2010. The Utility has
requested
the CPUC to approve a settlement agreement reached in the Utility’s 2007
GRC. The proposed revenue requirement provided in the settlement
agreement
reflects an increase of $222 million in the Utility's electric
distribution revenues, an increase of $21 million in gas distribution
revenues, and a decrease of $30 million in generation operation
revenues
for an overall increase of $213 million over the authorized 2006
amounts.
The settlement agreement also includes revenue increases for 2008,
2009
and 2010. The revenue requirements authorized in the 2007 GRC will
be
effective as of January 1, 2007. On February 13, 2007 a proposed
decision
and an alternate proposed decision were issued in the 2007 GRC.
(See
further discussion under “Regulatory Matters” below.)
|
|
|
|
|
·
|
Capital
Structure. The
Utility’s 2006 and 2007 authorized capital structure includes a 52% equity
component. For 2006 and 2007, the Utility is authorized to earn
a rate of
return on equity, or ROE, of 11.35% on
its electricity and natural gas distribution and electricity generation
rate base. The CPUC will conduct a new cost of capital proceeding
to set
the Utility’s authorized capital structure and rates of return for 2008.
The Utility is required to file its 2008 cost of capital application
by
May 8, 2007.
|
|
|
|
|
·
|
The
Success of the Utility’s Strategy to Achieve Operational Excellence and
Improved Customer Service.
During 2006, the Utility continued to undertake various initiatives
to
implement changes to its business processes and systems in an effort
to
provide better, faster and more cost-effective service to its customers.
During 2006, the Utility incurred approximately $137 million, including
approximately $36 million for employee severance costs, to implement
these
initiatives. The Utility intends to incur similar costs of approximately
$200 million for further implementation of these initiatives in
2007. The
proposed amounts of the revenue requirement increases for 2008,
2009 and
2010 included in the proposed 2007 GRC settlement agreement are
expected
to be adequate in light of the estimated cost savings anticipated
to be
realized from implementation of these initiatives. If the actual
cost
savings are greater than anticipated, such benefits would accrue
to
shareholders. Conversely, if these cost savings are not realized,
earnings
available for shareholders would be reduced.
|
|
|
|
|
·
|
The
Amount and Timing of Capital Expenditures. In
2006, the CPUC authorized the Utility to make substantial capital
expenditures in connection with the
construction of new generation facilities estimated to become operational
beginning in 2009 and 2010, and the installation of an advanced
metering
system. In addition, the
Utility has requested regulatory approval for various capital expenditures
to fund investments in transmission and distribution infrastructure
needed
to serve its customers (i.e., to extend the life of existing
infrastructure, to replace existing infrastructure and to add new
infrastructure to meet already authorized growth). The amount and
timing
of the Utility’s capital expenditures will affect the amount of rate base
on which the Utility may earn its authorized ROE. If the CPUC disallowed
the Utility from recovering any portion of its capital expenditures
from
customers the Utility would be unable to earn a ROE on the disallowed
amount. (See further discussion under “Capital Expenditures”
below.)
|
|
|
|
|
·
|
Changes
in Environmental Liabilities and the Outcome of
Litigation. The
Utility's operations are subject to extensive federal, state and
local
environmental laws and permits. Complying with these environmental
laws
has in the past required significant expenditures for environmental
compliance, monitoring and pollution control equipment, as well
as for
related fees and permits. During 2006, the Utility increased its
recorded
liability for environmental remediation by $74 million. In addition,
during 2006, the Utility paid approximately $295 million to settle
a
majority of claims
relating to alleged exposure to chromium at the Utility’s natural gas
compressor stations. (See discussion under “Environmental Matters” below
and Note 17 of the Notes to Consolidated Financial Statements.)
|
|
|
|
|
·
|
Impact
of the Utility’s Chapter 11 Reorganization. The
Utility’s plan of reorganization under Chapter 11 of the U.S. Bankruptcy
Code became effective on April 12, 2004. The plan of reorganization
incorporated the terms of a settlement agreement among the CPUC,
PG&E
Corporation and the Utility, referred to as the Chapter 11 Settlement
Agreement. During 2005, the Utility issued two series of ERBs.
The first
series was issued to refinance the after-tax portion of the settlement
regulatory asset established under the Chapter 11 Settlement Agreement.
The second series was issued to pre-fund the Utility’s tax liability that
will be due as the Utility collects the dedicated rate component,
or DRC,
used
to secure repayment of the first series of ERBs from its customers.
Until
these taxes are fully paid, the Utility provides customers a “carrying
cost” credit to compensate customers for the use of proceeds from the
second series of ERBs. The equity component of this carrying cost
credit
of approximately $56 million resulted in a net income decrease
in 2006 and
is expected to impact net income by approximately $48 million in
2007.
The
carrying cost credit will decline each year over the term of the
ERBs
until the ERBs are fully repaid in 2012. Additionally,
the Utility recovered net interest costs related to disputed generator
claims for the period between the effective date of the plan of
reorganization and the first series of ERBs, and for certain energy
supplier refund litigation costs, resulting in an increase of
approximately $39 million to net income in 2006.
|
|
·
|
the
Utility’s ability to timely recover costs through rates;
|
|
·
|
the
outcome of regulatory proceedings, including ratemaking proceedings
pending at the CPUC and the FERC;
|
|
·
|
the
adequacy and price of electricity and natural gas supplies, and
the
ability of the Utility to manage and respond to the volatility
of the
electricity and natural gas markets;
|
|
·
|
the
effect of weather, storms, earthquakes, fires, floods, disease,
other
natural disasters, explosions, accidents, mechanical breakdowns,
acts of
terrorism, and other events or hazards on the Utility’s facilities and
operations, its customers and third parties on which the Utility
relies;
|
|
·
|
the
potential impacts of climate change on the Utility’s electricity and
natural gas operations;
|
|
·
|
changes
in customer demand for
electricity and natural gas
resulting from unanticipated population growth or decline, general
economic and financial market conditions, changes in technology
including
the development of alternative energy sources, or other reasons;
|
|
·
|
operating
performance of the Utility’s Diablo Canyon nuclear generating facilities,
or Diablo Canyon, the occurrence of unplanned outages at Diablo
Canyon, or
the temporary or permanent cessation of operations at Diablo
Canyon;
|
|
·
|
the
ability of the Utility to recognize benefits from its initiatives
to
improve its business processes and customer service;
|
|
·
|
the
ability of the Utility to timely complete its planned capital investment
projects;
|
|
·
|
the
impact of changes in federal or state laws, or their interpretation,
on
energy policy and the regulation of utilities and their holding
companies;
|
|
·
|
the
impact of changing wholesale electric or gas market rules, including
the
California Independent System Operator’s,
or CAISO, new rules to restructure the California wholesale electricity
market;
|
|
·
|
how
the CPUC administers the conditions imposed on PG&E Corporation when
it became the Utility’s holding company;
|
|
·
|
the
extent to which PG&E Corporation or the Utility incurs costs in
connection with pending litigation that are not recoverable through
rates,
from third parties, or through insurance recoveries;
|
|
·
|
the
ability of PG&E Corporation and/or the Utility to access capital
markets and other sources of credit;
|
|
·
|
the
impact of environmental laws and regulations and the costs of compliance
and remediation; and
|
|
·
|
the
effect of municipalization, direct access, community choice aggregation,
or other forms of bypass.
|
|
Year
ended December 31,
|
||||||||||
|
2006
|
2005
|
2004
|
||||||||
|
(in
millions)
|
||||||||||
|
Utility
|
||||||||||
|
Electric
operating revenues
|
$
|
8,752
|
$
|
7,927
|
$
|
7,867
|
||||
|
Natural
gas operating revenues
|
3,787
|
3,777
|
3,213
|
|||||||
|
Total
operating revenues
|
12,539
|
11,704
|
11,080
|
|||||||
|
Cost
of electricity
|
2,922
|
2,410
|
2,770
|
|||||||
|
Cost
of natural gas
|
2,097
|
2,191
|
1,724
|
|||||||
|
Operating
and maintenance
|
3,697
|
3,399
|
2,848
|
|||||||
|
Recognition
of regulatory assets
|
-
|
-
|
(4,900
|
)
|
||||||
|
Depreciation,
amortization and decommissioning
|
1,708
|
1,734
|
1,494
|
|||||||
|
Total
operating expenses
|
10,424
|
9,734
|
3,936
|
|||||||
|
Operating
income
|
2,115
|
1,970
|
7,144
|
|||||||
|
Interest
income
|
175
|
76
|
50
|
|||||||
|
Interest
expense
|
(710
|
)
|
(554
|
)
|
(667
|
)
|
||||
|
Other
expense, net(1)
|
(7
|
)
|
-
|
(5
|
)
|
|||||
|
Income
before income taxes
|
1,573
|
1,492
|
6,522
|
|||||||
|
Income
tax provision
|
602
|
574
|
2,561
|
|||||||
|
Income
available for common stock
|
$
|
971
|
$
|
918
|
$
|
3,961
|
||||
|
PG&E
Corporation, Eliminations and Other(2)
|
||||||||||
|
Operating
revenues
|
$
|
-
|
$
|
(1
|
)
|
$
|
-
|
|||
|
Operating
(gain) expenses
|
7
|
(1
|
)
|
26
|
||||||
|
Operating
loss
|
(7
|
)
|
-
|
(26
|
)
|
|||||
|
Interest
income
|
13
|
4
|
13
|
|||||||
|
Interest
expense
|
(28
|
)
|
(29
|
)
|
(130
|
)
|
||||
|
Other
expense, net(1)
|
(6
|
)
|
(19
|
)
|
(93
|
)
|
||||
|
Loss
before income taxes
|
(28
|
)
|
(44
|
)
|
(236
|
)
|
||||
|
Income
tax benefit
|
(48
|
)
|
(30
|
)
|
(95
|
)
|
||||
|
Income
(loss) from continuing operations
|
20
|
(14
|
)
|
(141
|
)
|
|||||
|
Discontinued
operations(3)
|
-
|
13
|
684
|
|||||||
|
Net
income (loss)
|
$
|
20
|
$
|
(1
|
)
|
$
|
543
|
|||
|
Consolidated
Total
|
||||||||||
|
Operating
revenues
|
$
|
12,539
|
$
|
11,703
|
$
|
11,080
|
||||
|
Operating
expenses
|
10,431
|
9,733
|
3,962
|
|||||||
|
Operating
income
|
2,108
|
1,970
|
7,118
|
|||||||
|
Interest
income
|
188
|
80
|
63
|
|||||||
|
Interest
expense
|
(738
|
)
|
(583
|
)
|
(797
|
)
|
||||
|
Other
expenses, net(1)
|
(13
|
)
|
(19
|
)
|
(98
|
)
|
||||
|
Income
before income taxes
|
1,545
|
1,448
|
6,286
|
|||||||
|
Income
tax provision
|
554
|
544
|
2,466
|
|||||||
|
Income
from continuing operations
|
991
|
904
|
3,820
|
|||||||
|
Discontinued
operations(3)
|
-
|
13
|
684
|
|||||||
|
Net
income
|
$
|
991
|
$
|
917
|
$
|
4,504
|
||||
|
(1)
Includes preferred stock dividend requirement as other
expense.
|
||||||||||
|
(2)
PG&E Corporation eliminates all intercompany transactions in
consolidation.
|
||||||||||
|
(3)
Discontinued operations reflect items related to its former subsidiary,
NEGT. See Note 7 of the Notes to the Consolidated Financial Statements
for
further discussion.
|
||||||||||
|
|
2006
|
2005
|
2004
|
|||||||
|
(in
millions)
|
|
|||||||||
|
Electric
revenues
|
$
|
10,871
|
$
|
9,626
|
$
|
9,800
|
||||
|
DWR
pass-through revenue
|
(2,119
|
)
|
(1,699
|
)
|
(1,933
|
)
|
||||
|
Total
electric operating revenues
|
$
|
8,752
|
$
|
7,927
|
$
|
7,867
|
||||
|
Total
electricity sales (in GWh)
|
64,725
|
61,150
|
62,998
|
|||||||
|
·
|
Electricity
procurement costs, which are passed through to customers, increased
by
approximately $490 million. (See “Cost of Electricity” below.)
|
|
·
|
The
DRC charge related to the ERBs increased by approximately $175
million
(see further discussion in Notes 3 and 6 of the Notes to the Consolidated
Financial Statements). During 2005, the Utility collected only
the DRC for
the first series of ERBs that were issued on February 10, 2005.
During
2006, the Utility collected the DRC associated with the first series
of
ERBs and the DRC related to the second series of ERBs, issued on
November
9, 2005.
|
|
·
|
The
Utility recovered approximately $136 million of costs it incurred
as a SC,
from April 1998 through September 2006, based on a FERC order issued
in
August of 2006. SC costs incurred after September 2006 and in the
future
are considered probable of recovery.
|
|
·
|
The
Utility recognized attrition adjustments to the Utility’s authorized 2003
base revenue requirements of approximately $135 million as authorized
in
the 2003 GRC.
|
|
·
|
The
Utility recorded approximately $112 million in revenue requirements
to
recover a pension contribution attributable to the Utility’s electric
distribution and generation operations. (See "Regulatory Matters
- Defined
Benefit Pension Plan Contribution" below.)
|
|
·
|
Transmission
revenues increased by approximately $90 million primarily due to
an
increase in revenues as authorized in the Utility’s last FERC TO rate
case.
|
|
·
|
The
Utility recognized approximately $65 million due to the recovery
of net
interest costs related to disputed generator claims for the period
between
April 12, 2004, the effective date of the Utility’s plan of
reorganization, and February 10, 2005, when the first series of
ERBs was
issued, and for certain energy supplier refund litigation costs.
Recovery
of these costs in the Energy Recovery Bond Balancing Account, or
ERBBA,
was authorized by the CPUC upon their completion of the verification
audit
in the 2005 annual electric true-up proceeding in September 2006.
|
|
·
|
The
Utility recovered approximately $59 million of net interest costs
related
to disputed generator claims incurred after the issuance of the
first
series of ERBs. Recovery of these costs through the ERBBA was authorized
by the CPUC. Costs incurred after December 2006 and in the future
are
considered probable of recovery. (See “Interest Income” and “Interest
Expense” below for further discussion.)
|
|
·
|
In
2005, the Utility recognized approximately $160 million due to
the
resolution of the Utility’s claims for shareholder incentives related to
energy efficiency and other public purpose programs. No similar
amount was
recorded in 2006.
|
|
·
|
In
2005, the Utility recognized approximately $154 million related
to revenue
requirements associated with the settlement regulatory asset provided
under the Chapter 11 Settlement Agreement and the recovery of costs
on the
deferred tax component of the settlement regulatory asset. No similar
amounts were recorded in 2006.
|
|
·
|
The
carrying cost credit, including both the debt and equity components,
associated with the issuance of the second series of ERBs, decreased
electric operating revenues by approximately $123 million in 2006
from
2005. The second series of ERBs was issued to pre-fund the Utility's
tax
liability that will be due as the Utility collects the DRC related
to the
first series from its customers over the term of the ERBs. Until
these
taxes are fully paid, the Utility provides customers a carrying
cost
credit, computed at the Utility's authorized rate of return on
rate base
to compensate them for the use of proceeds from the second series
of ERBs.
|
|
·
|
The
Utility began collecting the DRC charge related to ERBs in 2005,
which
together with revenue requirements associated with the ERBBA, increased
electric operating revenues by approximately $390 million in 2005
compared
to 2004. (See further discussion in Notes 3 and 6 of the Notes
to the
Consolidated Financial Statements.)
|
|
|
|
|
·
|
The
Utility recognized approximately $160 million in 2005 due to the
resolution of the Utility’s claims for shareholder incentives related to
energy efficiency and other public purpose programs covering 1994
- 2001.
No similar amount was recorded in 2004.
|
|
|
|
|
·
|
Miscellaneous
other electric operating revenues, including revenues associated
with
public purpose programs and advanced metering and demand response
programs, increased by approximately $140 million.
|
|
|
|
|
·
|
The
Utility recognized approximately $100 million of revenues in 2005
relating
to the Self-Generation Incentive Program. No similar amount was
recorded
in 2004.
|
|
|
|
|
·
|
The
Utility recognized attrition adjustments to the Utility’s authorized 2003
base revenue requirements, which together with an increase in revenues
authorized in the 2004 cost of capital decision, increased electric
operating revenues by approximately $90 million, compared to
2004.
|
|
|
|
|
·
|
The
Utility recognized approximately $80 million in 2005 due to recovery
of
certain costs incurred in connection with electric industry restructuring.
No similar amount was recorded in 2004.
|
|
|
|
|
·
|
Electric
operating revenues included approximately $70 million in refunds
in
revenue requirements to customers in 2004, with no similar amount
in
2005.
|
|
·
|
Electricity
procurement and transmission costs, which are passed through to
customers,
decreased by approximately $530 million compared to
2004.
|
|
|
|
|
·
|
After
the issuance of the first series of ERBs on February 10, 2005,
the Utility
was no longer able to collect the revenue requirement associated
with the
settlement regulatory asset, decreasing electric operating revenues
by
approximately $435 million compared to 2004. (See further discussion
in
Notes 3 and 6 of the Notes to the Consolidated Financial Statements.)
|
|
|
2006
|
2005
|
2004
|
|||||||
|
(in
millions)
|
|
|||||||||
|
Cost
of purchased power
|
$
|
3,114
|
$
|
2,706
|
$
|
2,816
|
||||
|
Proceeds
from surplus sales allocated to the Utility
|
(343
|
)
|
(478
|
)
|
(192
|
)
|
||||
|
Fuel
used in own generation
|
151
|
182
|
146
|
|||||||
|
Total
cost of electricity
|
$
|
2,922
|
$
|
2,410
|
$
|
2,770
|
||||
|
Average
cost of purchased power per GWh
|
$
|
0.084
|
$
|
0.079
|
$
|
0.082
|
||||
|
Total
purchased power (GWh)
|
36,913
|
34,203
|
34,525
|
|||||||
|
·
|
The
increase in total purchased power of 2,710 Gigawatt hours, or GWh,
and the
increase in the average cost of purchased power of $0.005 per GWh
in 2006,
compared to 2005, resulted in an increase of approximately $408
million in
the cost of purchased power. This was primarily caused by an increase
in
volume of purchased power due to greater customer demand during
the July
2006 “heat storm” (see discussion below under “Regulatory Matters -
Catastrophic Events Memorandum Account”) and a decrease in the volume of
electricity provided by the DWR to the Utility’s customers. Additionally,
the Utility’s service to customers who purchase “bundled” services (e.g.
generation, transmission and distribution) grew, further increasing
volume.
|
|
·
|
Increased
electricity production from the Utility’s hydroelectric generation
facilities due to above average rainfall during 2005 increased
the
proceeds from surplus sales allocated to the Utility by $286 million.
|
|
|
|
|
·
|
The
volume of total purchased power decreased by 322 GWh in 2005 primarily
because increased electricity from the Utility’s hydroelectric facilities
and Diablo Canyon reduced the amount of electricity the Utility
needed to
purchase. During 2005, Diablo Canyon’s refueling outage lasted only 41
days compared to 2004 when the outage lasted 129.5 days. Also,
the average
cost of purchased power decreased by $0.003 per GWh in 2005 from
2004.
|
|
|
2006
|
2005
|
2004
|
|||||||
|
(in
millions)
|
|
|||||||||
|
Bundled
natural gas revenues
|
$
|
3,472
|
$
|
3,539
|
$
|
2,943
|
||||
|
Transportation
service-only revenues
|
315
|
238
|
270
|
|||||||
|
Total
natural gas operating revenues
|
$
|
3,787
|
$
|
3,777
|
$
|
3,213
|
||||
|
Average
bundled revenue per Mcf of natural gas sold
|
$
|
12.89
|
$
|
13.05
|
$
|
10.51
|
||||
|
Total
bundled natural gas sales (in millions of Mcf)
|
269
|
271
|
280
|
|||||||
|
·
|
The
Utility recorded approximately $43 million in revenue requirements
for a
pension contribution attributable to the Utility’s natural gas
distribution operations. (See "Regulatory Matters - Defined Benefit
Pension Plan Contribution" below.)
|
|
·
|
Attrition
adjustments to the Utility’s 2003 GRC authorized revenue requirements, and
revenues authorized in the 2006 cost of capital proceeding contributed
approximately $22 million.
|
|
·
|
Miscellaneous
natural gas revenues increased by approximately $26
million.
|
|
·
|
Transportation
service-only revenues increased by approximately $77 million, or
32%,
primarily as a result of an increase in rates.
|
|
·
|
The
cost of natural gas, which is passed through to customers, decreased
by
approximately $132 million, as further discussed below under “Cost of
Natural Gas.”
|
|
·
|
In
2005, the Utility recognized approximately $26 million due to the
resolution of the Utility’s claims for shareholder incentives related to
energy efficiency and other public purpose programs. No similar
amount was
recorded in 2006.
|
|
·
|
Excluding
the impact of the 2003 GRC decision, the 2005 cost of capital proceeding,
and the Utility’s recovery of shareholder incentives relating to energy
efficiency and other public purpose programs, bundled natural gas
operating revenues increased by approximately $580 million, or
20%. The
increase was attributable to an increase in the cost of natural
gas, which
is passed through to customers, and partially offset by a decrease
in the
volume of gas purchased.
|
|
·
|
Attrition
adjustments to the Utility’s 2003 GRC authorized revenue requirements, and
revenues authorized in the 2005 cost of capital proceeding contributed
approximately $42 million in 2005 compared to 2004.
|
|
|
|
|
·
|
The
Utility recognized approximately $26 million in 2005 due to the
resolution
of the Utility’s claims for shareholder incentives related to energy
efficiency and other public purpose programs covering 1994 - 2001.
