(Mark
One)
|
|
x
|
ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF
1934
|
For
the Fiscal Year Ended December 31, 2005
|
|
Or
|
|
o
|
TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
|
For
the transition period from to
|
Commission
File
Number
|
Exact
Name of Registrant
as
specified in its charter
|
State
or Other Jurisdiction of
Incorporation
or Organization
|
IRS
Employer
Identification
Number
|
|
1-12609
|
PG&E
CORPORATION
|
California
|
94-3234914
|
|
1-2348
|
PACIFIC
GAS AND ELECTRIC COMPANY
|
California
|
94-0742640
|
|
PG&E
Corporation
One
Market, Spear Tower
Suite
2400
San
Francisco, California 94105
(Address
of principal executive offices) (Zip Code)
(415)
267-7000
(Registrant's
telephone number, including area code)
|
Pacific
Gas and Electric Company
77
Beale Street
P.O.
Box 770000
San
Francisco, California 94177
(Address
of principal executive offices) (Zip Code)
(415)
973-7000
(Registrant's
telephone number, including area
code)
|
Title
of Each Class
|
Name
of Each Exchange on Which Registered
|
PG&E
Corporation:
Common
Stock, no par value
|
New
York Stock Exchange and Pacific Exchange
|
Pacific
Gas and Electric Company:
First
Preferred Stock,
cumulative,
par value $25 per share:
|
American
Stock Exchange and Pacific Exchange
|
Redeemable:
5% Series A, 5%, 4.80%, 4.50%, 4.36%
|
|
Nonredeemable:
6%, 5.50%, 5%
|
PG&E
Corporation
|
Yes
x
No
o
|
Pacific
Gas and Electric Company
|
Yes
x
No
¨
|
PG&E
Corporation
|
Yes
¨
No
x
|
Pacific
Gas and Electric Company
|
Yes
o
No
x
|
PG&E
Corporation
|
Yes
x
No
o
|
Pacific
Gas and Electric Company
|
Yes
x
No
¨
|
PG&E
Corporation
|
x
|
Pacific
Gas and Electric Company
|
x
|
PG&E
Corporation
|
Large
accelerated filer
x
|
Accelerated
filer
¨
|
Non-accelerated
filer
¨
|
Pacific
Gas and Electric Company
|
Large
accelerated filer
¨
|
Accelerated
filer
¨
|
Non-accelerated
filer
x
|
PG&E
Corporation
|
Yes
¨
No
x
|
Pacific
Gas and Electric Company
|
Yes
o
No
x
|
PG&E
Corporation Common Stock
|
$13,975
million
|
Pacific
Gas and Electric Company Common Stock
|
Wholly
owned by PG&E Corporation
|
Common
Stock outstanding as of February 10, 2006:
|
|
PG&E
Corporation:
|
345,319,971
(excluding shares held by a wholly owned subsidiary)
|
Pacific
Gas and Electric Company:
|
Wholly
owned by PG&E Corporation
|
Designated
portions of the combined 2005 Annual Report to
Shareholders
|
Part I
(Item 1, Item 1.A.), Part II (Items 5, 6, 7, 7A, 8 and
9A)
|
Designated
portions of the Joint Proxy Statement relating to the 2006
|
Part III
(Items 10, 11, 12, 13 and 14)
|
Annual
Meetings of Shareholders
|
Page
|
||
iii
|
||
Item
1
.
|
1
|
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1
|
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1
|
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1
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1
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1
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3
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3
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4
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4
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5
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5
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7
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8
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9
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9
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9
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11
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11
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12
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12
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12
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13
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13
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14
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15
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15
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16
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16
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17
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18
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18
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18
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18
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20
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20
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20
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21
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22
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24
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25
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25
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25
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26
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27
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27
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29
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30
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31
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31
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i
|
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32
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32
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32
|
||
33
|
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33
|
||
33
|
||
33
|
||
33
|
||
36
|
||
Item
4
.
|
37
|
|
38
|
||
|
||
39
|
||
39
|
||
40
|
||
40
|
||
40
|
||
40
|
||
40
|
||
Item
9B
.
|
40
|
|
40
|
||
40
|
||
41
|
||
43
|
||
43
|
||
43
|
||
44
|
||
44
|
||
45
|
||
50
|
||
51
|
||
52
|
1
Kilowatt (kW)
|
=
|
One
thousand watts
|
1
Kilowatt-Hour (kWh)
|
=
|
One
kilowatt continuously for one hour
|
1
Megawatt (MW)
|
=
|
One
thousand kilowatts
|
1
Megawatt-Hour (MWh)
|
=
|
One
megawatt continuously for one hour
|
1
Gigawatt (GW)
|
=
|
One
million kilowatts
|
1
Gigawatt-Hour (GWh)
|
=
|
One
gigawatt continuously for one hour
|
1
Kilovolt (kV)
|
=
|
One
thousand volts
|
1
MVA
|
=
|
One
megavolt ampere
|
1
Mcf
|
=
|
One
thousand cubic feet
|
1
MMcf
|
=
|
One
million cubic feet
|
1
Bcf
|
=
|
One
billion cubic feet
|
1
MDth
|
=
|
One
thousand decatherms
|
·
|
How
the Utility manages its responsibility to procure electric capacity
and
energy for its customers;
|
·
|
The
adequacy and price of natural gas supplies, and the ability of the
Utility
to manage and respond to the volatility of the natural gas market
for its
customers;
|
·
|
Weather,
storms, earthquakes, fires, floods, other natural disasters, explosions,
accidents, mechanical breakdowns, acts of terrorism, and other events
or
hazards that affect demand for electricity or natural gas, result
in power
outages, reduce generating output, disrupt natural gas supply, cause
damage to the Utility's assets or generating facilities, cause damage
to
the operations or assets of third parties on which the Utility relies,
or
subject the Utility to third party claims for damage or
injury;
|
·
|
Unanticipated
population growth or decline, general economic and financial market
conditions, changes in technology including the development of alternative
energy sources, all of which may affect customer demand for natural
gas or
electricity;
|
·
|
Whether
the Utility is required to cease operations temporarily or permanently
at
its Diablo Canyon nuclear power plant because the Utility is unable
to
increase its on-site spent nuclear fuel storage capacity, find another
depositary for spent fuel, or timely complete the replacement of
the steam
generators, or because of mechanical breakdown, lack of nuclear fuel,
environmental constraints, or for some other reason and the risk
that the
Utility may be required to purchase electricity from more expensive
sources; and
|
·
|
Whether
the Utility is able to recognize the anticipated cost benefits and
savings
expected to result from its efforts to improve customer service through
implementation of specific initiatives to streamline business processes
and deploy new technology.
|
·
|
The
outcome of the regulatory proceedings pending at the CPUC and the
FERC and
the impact of future ratemaking actions by the CPUC and the FERC;
|
·
|
The
impact of the recently enacted Energy Policy Act of 2005 which, among
other provisions, repeals the Public Utility Holding Company Act
of 1935
making electric utility industry consolidation more likely; expands
the
FERC’s authority to review proposed mergers; changes the FERC regulatory
scheme applicable to qualifying co-generation facilities, or QFs;
authorizes the formation of an Electric Reliability Organization
to be
overseen by the FERC to establish electric reliability standards;
and
modifies certain other aspects of energy regulation and federal tax
policies applicable to the Utility;
|
·
|
The
extent to which the CPUC or the FERC delays or denies recovery of
the
Utility's costs, including electricity or gas purchase costs, from
customers due to a regulatory determination that such costs were
not
reasonable or prudent, or for other reasons, resulting in write-offs
of
regulatory assets;
|
·
|
How
the CPUC administers the capital structure, stand-alone dividend,
and
first priority conditions of the CPUC's past decisions permitting
the
establishment of holding companies for the California investor-owned
electric utilities and the outcome of the CPUC's new rulemaking proceeding
concerning the relationship between the California investor-owned
energy
utilities and their holding companies and non-regulated affiliates,
which
may include (1) establishing reporting requirements for the allocation
of
capital between utilities and their non-regulated affiliates by the
parent
holding companies, and (2) changing the CPUC's affiliate transaction
rules;
|
·
|
Whether
the Utility is determined to be in compliance with all applicable
rules,
tariffs and orders relating to electricity and natural gas utility
operations, including tariffs related to the Utility’s billing and
collection practices, and the extent to which a finding of non-compliance
could result in customer refunds, penalties or other non-recoverable
expenses, such as has been recommended with respect to the CPUC’s
investigation into the Utility’s billing and collection practices;
and
|
·
|
Whether
the Utility is required to incur material costs or capital expenditures
or
curtail or cease operations at affected facilities, including the
Utility’s natural gas compressor stations, to comply with existing and
future environmental laws, regulations and
policies.
|
·
|
The
outcome of pending litigation; and
|
·
|
The
timing and resolution of the pending appeal of the bankruptcy court
order
confirming the Utility's plan of reorganization under Chapter 11
of the
U.S. Bankruptcy Code.
|
·
|
Continuing
efforts by local public utilities to take over the Utility's distribution
assets through exercise of their condemnation power or by duplication
of
the Utility's distribution assets or service, and other forms of
municipalization that may result in stranded investment capital,
decreased
customer growth, loss of customer load and additional barriers to
cost
recovery; and
|
·
|
The
extent to which the Utility's distribution customers are permitted
to
switch between purchasing electricity from the Utility and from alternate
energy service providers as direct access customers, and the extent
to
which cities, counties and others in the Utility's service territory
begin
directly serving the electricity needs of the Utility's customers,
potentially resulting in stranded generating asset costs and
non-recoverable procurement costs.
|
Agricultural
and Other Customers
|
6%
|
Industrial
Customers
|
18%
|
Residential
Customers
|
36%
|
Commercial
Customers
|
40%
|
2005
|
2004
|
2003
|
2002
|
2001
|
||||||
Customers
(average for the year):
|
||||||||||
Residential
|
4,353,458
|
4,366,897
|
4,286,085
|
4,171,365
|
4,165,073
|
|||||
Commercial
|
509,786
|
509,501
|
493,638
|
483,946
|
484,430
|
|||||
Industrial
|
1,271
|
1,339
|
1,372
|
1,249
|
1,368
|
|||||
Agricultural
|
78,876
|
80,276
|
81,378
|
78,738
|
81,375
|
|||||
Public
street and highway lighting
|
28,021
|
27,176
|
26,650
|
24,119
|
23,913
|
|||||
Other
electric utilities
|
4
|
3
|
4
|
5
|
5
|
|||||
Total
(1)
|
4,971,362
|
4,985,192
|
4,889,127
|
4,759,422
|
4,756,164
|
|||||
Deliveries
(in GWh):(2)
|
||||||||||
Residential
|
29,752
|
29,453
|
29,024
|
27,435
|
26,840
|
|||||
Commercial
|
32,375
|
32,268
|
31,889
|
31,328
|
30,780
|
|||||
Industrial
|
14,932
|
14,796
|
14,653
|
14,729
|
16,001
|
|||||
Agricultural
|
3,742
|
4,300
|
3,909
|
4,000
|
4,093
|
|||||
Public
street and highway lighting
|
792
|
2,091
|
605
|
674
|
418
|
|||||
Other
electric utilities
|
33
|
28
|
76
|
64
|
241
|
|||||
Subtotal
|
81,626
|
82,936
|
80,156
|
78,230
|
78,373
|
|||||
California
Department of Water Resources (DWR)
|
(20,476)
|
(19,938)
|
(23,554)
|
(21,031)
|
(28,640)
|
|||||
Total
non-DWR electricity
|
61,150
|
62,998
|
56,602
|
57,199
|
49,733
|
|||||
Revenues
(in millions):
|
||||||||||
Residential
|
$3,856
|
$3,718
|
$3,671
|
$3,646
|
$3,396
|
|||||
Commercial
|
4,114
|
4,179
|
4,440
|
4,588
|
4,105
|
|||||
Industrial
|
1,232
|
1,204
|
1,410
|
1,449
|
1,554
|
|||||
Agricultural
|
446
|
491
|
522
|
520
|
525
|
|||||
Public
street and highway lighting
|
66
|
71
|
69
|
73
|
60
|
|||||
Other
electric utilities
|
4
|
22
|
24
|
10
|
39
|
|||||
Subtotal
|
9,718
|
9,685
|
10,136
|
10,286
|
9,679
|
|||||
DWR
|
(1,699)
|
(1,933)
|
(2,243)
|
(2,056)
|
(2,173)
|
|||||
Direct
access credits
|
—
|
—
|
(277)
|
(285)
|
(461)
|
|||||
Miscellaneous(3)
|
235
|
(248)
|
(52)
|
193
|
244
|
|||||
Regulatory
balancing accounts
|
(327)
|
363
|
18
|
40
|
37
|
|||||
Total
electricity operating revenues
|
$7,927
|
$7,867
|
$7,582
|
$8,178
|
$7,326
|
|||||
Other
Data:
|
||||||||||
Average
annual residential usage (kWh)
|
6,834
|
6,744
|
6,772
|
6,577
|
6,444
|
|||||
Average
billed revenues (cents per kWh):
|
||||||||||
Residential
|
12.96
|
12.62
|
12.65
|
13.29
|
12.65
|
|||||
Commercial
|
12.71
|
12.95
|
13.92
|
14.65
|
13.34
|
|||||
Industrial
|
8.25
|
8.14
|
9.62
|
9.84
|
9.71
|
|||||
Agricultural
|
11.92
|
11.41
|
13.35
|
13.00
|
12.83
|
|||||
Net
plant investment per customer
|
$2,966
|
$2,790
|
$2,689
|
$2,105
|
$2,018
|
Owned
generation (nuclear, fossil fuel-fired and hydroelectric
facilities)
|
40%
|
DWR
|
27%
|
Qualifying
Facilities/Renewables
|
22%
|
Irrigation
Districts
|
5%
|
Other
Power Purchases
|
6%
|
Generation
Type
|
County
Location
|
Number
of
Units
|
Net
Operating
Capacity
(MW)
|
|||
Nuclear:
|
||||||
Diablo
Canyon
|
San
Luis Obispo
|
2
|
2,174
|
|||
Hydroelectric:
|
||||||
Conventional
|
16
counties in northern
and
central California
|
107
|
2,684
|
|||
Helms
pumped storage
|
Fresno
|
3
|
1,212
|
|||
Hydroelectric
subtotal
|
110
|
3,896
|
||||
Fossil
fuel:
|
||||||
Humboldt
Bay(1)
|
Humboldt
|
2
|
105
|
|||
Hunters
Point(2)
|
San
Francisco
|
2
|
215
|
|||
Mobile
turbines
|
Humboldt
|
2
|
30
|
|||
Fossil
fuel subtotal
|
6
|
350
|
||||
Total
|
118
|
6,420
|
2006
|
2007
|
2008
|
2009
|
2010
|
|||||
Unit
1
|
|||||||||
Refueling
|
-
|
April
|
-
|
January
|
October
|
||||
Duration
(days)
|
-
|
35
|
-
|
80
|
35
|
||||
Startup
|
-
|
June
|
-
|
April
|
November
|
||||
Unit
2
|
|||||||||
Refueling
|
April
|
-
|
February
|
October
|
-
|
||||
Duration
(days)
|
45
|
-
|
80
|
35
|
-
|
||||
Startup
|
June
|
-
|
April
|
November
|
-
|
· |
After
assumption, the Utility's issuer rating by Moody's Investors Service,
or
Moody's, will be no less than A2 and the Utility's long-term issuer
credit
rating by Standard & Poor's, or 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.
|
Residential
Customers
|
28%
|
Transport-only
Customers (noncore)
|
60%
|
Commercial
Customers
|
12%
|
2005
|
2004
|
2003
|
2002
|
2001
|
|||||
Customers
(average for the year):
|
|||||||||
Residential
|
3,929,117
|
3,812,914
|
3,744,011
|
3,738,524
|
3,705,141
|
||||
Commercial
|
216,749
|
215,547
|
208,857
|
206,953
|
205,681
|
||||
Industrial
|
962
|
2,178
|
1,988
|
1,819
|
1,764
|
||||
Other
gas utilities
|
6
|
6
|
6
|
5
|
6
|
||||
Total
|
4,146,834
|
4,030,645
|
3,954,862
|
3,947,301
|
3,912,592
|
||||
Gas
supply (MMcf):
|
|||||||||
Purchased
from suppliers in:
|
|||||||||
Canada
|
204,884
|
205,180
|
196,278
|
210,716
|
209,630
|
||||
California
|
(18,951)
|
(9,108)
|
(7,421)
|
19,533
|
20,352
|
||||
Other
states
|
103,237
|
103,801
|
102,941
|
67,878
|
76,589
|
||||
Total
purchased
|
289,170
|
299,873
|
291,798
|
298,127
|
306,571
|
||||
Net
(to storage) from storage
|
(3,659)
|
(532)
|
1,359
|
(218)
|
(27,027)
|
||||
Total
|
285,511
|
299,341
|
293,157
|
297,909
|
279,544
|
||||
Utility
use, losses, etc.(1)
|
(14,312)
|
(19,287)
|
(14,307)
|
(16,393)
|
(8,988)
|
||||
Net
gas for sales
|
271,199
|
280,054
|
278,850
|
281,516
|
270,556
|
||||
Bundled
gas sales (MMcf):
|
|||||||||
Residential
|
194,108
|
201,601
|
198,580
|
202,141
|
197,184
|
||||
Commercial
|
77,056
|
78,080
|
79,891
|
78,812
|
72,528
|
||||
Industrial
|
35
|
373
|
379
|
563
|
831
|
||||
Other
gas utilities
|
—
|
—
|
—
|
—
|
13
|
||||
Total
|
271,199
|
280,054
|
278,850
|
281,516
|
270,556
|
||||
Transportation
only (MMcf):
|
572,869
|
597,706
|
525,353
|
508,090
|
646,079
|
||||
Revenues
(in millions):
|
|||||||||
Bundled
gas sales:
|
|||||||||
Residential
|
$2,336
|
$1,944
|
$1,836
|
$1,379
|
$2,308
|
||||
Commercial
|
885
|
712
|
697
|
499
|
783
|
||||
Industrial
|
—
|
—
|
1
|
3
|
16
|
||||
Other
gas utilities
|
—
|
—
|
1
|
1
|
—
|
||||
Miscellaneous
|
(22)
|
(29)
|
(31)
|
127
|
(93)
|
||||
Regulatory
balancing accounts
|
340
|
316
|
68
|
11
|
(253)
|
||||
Bundled
gas revenues
|
3,539
|
2,943
|
2,572
|
2,020
|
2,761
|
||||
Transportation
service only revenue
|
238
|
270
|
284
|
316
|
375
|
||||
Operating
revenues
|
$3,777
|
$3,213
|
$2,856
|
$2,336
|
$3,136
|
||||
Selected
Statistics:
|
|||||||||
Average
annual residential usage (Mcf)
|
49
|
53
|
53
|
54
|
53
|
||||
Average
billed bundled gas sales revenues per Mcf:
|
|||||||||
Residential
|
$12.04
|
$9.64
|
$9.25
|
$6.82
|
$11.70
|
||||
Commercial
|
11.48
|
9.12
|
8.73
|
6.33
|
10.80
|
||||
Industrial
|
0.61
|
(0.56)
|
2.48
|
4.35
|
19.15
|
||||
Average
billed transportation only revenue per Mcf
|
0.42
|
0.45
|
0.54
|
0.62
|
0.58
|
||||
Net
plant investment per customer
|
$1,262
|
$1,266
|
$1,261
|
$1,006
|
$970
|
||||
2005
|
2004
|
2003
|
2002
|
2001
|
||||||||||||||||||||||||||
MMcf
|
Avg.
Price
|
MMcf
|
Avg.
Price
|
MMcf
|
Avg.
Price
|
MMcf
|
Avg.
Price
|
MMcf
|
Avg.
Price
|
|||||||||||||||||||||
Canada
|
204,884
|
$
|
7.12
|
205,180
|
$
|
5.37
|
196,278
|
$
|
4.73
|
210,716
|
$
|
2.42
|
209,630
|
$
|
4.43
|
|||||||||||||||
California(1)
|
(18,951
|
)
|
$
|
7.70
|
(9,108
|
)
|
$
|
4.89
|
(7,421
|
)
|
$
|
3.39
|
19,533
|
$
|
2.88
|
20,352
|
$
|
11.55
|
||||||||||||
Other
states (substantially all U.S southwest)
|
103,237
|
$
|
7.10
|
103,801
|
$
|
5.44
|
102,941
|
$
|
4.63
|
67,878
|
$
|
3.04
|
76,589
|
$
|
10.41
|
|||||||||||||||
Total/weighted
average
|
289,170
|
$
|
7.07
|
299,873
|
$
|
5.41
|
291,798
|
$
|
4.73
|
298,127
|
$
|
2.59
|
306,571
|
$
|
6.40
|
Pipeline
|
Expiration
Date
|
Quantity
MDth
per day
|
Demand
Charges
for
the Year Ended
December 31,
2005
(In
millions)
|
||||
TransCanada
NOVA Gas Transmission, Ltd.
|
12/31/2007
|
(a)
|
616
|
28.0
|
|||
TransCanada
PipeLines Ltd., B.C. System
|
10/31/2007
|
607
|
13.0
|
||||
Gas
Transmission Northwest Corporation
|
10/31/2007
|
610
|
54.8
|
||||
Transwestern
Pipeline Co.
|
03/31/2007
|
150
|
20.5
|
||||
El
Paso Natural Gas Company (b)
|
Various
|
202
|
19.2
|
(a) | A small portion (23 MDth/d) of the Utility’s capacity is due to expire on October 31, 2007. |
(b)
|
As
of December 31, 2005, the Utility has three active contracts with
El Paso
with expiration dates ranging from June 30, 2007 to June 30, 2010.
|
· |
The
Utility is precluded from guaranteeing any obligations of PG&E
Corporation without prior written consent from the
CPUC;
|
· |
The
Utility's dividend policy must continue to be established by the
Utility's
Board of Directors as though the Utility were a stand-alone utility
company;
|
· |
The
capital requirements of the Utility, as determined to be necessary
and
prudent to meet the Utility's obligation to serve or to operate the
Utility in a prudent and efficient manner, must be given first priority
by
PG&E Corporation's Board of Directors (known as the “first priority”
condition); and
|
· |
The
Utility must maintain on average its CPUC-authorized utility capital
structure, although it shall have an opportunity to request a waiver
of
this condition if an adverse financial event reduces the Utility's
equity
ratio by 1% or more.
|
·
|
The
decision finds that the Utility's strategy of adding approximately
1,200
MW of capacity and new peaking generation in 2008 and approximately
1,000
MW of new peaking and dispatchable generation in 2010 through requests
for
offers, or RFOs, is reasonable and compatible with the Utility's
resource
needs under its medium load preferred case scenario, does not crowd
out
policy-preferred resources, and is a reasonable level of commitment
given
load uncertainty.
|
·
|
To
meet the utilities' resource requirements, the utilities are required
to
solicit bids from providers of all potential sources of new generation
(e.g. conventional or renewable resources to be provided under
turnkey
developments, buyouts, or power purchase agreements, or PPAs) through
a
single, open, transparent and competitive RFO process, although
an utility
can tailor a RFO to meet specific resource needs. In particular,
bids for
long-term generation resources (whether PPAs or utility-owned)
would be
evaluated side-by-side. In evaluating bids, the IOUs are required
to:
|
·
|
To
meet the utilities' resource requirements, the utilities are required
to
solicit bids from providers of all potential sources of new generation
(e.g. conventional or renewable resources to be provided under
turnkey
developments, buyouts, or power purchase agreements, or PPAs) through
a
single, open, transparent and competitive RFO process, although
an utility
can tailor a RFO to meet specific resource needs. In particular,
bids for
long-term generation resources (whether PPAs or utility-owned)
would be
evaluated side-by-side. In evaluating bids, the IOUs are required
to:
|
|
Ø
|
procure
the maximum amount of renewable generation resources, and be prepared
to
defend any selection of fossil-fuel generation resources over renewable
resources,
|
|
Ø
|
employ
the Least-Cost Best-Fit methodology when evaluating bids for PPAs
and
utility-owned generation resources, taking into account the qualitative
and quantitative attributes (such as performance risk, credit risk,
price
diversity, term and operational flexibility) associated with each
bid,
and
|
|
Ø
|
employ
a "greenhouse gas adder" to evaluate fossil-fuel generation bids
as a
method to recognize the risk of future greenhouse gas emissions
costs to
develop a more accurate price comparison between fossil-fuel, renewable
and demand-side bids (the greenhouse gas adder would be used for
analytical purposes only and would not be paid to a
generator).
|
|
·
|
The
CPUC has agreed that it will consider the debt equivalence impact
of
procurement contracts on credit ratings in future cost of capital
proceedings. The Utility is required to employ S&P’s method for
assessing the debt equivalence of power purchase agreements when
evaluating bids in an all-source solicitation, except that the
debt
equivalence factor should be 20% instead of 30%.
|
|
·
|
The
utilities are prohibited from recovering initial capital costs
in excess
of their final bid price for utility-owned generation resources.
If final
project costs are less than the final bid price, the savings would
be
shared with customers and any cost overruns would be absorbed by
the
utilities. Costs of future plant additions and annual operating
and
maintenance costs and similar costs incurred by a utility would
be
eligible for cost-of service ratemaking treatment.
|
|
·
|
Affiliates
of the utilities are permitted to participate in the bidding process
for
long-term generation resources, subject to certain guidelines and
safeguards, including a requirement that the utility use an independent
third-party evaluator in resource solicitations where there are
bids that
involve affiliates or utility-built or utility-turnkey development
projects. The independent evaluator will not be able to make binding
decisions on behalf of the utility.
|
|
·
|
The
utilities are permitted to recover their net stranded costs of
all new
fossil-fuel generation resources from all customers, including
departing
customers, for a period of 10 years or the life of the PPA, whichever
is less, provided that the CPUC will allow the utilities an opportunity
to
justify a longer recovery period on a case-by-case basis. Stranded
costs
arising from renewable generation procurement activities can be
collected
from all customers, including departing load, over the life of
the
contract. The utilities are required to take appropriate steps
to minimize
potential stranded costs by selling excess energy and capacity
needs into
the marketplace and crediting the revenues from these sales against
the
utilities' costs.
|
|
·
|
The
CPUC extended the mandatory rate adjustment mechanism provided
under SB
1976 (which otherwise expired on January 1, 2006) to the length of a
resource commitment or 10 years, whichever is longer. Under this rate
adjustment mechanism, the CPUC has agreed to adjust retail electricity
rates or order refunds, as appropriate, when the aggregate
over-collections or under-collections exceed 5% of the utility's
prior-year electricity procurement revenues, excluding amounts
collected
for the DWR allocated contracts.
|
|
·
|
With
respect to the utilities' contracting authority, the decision permits
the
utilities to enter into short-term, mid-term and long-term contracts
with
starting delivery dates through 2014, provided the utilities submit
necessary compliance filings and provided that contracts with terms
five
years or longer are submitted to the CPUC for pre-approval. The
decision
adopts a rolling 10-year procurement period, noting that the LTPPs
cover a
10-year period and will be updated and reviewed every 2 years.
|
· |
Base
transmission rates, which are intended to recover the Utility's operating
and maintenance expenses, depreciation and amortization expenses,
interest
expense, tax expense and return on equity;
and
|
· |
Rates
to recover the pass-through of ISO charges for reliability service
costs
and an ISO charge associated with cost differences in utility-specific
transmission charges and an ISO grid-wide charge, both of which are
discussed below.
|
· |
The
discharge of pollutants into air, water and
soil;
|
· |
The
identification, generation, storage, handling, transportation, treatment,
disposal, record keeping, labeling, reporting of, remediation of
and
emergency response in connection with hazardous and radioactive
substances; and
|
· |
Land
use, including endangered species and habitat
protection.
|
Name
|
Age
|
Position
|
||
P.
A. Darbee
|
53
|
Chairman
of the Board, Chief Executive Officer and President
|
||
L.
H. Everett
|
55
|
Senior
Vice President, Communications and Public Affairs
|
||
K.M.
Harvey
|
47
|
Senior
Vice President and Chief Risk and Audit Officer
|
||
R.
M. Jackson
|
48
|
Senior
Vice President, Human Resources
|
||
C.
P. Johns
|
45
|
Senior
Vice President, Chief Financial Officer and Treasurer
|
||
T.
B. King
|
44
|
Senior
Vice President; President and Chief Executive Officer, Pacific
Gas and
Electric Company
|
||
R.
L. Rosenberg
|
52
|
Senior
Vice President, Corporate Strategy and Development
|
||
B.
R. Worthington
|
56
|
Senior
Vice President and General
Counsel
|
Name
|
Position
|
Period
Held Office
|
||
P.
A. Darbee
|
Chairman
of the Board, Chief Executive Officer and President
|
January 1,
2006 to present
|
||
Chairman
of the Board, Pacific Gas and Electric Company
|
January 1,
2006 to present
|
|||
President
and Chief Executive Officer
|
January 1,
2005 to December 31, 2005
|
|||
Senior
Vice President and Chief Financial Officer
|
July 9,
2001 to December 31, 2004
|
|||
Senior
Vice President, Chief Financial Officer, and Treasurer
|
September 20,
1999 to July 8, 2001
|
|||
L.
H. Everett
|
Senior
Vice President, Communications and Public Affairs
|
January 9,
2006 to present
|
||
Senior
Vice President and Assistant to the Chief Executive
Officer
|
January 1,
2005 to January 8, 2006
|
|||
Senior
Vice President and Assistant to the Chairman
|
August 2,
2004 to December 31, 2004
|
|||
Vice
President and Assistant to the Chairman
|
June 1,
2001 to August 1, 2004
|
|||
Vice
President, Corporate Secretary, and Assistant to the
Chairman
|
May 1,
2001 to May 31, 2001
|
|||
Vice
President and Corporate Secretary
|
July 1,
1997 to April 30, 2001
|
|||
Vice
President and Corporate Secretary, Pacific Gas and Electric
Company
|
November 1,
1996 to May 31, 2001
|
|||
K.