No
similar amount was recorded in 2004.
|
|
·
|
The
approval of the 2003 GRC in May 2004 resulted in the Utility recording
approximately $52 million in revenues related to 2003 in 2004.
No
comparable amount was recorded in 2005.
|
|
|
|
|
·
|
Transportation
service-only revenues decreased by approximately $32 million, or
12%,
primarily as a result of a decrease in rates.
|
|
2006
|
2005
|
2004
|
||||||||
|
(in
millions)
|
|
|||||||||
|
Cost
of natural gas sold
|
$
|
1,958
|
$
|
2,051
|
$
|
1,591
|
||||
|
Cost
of natural gas transportation
|
139
|
140
|
133
|
|||||||
|
Total
cost of natural gas
|
$
|
2,097
|
$
|
2,191
|
$
|
1,724
|
||||
|
Average
cost per Mcf of natural gas sold
|
$
|
7.28
|
$
|
7.57
|
$
|
5.68
|
||||
|
Total
natural gas sold (in millions of Mcf)
|
269
|
271
|
280
|
|||||||
|
·
|
Pension
contributions as a result of the CPUC-approved settlement (see
“Regulatory
Matters - Defined Benefit Pension Plan Contribution” below) resulted in an
additional $176 million in pension expense.
|
|
|
|
|
·
|
Administration
expenses for low-income customer assistance programs, the Self-Generation
Incentive Program, advanced metering infrastructure and other energy
incentives, increased by approximately $125 million.
|
|
·
|
Compensation
expense increased approximately $54 million, reflecting increased
base
salaries and incentives.
|
|
·
|
Expenses
for outside consulting, contracts and various programs and initiatives,
including strategies to achieve operational excellence and improved
customer service, increased by approximately $50
million.
|
|
·
|
Expenses
related to the accrual of severance costs as part of the Utility’s
strategies to achieve operational excellence and improved customer
service
increased by approximately $35 million.
|
|
·
|
Franchise
fee expense and property taxes increased by approximately $21 million.
The
increase in franchise fee expense was due to higher revenues and
franchise
fee rates. The increase in property taxes was due to electric plant
growth, a tax rate increase, and increases in assessed values in
2006.
|
|
·
|
An
additional $154 million was reserved to
settle the majority of claims related to alleged exposure to chromium
at
the Utility’s natural gas compressor stations.
(See “Legal Matters” in Note 17 of the Notes to the Consolidated Financial
Statements for further discussion.)
|
|
|
|
|
·
|
Administration
expenses for low-income customer assistance programs and community
outreach programs increased by approximately $110
million.
|
|
|
|
|
·
|
Approximately
$100 million in Self-Generation Incentive Program expenses that
were
deferred in prior periods because no specific revenue recovery
mechanism
was in place, were recognized in 2005. (See related revenues in
“Electric
Operating Revenues.”)
|
|
|
|
|
·
|
Expenses
for outside consulting, contract and legal expense and various
programs
and initiatives, including strategies to achieve operational excellence
and improved customer service, increased by approximately $55
million.
|
|
|
|
|
·
|
Natural
gas transportation operations charges increased by approximately
$60
million mainly due to rate increases for pipeline demand and
transportation.
|
|
·
|
The
estimated cost of environmental remediation related to the Topock
and
Hinkley gas compressor stations increased expenses by approximately
$40
million. (See “Environmental Matters” in Note 17 of the Notes to the
Consolidated Financial Statements for further
discussion.)
|
|
|
|
|
·
|
Property
taxes increased approximately $25 million mainly due to higher
assessments
in 2005.
|
|
·
|
The
Utility recorded approximately $141 million in 2005 for amortization
of
the settlement regulatory asset. Because the settlement regulatory
asset
was refinanced with the issuance of the first series of ERBs on
February
10, 2005, the Utility had no similar amount in 2006.
|
|
|
|
|
·
|
In
2005, the Utility recorded depreciation expense of approximately
$30
million related to recovery of capital plant costs associated with
electric industry restructuring costs that a December 2004 settlement
agreement allowed the Utility to collect through rates in 2005.
There was
no similar depreciation expense in 2006.
|
|
·
|
Amortization
of the regulatory asset related to rate recovery bonds, or RRBs,
decreased
by approximately $19 million in 2006, compared to 2005, due to
the
declining balance of the RRBs.
|
|
·
|
An
increase
of approximately $137 million related to the amortization
of the ERB regulatory asset. During 2005, the Utility amortized
only the
ERB regulatory asset for the first series of ERBs that were issued
on
February 10, 2005. During 2006, the Utility amortized the ERB regulatory
asset for the second series of ERBs that were issued on November
9, 2005
in addition to the first series.
|
|
·
|
Depreciation
expense increased by approximately $35 million as a result of plant
additions in 2006.
|
|
·
|
The
Utility recorded additional amortization expense of approximately
$202
million in 2005 as it began to amortize the ERB regulatory
asset.
|
|
|
|
|
·
|
In
2004, following the 2003 GRC decision in May 2004 that authorized
lower
depreciation rates, the Utility recorded an approximately $38 million
decrease to depreciation expense. There was no similar reduction
in 2005.
|
|
|
|
|
·
|
The
Utility recorded depreciation expense of approximately $30 million
related
to recovery of capital plant costs associated with electric industry
restructuring costs the December 2004 settlement agreement allowed
the
Utility to collect through rates. There was no similar depreciation
expense in 2004.
|
|
·
|
Amortization
of the regulatory asset related to the RRBs decreased by approximately
$20
million in 2005 compared to 2004 again reflecting the declining
balance of
the RRBs.
|
|
|
|
|
·
|
Amortization
of the settlement regulatory asset decreased by approximately $10
million
in 2005 reflecting the refinancing of the settlement regulatory
asset with
the ERBs.
|
|
|
Moody's
|
S&P
|
|||||
|
Utility
|
|||||||
|
Corporate
credit rating
|
Baa1
|
BBB
|
|||||
|
Senior
unsecured debt
|
Baa1
|
BBB
|
|||||
|
Pollution
control bonds backed by bond insurance
|
Aaa
|
AAA
|
|||||
|
Pollution
control bonds backed by letters of credit
|
-(1
|
)
|
AA-/A-1+
|
||||
|
Credit
facility
|
Baa1
|
BBB
|
|||||
|
Preferred
stock
|
Baa3
|
BB+
|
|||||
|
Commercial
paper program
|
P-2
|
A-2
|
|||||
|
|
|||||||
|
PG&E
Funding LLC
|
|||||||
|
Rate
reduction bonds
|
Aaa
|
AAA
|
|||||
|
|
|||||||
|
PG&E
Energy Recovery Funding LLC
|
|||||||
|
Energy
recovery bonds
|
Aaa
|
AAA
|
|||||
|
|
|||||||
|
PG&E
Corporation
|
|||||||
|
Credit
facility
|
Baa3
|
-
|
|||||
|
|
|||||||
|
(1) Moody's
has not assigned a rating to the Utility's
pollution control bonds backed by letters of
credit.
|
|||||||
|
·
|
Comparability:
Pay a dividend competitive with the securities of comparable companies
based on payout ratio (the proportion of earnings paid out as dividends)
and, with respect to PG&E Corporation, yield (i.e., dividend divided
by share price);
|
|
|
|
|
·
|
Flexibility:
Allow sufficient cash to pay a dividend and to fund investments
while
avoiding having to issue new equity unless PG&E Corporation's or the
Utility's capital expenditure requirements are growing rapidly
and
PG&E Corporation or the Utility can issue equity at reasonable cost
and terms; and
|
|
|
|
|
·
|
Sustainability:
Avoid reduction or suspension of the dividend despite fluctuations
in
financial performance except in extreme and unforeseen
circumstances.
|
|
|
2006
|
2005
|
2004
|
|||||||
|
(in
millions)
|
|
|||||||||
|
Net
income
|
$
|
985
|
$
|
934
|
$
|
3,982
|
||||
|
Adjustments
to reconcile net income to net cash provided by operating
activities:
|
||||||||||
|
Depreciation,
amortization, decommissioning and allowance for equity funds used
during
construction
|
1,755
|
1,697
|
1,494
|
|||||||
|
Gain
on sale of assets
|
(11
|
)
|
-
|
-
|
||||||
|
Recognition
of regulatory assets
|
-
|
-
|
(4,900
|
)
|
||||||
|
Deferred
income taxes and tax credits, net
|
(287
|
)
|
(636
|
)
|
2,580
|
|||||
|
Other
deferred charges and noncurrent liabilities
|
116
|
21
|
(391
|
)
|
||||||
|
Change
in accounts receivable
|
128
|
(245
|
)
|
(85
|
)
|
|||||
|
Change
in accrued taxes/income taxes receivable
|
28
|
(150
|
)
|
52
|
||||||
|
Regulatory
balancing accounts, net
|
329
|
254
|
(590
|
)
|
||||||
|
Other
uses of cash:
|
||||||||||
|
Payments
authorized by the Bankruptcy Court on amounts classified as liabilities
subject to compromise
|
-
|
-
|
(1,022
|
)
|
||||||
|
Other
changes in operating assets and liabilities
|
(466
|
)
|
491
|
718
|
||||||
|
Net
cash provided by operating activities
|
$
|
2,577
|
$
|
2,366
|
$
|
1,838
|
|
·
|
The
Utility paid approximately $900 million in net tax payments in
2006
compared to approximately $1.4 billion in 2005.
|
|
·
|
Deferred
income taxes and tax credits decreased approximately $350 million,
primarily due to an increased California franchise tax deduction,
lower
taxable supplier settlement income received and a deduction related
to the
payment of previously accrued litigation costs.
|
|
|
|
|
·
|
Cash
settlements with energy suppliers amounted to approximately $300
million
in 2006 compared to only $160 million in 2005.
|
|
|
|
|
·
|
Collections
on balancing accounts increased by approximately $75 million in
2006,
compared to 2005, since actual costs during 2006 were less than
the
forecasted costs used to set revenue
requirements.
|
|
·
|
Approximately
$290 million of pension contributions that were made during 2006.
(See the
“Regulatory Matters - Defined
Benefit Pension Plan Contribution” below.)
|
|
·
|
Approximately
$295 million was paid in April 2006 to settle the majority of claims
relating to alleged exposure to chromium at the Utility’s natural gas
compressor stations.
|
|
·
|
The
Utility had approximately $185 million in additional costs primarily
related to power and gas procurement that were unpaid at the end
of 2005,
compared to $60 million at the end of 2006, primarily due to higher
gas
prices during 2005.
|
|
·
|
The
Utility received approximately $160 million in cash under settlements
with
third parties to resolve claims relating to the California 2000-2001
energy crisis with no similar settlements in 2004.
|
|
|
|
|
·
|
The
Utility had approximately $100 million in expenditures related
to gas
procurement and administrative and general costs that were unpaid
at the
end of 2005. In 2004, the Utility did not have similar unpaid
expenditures.
|
|
|
|
|
·
|
Collections
on balancing accounts increased by approximately $800 million in
2005,
compared to 2004, due to an increase in revenue requirements intended
to
recover 2004 undercollections.
|
|
·
|
In
2004, the Utility paid approximately $1 billion of allowed creditor
claims
on the effective date of the Utility’s Chapter 11 plan of reorganization.
Other than the $1.4 billion in tax payments described below, no
similar
amount was paid in 2005.
|
|
|
|
|
·
|
In
2005, the Utility paid approximately $1.4 billion in tax payments
compared
to approximately $100 million in 2004. This increase in tax payments
was
primarily due to an increase in the taxable amount of payments
the Utility
received in 2005 under settlement agreements with energy suppliers
to
resolve claims relating to the California 2000-2001 energy crisis
compared
to 2004. In addition, 2005 tax payments increased due to a decrease
in
deductible tax depreciation compared to 2004.
|
|
|
|
|
·
|
The
Utility paid approximately $60 million more in 2005 compared to 2004
for gas inventory as a result of increased gas
prices.
|
|
|
2006
|
2005
|
2004
|
|||||||
|
(in
millions)
|
|
|||||||||
|
Capital
expenditures
|
$
|
(2,402
|
)
|
$
|
(1,803
|
)
|
$
|
(1,559
|
)
|
|
|
Net
proceeds from sale of assets
|
17
|
39
|
35
|
|||||||
|
Decrease
(increase) in restricted cash
|
115
|
434
|
(1,577
|
)
|
||||||
|
Other
investing activities, net
|
(156
|
)
|
(29
|
)
|
(178
|
)
|
||||
|
Net
cash used by investing activities
|
$
|
(2,426
|
)
|
$
|
(1,359
|
)
|
$
|
(3,279
|
)
|
|
|
|
2006
|
2005
|
2004
|
|||||||
|
|
|
|
|
|||||||
|
(in
millions)
|
|
|||||||||
|
Borrowings
under accounts receivable facility and working capital
facility
|
$
|
350
|
$
|
260
|
$
|
300
|
||||
|
Repayments
under accounts receivable facility and working capital
facility
|
(310
|
)
|
(300
|
)
|
-
|
|||||
|
Net
issuance of commercial paper, net of discount of $2
million
|
458
|
-
|
-
|
|||||||
|
Net
proceeds from long-term debt issued
|
-
|
451
|
7,742
|
|||||||
|
Net
proceeds from energy recovery bonds issued
|
-
|
2,711
|
-
|
|||||||
|
Long-term
debt, matured, redeemed or repurchased
|
-
|
(1,554
|
)
|
(8,402
|
)
|
|||||
|
Rate
reduction bonds matured
|
(290
|
)
|
(290
|
)
|
(290
|
)
|
||||
|
Energy
recovery bonds matured
|
(316
|
)
|
(140
|
)
|
-
|
|||||
|
Preferred
stock dividends paid
|
(14
|
)
|
(16
|
)
|
(90
|
)
|
||||
|
Common
stock dividends paid
|
(460
|
)
|
(445
|
)
|
-
|
|||||
|
Preferred
stock with mandatory redemption provisions redeemed
|
-
|
(122
|
)
|
(15
|
)
|
|||||
|
Preferred
stock without mandatory redemption provisions redeemed
|
-
|
(37
|
)
|
-
|
||||||
|
Common
stock repurchased
|
-
|
(1,910
|
)
|
-
|
||||||
|
Other
financing activities
|
38
|
65
|
-
|
|||||||
|
Net
cash used by financing activities
|
$
|
(544
|
)
|
$
|
(1,327
|
)
|
$
|
(755
|
)
|
|
·
|
The
Utility had net issuances of $458 million in commercial paper,
net of a $2
million discount, in 2006 with no similar amount in 2005.
|
|
·
|
In
2005, the Utility repurchased $1.9 billion in common stock from
PG&E
Corporation. There were no common stock repurchases in
2006.
|
|
·
|
The
Utility received proceeds of $2.7 billion from the issuance of
ERBs in
2005.
|
|
|
|
|
·
|
In
May 2005, the Utility borrowed $451 million from the California
Infrastructure and Economic Development Bank, which was funded
by the
bank’s issuance of Pollution Control Bonds Series A-G, with no similar
borrowing in 2006.
|
|
|
|
|
·
|
Approximately
$316 million of ERBs matured in 2006 with only $140 million of
maturities
in 2005.
|
|
|
|
|
·
|
The
Utility borrowed $350 million from the accounts receivable facility
during
2006, compared to $260 million in 2005.
|
|
·
|
The
Utility redeemed $122 million of preferred stock with no similar
redemption in 2006.
|
|
|
|
|
·
|
In
2005, the Utility redeemed $500 million and defeased $600 million
of
Floating Rate First Mortgage Bonds. The Utility also repaid $454
million
under certain reimbursement obligations that the Utility entered
into in
April 2004, when its plan of reorganization became effective. There
were
no similar redemptions and repayments in
2006.
|
|
·
|
Proceeds
from long-term debt decreased by approximately $7.3 billion. In
2004, the
Utility issued approximately $7.7 billion, net of issuance costs
of $107
million, in long-term debt to fund its plan of reorganization.