M. Harvey
|
Senior
Vice President and Chief Risk and Audit Officer
|
October 1,
2005 to present
|
||
Senior
Vice President - Chief Financial Officer and Treasurer, Pacific
Gas and
Electric Company
|
November 1,
2000 to September 30, 2005
|
|||
Senior
Vice President - Chief Financial Officer, Controller, and
Treasurer
,
Pacific Gas and Electric Company
|
January 1,
2000 to October 31, 2000
|
|||
R.
M. Jackson
|
Senior
Vice President, Human Resources, PG&E Corporation and Pacific Gas and
Electric Company
|
August 2,
2004 to present
|
||
Vice
President, Human Resources, PG&E Corporation
|
June 1,
2004 to August 1, 2004
|
|||
Vice
President, Human Resources, Pacific Gas and Electric
Company
|
June 1,
1999 to August 1, 2004
|
|||
C.
P. Johns
|
Senior
Vice President, Chief Financial Officer and Treasurer
|
October 4,
2005 to present
|
||
Senior
Vice President, Chief Financial Officer and Treasurer, Pacific
Gas and
Electric Company
|
October 1,
2005 to present
|
|||
Senior
Vice President, Chief Financial Officer and Controller
|
January 1,
2005 to October 3, 2005
|
|||
Senior
Vice President and Controller
|
September 19,
2001 to December 31, 2004
|
|||
Vice
President and Controller
|
July 1,
1997 to September 18, 2001
|
|||
T.
B. King
|
Senior
Vice President, PG&E Corporation
|
January 1,
2006 to present
|
||
President
and Chief Executive Officer, Pacific Gas and Electric
Company
|
January 1,
2006 to present
|
|||
Executive
Vice President and Chief Operating Officer, Pacific Gas and Electric
Company
|
July 1,
2005 to December 31, 2005
|
|||
Executive
Vice President and Chief of Utility Operations, Pacific Gas and
Electric
Company
|
August 2,
2004 to June 30, 2005
|
|||
Senior
Vice President and Chief of Utility Operations, Pacific Gas and
Electric
Company
|
November 1,
2003 to August 1, 2004
|
|||
Senior
Vice President, PG&E Corporation
|
January 1,
1999 to October 31, 2003
|
|||
President,
PG&E National Energy Group, Inc.
|
November 15,
2002 to July 8, 2003
|
|||
President
and Chief Operating Officer, PG&E Gas Transmission
Corporation
|
August 27,
2002 to July 8, 2003
|
|||
President
and Chief Operating Officer, Gas Transmission, PG&E National Energy
Group, Inc.
|
August 9,
2002 to November 14, 2002
|
|||
President
and Chief Operating Officer, West Region, PG&E National Energy
Group, Inc.
|
July 1,
2000 to August 8, 2002
|
|||
President
and Chief Operating Officer, PG&E Gas Transmission
Corporation
|
November 23,
1998 to September 10, 2002
|
|||
R.
L. Rosenberg
|
Senior
Vice President, Corporate Strategy and Development
|
November 1,
2005 to present
|
||
Executive
Vice President and Chief Financial Officer, Infospace,
Inc.
|
September
2000 to January 20, 2001
|
|||
Chief
Financial Officer and Senior Vice President, Finance and Corporate
Development, Infospace, Inc.
|
June
2000 to September 2000
|
|||
B.
R. Worthington
|
Senior
Vice President and General Counsel
|
June 1,
1997 to present
|
Name
|
Age
|
Position
|
||
P.A.
Darbee
|
53
|
Chairman
of the Board
|
||
T.
B. King
|
44
|
President
and Chief Executive Officer
|
||
T.
E. Bottorff
|
52
|
Senior
Vice President, Regulatory Relations
|
||
J.
D. Butler
|
50
|
Senior
Vice President, Energy Delivery
|
||
L.H.
Everett
|
55
|
Senior
Vice President, Communications and Public Affairs, PG&E
Corporation
|
||
R.M.
Jackson
|
48
|
Senior
Vice President, Human Resources
|
||
C.
P. Johns
|
45
|
Senior
Vice President, Chief Financial Officer and Treasurer
|
||
J.
S. Keenan
|
57
|
Senior
Vice President, Generation and Chief Nuclear Officer
|
||
S.
M. Ramsay
|
47
|
Vice
President, Asset Management and Electric Transmission
|
||
F
Wan
|
44
|
Vice
President, Energy Procurement
|
||
B.
R. Worthington
|
56
|
Senior
Vice President and General Counsel, PG&E
Corporation
|
Name
|
Position
|
Period
Held Office
|
||
P.
A. Darbee
|
Chairman
of the Board, Pacific Gas and Electric Company
|
January 1,
2006 to present
|
||
Chairman
of the Board, Chief Executive Officer and President, PG&E
Corporation
|
January 1,
2006 to present
|
|||
President
and Chief Executive Officer, PG&E Corporation
|
January 1,
2005 to December 31, 2005
|
|||
Senior
Vice President and Chief Financial Officer, PG&E
Corporation
|
July 9,
2001 to December 31, 2004
|
|||
Senior
Vice President, Chief Financial Officer, and Treasurer, PG&E
Corporation
|
September 20,
1999 to July 8, 2001
|
|||
T.
B. King
|
President
and Chief Executive Officer
|
January 1,
2006 to present
|
||
Senior
Vice President, PG&E Corporation
|
January 1,
2006 to present
|
|||
Executive
Vice President and Chief Operating Officer
|
July 1,
2005 to December 31, 2005
|
|||
Executive
Vice President and Chief of Utility Operations
|
August
2, 2004 to June 30, 2005
|
|||
Senior
Vice President and Chief of Utility Operations
|
November
1, 2003 to August 1, 2004
|
|||
Senior
Vice President, PG&E Corporation
|
January
1, 1999 to October 31, 2003
|
|||
President,
PG&E National Energy Group, Inc.
|
November
15, 2002 to July 8, 2003
|
|||
President
and Chief Operating Officer, PG&E Gas Transmission
Corporation
|
August
27, 2002 to July 8, 2003
|
|||
President
and Chief Operating Officer, Gas Transmission, PG&E National Energy
Group, Inc.
|
August
9, 2002 to November 14, 2002
|
|||
President
and Chief Operating Officer, West Region, PG&E National Energy Group,
Inc.
|
July
1, 2000 to August 8, 2002
|
|||
President
and Chief Operating Officer, PG&E Gas Transmission
Corporation
|
November
23, 1998 to September 10, 2002
|
|||
T.
E. Bottorff
|
Senior
Vice President, Regulatory Relations
|
October 14,
2005 to present
|
||
Senior
Vice President, Customer Service and Revenue
|
March 1,
2004 to October 13, 2005
|
|||
Vice
President, Customer Service
|
June 1,
1999 to February 29, 2004
|
|||
J.
D. Butler
|
Senior
Vice President, Energy Delivery
|
January 9,
2006 to present
|
||
Senior
Vice President, Transmission and Distribution
|
March 1,
2004 to January 8, 2006
|
|||
Vice
President, Operations, Maintenance and Construction
|
June 12,
2000 to February 29, 2004
|
|||
L.
H. Everett
|
Senior
Vice President, Communications and Public Affairs, PG&E
Corporation
|
January 9,
2006 to present
|
||
Senior
Vice President and Assistant to the Chief Executive Officer, PG&E
Corporation
|
January 1,
2005 to January 8, 2006
|
|||
Senior
Vice President and Assistant to the Chairman, PG&E
Corporation
|
August
2, 2004 to December 31, 2004
|
|||
Vice
President and Assistant to the Chairman, PG&E
Corporation
|
June
1, 2001 to August 1, 2004
|
|||
Vice
President, Corporate Secretary, and Assistant to the Chairman,
PG&E
Corporation
|
May
1, 2001 to May 31, 2001
|
|||
Vice
President and Corporate Secretary, PG&E Corporation
|
July
1, 1997 to April 30, 2001
|
|||
Vice
President and Corporate Secretary
|
November
1, 1996 to May 31, 2001
|
|||
R.
M. Jackson
|
Senior
Vice President, Human Resources, Pacific Gas and Electric Company
and
PG&E Corporation
|
August
2, 2004 to present
|
||
Vice
President, Human Resources, PG&E Corporation
|
June 1,
2004 to August 1, 2004
|
|||
Vice
President, Human Resources
|
June
1, 1999 to August 1, 2004
|
|||
C.
P. Johns
|
Senior
Vice President, Chief Financial Officer and Treasurer
|
October 1,
2005 to present
|
||
Senior
Vice President, Chief Financial Officer and Treasurer, PG&E
Corporation
|
October 4,
2005 to present
|
|||
Senior
Vice President, Chief Financial Officer and Controller, PG&E
Corporation
|
January 1,
2005 to October 3, 2005
|
|||
Senior
Vice President and Controller, PG&E Corporation
|
September 19,
2001 to December 31, 2004
|
|||
Vice
President and Controller, PG&E Corporation
|
July 1,
1997 to September 18, 2001
|
|||
J.
S. Keenan
|
Senior
Vice President, Generation and Chief Nuclear Officer
|
December 19,
2005 to present
|
||
Vice
President, Fossil Generation, Progress Energy
|
November 10,
2003 to December 18, 2005
|
|||
Vice
President, Brunswick Nuclear Plant, Progress Energy
|
May 1,
1998 to November 9, 2003
|
|||
S.
M. Ramsay
|
Vice
President, Asset Management and Electric Transmission
|
January 9,
2006 to present
|
||
Vice
President, Electric Transmission
|
July 1,
2005 to January 8, 2006
|
|||
Vice
President, Distribution Asset Management, American Electric
Power
|
February 1,
2004 to June
30,
2005
|
|||
Senior
Vice President, Power and Gas, UMS Group, Inc.
|
October 1,
2001 to January 31, 2004
|
|||
Managing
Director, UK Operations, UMS Group, Inc.
|
January 2,
2001 to September 30, 2001
|
|||
F.
Wan
|
Vice
President, Energy Procurement
|
January 9,
2006 to present
|
||
Vice
President, Power Contracts and Electric Resource
Development
|
May 1,
2004 to January 8, 2006
|
|||
Vice
President, Risk Initiatives, PG&E Corporation Support Services,
Inc.
|
November
1, 2000 to April 30, 2004
|
|||
B.
R. Worthington
|
Senior
Vice President and General Counsel, PG&E Corporation
|
June
1, 1997 to present
|
Period
|
Total
Number of Shares Purchased
|
Average
Price Paid Per Share
|
Total
Number of Shares Purchased as Part of Publicly Announced Plans
or
Programs
(1)(2)(3)
|
Approximate
Dollar Value of Shares that May Yet be Purchased Under the Plans
or
Programs
|
|||||||||
October
1 through October 31, 2005
|
-
|
$
|
-
|
-
|
$
|
-
|
|||||||
November
1 through November 30, 2005
|
31,650,300
|
$
|
34.75
|
31,650,300
|
$
|
500,000,000
|
|||||||
December 1
through December 31, 2005
|
-
|
$
|
-
|
-
|
$
|
-
|
|||||||
Total
|
31,650,300
|
$
|
34.75
|
31,650,300
|
$
|
500,000,000
|
(1)
|
On
September 15, 2004, the PG&E Corporation Board of Directors
authorized PG&E Corporation and its subsidiaries to repurchase shares
of PG&E Corporation's common stock with an aggregate purchase price
not to exceed PG&E Corporation's net cash proceeds from sales of
PG&E Corporation's common stock upon exercise of options granted under
PG&E Corporation's Stock Option Plan. The program was publicly
announced in a Current Report on Form 8-K filed by PG&E
Corporation on October 14, 2004. The program expired on
December 31, 2005.
|
(2)
|
On
December 15, 2004, the PG&E Corporation Board of Directors
authorized the repurchase of up to $975 million in PG&E
Corporation common stock. The program was publicly announced in a
Current
Report on Form 8-K filed by PG&E Corporation on December 16,
2004. On February 16, 2005, the Board of Directors increased the
repurchase authorization to $1.05 billion, which was announced in
PG&E Corporation’s Annual Report on Form 10-K for the year ended
December 31, 2004. PG&E Corporation used all of this authorization to
enter into an accelerated share repurchase arrangement on March 4,
2005
with Goldman, Sachs & Co., Inc., or GS&Co, to repurchase
29,489,400
shares at an initial price of $35.60 per share
.
Under
the share forward component of the March 2005 arrangement, certain
additional payments were required by both PG&E Corporation and
GS&Co upon termination. Most significantly, PG&E Corporation was
to receive from, or be required to pay to, GS&Co a price adjustment on
the repurchased shares based on the difference between the amount
it paid
and the daily volume weighted average price, or VWAP, of PG&E
Corporation common stock over the approximately six-month intended
arrangement period. PG&E Corporation made additional payments to
GS&Co of $78,000 on June 30, 2005 and $22 million on September 12,
2005. The amount of the price adjustment based on the VWAP of PG&E
Corporation common stock over the term of the arrangement increased
the
average purchase price per share to $36.19.
|
(3)
|
On
October 19, 2005, the PG&E Corporation Board of Directors authorized
the repurchase of up to $1.6 billion in shares of PG&E Corporation's
common stock, from time to time, but no later than December 31, 2006.
The
program was publicly announced in a
Current
Report on
Form
8-K filed by PG&E Corporation on October 21, 2005. As described in a
Current
Report on
Form 8-K filed by PG&E Corporation on November 18, 2005, PG&E
Corporation entered into an accelerated share repurchase arrangement
with
GS&Co on November 16, 2005 under which PG&E Corporation
repurchased 31,650,300 shares of its outstanding common stock at
an
initial price of $34.75 per share and an aggregate price of approximately
$1.1 billion. As with the March 2005arrangement, PG&E Corporation may
receive from, or be required to pay, GS&Co various payments, including
a price adjustment based on the daily VWAP of PG&E Corporation common
stock over a period of approximately seven
months.
|
Measure
|
2005
Results
|
2006
Target
|
||||
1.
|
Customer
Satisfaction (Residential & Business)
1
|
94.0
|
96.0
|
|||
2.
|
Timely
bills (% issued within 35 days)
|
99.38%
|
99.51%
|
|||
3.
|
Estimate
of Outage Restoration Accuracy
|
47%
|
50%
|
|||
4.
|
System
Average Interruption Duration Index (SAIDI)
2
|
178.7
|
166
|
|||
5.
|
System
Average Interruption Frequency Index (SAIFI)
2
|
1.344
|
1.31
|
|||
6.
|
Energy
Availability (Generation and Procurement)
3
|
--
3
|
--
3
|
|||
7.
|
Telephone
Service Level
4
|
75/20
|
76/20
|
|||
8.
|
Expense
Per Customer
|
$278
|
$283
5
|
|||
9.
|
Diablo
Canyon composite performance index
6
|
98.2
|
98.2
|
|||
10.
|
Employee
survey (Premier) index
|
64.0%
|
68.0%
|
|||
11.
|
Lost
workday case rate
7
|
1.04
|
0.878
|
Plan
Category
|
(a)
Number
of Securities to
be
Issued Upon Exercise
of
Outstanding Options,
Warrants
and Rights
|
(b)
Weighted
Average
Exercise
Price of
Outstanding
Options,
Warrants
and Rights
|
(c)
Number
of Securities
Remaining
Available for
Future
Issuance Under
Equity
Compensation Plans
(Excluding
Securities
Reflected
in Column(a))
|
|||
Equity
compensation plans approved by shareholders
|
12,012,774
|
$23.26
|
8,952,785(1)
|
|||
Equity
compensation plans not approved by shareholders
|
—
|
$—
|
—
|
|||
Total
equity compensation plans
|
12,012,774
|
$23.26
|
8,952,785
|
*By
|
BRUCE
R WORTHINGTON
(Bruce
R. Worthington, Attorney-in-Fact)
|
Balance
at December 31,
|
|||||||
2005
|
2004
|
||||||
ASSETS
|
|||||||
Cash
and cash equivalents
|
$
|
250
|
$
|
183
|
|||
Advances
to affiliates
|
38
|
22
|
|||||
Other
current assets
|
3
|
3
|
|||||
Total
current assets
|
291
|
208
|
|||||
Equipment
|
15
|
15
|
|||||
Accumulated
depreciation
|
(14
|
)
|
(13
|
)
|
|||
Net
equipment
|
1
|
2
|
|||||
Investments
in subsidiaries
|
7,401
|
8,848
|
|||||
Other
investments
|
71
|
31
|
|||||
Deferred
income taxes
|
127
|
104
|
|||||
Other
|
15
|
14
|
|||||
Total
Assets
|
$
|
7,906
|
$
|
9,207
|
|||
LIABILITIES
AND SHAREHOLDERS' EQUITY
|
|||||||
Current
Liabilities
|
|||||||
Accounts
payable—related parties
|
$
|
27
|
$
|
3
|
|||
Accounts
payable—other
|
17
|
15
|
|||||
Income
taxes payable
|
28
|
83
|
|||||
Other
|
193
|
53
|
|||||
Total
current liabilities
|
265
|
154
|
|||||
Noncurrent
Liabilities:
|
|||||||
Long-term
debt
|
280
|
280
|
|||||
Other
|
143
|
140
|
|||||
Total
noncurrent liabilities
|
423
|
420
|
|||||
Preferred
stock
|
—
|
—
|
|||||
Common
Shareholders' Equity
|
|||||||
Common
stock
|
5,827
|
6,518
|
|||||
Common
stock held by subsidiary
|
(718
|
)
|
(718
|
)
|
|||
Unearned
compensation
|
(22
|
)
|
(26
|
)
|
|||
Reinvested
earnings
|
2,139
|
2,863
|
|||||
Accumulated
other comprehensive loss
|
(8
|
)
|
(4
|
)
|
|||
Total
common shareholders' equity
|
7,218
|
8,633
|
|||||
Total
Liabilities and Shareholders' Equity
|
$
|
7,906
|
$
|
9,207
|
Year
Ended December 31,
|
||||||||||
2005
|
2004
|
2003
|
||||||||
Administrative
service revenue
|
$
|
97
|
$
|
85
|
$
|
101
|
||||
Equity
in earnings of subsidiaries
|
918
|
3,959
|
917
|
|||||||
Operating
expenses
|
(97
|
)
|
(110
|
)
|
(133
|
)
|
||||
Interest
income
|
9
|
15
|
20
|
|||||||
Interest
expense
|
(35
|
)
|
(132
|
)
|
(200
|
)
|
||||
Other
income (expense)
|
(17
|
)
|
(91
|
)
|
2
|
|||||
Income
before income taxes
|
875
|
3,726
|
707
|
|||||||
Income
tax benefit
|
29
|
|
94
|
|
84
|
|
||||
Income
from continuing operations
|
904
|
3,820
|
791
|
|||||||
Gain
on disposal of NEGT
|
13
|
684
|
—
|
|||||||
Discontinued
operations
|
—
|
—
|
(365
|
)
|
||||||
Cumulative
effect of changes in accounting principles
|
—
|
—
|
(6
|
)
|
||||||
Net
income before intercompany eliminations
|
$
|
917
|
$
|
4,504
|
$
|
420
|
||||
Weighted
average common shares outstanding
|
372
|
398
|
385
|
|||||||
Earnings
per common share, basic
(1)
|
$
|
2.40
|
$
|
10.80
|
$
|
1.04
|
||||
Earnings
per common share, diluted
(1)
|
$
|
2.37
|
$
|
10.57
|
$
|
1.02
|
|
Year
Ended December 31,
|
|
||||||||
|
|
2005
|
|
2004
|
|
2003
|
|
|||
Cash
Flows from Operating Activities:
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$
|
917
|
|
$
|
4,504
|
|
$
|
(420
|
)
|
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
|
)
|
|
—
|
|
Loss
from operations of NEGT (net of income tax benefit of $320
million)
|
|
|
—
|
|
|
—
|
|
|
365
|
|
Cumulative
effect of changes in accounting principles
|
|
|
—
|
|
|
—
|
|
|
6
|
|
Net
income from continuing operations
|
|
|
904
|
|
|
3,820
|
|
|
791
|
|
Adjustments
to reconcile net income to net cash provided by operating
activities:
|
|
|
|
|
|
|
|
|
|
|
Equity
in earnings of subsidiaries
|
|
|
(918
|
)
|
|
(3,959
|
)
|
|
(917
|
)
|
Deferred
taxes
|
|
|
(23
|
)
|
|
27
|
|
|
265
|
|
NEGT
settlement payment
|
|
|
—
|
|
|
(30
|
)
|
|
—
|
|
Other
|
|
|
86
|
|
|
160
|
|
|
391
|
|
Net
cash provided by operating activities
|
|
|
49
|
|
|
18
|
|
|
530
|
|
Cash
Flows From Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
Capital
expenditures
|
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
Investment
in subsidiaries
|
|
|
—
|
|
|
(28
|
)
|
|
—
|
|
Stock
repurchase by subsidiary
|
|
|
1,910
|
|
|
—
|
|
|
—
|
|
Dividends
received from subsidiaries
|
|
|
445
|
|
|
—
|
|
|
—
|
|
Increase
in restricted cash
|
|
|
—
|
|
|
361
|
|
|
—
|
|
Other
|
|
|
(38
|
)
|
|
—
|
|
|
—
|
|
Net
cash provided by investing activities
|
|
|
2,316
|
|
|
333
|
|
|
—
|
|
Cash
Flows From Financing Activities
(2)
:
|
|
|
|
|
|
|
|
|
|
|
Common
stock issued
|
|
|
243
|
|
|
162
|
|
|
166
|
|
Common
stock repurchased
|
|
|
(2,188
|
)
|
|
(350
|
)
|
|
—
|
|
Common
stock dividends paid
|
|
|
(334
|
)
|
|
—
|
|
|
—
|
|
Long-term
debt issued
|
|
|
—
|
|
|
—
|
|
|
581
|
|
Long-term
debt redeemed
|
|
|
(2
|
)
|
|
(652
|
)
|
|
(787
|
)
|
Other
|
|
|
(17
|
)
|
|
(1
|
)
|
|
1
|
|
Net
cash used by financing activities
|
|
|
(2,298
|
)
|
|
(841
|
)
|
|
(39
|
)
|
Net
change in cash and cash equivalents
|
|
|
67
|
|
|
(490
|
)
|
|
491
|
|
Cash
and cash equivalents at January 1
|
|
|
183
|
|
|
673
|
|
|
182
|
|
Cash
and cash equivalents at December 31
|
|
$
|
250
|
|
$
|
183
|
|
$
|
673
|
|
(1)
|
PG&E
Corporation adopted the consensus reached by Emerging Issues
Task Force,
or EITF, in EITF issue No. 03-06, "Participating Securities and the
Two-Class Method under FASB Statement No. 128," or EITF 03-06, as
ratified by the Financial Accounting Standards Board on March 31,
2004.
|
PG&E
Corporation currently has outstanding $280 million principal amount
of convertible subordinated 9.50% notes due 2010, or Convertible
Notes,
that are entitled to receive (non-cumulative) dividend payments
without
exercising the conversion option. These Convertible Notes,
which were
issued in June 2002, meet the criteria of a participating security in
the calculation of earnings per share using the "two-class"
method.
|
|
Accordingly,
the basic and diluted earnings per share calculations for
each of the
years in the three year period ended December 31, 2005 reflect the
allocation of earnings between PG&E Corporation common stock and the
participating security.
|
|
(2)
|
On
April 15, July 15 and October 17, 2005, PG&E Corporation paid a
quarterly common stock dividend of $0.30 per share, totaling
approximately
$356 million. Of the total dividend payments made by PG&E Corporation
in 2005, approximately $22 million was paid to Elm Power
Corporation, a
wholly owned subsidiary of PG&E Corporation. PG&E Corporation did
not pay any dividends during 2004 and
2003.
|
Additions
|
||||||||||||||||
Description
|
Balance
at
Beginning of Period
|
Charged
to Costs and
Expenses
|
Charged
to Other
Accounts
|
Deductions
(3)
|
Balance
at
End of Period
|
|||||||||||
(in
millions)
|
||||||||||||||||
Valuation
and qualifying accounts deducted from assets:
|
||||||||||||||||
2005
|
||||||||||||||||
Allowance
for uncollectible accounts
(1)
|
$
|
93
|
$
|
21
|
$
|
—
|
$
|
37
|
$
|
77
|
||||||
2004:
|
||||||||||||||||
Allowance
for uncollectible accounts
(1)(2)
|
$
|
68
|
$
|
85
|
$
|
—
|
$
|
60
|
$
|
93
|
||||||
2003:
|
||||||||||||||||
Allowance
for uncollectible accounts
(1)(2)
|
$
|
59
|
$
|
42
|
$
|
—
|
$
|
33
|
$
|
68
|
Additions
|
||||||||||||||||
Description
|
Balance
at
Beginning of Period
|
Charged
to Costs and
Expenses
|
Charged
to Other Accounts
|
Deductions
(2)
|
Balance
at
End of Period
|
|||||||||||
(in
millions)
|
||||||||||||||||
Valuation
and qualifying accounts deducted from assets:
|
||||||||||||||||
2005
|
||||||||||||||||
Allowance
for uncollectible accounts
(1)
|
$
|
93
|
$
|
21
|
$
|
—
|
$
|
37
|
$
|
77
|
||||||
2004:
|
||||||||||||||||
Allowance
for uncollectible accounts
(1)
|
$
|
68
|
$
|
85
|
$
|
—
|
$
|
60
|
$
|
93
|
||||||
2003:
|
||||||||||||||||
Allowance
for uncollectible accounts
(1)
|
$
|
59
|
$
|
42
|
$
|
—
|
$
|
33
|
$
|
68
|
Level
|
Rating
S&P/Moody’s
|
Applicable
Margin
for
ABR
Loans
|
Applicable
Margin
for
Eurodollar
Loans
|
1
|
A/A2
or higher
|
0%
|
0.180%
|
2
|
A-/A3
|
0%
|
0.220%
|
3
|
BBB+/Baa1
|
0%
|
0.310%
|
4
|
BBB/Baa2
|
0%
|
0.390%
|
5
|
BBB-/Baa3
|
0%
|
0.450%
|
6
|
BB+/Ba1
or lower
|
0%
|
0.675%
|
Level
|
Rating
S&P/Moody’s
|
Facility
Fee Rate
|
1
|
A/A2
or higher
|
0.070%
|
2
|
A-/A3
|
0.080%
|
3
|
BBB+/Baa1
|
0.090%
|
4
|
BBB/Baa2
|
0.110%
|
5
|
BBB-/Baa3
|
0.150%
|
6
|
BB+/Ba1
or lower
|
0.200%
|
Level
|
Rating
S&P/Moody’s
|
Utilization
Fee
Rate
|
1
|
A/A2
or higher
|
0.050%
|
2
|
A-/A3
|
0.050%
|
3
|
BBB+/Baa1
|
0.100%
|
4
|
BBB/Baa2
|
0.100%
|
5
|
BBB-/Baa3
|
0.100%
|
6
|
BB+/Ba1
or lower
|
0.125%
|
To:
|
PG&E
Corporation
One
Market Street Spear Tower
Suite
2400
San
Francisco, CA 94105
|
From:
|
Goldman,
Sachs & Co.
|
Subject:
|
Accelerated
Share Repurchase Transaction - VWAP Pricing
(Non-Collared)
|
Ref.