In 2005,
only $451 million, net of issuance costs of $3 million, in long-term
debt
was incurred by the Utility related to the Pollution Control Bonds
Series
A-G.
|
|
|
|
|
·
|
An
aggregate of $2.7 billion in ERBs were issued in 2005 with no similar
issuance in 2004.
|
|
|
|
|
·
|
The
Utility repaid $300 million in 2005 under its working capital facility,
with no similar repayment in 2004.
|
|
|
|
|
·
|
Approximately
$140 million of ERBs matured in 2005 with no similar maturities
in
2004.
|
|
|
|
|
·
|
Long-term
debt matured, redeemed or repurchased by the Utility decreased
by
approximately $6.8 billion in 2005. In 2004, repayments on long-term
debt
totaled approximately $8.4 billion, primarily to discharge pre-petition
debt at the effective date of the plan of
reorganization.
|
|
|
|
|
·
|
In
2005, the Utility repurchased $1.9 billion in common stock from
PG&E
Corporation and paid $445 million in common stock dividends to
PG&E
Corporation and $31 million to PG&E Holdings LLC, a wholly owned
subsidiary of the Utility.
|
|
|
|
|
·
|
In
2005, the Utility redeemed $159 million of preferred stock compared
to $15
million in 2004.
|
|
|
|
|
·
|
Approximately
$100 million in customer deposits (included in Other Financing
Activities
in the table above) was received in 2005 with no similar amount
in
2004.
|
|
|
2006
|
2005
|
2004
|
|||||||
|
(in
millions)
|
|
|||||||||
|
Net
income
|
$
|
991
|
$
|
917
|
$
|
4,504
|
||||
|
Gain
on disposal of NEGT (net of income tax benefit of $13 million in
2005 and
income tax expense of $374 million in 2004; See Note 7 of the Notes
to the
Consolidated Financial Statements for details)
|
-
|
(13
|
)
|
(684
|
)
|
|||||
|
Net
income from continuing operations
|
991
|
904
|
3,820
|
|||||||
|
Adjustments
to reconcile net income to net cash provided by operating
activities:
|
||||||||||
|
Depreciation,
amortization, decommissioning and allowance for equity funds used
during
construction
|
1,756
|
1,698
|
1,497
|
|||||||
|
Loss
from retirement of long-term debt
|
-
|
-
|
65
|
|||||||
|
Tax
benefit from employee stock plans
|
-
|
50
|
41
|
|||||||
|
Gain
on sale of assets
|
(11
|
)
|
-
|
(19
|
)
|
|||||
|
Recognition
of regulatory asset, net of tax
|
-
|
-
|
(4,900
|
)
|
||||||
|
Deferred
income taxes and tax credits, net
|
(285
|
)
|
(659
|
)
|
2,607
|
|||||
|
Other
deferred charges and noncurrent liabilities
|
151
|
33
|
(519
|
)
|
||||||
|
Other
changes in operating assets and liabilities
|
112
|
383
|
(736
|
)
|
||||||
|
Net
cash provided by operating activities
|
$
|
2,714
|
$
|
2,409
|
$
|
1,856
|
||||
|
|
2006
|
2005
|
2004
|
|||||||
|
(in
millions)
|
|
|||||||||
|
Borrowings
under accounts receivable facility and working capital
facility
|
$
|
350
|
$
|
260
|
$
|
300
|
||||
|
Repayments
under accounts receivable facility and working capital
facility
|
(310
|
)
|
(300
|
)
|
-
|
|||||
|
Net
issuance of commercial paper, net of discount of $2
million
|
458
|
-
|
-
|
|||||||
|
Net
proceeds from issuance of long-term debt
|
-
|
451
|
7,742
|
|||||||
|
Net
proceeds from issuance of energy recovery bonds
|
-
|
2,711
|
-
|
|||||||
|
Long-term
debt matured, redeemed or repurchased
|
-
|
(1,556
|
)
|
(9,054
|
)
|
|||||
|
Rate
reduction bonds matured
|
(290
|
)
|
(290
|
)
|
(290
|
)
|
||||
|
Energy
recovery bonds matured
|
(316
|
)
|
(140
|
)
|
-
|
|||||
|
Preferred
stock with mandatory redemption provisions redeemed
|
-
|
(122
|
)
|
(15
|
)
|
|||||
|
Preferred
stock without mandatory redemption provisions redeemed
|
-
|
(37
|
)
|
-
|
||||||
|
Common
stock issued
|
131
|
243
|
162
|
|||||||
|
Common
stock repurchased
|
(114
|
)
|
(2,188
|
)
|
(378
|
)
|
||||
|
Common
stock dividends paid
|
(456
|
)
|
(334
|
)
|
-
|
|||||
|
Other
|
3
|
32
|
(91
|
)
|
||||||
|
Net
cash used by financing activities
|
$
|
(544
|
)
|
$
|
(1,270
|
)
|
$
|
(1,624
|
)
|
|
|
·
|
PG&E
Corporation paid four quarterly common stock dividends in 2006,
but made
only three payments in 2005.
|
|
|
|
|
·
|
In
2005, PG&E Corporation repurchased approximately $2.2 billion in
common stock. There was no similar share repurchase in 2006 but
PG&E
Corporation paid certain additional payments of approximately $114
million
to Goldman Sachs & Co., Inc. related to the prior year
repurchase.
|
|
·
|
In
2005, PG&E Corporation paid $334 million in common stock dividends
with no similar payment in 2004.
|
|
·
|
In
2005, PG&E Corporation issued $81 million more in common stock than in
2004.
|
|
·
|
In
2005, PG&E Corporation repurchased $2.2 billion in common stock while
repurchasing only $378 million in common stock in
2004.
|
|
|
|
Payment
due by period
|
|
|
|
|
|
|
|
|
Total
|
Less
than One year
|
1-3
years
|
3-5
years
|
More
than 5 years
|
|||||||||||
|
|
|
|
|
|
|
|||||||||||
|
(in
millions)
|
|
|||||||||||||||
|
Contractual
Commitments:
Utility
|
||||||||||||||||
|
Purchase
obligations:
|
||||||||||||||||
|
Power
purchase agreements(1):
|
||||||||||||||||
|
Qualifying
facilities
|
$
|
16,238
|
$
|
1,672
|
$
|
3,331
|
$
|
2,693
|
$
|
8,542
|
||||||
|
Irrigation
district and water agencies
|
325
|
80
|
70
|
61
|
114
|
|||||||||||
|
Renewable
contracts
|
4,356
|
166
|
498
|
637
|
3,055
|
|||||||||||
|
Other
power purchase agreements
|
919
|
251
|
421
|
218
|
29
|
|||||||||||
|
Natural
gas supply and transportation
|
1,138
|
954
|
176
|
8
|
-
|
|||||||||||
|
Nuclear
fuel
|
539
|
135
|
152
|
101
|
151
|
|||||||||||
|
Preferred
dividends and redemption requirements(2)
|
42
|
8
|
17
|
17
|
-
|
|||||||||||
|
Employee
benefits:
|
||||||||||||||||
|
Pension(3)
|
528
|
176
|
352
|
-
|
-
|
|||||||||||
|
Other
commitments(4)
|
142
|
123
|
19
|
-
|
-
|
|||||||||||
|
Advanced
metering infrastructure
|
17
|
17
|
-
|
-
|
-
|
|||||||||||
|
Operating
leases
|
109
|
20
|
32
|
23
|
34
|
|||||||||||
|
Long-term
debt(5):
|
||||||||||||||||
|
Fixed
rate obligations
|
11,514
|
297
|
1,188
|
1,045
|
8,984
|
|||||||||||
|
Variable
rate obligations
|
1,738
|
40
|
75
|
688
|
935
|
|||||||||||
|
Other
long-term liabilities reflected on the Utility's balance sheet
under GAAP:
|
||||||||||||||||
|
Rate
reduction bonds(6)
|
302
|
302
|
-
|
-
|
-
|
|||||||||||
|
Energy
recovery bonds(7)
|
2,612
|
435
|
870
|
891
|
416
|
|||||||||||
|
Capital
lease obligations(8)
|
553
|
50
|
100
|
100
|
303
|
|||||||||||
|
|
||||||||||||||||
|
PG&E
Corporation
|
||||||||||||||||
|
Long-term
debt(5):
|
||||||||||||||||
|
Convertible
subordinated notes
|
372
|
27
|
53
|
292
|
-
|
|||||||||||
|
Operating
leases
|
13
|
3
|
5
|
5
|
-
|
|||||||||||
|
Canadian
natural gas pipeline firm transportation contracts (9)
|
128
|
2
|
18
|
16
|
92
|
|||||||||||
|
|
||||||||||||||||
|
(1) This
table does not include DWR allocated contracts because the DWR
is
currently legally and financially responsible for these contracts
and
payments.
|
||||||||||||||||
|
(2) Preferred
dividend and redemption requirement estimates beyond 5 years do
not
include nonredeemable preferred stock dividend payments as these
continue
in perpetuity.
|
||||||||||||||||
|
(3) PG&E
Corporation's and the Utility's funding policy is to contribute
tax
deductible amounts, consistent with applicable regulatory decisions,
sufficient to meet minimum funding requirements. Contribution estimates
after 2007 will be driven by CPUC decisions. See further discussion
under
“Regulatory Matters.”
|
||||||||||||||||
|
(4) Includes
commitments for capital infusion agreements for limited partnership
interests in the aggregate amount of approximately $4 million,
load-control and self-generation CPUC initiatives in the aggregate
amount
of approximately $123 million and contracts for local and long-distance
telecommunications in the aggregate amount of approximately $15
million.
|
||||||||||||||||
|
(5) Includes
interest payments over the terms of the debt. See Note 4 of the
Notes to
the Consolidated Financial Statements for further
discussion.
|
||||||||||||||||
|
(6) Includes
interest payments over the terms of the bonds. See Note 5 of the
Notes to
the Consolidated Financial Statements for further discussion of
RRBs.
|
||||||||||||||||
|
(7) Includes
interest payments over the terms of the bonds. See Note 6 of the
Notes to
the Consolidated Financial Statements for further discussion of
ERBs.
|
||||||||||||||||
|
(8) See
Note 17 of the Notes to the Consolidated Financial Statements for
further
discussion of the capital lease obligations.
|
|
(9) See
Note 17 of the Notes to the Consolidated Financial Statements for
further
discussion of the PG&E Corporation’s natural gas pipeline firm
transportation contracts.
|
|
·
|
Gateway
Generating Station.
In
June 2006, the CPUC authorized the Utility to acquire the equipment,
permits, and contracts related to a partially completed 530-megawatt,
or
MW, power plant in Antioch, California, referred to as the Gateway
Generating Station, or Gateway. The Utility completed the acquisition
in
November 2006. The CPUC authorized the Utility to recover approximately
$295 million in capital costs to complete the construction of the
facility
as well as costs for its operation. On February 15, 2007, the CPUC
approved
the Utility’s request to recover an additional approximately $75 million
necessary to convert the plant from fresh water cooling to dry
cooling in
order to reduce the environmental impact of the facility and as
a result
of changes to Gateway’s environmental permits. The Utility also has filed
a request with the California Energy Commission, or CEC, to amend
the
facility’s current permit to authorize the plant to be converted from
fresh water cooling to dry cooling. The Utility expects
that the CEC will issue a decision in the second quarter of 2007.
Subject
to obtaining the permit amendment from the CEC,
meeting construction schedules, operational performance requirements
and
other conditions, the
Utility estimates that it will
complete construction of the Gateway facility and commence operations
in
2009 at an estimated cost of approximately $370 million including
expenditures related to the conversion to dry cooling.
|
|
·
|
Colusa
Power Plant.
In
November 2006,
the CPUC approved
an agreement
for
the development and construction of a 657-MW power plant to be
located in
Colusa County, California. The CPUC adopted an initial capital
cost for
the Colusa project that is equal to the sum of the fixed contract
costs
plus the Utility’s estimated owner’s costs and a contingency
amount
to
account for the risk and uncertainty in the estimation of owner’s costs.
(Owner’s costs include the Utility’s expenses for legal, engineering, and
consulting services as well as the costs for internal personnel
and
overhead related to the project.)
The CPUC also authorized the Utility to adjust the initial capital
cost
for the Colusa project to reflect any actual incentive payments
made to,
or liquidated damages received from, the contractors through notification
to the CPUC but without a reasonableness review.
Subject
to obtaining required permits, meeting
construction schedules, operational performance requirements and
other
conditions,
it
is anticipated that the Colusa
project will commence operations in 2010 at an estimated cost of
approximately $673 million.
|
|
·
|
Humboldt
Bay Power Plant. In
November 2006,
the CPUC also approved
an agreement
for the construction of a 163-MW power plant to re-power the Utility’s
existing power plant at Humboldt Bay, which is at the end of its
useful
life. The
CPUC adopted an initial capital cost of the Humboldt Bay project
equal to
the sum of the fixed contract costs plus the Utility’s estimated owner’s
costs, but limited the contingency amount for owner’s costs to five
percent of the fixed contract cost and estimated owner’s costs.
Subject
to obtaining required permits, meeting
construction schedules, operational performance requirements and
other
conditions, it
is anticipated that the Humboldt
Bay project will commence operations in 2009 at an estimated cost
of
approximately $239 million.
|
|
|
Gross
Credit
Exposure
Before Credit Collateral(1)
|
Credit
Collateral
|
Net
Credit Exposure(2)
|
Number
of
Wholesale
Customer
or Counterparties
>10%
|
Net
Exposure to
Wholesale
Customer
or Counterparties
>10%
|
|||||||||||
|
(in
millions)
|
||||||||||||||||
|
December
31, 2006
|
$
|
255
|
$
|
87
|
$
|
168
|
2
|
$
|
113
|
|||||||
|
December
31, 2005
|
$
|
447
|
$
|
105
|
$
|
342
|
3
|
$
|
165
|
|||||||
|
|
||||||||||||||||
|
|
||||||||||||||||
|
(1) Gross
credit exposure equals mark-to-market value on financially settled
contracts, notes receivable and net receivables (payables) where
netting
is contractually allowed. Gross and net credit exposure amounts
reported
above do not include adjustments for time value or liquidity. The
Utility's gross credit exposure includes wholesale activity only.
|
||||||||||||||||
|
(2) Net
credit exposure is the gross credit exposure minus credit collateral
(cash
deposits and letters of credit). For purposes of this table, parental
guarantees are not included as part of the
calculation.
|
|
Proposed
Decision (Recommending Modification to Settlement
Amounts)
|
Alternate
Proposed Decision
(Recommending
Settlement Amounts)
|
Difference
Between Recommended Amounts
|
||||||||
|
(in
millions)
|
||||||||||
|
Electric
distribution
|
$
|
199
|
$
|
222
|
$
|
(23
|
)
|
|||
|
Gas
distribution
|
9
|
21
|
(12
|
)
|
||||||
|
Electric
generation
|
(38
|
)
|
(30
|
)
|
(8
|
)
|
||||
|
Total
revenue requirement increase (decrease) for 2007:
|
$
|
170
|
$
|
213
|
$
|
(43
|
)
|
|||
|
·
|
short,
medium and long-term procurement implementation
authority;
|
|
|
|
|
·
|
a
nuclear fuel supply plan;
|
|
|
|
|
·
|
a
gas supply plan and asset plan; and
|
|
·
|
an
electric and gas price risk hedging
plan.
|
|
·
|
periodic
expirations of existing electricity purchase contracts, or entering
into
new purchase contracts;
|
|
|
|
|
·
|
fluctuation
in the output of hydroelectric and other renewable power facilities
owned
or under contract;
|
|
|
|
|
·
|
changes
in the Utility's customers' electricity demands due to customer
and
economic growth, weather, implementation of new energy efficiency
and
demand response programs, direct access, and community choice aggregation;
|
|
·
|
the
acquisition, retirement or closure of generation facilities; and
|
|
·
|
changes
in market prices that make it more economical to purchase power
in the
market rather than use the Utility’s existing
resources.
|
|
·
|
Decommissioning
costs -
The estimated costs for labor, equipment, material and other disposal
costs;
|
|
·
|
Inflation
adjustment
-
The estimated cash flows are adjusted for inflation estimates;
|
|
|
|
|
·
|
Discount
rate
-
The fair value of the obligation is based on a credit-adjusted
risk free
rate that reflects the risk associated with the obligation;
and
|
|
|
|
|
·
|
Third
party markup adjustments
-
Internal labor costs included in the cash flow calculation were
adjusted
for costs that a third party would incur in performing the tasks
necessary
to retire the asset in accordance with SFAS No. 143.
|
|
|
Increase
(decrease)
in Assumption
|
Increase
in 2006 Pension Cost
|
Increase
in Projected Benefit Obligation at December 31,
2006
|
|||||||
|
(in
millions)
|
|
|||||||||
|
Discount
rate
|
(0.5
|
)%
|
$
|
73
|
$
|
643
|
||||
|
Rate
of return on plan assets
|
(0.5
|
)%
|
40
|
-
|
||||||
|
Rate
of increase in compensation
|
0.5
|
%
|
30
|
139
|
||||||
|
|
Increase
(decrease)
in Assumption
|
Increase
in 2006
Other
Postretirement Benefit Cost
|
Increase
in Accumulated Benefit Obligation at December 31,
2006
|
|||||||
|
(in
millions)
|
|
|||||||||
|
Health
care cost trend rate
|
0.5
|
%
|
$
|
5
|
$
|
36
|
||||
|
Discount
rate
|
(0.5
|
)%
|
5
|
81
|
||||||
|
·
|
approximately
$238 million for remediation at the Hinkley and Topock natural
gas
compressor sites;
|
|
·
|
approximately
$98 million related to the pre-closing remediation liability associated
with divested generation facilities; and
|
|
·
|
approximately
$175 million related to remediation costs for the Utility’s generation
facilities and gas gathering sites, third-party disposal sites
and
manufactured gas plant sites owned by the Utility or third parties
(including those sites that are the subject of remediation orders
by
environmental agencies or claims by the current owners of the former
manufactured gas plant sites).
|
|
·
|
weather;
|
|
·
|
supply
and demand;
|
|
·
|
the
availability of competitively priced alternative energy
sources;
|
|
·
|
the
level of production of natural gas;
|
|
·
|
the
availability of nuclear fuel;
|
|
·
|
the
availability of LNG supplies;
|
|
·
|
the
price of fuels that are used to produce electricity, including
natural
gas, crude oil, coal and nuclear materials;
|
|
·
|
the
transparency, efficiency, integrity and liquidity of regional energy
markets affecting California;
|
|
·
|
electricity
transmission or natural gas transportation capacity
constraints;
|
|
·
|
federal,
state and local energy and environmental regulation and legislation;
and
|
|
·
|
natural
disasters, war, terrorism, and other catastrophic
events.