No:
|
As
provided in the Supplemental Confirmation
|
Date:
|
November
16, 2005
|
Trade
Date:
|
For
each Transaction, as set forth in the Supplemental
Confirmation.
|
Seller:
|
Counterparty
|
Buyer:
|
GS&Co.
|
Shares:
|
Common
Stock of Counterparty (Ticker: PCG)
|
Number
of Shares:
|
For
each Transaction, as set forth in the Supplemental
Confirmation.
|
Forward
Price:
|
For
each Transaction, as set forth in the Supplemental
Confirmation.
|
Prepayment:
|
Not
Applicable
|
Variable
Obligation:
|
Not
Applicable
|
Exchange:
|
New
York Stock Exchange
|
Related
Exchange(s):
|
All
Exchanges
|
Market
Disruption Event:
|
The
definition of “Market Disruption Event” in Section 6.3(a) of the Equity
Definitions is hereby amended by inserting the words “at any time on any
Scheduled Trading Day during the Valuation Period or” after the word
“material,” in the third line
thereof.
|
Valuation
Period:
|
Each
Scheduled Trading Day during the period commencing on and including
the
Valuation Period Start Date to and including the Valuation Date
(but
excluding any day(s) on which the Valuation Period is suspended
in
accordance with Section 5 herein and including any day(s) by which
the
Valuation Period is extended pursuant to the provision
below).
|
Notwithstanding
anything to the contrary in the Equity Definitions, to the extent
that any
Scheduled Trading Day in the Valuation Period is a Disrupted Day,
the
Valuation Date shall be postponed and the Calculation Agent in
its sole
discretion shall extend the Valuation Period and make adjustments
to the
weighting of each Relevant Price for purposes of determining the
Settlement Price, with such adjustments based on, among other factors,
the
duration of any Market Disruption Event and the volume, historical
trading
patterns and price of the Shares. To the extent that there are
9
consecutive Disrupted Days during the Valuation Period, then
notwithstanding the occurrence of a Disrupted Day, the Calculation
Agent
shall have the option in its sole discretion to either determine
the
Relevant Price using its good faith estimate of the value for the
Share on
such 9
th
consecutive Disrupted Day or elect to further extend the Valuation
Period
as it deems necessary or
appropriate.
|
Valuation
Period Start Date:
|
For
each Transaction, as set forth in the Supplemental
Confirmation.
|
Valuation
Date:
|
For
each Transaction, as set forth in the Supplemental Confirmation
(as the
same may be postponed in accordance with the provisions of “Valuation
Period” and Section 5 herein).
|
Settlement
Currency:
|
USD
(all amounts shall be converted to the Settlement Currency in good
faith
and in a commercially reasonable manner by the Calculation
Agent).
|
Settlement
Method Election:
|
Applicable;
provided that Section 7.1 of the Equity Definitions is hereby amended
by deleting the word “
Physical
”
in the sixth line thereof and replacing it with the words “
Net
Share
”
and deleting the word “Physical” in the last line thereof and replacing it
with the word “Cash”.
|
Electing
Party:
|
Counterparty
|
Settlement
Method Election Date:
|
10
Scheduled Trading Days prior to the originally scheduled Valuation
Date.
|
Default
Settlement Method:
|
Cash
Settlement
|
Forward
Cash Settlement Amount:
|
An
amount in the Settlement Currency equal to the product of (a) the
Number of Shares multiplied by (b) an amount equal to (i) the Settlement
Price minus (ii) the Forward Price.
|
Settlement
Price:
|
The
arithmetic mean of the Relevant Prices of the Shares for each Exchange
Business Day in the Valuation
Period.
|
Relevant
Price:
|
The
New York 10b-18 Volume Weighted Average Price per share of the
Shares for
the regular trading session (including any extensions thereof)
of the
Exchange on the related Exchange Business Day (without regard to
pre-open
or after hours trading outside of such regular trading session)
as
published by Bloomberg at 4:15 p.m. New York time on such date.
|
Cash
Settlement Payment Date:
|
3
Currency Business Days after the Valuation
Date.
|
for
Purpose of Giving Notice:
|
Nicholas
Bijur
|
Assistant
Treasurer
|
PG&E
Corporation
|
One
Market Street, Spear Tower
|
Suite
2400
|
San
Francisco, CA 94105
|
Telephone
No.: (415) 817-8199
|
Facsimile
No.: (415) 267-7265
|
With
a copy to:
|
Gary
Encinas
|
Chief
Counsel-Corporate
|
PG&E
Corporation
|
One
Market Street, Spear Tower
|
Suite
2400
|
San
Francisco, CA 94105
|
Telephone
No.: (415) 817-8201
|
Facsimile
No.: (415) 817-8225
|
Attention:
Equity Operations: Options and
Derivatives
|
With
a copy to:
|
Kelly
Coffey
|
Equity
Capital Markets
|
One
New York Plaza
|
New
York, NY 10004
|
Net
Share Settlement Procedures:
|
Net
Share Settlement shall be made in accordance with the procedures
attached
hereto as Annex B.
|
Net
Share Settlement Price:
|
The
Net Share Settlement Price shall be the price per Share as of the
Valuation Time on the Net Share Valuation Date as reported in the
official
real-time price dissemination mechanism for
the
Exchange. In the event Counterparty owes GS&Co. any amount,
the
Net Share Settlement Price shall be reduced by the per Share amount
of the
underwriting discount and/or commissions agreed to pursuant to
the
registration
agreement contemplated by Annex B.
|
Valuation
Time:
|
As
provided in Section 6.1 of the Equity Definitions; provided that
Section
6.1 of the Equity Definitions is hereby amended by inserting the
words
“Net Share,”
before
the words “Valuation Date” in the first and third lines
thereof.
|
Net
Share Valuation Date:
|
The
Exchange Business Day immediately following the Valuation
Date.
|
Net
Share Settlement Date:
|
The
third Exchange Business Day immediately following the Valuation
Date.
|
Reserved
Shares:
|
For
each Transaction, as set forth in the Supplemental
Confirmation.
|
Floating
Amount Payment Date:
|
The
Cash Settlement Payment Date
|
Floating
Amount:
|
For
each Transaction, an amount equal to the sum of the applicable
Federal
Funds Rate multiplied by (i) the Daily Notional Amount multiplied
by (ii)
1/360 for each day from and including the Floating Amount Accrual
Date to
and including the Valuation Date.
|
Floating
Amount Accrual Date:
|
Trade
Date
|
Federal
Funds Rate:
|
For
any date of determination, the “Fed Funds Open Rate,” which shall be the
interest rate reported on Bloomberg under the symbol “FEDSOPEN
<index>” on such date. For the avoidance of doubt, for any day which
is not a Currency Business Day the “Federal Funds Open Rate” for the
immediately preceding Currency Business Day shall
apply.
|
Daily
Notional Amount:
|
Commencing
with the Floating Amount Accrual Date, for any date of determination,
the
Daily Notional Amount shall be an amount equal to the product of
the
Initial Notional Amount (as set forth in the Supplemental Confirmation)
multiplied by a fraction with a numerator equal to the Originally
Scheduled Number of Scheduled Trading Days in the Valuation Period
minus
the number of Exchange Business Days in the Valuation Period that
have
elapsed (other than any days during which the Valuation Period
is
suspended pursuant to Section 5 herein) as of such date of determination
and a denominator equal to the Originally Scheduled Number of Scheduled
Trading Days in the Valuation Period (such fraction, the “Remaining
Percentage”).
|
To
the extent that the Valuation Period is extended pursuant to the
terms of
this Master Confirmation, the Calculation Agent shall adjust the
Daily
Notional Amount commencing with the first Exchange Business Day
after such
extension (the “Valuation Period Extension Date”). The notional amount
deemed to be remaining at the end of the Exchange Business Day
before the
Valuation Period Extension Date (the “Remaining Notional Value”) shall be
the Initial Notional Value multiplied by the Remaining Percentage
at the
end of such day. Commencing with the Valuation Period Extension
Date, for
any date of determination, the Daily Notional Amount shall be equal
to the
product of the Remaining Notional Value multiplied by a fraction
with (a)
a numerator equal to (i) the number of Scheduled Trading Days remaining
from and including the Valuation Period Extension Date to the Valuation
Date after extension (the “Remaining Scheduled Trading Days”) minus (ii)
the number of Exchange Business Days in the Valuation Period after
extension from and including the Valuation Period Extension Date
that have
elapsed (other than any days during which the Valuation Period
after
extension is suspended pursuant to Section 5 herein) as of such
date of
determination and (b) a denominator equal to the Remaining Scheduled
Trading Days.
|
Fixed
Amount Payment Date:
|
The
Cash Settlement Payment Date
|
Fixed
Amount:
|
For
each Transaction, an amount equal to the sum
of
(I)
the applicable Daily Additional Spread multiplied by (i) the
Daily
Notional Amount multiplied by (ii) 1/360
for each day from and including the Floating Amount Accrual Date
to and
including the Valuation Date
plus (II)
the applicable Fixed Rate
multiplied by (i)
the
Notional Amount multiplied by (ii)
1/360
for each day from and including the Floating Amount Accrual Date
to and
including the Valuation Date.
|
Fixed
Rate:
|
For
each Transaction, as set forth in the Supplemental
Confirmation.
|
Daily
Additional Spread:
|
The
Daily Additional Spread shall be
25
basis points
.
|
Notional
Amount:
|
For
any date of determination, 105% of the Daily Notional
Amount.
|
Counterparty
Additional
|
For
each Transaction, as set forth in the
Supplemental
|
Payment
Amount:
|
Confirmation.
|
Payment
Date:
|
The
Cash Settlement Payment Date.
|
Settlement
Currency:
|
USD
(all amounts shall be converted to the Settlement Currency in good
faith
and in a commercially reasonable manner by the Calculation
Agent).
|
Settlement
Method Election:
|
Applicable;
provided that Section 7.1 of the Equity Definitions is hereby amended
by deleting the word “Physical” in the sixth line thereof and replacing it
with the words “Net Share” and deleting the word “Physical” in the last
line thereof and replacing it with the word
“Cash”.
|
Electing
Party:
|
Counterparty
|
Settlement
Method Election Date:
|
10
Scheduled Trading Days prior to the originally scheduled Valuation
Date.
|
Default
Settlement Method:
|
Cash
Settlement
|
Method
of Adjustment:
|
Calculation
Agent Adjustment
|
Consequences
of Merger Events:
|
Subject
to Section 7(b) of the Master
Confirmation:
|
(a)
|
Share-for-Share:
|
Modified
Calculation Agent Adjustment
|
(b)
|
Share-for-Other:
|
Cancellation
and Payment on that portion of the Other Consideration that consists
of
cash; Modified Calculation Agent Adjustment on the remainder of
the Other
Consideration.
|
(c)
|
Share-for-Combined:
|
Component
Adjustment
|
Determining
Party:
|
GS&Co.
|
Tender
Offer:
|
Applicable
|
Consequences
of Tender Offers:
|
Subject
to Section 7(b) of the Master
Confirmation:
|
(a)
|
Share-for-Share:
|
Modified
Calculation Agent Adjustment
|
(b)
|
Share-for-Other:
|
Cancellation
and Payment on that portion of the Other Consideration that consists
of
cash; Modified Calculation Agent Adjustment on the remainder of
the Other
Consideration.
|
(c)
|
Share-for-Combined:
|
Component
Adjustment
|
Nationalization,
Insolvency or Delisting:
|
Subject
to Section 7(a) of this Master Confirmation, Negotiated Close-out;
provided that in addition to the provisions of Section 12.6(a)(iii)
of the
Equity Definitions, it shall also constitute a Delisting if the
Exchange
is located in the United States and the Shares are not immediately
re-listed, re-traded or re-quoted on any of the New York Stock
Exchange,
the American Stock Exchange or The NASDAQ National Market (or their
respective successors); if the Shares are immediately re-listed,
re-traded
or re-quoted on any such exchange or quotation system, such exchange
or
quotation system shall be deemed to be the
Exchange.
|
Determining
Party:
|
GS&Co.
|
Additional
Acknowledgements:
|
Applicable
|
Extraordinary
Event:
|
Counterparty
shall have the right, in its sole discretion, to elect that any
payment
required to be made pursuant to Sections 12.7 or 12.9 of the Equity
Definitions (except with respect to any portion of the consideration
for
the Shares consisting of cash in the event of a Merger Event or
Tender
Offer) following the occurrence of an Extraordinary Event by Net
Share
Settlement of the Transactions under this Master Confirmation in
accordance with the terms, and subject to the conditions, for Net
Share
Settlement herein by giving written notice to GS&Co. of such election
on the day that the notice fixing the date that the Transactions
are
terminated or cancelled, as the case may be (the “Cancellation Date”),
pursuant to the applicable provisions of Section 12 of the Equity
Definitions is effective. If Counterparty elects Net Share Settlement:
(a) the Net Share Valuation Date shall be the date specified in the
notice fixing the date that the Transactions are terminated or
cancelled,
as the case may be; provided that the Net Share Valuation Date
shall be
either the Exchange Business Day that such notice is effective
or the
first Exchange Business Day immediately following the Exchange
Business
Day that such notice is effective, (b) the Net Share Settlement
Date shall
be deemed to be the Exchange Business Day immediately following
the
Cancellation Date and (c) all references to the Forward Cash Settlement
Amount
,
the Fixed Amount, the Floating Rate Amount and the Counterparty
Additional
Payment Amount, as the case may be, in Annex B hereto shall be
deemed to
be references to the Cancellation Amount.
The
definition of “Cancellation Amount” in Section 12.8 of the Equity
Definitions is hereby amended by inserting the following paragraph:
“(h)
The Determining Party shall show the other party in reasonable
detail its
calculation of the Cancellation Amount, including without limitation
providing all relevant quotations and assumptions and specifying
the
methodologies used in sufficient detail so as to enable the other
party to
replicate the calculation”.
|
Net
Share Settlement Upon
Early Termination:
|
Counterparty
shall have the right, in its sole discretion, to elect that any
payment
required to be made (the “Early Termination Amount”) pursuant to
Sections 6(d) and 6(e) of the Agreement following the occurrence of
an Early Termination Date in respect of the Agreement by Net Share
Settlement of all the Transactions under this Master Confirmation
in
accordance with the terms, and subject to the conditions, for Net
Share
Settlement herein by giving written notice to GS&Co. of such election
on the day that the notice fixing an Early Termination Date is
effective.
If Counterparty elects Net Share Settlement: (a) the Net Share
Valuation Date shall be the date specified in the notice fixing
an Early
Termination Date; provided that the Net Share Valuation Date shall
be
either the Exchange Business Day that such notice is effective
or the
first Exchange Business Day immediately following the Exchange
Business
Day that such notice is effective, (b) the Net Share Settlement
Date shall
be deemed to be the Exchange Business Day immediately following
the Early
Termination Date
(except
for an Early Termination as a result of Section 7(d), in which
event the
Net Share Settlement Date shall be deemed to be the tenth Exchange
Business Day following the Early Termination Date)
and
(c) all references to Forward Cash Settlement Amount
,
the Fixed
Amount, the Floating Rate Amount and the Counterparty Additional
Payment
Amount, as the case may be, in Annex B hereto shall be deemed references
to the Early Termination Amount.
|
Transfer:
|
Notwithstanding
anything to the contrary in the Agreement, GS&Co. may assign, transfer
and set over all rights, title and interest, powers, privileges
and
remedies of GS&Co. under any Transaction, in whole or in part, to an
affiliate of GS&Co. that is fully and unconditionally guaranteed by
The Goldman Sachs Group, Inc. without the consent of Counterparty,
provided that Counterparty is not required to make a payment to
GS&Co.
in respect of an Indemnifiable Tax as a result of such
transfer.
|
GS&Co.
Payment Instructions:
|
Chase
Manhattan Bank New York
|
Counterparty
Payment Instructions:
|
PG&E
Corporation Master Account No.
099023
|
Mellon
Trust of New England, N.A.
|
Boston,
MA
|
ABA
Routing No: 011001234
|
To:
|
PG&E
Corporation
One
Market Street, Spear Tower
Suite
2400
San
Francisco, CA 94105
|
From:
|
Goldman,
Sachs & Co.
|
Subject:
|
Accelerated
Share Repurchase Transaction - VWAP Pricing
|
Ref.
No:
|
EN51R8000000000
|
Date:
|
November
16, 2005
|
Trade
Date:
|
November
16, 2005
|
Forward
Price:
|
USD
34.75 per Share
|
Number
of Shares:
|
31,650,300
Shares
|
Valuation
Period Start Date:
|
November
17, 2005
|
Valuation
Date:
|
June
8, 2006
|
Termination
Price:
|
$10.00
per Share
|
Fixed
Rate:
|
25
basis points
|
Reserved
Shares:
|
Two
times the Number of Shares
|
Extraordinary
Dividends:
|
Any
cash dividend declared by the Issuer in excess of $0.00 per Share;
provided that the cash dividend declared by the Counterparty in
December
2005 shall not be an Extraordinary
Dividend.
|
Initial
Number of Daily Reference Shares:
|
227,700
Shares
|
Initial
Notional Amount:
|
The
Number of Shares multiplied by the Forward Price.
|
Counterparty
Additional Payment Amount:
|
USD
8,415,792.00
|
Where
|
A
=
the number of authorized but unissued shares of the Issuer that
are not
reserved for future issuance on the date of the determination of
the
Capped Number; and
|
B
=
the maximum number of Shares required to be delivered to third
parties if
Counterparty elected Net Share Settlement of all transactions in
the
Shares (other than Transactions in the Shares under this Master
Confirmation) with all third parties that are then currently outstanding
and unexercised.
|
1. |
An
annual base salary of $475,000 ($39,583.33/month) subject to possible
increases through our annual salary review
plan.
|
2. |
A
target incentive of $261,250 (55% of your base salary) in an annual
short-term incentive plan under which your actual incentive dollars
may
range from zero to $522,500 based on performance relative to established
goals. For 2005, this incentive will be prorated for the number of
months
worked from your date of hire and will be payable in 2006.
|
3. |
Participation
in the PG&E Corporation Long-Term Incentive Plan (LTIP) as a band 2
officer. Your initial LTIP grant will take the form of restricted
stock
with annual time-based vesting over four calendar years on the first
business days of January 2006, 2007, 2008, and 2009, respectively.
That
grant will have an initial value of $400,000, which will be converted
to
shares of restricted stock based on the closing price of PG&E
Corporation common stock on your date of hire. You will also receive
a
2006 LTIP grant with an initial value of $800,000. That grant will
be spit
equally between restricted stock and performance shares, and will
be made
on the first business day of January 2006. The ultimate value that
you
realize from these grants will depend upon your employment status
and the
performance of PG&E Corporation common
stock.
|
4. |
Participation
in the PG&E Corporation Supplemental Executive Retirement Plan (SERP).
The basic benefit payable from the SERP at retirement is a monthly
annuity
equal to the product of 1.7% x [average of the three highest years’
combination of salary and annual incentive for the last ten years
of
service] x years of credited service x
1/12.
|
5. |
Participation
in the PG&E Corporation Retirement Savings Plan (RSP), a 401(k)
savings plan. You will be eligible to contribute as much as 20% of
your
salary on either a pre-tax or after-tax basis, subject to legal limits.
After your first year of service, we will match contributions you
make up
to 3% of your salary at 75 cents on each dollar contributed for the
first
three years of employment. Thereafter, we will match contributions
up to
6% of your salary at 75 cents on each dollar
contributed.
|
6. |
Participation
in the PG&E Corporation Supplemental Retirement Savings Plan (SRSP), a
non-qualified, deferred compensation plan. You may elect to defer
payment
of some of your compensation on a pre-tax basis. We will provide
you with
the full matching contributions that cannot be provided through the
RSP,
due to legal limitations imposed on highly compensated employees.
|
7. |
Participation
in a cafeteria-style benefits program that permits you to select
coverage
tailored to your personal needs and circumstances. The benefits you
elect
will be effective the first of the month following the date of your
hire.
|
8. |
PG&E
Corporation also offers employees an initial allocation of Paid Time
Off
(PTO) upon hire; this initial allocation may be up to 160 hours based
on
start date. Future allocations of PTO are made each year on January
1 and
are based on your start date and amount worked in the preceding year.
For
example, by starting work in November and working full-time for the
remainder of 2005, you will be eligible for 80 hours of PTO upon
hire and
27 hours on January 1, 2006. Beginning January 1, 2007, you will
be
eligible for 160 hours of PTO, provided that you work full-time for
all of
2006. In addition, PG&E Corporation recognizes 10 paid company
holidays annually and provides 3 floating holidays immediately upon
hire
and at the beginning of each year.
|
9. |
An
annual perquisite allowance of $25,000 to be used in lieu of individual
authorizations for cars and memberships in clubs and civic organizations.
For 2005, you will receive 50% of this amount
($12,500).
|
10. |
A
comprehensive executive relocation assistance package, including:
(1) the
reimbursement of closing costs on the sale of your current residence,
contingent upon using a PG&E-designated relocation company and
purchasing a new residence; (2) the move of your household goods,
including 60 days of storage and the movement of the goods out of
storage;
and (3) a lump sum payment of $10,000 payable within 60 days of your
date
of employment. Should you have any questions regarding the relocation
package, please contact Denise Nicco, Director of Relocation at (415)
817-8230.
|
Measure
|
2005
Results
|
2006
Target
|
|
1.
|
Customer
Satisfaction (Residential & Business)
1
|
94.0
|
96.0
|
2.
|
Timely
bills (% issued within 35 days)
|
99.38%
|
99.51%
|
3.
|
Estimate
of Outage Restoration Accuracy
|
47%
|
50%
|
4.
|
System
Average Interruption Duration Index (SAIDI)
2
|
178.7
|
166
|
5.
|
System
Average Interruption Frequency Index (SAIFI)
2
|
1.344
|
1.31
|
6.
|
Energy
Availability (Generation and Procurement)
3
|
--
3
|
--
3
|
7.
|
Telephone
Service Level
4
|
75/20
|
76/20
|
8.
|
Expense
Per Customer
|
$278
|
$283
5
|
9.
|
Diablo
Canyon composite performance index
6
|
98.2
|
98.2
|
10.
|
Employee
survey (Premier) index
|
64.0%
|
68.0%
|
11.
|
Lost
workday case rate
7
|
1.04
|
0.878
|
Name
and Title
|
2006
Base Salary
|
2006
STIP % Target
|
Peter
A. Darbee, Chairman of the Boards, Chief Executive Officer and President,
PG&E Corporation
|
$975,000
|
100%
|
Thomas
B. King, President and Chief Executive Officer, Utility
|
$615,000
|
75%
|
Christopher
P. Johns, Senior Vice President, Chief Financial Officer and Treasurer,
PG&E Corporation and Utility
|
$494,000
|
55%
|
Bruce
R. Worthington, Senior Vice President and General Counsel, PG&E
Corporation
|
$489,250
|
55%
|
Rand
L. Rosenberg, Senior Vice President, Corporate Strategy and Development,
PG&E Corporation
|
$475,000
|
55%
|
Name
and Title
|
2006
LTIP Award Value
|
Peter
A. Darbee, Chairman of the Boards, Chief Executive Officer and President,
PG&E Corporation
|
$3,500,000
|
Thomas
B. King, President and Chief Executive Officer, Utility
|
$1,450,000
|
Christopher
P. Johns, Senior Vice President, Chief Financial Officer and Treasurer,
PG&E Corporation and Utility
|
$900,000
|
Bruce
R. Worthington, Senior Vice President and General Counsel, PG&E
Corporation
|
$800,000
|
Rand
L. Rosenberg, Senior Vice President, Corporate Strategy and
Development
|
$800,000
|
TABLE
OF CONTENTS
|
Page
|
||
|
Establishment,
Purpose and Term of Plan
|
1
|
|
1.1
|
Establishment
|
1
|
|
1.2
|
Purpose
|
1
|
|
1.3
|
Term
of Plan
|
1
|
|
2.
|
Definitions
and Construction
|
1
|
|
2.1
|
Definitions
|
1
|
|
2.2
|
Construction
|
7
|
|
3.
|
Administration
|
7
|
|
3.1
|
Administration
by the Committee
|
7
|
|
3.2
|
Authority
of Officers
|
7
|
|
3.3
|
Administration
with Respect to Insiders
|
8
|
|
3.4
|
Committee
Complying with Section 162(m)
|
8
|
|
3.5
|
Powers
of the Committee
|
8
|
|
3.6
|
Option
or SAR Repricing
|
9
|
|
3.7
|
Indemnification
|
9
|
|
4.
|
Shares
Subject to Plan
|
10
|
|
4.1
|
Maximum
Number of Shares Issuable
|
10
|
|
4.2
|
Adjustments
for Changes in Capital Structure
|
10
|
|
5.
|
Eligibility
and Award Limitations
|
11
|
|
5.1
|
Persons
Eligible for Awards
|
11
|
|
5.2
|
Participation
|
11
|
|
5.3
|
Incentive
Stock Option Limitations
|
11
|
|
5.4
|
Award
Limits
|
12
|
|
6.
|
Terms
and Conditions of Options
|
13
|
|
6.1
|
Exercise
Price
|
13
|
|
6.2
|
Exercisability
and Term of Options
|
13
|
|
6.3
|
Payment
of Exercise Price
|
13
|
|
6.4
|
Effect
of Termination of Service
|
14
|
|
6.5
|
Transferability
of Options
|
14
|
|
7.
|
Terms
and Conditions of Nonemployee Director Awards
|
15
|
|
7.1
|
Automatic
Grant of Restricted Stock
|
15
|
|
7.2
|
Annual
Election to Receive Nonstatutory Stock Option and Restricted Stock
Units
|
15
|
|
7.3
|
Grant
of Nonstatutory Stock Option
|
15
|
TABLE
OF CONTENTS
(continued)
|
Page
|
||
7.4
|
Grant
of Restricted Stock Unit
|
16
|
|
7.5
|
Effect
of Termination of Service as a Nonemployee Director
|
17
|
|
7.6
|
Effect
of Change in Control on Nonemployee Director Awards
|
18
|
|
7.7
|
Right
to Decline Nonemployee Director Awards
|
18
|
|
8.
|
Terms
and Conditions of Stock Appreciation Rights
|
19
|
|
8.1
|
Types
of SARs Authorized
|
19
|
|
8.2
|
Exercise
Price
|
19
|
|
8.3
|
Exercisability
and Term of SARs
|
19
|
|
8.4
|
Deemed
Exercise of SARs
|
19
|
|
8.5
|
Effect
of Termination of Service
|
20
|
|
8.6
|
Nontransferability
of SARs
|
20
|
|
9.
|
Terms
and Conditions of Restricted Stock Awards
|
20
|
|
9.1
|
Types
of Restricted Stock Awards Authorized
|
20
|
|
9.2
|
Purchase
Price
|
20
|
|
9.3
|
Purchase
Period
|
20
|
|
9.4
|
Vesting
and Restrictions on Transfer
|
20
|
|
9.5
|
Voting
Rights, Dividends and Distributions
|
21
|
|
9.6
|
Effect
of Termination of Service
|
21
|
|
9.7
|
Nontransferability
of Restricted Stock Award Rights
|
21
|
|
10.
|
Terms
and Conditions of Performance Awards
|
21
|
|
10.1
|
Types
of Performance Awards Authorized
|
22
|
|
10.2
|
Initial
Value of Performance Shares and Performance Units
|
22
|
|
10.3
|
Establishment
of Performance Period, Performance Goals and Performance Award
Formula
|
22
|
|
10.4
|
Measurement
of Performance Goals
|
22
|
|
10.5
|
Settlement
of Performance Awards
|
23
|
|
10.6
|
Voting
Rights, Dividend Equivalent Rights and Distributions
|
24
|
|
10.7
|
Effect
of Termination of Service
|
24
|
|
10.8
|
Nontransferability
of Performance Awards
|
25
|
|
11.
|
Terms
and Conditions of Restricted Stock Unit Awards
|
25
|
|
11.1
|
Grant
of Restricted Stock Unit Awards
|
25
|
|
11.2
|
Vesting
|
25
|
|
11.3
|
Voting
Rights, Dividend Equivalent Rights and Distributions
|
25
|
|
11.4
|
Effect
of Termination of Service
|
26
|
|
11.5
|
Settlement
of Restricted Stock Unit Awards
|
26
|
|
11.6
|
Nontransferability
of Restricted Stock Unit Awards
|
26
|
TABLE
OF CONTENTS
(continued)
|
Page
|
||
12.
|
Deferred
Compensation Awards
|
27
|
|
12.1
|
Establishment
of Deferred Compensation Award Programs
|
27
|
|
12.2
|
Terms
and Conditions of Deferred Compensation Awards
|
27
|
|
13.
|
Other
Stock-Based Awards
|
28
|
|
14.
|
Change
in Control
|
28
|
|
14.1
|
Effect
of Change in Control on Options and SARs
|
28
|
|
14.2
|
Effect
of Change in Control on Restricted Stock and Other Awards
|
29
|
|
14.3
|
Nonemployee
Director Awards
|
29
|
|
15.
|
Compliance
with Securities Law
|
29
|
|
16.
|
Tax
Withholding
|
29
|
|
16.1
|
Tax
Withholding in General
|
29
|
|
16.2
|
Withholding
in Shares
|
30
|
|
17.
|
Amendment
or Termination of Plan
|
30
|
|
18.
|
Miscellaneous
Provisions
|
30
|
|
18.1
|
Repurchase
Rights
|
30
|
|
18.2
|
Provision
of Information
|
30
|
|
18.3
|
Rights
as Employee, Consultant or Director
|
30
|
|
18.4
|
Rights
as a Shareholder
|
31
|
|
18.5
|
Fractional
Shares
|
31
|
|
18.6
|
Severability
|
31
|
|
18.7
|
Beneficiary
Designation
|
31
|
|
18.8
|
Unfunded
Obligation
|
31
|
|
18.9
|
Choice
of Law
|
32
|
|
December 15,
2004
|
Board
adopts Plan with a reserve of 12 million shares.
|
April
20, 2005
|
Shareholders
approve Plan.
|
January
1, 2006
|
Plan
Effective Date
|
February
15, 2006
|
Change
in control provisions are amended
|
PG&E
CORPORATION
|
EXECUTIVE
STOCK OWNERSHIP PROGRAM
|
1. |
Description
.
The Executive Stock Ownership Program (“Program”) was approved by the
Nominating and Compensation Committee of the Board of Directors on
October
15, 1997. The Program is an important element of the Committee’s
compensation policy of aligning executive interests with those of
the
Corporation’s shareholders. As an integral part of the Program, the
Committee also authorized the use of Special Incentive Stock Ownership
Premiums (“SISOPs”) which are designed to provide incentives to Eligible
Executives to assist in achieving minimum stock ownership targets
established by the Committee. These Guidelines were originally adopted
by
the Committee on November 19, 1997, amended by the Committee on July
22,
1998, October 21, 1998, February 16, 2000, September 19, 2000, February
19, 2003, and February 15, 2006. These amended Guidelines, along
with the
written materials provided to the Committee on October 15, 1997,
describe
the Program which became effective on January 1, 1998. The Program
is
administered by the Corporation’s Senior Human Resources
Officer.
|
2. |
Eligible
Executives
.
The Chief Executive Officer shall designate the officers of the
Corporation and its affiliates who shall be Eligible Executives covered
by
the Program. The officers covered by the Guidelines and the applicable
total stock ownership target (“Target”) are:
|
Officer
Band
|
Position
|
Total
Stock
Ownership
Target
|
1
|
CEO
|
3
x
base salary
|
2
|
Heads
of Business Lines, CFO, & General Counsel
|
2
x
base salary
|
3
|
SVPs
of Corp. & Utility
|
1.5
x base salary
|
3. |
Annual
Milestones
.
Under the Guidelines, Targets are designed to be achieved by the
end of
the fifth calendar year following the calendar year in which an officer
first becomes an Eligible Executive (“Target Date”). Annual Milestones
have been established as a means of measuring progress towards achieving
Targets and of providing incentives for Eligible Executives to
expeditiously meet their Targets. The Annual Milestone at the end
of the
first full calendar year is 20 percent of the Target, and the Annual
Milestone for each succeeding year is an additional 20 percent of
the
Target. Annual Milestones shall be adjusted to reflect changes in
base
salary; provided, however, that in each instance any such modification
shall be amortized over the remaining original five-year term. Following
the Target Date, Targets also shall be modified to reflect changes
in base
salary.
|
4. |
Calculation
of Stock Ownership Levels
.
Stock ownership level is the dollar value of stock and stock equivalents
owned by an Eligible Executive and calculated as of the last day
of the
calendar year (“Measurement Date”). The purpose of this calculation is to
determine the value of the stock or stock equivalents owned by the
Eligible Executive as compared with the Annual Milestone or Target
for
that executive. For purposes of this calculation, the value per share
of
stock or stock equivalent ("Measurement Value") is the average closing
price of PG&E Corporation common stock as traded on the New York Stock
Exchange for the last thirty (30) trading days of the
year.
|
a) |
The
value of stock beneficially owned by the Eligible Executive is determined
by multiplying the number of shares owned beneficially on the Measurement
Date times the Measurement Value.
|
b) |
The
value of PG&E Corporation phantom stock units credited to the Eligible
Executive's account in the PG&E Corporation Supplemental Retirement
Savings Plan (“SRSP”) is determined by multiplying the number of phantom
stock units credited to the Eligible Executive's SRSP account on
the
Measurement Date times the Measurement
Value.
|
c) |
The
value of stock held in the PG&E Corporation stock fund of any defined
contribution plan maintained by PG&E Corporation or any of its
subsidiaries is determined by multiplying the number of shares in
such
plan on the Measurement Date times the Measurement
Value.
|
d) |
The
value of restricted stock held by the Eligible Executive is determined
by
multiplying the number of shares held by the Eligible Executive on
the
Measurement Date times the Measurement Value (for purposes of this
calculation, restricted stock shall include any shares that have
been
approved by the Nominating, Compensation and Governance Committee
but not
yet issued as of the Measurement Date).
|
e) |
For
Eligible Executive’s whose Target Date is on or before 12/31/2004, the
value of the frozen share-equivalent units of the vested "in the
money"
stock options as of 12/31/2000 is the difference between the number
of
options on 12/31/2000 multiplied by the Measurement Value on 12/31/2000
minus the number of options on 12/31/2000 multiplied by the option
exercise price (for purposes of this calculation, any value attributable
to dividend equivalents is excluded).
|
5. |
Award
of SISOPs
.
SISOPs are awarded to Eligible Executives who achieve and maintain
stock
ownership levels prior to the end of the third year following the
year in
which an officer first became an Eligible Executive. For purposes
of
determining awards, the total stock ownership level is calculated
as set
forth under paragraph 4 on the Measurement Date; however, such
calculations will exclude the value of restricted stock held by the
Eligible Executive as defined in paragraph 4(d). The amount of a
SISOP
award shall be equal to:
|
a) |
For
the first year, 20 percent of the amount of the Eligible Executive’s stock
ownership level at the end of the year, up to the Annual Milestone,
plus
an additional 30 percent of the amount by which the stock ownership
level
exceeds the Annual Milestone up to the Target;
and
|
b) |
For
each of the second and third years, the current stock ownership level
is
reduced by the stock ownership level used to calculate previous SISOP
awards to determine the new ownership, then 20 percent of the amount
up to
the Annual Milestone by which the end of the year stock ownership
level
exceeds the beginning of the year stock ownership level, plus an
additional 30 percent of the amount by which the end of the year
balance
exceeds the Annual Milestone, up to the
Target.
|
6. |
SISOPs
Credited to the SRSP.
Upon award, SISOPs are credited to the Eligible Executive's SRSP
account
and converted into units of phantom stock each equal in value to
a share
of PG&E Corporation common stock ("SISOP units") as determined in
accordance with the SRSP. The SISOP units constitute "incentive awards"
authorized to be awarded by the Committee to Eligible Executives
under the
PG&E Corporation 2006 Long-Term Incentive Plan ("2006 LTIP"). Upon
credit of SISOP units to an Eligible Executive's SRSP account, an
equal
number of shares of PG&E Corporation common stock shall be reserved
for issuance from the pool of shares authorized for issuance under
the
2006 LTIP. Once a SISOP unit is credited to the Eligible Executive's
SRSP
account, it shall be subject to all of the terms and conditions
specifically applicable to SISOP units under the SRSP. Once vested
in
accordance with paragraph 7 below, SISOP units are distributed in
the form
of an equal number of shares of PG&E Corporation common stock as
provided in the SRSP.
|
7. |
Vesting.
SISOPs vest only upon the expiration of three years after the date
of
award (provided the Eligible Executive continues to be employed on
such
date). An Eligible Executive's unvested SISOPs will be forfeited
upon
termination of employment except as otherwise provided in the Vesting
Guidelines in effect on the grant date for a particular award.
|
8. |
Forfeiture
of SISOP Units
.
So long as SISOP units remain unvested, such units are subject to
forfeiture if, on each Measurement Date, the Eligible Executive's
stock
ownership is less than the Minimum Ownership Level established when
the
SISOPs were granted (see paragraph 5). To determine forfeiture, the
following steps are followed on each Measurement
Date:
|
a) |
The
total stock and stock equivalents owned by an Eligible Executive
is
determined as set forth under paragraph 4, excluding section 4(d).
This
total ("Current Holdings") is compared with the Minimum Ownership
Level
determined when the SISOPs were granted. If the Current Holdings
are equal
to or greater than the Minimum Ownership Level, then no unvested
SISOP
units are forfeited. If the Current Holdings are less than the Minimum
Ownership Level, then the unvested SISOP units are forfeited in the
same
proportion as the Current Holdings are less than Minimum Ownership
Level
(for example, if the Current Holdings are 20 percent less than the
Minimum
Ownership Level, then 20 percent of the SISOP units are
forfeited).
|
9. |
Failure
to Achieve or Maintain Target.
Failure to achieve stock ownership levels at Target on the Target
Date, or
to maintain stock ownership levels at Target on any Measurement Date
thereafter, will result in the deferral into the PG&E Corporation
Phantom Stock Fund of the SRSP of awards from the PG&E Corporation
Long-Term Incentive Program and/or 2006 LTIP that are settled only
in cash
(“Cash-Settled Awards”), and the Short-Term Incentive Plan (“STIP”). As of
any Measurement Date, to the extent that stock ownership levels are
below
Target, Cash-Settled Awards shall be converted into PG&E Corporation
Phantom Stock Units and held in the PG&E Corporation Phantom Stock
Fund of the SRSP. If, with the addition of the phantom stock units
attributable to the Cash-Settled Awards, the stock ownership level
is
still below Target for any Measurement Date, any STIP award above
target
STIP also shall be converted into phantom stock units, to the extent
necessary to achieve the Target stock ownership level. Such conversion
of
Cash-Settled Awards and STIP awards shall continue for successive
Measurement Dates, if necessary, until Target is met. Phantom stock
units
attributable to Cash-Settled Awards and STIP awards described in
this
paragraph 9 will be paid from the SRSP in a lump sum in the seventh
month
following the month in which the Eligible Executive's employment
terminates.
|
1. |
Purpose
|
2. |
Termination
of Employment Not Following a Change in Control or Potential Change
in
Control
|
(a) |
Corporation
or Employer’s Obligations
.
If the Corporation or an Employer exercises its right to terminate
an
Officer’s employment without cause and such termination does not entitle
Officer to payments under Section 3, the Officer shall be given thirty
(30) days’ advance written notice or pay in lieu thereof. Except as
provided in Section 2(b) below, in consideration of the Officer's
agreement to the obligations described in Section 2(d) below and
to the
arbitration provisions described in Section 12 below,
the
following payments and benefits shall also be provided to
Officer:
2
/
|
(1) |
A
lump sum severance payment equal to: 1/12 (the sum of the Officer’s annual
base compensation and the Officer’s Short-Term Incentive Plan target award
at the time of his or her termination) times (the number of
|
1
/
|
Severance
benefits for Officers who are currently covered by an employment
agreement
will continue to be provided solely under such agreements
until their
expiration at which time this Policy will become effective
for such
Officers.
|
2/
|
Any
payments made hereunder shall be less applicable taxes.
|
(2) |
If
Officer is a participant in the Supplemental Executive Retirement
Plan of
PG&E Corporation (SERP) and Officer’s age is less than 55 years, such
portion of the amount described in the preceding Section 2(a)(1)
to
provide for additional years to Officer's age to age 55 shall be
converted
for purposes of calculating a benefit under the SERP. Any amount
of
severance payment remaining after conversion under this subsection
shall
be paid to Officer in a lump sum. The value of any amount so converted
shall be calculated using the same actuarial factors used in calculating
benefits under the Retirement Plan for Employees of Pacific Gas and
Electric Company. If Officer is a participant in the SERP and if
the
additional age resulting from a conversion under Section 2(a)(2)
does not
result in an age of 55, Officer shall be paid the amount calculated
under
2(a)(1) in a lump sum;
|
(3) |
The
incentive awards granted to Officer under the Corporation’s Long-Term
Incentive Program which have not yet vested as of the date of termination
will continue to vest over a period of months equal to the Severance
Multiple after the date of termination as if the Officer had remained
employed for such period. For vested stock options as of the date
of
termination, the Officer shall have the right to exercise such stock
options at any time within their respective terms or within five
years
after termination, whichever is shorter. For stock options that vest
during a period of months equal to the Severance Multiple, the Officer
shall have the right to exercise such options at any time within
five
years after termination. Any unvested incentive awards remaining
at the
end of such period shall be forfeited;
|
(4) |
For
Officers in Officer Bands I, II or III, two thirds of the unvested
Company
stock units in the Officer's account in the Corporation's Deferred
Compensation Plan for Officers which were awarded in connection with
the
Executive Stock Ownership Program requirements ("SISOPs") shall vest
upon
the Officer's termination, and one third shall be forfeited. For
Officers
in Officer Bands IV and V, one third of any unvested SISOPs shall
vest
upon the Officer's termination, and two thirds shall be forfeited.
Unvested stock units attributable to SISOPs which become vested under
this
provision shall be distributed to Officer in accordance with the
Deferred
Compensation Plan after such stock units vest;
|
(5) |
For
a period of 18 months, the Officer's COBRA premiums, if any;
|
(6) |
If
Officer is terminated after serving consecutively for six months
in a
fiscal year, Officer shall be entitled to receive a prorated bonus
under
any short-term incentive plan in which such Officer participates,
at the
time such bonus would otherwise be paid, if any;
|
(7) |
To
the extent not theretofore paid or provided, the Officer shall be
paid or
provided with any other amounts or benefits required to be paid or
provided or which the Officer is eligible to receive under any plan,
contract or agreement of the Corporation or Employer;
|
(8) |
Such
career transition services as the Corporation's Senior Human Resources
Officer shall determine is appropriate;
and
|
(9) |
All
acts required of the Employer under the Policy may be performed by
the
Corporation for itself and the Employer, and the costs of the Policy
may
be equitably apportioned by the Administrator among the Corporation
and
the other Employers. The Corporation shall be responsible for making
payments and providing benefits pursuant to this Policy for Officers
employed by the Corporation. Whenever the Employer is permitted or
required under the terms of the Policy to do or perform any act,
matter or
thing, it shall be done and performed by any Officer or employee
of the
Employer who is thereunto duly authorized by the board of directors
of the
Employer. Each Employer shall be responsible for making payments
and
providing benefits pursuant to the Policy on behalf of its Officers
or for
reimbursing the Corporation for the cost of such payments or benefits,
as
determined by the Corporation in its sole discretion. In the event
the
respective Employer fails to make such payment or reimbursement,
an
Officer’s (or other payee’s) sole recourse shall be against the respective
Employer, and not against the
Corporation.
|
(b) |
Remedies
.
An Officer shall be entitled to recover damages for late or nonpayment
of
amounts to which the Officer is entitled hereunder. The Officer shall
also
be entitled to seek specific performance of the obligations and any
other
applicable equitable or injunctive
relief.
|
(c) |
Section
2(a) shall not apply in the event that an Officer’s employment is
terminated “for cause.” Except as used in Section 3 of this Policy, “for
cause” means that the Corporation, in the case of an Officer employed by
the Corporation, or Employer in the case of an Officer employed by
an
Employer, acting in good faith based upon information then known
to it,
determines that the Officer has engaged in, committed, or is responsible
for (1) serious misconduct, gross negligence, theft, or fraud against
the
Corporation and/or an Employer; (2) refusal or unwillingness to perform
his duties; (3) inappropriate conduct in
violation
of Corporation’s equal employment opportunity policy; (4) conduct which
reflects adversely upon, or making any remarks disparaging of, the
Corporation, its Board of Directors, Officers, or employees, or its
affiliates or subsidiaries; (5) insubordination; (6) any willful
act that
is likely to have the effect of injuring the reputation, business,
or
business relationship of the Corporation or its subsidiaries or
affiliates; (7) violation of any fiduciary duty; or (8) breach of
any duty
of loyalty; or (9) any breach of the restrictive covenants contained
in
Subsection 2(d) below. Upon termination “for cause,” the Corporation, its
Board of Directors, Officers, or employees, or its affiliates or
subsidiaries shall have no liability to the Officer other than for
accrued
salary, vacation benefits, and any vested rights the Officer may
have
under the benefit and compensation plans in which the Officer participates
and under the general terms and conditions of the applicable plan.
|
(d) |
Obligations
of Officer
|
(1) |
Release
of Claims.
There shall be no obligation to commence the payment of the amounts
and
benefits described in Section 2(a) until the latter of (1) the delivery
by
Officer to the Corporation a fully executed comprehensive general
release
of any and all known or unknown claims that he or she may have against
the
Corporation, its Board of Directors, Officers, or employees, or its
affiliates or subsidiaries and a covenant not to sue in the form
prescribed by the Administrator, and (2) the expiration of any revocation
period associated with the release to which the Officer may be entitled
under law.
|
(2) |
Covenant
Not to Compete
.
(i) During the period of Officer's employment with the Corporation
or its
subsidiaries and for a period of months equal to the Severance Multiple
thereafter (the "Restricted Period"), Officer shall not, in any county
within the State of California or in any city, county or area outside
the
State of California within the United States or in the countries
of Canada
or Mexico, directly or indirectly, whether as partner, employee,
consultant, creditor, shareholder, or other similar capacity, promote,
participate, or engage in any activity or other business competitive
with
the Corporation's business or that of any of its subsidiaries or
affiliates, without the prior written consent of the Corporation's
Chief
Executive Officer. Notwithstanding the foregoing, Officer may have
an
interest in any public company engaged in a competitive business
so long
as Officer does not own more than 2 percent of any class of securities
of
such company, Officer is not employed by and does not consult with,
or
becomes a director of, or otherwise engage in any activities for,
such
competing company.
|
(3) |
Soliciting
Customers and Employees
.
During the Restricted Period, Officer shall not, directly or indirectly,
solicit or contact any customer or any prospective customer of the
Corporation or its subsidiaries or affiliates for any commercial
pursuit
that could be reasonably construed to be in competition with the
Corporation, or induce, or attempt to induce, any employees, agents
or
consultants of or to the Corporation or any of its subsidiaries or
affiliates to do anything from which Officer is restricted by reason
of
this covenant nor shall Officer, directly or indirectly, offer or
aid to
others to offer employment to, or interfere or attempt to interfere
with
any employment, consulting or agency relationship with, any employees,
agents or consultants of the Corporation, its subsidiaries and affiliates,
who received compensation of $75,000 or more during the preceding
six (6)
months, to work for any business competitive with any business of
the
Corporation, its subsidiaries or affiliates.
|
(4) |
Confidentiality
.
Officer shall not at any time (including after termination of employment)
divulge to others, use to the detriment of the Corporation or its
subsidiaries or affiliates, or use in any business competitive with
any
business of the Corporation or its subsidiaries or affiliates any
trade
secret, confidential or privileged information obtained during his
employment with the Corporation or its subsidiaries or affiliates,
without
first obtaining the written consent of the Corporation's Chief Executive
Officer. This paragraph covers but is not limited to discoveries,
inventions (except as otherwise provided by California law), improvements,
and writings, belonging to or relating to the affairs of the Corporation
or of any of its subsidiaries or affiliates, or any marketing systems,
customer lists or other marketing data. Officer shall, upon termination
of
employment for any reason, deliver to the Corporation all data, records
and communications, and all drawings, models, prototypes or similar
visual
or conceptual presentations of any type, and all copies or duplicates
thereof, relating to all matters contemplated by this paragraph.
|
(5) |
Assistance
in Legal Proceedings
.
During the Restricted Period, Officer shall, upon reasonable notice
from
the Corporation, furnish information and proper assistance (including
testimony and document production) to the Corporation as may be reasonably
required by the Corporation in connection with any legal, administrative
or regulatory proceeding in which it or any of its subsidiaries or
affiliates is, or may become, a party, or in connection with any
filing or
similar obligation of the Corporation imposed by any taxing,
administrative or regulatory authority having jurisdiction, provided,
however, that the Corporation shall pay all reasonable expenses incurred
by Officer in complying with this paragraph.
|
(6) |
Remedies
.
Upon Officer's failure to comply with the provisions of this Section
2(d),
the Corporation shall have the right to immediately terminate any
unpaid
amounts or benefits described in Section 2(a) to Officer. In the
event of
such termination, the Corporation shall have no further obligations
under
this Policy and shall be entitled to recover damages. In the event
of an
Officer’s breach or threatened breach of any of the covenants set forth in
this Section 2(d), the Corporation shall also be entitled to specific
performance by Officer of any such covenant and any other applicable
equitable or injunctive relief.
|
3. |
Termination
of Employment Following a Change in Control or Potential Change in
Control
|
(a) |
If
an Executive Officer’s employment by the Corporation or any subsidiary or
successor of the Corporation shall be subject to an Involuntary
Termination within the Covered Period, then the provisions of this
Section
3 instead of Section 2 shall govern the obligations of the Corporation
as
to the payments and benefits it shall provide to the Executive Officer.
In
the event that Executive Officer’s employment with the Corporation or an
employing subsidiary is terminated under circumstances which would
not
entitle Executive Officer to payments under this Section 3, Executive
Officer shall only receive such benefits to which he is entitled
under
Section 2, if any. In no event shall Executive Officer be entitled
to
receive termination benefits under both this Section 3 and Section
2.
|
(1) |
"Affiliate"
shall mean any entity which owns or controls, is owned or is under
common
ownership or control with, the Corporation.
|
(2) |
"Cause"
shall mean (i) the willful and continued failure of the Executive
Officer
to perform substantially the Executive Officer’s duties with the
Corporation or one of its affiliates (other than any such failure
resulting from incapacity due to physical or mental illness), after
a
written demand for substantial performance is delivered to the Executive
Officer by the Board of Directors or the Chief Executive Officer
of the
Corporation which specifically identifies the manner in which the
Board of
Directors or Chief Executive Officer believes that the Executive
Officer
has not substantially performed the Executive Officer’s duties; or (ii)
the willful engaging by the Executive Officer in illegal conduct
or gross
misconduct which is materially demonstrably injurious to the
Corporation.
|
(3) |
"Change
in Control" shall be deemed to have occurred
if:
|
(a) |
any
“person” (as such term is used in Sections 13(d) and 14(d)(2) of the
Securities Exchange Act of 1934, but excluding any benefit plan for
employees or any trustee, agent or other fiduciary for any such plan
acting in such person’s capacity as such fiduciary), directly or
indirectly, becomes the beneficial owner of securities of the Corporation
representing 20 percent or more of the combined voting power of the
Corporation's then outstanding
securities;
|
(b) |
during
any two consecutive years, individuals who at the beginning of such
a
period constitute the Board of Directors of the Corporation cease
for any
reason to constitute at least a majority of the Board of Directors
of the
Corporation, unless the election or the nomination for election by
the
shareholders of the Corporation, of each new Director was approved
by a
vote of at least two-thirds (2/3) of the Directors then still in
office
who were Directors at the beginning of the period;
or
|
(c) |
any
consolidation or merger of the Corporation shall have been consummated
other than a merger or consolidation which would result in the voting
securities of the Corporation outstanding immediately prior thereto
continuing to represent (either by remaining outstanding or by being
converted into voting securities of the surviving entity or any parent
of
such surviving entity) at least 70 percent of the Combined Voting
Power of
the Corporation, such surviving entity or the parent of such surviving
entity outstanding immediately after such merger or consolidation;
or
|
(d) |
the
shareholders of the Corporation shall have approved (i) any sale,
lease, exchange or other transfer (in one transaction or a series
of
related transactions) of all or substantially all of the assets of
the
Corporation; or (ii) any plan or proposal for the liquidation or
dissolution of the Corporation.
|
(4) |
"Change
in Control Date" shall mean the date on which a Change in Control
occurs.
|
(5) |
"Combined
Voting Power" shall mean the combined voting power of the Corporation's
or
other relevant entity's then outstanding voting
securities.
|
(6) |
“Covered
Period" shall mean the period commencing with the Change in Control
Date
and terminating two (2) years following said commencement; provided,
however, that if a Change in Control occurs and Executive Officer's
employment with the Corporation or the employing subsidiary is subject
to
an Involuntary Termination before the Change in Control Date but
on or
after a Potential Change in Control Date, and if it is reasonably
demonstrated by the Executive Officer that such termination (i) was
at the
request of a third party who has taken steps reasonably calculated
to
effect a Change in Control, or (ii) otherwise arose in connection
with or
in anticipation of a Change in Control, then the Covered Period shall
mean, as applied to Executive Officer, the two-year period beginning
on
the date immediately before the Potential Change in Control Date.
In the
case of termination of employment following a Potential Change in
Control
Date, references in the definition of "Good Reason" to conditions
in
effect immediately prior to a Change in Control shall be deemed to
mean
conditions in effect immediately prior to Executive Officer's
termination.
|
(7) |
"Disability"
shall mean the absence of the Executive Officer from the Executive
Officer's duties with the Corporation or the employing subsidiary
on a
full-time basis for 180 consecutive business days as a result of
incapacity due to physical or mental illness which is determined
to be
total and permanent by a physician selected by the Corporation or
its
insurers and acceptable to the Executive Officer or the Executive
Officer's legal representative.
|
(8) |
“Executive
Officer” shall mean officers of the Corporation at the level of Senior
Vice President and above and the principal executive officer of each
Employer.
|
(9) |
"Good
Reason" shall mean any one or more of the following which takes place
within the Covered Period:
|
(a) |
An
adverse change in Executive Officer's status or position(s) as in
effect
immediately before a Change in Control or Potential Change in Control,
including, without limitation, the assignment to the Executive Officer
of
any duties inconsistent in any respect with the Executive Officer’s
position (including status, offices, titles and reporting requirements,
including reporting requirements under Section 16 of the Securities
Exchange Act of 1934), authority, duties or responsibilities prior
to a
Change in Control or Potential Change in Control, or any other action
by
the Corporation which results in the diminution in such position,
authority, duties or responsibilities prior to a Change in Control
or
Potential Change in Control, excluding for this purpose an isolated,
insubstantial and inadvertent action not taken in bad faith and which
is
remedied by the Corporation promptly after receipt of notice thereof
given
by the Executive Officer;
|
(b) |
Executive
Officer's base salary is reduced from that provided to him immediately
before the Change in Control Date or as the same may be increased
from
time to time thereafter, unless such reduction is part of an
across-the-board reduction for all similarly situated executives,
including executives of the other party to the transaction that results
in
the Change in Control;
|
(c) |
Executive
Officer's eligibility to participate in bonus, stock option, incentive
award and other compensation plans which provide opportunities to
receive
compensation is diminished from that provided to him immediately
before
the Change in Control Date, unless substantially equal benefits are
provided to Executive Officer under comparable compensation plans,
or
unless such reduction is part of an across-the-board reduction for
all
similarly situated executives, including executives of the other
party to
the transaction that results in the Change in
Control;
|
(d) |
The
aggregate projected value of Executive Officer's employee benefits
(including but not limited to supplemental and excess retirement
programs,
medical, dental, life insurance and long-term disability plans) and
perquisites is diminished from that provided to him immediately before
the
Change in Control Date, unless such reduction is part of an
across-the-board reduction for all similarly situated executives,
including executives of the other party to the transaction that results
in
the Change in Control;
|
(e) |
A
change in Executive Officer's principal place of employment by Corporation
(including its subsidiaries) to a location more than thirty-five
miles
from Executive Officer's principal place of employment immediately
before
the Change in Control Date;
|
(f) |
A
reasonable determination by the Board of Directors that, as a result
of a
Change in Control and a change in circumstances thereafter significantly
affecting his position, he is unable to exercise the authorities,
powers,
function or duties attached to his position immediately before the
Change
in Control Date;
|
(g) |
The
failure of the Corporation to obtain the assumption of this Policy
by any
successor contemplated in Section 7, hereof;
or
|
(h) |
The
material failure of the Corporation to fulfill its obligations under
this
Policy, to the extent not remedied in a reasonable period of time
after
the Corporation’s receipt of written notice from Executive Officer
specifying the material failure by the
Corporation.
|
(10) |
"Involuntary
Termination" shall mean a termination (i) by the Corporation without
Cause, or (ii) by Executive Officer following Good Reason; provided,
however, the term "Involuntary Termination" shall not include termination
of Executive Officer's employment due to Executive Officer's death,
Disability, or voluntary retirement.
|
(11) |
"Potential
Change in Control" shall mean the earliest to occur of (i) the date
on
which the Corporation executes an agreement or letter of intent,
where the
consummation of the transaction described therein would result in
the
occurrence of a Change in Control, (ii) the date on which the Board
of
Directors approves a transaction or series of transactions, the
consummation of which would result in a Change in Control, or (iii)
the
date on which a tender offer for the Corporation's voting stock is
publicly announced, the completion of which would result in a Change
in
Control; provided, however, that if such Potential Change in Control
terminates by its terms, such transaction shall no longer constitute
a
Potential Change in Control.
|
(12) |
"Potential
Change in Control Date" shall mean the date on which a Potential
Change in
Control occurs.
|
(13) |
"Reference
Salary" shall mean the greater of (i) the annual rate of Executive
Officer's base salary from the Corporation or the employing subsidiary
in
effect immediately before the date of Executive Officer's Involuntary
Termination, or (ii) the annual rate of Executive Officer's base
salary
from the Corporation or the employing subsidiary in effect immediately
before the Change in Control Date.
|
(14) |
"Termination
Date" shall be the date specified in the written notice of termination
of
Executive Officer's employment given by either party in accordance
with
Section 3(b) of this Policy.
|
(b) |
Notice
of Termination
.
During the Covered Period, in the event that the Corporation (including
an
employing subsidiary) or Executive Officer terminates Executive Officer’s
employment with the Corporation or Employer, the party terminating
employment shall give written notice of termination to the other
party,
specifying the Termination Date and the specific termination provision
in
this Section 3 that is relied upon, if any, and setting forth in
reasonable detail the facts and circumstances claimed to provide
a basis
for termination of Executive Officer’s employment under the provision so
indicated. The Termination Date shall be determined as follows: (i)
if
Executive Officer's employment is terminated for Disability, thirty
(30)
days after a Notice of Termination is given (provided that Executive
Officer shall not have returned to the full-time performance of Executive
Officer's duties during such 30-day period); (ii) if Executive Officer's
employment is terminated by the Corporation in an Involuntary Termination,
five days after the date the Notice of Termination is received by
Executive Officer; and (iii) (as defined in this Section 3) if Executive
Officer's employment is terminated by the Corporation for Cause,
the date
specified in the Notice of Termination, provided, that the events
or
circumstances cited by the Board of Directors as constituting Cause
are
not cured by Executive Officer during any cure period that may be
offered
by the Board of Directors. The Date of Termination for a resignation
of
employment other than for Good Reason shall be the date set forth
in the
applicable notice, which shall be no earlier than ten (10) days after
the
date such notice is received by the Corporation, unless waived by
the
Corporation.
|
(c) |
Corporation’s
Obligations
.
If Executive Officer's employment by the Corporation or any Employer
or
successor of the Corporation shall be subject to an Involuntary
Termination within the Covered Period, then the Corporation shall
provide
Executive Officer the following benefits:
|
(1) |
The
Corporation shall pay to the Executive Officer a lump sum in cash
within
thirty (30) days after the Termination Date:
|
(a) |
the
sum of (1) any earned but unpaid base salary through the Termination
Date
at the rate in effect at the time of the notice of termination to
the
extent not theretofore paid; (2) the Executive Officer's target bonus
under the Short-Term Incentive Plan of the Corporation, an Affiliate,
or a
predecessor, for the fiscal year in which the Termination Date occurs
(the
"Target Bonus"); and (3) any accrued but unpaid vacation pay, in
each case
to the extent not theretofore paid; and
|
(b) |
the
amount equal to the product of (1) three and (2) the sum of (x) the
Reference Salary and (y) the Target
Bonus.
|
(2) |
Any
benefits conditioned upon continued future employment shall accelerate
in
full.
|
(3) |
Remedies
.
The Executive Officer shall be entitled to recover damages for late
or
nonpayment of amounts which the Corporation is obligated to pay hereunder.
The Executive Officer shall also be entitled to seek specific performance
of the Corporation’s obligations and any other applicable equitable or
injunctive relief.
|
(4) |
Benefits
provided hereunder to “key employees” within the meaning of Code Section
409A shall be paid on a delayed basis to the extent the Company determines
in good faith that the delay is necessary to avoid an additional
tax under
Code Section 409A.
|
(d) |
Adjustment
for Excise Taxes
.
If any portion of the payments to the Executive Officer under this
Section
3 or under any other plan, program, or arrangement maintained by
the
Corporation (a "Payment") would be subject to the excise tax levied
under
Section 4999 of the Internal Revenue Code ("Code"), or any interest
or
penalties are incurred by Executive Officer with respect to such
excise
tax (such excise tax together with such interest and penalties are
referred to herein as the "Excise Tax"), then the Corporation shall
make
an additional payment to Executive Officer (a "Tax Restoration Payment")
in an amount such that after payment by the Executive Officer of
all taxes
(including any interest or penalties imposed with respect to such
taxes),
including, without limitation, any income taxes (and any interest
and
penalties imposed with respect thereto) and Excise Tax imposed upon
the
Tax Restoration Payment, the Executive Officer retains an amount
of the
Tax Restoration Payment equal to the Excise Tax imposed upon the
Payments.