|
|
·
|
operating
limitations that may be imposed by environmental laws or regulations,
including those relating to greenhouse gases,
or other regulatory requirements;
|
|
|
|
|
·
|
imposition
of
operational performance standards by agencies with regulatory oversight
of
the Utility's
facilities;
|
|
|
|
|
·
|
environmental
accidents, including the release of hazardous or toxic substances
into the
air or water, urban wildfires and other events caused by operation
of the
Utility’s facilities or equipment failure;
|
|
|
|
|
·
|
fuel
supply interruptions;
|
|
|
|
|
·
|
blackouts;
|
|
|
|
|
·
|
failure
of the Utility’s computer information systems, including those relating to
operations or financial information such as customer billing;
|
|
·
|
labor
disputes, workforce shortage, availability of qualified
personnel;
|
|
|
|
|
·
|
weather,
storms, earthquakes, fires, floods or other natural disasters,
war,
pandemic and other catastrophic events;
|
|
|
|
|
·
|
explosions,
accidents, dam failure, mechanical breakdowns,
terrorist activities;
and
|
|
·
|
other
events or hazards
|
|
|
Year
ended December 31,
|
|||||||||
|
|
2006
|
2005
|
2004
|
|||||||
|
Operating
Revenues
|
||||||||||
|
Electric
|
$
|
8,752
|
$
|
7,927
|
$
|
7,867
|
||||
|
Natural
gas
|
3,787
|
3,776
|
3,213
|
|||||||
|
Total
operating revenues
|
12,539
|
11,703
|
11,080
|
|||||||
|
Operating
Expenses
|
||||||||||
|
Cost
of electricity
|
2,922
|
2,410
|
2,770
|
|||||||
|
Cost
of natural gas
|
2,097
|
2,191
|
1,724
|
|||||||
|
Operating
and maintenance
|
3,703
|
3,397
|
2,871
|
|||||||
|
Recognition
of regulatory assets
|
-
|
-
|
(4,900
|
)
|
||||||
|
Depreciation,
amortization, and decommissioning
|
1,709
|
1,735
|
1,497
|
|||||||
|
Total
operating expenses
|
10,431
|
9,733
|
3,962
|
|||||||
|
Operating
Income
|
2,108
|
1,970
|
7,118
|
|||||||
|
Interest
income
|
188
|
80
|
63
|
|||||||
|
Interest
expense
|
(738
|
)
|
(583
|
)
|
(797
|
)
|
||||
|
Other
expense, net
|
(13
|
)
|
(19
|
)
|
(98
|
)
|
||||
|
Income
Before Income Taxes
|
1,545
|
1,448
|
6,286
|
|||||||
|
Income
tax provision
|
554
|
544
|
2,466
|
|||||||
|
Income
From Continuing Operations
|
991
|
904
|
3,820
|
|||||||
|
Discontinued
Operations
|
||||||||||
|
Gain
on disposal of NEGT (net of income tax benefit of $13 million in
2005 and
income tax expense of $374 million in 2004)
|
-
|
13
|
684
|
|||||||
|
Net
Income
|
$
|
991
|
$
|
917
|
$
|
4,504
|
||||
|
Weighted
Average Common Shares Outstanding, Basic
|
346
|
372
|
398
|
|||||||
|
Earnings
Per Common Share from Continuing Operations,
Basic
|
$
|
2.78
|
$
|
2.37
|
$
|
9.16
|
||||
|
Net
Earnings Per Common Share, Basic
|
$
|
2.78
|
$
|
2.40
|
$
|
10.80
|
||||
|
Earnings
Per Common Share from Continuing Operations,
Diluted
|
$
|
2.76
|
$
|
2.34
|
$
|
8.97
|
||||
|
Net
Earnings Per Common Share, Diluted
|
$
|
2.76
|
$
|
2.37
|
$
|
10.57
|
||||
|
Dividends
Declared Per Common Share
|
$
|
1.32
|
$
|
1.23
|
$
|
-
|
||||
|
|
Balance
at December 31,
|
||||||
|
|
2006
|
2005
|
|||||
|
ASSETS
|
|||||||
|
Current
Assets
|
|||||||
|
Cash
and cash equivalents
|
$
|
456
|
$
|
713
|
|||
|
Restricted
cash
|
1,415
|
1,546
|
|||||
|
Accounts
receivable:
|
|||||||
|
Customers
(net of allowance for doubtful accounts of $50 million in 2006
and $77
million in 2005)
|
2,343
|
2,422
|
|||||
|
Regulatory
balancing accounts
|
607
|
727
|
|||||
|
Inventories:
|
|||||||
|
Gas
stored underground and fuel oil
|
181
|
231
|
|||||
|
Materials
and supplies
|
149
|
133
|
|||||
|
Income
taxes receivable
|
-
|
21
|
|||||
|
Prepaid
expenses and other
|
716
|
187
|
|||||
|
Total
current assets
|
5,867
|
5,980
|
|||||
|
Property,
Plant and Equipment
|
|||||||
|
Electric
|
24,036
|
22,482
|
|||||
|
Gas
|
9,115
|
8,794
|
|||||
|
Construction
work in progress
|
1,047
|
738
|
|||||
|
Other
|
16
|
16
|
|||||
|
Total
property, plant and equipment
|
34,214
|
32,030
|
|||||
|
Accumulated
depreciation
|
(12,429
|
)
|
(12,075
|
)
|
|||
|
Net
property, plant and equipment
|
21,785
|
19,955
|
|||||
|
Other
Noncurrent Assets
|
|||||||
|
Regulatory
assets
|
4,902
|
5,578
|
|||||
|
Nuclear
decommissioning funds
|
1,876
|
1,719
|
|||||
|
Other
|
373
|
842
|
|||||
|
Total
other noncurrent assets
|
7,151
|
8,139
|
|||||
|
TOTAL
ASSETS
|
$
|
34,803
|
$
|
34,074
|
|||
|
|
Balance
at December 31,
|
||||||
|
|
2006
|
2005
|
|||||
|
LIABILITIES
AND SHAREHOLDERS' EQUITY
|
|||||||
|
Current
Liabilities
|
|||||||
|
Short-term
borrowings
|
$
|
759
|
$
|
260
|
|||
|
Long-term
debt, classified as current
|
281
|
2
|
|||||
|
Rate
reduction bonds, classified as current
|
290
|
290
|
|||||
|
Energy
recovery bonds, classified as current
|
340
|
316
|
|||||
|
Accounts
payable:
|
|||||||
|
Trade
creditors
|
1,075
|
980
|
|||||
|
Disputed
claims and customer refunds
|
1,709
|
1,733
|
|||||
|
Regulatory
balancing accounts
|
1,030
|
840
|
|||||
|
Other
|
420
|
441
|
|||||
|
Interest
payable
|
583
|
473
|
|||||
|
Income
taxes payable
|
102
|
-
|
|||||
|
Deferred
income taxes
|
148
|
181
|
|||||
|
Other
|
1,513
|
1,416
|
|||||
|
Total
current liabilities
|
8,250
|
6,932
|
|||||
|
Noncurrent
Liabilities
|
|||||||
|
Long-term
debt
|
6,697
|
6,976
|
|||||
|
Rate
reduction bonds
|
-
|
290
|
|||||
|
Energy
recovery bonds
|
1,936
|
2,276
|
|||||
|
Regulatory
liabilities
|
3,392
|
3,506
|
|||||
|
Asset
retirement obligations
|
1,466
|
1,587
|
|||||
|
Deferred
income taxes
|
2,840
|
3,092
|
|||||
|
Deferred
tax credits
|
106
|
112
|
|||||
|
Other
|
2,053
|
1,833
|
|||||
|
Total
noncurrent liabilities
|
18,490
|
19,672
|
|||||
|
Commitments
and Contingencies (Notes 2, 4, 5, 6, 8, 9, 13, 15 and
17)
|
|||||||
|
Preferred
Stock of Subsidiaries
|
252
|
252
|
|||||
|
Preferred
Stock
|
|||||||
|
Preferred
stock, no par value, 80,000,000 shares, $100 par value, 5,000,000
shares,
none issued
|
-
|
-
|
|||||
|
Common
Shareholders' Equity
|
|||||||
|
Common
stock, no par value, authorized 800,000,000 shares, issued 372,803,521
common and 1,377,538 restricted shares in 2006 and issued 366,868,512
common and 1,399,990 restricted shares in 2005
|
5,877
|
5,827
|
|||||
|
Common
stock held by subsidiary, at cost, 24,665,500 shares
|
(718
|
)
|
(718
|
)
|
|||
|
Unearned
compensation
|
-
|
(22
|
)
|
||||
|
Reinvested
earnings
|
2,671
|
2,139
|
|||||
|
Accumulated
other comprehensive loss
|
(19
|
)
|
(8
|
)
|
|||
|
Total
common shareholders' equity
|
7,811
|
7,218
|
|||||
|
TOTAL
LIABILITIES AND SHAREHOLDERS' EQUITY
|
$
|
34,803
|
$
|
34,074
|
|||
|
|
Year
ended December 31,
|
|||||||||
|
|
2006
|
2005
|
2004
|
|||||||
|
Cash
Flows From Operating Activities
|
||||||||||
|
Net
income
|
$
|
991
|
$
|
917
|
$
|
4,504
|
||||
|
Gain
on disposal of NEGT (net of income tax benefit of $13 million in
2005 and
income tax expense of $374 million in 2004)
|
-
|
(13
|
)
|
(684
|
)
|
|||||
|
Net
income from continuing operations
|
991
|
904
|
3,820
|
|||||||
|
Adjustments
to reconcile net income to net cash provided by operating activities:
|
||||||||||
|
Depreciation,
amortization, decommissioning and allowance for equity funds used
during
construction
|
1,756
|
1,698
|
1,497
|
|||||||
|
Loss
from retirement of long-term debt
|
-
|
-
|
65
|
|||||||
|
Tax
benefit from employee stock plans
|
-
|
50
|
41
|
|||||||
|
Gain
on sale of assets
|
(11
|
)
|
-
|
(19
|
)
|
|||||
|
Recognition
of regulatory assets
|
-
|
-
|
(4,900
|
)
|
||||||
|
Deferred
income taxes and tax credits, net
|
(285
|
)
|
(659
|
)
|
2,607
|
|||||
|
Other
deferred charges and noncurrent liabilities
|
151
|
33
|
(519
|
)
|
||||||
|
Net
effect of changes in operating assets and liabilities:
|
||||||||||
|
Accounts
receivable
|
130
|
(245
|
)
|
(85
|
)
|
|||||
|
Inventories
|
32
|
(60
|
)
|
(12
|
)
|
|||||
|
Accounts
payable
|
17
|
257
|
273
|
|||||||
|
Accrued
taxes/income taxes receivable
|
124
|
(207
|
)
|
(122
|
)
|
|||||
|
Regulatory
balancing accounts, net
|
329
|
254
|
(590
|
)
|
||||||
|
Other
current assets
|
(273
|
)
|
29
|
760
|
||||||
|
Other
current liabilities
|
(233
|
)
|
273
|
(48
|
)
|
|||||
|
Payments
authorized by the Bankruptcy Court on amounts classified as liabilities
subject to compromise
|
-
|
-
|
(1,022
|
)
|
||||||
|
Other
|
(14
|
)
|
82
|
110
|
||||||
|
Net
cash provided by operating activities
|
2,714
|
2,409
|
1,856
|
|||||||
|
Cash
Flows From Investing Activities
|
||||||||||
|
Capital
expenditures
|
(2,402
|
)
|
(1,804
|
)
|
(1,559
|
)
|
||||
|
Net
proceeds from sale of assets
|
17
|
39
|
35
|
|||||||
|
Decrease
(increase) in restricted cash
|
115
|
434
|
(1,216
|
)
|
||||||
|
Proceeds from
nuclear decommissioning trust sales
|
1,087
|
2,918
|
1,821
|
|||||||
|
Purchases
of nuclear decommissioning trust investments
|
(1,244
|
)
|
(3,008
|
)
|
(1,972
|
)
|
||||
|
Other
|
-
|
23
|
(27
|
)
|
||||||
|
Net
cash used in investing activities
|
(2,427
|
)
|
(1,398
|
)
|
(2,918
|
)
|
||||
|
Cash
Flows From Financing Activities
|
||||||||||
|
Borrowings
under accounts receivable facility and working capital
facility
|
350
|
260
|
300
|
|||||||
|
Repayments
under accounts receivable facility and working capital
facility
|
(310
|
)
|
(300
|
)
|
-
|
|||||
|
Net
issuance of commercial paper, net of discount of $2
million
|
458
|
-
|
-
|
|||||||
|
Proceeds
from issuance of long-term debt, net of issuance costs of $3 million
in
2005 and $107 million in 2004
|
-
|
451
|
7,742
|
|||||||
|
Proceeds
from issuance of energy recovery bonds, net of issuance costs of
$21
million in 2005
|
-
|
2,711
|
-
|
|||||||
|
Long-term
debt matured, redeemed or repurchased
|
-
|
(1,556
|
)
|
(9,054
|
)
|
|||||
|
Rate
reduction bonds matured
|
(290
|
)
|
(290
|
)
|
(290
|
)
|
||||
|
Energy
recovery bonds matured
|
(316
|
)
|
(140
|
)
|
-
|
|||||
|
Preferred
stock with mandatory redemption provisions redeemed
|
-
|
(122
|
)
|
(15
|
)
|
|||||
|
Preferred
stock without mandatory redemption provisions redeemed
|
-
|
(37
|
)
|
-
|
||||||
|
Common
stock issued
|
131
|
243
|
162
|
|||||||
|
Common
stock repurchased
|
(114
|
)
|
(2,188
|
)
|
(378
|
)
|
||||
|
Common
stock dividends paid
|
(456
|
)
|
(334
|
)
|
-
|
|||||
|
Other
|
3
|
32
|
(91
|
)
|
||||||
|
Net
cash used in financing activities
|
(544
|
)
|
(1,270
|
)
|
(1,624
|
)
|
||||
|
Net
change in cash and cash equivalents
|
(257
|
)
|
(259
|
)
|
(2,686
|
)
|
||||
|
Cash
and cash equivalents at January 1
|
713
|
972
|
3,658
|
|||||||
|
|
||||||||||
|
Cash
and cash equivalents at December 31
|
$
|
456
|
$
|
713
|
$
|
972
|
||||
|
Supplemental
disclosures of cash flow information
|
||||||||||
|
Cash
received for:
|
||||||||||
|
Reorganization
interest income
|
$
|
-
|
$
|
-
|
$
|
16
|
||||
|
Cash
paid for:
|
||||||||||
|
Interest
(net of amounts capitalized)
|
503
|
403
|
646
|
|||||||
|
Income
taxes paid, net
|
736
|
1,392
|
128
|
|||||||
|
Reorganization
professional fees and expenses
|
-
|
-
|
61
|
|||||||
|
Supplemental
disclosures of noncash investing and financing
activities
|
||||||||||
|
Common
stock dividends declared but not yet paid
|
$
|
117
|
$
|
115
|
$
|
-
|
||||
|
Transfer
of liabilities and other payables subject to compromise to operating
assets and liabilities
|
-
|
-
|
(2,877
|
)
|
||||||
|
Assumption
of capital lease obligation
|
408
|
-
|
-
|
|||||||
|
Transfer
of Gateway Generating Station asset
|
69
|
-
|
-
|
|
Common
Stock Shares
|
Common
Stock Amount
|
Common
Stock Held by
Subsidiary
|
Unearned
Compen-sation
|
Reinvested
Earnings (Accumulated Deficit)
|
Accumulated
Other Comprehensive Income (Loss)
|
Total
Common Share-holders' Equity
|
Comprehensive
Income (Loss)
|
||||||||||||||||||
|
Balance
at December 31, 2003
|
416,520,282
|
$
|
6,468
|
$
|
(690
|
)
|
$
|
(20
|
)
|
$
|
(1,458
|
)
|
$
|
(85
|
)
|
$
|
4,215
|
||||||||
|
Net
income
|
-
|
-
|
-
|
-
|
4,504
|
-
|
4,504
|
$
|
4,504
|
||||||||||||||||
|
Mark-to-market
adjustments for hedging transactions in accordance with SFAS No.
133 (net
of income tax expense of $2 million)
|
-
|
-
|
-
|
-
|
-
|
3
|
3
|
3
|
|||||||||||||||||
|
NEGT
losses reclassified to earnings upon elimination of equity interest
by
PG&E Corporation (net of income tax expense of $43
million)
|
-
|
-
|
-
|
-
|
-
|
77
|
77
|
77
|
|||||||||||||||||
|
Other
|
-
|
-
|
-
|
-
|
-
|
1
|
1
|
1
|
|||||||||||||||||
|
Comprehensive
income
|
$
|
4,585
|
|||||||||||||||||||||||
|
Common
stock issued
|
8,410,058
|
162
|
-
|
-
|
-
|
-
|
162
|
||||||||||||||||||
|
Common
stock repurchased
|
(10,783,200
|
)
|
(167
|
)
|
-
|
-
|
(183
|
)
|
-
|
(350
|
)
|
||||||||||||||
|
Common
stock held by subsidiary
|
-
|
-
|
(28
|
)
|
-
|
-
|
-
|
(28
|
)
|
||||||||||||||||
|
Common
stock warrants exercised
|
4,003,812
|
-
|
-
|
-
|
-
|
-
|
-
|
||||||||||||||||||
|
Common
restricted stock issued
|
498,910
|
16
|
-
|
(16
|
)
|
-
|
-
|
-
|
|||||||||||||||||
|
Common
restricted stock cancelled
|
(33,721
|
)
|
(1
|
)
|
-
|
1
|
-
|
-
|
-
|
||||||||||||||||
|
Common
restricted stock amortization
|
-
|
-
|
-
|
9
|
-
|
-
|
9
|
||||||||||||||||||
|
Tax
benefit from employee stock plans
|
-
|
41
|
-
|
-
|
-
|
-
|
41
|
||||||||||||||||||
|
Other
|
-
|
(1
|
)
|
-
|
-
|
-
|
-
|
(1
|
)
|
||||||||||||||||
|
Balance
at December 31, 2004
|
418,616,141
|
6,518
|
(718
|
)
|
(26
|
)
|
2,863
|
(4
|
)
|
8,633
|
|||||||||||||||
|
Net
income
|
-
|
-
|
-
|
-
|
917
|
-
|
917
|
917
|
|||||||||||||||||
|
Minimum
pension liability adjustment (net of income tax benefit of $3
million)
|
-
|
-
|
-
|
-
|
-
|
(4
|
)
|
(4
|
)
|
(4
|
)
|
||||||||||||||
|
Comprehensive
income
|
$
|
913
|
|||||||||||||||||||||||
|
Common
stock issued
|
10,264,535
|
247
|
-
|
-
|
-
|
-
|
247
|
||||||||||||||||||
|
Common
stock repurchased
|
(61,139,700
|
)
|
(998
|
)
|
-
|
-
|
(1,190
|
)
|
-
|
(2,188
|
)
|
||||||||||||||
|
Common
stock warrants exercised
|
295,919
|
-
|
-
|
-
|
-
|
-
|
-
|
||||||||||||||||||
|
Common
restricted stock issued
|
347,710
|
13
|
-
|
(13
|
)
|
-
|
-
|
-
|
|||||||||||||||||
|
Common
restricted stock cancelled
|
(116,103
|
)
|
(4
|
)
|
-
|
4
|
-
|
-
|
-
|
||||||||||||||||
|
Common
restricted stock amortization
|
-
|
-
|
-
|
13
|
-
|
-
|
13
|
||||||||||||||||||
|
Common
stock dividends declared and paid
|
-
|
-
|
-
|
-
|
(334
|
)
|
-
|
(334
|
)
|
||||||||||||||||
|
Common
stock dividends declared but not yet paid
|
-
|
-
|
-
|
-
|
(115
|
)
|
-
|
(115
|
)
|
||||||||||||||||
|
Tax
benefit from employee stock plans
|
-
|
50
|
-
|
-
|
-
|
-
|
50
|
||||||||||||||||||
|
Other
|
-
|
1
|
-
|
-
|
(2
|
)
|
-
|
(1
|
)
|
||||||||||||||||
|
Balance
at December 31, 2005
|
368,268,502
|
5,827
|
(718
|
)
|
(22
|
)
|
2,139
|
(8
|
)
|
7,218
|
|||||||||||||||
|
Net
income
|
-
|
-
|
-
|
-
|
991
|
-
|
991
|
$
|
991
|
||||||||||||||||
|
Comprehensive
income
|
$
|
991
|
|||||||||||||||||||||||
|
|
|||||||||||||||||||||||||
|
Common
stock issued
|
5,399,707
|
110
|
-
|
-
|
-
|
-
|
110
|
||||||||||||||||||
|
ASR
settlement of stock repurchased in 2005
|
-
|
(114
|
)
|
-
|
-
|
-
|
-
|
(114
|
)
|
||||||||||||||||
|
Common
stock warrants exercised
|
51,890
|
-
|
-
|
-
|
-
|
-
|
-
|
||||||||||||||||||
|
Common
restricted stock, unearned compensation reversed in accordance
with SFAS
No. 123R
|
-
|
(22
|
)
|
-
|
22
|
-
|
-
|
-
|
|||||||||||||||||
|
Common
restricted stock issued
|
566,255
|
21
|
-
|
-
|
-
|
-
|
21
|
||||||||||||||||||
|
Common
restricted stock cancelled
|
(105,295
|
)
|
(1
|
)
|
-
|
-
|
-
|
-
|
(1
|
)
|
|||||||||||||||
|
Common
restricted stock amortization
|
-
|
20
|
-
|
-
|
-
|
-
|
20
|
||||||||||||||||||
|
Common
stock dividends declared and paid
|
-
|
-
|
-
|
-
|
(342
|
)
|
-
|
(342
|
)
|
||||||||||||||||
|
Common
stock dividends declared but not yet paid
|
-
|
-
|
-
|
-
|
(117
|
)
|
-
|
(117
|
)
|
||||||||||||||||
|
Tax
benefit from employee stock plans
|
-
|
35
|
-
|
-
|
-
|
-
|
35
|
||||||||||||||||||
|
Adoption
of SFAS No. 158 (net of income tax benefit of $8 million)
|
-
|
-
|
-
|
-
|
-
|
(11
|
)
|
(11
|
)
|
||||||||||||||||
|
Other
|
-
|
1
|
-
|
-
|
-
|
-
|
1
|
||||||||||||||||||
|
Balance
at December 31, 2006
|
374,181,059
|
$
|
5,877
|
$
|
(718
|
)
|
$
|
-
|
$
|
2,671
|
$
|
(19
|
)
|
$
|
7,811
|
|
|
Year
ended December 31,
|
|||||||||
|
|
2006
|
2005
|
2004
|
|||||||
|
Operating
Revenues
|
||||||||||
|
Electric
|
$
|
8,752
|
$
|
7,927
|
$
|
7,867
|
||||
|
Natural
gas
|
3,787
|
3,777
|
3,213
|
|||||||
|
Total
operating revenues
|
12,539
|
11,704
|
11,080
|
|||||||
|
Operating
Expenses
|
||||||||||
|
Cost
of electricity
|
2,922
|
2,410
|
2,770
|
|||||||
|
Cost
of natural gas
|
2,097
|
2,191
|
1,724
|
|||||||
|
Operating
and maintenance
|
3,697
|
3,399
|
2,848
|
|||||||
|
Recognition
of regulatory assets
|
-
|
-
|
(4,900
|
)
|
||||||
|
Depreciation,
amortization and decommissioning
|
1,708
|
1,734
|
1,494
|
|||||||
|
Total
operating expenses
|
10,424
|
9,734
|
3,936
|
|||||||
|
Operating
Income
|
2,115
|
1,970
|
7,144
|
|||||||
|
Interest
income
|
175
|
76
|
50
|
|||||||
|
Interest
expense
|
(710
|
)
|
(554
|
)
|
(667
|
)
|
||||
|
Other
income, net
|
7
|
16
|
16
|
|||||||
|
Income
Before Income Taxes
|
1,587
|
1,508
|
6,543
|
|||||||
|
Income
tax provision
|
602
|
574
|
2,561
|
|||||||
|
Net
Income
|
985
|
934
|
3,982
|
|||||||
|
Preferred
stock dividend requirement
|
14
|
16
|
21
|
|||||||
|
Income
Available for Common Stock
|
$
|
971
|
$
|
918
|
$
|
3,961
|
||||
|
|
Balance
at December 31,
|
||||||
|
|
2006
|
2005
|
|||||
|
ASSETS
|
|||||||
|
Current
Assets
|
|||||||
|
Cash
and cash equivalents
|
$
|
70
|
$
|
463
|
|||
|
Restricted
cash
|
1,415
|
1,546
|
|||||
|
Accounts
receivable:
|
|||||||
|
Customers
(net of allowance for doubtful accounts of $50 million in 2006
and $77
million in 2005)
|
2,343
|
2,422
|
|||||
|
Related
parties
|
6
|
3
|
|||||
|
Regulatory
balancing accounts
|
607
|
727
|
|||||
|
Inventories:
|
|||||||
|
Gas
stored underground and fuel oil
|
181
|
231
|
|||||
|
Materials
and supplies
|
149
|
133
|
|||||
|
Income
taxes receivable
|
20
|
48
|
|||||
|
Prepaid
expenses and other
|
714
|
183
|
|||||
|
Total
current assets
|
5,505
|
5,756
|
|||||
|
Property,
Plant and Equipment
|
|||||||
|
Electric
|
24,036
|
22,482
|
|||||
|
Gas
|
9,115
|
8,794
|
|||||
|
Construction
work in progress
|
1,047
|
738
|
|||||
|
Total
property, plant and equipment
|
34,198
|
32,014
|
|||||
|
Accumulated
depreciation
|
(12,415
|
)
|
(12,061
|
)
|
|||
|
Net
property, plant and equipment
|
21,783
|
19,953
|
|||||
|
Other
Noncurrent Assets
|
|||||||
|
Regulatory
assets
|
4,902
|
5,578
|
|||||
|
Nuclear
decommissioning funds
|
1,876
|
1,719
|
|||||
|
Related
parties receivable
|
25
|
23
|
|||||
|
Other
|
280
|
754
|
|||||
|
Total
other noncurrent assets
|
7,083
|
8,074
|
|||||
|
TOTAL
ASSETS
|
$
|
34,371
|
$
|
33,783
|
|||
|
|
Balance
at December 31,
|
||||||
|
|
2006
|
2005
|
|||||
|
LIABILITIES
AND SHAREHOLDERS' EQUITY
|
|||||||
|
Current
Liabilities
|
|||||||
|
Short-term
borrowings
|
$
|
759
|
$
|
260
|
|||
|
Long-term
debt, classified as current
|
1
|
2
|
|||||
|
Rate
reduction bonds, classified as current
|
290
|
290
|
|||||
|
Energy
recovery bonds, classified as current
|
340
|
316
|
|||||
|
Accounts
payable:
|
|||||||
|
Trade
creditors
|
1,075
|
980
|
|||||
|
Disputed
claims and customer refunds
|
1,709
|
1,733
|
|||||
|
Related
parties
|
40
|
37
|
|||||
|
Regulatory
balancing accounts
|
1,030
|
840
|
|||||
|
Other
|
402
|
423
|
|||||
|
Interest
payable
|
570
|
460
|
|||||
|
Deferred
income taxes
|
118
|
161
|
|||||
|
Other
|
1,346
|
1,255
|
|||||
|
Total
current liabilities
|
7,680
|
6,757
|
|||||
|
Noncurrent
Liabilities
|
|||||||
|
Long-term
debt
|
6,697
|
6,696
|
|||||
|
Rate
reduction bonds
|
-
|
290
|
|||||
|
Energy
recovery bonds
|
1,936
|
2,276
|
|||||
|
Regulatory
liabilities
|
3,392
|
3,506
|
|||||
|
Asset
retirement obligations
|
1,466
|
1,587
|
|||||
|
Deferred
income taxes
|
2,972
|
3,218
|
|||||
|
Deferred
tax credits
|
106
|
112
|
|||||
|
Other
|
1,922
|
1,691
|
|||||
|
Total
noncurrent liabilities
|
18,491
|
19,376
|
|||||
|
Commitments
and Contingencies (Notes 2, 4, 5, 6, 8, 9, 13, 15 and
17)
|
|||||||
|
Shareholders'
Equity
|
|||||||
|
Preferred
stock without mandatory redemption provisions:
|
|||||||
|
Nonredeemable,
5.00% to 6.00%, outstanding 5,784,825 shares
|
145
|
145
|
|||||
|
Redeemable,
4.36% to 5.00%, outstanding 4,534,958 shares
|
113
|
113
|
|||||
|
Common
stock, $5 par value, authorized 800,000,000 shares, issued 279,624,823
shares in 2006 and 2005
|
1,398
|
1,398
|
|||||
|
Common
stock held by subsidiary, at cost, 19,481,213 shares
|
(475
|
)
|
(475
|
)
|
|||
|
Additional
paid-in capital
|
1,822
|
1,776
|
|||||
|
Reinvested
earnings
|
5,213
|
4,702
|
|||||
|
Accumulated
other comprehensive loss
|
(16
|
)
|
(9
|
)
|
|||
|
Total
shareholders' equity
|
8,200
|
7,650
|
|||||
|
TOTAL
LIABILITIES AND SHAREHOLDERS' EQUITY
|
$
|
34,371
|
$
|
33,783
|
|||
|
|
Year
ended December 31,
|
|||||||||
|
|
2006
|
2005
|
2004
|
|||||||
|
Cash
Flows From Operating Activities
|
||||||||||
|
Net
income
|
$
|
985
|
$
|
934
|
$
|
3,982
|
||||
|
Adjustments
to reconcile net income to net cash provided by operating activities:
|
||||||||||
|
Depreciation,
amortization, decommissioning and allowance for equity funds used
during
construction
|
1,755
|
1,697
|
1,494
|
|||||||
|
Gain
on sale of assets
|
(11
|
)
|
-
|
-
|
||||||
|
Recognition
of regulatory assets
|
-
|
-
|
(4,900
|
)
|
||||||
|
Deferred
income taxes and tax credits, net
|
(287
|
)
|
(636
|
)
|
2,580
|
|||||
|
Other
deferred charges and noncurrent liabilities
|
116
|
21
|
(391
|
)
|
||||||
|
Net
effect of changes in operating assets and liabilities:
|
||||||||||
|
Accounts
receivable
|
128
|
(245
|
)
|
(85
|
)
|
|||||
|
Inventories
|
34
|
(60
|
)
|
(12
|
)
|
|||||
|
Accounts
payable
|
21
|
257
|
273
|
|||||||
|
Accrued
taxes/income taxes receivable
|
28
|
(150
|
)
|
52
|
||||||
|
Regulatory
balancing accounts, net
|
329
|
254
|
(590
|
)
|
||||||
|
Other
current assets
|
(273
|
)
|
2
|
55
|
||||||
|
Other
current liabilities
|
(235
|
)
|
273
|
395
|
||||||
|
Payments
authorized by the Bankruptcy Court on amounts classified as liabilities
subject to compromise
|
-
|
-
|
(1,022
|
)
|
||||||
|
Other
|
(13
|
)
|
19
|
7
|
||||||
|
Net
cash provided by operating activities
|
2,577
|
2,366
|
1,838
|
|||||||
|
Cash
Flows From Investing Activities
|
||||||||||
|
Capital
expenditures
|
(2,402
|
)
|
(1,803
|
)
|
(1,559
|
)
|
||||
|
Net
proceeds from sale of assets
|
17
|
39
|
35
|
|||||||
|
Decrease
(increase) in restricted cash
|
115
|
434
|
(1,577
|
)
|
||||||
|
Proceeds from
nuclear decommissioning trust sales
|
1,087
|
2,918
|
1,821
|
|||||||
|
Purchases of
nuclear decommissioning trust investments
|
(1,244
|
)
|
(3,008
|
)
|
(1,972
|
)
|
||||
|
Other
|
1
|
61
|
(27
|
)
|
||||||
|
Net
cash used in investing activities
|
(2,426
|
)
|
(1,359
|
)
|
(3,279
|
)
|
||||
|
Cash
Flows From Financing Activities
|
||||||||||
|
Borrowings
under accounts receivable facility and working capital
facility
|
350
|
260
|
300
|
|||||||
|
Repayments
under accounts receivable facility and working capital
facility
|
(310
|
)
|
(300
|
)
|
-
|
|||||
|
Net
issuance of commercial paper, net of discount of $2
million
|
458
|
-
|
-
|
|||||||
|
Proceeds
from issuance of long-term debt, net of issuance costs of $3 million
in
2005 and $107 million in 2004
|
-
|
451
|
7,742
|
|||||||
|
Proceeds
from issuance of energy recovery bonds, net of issuance costs of
$21
million in 2005
|
-
|
2,711
|
-
|
|||||||
|
Long-term
debt matured, redeemed or repurchased
|
-
|
(1,554
|
)
|
(8,402
|
)
|
|||||
|
Rate
reduction bonds matured
|
(290
|
)
|
(290
|
)
|
(290
|
)
|
||||
|
Energy
recovery bonds matured
|
(316
|
)
|
(140
|
)
|
-
|
|||||
|
Preferred
stock dividends paid
|
(14
|
)
|
(16
|
)
|
(90
|
)
|
||||
|
Common
stock dividends paid
|
(460
|
)
|
(445
|
)
|
-
|
|||||
|
Preferred
stock with mandatory redemption provisions redeemed
|
-
|
(122
|
)
|
(15
|
)
|
|||||
|
Preferred
stock without mandatory redemption provisions redeemed
|
-
|
(37
|
)
|
-
|
||||||
|
Common
stock repurchased
|
-
|
(1,910
|
)
|
-
|
||||||
|
Other
|
38
|
65
|
-
|
|||||||
|
Net
cash used in financing activities
|
(544
|
)
|
(1,327
|
)
|
(755
|
)
|
||||
|
Net
change in cash and cash equivalents
|
(393
|
)
|
(320
|
)
|
(2,196
|
)
|
||||
|
Cash
and cash equivalents at January 1
|
463
|
783
|
2,979
|
|||||||
|
Cash
and cash equivalents at December 31
|
$
|
70
|
$
|
463
|
$
|
783
|
||||
|
Supplemental
disclosures of cash flow information
|
||||||||||
|
Cash
received for:
|
||||||||||
|
Reorganization
interest income
|
$
|
-
|
$
|
-
|
$
|
16
|
||||
|
Cash
paid for:
|
||||||||||
|
Interest
(net of amounts capitalized)
|
476
|
390
|
512
|
|||||||
|
Income
taxes paid, net
|
897
|
1,397
|
109
|
|||||||
|
Reorganization
professional fees and expenses
|
-
|
-
|
61
|
|||||||
|
Supplemental
disclosures of noncash investing and financing
activities
|
||||||||||
|
Transfer
of liabilities and other payables subject to compromise to operating
assets and liabilities
|
$
|
-
|
$
|
-
|
$
|
(2,877
|
)
|
|||
|
Equity
contribution for settlement of plan of reorganization, or POR,
payable
|
-
|
-
|
(129
|
)
|
||||||
|
Assumption
of capital lease obligation
|
408
|
-
|
-
|
|||||||
|
Transfer
of Gateway Generating Station asset
|
69
|
-
|
-
|
|
Preferred
Stock Without Mandatory Redemption Provisions
|
Common
Stock
|
Additional
Paid-in Capital
|
Common
Stock Held by Subsidiary
|
Reinvested
Earnings
|
Accumu-
lated Other Compre- hensive Income (Loss)
|
Total
Share- holders' Equity
|
Comprehensive
Income (Loss)
|
||||||||||||||||||
|
Balance
at December 31, 2003
|
$
|
294
|
$
|
1,606
|
$
|
1,964
|
$
|
(475
|
)
|
$
|
1,706
|
$
|
(6
|
)
|
$
|
5,089
|
|||||||||
|
Net
income
|
-
|
-
|
-
|
-
|
3,982
|
-
|
3,982
|
$
|
3,982
|
||||||||||||||||
|
Mark-to-market
adjustments for hedging transactions in accordance with SFAS No.
133 (net
of income tax expense of $2 million)
|
-
|
-
|
-
|
-
|
-
|
3
|
3
|
3
|
|||||||||||||||||
|
Comprehensive
income
|
$
|
3,985
|
|||||||||||||||||||||||
|
|
|||||||||||||||||||||||||
|
Equity
contribution for settlement of POR payable (net of income taxes
of $52
million)
|
-
|
-
|
77
|
-
|
-
|
-
|
77
|
||||||||||||||||||
|
Preferred
stock dividend
|
-
|
-
|
-
|
-
|
(21
|
)
|
-
|
(21
|
)
|
||||||||||||||||
|
Balance
at December 31, 2004
|
294
|
1,606
|
2,041
|
(475
|
)
|
5,667
|
(3
|
)
|
9,130
|
||||||||||||||||
|
Net
income
|
-
|
-
|
-
|
-
|
934
|
-
|
934
|
$
|
934
|
||||||||||||||||
|
Minimum
pension liability adjustment (net of income tax benefit of $4
million)
|
-
|
-
|
-
|
-
|
-
|
(6
|
)
|
(6
|
)
|
(6
|
)
|
||||||||||||||
|
Comprehensive
income
|
$
|
928
|
|||||||||||||||||||||||
|
|
|||||||||||||||||||||||||
|
Common
stock repurchased
|
-
|
(208
|
)
|
(266
|
)
|
-
|
(1,436
|
)
|
-
|
(1,910
|
)
|
||||||||||||||
|
Common
stock dividend
|
-
|
-
|
-
|
-
|
(445
|
)
|
-
|
(445
|
)
|
||||||||||||||||
|
Preferred
stock redeemed
|
(36
|
)
|
-
|
1
|
-
|
(2
|
)
|
-
|
(37
|
)
|
|||||||||||||||
|
Preferred
stock dividend
|
-
|
-
|
-
|
-
|
(16
|
)
|
-
|
(16
|
)
|
||||||||||||||||
|
Balance
at December 31, 2005
|
258
|
1,398
|
1,776
|
(475
|
)
|
4,702
|
(9
|
)
|
7,650
|
||||||||||||||||
|
Net
income
|
-
|
-
|
-
|
-
|
985
|
-
|
985
|
$
|
985
|
||||||||||||||||
|
Minimum
pension liability adjustment (net of income tax expense of $2
million)
|
-
|
-
|
-
|
-
|
-
|
3
|
3
|
3
|
|||||||||||||||||
|
Comprehensive
income
|
$
|
988
|
|||||||||||||||||||||||
|
|
|||||||||||||||||||||||||
|
Tax
benefit from employee stock plans
|
-
|
-
|
46
|
-
|
-
|
-
|
46
|
|||||||||||||||
|
Common
stock dividend
|
-
|
-
|
-
|
-
|
(460
|
)
|
-
|
(460
|
)
|
|||||||||||||
|
Preferred
stock dividend
|
-
|
-
|
-
|
-
|
(14
|
)
|
-
|
(14
|
)
|
|||||||||||||
|
Adoption
of SFAS No. 158 (net of income tax benefit of $7 million)
|
-
|
-
|
-
|
-
|
-
|
(10
|
)
|
(10
|
)
|
|||||||||||||
|
Balance
at December 31, 2006
|
$
|
258
|
$
|
1,398
|
$
|
1,822
|
$
|
(475
|
)
|
$
|
5,213
|
$
|
(16
|
)
|
$
|
8,200
|
|
·
|
Labor
and materials;
|
|
·
|
Construction
overhead; and
|
|
·
|
Allowance
for funds used during construction, or AFUDC.
|
|
(in
millions)
|
Gross
Plant
As
of December 31, 2006
|
Estimated
Useful Lives
|
|||||
|
Electricity
generating facilities
|
$
|
2,068
|
15
to 44 years
|
||||
|
Electricity
distribution facilities
|
15,305
|
16
to 58 years
|
|||||
|
Electricity
transmission
|
4,397
|
40
to 70 years
|
|||||
|
Natural
gas distribution facilities
|
5,028
|
23
to 54 years
|
|||||
|
Natural
gas transportation
|
3,016
|
25
to 45 years
|
|||||
|
Natural
gas storage
|
48
|
25
to 48 years
|
|||||
|
Other
|
3,289
|
5
to 40 years
|
|||||
|
Total
|
$
|
33,151
|
|||||
|
(in
millions)
|
||||
|
ARO
liability at December 31, 2004
|
$
|
1,301
|
||
|
Recognition
of FIN 47 obligation
|
203
|
|||
|
Accretion
expense
|
85
|
|||
|
Liabilities
settled
|
(2
|
)
|
||
|
ARO
liability at December 31, 2005
|
1,587
|
|||
|
Revision
in estimated cash flows
|
(204
|
)
|
||
|
Accretion
expense
|
98
|
|||
|
Liabilities
settled
|
(15
|
)
|
||
|
ARO
liability at December 31, 2006
|
$
|
1,466
|
|
·
|
The
fair values of cash and cash equivalents, restricted cash and deposits,
net accounts receivable, price risk management assets and liabilities,
short-term borrowings, accounts payable, customer deposits and
the
Utility's variable rate pollution control bond loan agreements
approximate
their carrying values as of December 31, 2006 and 2005;
and
|
|
|
|
|
·
|
The
fair values of the Utility’s fixed rate senior notes and fixed rate
pollution control bond loan agreements, PG&E Funding, LLC’s rate
reduction bonds, PG&E Energy Recovery Funding, LLC’s energy recovery
bonds, or ERBs, and PG&E Corporation’s 9.50% Convertible Subordinated
Notes, were based on quoted market prices obtained from the Bloomberg
financial information system at December 31,
2006.
|
|
|
At
December 31,
|
||||||||||||
|
|
2006
|
2005
|
|||||||||||
|
|
Carrying
Amount
|
Fair
Value
|
Carrying
Amount
|
Fair
Value
|
|||||||||
|
(in
millions)
|
|||||||||||||
|
Debt
(Note 4):
|
|||||||||||||
|
PG&E
Corporation
|
$
|
280
|
$
|
937
|
$
|
280
|
$
|
783
|
|||||
|
Utility
|
5,629
|
5,616
|
5,628
|
5,720
|
|||||||||
|
Rate
reduction bonds (Note 5)
|
290
|
292
|
580
|
591
|
|||||||||
|
Energy
recovery bonds (Note 6)
|
2,276
|
2,239
|
2,592
|
2,558
|
|||||||||
|
Hedging
Transactions in Accordance with SFAS No. 133
|
Foreign
Currency Translation Adjustment
|
Minimum
Pension Liability Adjustment
|
Adoption
of SFAS No. 158
|
Other
|
Accumulated
Other Comprehensive Income (Loss)
|
||||||||||||||
|
Balance
at
December
31, 2003
|
$
|
(81
|
)
|
$
|
-
|
$
|
(4
|
)
|
$
|
-
|
$
|
-
|
$
|
(85
|
)
|
||||
|
Period
change in:
|
|||||||||||||||||||
|
Mark-to-market
adjustments for hedging transactions in accordance with SFAS No.