The payment of a Tax Restoration Payment under this Section 3 shall
not be
conditioned upon the Executive Officer's termination of employment.
|
4. |
Administration
|
5. |
No
Mitigation
|
6. |
Amendment
and Termination
|
7. |
Successors
|
8. |
Nonassignability
of Benefits
|
9. |
Nonguarantee
of Employment
|
10. |
Benefits
Unfunded and Unsecured
|
11. |
Applicable
Law
|
12. |
Arbitration
|
· |
"Base
Salary Plus Bonus"
means
the sum of:
|
(i) |
the
greater of a Senior Executive’s annual base salary as in effect
immediately prior to the date of (1) the Senior Executive’s termination of
employment or (2) the change in control,
plus
|
(ii) |
the
Short-Term Incentive Plan bonus target calculated for the fiscal year
in
which termination occurs.
|
· |
"Future
Golden Parachute Agreement”
means the following:
|
(i) |
an
employment agreement or arrangement between PG&E Corporation (or one
of its subsidiaries) and a Senior Executive pursuant to which the Senior
Executive renders services to PG&E Corporation (or one of its
subsidiaries) as an employee (and not as a consultant or other independent
contractor), when such agreement is entered into on or after the effective
date of this Policy, or
|
(ii) |
a
severance agreement between the Corporation (or one of its subsidiaries)
and a Senior Executive related to the termination of employment of
the
Senior Executive with the Corporation (or one of its subsidiaries),
when
such agreement is entered into on or
after
the effective date of this Policy, or
|
(iii) |
any
policy of PG&E Corporation (or one of its subsidiaries) that provides
benefits for a Senior Executive upon severance related to a change
in
control, if such Senior Executive becomes covered by such policy on
or
after
the effective date of this Policy, or
|
(iv) |
any
renewal, material modification, or extension that is made on
or
after
the effective date of this Policy to an employment agreement, severance
agreement, or policy that is in effect as of the effective date of
this
Policy, to the extent permitted by law or the terms of that existing
agreement or policy.
|
· |
“Golden
Parachute Benefits”
means
payments that a Senior Executive is entitled to receive if that Senior
Executive is severed (or constructively severed) following or in
connection with a change in control, and includes the following:
|
(i) |
amounts
payable in cash to a Senior Executive (including cash amounts payable
for
the uncompleted portion of an employment term under an agreement) after
that Senior Officer is severed (or constructively severed) following
a
change in control, and
|
(ii) |
special
benefits or perquisites provided to a Senior Executive at the time
of such
Senior Executive’s termination of employment.
|
· |
“Senior
Executive”
means
a person who, immediately prior to his or her severance or employment,
is
an officer of PG&E Corporation or a subsidiary who has the title of
Senior Vice President or higher.
|
Year
Ended December 31,
|
||||||||||
2005
|
2004
|
2003
|
||||||||
(in
millions, except per share amounts)
|
||||||||||
Net
Income
|
$
|
917
|
$
|
4,504
|
$
|
420
|
||||
Less:
distributed earnings to common shareholders
|
449
|
-
|
-
|
|||||||
Undistributed
earnings
|
468
|
4,504
|
420
|
|||||||
Less:
undistributed earnings (loss) from discontinued operations
|
13
|
684
|
(365
|
)
|
||||||
Undistributed
earnings before cumulative effect of changes in accounting
principles
|
455
|
3,820
|
785
|
|||||||
Less:
undistributed loss from cumulative effect of changes in accounting
principles
|
-
|
-
|
(6
|
)
|
||||||
Undistributed
earnings from continuing operations
|
$
|
455
|
$
|
3,820
|
$
|
791
|
||||
Common
shareholder earnings
|
||||||||||
Basic
|
||||||||||
Distributed
earnings to common shareholders
|
$
|
449
|
$
|
-
|
$
|
-
|
||||
Undistributed
earnings allocated to common shareholders - continuing
operations
|
433
|
3,646
|
754
|
|||||||
Undistributed
earnings (loss) allocated to common shareholders - discontinued
operations
|
12
|
653
|
(348
|
)
|
||||||
Undistributed
earnings (loss) allocated to common shareholders - cumulative effect
in
change in accounting principles
|
-
|
-
|
(6
|
)
|
||||||
Total
common shareholders earnings, basic
|
$
|
894
|
$
|
4,299
|
$
|
400
|
||||
Diluted
|
||||||||||
Distributed
earnings to common shareholders
|
$
|
449
|
$
|
-
|
$
|
-
|
||||
Undistributed
earnings allocated to common shareholders - continuing
operations
|
433
|
3,650
|
755
|
|||||||
Undistributed
earnings (loss) allocated to common shareholders - discontinued
operations
|
12
|
653
|
(348
|
)
|
||||||
Undistributed
earnings (loss) allocated to common shareholders - cumulative effect
of
changes in accounting principles
|
-
|
-
|
(6
|
)
|
||||||
Total
common shareholders earnings, diluted
|
$
|
894
|
$
|
4,303
|
$
|
401
|
||||
Weighted
average common shares outstanding, basic
|
372
|
398
|
385
|
|||||||
9.50%
Convertible Subordinated Notes
|
19
|
19
|
9
|
|||||||
Weighted
average common shares outstanding and participating securities,
basic
|
391
|
417
|
404
|
|||||||
Weighted
average common shares outstanding, basic
|
372
|
398
|
385
|
|||||||
Employee
stock-based compensation and accelerated share repurchase
program
(1)
|
6
|
7
|
4
|
|||||||
PG&E
Corporation Warrants
|
-
|
2
|
5
|
|||||||
Weighted
average common shares outstanding, diluted
|
378
|
407
|
394
|
|||||||
9.50%
Convertible Subordinated Notes
|
19
|
19
|
19
|
|||||||
Weighted
average common shares outstanding and participating securities,
diluted
|
397
|
426
|
413
|
|||||||
Net
earnings per common share, basic
|
||||||||||
Distributed
earnings, basic
(2)
|
$
|
1.21
|
$
|
-
|
$
|
-
|
||||
Undistributed
earnings - continuing operations, basic
|
1.16
|
9.16
|
1.96
|
|||||||
Undistributed
earnings (loss) - discontinued operations, basic
|
0.03
|
1.64
|
(0.90
|
)
|
||||||
Undistributed
earnings (loss) - cumulative effect of changes in accounting
principles
|
-
|
-
|
(0.01
|
)
|
||||||
Rounding
|
-
|
-
|
(0.01
|
)
|
||||||
Total
|
$
|
2.40
|
$
|
10.80
|
$
|
1.04
|
||||
Net
earnings per common share, diluted
|
||||||||||
Distributed
earnings, diluted
|
$
|
1.19
|
$
|
-
|
$
|
-
|
||||
Undistributed
earnings - continuing operations, diluted
|
1.15
|
8.97
|
1.92
|
|||||||
Undistributed
earnings (loss) - discontinued operations, diluted
|
0.03
|
1.60
|
(0.88
|
)
|
||||||
Undistributed
earnings (loss) - cumulative effect of changes in accounting
principles
|
-
|
-
|
(0.01
|
)
|
||||||
Rounding
|
-
|
-
|
(0.01
|
)
|
||||||
Total
|
$
|
2.37
|
$
|
10.57
|
$
|
1.02
|
Year
ended December 31,
|
||||||||||||||||
2005
|
2004
|
2003
|
2002
|
2001
|
||||||||||||
Earnings:
|
||||||||||||||||
Net
income
|
$
|
934
|
$
|
3,982
|
$
|
923
|
$
|
1,819
|
$
|
1,015
|
||||||
Adjustments
for minority interest in losses of less than 100% owned affiliates
and the
Company's equity in undistributed income (losses) of less than 50%
owned
affiliates
|
-
|
-
|
-
|
-
|
-
|
|||||||||||
Income
tax provision
|
574
|
2,561
|
528
|
1,178
|
596
|
|||||||||||
Net
fixed charges
|
589
|
671
|
964
|
1,029
|
1,019
|
|||||||||||
Total
Earnings
|
$
|
2,097
|
$
|
7,214
|
$
|
2,415
|
$
|
4,026
|
$
|
2,630
|
||||||
Fixed
Charges:
|
||||||||||||||||
Interest
on short-term borrowings and long-term debt, net
|
$
|
573
|
$
|
682
|
$
|
947
|
$
|
996
|
$
|
981
|
||||||
Interest
on capital leases
|
1
|
1
|
1
|
2
|
2
|
|||||||||||
AFUDC
debt
|
15
|
(12
|
)
|
16
|
21
|
12
|
||||||||||
Earnings
required to cover the preferred stock dividend and preferred security
distribution requirements of majority owned trust
|
-
|
-
|
-
|
10
|
24
|
|||||||||||
Total
Fixed Charges
|
$
|
589
|
$
|
671
|
$
|
964
|
$
|
1,029
|
$
|
1,019
|
||||||
Ratios
of Earnings to
Fixed
Charges
|
3.56
|
10.75
|
2.51
|
3.91
|
2.58
|
Year
ended December 31,
|
||||||||||||||||
Earnings:
|
2005
|
2004
|
2003
|
2002
|
2001
|
|||||||||||
Net
income
|
$
|
934
|
$
|
3,982
|
$
|
923
|
$
|
1,819
|
$
|
1,015
|
||||||
Adjustments
for minority interest in losses of less than 100% owned affiliates
and the
Company's equity in undistributed income (losses) of less than 50%
owned
affiliates
|
-
|
-
|
-
|
-
|
-
|
|||||||||||
Income
taxes provision
|
574
|
2,561
|
528
|
1,178
|
596
|
|||||||||||
Net
fixed charges
|
589
|
671
|
964
|
1,029
|
1,019
|
|||||||||||
Total
Earnings
|
$
|
2,097
|
$
|
7,214
|
$
|
2,415
|
$
|
4,026
|
$
|
2,630
|
||||||
Fixed
Charges:
|
||||||||||||||||
Interest
on short-term borrowings
and
long-term debt, net
|
$
|
573
|
$
|
682
|
$
|
947
|
$
|
996
|
$
|
981
|
||||||
Interest
on capital leases
|
1
|
1
|
1
|
2
|
2
|
|||||||||||
AFUDC
debt
|
15
|
(12
|
)
|
16
|
21
|
12
|
||||||||||
Earnings
required to cover the preferred stock dividend and preferred security
distribution requirements of majority owned trust
|
-
|
-
|
-
|
10
|
24
|
|||||||||||
Total
Fixed Charges
|
589
|
671
|
964
|
1,029
|
1,019
|
|||||||||||
Preferred
Stock Dividends:
|
||||||||||||||||
Tax
deductible dividends
|
12
|
9
|
9
|
9
|
9
|
|||||||||||
Pre-tax
earnings required to cover
non-tax
deductible preferred stock
dividend
requirements
|
13
|
34
|
27
|
28
|
27
|
|||||||||||
Total
Preferred Stock Dividends
|
25
|
43
|
36
|
37
|
36
|
|||||||||||
Total
Combined Fixed Charges
and
Preferred Stock Dividends
|
$
|
614
|
$
|
714
|
$
|
1,000
|
$
|
1,066
|
$
|
1,055
|
||||||
Ratios
of Earnings to Combined Fixed Charges and
Preferred Stock Dividends
|
3.42
|
10.10
|
2.42
|
3.78
|
2.49
|
2005
|
2004
|
2003
|
2002
|
2001
|
||||||||||||
(in
millions, except per share amounts)
|
||||||||||||||||
PG&E
Corporation
(1)
For
the Year
|
||||||||||||||||
Operating
revenues
|
$
|
11,703
|
$
|
11,080
|
$
|
10,435
|
$
|
10,505
|
$
|
10,450
|
||||||
Operating
income
|
1,970
|
7,118
|
2,343
|
3,954
|
2,613
|
|||||||||||
Income
from continuing operations
|
904
|
3,820
|
791
|
1,723
|
1,021
|
|||||||||||
Earnings
per common share from continuing operations, basic
|
2.37
|
9.16
|
1.96
|
4.53
|
2.81
|
|||||||||||
Earnings
per common share from continuing operations, diluted
|
2.34
|
8.97
|
1.92
|
4.49
|
2.80
|
|||||||||||
Dividends
declared per common share
(2)
|
1.23
|
-
|
-
|
-
|
-
|
|||||||||||
At
Year-End
|
||||||||||||||||
Book
value per common share
(3)
|
$
|
19.94
|
$
|
20.90
|
$
|
10.16
|
$
|
8.92
|
$
|
11.91
|
||||||
Common
stock price per share
|
37.12
|
33.28
|
27.77
|
13.90
|
19.24
|
|||||||||||
Total
assets
|
34,074
|
34,540
|
30,175
|
36,081
|
38,529
|
|||||||||||
Long-term
debt (excluding current portion)
|
6,976
|
7,323
|
3,314
|
3,715
|
3,923
|
|||||||||||
Rate
reduction bonds (excluding current portion)
|
290
|
580
|
870
|
1,160
|
1,450
|
|||||||||||
Energy
recovery bonds (excluding current portion)
|
2,276
|
-
|
-
|
-
|
-
|
|||||||||||
Financial
debt subject to compromise
|
-
|
-
|
5,603
|
5,605
|
5,651
|
|||||||||||
Preferred
stock of subsidiary with mandatory redemption provisions
|
-
|
122
|
137
|
137
|
137
|
|||||||||||
Pacific
Gas and Electric Company
(1)
For
the Year
|
||||||||||||||||
Operating
revenues
|
$
|
11,704
|
$
|
11,080
|
$
|
10,438
|
$
|
10,514
|
$
|
10,462
|
||||||
Operating
income
|
1,970
|
7,144
|
2,339
|
3,913
|
2,478
|
|||||||||||
Income
available for common stock
|
918
|
3,961
|
901
|
1,794
|
990
|
|||||||||||
At
Year-End
|
||||||||||||||||
Total
assets
|
$
|
33,783
|
$
|
34,302
|
$
|
29,066
|
$
|
27,593
|
$
|
28,105
|
||||||
Long-term
debt (excluding current portion)
|
6,696
|
7,043
|
2,431
|
2,739
|
3,019
|
|||||||||||
Rate
reduction bonds (excluding current portion)
|
290
|
580
|
870
|
1,160
|
1,450
|
|||||||||||
Energy
recovery bonds (excluding current portion)
|
2,276
|
-
|
-
|
-
|
-
|
|||||||||||
Financial
debt subject to compromise
|
-
|
-
|
5,603
|
5,605
|
5,651
|
|||||||||||
Preferred
stock with mandatory redemption provisions
|
-
|
122
|
137
|
137
|
137
|
|||||||||||
(1)
Operating
income and income from continuing operations reflect the recognition
of
regulatory assets in 2004 provided under the December 19, 2003 settlement
agreement entered into among PG&E Corporation, the Utility, and the
CPUC to resolve the Utility's Chapter 11 proceeding. Matters relating
to
certain data, including discontinued operations, and the cumulative
effect
of changes in accounting principles, are discussed in Management's
Discussion and Analysis and in the Notes to the Consolidated Financial
Statements.
|
||||||||||||||||
(2)
The
Board of Directors of PG&E Corporation declared a cash dividend of
$0.30 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.
|
||||||||||||||||
(3)
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.
|
·
|
Issuance
of Energy Recovery Bonds -
During
2005, PG&E Energy Recovery Funding LLC, a limited liability company
wholly owned by the Utility, or PERF, issued two separate series
of Energy
Recovery Bonds, or ERBs, for the aggregate amount of approximately
$2.7
billion. (See Note 6 of the Notes to the Consolidated Financial
Statements). The
Settlement
Agreement established a $2.2 billion, after-tax, regulatory asset
($3.7
billion, pre-tax), or the Settlement Regulatory Asset, on which the
Utility was authorized to earn a return on equity, or ROE, of
11.22%
.
In
February 2005, the proceeds of the first series of ERBs in the amount
of
$1.9 billion were used to refinance the after-tax portion of the
Settlement Regulatory Asset. As a result, the Utility's net income
for the
year ended December 31, 2005, was reduced by approximately $99 million
as
compared to the same period in 2004, when the Utility earned its
authorized 11.22% ROE, on the after-tax portion of the Settlement
Regulatory Asset. The November 2005 issuance of the remainder of
ERBs in
the amount of $844 million had a minimal effect on 2005 net income
and is
expected to reduce the Utility’s 2006 net income, as compared to 2005, by
approximately $56 million;
|
·
|
Improved
Capital Structure -
In
January 2005, the equity component of the Utility's capital structure
reached 52%, the target specified in the Settlement Agreement. Since
this
allowed the Utility to restore dividends and repurchase shares held
by
PG&E Corporation,
PG&E Corporation reinstated the payment of a regular quarterly
dividend at an annual rate of $1.20 per share. As discussed below
under
"Liquidity and Financial Resources," on December 21, 2005 the Board
of
Directors of PG&E Corporation increased the annual dividend to $1.32
per share. For 2006, the CPUC has authorized the equity component
of the
Utility’s capital structure to remain at 52% and has set a ROE for 2006 of
11.35%;
|
·
|
Stock
Repurchases -
PG&E
Corporation repurchased 61,139,700 shares of common stock for
approximately $2.2 billion under accelerated share repurchase arrangements
that increased both basic and diluted earnings per share, or EPS,
by
approximately $0.16 and $0.15, respectively, for 2005, as discussed
below
under "Liquidity and Financial Resources - Stock Repurchases.” PG&E
Corporation remains obligated to settle certain obligations under
the
accelerated share repurchase arrangement it entered in November 2005
either in cash or in shares, or a combination of the two, at PG&E
Corporation’s option. The settlement may have a material effect on
PG&E Corporation’s financial condition or results of
operations;
|
·
|
Resolution
of Claims for Energy Efficiency Incentives -
In
October 2005, the CPUC approved a settlement agreement between the
Utility
and the CPUC's
Office
of Ratepayer Advocates, or the
ORA,
in which the parties agreed that the Utility would receive approximately
$186 million for shareholder incentives for the successful implementation,
over the years 1994 through 2001, of demand-side management, energy
efficiency, and low-income energy efficiency programs. As discussed
further in “Regulatory Matters” below, as a result of the CPUC's decision,
the Utility recognized $186 million in electric and natural gas operating
revenues in the fourth quarter of 2005. As a result of this settlement,
the Utility will not record any future earnings due to shareholder
incentives for these program years;
|
·
|
The
Outcome of Regulatory Proceedings, including the 2007 General Rate
Case -
On
December 2, 2005, the Utility filed its 2007 General Rate Case, or
GRC,
application with the CPUC to determine the amount of authorized base
revenues to be collected from customers to recover the Utility's
basic
business and operational costs for its electric and gas distribution
and
electric generation operations for the period 2007 through 2009.
As
compared to the projected authorized 2006 revenue requirements, the
Utility's application requested increases in electric and gas distribution
revenue requirements of $481 million and $114 million, respectively,
and
an increase of $87 million related to generation expenses and
administrative costs associated with electric procurement activities
(see
"Regulatory Matters" below);
|
·
|
The
Success of the Utility’s Strategy to Achieve Operational Excellence and
Improved Customer Service
-
During 2005, the Utility identified and has undertaken 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.
The Utility aims to achieve these goals in a three to five-year period.
The Utility's 2007 GRC application included a proposed mechanism
to share
with customers savings that may be achieved through implementation
of
these initiatives. In addition, the Utility’s 2007 GRC application
includes a proposal to replace the current incentive mechanism for
reliability performance for the 2007-2009 period with a new customer
service performance incentive mechanism. Under the proposal, the
Utility
would be rewarded or penalized up to $60 million per year to the
extent
that the Utility’s actual performance exceeds or falls short of pre-set
annual performance improvement targets over the 2007-2009 period
(see
“Regulatory Matters” below);
|
·
|
The
Amount and Timing of Capital Expenditures -
The
Utility has requested, in various proceedings including the GRC,
that the
CPUC approve various capital expenditures to fund (1) 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 load growth),
(2)
the installation of advanced meters, and (3) investment in new long-term
generation resources, as may be authorized by the CPUC in accordance
with
the Utility’s long-term electricity procurement plan. As discussed below
under "Capital Expenditures," it is estimated that the Utility's
capital
expenditures will average approximately $2.5 billion annually from
2006
through 2010, resulting in a projected rate base of approximately
$20.7
billion in 2010, reflecting a projected rate base growth of approximately
6.3% per year;
|
·
|
Actions
Taken in Response to Rising Natural Gas Prices -
In
response to rising natural gas prices during the fourth quarter of
2005,
the CPUC permitted the Utility to implement additional hedging strategies
to reduce the impact of higher prices on the Utility's residential
and
small commercial retail natural gas customers (referred to as core
customers) and to reduce the impact of higher natural gas prices
on the
Utility's electric generation portfolio. For further discussion,
see "Risk
Management Activities" below. Although there are ratemaking mechanisms
in
place to recover the Utility's natural gas costs, the Utility's
implementation of the CPUC-approved hedging strategies is subject
to a
compliance review. In addition, the CPUC approved the Utility’s 10/20
Winter Gas Savings Program
that
offers residential and small business customers a 20% rebate for
reducing
their gas usage by 10% or more from January through March 2006. The
Utility forecasts that these rebates will total approximately $150
million
reducing cash inflows during the first four months of 2006. The Utility
expects to recover this cash through rates during April through October
2006
;
and
|
·
|
The
Accrual of Additional Liability for the Chromium Litigation and the
Outcome of the CPUC’s Investigation into the Utility’s Billing and
Collection Practices -
PG&E
Corporation's and the Utility’s net income for the year ended December 31,
2005 include an accrual of approximately $314 million reflecting
the
settlement of most of the claims in the litigation pending against
the
Utility involving allegations that exposure to chromium at or near
some of
the Utility’s natural gas compressor stations caused personal injuries,
wrongful deaths, or other injuries, referred to as the Chromium Litigation
(discussed in Note 17 of the Notes to the Consolidated Financial
Statements below) and an accrual for the remaining unresolved claims.
PG&E Corporation and the Utility do not believe that the outcome of
the remaining unresolved claims will have a material adverse affect
on
their future results of operations or financial condition. PG&E
Corporation and the Utility are unable to predict the outcome of
the
CPUC’s investigation into the Utility’s billing and collection practices
as discussed below under “Regulatory Matters.”
In
light of the recommended refunds and penalties, the outcome of the
investigation could have a material adverse affect on their future
results
of operations or financial
condition.
|
·
|
How
the Utility manages its responsibility to procure electric capacity
and
energy for its customers;
|
·
|
The
adequacy and price of natural gas supplies, and the ability of the
Utility
to manage and respond to the volatility of the natural gas market
for its
customers;
|
·
|
Weather,
storms, earthquakes, fires, floods, other natural disasters, explosions,
accidents, mechanical breakdowns, acts of terrorism, and other events
or
hazards that affect demand for electricity or natural gas, result
in power
outages, reduce generating output, disrupt natural gas supply, cause
damage to the Utility's assets or generating facilities, cause damage
to
the operations or assets of third parties on which the Utility relies,
or
subject the Utility to third party claims for damage or
injury;
|
·
|
Unanticipated
population growth or decline, general economic and financial market
conditions, changes in technology including the development of alternative
energy sources, all of which may affect customer demand for natural
gas or
electricity;
|
·
|
Whether
the Utility is required to cease operations temporarily or permanently
at
its Diablo Canyon nuclear power plant, or Diablo Canyon, because
the Utility is unable to increase its on-site spent nuclear fuel
storage
capacity, find another depositary for spent fuel, or timely complete
the
replacement of the steam generators, or because of mechanical breakdown,
lack of nuclear fuel, environmental constraints, or for some other
reason
and the risk that the Utility may be required to purchase electricity
from
more expensive sources; and
|
·
|
Whether
the Utility is able to recognize the anticipated cost benefits and
savings
expected to result from its efforts to improve customer service through
implementation of specific initiatives to streamline business processes
and deploy new technology.
|
·
|
The
outcome of the regulatory proceedings pending at the CPUC and the
FERC
discussed in "Regulatory Matters" below, and the impact of future
ratemaking actions by the CPUC and the FERC;
|
·
|
The
impact of the recently enacted Energy Policy Act of 2005 which, among
other provisions, repeals the Public Utility Holding Company Act
of 1935
making electric utility industry consolidation more likely; expands
the
FERC’s authority to review proposed mergers; changes the FERC regulatory
scheme applicable to qualifying co-generation facilities, or QFs;
authorizes the formation of an Electric Reliability Organization
to be
overseen by the FERC to establish electric reliability standards;
and
modifies certain other aspects of energy regulation and federal tax
policies applicable to the Utility;
|
·
|
The
extent to which the CPUC or the FERC delays or denies recovery of
the
Utility's costs, including electricity or gas purchase costs, from
customers due to a regulatory determination that such costs were
not
reasonable or prudent, or for other reasons, resulting in write-offs
of
regulatory assets;
|
·
|
How
the CPUC administers the capital structure, stand-alone dividend,
and
first priority conditions of the CPUC's past decisions permitting
the
establishment of holding companies for the California investor-owned
electric utilities and the outcome of the CPUC's new rulemaking proceeding
concerning the relationship between the California investor-owned
energy
utilities and their holding companies and non-regulated affiliates,
which
may include (1) establishing reporting requirements for the allocation
of
capital between utilities and their non-regulated affiliates by the
parent
holding companies, and (2) changing the CPUC's affiliate transaction
rules;
|
·
|
Whether
the Utility is determined to be in compliance with all applicable
rules,
tariffs and orders relating to electricity and natural gas utility
operations, including tariffs related to the Utility’s billing and
collection practices as discussed below in “Regulatory Matters,” and the
extent to which a finding of non-compliance could result in customer
refunds, penalties or other non-recoverable expenses, such as has
been
recommended with respect to the CPUC’s investigation into the Utility’s
billing and collection practices; and
|
·
|
Whether
the Utility is required to incur material costs or capital expenditures
or
curtail or cease operations at affected facilities, including the
Utility’s natural gas compressor stations, to comply with existing and
future environmental laws, regulations and
policies.
|
·
|
The
outcome of pending litigation; and
|
·
|
The
timing and resolution of the pending appeal of the bankruptcy court
order
confirming the Utility's plan of reorganization under Chapter 11.
|
·
|
Continuing
efforts by local public utilities to take over the Utility's distribution
assets through exercise of their condemnation power or by duplication
of
the Utility's distribution assets or service, and other forms of
municipalization that may result in stranded investment capital,
decreased
customer growth, loss of customer load and additional barriers to
cost
recovery; and
|
·
|
The
extent to which the Utility's distribution customers are permitted
to
switch between purchasing electricity from the Utility and from alternate
energy service providers as direct access customers, and the extent
to
which cities, counties and others in the Utility's service territory
begin
directly serving the electricity needs of the Utility's customers,
potentially resulting in stranded generating asset costs and
non-recoverable procurement costs.
|
Year
ended December 31,
|
||||||||||
2005
|
2004
|
2003
|
||||||||
(in
millions)
|
||||||||||
Utility
|
||||||||||
Electric
operating revenues
|
$
|
7,927
|
$
|
7,867
|
$
|
7,582
|
||||
Natural
gas operating revenues
|
3,777
|
3,213
|
2,856
|
|||||||
Total
operating revenues
|
11,704
|
11,080
|
10,438
|
|||||||
Cost
of electricity
|
2,410
|
2,770
|
2,319
|
|||||||
Cost
of natural gas
|
2,191
|
1,724
|
1,467
|
|||||||
Operating
and maintenance
|
3,399
|
2,842
|
2,935
|
|||||||
Recognition
of regulatory assets
|
-
|
(4,900
|
)
|
-
|
||||||
Depreciation,
amortization and decommissioning
|
1,734
|
1,494
|
1,218
|
|||||||
Reorganization
professional fees and expenses
|
-
|
6
|
160
|
|||||||
Total
operating expenses
|
9,734
|
3,936
|
8,099
|
|||||||
Operating
income
|
1,970
|
7,144
|
2,339
|
|||||||
Interest
income
|
76
|
50
|
53
|
|||||||
Interest
expense
|
(554
|
)
|
(667
|
)
|
(953
|
)
|
||||
Other
expense, net
(1)
|
-
|
(5
|
)
|
(9
|
)
|
|||||
Income
before income taxes
|
1,492
|
6,522
|
1,430
|
|||||||
Income
tax provision
|
574
|
2,561
|
528
|
|||||||
Income
before cumulative effect of a change in accounting
principle
|
918
|
3,961
|
902
|
|||||||
Cumulative
effect of a change in accounting principle
|
-
|
-
|
(1
|
)
|
||||||
Income
available for common stock
|
$
|
918
|
$
|
3,961
|
$
|
901
|
||||
PG&E
Corporation, Eliminations and Other
(2)(3)
|
||||||||||
Operating
revenues
|
$
|
(1
|
)
|
$
|
-
|
$
|
(3
|
)
|
||
Operating
expenses
|
(1
|
)
|
26
|
(7
|
)
|
|||||
Operating
income (loss)
|
-
|
(26
|
)
|
4
|
||||||
Interest
income
|
4
|
13
|
9
|
|||||||
Interest
expense
|
(29
|
)
|
(130
|
)
|
(194
|
)
|
||||
Other
expense, net
(1)
|
(19
|
)
|
(93
|
)
|
-
|
|||||
Loss
before income taxes
|
(44
|
)
|
(236
|
)
|
(181
|
)
|
||||
Income
tax benefit
|
(30
|
)
|
(95
|
)
|
(70
|
)
|
||||
Income
(loss) from continuing operations
|
(14
|
)
|
(141
|
)
|
(111
|
)
|
||||
Discontinued
operations
|
13
|
684
|
(365
|
)
|
||||||
Cumulative
effect of changes in accounting principles
|
-
|
-
|
(5
|
)
|
||||||
Net
income (loss)
|
$
|
(1
|
)
|
$
|
543
|
$
|
(481
|
)
|
||
Consolidated
Total
(3)
|
||||||||||
Operating
revenues
|
$
|
11,703
|
$
|
11,080
|
$
|
10,435
|
||||
Operating
expenses
|
9,733
|
3,962
|
8,092
|
|||||||
Operating
income
|
1,970
|
7,118
|
2,343
|
|||||||
Interest
income
|
80
|
63
|
62
|
|||||||
Interest
expense
|
(583
|
)
|
(797
|
)
|
(1,147
|
)
|
||||
Other
expenses, net
(1)
|
(19
|
)
|
(98
|
)
|
(9
|
)
|
||||
Income
before income taxes
|
1,448
|
6,286
|
1,249
|
|||||||
Income
tax provision
|
544
|
2,466
|
458
|
|||||||
Income
from continuing operations
|
904
|
3,820
|
791
|
|||||||
Discontinued
operations
|
13
|
684
|
(365
|
)
|
||||||
Cumulative
effect of changes in accounting principles
|
-
|
-
|
(6
|
)
|
||||||
Net
income
|
$
|
917
|
$
|
4,504
|
$
|
420
|
||||
(1)
Includes
preferred dividend requirement as other expense.