133
|
3
|
-
|
-
|
-
|
-
|
3
|
|||||||||||||
|
NEGT
losses reclassified to earnings upon elimination of equity interest
by
PG&E Corporation
|
77
|
-
|
-
|
-
|
-
|
77
|
|||||||||||||
|
Other
|
-
|
-
|
-
|
-
|
1
|
1
|
|||||||||||||
|
Balance
at
December
31, 2004
|
(1
|
)
|
-
|
(4
|
)
|
-
|
1
|
(4
|
)
|
||||||||||
|
Period
change in:
|
|||||||||||||||||||
|
Minimum
pension liability adjustment
|
-
|
-
|
(4
|
)
|
-
|
-
|
(4
|
)
|
|||||||||||
|
Other
|
1
|
-
|
-
|
-
|
(1
|
)
|
-
|
||||||||||||
|
Balance
at
December
31, 2005
|
-
|
-
|
(8
|
)
|
-
|
-
|
(8
|
)
|
|||||||||||
|
Period
change in:
|
|||||||||||||||||||
|
Adoption
of SFAS No. 158
|
-
|
-
|
8
|
(19
|
)
|
-
|
(11
|
)
|
|||||||||||
|
Balance
at
December
31, 2006
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
(19
|
)
|
$
|
-
|
$
|
(19
|
)
|
|
PG&E
Corporation
|
Utility
|
||||||
|
Year
Ended December 31,
|
Year
Ended December 31,
|
||||||
|
(in
millions except per share amounts)
|
2006
|
2006
|
|||||
|
Operating
Income
|
$
|
(18
|
)
|
$
|
(13
|
)
|
|
|
Income
Before Income Taxes
|
(18
|
)
|
(13
|
)
|
|||
|
Net
Income
|
(11
|
)
|
(8
|
)
|
|||
|
Earnings
Per Common Share, Basic
|
$
|
(0.04
|
)
|
||||
|
Earnings
Per Common Share, Diluted
|
$
|
(0.04
|
)
|
||||
|
|
Year
ended December 31,
|
||||||
|
|
2005
|
2004
|
|||||
|
(in
millions, except per share amounts)
|
|
|
|||||
|
Net
earnings:
|
|||||||
|
As
reported
|
$
|
917
|
$
|
4,504
|
|||
|
Deduct:
Incremental stock-based employee compensation expense determined
under the
fair value based method for all awards, net of related tax
effects
|
(12
|
)
|
(14
|
)
|
|||
|
Pro
forma
|
$
|
905
|
$
|
4,490
|
|||
|
Basic
earnings per share:
|
|||||||
|
As
reported
|
$
|
2.40
|
$
|
10.80
|
|||
|
Pro
forma
|
2.37
|
10.77
|
|||||
|
Diluted
earnings per share:
|
|||||||
|
As
reported
|
2.37
|
10.57
|
|||||
|
Pro
forma
|
2.33
|
10.59
|
|||||
|
Year
ended December 31,
|
|||||||
|
2005
|
2004
|
||||||
|
(in
millions)
|
|||||||
|
Net
earnings:
|
|||||||
|
As
reported
|
$
|
918
|
$
|
3,961
|
|||
|
Deduct:
Incremental stock-based employee compensation expense determined
under the
fair value based method for all awards, net of related tax
effects
|
(7
|
)
|
(8
|
)
|
|||
|
Pro
forma
|
$
|
911
|
$
|
3,953
|
|||
|
Balance
at December 31,
|
|||||||
|
2006
|
2005
|
||||||
|
(in
millions)
|
|
||||||
|
Energy
recovery bond regulatory asset
|
$
|
2,170
|
$
|
2,509
|
|||
|
Utility
retained generation regulatory assets
|
1,018
|
1,099
|
|||||
|
Regulatory
assets for deferred income tax
|
599
|
536
|
|||||
|
Environmental
compliance costs
|
303
|
310
|
|||||
|
Unamortized
loss, net of gain, on reacquired debt
|
295
|
321
|
|||||
|
Regulatory
assets associated with plan of reorganization
|
147
|
163
|
|||||
|
Post-transition
period contract termination costs
|
120
|
131
|
|||||
|
Scheduling
coordinator costs
|
111
|
-
|
|||||
|
Rate
reduction bond regulatory asset
|
-
|
456
|
|||||
|
Other
|
139
|
53
|
|||||
|
Total
regulatory assets
|
$
|
4,902
|
$
|
5,578
|
|||
|
|
|
Balance
at December 31,
|
|
||||
|
|
|
2006
|
|
2005
|
|
||
|
(in
millions)
|
|
|
|
||||
|
Cost
of removal obligation
|
|
$
|
2,340
|
$
|
2,141
|
|
|
|
Asset
retirement costs
|
|
|
608
|
|
538
|
|
|
|
Public
purpose programs
|
169
|
154
|
|||||
|
Price
risk management
|
37
|
213
|
|||||
|
Employee
benefit plans
|
23
|
195
|
|||||
|
Rate
reduction bond regulatory liability
|
-
|
157
|
|||||
|
Other
|
|
|
215
|
|
108
|
|
|
|
Total
regulatory liabilities
|
|
$
|
3,392
|
$
|
3,506
|
|
|
|
|
Balance
at December 31,
|
||||||
|
|
2006
|
2005
|
|||||
|
(in
millions)
|
|
||||||
|
Electricity
revenue and cost balancing accounts
|
$
|
501
|
$
|
568
|
|||
|
Natural
gas revenue and cost balancing accounts
|
106
|
159
|
|||||
|
Total
|
$
|
607
|
$
|
727
|
|||
|
|
Balance
at December 31,
|
||||||
|
|
2006
|
2005
|
|||||
|
(in
millions)
|
|
||||||
|
Electricity
revenue and cost balancing accounts
|
$
|
951
|
$
|
827
|
|||
|
Natural
gas revenue and cost balancing accounts
|
79
|
13
|
|||||
|
Total
|
$
|
1,030
|
$
|
840
|
|||
|
|
December
31,
|
||||||
|
|
2006
|
2005
|
|||||
|
(in
millions)
|
|
||||||
|
PG&E
Corporation
|
|||||||
|
Convertible
subordinated notes, 9.50%, due 2010
|
$
|
280
|
$
|
280
|
|||
|
Less:
current portion
|
(280
|
)
|
-
|
||||
|
|
- |
280
|
|||||
|
Utility
|
|||||||
|
Senior
notes/first mortgage bonds(1):
|
|||||||
|
3.60%
to 6.05% bonds, due 2009-2034
|
5,100
|
5,100
|
|||||
|
Unamortized
discount, net of premium
|
(16
|
)
|
(17
|
)
|
|||
|
Total
senior notes/first mortgage bonds
|
5,084
|
5,083
|
|||||
|
Pollution
control bond loan agreements, variable rates(2),
due 2026(3)
|
614
|
614
|
|||||
|
Pollution
control bond loan agreement, 5.35%, due 2016
|
200
|
200
|
|||||
|
Pollution
control bond loan agreements, 3.50%, due 2023(4)
|
345
|
345
|
|||||
|
Pollution
control bond loan agreements, variable rates(5),
due 2016-2026
|
454
|
454
|
|||||
|
Other
|
1
|
2
|
|||||
|
Less:
current portion
|
(1
|
)
|
(2
|
)
|
|||
|
Long-term
debt, net of current portion
|
6,697
|
6,696
|
|||||
|
Total
consolidated long-term debt, net of current
portion
|
$
|
6,697
|
$
|
6,976
|
|||
|
(1) When
originally issued, these debt instruments were denominated as first
mortgage bonds and were secured by a lien, subject to permitted
exceptions, on substantially all of the Utility’s real property and
certain tangible personal property related to its facilities. The
indenture under which the first mortgage bonds were issued provided
for
release of the lien in certain circumstances subject to certain
conditions. The release occurred in April 2005 and the remaining
bonds
were redesignated as senior notes.
|
|||||||
|
(2) At
December 31, 2006, interest rates on these loans ranged from 3.80%
to
3.92%.
|
|||||||
|
(3) These
bonds are supported by $620 million of letters of credit which
expire on
April 22, 2010. Although the stated maturity date is 2026, the
bonds will
remain outstanding only if the Utility extends or replaces the
letters of
credit.
|
|||||||
|
(4) These
bonds are subject to a mandatory tender for purchase on June 1,
2007 and
the interest rates for these bonds are set until that date.
|
|||||||
|
(5) At
December 31, 2006, interest rates on these loans ranged from 3.25%
to
3.70%.
|
|||||||
|
(in
millions)
|
|
|
|
|
|
|
|
|
Utility
|
|
|
|
|
|
At
December 31, 2006
|
|
|
Facility(1)
|
|
Series
|
|
Termination
Date
|
|
Commitment
|
|
|
Pollution
control bond bank reimbursement agreements
|
|
96
C, E, F, 97 B
|
|
April
2010
|
|
$
|
620
|
|
Pollution
control bond - bond insurance reimbursement agreements
|
|
96A
|
|
December
2016
|
(2)
|
|
200
|
|
Pollution
control bond - bond insurance reimbursement agreements
|
|
2004
A - D
|
|
December
2023
|
(2)
|
|
345
|
|
Pollution
control bond - bond insurance reimbursement agreements
|
|
2005
A - G
|
|
2016
- 2026
|
(2)
|
|
454
|
|
Total
credit support
|
|
|
|
|
|
$
|
1,619
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Off-balance
sheet commitments.
|
|||||||
|
(2) Principal
and debt service insured by the bond insurance
company.
|
|||||||
|
(in
millions, except interest rates)
|
2007
|
2008
|
2009
|
2010
|
2011
|
Thereafter
|
Total
|
|||||||||||||||
|
Long-term
debt:
|
||||||||||||||||||||||
|
PG&E
Corporation
|
||||||||||||||||||||||
|
Average
fixed interest rate
|
9.50
|
%
|
-
|
-
|
-
|
-
|
-
|
9.50
|
%
|
|||||||||||||
|
Fixed
rate obligations
|
$
|
280
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
280
|
||||||||
|
Utility
|
||||||||||||||||||||||
|
Average
fixed interest rate
|
-
|
-
|
3.60
|
%
|
-
|
4.20
|
%
|
5.55
|
%
|
5.22
|
%
|
|||||||||||
|
Fixed
rate obligations
|
$
|
-
|
$
|
-
|
$
|
600
|
$
|
-
|
$
|
500
|
$
|
4,529
|
$
|
5,629
|
||||||||
|
Variable
interest rate as of December 31, 2006
|
-
|
-
|
-
|
3.88
|
%
|
-
|
3.59
|
%
|
3.76
|
%
|
||||||||||||
|
Variable
rate obligations
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
614(1
|
)
|
$
|
-
|
$
|
454
|
$
|
1,068
|
|||||||
|
Other
|
$
|
1
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
1
|
||||||||
|
Less:
current portion
|
(281
|
)
|
-
|
-
|
-
|
-
|
-
|
(281
|
)
|
|||||||||||||
|
Total
consolidated long-term debt
|
$
|
-
|
$
|
-
|
$
|
600
|
$
|
614
|
$
|
500
|
$
|
4,983
|
$
|
6,697
|
||||||||
|
(1)
The $614 million pollution control bonds, due in 2026, are backed
by
letters of credit which expire on April 22, 2010. The bonds will
be
subject to a mandatory redemption unless the letters of credit
are
extended or replaced. Accordingly, the bonds have been classified
for
repayment purposes in 2010.
|
||||||||||||||||||||||
|
(in
millions)
|
|
|
|
|
|
||||||||||||
|
|
|
|
|
|
|
|
At
December 31, 2006
|
||||||||||
|
Authorized
Borrower
|
|
Facility
|
|
Termination
Date
|
|
|
Facility
Limit
|
|
|
Letters
of Credit Out-standing
|
|
Cash
Borrowings
|
|
Commercial
Paper Backup
|
Availability
|
||
|
PG&E
Corporation
|
Senior
credit facility
|
|
December
2009
|
$
|
200
|
(1)
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
200
|
|||
|
Utility
|
Accounts
receivable financing
|
|
March
2007
|
|
650
|
|
|
-
|
|
300
|
|
-
|
350
|
||||
|
Utility
|
Working
capital facility
|
|
April
2010
|
|
1,350
|
(2)
|
|
144
|
|
-
|
|
460
|
746
|
||||
|
Total
credit facilities
|
$
|
2,200
|
|
$
|
144
|
$
|
300
|
$
|
460
|
$
|
1,296
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
|
|
|
|
|
|
|
|
|
|
|
||||||||
|
(1) Includes
$50 million sublimit for letters of credit and $100 million sublimit
for
swingline loans, which are made available on a same-day basis and
repayable in full within 30 days.
|
|||||||||||||||||
|
(2) Includes
a $950 million sublimit for letters of credit and $100 million
sublimit
for swingline loans, which are made available on a same-day basis
and
repayable in full within 30 days.
|
|||||||||||||||||
|
(in
millions)
|
2007
|
2008
|
2009
|
2010
|
2011
|
Thereafter
|
Total
|
|||||||||||||||
|
Utility
|
||||||||||||||||||||||
|
Average
fixed interest rate
|
4.19
|
%
|
4.19
|
%
|
4.36
|
%
|
4.49
|
%
|
4.61
|
%
|
4.64
|
%
|
4.43
|
%
|
||||||||
|
Energy
recovery bonds
|
$
|
340
|
$
|
354
|
$
|
369
|
$
|
386
|
$
|
424
|
$
|
403
|
$
|
2,276
|
||||||||
|
(in
millions)
|
||||
|
Negative
investment in NEGT
|
$
|
1,208
|
||
|
Accumulated
other comprehensive loss
|
(120
|
)
|
||
|
Cash
paid pursuant to settlement of tax related litigation
|
(30
|
)
|
||
|
Tax
effect
|
(374
|
)
|
||
|
Gain
on disposal of NEGT, net of tax
|
$
|
684
|
|
Year
ended December 31,
|
||||||||||
|
(in
millions, except per share amounts)
|
2006
|
2005
|
2004
|
|||||||
|
Net
Income
|
$
|
991
|
$
|
917
|
$
|
4,504
|
||||
|
Less:
distributed earnings to common shareholders
|
460
|
449
|
-
|
|||||||
|
Undistributed
earnings
|
531
|
468
|
4,504
|
|||||||
|
Less:
undistributed earnings from discontinued operations
|
-
|
13
|
684
|
|||||||
|
Undistributed
earnings from continuing operations
|
$
|
531
|
$
|
455
|
$
|
3,820
|
||||
|
|
||||||||||
|
Common
shareholders earnings
|
||||||||||
|
Basic
|
||||||||||
|
Distributed
earnings to common shareholders
|
$
|
460
|
$
|
449
|
$
|
-
|
||||
|
Undistributed
earnings allocated to common shareholders - continuing
operations
|
503
|
433
|
3,646
|
|||||||
|
Undistributed
earnings allocated to common shareholders - discontinued
operations
|
-
|
12
|
653
|
|||||||
|
Total
common shareholders earnings, basic
|
$
|
963
|
$
|
894
|
$
|
4,299
|
||||
|
Diluted
|
||||||||||
|
Distributed
earnings to common shareholders
|
$
|
460
|
$
|
449
|
$
|
-
|
||||
|
Undistributed
earnings allocated to common shareholders - continuing
operations
|
504
|
433
|
3,650
|
|||||||
|
Undistributed
earnings allocated to common shareholders - discontinued
operations
|
-
|
12
|
653
|
|||||||
|
Total
common shareholders earnings, diluted
|
$
|
964
|
$
|
894
|
$
|
4,303
|
||||
|
|
||||||||||
|
Weighted
average common shares outstanding, basic
|
346
|
372
|
398
|
|||||||
|
9.50%
Convertible Subordinated Notes
|
19
|
19
|
19
|
|||||||
|
Weighted
average common shares outstanding and participating securities,
basic
|
365
|
391
|
417
|
|||||||
|
|
||||||||||
|
Weighted
average common shares outstanding, basic
|
346
|
372
|
398
|
|||||||
|
Employee
share-based compensation and accelerated share repurchases (1)
|
3
|
6
|
7
|
|||||||
|
PG&E
Corporation warrants
|
-
|
-
|
2
|
|||||||
|
Weighted
average common shares outstanding, diluted
|
349
|
378
|
407
|
|||||||
|
9.50%
Convertible Subordinated Notes
|
19
|
19
|
19
|
|||||||
|
Weighted
average common shares outstanding and participating securities,
diluted
|
368
|
397
|
426
|
|||||||
|
|
||||||||||
|
Net
earnings per common share, basic
|
||||||||||
|
Distributed
earnings, basic (2)
|
$
|
1.33
|
$
|
1.21
|
$
|
-
|
||||
|
Undistributed
earnings - continuing operations, basic
|
1.45
|
1.16
|
9.16
|
|||||||
|
Undistributed
earnings - discontinued operations, basic
|
-
|
0.03
|
1.64
|
|||||||
|
Total
|
$
|
2.78
|
$
|
2.40
|
$
|
10.80
|
||||
|
Net
earnings per common share, diluted
|
||||||||||
|
Distributed
earnings, diluted
|
$
|
1.32
|
$
|
1.19
|
$
|
-
|
||||
|
Undistributed
earnings - continuing operations, diluted
|
1.44
|
1.15
|
8.97
|
|||||||
|
Undistributed
earnings - discontinued operations, diluted
|
-
|
0.03
|
1.60
|
|||||||
|
Total
|
$
|
2.76
|
$
|
2.37
|
$
|
10.57
|
||||
|
(1)
Includes
approximately 1 million, 2 million and 222,000 shares of PG&E
Corporation common stock treated as outstanding in connection with
accelerated share repurchases for the year ended December 31, 2006,
December 31, 2005 and December 31, 2004, respectively. The remaining
shares of approximately 2 million at December 31, 2006, 4 million
at
December 31, 2005 and 6.8 million at December 31, 2004, relate
to
share-based compensation and are deemed to be outstanding under
SFAS No.
128 for the purpose of calculating EPS. See section of Note 2 entitled
“Earnings Per Share.”
|
||||||||||
|
(2) “Distributed
earnings, basic” differs from actual per share amounts paid as dividends
as the EPS computation under GAAP requires the use of the weighted
average, rather than the actual number of shares
outstanding.
|
|
|
PG&E
Corporation
|
Utility
|
|||||||||||||||||
|
|
Year
Ended December 31,
|
||||||||||||||||||
|
|
2006
|
2005
|
2004
|
2006
|
2005
|
2004
|
|||||||||||||
|
(in
millions)
|
|||||||||||||||||||
|
Current:
|
|||||||||||||||||||
|
Federal
|
$
|
743
|
$
|
1,027
|
$
|
121
|
$
|
771
|
$
|
1,048
|
$
|
73
|
|||||||
|
State
|
201
|
189
|
91
|
210
|
196
|
85
|
|||||||||||||
|
Deferred:
|
|||||||||||||||||||
|
Federal
|
(286
|
)
|
(574
|
)
|
1,877
|
(276
|
)
|
(572
|
)
|
2,000
|
|||||||||
|
State
|
(98
|
)
|
(89
|
)
|
384
|
(97
|
)
|
(89
|
)
|
410
|
|||||||||
|
Tax
credits, net
|
(6
|
)
|
(9
|
)
|
(7
|
)
|
(6
|
)
|
(9
|
)
|
(7
|
)
|
|||||||
|
Income
tax expense
|
$
|
554
|
$
|
544
|
$
|
2,466
|
$
|
602
|
$
|
574
|
$
|
2,561
|
|||||||
|
|
PG&E
Corporation
|
Utility
|
|||||||||||
|
|
Year
ended December 31,
|
||||||||||||
|
|
2006
|
2005
|
2006
|
2005
|
|||||||||
|
(in
millions)
|
|||||||||||||
|
Deferred
income tax assets:
|
|||||||||||||
|
Customer
advances for construction
|
$
|
806
|
$
|
607
|
$
|
806
|
$
|
607
|
|||||
|
Reserve
for damages
|
165
|
276
|
165
|
276
|
|||||||||
|
Environmental
reserve
|
177
|
188
|
177
|
188
|
|||||||||
|
Compensation
|
131
|
90
|
95
|
66
|
|||||||||
|
Other
|
206
|
382
|
166
|
300
|
|||||||||
|
Total
deferred income tax assets
|
$
|
1,485
|
$
|
1,543
|
$
|
1,409
|
$
|
1,437
|
|||||
|
Deferred
income tax liabilities:
|
|||||||||||||
|
Regulatory
balancing accounts
|
$
|
1,305
|
$
|
1,719
|
$
|
1,305
|
$
|
1,719
|
|||||
|
Property
related basis differences
|
2,778
|
2,694
|
2,778
|
2,694
|
|||||||||
|
Income
tax regulatory asset
|
243
|
218
|
243
|
218
|
|||||||||
|
Unamortized
loss on reacquired debt
|
120
|
128
|
120
|
128
|
|||||||||
|
Other
|
27
|
57
|
53
|
57
|
|||||||||
|
Total
deferred income tax liabilities
|
$
|
4,473
|
$
|
4,816
|
$
|
4,499
|
$
|
4,816
|
|||||
|
Total
net deferred income tax liabilities
|
$
|
2,988
|
$
|
3,273
|
$
|
3,090
|
$
|
3,379
|
|||||
|
Classification
of net deferred income tax liabilities:
|
|||||||||||||
|
Included
in current liabilities
|
$
|
148
|
$
|
181
|
$
|
118
|
$
|
161
|
|||||
|
Included
in noncurrent liabilities
|
2,840
|
3,092
|
2,972
|
3,218
|
|||||||||
|
Total
net deferred income tax liabilities
|
$
|
2,988
|
$
|
3,273
|
$
|
3,090
|
$
|
3,379
|
|||||
|
|
PG&E
Corporation
|
Utility
|
|||||||||||||||||
|
|
Year
Ended December 31,
|
||||||||||||||||||
|
|
2006
|
2005
|
2004
|
2006
|
2005
|
2004
|
|||||||||||||
|
|
|||||||||||||||||||
|
Federal
statutory income tax rate
|
35.0
|
%
|
35.0
|
%
|
35.0
|
%
|
35.0
|
%
|
35.0
|
%
|
35.0
|
%
|
|||||||
|
Increase
(decrease) in income tax rate resulting from:
|
|||||||||||||||||||
|
State
income tax (net of federal benefit)
|
4.3
|
4.5
|
4.6
|
4.6
|
4.7
|
4.7
|
|||||||||||||
|
Effect
of regulatory treatment of depreciation differences
|
0.6
|
0.9
|
(0.5
|
)
|
0.6
|
0.9
|
(0.4
|
)
|
|||||||||||
|
Tax
credits, net
|
(0.6
|
)
|
(1.0
|
)
|
(0.2
|
)
|
(0.6
|
)
|
(1.0
|
)
|
(0.2
|
)
|
|||||||
|
Other,
net
|
(3.4
|
)
|
(1.8
|
)
|
0.3
|
(1.6
|
)
|
(1.6
|
)
|
0.2
|
|||||||||
|
Effective
tax rate
|
35.9
|
%
|
37.6
|
%
|
39.2
|
%
|
38.0
|
%
|
38.0
|
%
|
39.3
|
%
|
|||||||
|
December
31, 2006
|
December
31, 2005
|
||||||
|
(in
millions)
|
|||||||
|
Current
Assets - Prepaid expenses and other
|
$
|
16
|
$
|
140
|
|||
|
Other
Noncurrent Assets - Other
|
$
|
37
|
$
|
212
|
|||
|
Current
Liabilities - Other
|
$
|
192
|
$
|
2
|
|||
|
Noncurrent
Liabilities - Other
|
$
|
50
|
$
|
-
|
|
|
Maturity
Date
|
Total
Unrealized
Gains
|
Total
Unrealized
Losses
|
Estimated
Fair Value
|
|||||||||
|
(in
millions)
|
|
||||||||||||
|
Year
ended December 31, 2006
|
|||||||||||||
|
U.S.
government and agency issues
|
2007-2036
|
$
|
34
|
$
|
(1
|
)
|
$
|
814
|
|||||
|
Municipal
bonds and other
|
2007-2049
|
7
|
(1
|
)
|
258
|
||||||||
|
Equity
securities
|
644
|
-
|
991
|
||||||||||
|
Total
|
$
|
685
|
$
|
(2
|
)
|
$
|
2,063
|
||||||
|
Year
ended December 31, 2005
|
|||||||||||||
|
U.S.
government and agency issues
|
2006-2035
|
$
|
42
|
$
|
(2
|
)
|
$
|
763
|
|||||
|
Municipal
bonds and other
|
2006-2036
|
10
|
(1
|
)
|
192
|
||||||||
|
Equity
securities
|
534
|
-
|
871
|
||||||||||
|
Total
|
$
|
586
|
$
|
(3
|
)
|
$
|
1,826
|
||||||
|
Year
Ended December 31,
|
||||||||||
|
2006
|
2005
|
2004
|
||||||||
|
(in
millions)
|
||||||||||
|
Proceeds
received from sales of securities
|
$
|
1,087
|
$ |
2,918
|
$ |
1,821
|
||||
|
Gross
realized gains on sales of securities held as
available-for-sale
|
55
|
56
|
28
|
|||||||
|
Gross
realized losses on sales of securities held as
available-for-sale
|
(29
|
)
|
(14
|
)
|
(22
|
)
|
||||
|
|
PG&E
Corporation
|
Utility
|
|||||||||||
|
|
2006
|
2005
|
2006
|
2005
|
|||||||||
|
(in
millions)
|
|||||||||||||
|
Projected
benefit obligation at January 1
|
$
|
9,249
|
$
|
8,557
|
$
|
9,211
|
$
|
8,551
|
|||||
|
Service
cost for benefits earned
|
236
|
214
|
233
|
211
|
|||||||||
|
Interest
cost
|
511
|
500
|
509
|
498
|
|||||||||
|
Plan
amendments
|
1
|
(7
|
)
|
3
|
(3
|
)
|
|||||||
|
Actuarial
loss/(gain)
|
(592
|
)
|
331
|
(594
|
)
|
326
|
|||||||
|
Benefits
and expenses paid
|
(341
|
)
|
(348
|
)
|
(339
|
)
|
(347
|
)
|
|||||
|
Other
(1)
|
-
|
2
|
-
|
(25
|
)
|
||||||||
|
Projected
benefit obligation at December 31
|
$
|
9,064
|
$
|
9,249
|
$
|
9,023
|
$
|
9,211
|
|||||
|
Accumulated
benefit obligation
|
$
|
8,178
|
$
|
8,276
|
$
|
8,145
|
$
|
8,246
|
|||||
|
(1) In
2005 a Supplemental Executive Retirement Plan was split into two
plans.
The Utility remained sponsor of the first plan and PG&E Corporation
became the sponsor of the second
plan.
|
|||||||||||||
|
|
PG&E
Corporation
|
Utility
|
|||||||||||
|
|
2006
|
2005
|
2006
|
2005
|
|||||||||
|
(in
millions)
|
|
||||||||||||
|
Benefit
obligation at January 1
|
$
|
1,339
|
$
|
1,399
|
$
|
1,339
|
$
|
1,399
|
|||||
|
Service
cost for benefits earned
|
28
|
30
|
28
|
30
|
|||||||||
|
Interest
cost
|
74
|
74
|
74
|
74
|
|||||||||
|
Actuarial
gain
|
(105
|
)
|
(103
|
)
|
(105
|
)
|
(103
|
)
|
|||||
|
Participants
paid benefits
|
31
|
30
|
31
|
30
|
|||||||||
|
Plan
amendments
|
31
|
-
|
31
|
-
|
|||||||||
|
Gross
benefits paid
|
(92
|
)
|
(91
|
)
|
(92
|
)
|
(91
|
)
|
|||||
|
Federal
subsidy on benefits paid
|
4
|
-
|
4
|
-
|
|||||||||
|
Benefit
obligation at December 31
|
$
|
1,310
|
$
|
1,339
|
$
|
1,310
|
$
|
1,339
|
|||||
|
PG&E
Corporation
|
Utility
|
||||||||||||
|
2006
|
2005
|
2006
|
2005
|
||||||||||
|
(in
millions)
|
|||||||||||||
|
Fair
value of plan assets at January 1
|
$
|
8,049
|
$
|
7,614
|
$
|
8,049
|
$
|
7,614
|
|||||
|
Actual
return on plan assets
|
1,050
|
758
|
1,050
|
758
|
|||||||||
|
Company
contributions
|
300
|
25
|
298
|
24
|
|||||||||
|
Benefits
and expenses paid
|
(371
|
)
|
(348
|
)
|
(369
|
)
|
(347
|
)
|
|||||
|
Fair
value of plan assets at December 31
|
$
|
9,028
|
$
|
8,049
|
$
|
9,028
|
$
|
8,049
|
|
|
PG&E
Corporation
|
Utility
|
|||||||||||
|
|
2006
|
2005
|
2006
|
2005
|
|||||||||
|
(in
millions)
|
|
||||||||||||
|
Fair
value of plan assets at January 1
|
$
|
1,146
|
$
|
1,069
|
$
|
1,146
|
$
|
1,069
|
|||||
|
Actual
return on plan assets
|
154
|
86
|
154
|
86
|
|||||||||
|
Company
contributions
|
25
|
59
|
25
|
59
|
|||||||||
|
Plan
participant contribution
|
31
|
30
|
31
|
30
|
|||||||||
|
Benefits
and expenses paid
|
(100
|
)
|
(98
|
)
|
(100
|
)
|
(98
|
)
|
|||||
|
Fair
value of plan assets at December 31
|
$
|
1,256
|
$
|
1,146
|
$
|
1,256
|
$
|
1,146
|
|||||
|
|
PG&E
Corporation
|
Utility
|
|||||||||||
|
|
December
31,
|
December
31,
|
|||||||||||
|
|
2006
|
2005
|
2006
|
2005
|
|||||||||
|
(in
millions)
|
|
||||||||||||
|
Fair
value of plan assets at December 31
|
$
|
9,028
|
$
|
8,049
|
$
|
9,028
|
$
|
8,049
|
|||||
|
Projected
benefit obligation at December 31
|
(9,064
|
)
|
(9,249
|
)
|
(9,023
|
)
|
(9,211
|
)
|
|||||
|
Funded
status plan assets less than projected benefit obligation
|
(36
|
)
|
(1,200
|
)
|
5
|
(1,162
|
)
|
||||||
|
Unrecognized
prior service cost
|
268
|
321
|
275
|
327
|
|||||||||
|
Unrecognized
net loss
|
318
|
1,314
|
306
|
1,302
|
|||||||||
|
Unrecognized
net transition obligation
|
1
|
1
|
1
|
-
|
|||||||||
|
Less:
transfer to accumulated other comprehensive income(2)
|
(587
|
)
|
-
|
(582
|
)
|
-
|
|||||||
|
Prepaid/(accrued)
benefit cost
|
$
|
(36
|
)
|
$
|
436
|
$
|
5
|
$
|
467
|
||||
|
Noncurrent
Asset
|
$
|
34
|
$
|
-
|
$
|
34
|
$
|
-
|
|||||
|
Current
Liability
|
(5
|
)
|
-
|
(3
|
)
|
-
|
|||||||
|
Noncurrent
liability
|
(65
|
)
|
-
|
(26
|
)
|
-
|
|||||||
|
Prepaid
benefit cost
|
-
|
491
|
-
|
491
|
|||||||||
|
Accrued
benefit liability
|
-
|
(55
|
)
|
-
|
(24
|
)
|
|||||||
|
Additional
minimum liability
|
-
|
(671
|
)
|
-
|
(668
|
)
|
|||||||
|
Intangible
asset
|
-
|
332
|
-
|
332
|
|||||||||
|
Excess
additional minimum liability (1)
|
-
|
339
|
-
|
336
|
|||||||||
|
Prepaid/(accrued)
benefit cost
|
$
|
(36
|
)
|
$
|
436
|
$
|
5
|
$
|
467
|
||||
|
|
|||||||||||||
|
|
|||||||||||||
|
(1)
Of
this amount, approximately $325 million has been recorded as a
reduction
to a pension regulatory liability in accordance with the provisions
of
SFAS No. 71 and the remainder is recorded to other comprehensive
income,
net of the related income tax benefit, for 2005.
(2)
Under
SFAS No. 158 this amount is recorded to accumulated other comprehensive
income, net of the related income tax benefit, for
2006.
|
|||||||||||||
|
|
|
PG&E
Corporation
|
|
Utility
|
|
|
|
December
31,
|
December
31,
|
|||||||||||
|
|
2006
|
2005
|
2006
|
2005
|
|||||||||
|
(in
millions)
|
|
||||||||||||
|
Fair
value of plan assets at December 31
|
$
|
1,256
|
$
|
1,146
|
$
|
1,256
|
$
|
1,146
|
|||||
|
Benefit
obligation at December 31
|
(1,310
|
)
|
(1,339
|
)
|
(1,310
|
)
|
(1,339
|
)
|
|||||
|
Funded
status plan assets less than benefit obligation
|
(54
|
)
|
(193
|
)
|
(54
|
)
|
(193
|
)
|
|||||
|
Unrecognized
prior service cost
|
114
|
132
|
114
|
132
|
|||||||||
|
Unrecognized
net gain
|
(250
|
)
|
(129
|
)
|
(250
|
)
|
(129
|
)
|
|||||
|
Unrecognized
net transition obligation
|
154
|
179
|
154
|
179
|
|||||||||
|
Less:
transfer to accumulated other comprehensive income(1)
|
(18
|
)
|
-
|
(18
|
)
|
-
|
|||||||
|
Accrued
benefit cost
|
$
|
(54
|
)
|
$
|
(11
|
)
|
$
|
(54
|
)
|
$
|
(11
|
)
|
|
|
Noncurrent
liability
|
$
|
(54
|
)
|
$
|
-
|
$
|
(54
|
)
|
$
|
-
|
|||
|
Accrued
benefit liability
|
-
|
(11
|
)
|
-
|
(11
|
)
|
|||||||
|
Accrued
benefit cost
|
$
|
(54
|
)
|
$
|
(11
|
)
|
$
|
(54
|
)
|
$
|
(11
|
)
|
|
|
|
|||||||||||||
|
(1)
Under SFAS No. 158 this amount is recorded to accumulated other
comprehensive income, net of the related income tax benefit, for
2006.
|
|||||||||||||
|
|
Pension
Benefits
|
Other
Benefits
|
|||||||||||
|
|
2006
|
2005
|
2006
|
2005
|
|||||||||
|
(in
millions)
|
|
||||||||||||
|
PG&E
Corporation:
|
|||||||||||||
|
Projected
benefit obligation
|
$
|
(70
|
)
|
$
|
(9,249
|
)
|
$
|
(1,310
|
)
|
$
|
(1,339
|
)
|
|
|
Accumulated
benefit obligation
|
(62
|
)
|
(8,276
|
)
|
-
|
-
|
|||||||
|
Fair
value of plan assets
|
-
|
8,049
|
1,256
|
1,146
|
|||||||||
|
Utility:
|
|||||||||||||
|
Projected
benefit obligation
|
$
|
(29
|
)
|
$
|
(9,211
|
)
|
$
|
(1,310
|
)
|
$
|
(1,339
|
)
|
|
|
Accumulated
benefit obligation
|
(28
|
)
|
(8,246
|
)
|
-
|
-
|
|||||||
|
Fair
value of plan assets
|
-
|
8,049
|
1,256
|
1,146
|
|||||||||
|
|
December
31,
|
|||||||||
|
|
2006
|
2005
|
2004
|
|||||||
|
(in
millions)
|
||||||||||
|
Service
cost for benefits earned
|
$
|
236
|
$
|
214
|
$
|
194
|
||||
|
Interest
cost
|
511
|
500
|
482
|
|||||||
|
Expected
return on plan assets
|
(640
|
)
|
(623
|
)
|
(563
|
)
|
||||
|
Amortized
prior service cost
|
56
|
56
|
63
|
|||||||
|
Amortization
of unrecognized loss
|
22
|
29
|
6
|
|||||||
|
Net
periodic benefit cost
|
$
|
185
|
$
|
176
|
$
|
182
|
||||
|
|
|
December
31,
|
|
|
|
2006
|
2005
|
2004
|
|||||||
|
(in
millions)
|
||||||||||
|
Service
cost for benefits earned
|
$
|
28
|
$
|
30
|
$
|
32
|
||||
|
Interest
cost
|
74
|
74
|
84
|
|||||||
|
Expected
return on plan assets
|
(90
|
)
|
(85
|
)
|
(76
|
)
|
||||
|
Amortized
prior service cost
|
14
|
11
|
12
|
|||||||
|
Amortization
of unrecognized loss (gain)
|
(3
|
)
|
(1
|
)
|
-
|
|||||
|
Amortization
of transition obligation
|
26
|
26
|
26
|
|||||||
|
Net
periodic benefit cost
|
$
|
49
|
$
|
55
|
$
|
78
|
||||
|
|
PG&E
Corporation
|
Utility
|
|||||||||||
|
|
2006
|
2005
|
2006
|
2005
|
|||||||||
|
(in
millions)
|
|
||||||||||||
|
Pension
Benefits:
|
|||||||||||||
|
Unrecognized
prior service cost
|
$
|
268
|
$
|
-
|
$
|
275
|
$
|
-
|
|||||
|
Unrecognized
net loss
|
318
|
-
|
306
|
-
|
|||||||||
|
Unrecognized
net transition obligation
|
1
|
-
|
1
|
-
|
|||||||||
|
Less:
transfer to regulatory account(1)
|
(574
|
)
|
-
|
(574
|
)
|
-
|
|||||||
|
Total
|
$
|
13
|
$
|
-
|
$
|
8
|
$
|
-
|
|||||
|
Other
Benefits:
|
|||||||||||||
|
Unrecognized
prior service cost
|
$
|
114
|
$
|
-
|
$
|
114
|
$
|
-
|
|||||
|
Unrecognized
net gain
|
(250
|
)
|
-
|
(250
|
)
|
-
|
|||||||
|
Unrecognized
net transition obligation
|
154
|
-
|
154
|
-
|
|||||||||
|
Total
|
$
|
18
|
$
|
-
|
$
|
18
|
$
|
-
|
|||||
|
(1) The
Utility recorded approximately $574 million as a reduction to the
existing
pension regulatory liability in accordance with the provisions
of SFAS No.