|
||||||||||
(2)
PG&E
Corporation eliminates all intercompany transactions in
consolidation.
|
||||||||||
(3)
Operating
results of NEGT are reflected as discontinued operations. See Note
7 of
the Notes to the Consolidated Financial Statements for further
discussion.
|
·
|
Authorized
yearly adjustments to the Utility’s base revenues
,
or attrition revenues as authorized in the 2003 GRC and revenues
authorized in the 2004 cost of capital proceeding resulted in an
increase
in electric operating revenues of approximately $90 million for the
year
ended December 31, 2005, as compared to 2004;
|
·
|
The
Utility's collection of the dedicated rate component, or DRC, charge
and
revenue requirements associated with the Energy Recovery Bond Balancing
Account, or ERBBA, resulted in an increase of approximately $390
million
in electric operating revenue in 2005, with no similar amount in
2004 (see
further discussion in Note 6 of the Notes to the Consolidated Financial
Statements);
|
·
|
The
resolution of claims made in the Utility’s Annual Earnings Assessment
Proceeding, or AEAP, for shareholder incentives related to energy
efficiency and other public purpose programs covering past program
years
1994-2001, resulted in an increase of approximately $160 million
in
electric revenues in 2005, with no similar amount in 2004 (see further
discussion in “Regulatory Matters”);
|
·
|
The
settlement entered in the CPUC proceeding related to the Electric
Restructuring Costs Account resulted in an increase of approximately
$80
million in electric operating revenues in 2005, with no similar amount
in
2004. The settlement agreement authorized the Utility to collect
revenue
requirements to recover the distribution-related electric industry
restructuring costs through rates charged to certain of the Utility’s
customers during 2005;
|
·
|
Electric
operating revenues increased by approximately $70 million primarily
as a
result of certain regulatory proceedings resulting in refunds in
revenue
requirements to customers in 2004, with no similar amount in 2005;
|
·
|
An
increase of approximately $100 million reflecting the recognition
of Self
Generation Incentive Program revenues as authorized in the 2005 Annual
Electric True-up, or AET, that previously had no specific revenue
recovery
mechanism, with no similar amount in 2004; and
|
·
|
Miscellaneous
other electric operating revenues, including revenues associated
with
public purpose programs and advanced metering and demand response
programs, increased by approximately $140 million in 2005 compared
to
2004.
|
·
|
Electric
operating revenues decreased approximately $530 million compared
to 2004,
primarily due to lower electricity procurement and transmission costs
which are passed through to customers; and
|
·
|
Electric
operating revenues decreased approximately $435 million as a result
of a
decrease in the revenue requirement associated with the Settlement
Regulatory Asset. As a result of the refinancing of the after-tax
portion
of the Settlement Regulatory Asset on February 10, 2005 through issuance
of the first series of ERBs the Utility was no longer authorized
to
collect this revenue requirement (see further discussion in Note
6 of the
Notes to the Consolidated Financial Statements).
|
·
|
The
CPUC authorization for the Utility to collect the revenue requirements
associated with the Settlement Regulatory Asset and the other regulatory
assets provided under the Settlement Agreement resulted in an electric
operating revenue increase of approximately $490
million during 2004, compared to 2003;
|
·
|
The
approval of the Utility's 2003 GRC in May
2004 resulted in an electric operating revenue increase of approximately
$100 million;
|
·
|
Electric
transmission revenues increased by approximately $400
million in 2004 compared to 2003 primarily due to an increase in
recoverable reliability must run, or RMR, costs and an increase in
at-risk
transmission access revenues; and
|
·
|
The
remaining increases in the Utility's electric operating revenues
were due
to increases of approximately $170 million in the Utility's authorized
revenue requirements for procurement and miscellaneous other electric
revenues in 2004 compared to 2003.
|
2005
|
2004
|
2003
|
||||||||
(in
millions)
|
||||||||||
Cost
of purchased power
|
$
|
2,706
|
$
|
2,816
|
$
|
2,449
|
||||
Proceeds
from surplus sales allocated to the Utility
|
(478
|
)
|
(192
|
)
|
(247
|
)
|
||||
Fuel
used in own generation
|
182
|
146
|
117
|
|||||||
Total
net cost of electricity
|
$
|
2,410
|
$
|
2,770
|
$
|
2,319
|
||||
Average
cost of purchased power per GWh
|
$
|
0.079
|
$
|
0.082
|
$
|
0.076
|
||||
Total
purchased power (GWh)
|
34,203
|
34,525
|
32,249
|
·
|
The
increase in surplus conditions created by increased electricity production
from the Utility’s hydroelectric generation facilities due to above
average rainfall during 2005 resulted in an increase in proceeds
from
surplus sales allocated to the Utility of $286 million in 2005, as
compared to 2004, which resulted in a corresponding decrease in the
cost
of electricity; and
|
·
|
The
decrease in total purchased power of 322 Gigawatt hours, or GWh,
and the
decrease in the average cost of purchased power of $0.003 per GWh
in 2005,
as compared to 2004, resulted in a decrease of approximately $110
million
in the cost of purchased power.
|
·
|
The
increase in total purchased power of 2,276 GWh and the increase in
the
average cost of purchased power of $0.006 per
GWh,
in 2004 as compared to 2003 resulted in an increase of approximately
$367
million in the cost of purchased power; and
|
·
|
The
cost of electricity increased by approximately $84
million in 2004 as compared to 2003 as a result of a decrease in
the
proceeds from surplus sales allocated to the Utility in 2004 and
an
increase in the amount of fuel used in the Utility's owned generation.
|
2005
|
2004
|
2003
|
||||||||
(in
millions)
|
||||||||||
Bundled
natural gas revenues
|
$
|
3,539
|
$
|
2,943
|
$
|
2,572
|
||||
Transportation
service-only revenues
|
238
|
270
|
284
|
|||||||
Total
natural gas operating revenues
|
$
|
3,777
|
$
|
3,213
|
$
|
2,856
|
||||
Average
bundled revenue per Mcf of natural gas sold
|
$
|
13.05
|
$
|
10.51
|
$
|
9.22
|
||||
Total
bundled natural gas sales (in millions of Mcf)
|
271
|
280
|
279
|
·
|
Excluding
the impact of the 2003 GRC decision, the 2004 and 2005 cost of capital
proceedings, and the Utility’s AEAP discussed below, bundled natural gas
operating revenues increased by approximately $580 million, or 20%,
in
2005 as compared to 2004. This increase was primarily due to an increase
in the cost of natural gas, which the Utility is permitted by the
CPUC to
pass on to its customers through higher rates, resulting in an increase
in
the average bundled revenue per thousand cubic feet, or Mcf, of natural
gas sold of approximately $2.48 per Mcf, or 24%, partially offset
by a
decrease in volume of approximately 9 Mcf, or 3%;
|
·
|
Authorized
yearly adjustments to the Utility’s base revenues, or attrition revenues,
as authorized in the 2003 GRC and revenues authorized in the 2004
cost of
capital proceeding resulted in an increase in natural gas operating
revenues of approximately $42 million in 2005 as compared to 2004;
and
|
·
|
The
resolution of the Utility’s claims made in the AEAP for shareholder
incentives related to energy efficiency and other public purpose
programs
covering past program years 1994-2001, resulted in an increase of
approximately $26 million in gas revenues in 2005, with no similar
amount
in 2004. (See further discussion in “Regulatory Matters”).
|
·
|
The
approval of the 2003 GRC in May 2004 resulted in the Utility recording
approximately $52 million in revenues related to 2003 in 2004 with
no
comparable amount in 2005; and
|
·
|
Transportation
service-only revenues decreased by approximately $32 million, or
12%, in
2005 as compared to 2004, primarily as a result of a decrease in
rates.
|
·
|
Bundled
natural gas revenues (excluding the effects of the 2003 GRC decision
discussed below) increased by approximately $250
million, or 10%, in 2004 compared to 2003, mainly due to a higher
cost of
natural gas, which the Utility is permitted by the CPUC to pass on
to its
customers through higher rates. The average bundled revenue per Mcf
of
natural gas sold in 2004 (excluding the effects of the 2003 GRC decision
discussed below) increased by approximately $0.86, or 9%, as compared
to
2003; and
|
·
|
The
approval of the 2003 GRC resulted in an increase in natural gas revenues
of approximately $121 million (consisting of a 2004 portion of $69
million
and a 2003 portion of $52 million) in 2004 compared to 2003.
|
2005
|
2004
|
2003
|
||||||||
(in
millions)
|
||||||||||
Cost
of natural gas sold
|
$
|
2,051
|
$
|
1,591
|
$
|
1,336
|
||||
Cost
of natural gas transportation
|
140
|
133
|
131
|
|||||||
Total
cost of natural gas
|
$
|
2,191
|
$
|
1,724
|
$
|
1,467
|
||||
Average
cost per Mcf of natural gas sold
|
$
|
7.57
|
$
|
5.68
|
$
|
4.79
|
||||
Total
natural gas sold (in millions of Mcf)
|
271
|
280
|
279
|
·
|
An
increase of approximately $40 million associated with the reassessment
of
the estimated cost of environmental remediation related to the Topock
and
Hinkley gas compressor stations (see “Environmental Matters” in Note 17 of
the Notes to the Consolidated Financial Statements for further
discussion);
|
·
|
An
increase of approximately $110 million related to administration
expenses
for low-income customer assistance programs and community outreach
programs;
|
·
|
An
increase of approximately $100 million reflecting recognition of
Self
Generation Incentive Program expenses in 2005 as authorized in the
2005
AET that were deferred in prior periods as there was no specific
revenue
recovery mechanism in place (see related revenues in “Electric Operating
Revenues”);
|
·
|
An
increase of approximately $154 million reflecting a settlement related
to
the Chromium Litigation and an accrual for the remaining unresolved
claims
(see further discussion in “Legal Matters”);
|
·
|
An
increase of approximately $55 million related to outside consulting,
contract and legal expense and various programs and initiatives including
strategies to achieve operational excellence and improved customer
service;
|
·
|
An
increase of approximately $60 million primarily related to gas
transportation operations charges mainly due to rate increases for
pipeline demand and transportation; and
|
·
|
An
increase of approximately $25 million primarily related to property
taxes
mainly due to higher assessments in 2005.
|
·
|
A
decrease of approximately $50 million in operating and maintenance
expenses at Diablo Canyon in 2005, as compared to 2004, primarily
reflecting costs associated with the longer scheduled refueling outage
in
2004 as compared to 2005.
|
·
|
The
Utility recorded approximately $202 million in 2005 for amortization
of
the ERB regulatory asset with no similar amount in
2004;
|
·
|
As
a result of the 2003 GRC decision in May 2004 authorizing lower
depreciation rates, the Utility recorded an approximately $38 million
decrease to depreciation expense related to 2003 in 2004 with no
similar
reduction in 2005; and
|
·
|
Depreciation
expense increased by approximately $32 million as a result of plant
additions in 2005 as compared to 2004.
|
·
|
Amortization
of the regulatory asset related to rate recovery bonds, or RRBs,
decreased
by approximately $20 million in 2005, as compared to 2004. The Utility’s
regulatory asset related to the RRBs is amortized simultaneously
with the
amortization of the RRB liability, and is expected to be recovered
by the
end of 2007. This decrease is mainly due to the declining balance
of the
RRB liability; and
|
·
|
Amortization
of the Settlement Regulatory Asset decreased by approximately $10
million
in 2005 as compared to the same period in 2004. This decrease is
mainly
due to the refinancing of the Settlement Regulatory Asset following
the
first and second series of ERBs on February 10, 2005 and November
9, 2005,
respectively.
|
(in
millions)
|
||||
Investment
in NEGT
|
$
|
1,208
|
||
Accumulated
other comprehensive income
|
(120
|
)
|
||
Cash
paid pursuant to settlement of tax related litigation
|
(30
|
)
|
||
Tax
effect
|
(374
|
)
|
||
Gain
on disposal of NEGT, net of tax
|
$
|
684
|
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
|
||||
Corporate
credit rating
|
Baa3
|
-
(2)
|
||
Credit
facility
|
Baa3
|
-
(2)
|
||
(1)
Moody’s
has not assigned a rating to the Utility’s pollution control bonds backed
by letters of credit.
|
(2)
S&P
has not assigned a rating to PG&E Corporation.
|
·
|
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., d
ividend
divided by share price);
|
·
|
Flexibility:
Allow sufficient cash to pay a dividend and to fund investments while
avoiding the necessity 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.
|
2005
|
2004
|
2003
|
||||||||
(in
millions)
|
||||||||||
Net
income
|
$
|
934
|
$
|
3,982
|
$
|
923
|
||||
Non-cash
(income) expenses:
|
||||||||||
Depreciation,
amortization and decommissioning
|
1,697
|
1,494
|
1,218
|
|||||||
Gain
on establishment of regulatory asset, net
|
-
|
(2,904
|
)
|
-
|
||||||
Change
in accounts receivable
|
(245
|
)
|
(85
|
)
|
(590
|
)
|
||||
Change
in accrued taxes
|
(150
|
)
|
52
|
48
|
||||||
Other
uses of cash:
|
||||||||||
Payments
authorized by the bankruptcy court on amounts classified as liabilities
subject to compromise
|
-
|
(1,022
|
)
|
(87
|
)
|
|||||
Other
changes in operating assets and liabilities
|
130
|
321
|
711
|
|||||||
Net
cash provided by operating activities
|
$
|
2,366
|
$
|
1,838
|
$
|
2,223
|
·
|
The
Utility received approximately $160 million related to settlements
with El
Paso Natural Gas Company and Mirant. See Note 17 of the Notes to
the
Consolidated Financial Statements for further discussion
;
|
·
|
In
2005, the Utility had approximately $100 million in additional
expenditures related to gas procurement, administrative and general
costs
that were unpaid at the end of 2005. In 2004, the Utility did not
have
similar unpaid expenditures;
|
·
|
In
2004, the Utility paid approximately $1 billion of allowed creditor
claims
with no similar amount in 2005;
|
·
|
Collections
on balancing accounts increased approximately $800 million in 2005
as
compared to 2004 due to an increase in revenue requirements intended
to
recover 2004 undercollections;
|
·
|
The
Utility paid approximately $60 million more in 2005 as compared to
2004 for gas inventory as a result of increased gas prices;
and
|
·
|
In
2005, the Utility paid approximately $1.4 billion in tax payments
as
compared to approximately $100 million in 2004. This increase was
primarily due to an increase in taxable generator settlements in
2005 as
compared to 2004, and a decrease in deductible tax depreciation in
2005 as
compared to 2004.
|
·
|
Net
income increased
by
approximately $431 million, excluding the one-time non-cash gain,
after-tax, of approximately $2.9 billion related to the recognition
of the
regulatory assets established under the Settlement Agreement and
including
$276 million for the impact of depreciation, amortization, and
decommissioning which are also non-cash items;
|
·
|
Accounts
receivable increased
by
approximately $505 million in 2004, as compared to 2003 when the
Utility
recorded a reduction to accounts receivable to reflect the settlement
of
an amount payable to the DWR. Amounts payable to the DWR are offset
against amounts receivable from the Utility’s customers for energy
supplied by the DWR reflecting the Utility’s role as a billing and
collection agent for the DWR’s sales to the Utility’s customers;
|
·
|
Payments
authorized by the bankruptcy court on amounts classified as liabilities
subject to compromise increased
by
approximately $935 million due to payment of all allowed creditor
claims
on the effective date; and
|
·
|
Cash
provided by operating assets and liabilities decreased by approximately
$390 million primarily due to balancing account activity.
|
2005
|
2004
|
2003
|
||||||||
(in
millions)
|
||||||||||
Capital
expenditures
|
$
|
(1,803
|
)
|
$
|
(1,559
|
)
|
$
|
(1,698
|
)
|
|
Net
proceeds from sale of assets
|
39
|
35
|
49
|
|||||||
(Increase)
decrease in restricted cash
|
434
|
(1,577
|
)
|
(253
|
)
|
|||||
Other
investing activities, net
|
(29
|
)
|
(178
|
)
|
(114
|
)
|
||||
Net
cash used by investing activities
|
$
|
(1,359
|
)
|
$
|
(3,279
|
)
|
$
|
(2,016
|
)
|
2005
|
2004
|
2003
|
||||||||
(in
millions)
|
||||||||||
Net
proceeds from long-term debt issued
|
$
|
451
|
$
|
7,742
|
$
|
-
|
||||
Net
proceeds from energy recovery bonds issued
|
2,711
|
-
|
-
|
|||||||
Net
borrowings under accounts receivable facility and working capital
facility
|
260
|
300
|
-
|
|||||||
Net
repayments under working capital facility
|
(300
|
)
|
-
|
-
|
||||||
Rate
reduction bonds matured
|
(290
|
)
|
(290
|
)
|
(290
|
)
|
||||
Energy
recovery bonds matured
|
(140
|
)
|
-
|
-
|
||||||
Long-term
debt, matured, redeemed or repurchased
|
(1,554
|
)
|
(8,402
|
)
|
(281
|
)
|
||||
Common
stock dividends paid
|
(445
|
)
|
-
|
-
|
||||||
Preferred
dividends paid
|
(16
|
)
|
(90
|
)
|
-
|
|||||
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
|
65
|
-
|
-
|
|||||||
Net
cash used by financing activities
|
$
|
(1,327
|
)
|
$
|
(755
|
)
|
$
|
(571
|
)
|
·
|
During
2005, proceeds from long-term debt decreased by approximately $7.3
billion. In 2004, in connection with the Utility's plan of reorganization,
the Utility issued approximately $7.7 billion, net of issuance costs
of
$107 million, in long-term debt. In 2005, the only long-term debt
incurred
by the Utility was seven loan agreements with the California
Infrastructure and Economic Development Bank to issue PC Bonds Series
A-G,
totaling $451 million, net of issuance costs of $3
million;
|
·
|
PERF
issued two separate series of ERBs in 2005 in the aggregate amount
of $2.7
billion with no similar issuance in 2004 (see Note 6 of the Notes
to the
Consolidated Financial Statements for further discussion). In March
2005,
the Utility used some of the proceeds from the issuance of the first
series of ERBs to repurchase $960 million of its common stock from
PG&E Corporation. In November 2005, the Utility used the proceeds from
the issuance of the second series of ERBs to repurchase $950 million
of
its common stock from PG&E Corporation;
|
·
|
Net
borrowings under the accounts receivable facility and working capital
facility were $260 million in 2005 due to the Utility borrowing $260
million under its accounts receivable facility in the fourth
quarter;
|
·
|
Net
repayments under the working capital facility were $300 million in
2005
due to the Utility repaying in the first quarter $300 million it
borrowed
under its working capital facility;
|
·
|
Approximately
$140 million of ERBs matured in 2005 with no similar maturities in
2004;
|
·
|
During
2005, long-term debt matured, redeemed, or repurchased by the Utility
decreased by approximately $6.8 billion. In 2005, the Utility redeemed
$1.1 billion of floating rate debt and repaid $454 million under
certain
reimbursement obligations the Utility entered into in April 2004
when its
plan of reorganization under Chapter 11 became effective. 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 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 $122 million of preferred stock with mandatory
redemption provisions compared to $15 million in 2004;
|
·
|
In
2005, the Utility redeemed $37 million of preferred stock without
mandatory redemption provisions with no similar redemption in 2004;
and
|
·
|
In
2005, approximately $100 million was received from customers for
deposits
to ensure that they do not exceed the credit risk threshold that
has been
set for them, with no similar amount in
2004.
|
·
|
In
March
2004, the Utility consummated a public offering of $6.7 billion in
First
Mortgage Bonds. In April 2004, the Utility entered into pollution
control
bond loans in the amount of $454 million and borrowed $350 million
under
the accounts receivable financing facility. In June 2004, the Utility
entered into four separate loan agreements with the California Pollution
Control Financing Authority, which issued $345 million aggregate
principal
amount of its Pollution Control Refunding Revenue
Bonds;
|
·
|
Partially
offsetting these proceeds are issuance costs of approximately
$107
million associated with the $6.7 billion in First Mortgage Bonds,
working
capital facilities, bridge loans and other exit financing
activities;
|
·
|
In
November
2004, the Utility borrowed $300 million under its working capital
facility;
|
·
|
The
amount of long-term debt, matured, redeemed or repurchased
in
2004 was approximately $8.4 billion compared to $281 million in 2003.
In
2004, the Utility paid $310 million in March 2004 upon maturity of
secured
debt, $6.9 billion of long-term debt on the effective date of its
plan of
reorganization and $345 million of pollution control bond loans in
June
2004. In 2003,the Utility repaid approximately $281 million in principal
on its mortgage bonds that matured in August 2003;
|
·
|
In
May 2004, the Utility repaid $350 million borrowed under the accounts
receivable financing facility;
|
·
|
In
October
2004, the Utility redeemed $500 million of Floating Rate First Mortgage
Bonds;
|
·
|
The
Utility paid a
pproximately
$90 million of preferred stock dividends during 2004;
and
|
·
|
The
Utility redeemed a
pproximately
$15 million of preferred stock with mandatory redemption provisions
during
2004.
|
2005
|
2004
|
2003
|
||||||||
(in
millions)
|
||||||||||
Net
income
|
$
|
917
|
$
|
4,504
|
$
|
420
|
||||
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
|
)
|
-
|
|||||
Loss
from operations of NEGT (net of income tax benefit of $230
million)
|
-
|
-
|
365
|
|||||||
Cumulative
effect of changes in accounting principles
|
-
|
-
|
6
|
|||||||
Net
income from continuing operations
|
904
|
3,820
|
791
|
|||||||
Non-cash
(income) expenses:
|
||||||||||
Depreciation,
amortization and decommissioning
|
1,698
|
1,497
|
1,222
|
|||||||
Deferred
income taxes and tax credits, net
|
(659
|
)
|
611
|
190
|
||||||
Recognition
of regulatory asset, net of tax
|
-
|
(2,904
|
)
|
-
|
||||||
Other
deferred charges and noncurrent liabilities
|
33
|
(519
|
)
|
857
|
||||||
Loss
from retirement of long-term debt
|
-
|
65
|
89
|
|||||||
Gain
of sale of assets
|
-
|
(19
|
)
|
(29
|
)
|
|||||
Tax
benefit from employee stock plans
|
50
|
41
|
-
|
|||||||
Other
changes in operating assets and liabilities
|
383
|
(736
|
)
|
(381
|
)
|
|||||
Net
cash provided by operating activities
|
$
|
2,409
|
$
|
1,856
|
$
|
2,739
|
2005
|
2004
|
2003
|
||||||||
(in
millions)
|
||||||||||
Net
borrowings under accounts receivable facility and working capital
facility
|
$
|
260
|
$
|
300
|
$
|
-
|
||||
Net
repayments under working capital facility
|
(300
|
)
|
-
|
-
|
||||||
Net
proceeds from issuance of energy recovery bonds
|
2,711
|
-
|
-
|
|||||||
Net
proceeds from long-term debt issued
|
451
|
7,742
|
581
|
|||||||
Long-term
debt matured, redeemed or repurchased
|
(1,556
|
)
|
(9,054
|
)
|
(1,068
|
)
|
||||
Rate
reduction bonds matured
|
(290
|
)
|
(290
|
)
|
(290
|
)
|
||||
Energy
recovery bonds matured
|
(140
|
)
|
-
|
-
|
||||||
Preferred
stock with mandatory redemption provisions redeemed
|
(122
|
)
|
(15
|
)
|
-
|
|||||
Preferred
stock without mandatory redemption provisions redeemed
|
(37
|
)
|
-
|
-
|
||||||
Common
stock dividends paid
|
(334
|
)
|
-
|
-
|
||||||
Common
stock issued
|
243
|
162
|
166
|
|||||||
Common
stock repurchased
|
(2,188
|
)
|
(378
|
)
|
-
|
|||||
Preferred
dividends paid
|
(16
|
)
|
(90
|
)
|
-
|
|||||
Other,
net
|
48
|
(1
|
)
|
(4
|
)
|
|||||
Net
cash used by financing activities
|
$
|
(1,270
|
)
|
$
|
(1,624
|
)
|
$
|
(615
|
)
|
·
|
New
customer connections
,
replacements, upgrades and expansion of the existing electricity
distribution systems (including expenditures for the Advanced Metering
Infrastructure, or AMI, program) expected to average approximately
$1.0
billion annually over the next five years;
|
·
|
Replacement
of natural gas distribution pipelines expected to average approximately
$
310
million annually over the next five years;
|
·
|
Replacements
,
capacity expansion, and other life extension programs of the electricity
transmission system expected to average approximately $360 million
annually over the next five years;
|
·
|
Replacements
and upgrades
for improved system reliability to the Utility's natural gas
transportation facilities expected to average approximately $150
million
annually over the next five years;
|
·
|
Replacements
and upgrades of existing facilities at Diablo Canyon, including
replacement
of the turbines and steam generators, potential investments in a
new
combined cycle generation unit in Contra Costa County that may be
acquired
pursuant to a settlement agreement with the Mirant Corporation (Contra
Costa 8); replacements, upgrades and relicensing of the Utility's
hydroelectric generation facilities; and the repowering of the Humboldt
Bay Power Plant. All of these generation-related projects are expected
to
average approximately $440 million annually over the next five years;
and
|
·
|
Investment
in common plant, including computers, vehicles, facilities and
communications equipment, expected to average approximately $
260
million annually over the next five years.
|
·
|
An
increase in electric and gas distribution revenue requirements of
$481
million and $114 million, respectively, over the authorized 2006
revenue
requirements to maintain current service levels, to support increased
investment in distribution infrastructure as plant in service is
upgraded
and replaced, and to adjust for wages and inflation;
|
·
|
An
increase of $87 million, over the authorized 2006 revenue requirement,
to
cover increases in operational costs for the Utility's fossil, hydro,
and
nuclear generation facilities and administrative costs associated
with
electric procurement activities; and
|
·
|
Attrition
increases of $186 million for 2008 and $243 million for 2009 designed
to
avoid a reduction in earnings in years between GRCs that would otherwise
occur because of increases in rate base and expenses.
|
ROE
|
Customer
|
Shareholder
|
||
Below
10.72%
|
50%
|
50%
|
||
10.72%
- 11.72%
|
0%
|
100%
|
||
11.73%
- 14.22%
|
50%
|
50%
|
||
Above
14.22%
|
100%
|
0%
|
ROE
|
Customer
|
Shareholder
|
||
Below
10.85%
|
50%
|
50%
|
||
10.85%
- 11.85%
|
0%
|
100%
|
||
11.86%
- 14.35%
|
50%
|
50%
|
||
Above
14.35%
|
100%
|
0%
|
·
|
Periodic
expirations of existing electricity purchase contracts, or entering
into
new energy and capacity 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,
and
community choice aggregation;
|
·
|
The
reallocation of the DWR power purchase contracts among California
investor-owned electric utilities; and
|
·
|
The
acquisition, retirement or closure of generation facilities.
|
·
|
Inflation
adjustment
-
The estimated cash flows are adjusted for inflation estimates for
labor,
equipment, materials, and other disposal costs based on data from
regulatory filings including the Nuclear Decommissioning Cost Triennial
Proceeding and GRC filings;
|
·
|
Discount
rate
-
The estimated cash flows include contingency factors that were used
as a
proxy for the market risk premium; 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.
|
Increase
(decrease)
in Assumption
|
Increase
in 2005 Pension Cost
|
Increase
in Projected Benefit Obligation at December 31,
2005
|
||||
(in
millions)
|
||||||
Discount
rate
|
(0.5)%
|
$
|
50
|
$
|
642
|
|
Rate
of return on plan assets
|
(0.5)%
|
37
|
-
|
|||
Rate
of increase in compensation
|
0.5%
|
29
|
141
|
Increase
(decrease)
in Assumption
|
Increase
in 2005
Postretirement
Benefit Cost
|
Increase
in Accumulated Benefit Obligation at December 31,
2005
|
||||
(in
millions)
|
||||||
Health
care cost trend rate
|
0.5%
|
$
|
5
|
$
|
35
|
|
Discount
rate
|
(0.5)%
|
2
|
64
|
·
|
Weather;
|
·
|
Supply
and demand;
|
·
|
The
availability of competitively priced alternative energy
sources;
|
·
|
The
level of production of natural gas;
|
·
|
The
availability of
LNG
supplies;
|
·
|
The
price of fuels that are used to produce electricity, including
natural
gas, crude oil and coal;
|
·
|
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 climate change, or other
regulatory requirements;
|
·
|
Imposition
of operational performance standards by agencies with regulatory
oversight
of the Utility's facilities;
|
·
|
Environmental
and personal injury liabilities;
|
·
|
Fuel
interruptions;
|
·
|
Blackouts;
|
·
|
Labor
disputes;
|
·
|
Weather,
storms, earthquakes, fires, floods or other natural disasters
,
war, disease, and other catastrophic events; and
|
·
|
Explosions,
accidents, mechanical breakdowns and other events or hazards that
affect
demand, result in power outages, reduce generating output or cause
damage
to the Utility's assets or operations or those of third parties on
which
it relies.
|
Year
ended December 31,
|
||||||||||
2005
|
2004
|
2003
|
||||||||
Operating
Revenues
|
||||||||||
Electric
|
$
|
7,927
|
$
|
7,867
|
$
|
7,582
|
||||
Natural
gas
|
3,776
|
3,213
|
2,853
|
|||||||
Total
operating revenues
|
11,703
|
11,080
|
10,435
|
|||||||
Operating
Expenses
|
||||||||||
Cost
of electricity
|
2,410
|
2,770
|
2,309
|
|||||||
Cost
of natural gas
|
2,191
|
1,724
|
1,438
|
|||||||
Operating
and maintenance
|
3,397
|
2,865
|
2,963
|
|||||||
Recognition
of regulatory assets
|
-
|
(4,900
|
)
|
-
|
||||||
Depreciation,
amortization, and decommissioning
|
1,735
|
1,497
|
1,222
|
|||||||
Reorganization
professional fees and expenses
|
-
|
6
|
160
|
|||||||
Total
operating expenses
|
9,733
|
3,962
|
8,092
|
|||||||
Operating
Income
|
1,970
|
7,118
|
2,343
|
|||||||
Reorganization
interest income
|
-
|
8
|
46
|
|||||||
Interest
income
|
80
|
55
|
16
|
|||||||
Interest
expense
|
(583
|
)
|
(797
|
)
|
(1,147
|
)
|
||||
Other
expense, net
|
(19
|
)
|
(98
|
)
|
(9
|
)
|
||||
Income
Before Income Taxes
|
1,448
|
6,286
|
1,249
|
|||||||
Income
tax provision
|
544
|
2,466
|
458
|
|||||||
Income
From Continuing Operations
|
904
|
3,820
|
791
|
|||||||
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
|
-
|
|||||||
Loss
from operations of NEGT (net of income tax benefit of $230
million)
|
-
|
-
|
(365
|
)
|
||||||
Net
Income Before Cumulative Effect of Changes in Accounting
Principles
|
917
|
4,504
|
426
|
|||||||
Cumulative
effect of changes in accounting principles of $(5) million in 2003
related
to discontinued operations (net of income tax benefit of $3 million
in
2003). In 2003, $(1)million related to continuing operations (net
of
income tax benefit of $1 million)
|
-
|
-
|
(6
|
)
|
||||||
Net
Income
|
$
|
917
|
$
|
4,504
|
$
|
420
|
||||
Weighted
Average Common Shares Outstanding, Basic
|
372
|
398
|
385
|
|||||||
Earnings
Per Common Share from Continuing Operations,
Basic
|
$
|
2.37
|
$
|
9.16
|
$
|
1.96
|
||||
Net
Earnings Per Common Share, Basic
|
$
|
2.40
|
$
|
10.80
|
$
|
1.04
|
||||
Earnings
Per Common Share from Continuing Operations,
Diluted
|
$
|
2.34
|
$
|
8.97
|
$
|
1.92
|
||||
Net
Earnings Per Common Share, Diluted
|
$
|
2.37
|
$
|
10.57
|
$
|
1.02
|
||||
Dividends
Declared Per Common Share
|
$
|
1.23
|
$
|
-
|
$
|
-
|
Balance
at December 31,
|
|||||||
2005
|
2004
|
||||||
ASSETS
|
|||||||
Current
Assets
|
|||||||
Cash
and cash equivalents
|
$
|
713
|
$
|
972
|
|||
Restricted
cash
|
1,546
|
1,980
|
|||||
Accounts
receivable:
|
|||||||
Customers
(net of allowance for doubtful accounts of $77 million in 2005 and
$93
million in 2004)
|
2,422
|
2,085
|
|||||
Regulatory
balancing accounts
|
727
|
1,021
|
|||||
Inventories:
|
|||||||
Gas
stored underground and fuel oil
|
231
|
175
|
|||||
Materials
and supplies
|
133
|
129
|
|||||
Income
taxes receivable
|
21
|
-
|
|||||
Prepaid
expenses and other
|
187
|
46
|
|||||
Total
current assets
|
5,980
|
6,408
|
|||||
Property,
Plant and Equipment
|
|||||||
Electric
|
22,482
|
21,519
|
|||||
Gas
|
8,794
|
8,526
|
|||||
Construction
work in progress
|
738
|
449
|
|||||
Other
|
16
|
15
|
|||||
Total
property, plant and equipment
|
32,030
|
30,509
|
|||||
Accumulated
depreciation
|
(12,075
|
)
|
(11,520
|
)
|
|||
Net
property, plant and equipment
|
19,955
|
18,989
|
|||||
Other
Noncurrent Assets
|
|||||||
Regulatory
assets
|
5,578
|
6,526
|
|||||
Nuclear
decommissioning funds
|
1,719
|
1,629
|
|||||
Other
|
842
|
988
|
|||||
Total
other noncurrent assets
|
8,139
|
9,143
|
|||||
TOTAL
ASSETS
|
$
|
34,074
|
$
|
34,540
|
Balance
at December 31,
|
|||||||
2005
|
2004
|
||||||
LIABILITIES
AND SHAREHOLDERS' EQUITY
|
|||||||
Current
Liabilities
|
|||||||
Short-term
borrowings
|
$
|
260
|
$
|
300
|
|||
Long-term
debt, classified as current
|
2
|
758
|
|||||
Rate
reduction bonds, classified as current
|
290
|
290
|
|||||
Energy
recovery bonds, classified as current
|
316
|
-
|
|||||
Accounts
payable:
|
|||||||
Trade
creditors
|
980
|
762
|
|||||
Disputed
claims and customer refunds
|
1,733
|
2,142
|
|||||
Regulatory
balancing accounts
|
840
|
369
|
|||||
Other
|
441
|
352
|
|||||
Interest
payable
|
473
|
461
|
|||||
Income
taxes payable
|
-
|
185
|
|||||
Deferred
income taxes
|
181
|
394
|
|||||
Other
|
1,416
|
905
|
|||||
Total
current liabilities
|
6,932
|
6,918
|
|||||
Noncurrent
Liabilities
|
|||||||
Long-term
debt
|
6,976
|
7,323
|
|||||
Rate
reduction bonds
|
290
|
580
|
|||||
Energy
recovery bonds
|
2,276
|
-
|
|||||
Regulatory
liabilities
|
3,506
|
4,035
|
|||||
Asset
retirement obligations
|
1,587
|
1,301
|
|||||
Deferred
income taxes
|
3,092
|
3,531
|
|||||
Deferred
tax credits
|
112
|
121
|
|||||
Preferred
stock of subsidiary with mandatory redemption provisions (redeemable,
6.30% and 6.57%, no shares outstanding at December 31, 2005, 4,925,000
shares outstanding at December 31, 2004)
|
-
|
122
|
|||||
Other
|
1,833
|
1,690
|
|||||
Total
noncurrent liabilities
|
19,672
|
18,703
|
|||||
Commitments
and Contingencies (Notes 2, 4, 5, 6, 8, 9, 13, 15 and
17)
|
|||||||
Preferred
Stock of Subsidiaries
|
252
|
286
|
|||||
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
366,868,512
common
and 1,399,990 restricted shares in 2005 and issued 417,014,431 common
and
1,601,710 restricted shares in 2004
|
5,827
|
6,518
|
|||||
Common
stock held by subsidiary, at cost, 24,665,500 shares
|
(718
|
)
|
(718
|
)
|
|||
Unearned
compensation
|
(22
|
)
|
(26
|
)
|
|||
Reinvested
earnings
|
2,139
|
2,863
|
|||||
Accumulated
other comprehensive loss
|
(8
|
)
|
(4
|
)
|
|||
Total
common shareholders' equity
|
7,218
|
8,633
|
|||||
TOTAL
LIABILITIES AND SHAREHOLDERS' EQUITY
|
$
|
34,074
|
$
|
34,540
|
Year
ended December 31,
|
||||||||||
2005
|
2004
|
2003
|
||||||||
Cash
Flows From Operating Activities
|
||||||||||
Net
income
|
$
|
917
|
$
|
4,504
|
$
|
420
|
||||
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
|
)
|
-
|
|||||
Loss
from operations of NEGT (net of income tax benefit of $230
million)
|
-
|
-
|
365
|
|||||||
Cumulative
effect of changes in accounting principles
|
-
|
-
|
6
|
|||||||
Net
income from continuing operations
|
904
|
3,820
|
791
|
|||||||
Adjustments
to reconcile net income to net cash provided by operating activities:
|
||||||||||
Depreciation,
amortization, decommissioning and allowance for equity funds used
during
construction
|
1,698
|
1,497
|
1,222
|
|||||||
Recognition
of regulatory assets
|
-
|
(4,900
|
)
|
-
|
||||||
Deferred
income taxes and tax credits, net
|
(659
|
)
|
2,607
|
190
|
||||||
Other
deferred charges and noncurrent liabilities
|
33
|
(519
|
)
|
857
|
||||||
Loss
from retirement of long-term debt
|
-
|
65
|
89
|
|||||||
Tax
benefit from employee stock plans
|
50
|
41
|
-
|
|||||||
Gain
on sale of assets
|
-
|
(19
|
)
|
(29
|
)
|
|||||
Net
effect of changes in operating assets and liabilities:
|
||||||||||
Accounts
receivable
|
(245
|
)
|
(85
|
)
|
(605
|
)
|
||||
Inventories
|
(60
|
)
|
(12
|
)
|
(17
|
)
|
||||
Accounts
payable
|
257
|
273
|
403
|
|||||||
Accrued
taxes/income taxes receivable
|
(207
|
)
|
(122
|
)
|
173
|
|||||
Regulatory
balancing accounts, net
|
254
|
(590
|
)
|
(329
|
)
|
|||||
Other
current assets
|
29
|
760
|
(84
|
)
|
||||||
Other
current liabilities
|
273
|
(48
|
)
|
(6
|
)
|
|||||
Payments
authorized by the bankruptcy court on amounts classified as liabilities
subject to compromise
|
-
|
(1,022
|
)
|
(87
|
)
|
|||||
Other
|
82
|
110
|
171
|
|||||||
Net
cash provided by operating activities
|
2,409
|
1,856
|
2,739
|
|||||||
Cash
Flows From Investing Activities
|
||||||||||
Capital
expenditures
|
(1,804
|
)
|
(1,559
|
)
|
(1,698
|
)
|
||||
Net
proceeds from sale of assets
|
39
|
35
|
49
|
|||||||
Decrease
(increase) in restricted cash
|
434
|
(1,216
|
)
|
(237
|
)
|
|||||
Proceeds from
nuclear decommissioning trust sales
|
2,918
|
1,821
|
1,087
|
|||||||
Purchases
of nuclear decommissioning trust investments
|
(3,008
|
)
|
(1,972
|
)
|
(1,230
|
)
|
||||
Other
|
23
|
(27
|
)
|
31
|
||||||
Net
cash used in investing activities
|
(1,398
|
)
|
(2,918
|
)
|
(1,998
|
)
|
Year
ended December 31,
|
||||||||||
2005
|
2004
|
2003
|
||||||||
Cash
Flows From Financing Activities
|
||||||||||
Net
borrowings under accounts receivable facility and working capital
facility
|
260
|
300
|
-
|
|||||||
Net
repayments under working capital facility
|
(300
|
)
|
-
|
-
|
||||||
Proceeds
from issuance of long-term debt, net of issuance costs of $3 million
in
2005 and $107 million in 2004
|
451
|
7,742
|
581
|
|||||||
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
|
)
|
(1,068
|
)
|
||||
Rate
reduction bonds matured
|
(290
|
)
|
(290
|
)
|
(290
|
)
|
||||
Energy
recovery bonds matured
|
(140
|
)
|
-
|
-
|
||||||
Preferred
stock with mandatory redemption provisions redeemed
|
(122
|
)
|
(15
|
)
|
-
|
|||||
Preferred
stock without mandatory redemption provisions redeemed
|
(37
|
)
|
-
|
-
|
||||||
Common
stock issued
|
243
|
162
|
166
|
|||||||
Common
stock repurchased
|
(2,188
|
)
|
(378
|
)
|
-
|
|||||
Preferred
stock dividends paid
|
(16
|
)
|
(90
|
)
|
-
|
|||||
Common
stock dividends paid
|
(334
|
)
|
-
|
-
|
||||||
Other
|
48
|
(1
|
)
|
(4
|
)
|
|||||
Net
cash used in financing activities
|
(1,270
|
)
|
(1,624
|
)
|
(615
|
)
|
||||
Net
change in cash and cash equivalents
|
(259
|
)
|
(2,686
|
)
|
126
|
|||||
Cash
and cash equivalents at January 1
|
972
|
3,658
|
3,532
|
|||||||
Cash
and cash equivalents at December 31
|
$
|
713
|
$
|
972
|
$
|
3,658
|
||||
Supplemental
disclosures of cash flow information
|
||||||||||
Cash
received for:
|
||||||||||
Reorganization
interest income
|
$
|
-
|
$
|
16
|
$
|
39
|
||||
Cash
paid for:
|
||||||||||
Interest
(net of amounts capitalized)
|
403
|
646
|
866
|
|||||||
Income
taxes paid (refunded), net
|
1,392
|
128
|
(91
|
)
|
||||||
Reorganization
professional fees and expenses
|
-
|
61
|
99
|
|||||||
Supplemental
disclosures of noncash investing and financing
activities
|
||||||||||
Common
stock dividends declared but not yet paid
|
$
|
115
|
$
|
-
|
$
|
-
|
||||
Transfer
of liabilities and other payables subject to compromise (to) from
operating assets and liabilities
|
-
|
(2,877
|
)
|
181
|
Common
Stock
|
Common
Stock Held by
|
Unearned
|
Reinvested
Earnings (Accumulated
|
Accumulated
Other Comprehensive
|
Total
Common Share-holders'
|
Comprehensive
Income
|
|||||||||||||||||||
Shares
|
Amount
|
Subsidiary
|
Compensation
|
Deficit)
|
Income
(Loss)
|
Equity
|
(Loss)
|
||||||||||||||||||
Balance
at December 31, 2002
|
405,486,015
|
$
|
6,274
|
$
|
(690
|
)
|
-
|
$
|
(1,878
|
)
|
$
|
(93
|
)
|
$
|
3,613
|
||||||||||
Net
income
|
-
|
-
|
-
|
-
|
420
|
-
|
420
|
$
|
420
|
||||||||||||||||
Mark-to-market
adjustments for hedging transactions in accordance with SFAS
No. 133 (net
of income tax benefit of $10 million)
|
-
|
-
|
-
|
-
|
-
|
(8
|
)
|
(8
|
)
|
(8
|
)
|
||||||||||||||
Retirement
plan remeasurement (net of income tax benefit of $3
million)
|
-
|
-
|
-
|
-
|
-
|
(4
|
)
|
(4
|
)
|
(4
|
)
|
||||||||||||||
Net
reclassification to earnings (net of income tax expense of
$27
million)
|
-
|
-
|
-
|
-
|
-
|
17
|
17
|
17
|
|||||||||||||||||
Foreign
currency translation adjustment (net of income tax expense
of $5
million)
|
-
|
-
|
-
|
-
|
-
|
3
|
3
|
3
|
|||||||||||||||||
Comprehensive
income
|
$
|
428
|
|||||||||||||||||||||||
Common stock issued |
8,796,632
|
166
|
-
|
-
|
-
|
-
|
166
|
||||||||||||||||||
Common
stock warrants exercised
|
702,367
|
-
|
-
|
-
|
-
|
-
|
-
|
||||||||||||||||||
Common
restricted stock issued
|
1,590,010
|
28
|
-
|
(28
|
)
|
-
|
-
|
-
|
|||||||||||||||||
Common
restricted stock cancelled
|
(54,742
|
) |
(1
|
)
|
-
|
1
|
-
|
-
|
-
|
||||||||||||||||
Common
restricted stock amortization
|
-
|
-
|
-
|
7
|
-
|
-
|
7
|
||||||||||||||||||
Other
|
-
|
1
|
-
|
-
|
-
|
-
|
1
|
||||||||||||||||||
Balance
at December 31, 2003
|
416,520,282
|
$
|
6,468
|
$
|
(690
|
)
|
$
|
(20
|
)
|
$
|
(1,458
|
)
|
$
|
(85
|
)
|
$
|
4,215
|
Common
Stock
|
Common
Stock Held by
|
Unearned
|
Reinvested
Earnings (Accumulated
|
Accumulated
Other Comprehensive
|
Total
Common Share-holders'
|
Comprehensive
Income
|
|||||||||||||||||||
Shares
|
Amount
|
Subsidiary
|
Compensation
|
Deficit)
|
Income
(Loss)
|
Equity
|
(Loss)
|
||||||||||||||||||
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
|
Common
Stock
|
Common
Stock Held by
|
Unearned
|
Reinvested
Earnings (Accumulated
|
Accumulated
Other Comprehensive
|
Total
Common Share-holders'
|
Comprehensive
Income
|
|||||||||||||||||||
Shares
|
Amount
|
Subsidiary
|
Compensation
|
Deficit)
|
Income
(Loss)
|
Equity
|
(Loss)
|
||||||||||||||||||
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 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
|
Year
ended December 31,
|
||||||||||
2005
|
2004
|
2003
|
||||||||
Operating
Revenues
|
||||||||||
Electric
|
$
|
7,927
|
$
|
7,867
|
$
|
7,582
|
||||
Natural
gas
|
3,777
|
3,213
|
2,856
|
|||||||
Total
operating revenues
|
11,704
|
11,080
|
10,438
|
|||||||
Operating
Expenses
|
||||||||||
Cost
of electricity
|
2,410
|
2,770
|
2,319
|
|||||||
Cost
of natural gas
|
2,191
|
1,724
|
1,467
|
|||||||
Operating
and maintenance
|
3,399
|
2,842
|
2,935
|
|||||||
Recognition
of regulatory assets
|
-
|
(4,900
|
)
|
-
|
||||||
Depreciation,
amortization and decommissioning
|
1,734
|
1,494
|
1,218
|
|||||||
Reorganization
professional fees and expenses
|
-
|
6
|
160
|
|||||||
Total
operating expenses
|
9,734
|
3,936
|
8,099
|
|||||||
Operating
Income
|
1,970
|
7,144
|
2,339
|
|||||||
Reorganization
interest income
|
-
|
8
|
46
|
|||||||
Interest
income
|
76
|
42
|
7
|
|||||||
Interest
expense (non-contractual interest expense of $31 million in 2004
and $131
million in 2003)
|
(554
|
)
|
(667
|
)
|
(953
|
)
|
||||
Other
income, net
|
16
|
16
|
13
|
|||||||
Income
Before Income Taxes
|
1,508
|
6,543
|
1,452
|
|||||||
Income
tax provision
|
574
|
2,561
|
528
|
|||||||
Net
Income Before Cumulative Effect of a Change in Accounting
Principle
|
934
|
3,982
|
924
|
|||||||
Cumulative
effect of a change in accounting principle (net of income tax benefit
of
$1 million in 2003)
|
-
|
-
|
(1
|
)
|
||||||
Net
Income
|
934
|
3,982
|
923
|
|||||||
Preferred
stock dividend requirement
|
16
|
21
|
22
|
|||||||
Income
Available for Common Stock
|
$
|
918
|
$
|
3,961
|
$
|
901
|
Balance
at December 31,
|
|||||||
2005
|
2004
|
||||||
ASSETS
|
|||||||
Current
Assets
|
|||||||
Cash
and cash equivalents
|
$
|
463
|
$
|
783
|
|||
Restricted
cash
|
1,546
|
1,980
|
|||||
Accounts
receivable:
|
|||||||
Customers
(net of allowance for doubtful accounts of $77 million in 2005 and
$93
million in 2004)
|
2,422
|
2,085
|
|||||
Related
parties
|
3
|
2
|
|||||
Regulatory
balancing accounts
|
727
|
1,021
|
|||||
Inventories:
|
|||||||
Gas
stored underground and fuel oil
|
231
|
175
|
|||||
Materials
and supplies
|
133
|
129
|
|||||
Income
taxes receivable
|
48
|
-
|
|||||
Prepaid
expenses and other
|
183
|
43
|
|||||
Total
current assets
|
5,756
|
6,218
|
|||||
Property,
Plant and Equipment
|
|||||||
Electric
|
22,482
|
21,519
|
|||||
Gas
|
8,794
|
8,526
|
|||||
Construction
work in progress
|
738
|
449
|
|||||
Total
property, plant and equipment
|
32,014
|
30,494
|
|||||
Accumulated
depreciation
|
(12,061
|
)
|
(11,507
|
)
|
|||
Net
property, plant and equipment
|
19,953
|
18,987
|
|||||
Other
Noncurrent Assets
|
|||||||
Regulatory
assets
|
5,578
|
6,526
|
|||||
Nuclear
decommissioning funds
|
1,719
|
1,629
|
|||||
Related
parties receivable
|
23
|
-
|
|||||
Other
|
754
|
942
|
|||||
Total
other noncurrent assets
|
8,074
|
9,097
|
|||||
TOTAL
ASSETS
|
$
|
33,783
|
$
|
34,302
|
Balance
at December 31,
|
|||||||
2005
|
2004
|
||||||
LIABILITIES
AND SHAREHOLDERS' EQUITY
|
|||||||
Current
Liabilities
|
|||||||
Short
term borrowings
|
$
|
260
|
$
|
300
|
|||
Long-term
debt, classified as current
|
2
|
757
|
|||||
Rate
reduction bonds, classified as current
|
290
|
290
|
|||||
Energy
recovery bonds, classified as current
|
316
|
-
|
|||||
Accounts
payable:
|
|||||||
Trade
creditors
|
980
|
762
|
|||||
Disputed
claims and customer refunds
|
1,733
|
2,142
|
|||||
Related
parties
|
37
|
20
|
|||||
Regulatory
balancing accounts
|
840
|
369
|
|||||
Other
|
423
|
337
|
|||||
Interest
payable
|
460
|
461
|
|||||
Income
taxes payable
|
-
|
102
|
|||||
Deferred
income taxes
|
161
|
377
|
|||||
Other
|
1,255
|
869
|
|||||
Total
current liabilities
|
6,757
|
6,786
|
|||||
Noncurrent
Liabilities
|
|||||||
Long-term
debt
|
6,696
|
7,043
|
|||||
Rate
reduction bonds
|
290
|
580
|
|||||
Energy
recovery bonds
|
2,276
|
-
|
|||||
Regulatory
liabilities
|
3,506
|
4,035
|
|||||
Asset
retirement obligations
|
1,587
|
1,301
|
|||||
Deferred
income taxes
|
3,218
|
3,629
|
|||||
Deferred
tax credits
|
112
|
121
|
|||||
Preferred
stock with mandatory redemption provisions (redeemable, 6.30% and
6.57%,
no shares outstanding at December 31, 2005 and 4,925,000 shares
outstanding at December 31, 2004)
|
-
|
122
|
|||||
Other
|
1,691
|
1,555
|
|||||
Total
noncurrent liabilities
|
19,376
|
18,386
|
|||||
Commitments
and Contingencies (Notes 2, 4, 5, 6, 8, 9, 13, 15 and
17)
|
|||||||
Shareholders'
Equity
|
|||||||
Preferred
stock without mandatory redemption provisions :
|
|||||||
Nonredeemable,
5% to 6%, outstanding 5,784,825 shares
|
145
|
145
|
|||||
Redeemable,
4.36% to 5.00%, outstanding 4,534,958 shares in 2005 and 4.36% to
7.04%,
outstanding 5,973,456 shares in 2004
|
113
|
149
|
|||||
Common
stock, $5 par value, authorized 800,000,000 shares, issued 279,624,823
shares in 2005 shares and issued 321,314,760 shares in
2004
|
1,398
|
1,606
|
|||||
Common
stock held by subsidiary, at cost, 19,481,213 shares
|
(475
|
)
|
(475
|
)
|
|||
Additional
paid-in capital
|
1,776
|
2,041
|
|||||
Reinvested
earnings
|
4,702
|
5,667
|
|||||
Accumulated
other comprehensive loss
|
(9
|
)
|
(3
|
)
|
|||
Total
shareholders' equity
|
7,650
|
9,130
|
|||||
TOTAL
LIABILITIES AND SHAREHOLDERS' EQUITY
|
$
|
33,783
|
$
|
34,302
|
Year
ended December 31,
|
||||||||||
2005
|
2004
|
2003
|
||||||||
Cash
Flows From Operating Activities
|
||||||||||
Net
income
|
$
|
934
|
$
|
3,982
|
$
|
923
|
||||
Adjustments
to reconcile net income to net cash provided by operating activities:
|
||||||||||
Depreciation,
amortization, decommissioning and allowance for equity funds used
during
construction
|
1,697
|
1,494
|
1,218
|
|||||||
Recognition
of regulatory assets
|
-
|
(4,900
|
)
|
-
|
||||||
Deferred
income taxes and tax credits, net
|
(636
|
)
|
2,580
|
(75
|
)
|
|||||
Other
deferred charges and noncurrent liabilities
|
21
|
(391
|
)
|
581
|
||||||
Cumulative
effect of a change in accounting principle
|
-
|
-
|
1
|
|||||||
Net
effect of changes in operating assets and liabilities:
|
||||||||||
Accounts
receivable
|
(245
|
)
|
(85
|
)
|
(590
|
)
|
||||
Inventories
|
(60
|
)
|
(12
|
)
|
(17
|
)
|
||||
Accounts
payable
|
257
|
273
|
507
|
|||||||
Accrued
taxes/income taxes receivable
|
(150
|
)
|
52
|
48
|
||||||
Regulatory
balancing accounts, net
|
254
|
(590
|
)
|
(329
|
)
|
|||||
Other
current assets
|
2
|
55
|
12
|
|||||||
Other
current liabilities
|
273
|
395
|
17
|
|||||||
Payments
authorized by the bankruptcy court on amounts classified as liabilities
subject to compromise
|
-
|
(1,022
|
)
|
(87
|
)
|
|||||
Other
|
19
|
7
|
14
|
|||||||
Net
cash provided by operating activities
|
2,366
|
1,838
|
2,223
|
|||||||
Cash
Flows From Investing Activities
|
||||||||||
Capital
expenditures
|
(1,803
|
)
|
(1,559
|
)
|
(1,698
|
)
|
||||
Net
proceeds from sale of assets
|
39
|
35
|
49
|
|||||||
Decrease
(increase) in restricted cash
|
434
|
(1,577
|
)
|
(253
|
)
|
|||||
Proceeds from
nuclear decommissioning trust sales
|
2,918
|
1,821
|
1,087
|
|||||||
Purchases of
nuclear decommissioning trust investments
|
(3,008
|
)
|
(1,972
|
)
|
(1,230
|
)
|
||||
Other
|
61
|
(27
|
)
|
29
|
||||||
Net
cash used in investing activities
|
(1,359
|
)
|
(3,279
|
)
|
(2,016
|
)
|
||||
Cash
Flows From Financing Activities
|
||||||||||
Net
borrowings under accounts receivable facility and working capital
facility
|
260
|
300
|
-
|
|||||||
Net
repayments under working capital facility
|
(300
|
)
|
-
|
-
|
||||||
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
|
)
|
(281
|
)
|
||||
Rate
reduction bonds matured
|
(290
|
)
|
(290
|
)
|
(290
|
)
|
||||
Energy
recovery bonds matured
|
(140
|
)
|
-
|
-
|
||||||
Preferred
stock dividends paid
|
(16
|
)
|
(90
|
)
|
-
|
|||||
Common
stock dividends paid
|
(445
|
)
|
-
|
-
|
||||||
Preferred
stock with mandatory redemption provisions redeemed
|
(122
|
)
|
(15
|
)
|
-
|
|||||
Preferred
stock without mandatory redemption provisions redeemed
|
(37
|
)
|
-
|
-
|
||||||
Common
stock repurchased
|
(1,910
|
)
|
-
|
-
|
||||||
Other
|
65
|
-
|
-
|
|||||||
Net
cash used in financing activities
|
(1,327
|
)
|
(755
|
)
|
(571
|
)
|
||||
Net
change in cash and cash equivalents
|
(320
|
)
|
(2,196
|
)
|
(364
|
)
|
||||
Cash
and cash equivalents at January 1
|
783
|
2,979
|
3,343
|
|||||||
Cash
and cash equivalents at December 31
|
$
|
463
|
$
|
783
|
$
|
2,979
|
Year
ended December 31,
|
||||||||||
2005
|
2004
|
2003
|
Supplemental
disclosures of cash flow information
|
||||||||||
Cash
received for:
|
||||||||||
Reorganization
interest income
|
$
|
-
|
$
|
16
|
$
|
39
|
||||
Cash
paid for:
|
||||||||||
Interest
(net of amounts capitalized)
|
390
|
512
|
773
|
|||||||
Income
taxes paid, net
|
1,397
|
109
|
648
|
|||||||
Reorganization
professional fees and expenses
|
-
|
61
|
99
|
|||||||
Supplemental
disclosures of noncash investing and financing
activities
|
||||||||||
Transfer
of liabilities and other payables subject to compromise (to) from
operating assets and liabilities
|
$
|
-
|
$
|
(2,877
|
)
|
$
|
181
|
|||
Equity
contribution for settlement of plan of reorganization, or POR,
payable
|
-
|
(129
|
)
|
-
|
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, 2002
|
$
|
294
|
$
|
1,606
|
$
|
1,964
|
$
|
(475
|
)
|
$
|
805
|
$ |
-
|
$
|
4,194
|
||||||||||
Net
income
|
-
|
-
|
-
|
-
|
923
|
-
|
923
|
$
|
923
|
||||||||||||||||
Retirement
plan remeasurement (net of income tax benefit of $2
million)
|
-
|
-
|
-
|
-
|
-
|
(3
|
) |
(3
|
)
|
(3
|
)
|
||||||||||||||
Mark-to-market
adjustments for hedging transactions in accordance with SFAS No.