71.
|
|||||||||||||
|
|
PG&E
Corporation
|
Utility
|
|||||
|
(in
millions)
|
|
||||||
|
Pension
benefits:
|
|||||||
|
Unrecognized
prior service cost
|
$
|
49
|
$
|
50
|
|||
|
Unrecognized
net loss
|
1
|
-
|
|||||
|
Unrecognized
net transition obligation
|
1
|
1
|
|||||
|
Total
|
$
|
51
|
$
|
51
|
|||
|
Other
benefits:
|
|||||||
|
Unrecognized
prior service cost
|
$
|
14
|
$
|
14
|
|||
|
Unrecognized
net gain
|
(12
|
)
|
(12
|
)
|
|||
|
Unrecognized
net transition obligation
|
26
|
26
|
|||||
|
Total
|
$
|
28
|
$
|
28
|
|||
|
|
PG&E
Corporation
|
Utility
|
|||||||||||||||||
|
|
Before
Application
|
Effect
of Adopting SFAS No. 158
|
As
Reported at December 31, 2006
|
Before
Application
|
Effect
of Adopting SFAS No. 158
|
As
Reported at December 31, 2006
|
|||||||||||||
|
(in
millions)
|
|||||||||||||||||||
|
Other
Noncurrent Assets
|
|||||||||||||||||||
|
Other
|
$
|
339
|
$
|
34
|
$
|
373
|
$
|
246
|
$
|
34
|
$
|
280
|
|||||||
|
Total
other noncurrent assets
|
7,117
|
34
|
7,151
|
7,049
|
34
|
7,083
|
|||||||||||||
|
TOTAL
ASSETS
|
$
|
34,769
|
$
|
34
|
$ |
34,803
|
$ |
34,337
|
$
|
34
|
$ |
34,371
|
|||||||
|
Current
Liabilities
|
|||||||||||||||||||
|
Accounts
payable:
|
|||||||||||||||||||
|
Other
|
$ |
454
|
$
|
(34
|
)
|
$
|
420
|
$
|
436
|
$
|
(34
|
)
|
$
|
402
|
|||||
|
Deferred
income taxes
|
134
|
14
|
148
|
104
|
14
|
118
|
|||||||||||||
|
Total
current liabilities
|
8,270
|
(20
|
)
|
8,250
|
7,700
|
(20
|
)
|
7,680
|
|||||||||||
|
Noncurrent
Liabilities
|
|||||||||||||||||||
|
Regulatory
liabilities
|
3,966
|
(574
|
)
|
3,392
|
3,966
|
(574
|
)
|
3,392
|
|||||||||||
|
Deferred
income taxes
|
2,862
|
(22
|
)
|
2,840
|
2,993
|
(21
|
)
|
2,972
|
|||||||||||
|
Other
|
1,392
|
661
|
2,053
|
1,263
|
659
|
1,922
|
|||||||||||||
|
Total
noncurrent liabilities
|
18,425
|
65
|
18,490
|
18,427
|
64
|
18,491
|
|||||||||||||
|
Accumulated
other comprehensive income
|
(8
|
)
|
(11
|
)
|
(19
|
)
|
(6
|
)
|
(10
|
)
|
(16
|
)
|
|||||||
|
Total
shareholders’ equity
|
7,822
|
(11
|
)
|
7,811
|
8,210
|
(10
|
)
|
8,200
|
|||||||||||
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
$ |
34,769
|
$
|
34
|
$ |
34,803
|
$ |
34,337
|
$
|
34
|
$
|
34,371
|
|||||||
|
|
Pension
Benefits
|
Other
Benefits
|
|||||||||||||||||
|
|
December
31,
|
December
31,
|
|||||||||||||||||
|
|
2006
|
2005
|
2004
|
2006
|
2005
|
2004
|
|||||||||||||
|
|
|||||||||||||||||||
|
Discount
rate
|
5.90
|
%
|
5.60
|
%
|
5.80
|
%
|
5.50
- 6.00
|
%
|
5.20
- 5.65
|
%
|
5.80
|
%
|
|||||||
|
Average
rate of future compensation increases
|
5.00
|
%
|
5.00
|
%
|
5.00
|
%
|
-
|
-
|
-
|
||||||||||
|
Expected
return on plan assets
|
|||||||||||||||||||
|
Pension
benefits
|
8.00
|
%
|
8.00
|
%
|
8.10
|
%
|
-
|
-
|
-
|
||||||||||
|
Other
benefits:
|
|||||||||||||||||||
|
Defined
benefit—medical plan bargaining
|
-
|
-
|
-
|
8.20
|
%
|
8.40
|
%
|
8.50
|
%
|
||||||||||
|
Defined
benefit—medical plan non-bargaining
|
-
|
-
|
-
|
7.30
|
%
|
7.60
|
%
|
7.60
|
%
|
||||||||||
|
Defined
benefit—life insurance plan
|
-
|
-
|
-
|
8.20
|
%
|
8.40
|
%
|
8.50
|
%
|
||||||||||
|
(in
millions)
|
One-Percentage
Point Increase
|
One-Percentage
Point Decrease
|
|||||
|
Effect
on postretirement benefit obligation
|
$
|
71
|
$
|
(58
|
)
|
||
|
Effect
on service and interest cost
|
8
|
(6
|
)
|
|
Pension
Benefits
|
Other
Benefits
|
||||||||||||||||||
|
2007
|
2006
|
2005
|
2007
|
2006
|
2005
|
||||||||||||||
|
Equity
securities
|
|||||||||||||||||||
|
U.S.
equity
|
37.5
|
%
|
38
|
%
|
41
|
%
|
49
|
%
|
49
|
%
|
51
|
%
|
|||||||
|
Non-U.S.
equity
|
17.5
|
%
|
18
|
%
|
24
|
%
|
18
|
%
|
20
|
%
|
20
|
%
|
|||||||
|
Global
equity
|
5
|
%
|
5
|
%
|
0
|
%
|
4
|
%
|
4
|
%
|
0
|
%
|
|||||||
|
Fixed
income securities
|
40
|
%
|
39
|
%
|
35
|
%
|
29
|
%
|
27
|
%
|
29
|
%
|
|||||||
|
Total
|
100
|
%
|
100
|
%
|
100
|
%
|
100
|
%
|
100
|
%
|
100
|
%
|
|||||||
|
|
PG&E
Corporation
|
Utility
|
|||||
|
(in
millions)
|
|
||||||
|
Pension
|
|||||||
|
2007
|
$
|
392
|
$
|
390
|
|||
|
2008
|
417
|
415
|
|||||
|
2009
|
441
|
439
|
|||||
|
2010
|
465
|
462
|
|||||
|
2011
|
511
|
508
|
|||||
|
2012-2016
|
2,771
|
2,757
|
|||||
|
Other
benefits
|
|||||||
|
2007
|
$
|
80
|
$
|
80
|
|||
|
2008
|
84
|
84
|
|||||
|
2009
|
86
|
86
|
|||||
|
2010
|
89
|
89
|
|||||
|
2011
|
91
|
91
|
|||||
|
2012-2016
|
484
|
484
|
|||||
|
(in
millions)
|
PG&E
Corporation
|
Utility
|
|||||
|
Year
ended December 31,
|
|||||||
|
2006
|
$
|
45
|
$
|
43
|
|||
|
2005
|
43
|
42
|
|||||
|
2004(1)
|
40
|
39
|
|||||
|
|
|||||||
|
|
|||||||
|
(1) Includes
NEGT-related amounts within PG&E Corporation.
|
|||||||
|
PG&E
Corporation
|
Utility
|
||||||
|
(in
millions)
|
|||||||
|
Stock
Options
|
$
|
12
|
$
|
8
|
|||
|
Restricted
Stock
|
20
|
14
|
|||||
|
Performance
Shares
|
33
|
24
|
|||||
|
Total
Compensation Expense (pre-tax)
|
$
|
65
|
$
|
46
|
|||
|
Total
Compensation Expense (after-tax)
|
$
|
39
|
$
|
27
|
|||
|
2006
|
2005
|
2004
|
||||||||
|
Expected
stock price volatility
|
22.1
|
%
|
40.6
|
%
|
45.0
|
%
|
||||
|
Expected
annual dividend payment
|
$
|
1.32
|
$
|
1.20
|
$
|
1.20
|
||||
|
Risk-free
interest rate
|
4.46
|
%
|
3.74
|
%
|
3.66
|
%
|
||||
|
Expected
life
|
5.6
years
|
5.9
years
|
6.5
years
|
|||||||
|
PG&E
Corporation
|
Utility
|
||||||
|
(in
millions)
|
|||||||
|
2006:
|
|||||||
|
Intrinsic
value of options exercised
|
$
|
97
|
$
|
51
|
|||
|
2005:
|
|||||||
|
Intrinsic
value of options exercised
|
$
|
125
|
$
|
57
|
|||
|
2004:
|
|||||||
|
Intrinsic
value of options exercised
|
$
|
83
|
$
|
44
|
|||
|
Options
|
Shares
|
Weighted
Average Exercise Price
|
Weighted
Average Remaining Contractual Term
|
Aggregate
Intrinsic Value
|
|||||||||
|
Outstanding
at January 1
|
11,899,059
|
$
|
23.26
|
||||||||||
|
Granted(1)
|
12,457
|
37.47
|
|||||||||||
|
Exercised
|
(5,369,818
|
)
|
22.05
|
||||||||||
|
Forfeited
or expired
|
(142,728
|
)
|
25.50
|
||||||||||
|
Outstanding
at December 31
|
6,398,970
|
23.52
|
5.5
|
$
|
148,248,308
|
||||||||
|
Expected
to vest at December 31
|
2,226,843
|
25.29
|
6.9
|
$
|
46,872,341
|
||||||||
|
Exercisable
at December 31
|
4,115,402
|
17.50
|
3.8
|
$
|
101,375,967
|
||||||||
|
(1)No
stock options were awarded to employees in 2006; however, certain
non-employee directors of PG&E Corporation were awarded stock
options.
|
|||||||||||||
|
Options
|
Shares
|
Weighted
Average Exercise Price
|
Weighted
Average Remaining Contractual Term
|
Aggregate
Intrinsic Value
|
|||||||||
|
Outstanding
at January 1(1)
|
7,344,455
|
$
|
23.15
|
||||||||||
|
Granted
|
-
|
-
|
|||||||||||
|
Exercised
|
(2,836,769
|
)
|
22.21
|
||||||||||
|
Forfeited
or expired
|
(105,180
|
)
|
25.48
|
||||||||||
|
Outstanding
at December 31
|
4,402,506
|
23.66
|
5.8
|
$
|
104,083,574
|
||||||||
|
Expected
to vest at December 31
|
1,571,779
|
25.28
|
6.9
|
$
|
33,113,132
|
||||||||
|
Exercisable
at December 31
|
2,799,712
|
17.99
|
4.1
|
$
|
70,970,442
|
||||||||
|
(1)Includes
net employee transfers between PG&E Corporation and the Utility during
2006.
|
|||||||||||||
|
Number
of Shares of
Restricted
Stock
|
Weighted
Average Grant-Date Fair Value
|
||||||
|
Nonvested
at January 1
|
1,399,990
|
$
|
22.31
|
||||
|
Granted
|
559,855
|
37.47
|
|||||
|
Vested
|
(493,874
|
)
|
20.97
|
||||
|
Forfeited
|
(88,433
|
)
|
19.41
|
||||
|
Nonvested
at December 31
|
1,377,538
|
$
|
29.24
|
||||
|
Number
of Shares of
Restricted
Stock
|
Weighted
Average Grant-Date Fair Value
|
||||||
|
Nonvested
at January 1
|
958,997
|
$
|
22.48
|
||||
|
Granted
|
387,735
|
37.47
|
|||||
|
Vested
|
(339,362
|
)
|
21.08
|
||||
|
Forfeited
|
(74,642
|
)
|
20.74
|
||||
|
Nonvested
at December 31
|
932,728
|
$
|
29.36
|
||||
|
Number
of Performance Shares
|
||||
|
Nonvested
at January 1
|
803,975
|
|||
|
Granted
|
559,855
|
|||
|
Vested
|
(469,023
|
)
|
||
|
Forfeited
|
(62,201
|
)
|
||
|
Nonvested
at December 31
|
832,606
|
|||
|
Number
of Performance Shares
|
|
|
Nonvested
at January 1
|
566,086
|
|||
|
Granted
|
387,735
|
|||
|
Vested
|
(319,119
|
)
|
||
|
Forfeited
|
(51,105
|
)
|
||
|
Nonvested
at December 31
|
583,597
|
|
PG&E
Corporation
|
Utility
|
||||||
|
(in
millions)
|
|||||||
|
2006:
|
$
|
4
|
$
|
2
|
|||
|
2005:
|
3
|
1
|
|||||
|
2004:
|
3
|
1
|
|||||
|
|
Year
Ended December 31,
|
Receivable
(Payable)
Balance
Outstanding at Year Ended December 31,
|
||||||||||||||
|
|
2006
|
2005
|
2004
|
2006
|
2005
|
|||||||||||
|
(in
millions)
|
||||||||||||||||
|
Utility
revenues from:
|
||||||||||||||||
|
Administrative
services provided to PG&E Corporation
|
$
|
5
|
$
|
5
|
$
|
8
|
$
|
2
|
$
|
2
|
||||||
|
Utility
employee benefit assets due from PG&E
Corporation
|
-
|
-
|
-
|
25
|
23
|
|||||||||||
|
Interest
from PG&E Corporation on employee
benefit
assets
|
1
|
-
|
-
|
-
|
-
|
|||||||||||
|
Utility
expenses from:
|
||||||||||||||||
|
Administrative
services received from PG&E
Corporation
|
$
|
108
|
$
|
111
|
$
|
81
|
$
|
(40
|
)
|
$
|
(37
|
)
|
||||
|
Utility
employee benefit payments due to PG&E
Corporation
|
3
|
-
|
-
|
-
|
-
|
|||||||||||
|
Interest
accrued on pre-petition liabilities due to PG&E
Corporation
|
-
|
-
|
2
|
-
|
-
|
|||||||||||
|
Natural
gas transportation services received from GTNW
|
-
|
-
|
43
|
-
|
-
|
|||||||||||
|
(in
millions)
|
2006
|
2005
|
2004
|
|||||||
|
Qualifying
facility energy payments
|
$
|
661
|
$
|
663
|
$
|
701
|
||||
|
Qualifying
facility capacity payments
|
366
|
372
|
382
|
|||||||
|
Irrigation
district and water agency payments
|
64
|
54
|
61
|
|||||||
|
Renewable
energy and capacity payments
|
429
|
405
|
406
|
|||||||
|
Other
power purchase agreement payments
|
670
|
774
|
834
|
|||||||
|
Qualifying
Facility
|
Irrigation
District & Water Agency
|
Renewable
|
Other
|
||||||||||||||||||||||
|
Energy
|
Capacity
|
Operations
& Maintenance
|
Debt
Service
|
Energy
|
Capacity
|
Energy
|
Capacity
|
||||||||||||||||||
|
(in
millions)
|
|||||||||||||||||||||||||
|
2007
|
$
|
1,195
|
$
|
477
|
$
|
54
|
$
|
26
|
$
|
148
|
$
|
18
|
$
|
50
|
$
|
201
|
|||||||||
|
2008
|
1,276
|
468
|
34
|
4
|
205
|
21
|
41
|
169
|
|||||||||||||||||
|
2009
|
1,159
|
428
|
32
|
-
|
254
|
18
|
40
|
171
|
|||||||||||||||||
|
2010
|
995
|
391
|
31
|
-
|
294
|
14
|
11
|
158
|
|||||||||||||||||
|
2011
|
930
|
377
|
30
|
-
|
315
|
14
|
5
|
44
|
|||||||||||||||||
|
Thereafter
|
5,941
|
2,601
|
114
|
-
|
2,979
|
76
|
11
|
18
|
|||||||||||||||||
|
Total
|
$
|
11,496
|
$
|
4,742
|
$
|
295
|
$
|
30
|
$
|
4,195
|
$
|
161
|
$
|
158
|
$
|
761
|
|||||||||
|
(in
millions)
|
||||
|
2007
|
$
|
50
|
||
|
2008
|
50
|
|||
|
2009
|
50
|
|||
|
2010
|
50
|
|
2011
|
50
|
|||
|
Thereafter
|
303
|
|||
|
Total
fixed capacity payments
|
553
|
|||
|
Less:
Amount representing interest
|
154
|
|||
|
Present
value of fixed capacity payments
|
$
|
399
|
|
(in
millions)
|
|
|||
|
2007
|
$
|
954
|
||
|
2008
|
151
|
|||
|
2009
|
25
|
|||
|
2010
|
8
|
|||
|
2011
|
-
|
|||
|
Thereafter
|
-
|
|||
|
Total
|
$
|
1,138
|
||
|
(in
millions)
|
|
|||
|
2007
|
$
|
135
|
||
|
2008
|
86
|
|||
|
2009
|
66
|
|||
|
2010
|
64
|
|||
|
2011
|
37
|
|||
|
Thereafter
|
151
|
|||
|
Total
|
$
|
539
|
||
|
(in
millions)
|
|
|||
|
2007
|
$
|
160
|
||
|
2008
|
33
|
|||
|
2009
|
18
|
|||
|
2010
|
12
|
|||
|
2011
|
11
|
|||
|
Thereafter
|
34
|
|||
|
Total
|
$
|
268
|
||
|
·
|
After
assumption, the Utility's issuer rating by Moody's will be no less
than A2
and the Utility's long-term issuer credit rating by S&P will be no
less than A;
|
|
|
|
|
·
|
The
CPUC first makes a finding that the DWR power purchase contracts
to be
assumed are just and reasonable; and
|
|
|
|
|
·
|
The
CPUC has acted to ensure that the Utility will receive full and
timely
recovery in its retail electricity rates of all costs associated
with the
DWR power purchase contracts to be assumed without further
review.
|
|
(in
millions)
|
||||
|
Balance
at December 31, 2005
|
$
|
2
|
||
|
Expenses
|
36
|
|||
|
Less:
Payments
|
(4
|
)
|
||
|
Balance
at December 31, 2006
|
$
|
34
|
|
·
|
approximately
$238 million for remediation at the Hinkley and Topock natural
gas
compressor sites;
|
|
·
|
approximately
$98 million related to the pre-closing remediation liability associated
with divested generation facilities; and
|
|
·
|
approximately
$175 million related to remediation costs for the Utility’s generation
facilities and gas gathering sites, third-party disposal sites,
and
manufactured gas plant sites owned by the Utility or third parties
(including those sites that are the subject of remediation orders
by
environmental agencies or claims by the current owners of the former
manufactured gas plant sites).
|
|
|
Quarter
ended
|
||||||||||||
|
|
December
31
|
September
30
|
June
30
|
March
31
|
|||||||||
|
(in
millions, except per share amounts)
|
|||||||||||||
|
2006
|
|||||||||||||
|
PG&E
CORPORATION
|
|||||||||||||
|
Operating
revenues
|
$
|
3,206
|
$
|
3,168
|
$
|
3,017
|
$
|
3,148
|
|||||
|
Operating
income
|
439
|
735
|
465
|
469
|
|||||||||
|
Income
from continuing operations
|
152
|
393
|
232
|
214
|
|||||||||
|
Net
income
|
152
|
393
|
232
|
214
|
|||||||||
|
Earnings
per common share from continuing operations, basic
|
0.43
|
1.09
|
0.65
|
0.61
|
|||||||||
|
Earnings
per common share from continuing operations, diluted
|
0.43
|
1.09
|
0.65
|
0.60
|
|||||||||
|
Net
income per common share, basic
|
0.43
|
1.09
|
0.65
|
0.61
|
|||||||||
|
Net
income per common share, diluted
|
0.43
|
1.09
|
0.65
|
0.60
|
|||||||||
|
Common
stock price per share:
|
|||||||||||||
|
High
|
48.17
|
42.51
|
40.90
|
40.68
|
|||||||||
|
Low
|
40.72
|
39.06
|
38.30
|
36.25
|
|||||||||
|
UTILITY
|
|||||||||||||
|
Operating
revenues
|
$
|
3,206
|
$
|
3,168
|
$
|
3,017
|
$
|
3,148
|
|||||
|
Operating
income
|
443
|
737
|
465
|
470
|
|||||||||
|
Net
income
|
159
|
378
|
231
|
217
|
|||||||||
|
Income
available for common stock
|
155
|
375
|
227
|
214
|
|||||||||
|
2005(1)
|
|||||||||||||
|
PG&E
CORPORATION
|
|||||||||||||
|
Operating
revenues
|
$
|
3,732
|
$
|
2,804
|
$
|
2,498
|
$
|
2,669
|
|||||
|
Operating
income
|
414
|
515
|
540
|
501
|
|||||||||
|
Income
from continuing operations
|
180
|
239
|
267
|
218
|
|||||||||
|
Net
income
|
180
|
252
|
267
|
218
|
|||||||||
|
Earnings
per common share from continuing operations, basic
|
0.49
|
0.63
|
0.70
|
0.55
|
|||||||||
|
Earnings
per common share from continuing operations, diluted
|
0.49
|
0.62
|
0.70
|
0.54
|
|||||||||
|
Net
income per common share, basic
|
0.49
|
0.66
|
0.70
|
0.55
|
|||||||||
|
Net
income per common share, diluted
|
0.49
|
0.65
|
0.70
|
0.54
|
|||||||||
|
Common
stock price per share:
|
|||||||||||||
|
High
|
40.10
|
39.64
|
37.91
|
36.18
|
|||||||||
|
Low
|
34.54
|
35.60
|
33.78
|
31.83
|
|||||||||
|
UTILITY
|
|||||||||||||
|
Operating
revenues
|
$
|
3,733
|
$
|
2,804
|
$
|
2,498
|
$
|
2,669
|
|||||
|
Operating
income
|
418
|
517
|
540
|
495
|
|||||||||
|
Net
income
|
187
|
248
|
276
|
223
|
|||||||||
|
Income
available for common stock
|
183
|
244
|
272
|
219
|
|||||||||
|
|
|||||||||||||
|
|
|||||||||||||
|
(1) During
the third quarter of 2005, PG&E Corporation received additional
information from NEGT regarding income to be included in PG&E
Corporation's 2004 federal income tax return. This information
was
incorporated in the 2004 tax return, which was filed with the IRS
in
September 2005. As a result, the 2004 federal income tax liability
was
reduced by approximately $19 million. In addition, NEGT provided
additional information with respect to amounts previously included
in
PG&E Corporation's 2003 federal income tax return. This change
resulted in PG&E Corporation's 2003 federal income tax liability
increasing by approximately $6 million. These two adjustments,
netting to
$13 million, were recognized in income from discontinued operations
in the
third quarter of 2005.
|
|||||||||||||