133 (net
of income tax benefit of $2 million)
|
-
|
-
|
-
|
-
|
-
|
(3
|
) |
(3
|
) |
(3
|
) | ||||||||||||||
Comprehensive
income
|
$
|
917
|
|||||||||||||||||||||||
Preferred
stock dividend
|
-
|
-
|
-
|
-
|
(22
|
) |
-
|
(22
|
) | ||||||||||||||||
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
|
·
|
Labor
and materials;
|
·
|
Construction
overhead; and
|
·
|
Allowance
for funds used during construction, or AFUDC.
|
Gross
Plant
|
Estimated
Useful Lives
|
||||||
(in
millions)
|
As
of December 31, 2005
|
||||||
Electricity
generating facilities
|
$
|
1,929
|
15
to 44 years
|
||||
Electricity
distribution facilities
|
14,551
|
16
to 58 years
|
|||||
Electricity
transmission
|
3,892
|
40
to 70 years
|
|||||
Natural
gas distribution facilities
|
4,838
|
23
to 54 years
|
|||||
Natural
gas transportation
|
2,948
|
25
to 45 years
|
|||||
Natural
gas storage
|
47
|
25
to 48 years
|
|||||
Other
|
3,071
|
5
to 40 years
|
|||||
Total
|
$
|
31,276
|
·
|
T
he
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, 2005 and 2004;
|
·
|
The
estimated
fair values of the Utility’s fixed rate Senior Notes, fixed rate pollution
control bond loan agreements, rate reduction bonds, energy recovery
bonds,
or ERBs, and the Utility's preferred stock were based on market prices
obtained from the Bloomberg financial information system;
and
|
·
|
The
estimated
fair value of PG&E Corporation’s 9.50% Convertible Subordinated debt
was determined by a third-party by considering the values embedded
in
reported trade prices and employing these values in a proprietary
option
valuation model (using a stock volatility assumption of between 15
- 20%).
|
At
December 31,
|
|||||||||||||
2005
|
2004
|
||||||||||||
Carrying
Amount
|
Fair
Value
|
Carrying
Amount
|
Fair
Value
|
||||||||||
(in
millions)
|
|||||||||||||
Long-term
debt (Note 4):
|
|||||||||||||
PG&E
Corporation
|
$
|
280
|
$
|
783
|
$
|
280
|
$
|
738
|
|||||
Utility
|
5,628
|
5,720
|
5,632
|
5,813
|
|||||||||
Rate
reduction bonds (Note 5)
|
580
|
591
|
870
|
911
|
|||||||||
Energy
recovery bonds (Note 6)
|
2,592
|
2,558
|
-
|
-
|
|||||||||
Utility
preferred stock with mandatory redemption provisions (Note
9)
|
-
|
-
|
122
|
127
|
Hedging
Transactions in Accordance with SFAS No. 133
|
Foreign
Currency Translation Adjustment
|
Minimum
Pension Liability Adjustment
|
Other
|
Accumulated
Other Comprehensive Income (Loss)
|
||||||||||||
Balance
at
December
31, 2002
|
$
|
(90
|
)
|
$
|
(3
|
)
|
$
|
-
|
$
|
-
|
$
|
(93
|
)
|
|||
Period
change in:
|
||||||||||||||||
Mark-to-market
adjustments for hedging transactions in accordance with SFAS No.
133
|
(8
|
)
|
-
|
-
|
-
|
(8
|
)
|
|||||||||
Net
reclassification
to
earnings
|
17
|
-
|
-
|
-
|
17
|
|||||||||||
Other
|
-
|
3
|
(4
|
)
|
-
|
(1
|
)
|
|||||||||
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
|
)
|
Years
ended December 31,
|
||||||||||
|
2005
|
2004
|
2003
|
|||||||
(in millions, except per share amounts) | ||||||||||
Net
earnings:
|
||||||||||
As
reported
|
$
|
917
|
$
|
4,504
|
$
|
420
|
||||
Deduct:
Incremental stock-based employee compensation expense determined
under the
fair value based method for all awards, net of related tax
effects
|
(12
|
)
|
(14
|
)
|
(19
|
)
|
||||
Pro
forma
|
$
|
905
|
$
|
4,490
|
$
|
401
|
||||
Basic
earnings per share:
|
||||||||||
As
reported
|
$
|
2.40
|
$
|
10.80
|
$
|
1.04
|
||||
Pro
forma
|
2.37
|
10.77
|
0.99
|
|||||||
Diluted
earnings per share:
|
||||||||||
As
reported
|
2.37
|
10.57
|
1.02
|
|||||||
Pro
forma
|
2.33
|
10.59
|
0.97
|
Years
ended December 31,
|
||||||||||
2005
|
2004
|
2003
|
||||||||
(in
millions)
|
||||||||||
Net
earnings:
|
||||||||||
As
reported
|
$
|
918
|
$
|
3,961
|
$
|
901
|
||||
Deduct:
Incremental stock-based employee compensation expense determined
under the
fair value based method for all awards, net of related tax
effects
|
(7
|
)
|
(8
|
)
|
(8
|
)
|
||||
Pro
forma
|
$
|
911
|
$
|
3,953
|
$
|
893
|
Balance
at December 31,
|
|||||||
2005
|
2004
|
||||||
(in
millions)
|
|||||||
Settlement
regulatory asset
|
$
|
-
|
$
|
3,188
|
|||
Energy
recovery bond regulatory asset
|
2,509
|
-
|
|||||
Utility
retained generation regulatory assets
|
1,099
|
1,181
|
|||||
Rate
reduction bond assets
|
456
|
741
|
|||||
Regulatory
assets for deferred income tax
|
536
|
490
|
|||||
Unamortized
loss, net of gain, on reacquired debt
|
321
|
345
|
|||||
Environmental
compliance costs
|
310
|
192
|
|||||
Post-transition
period contract termination costs
|
131
|
142
|
|||||
Regulatory
assets associated with plan of reorganization
|
163
|
182
|
|||||
Other,
net
|
53
|
65
|
|||||
Total
regulatory assets
|
$
|
5,578
|
$
|
6,526
|
Balance
at December 31,
|
|||||||
2005
|
2004
|
||||||
(in
millions)
|
|||||||
Cost
of removal obligation
|
$
|
2,141
|
$
|
1,990
|
|||
Asset
retirement costs
|
538
|
700
|
|||||
Employee
benefit plans
|
195
|
687
|
|||||
Price
risk management
|
213
|
-
|
|||||
Public
purpose programs
|
154
|
191
|
|||||
Rate
reduction bonds
|
157
|
182
|
|||||
Other
|
108
|
285
|
|||||
Total
regulatory liabilities
|
$
|
3,506
|
$
|
4,035
|
Balance
at December 31,
|
|||||||
2005
|
2004
|
||||||
(in
millions)
|
|||||||
Natural
gas revenue and cost balancing accounts
|
$
|
159
|
$
|
171
|
|||
Electricity
revenue and cost balancing accounts
|
568
|
850
|
|||||
Total
|
$
|
727
|
$
|
1,021
|
Balance
at December 31,
|
|||||||
2005
|
2004
|
||||||
(in
millions)
|
|||||||
Natural
gas revenue and cost balancing accounts
|
$
|
13
|
$
|
34
|
|||
Electricity
revenue and cost balancing accounts
|
827
|
335
|
|||||
Total
|
$
|
840
|
$
|
369
|
December
31,
|
|||||||
2005
|
2004
|
||||||
(in
millions)
|
|||||||
PG&E
Corporation
|
|||||||
Convertible
subordinated notes, 9.50%, due 2010
|
$
|
280
|
$
|
280
|
|||
Other
long-term debt
|
-
|
1
|
|||||
Less:
current portion
|
-
|
(1
|
)
|
||||
280
|
280
|
||||||
Utility
|
|||||||
Senior
notes/first mortgage bonds
(1)
:
|
|||||||
3.60%
to 6.05% bonds, due 2009-2034
|
5,100
|
6,200
|
|||||
Unamortized
discount, net of premium
|
(17
|
)
|
(17
|
)
|
|||
Total
senior notes/first mortgage bonds
|
5,083
|
6,183
|
|||||
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
|
-
|
|||||
Pollution
control bond reimbursement agreements, variable rates, due
2005
|
-
|
454
|
|||||
Other
|
2
|
4
|
|||||
Less:
current portion
|
(2
|
)
|
(757
|
)
|
|||
Long-term
debt, net of current portion
|
6,696
|
7,043
|
|||||
Total
consolidated long-term debt, net of current
portion
|
$
|
6,976
|
$
|
7,323
|
|||
(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, 2005, interest rates on these loans ranged from 3.70%
to
3.79%.
|
|||||||
(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, 2005, interest rates on these loans ranged from 3.10%
to
3.35%.
|
(in
millions)
|
2006
|
2007
|
2008
|
2009
|
2010
|
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
|
-
|
3.50
|
%
|
-
|
3.60
|
%
|
-
|
5.56
|
%
|
5.22
|
%
|
||||||||||||||
Fixed
rate obligations
|
$ |
-
|
$
|
345
|
(1)
|
$
|
-
|
$
|
600
|
$ |
-
|
$ |
4,683
|
$ |
5,628
|
||||||||||
Variable
interest rate as of December 31, 2005
|
-
|
-
|
-
|
-
|
3.73
|
%
|
3.20
|
%
|
3.51
|
%
|
|||||||||||||||
Variable
rate obligations
|
$ |
-
|
$ |
-
|
$ |
-
|
$ |
-
|
$
|
614
|
(2) | $ |
454
|
$ |
1,068
|
||||||||||
Other
|
$ |
2
|
$ |
-
|
$ |
-
|
$ |
-
|
$ |
-
|
$ |
-
|
$ |
2
|
|||||||||||
Total
consolidated long-term debt
|
$
|
2
|
$
|
345
|
$
|
-
|
$
|
600
|
$
|
894
|
$ |
5,137
|
$ |
6,978
|
(1)
The $345 million pollution control bonds, due in 2023, are subject
to a
mandatory tender for purchase on June 1, 2007. Under the loan agreement,
unless the Utility remarkets the bonds by June 1, 2007, the bonds
will
either be returned to the bondholders and bear interest at a daily
rate
equal to 10% or the Utility has the option to redeem the bonds.
Accordingly, these bonds are classified for repayment purposes
in
2007.
|
(2)
The $614 million pollution control bonds, due in 2026, are backed
by
letters of credit which expire on April 22, 2010. The Utility 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.
|
2006
|
2007
|
2008
|
2009
|
2010
|
Thereafter
|
Total
|
||||||||||||||||
Utility
|
||||||||||||||||||||||
Average
fixed interest rate
|
6.44
|
%
|
6.48
|
%
|
-
|
-
|
-
|
- |
6.46
|
%
|
||||||||||||
Rate
reduction bonds
|
$
|
290
|
$
|
290
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
580
|
||||||||
Average
fixed interest rate
|
3.94
|
%
|
4.19
|
%
|
4.19
|
%
|
4.36
|
%
|
4.49
|
%
|
4.63
|
%
|
4.37
|
%
|
||||||||
Energy
recovery bonds
|
$
|
316
|
$
|
340
|
$
|
354
|
$
|
369
|
$
|
386
|
$
|
827
|
$
|
2,592
|
(in
millions)
|
|||||||||||||||
At
December 31, 2005
|
|||||||||||||||
Authorized
Borrower
|
Facility
|
Termination
Date
|
Facility
Limit
|
Letters
of Credit Out-standing
|
Cash
Borrowings
|
Availability
|
|||||||||
PG&E
Corporation
|
Senior
credit facility
|
December
2009
|
$
|
200
|
(1)
|
$
|
-
|
$
|
-
|
$
|
200
|
||||
Utility
|
Accounts
receivable financing
|
March
2007
|
650
|
-
|
260
|
390
|
|||||||||
Utility
|
Working
capital facility
|
April
2010
|
1,350
|
(2)
|
242
|
-
|
1,108
|
||||||||
Total
credit facilities
|
$
|
2,200
|
$
|
242
|
$
|
260
|
$
|
1,698
|
|||||||
(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 thirty 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 thirty
days.
|
(in
millions)
|
||||
Investment
in NEGT
|
$
|
1,208
|
||
Accumulated
other comprehensive income
|
(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)
|
2005
|
2004
|
2003
|
|||||||
|
||||||||||
Net
Income
|
$
|
917
|
$
|
4,504
|
$
|
420
|
||||
Less:
distributed earnings to common shareholders
|
449
|
-
|
-
|
|||||||
Undistributed
earnings
|
468
|
4,504
|
420
|
|||||||
Less:
undistributed earnings (loss) from discontinued operations
|
13
|
684
|
(365
|
) | ||||||
Undistributed
earnings before cumulative effect of changes in accounting
principles
|
455
|
3,820
|
785
|
|||||||
Less:
undistributed earnings (loss) from cumulative effect of changes
in
accounting principles
|
-
|
-
|
(6
|
) | ||||||
Undistributed
earnings from continuing operations
|
$
|
455
|
$
|
3,820
|
$
|
791
|
||||
Common
shareholders earnings
|
||||||||||
Basic
|
||||||||||
Distributed
earnings to common shareholders
|
$ |
449
|
$ |
-
|
$ |
-
|
||||
Undistributed
earnings allocated to common shareholders - continuing
operations
|
433
|
3,646
|
754
|
|||||||
Undistributed
earnings (loss) allocated to common shareholders - discontinued
operations
|
12
|
653
|
(348
|
) | ||||||
Undistributed
earnings (loss) allocated to common shareholders - cumulative effect
of
changes in accounting principles
|
-
|
-
|
(6
|
) | ||||||
Total
common shareholders earnings, basic
|
$
|
894
|
$
|
4,299
|
$
|
400
|
||||
Diluted
|
||||||||||
Distributed
earnings to common shareholders
|
$ |
449
|
$ |
-
|
$ |
-
|
||||
Undistributed
earnings allocated to common shareholders - continuing
operations
|
433
|
3,650
|
755
|
|||||||
Undistributed
earnings (loss) allocated to common shareholders - discontinued
operations
|
12
|
653
|
(348
|
) | ||||||
Undistributed
earnings (loss) allocated to common shareholders - cumulative effect
of
changes in accounting principles
|
-
|
-
|
(6
|
) | ||||||
Total
common shareholders earnings, diluted
|
$ |
894
|
$ |
4,303
|
$ |
401
|
||||
Weighted
average common shares outstanding, basic
|
372
|
398
|
385
|
|||||||
9.50%
Convertible Subordinated Notes
|
19
|
19
|
19
|
|||||||
Weighted
average common shares outstanding and participating securities,
basic
|
391
|
417
|
404
|
|||||||
Weighted
average common shares outstanding, basic
|
372
|
398
|
385
|
|||||||
Employee
stock-based compensation and accelerated share repurchase program
(1)
|
6
|
7
|
4
|
|||||||
PG&E
Corporation warrants
|
-
|
2
|
5
|
|||||||
Weighted
average common shares outstanding, diluted
|
|
378
|
|
407
|
|
394
|
||||
9.50%
Convertible Subordinated Notes
|
19
|
19
|
19
|
|||||||
Weighted
average common shares outstanding and participating securities,
diluted
|
397
|
426
|
413
|
|||||||
Net
earnings per common share, basic
|
||||||||||
Distributed
earnings, basic
(2)
|
$
|
1.21
|
$ |
-
|
$ |
-
|
||||
Undistributed
earnings - continuing operations, basic
|
1.16
|
9.16
|
1.96
|
|||||||
Undistributed
earnings (loss) - discontinued operations, basic
|
0.03
|
1.64
|
(0.90
|
)
|
||||||
Undistributed
earnings (loss) - cumulative effect of changes in accounting
principles
|
-
|
-
|
(0.01
|
)
|
||||||
Rounding
|
-
|
-
|
(0.01
|
)
|
||||||
Total
|
$
|
2.40
|
$
|
10.80
|
$
|
1.04
|
Year
ended December 31,
|
||||||||||
(in
millions, except per share amounts)
|
2005
|
2004
|
2003
|
|||||||
Net
earnings per common share, diluted
|
||||||||||
Distributed
earnings, diluted
|
$
|
1.19
|
$
|
-
|
$
|
-
|
||||
Undistributed
earnings - continuing operations, diluted
|
1.15
|
8.97
|
1.92
|
|||||||
Undistributed
earnings (loss) - discontinued operations, diluted
|
0.03
|
1.60
|
(0.88
|
)
|
||||||
Undistributed
earnings (loss) - cumulative effect of changes in accounting
principles
|
-
|
-
|
(0.01
|
)
|
||||||
Rounding
|
-
|
-
|
(0.01
|
)
|
||||||
Total
|
$
|
2.37
|
$
|
10.57
|
$
|
1.02
|
(1)
Includes
approximately 2 million shares and 222,000 shares, respectively,
of
PG&E Corporation common stock potentially issuable in settlement of
an
obligation of PG&E Corporation of approximately $71 million and $7.4
million, respectively,
under
an ASR at December 31, 2005 and December 31, 2004, respectively.
See Note
8 for further discussion. The remaining shares, approximately 4 million
at
December 31, 2005 and 6.8 million shares at December 31, 2004, are
deemed
to be outstanding per SFAS No. 128 for the purpose of calculating
EPS.
See Note 2 under “Earnings Per Share.”
|
|||||||
(2)
Distributed
earnings, basic differs from actual per share amounts paid as dividends
as
the EPS computation under GAAP requires that we use the weighted
average, rather than the actual number of shares outstanding.
|
PG&E
Corporation
|
Utility
|
||||||||||||||||||
Year
Ended December 31,
|
|||||||||||||||||||
2005
|
2004
|
2003
|
2005
|
2004
|
2003
|
||||||||||||||
(in
millions)
|
|||||||||||||||||||
Current:
|
|||||||||||||||||||
Federal
|
$
|
1,027
|
$
|
121
|
$
|
61
|
$
|
1,048
|
$
|
73
|
$
|
524
|
|||||||
State
|
189
|
91
|
41
|
196
|
85
|
171
|
|||||||||||||
Deferred:
|
|||||||||||||||||||
Federal
|
(574
|
)
|
1,877
|
422
|
(572
|
)
|
2,000
|
(88
|
)
|
||||||||||
State
|
(89
|
)
|
384
|
(49
|
)
|
(89
|
)
|
410
|
(62
|
)
|
|||||||||
Tax
credits, net
|
(9
|
)
|
(7
|
)
|
(17
|
)
|
(9
|
)
|
(7
|
)
|
(17
|
)
|
|||||||
Income
tax expense
|
$
|
544
|
$
|
2,466
|
$
|
458
|
$
|
574
|
$
|
2,561
|
$
|
528
|
PG&E
Corporation
|
Utility
|
||||||||||||
Year
ended December 31,
|
|||||||||||||
2005
|
2004
|
2005
|
2004
|
||||||||||
(in millions) | |||||||||||||
Deferred
income tax assets:
|
|||||||||||||
Customer
advances for construction
|
$
|
607
|
$
|
472
|
$
|
607
|
$
|
472
|
|||||
Unamortized investment tax credits | 106 | 108 | 106 | 108 | |||||||||
Reserve
for damages
|
276
|
270
|
276
|
270
|
|||||||||
Environmental
reserve
|
188
|
194
|
188
|
194
|
|||||||||
Other
|
366
|
151
|
260
|
70
|
|||||||||
Total
deferred income tax assets
|
$
|
1,543
|
$
|
1,195
|
$
|
1,437
|
$
|
1,114
|
|||||
Deferred
income tax liabilities:
|
|||||||||||||
Regulatory
balancing accounts
|
$
|
1,719
|
$
|
2,097
|
$
|
1,719
|
$
|
2,097
|
|||||
Property
related basis differences
|
2,694
|
2,413
|
2,694
|
2,413
|
|||||||||
Income
tax regulatory asset
|
218
|
209
|
218
|
209
|
|||||||||
Unamortized
loss on reacquired debt
|
128
|
137
|
128
|
137
|
|||||||||
Other
|
57
|
264
|
57
|
264
|
|||||||||
Total
deferred income tax liabilities
|
$
|
4,816
|
$
|
5,120
|
$
|
4,816
|
$
|
5,120
|
|||||
Total
net deferred income tax liabilities
|
$
|
3,273
|
$
|
3,925
|
$
|
3,379
|
$
|
4,006
|
|||||
Classification
of net deferred income tax liabilities:
|
|||||||||||||
Included
in current liabilities
|
$
|
181
|
$
|
394
|
$
|
161
|
$
|
377
|
|||||
Included
in noncurrent liabilities
|
3,092
|
3,531
|
3,218
|
3,629
|
|||||||||
Total
net deferred income tax liabilities
|
$
|
3,273
|
$
|
3,925
|
$
|
3,379
|
$
|
4,006
|
PG&E
Corporation
|
Utility
|
||||||||||||||||||
Year
Ended December 31,
|
|||||||||||||||||||
2005
|
2004
|
2003
|
2005
|
2004
|
2003
|
||||||||||||||
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)
|
4.5
|
4.6
|
4.7
|
4.7
|
4.7
|
4.9
|
|||||||||||||
Effect
of regulatory treatment of depreciation differences
|
0.9
|
(0.5
|
)
|
(2.9
|
)
|
0.9
|
(0.4
|
)
|
(2.5
|
)
|
|||||||||
Tax
credits, net
|
(1.0
|
)
|
(0.2
|
)
|
(1.7
|
)
|
(1.0
|
)
|
(0.2
|
)
|
(1.5
|
)
|
|||||||
Other,
net
|
(1.8
|
)
|
0.3
|
1.3
|
(1.6
|
)
|
0.2
|
0.5
|
|||||||||||
Effective
tax rate
|
37.6
|
%
|
39.2
|
%
|
36.4
|
%
|
38.0
|
%
|
39.3
|
%
|
36.4
|
%
|
Maturity
Date
|
Total
Unrealized
Gains
|
Total
Unrealized
Losses
|
Estimated
Fair Value
|
||||||||||
(in
millions)
|
|||||||||||||
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, 2004
|
|||||||||||||
U.S.
government and agency issues
|
2005-2033
|
$
|
47
|
$
|
-
|
$
|
681
|
||||||
Municipal
bonds and other
|
2005-2034
|
14
|
-
|
181
|
|||||||||
Equity
securities
|
523
|
-
|
880
|
||||||||||
Total
|
$
|
584
|
$
|
-
|
$
|
1,742
|
Year
Ended December 31,
|
||||||||||
2005
|
2004
|
2003
|
||||||||
(in
millions)
|
||||||||||
Proceeds
received from sales of securities
|
$
|
2,918
|
$
|
1,821
|
$
|
1,087
|
||||
Gross
realized gains on sales of securities held as
available-for-sale
|
56
|
28
|
27
|
|||||||
Gross
realized losses on sales of securities held as
available-for-sale
|
(14
|
)
|
(22
|
)
|
(44
|
)
|
PG&E
Corporation
|
Utility
|
||||||||||||
2005
|
2004
|
2005
|
2004
|
||||||||||
(in millions) | |||||||||||||
Projected
benefit obligation at January 1
|
$
|
8,557
|
$
|
7,516
|
$
|
8,551
|
$
|
7,509
|
|||||
Service
cost for benefits earned
|
214
|
194
|
211
|
194
|
|||||||||
Interest
cost
|
500
|
482
|
498
|
482
|
|||||||||
Plan
amendments
|
(7
|
)
|
28
|
(3
|
)
|
28
|
|||||||
Actuarial
loss
|
331
|
667
|
326
|
667
|
|||||||||
Settlement
|
-
|
-
|
-
|
-
|
|||||||||
Benefits
and expenses paid
|
(348
|
)
|
(330
|
)
|
(347
|
)
|
(329
|
)
|
|||||
Other
(1)
|
2
|
-
|
(25
|
)
|
-
|
||||||||
Projected
benefit obligation at December 31
|
$
|
9,249
|
$
|
8,557
|
$
|
9,211
|
$
|
8,551
|
|||||
Accumulated
benefit obligation
|
$
|
8,276
|
$
|
7,638
|
$
|
8,246
|
$
|
7,632
|
|||||
(1)
In
2004,
the
pension
benefits included a Supplemental Executive Retirement Plan
sponsored by the Utility. In 2005, this 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
|
||||||||||||
2005
|
2004
|
2005
|
2004
|
||||||||||
(in
millions)
|
|||||||||||||
Benefit
obligation at January 1
|
$
|
1,399
|
$
|
1,444
|
$
|
1,399
|
$
|
1,444
|
|||||
Service
cost for benefits earned
|
30
|
32
|
30
|
32
|
|||||||||
Interest
cost
|
74
|
85
|
74
|
85
|
|||||||||
Actuarial
loss
|
(103
|
)
|
(103
|
)
|
(103
|
)
|
(103
|
)
|
|||||
Participants
paid benefits
|
30
|
30
|
30
|
30
|
|||||||||
Plan
amendments
|
-
|
-
|
-
|
-
|
|||||||||
Benefits
paid
|
(91
|
)
|
(89
|
)
|
(91
|
)
|
(89
|
)
|
|||||
Benefit
obligation at December 31
|
$
|
1,339
|
$
|
1,399
|
$
|
1,339
|
$
|
1,399
|
PG&E
Corporation
|
Utility
|
||||||||||||
2005
|
2004
|
2005
|
2004
|
||||||||||
(in
millions)
|
|||||||||||||
Fair
value of plan assets at January 1
|
$
|
7,614
|
$
|
7,129
|
$
|
7,614
|
$
|
7,129
|
|||||
Actual
return on plan assets
|
758
|
787
|
758
|
787
|
|||||||||
Company
contributions
|
25
|
27
|
24
|
27
|
|||||||||
Settlement
|
-
|
-
|
-
|
-
|
|||||||||
Benefits
and expenses paid
|
(348
|
)
|
(329
|
)
|
(347
|
)
|
(329
|
)
|
|||||
Fair
value of plan assets at December 31
|
$
|
8,049
|
$
|
7,614
|
$
|
8,049
|
$
|
7,614
|
PG&E
Corporation
|
Utility
|
||||||||||||
2005
|
2004
|
2005
|
2004
|
||||||||||
(in
millions)
|
|||||||||||||
Fair
value of plan assets at January 1
|
$
|
1,069
|
$
|
955
|
$
|
1,069
|
$
|
955
|
|||||
Actual
return on plan assets
|
86
|
108
|
86
|
108
|
|||||||||
Company
contributions
|
59
|
71
|
59
|
71
|
|||||||||
Plan
participant contribution
|
30
|
30
|
30
|
30
|
|||||||||
Benefits
and expenses paid
|
(98
|
)
|
(95
|
)
|
(98
|
)
|
(95
|
)
|
|||||
Fair
value of plan assets at December 31
|
$
|
1,146
|
$
|
1,069
|
$
|
1,146
|
$
|
1,069
|
PG&E
Corporation
|
Utility
|
||||||||||||
December
31,
|
December
31,
|
||||||||||||
2005
|
2004
|
2005
|
2004
|
||||||||||
(in
millions)
|
|||||||||||||
Fair
value of plan assets at December 31
|
$
|
8,049
|
$
|
7,614
|
$
|
8,049
|
$
|
7,614
|
|||||
Projected
benefit obligation at December 31
|
(9,249
|
)
|
(8,557
|
)
|
(9,211
|
)
|
(8,551
|
)
|
|||||
Funded
status plan assets less than projected benefit obligation
|
(1,200
|
)
|
(943
|
)
|
(1,162
|
)
|
(937
|
)
|
|||||
Unrecognized
prior service cost
|
321
|
378
|
327
|
378
|
|||||||||
Unrecognized
net loss
|
1,314
|
1,148
|
1,302
|
1,148
|
|||||||||
Unrecognized
net transition obligation
|
1
|
2
|
-
|
2
|
|||||||||
Prepaid
benefit cost
|
$
|
436
|
$
|
585
|
$
|
467
|
$
|
591
|
|||||
Prepaid
benefit cost
|
$
|
491
|
$
|
638
|
$
|
491
|
$
|
638
|
|||||
Accrued
benefit liability
|
(55
|
)
|
(53
|
)
|
(24
|
)
|
(47
|
)
|
|||||
Additional
minimum liability
|
(671
|
)
|
-
|
(668
|
)
|
-
|
|||||||
Intangible
asset
|
332
|
-
|
332
|
-
|
|||||||||
Excess
additional minimum liability
(1)
|
339
|
-
|
336
|
-
|
|||||||||
Prepaid
benefit cost
|
$
|
436
|
$
|
585
|
$
|
467
|
$
|
591
|
|||||
(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 the year ended December
31,
2005.
|
PG&E
Corporation
|
Utility
|
||||||||||||
December
31,
|
December
31,
|
||||||||||||
2005
|
2004
|
2005
|
2004
|
||||||||||
(in
millions)
|
|||||||||||||
Fair
value of plan assets at December 31
|
$
|
1,146
|
$
|
1,069
|
$
|
1,146
|
$
|
1,069
|
|||||
Benefit
obligation at December 31
|
(1,339
|
)
|
(1,399
|
)
|
(1,339
|
)
|
(1,399
|
)
|
|||||
Funded
status plan assets less than benefit obligation
|
(193
|
)
|
(330
|
)
|
(193
|
)
|
(330
|
)
|
|||||
Unrecognized
prior service cost
|
132
|
110
|
132
|
110
|
|||||||||
Unrecognized
net loss (gain)
|
(129
|
)
|
1
|
(129
|
)
|
1
|
|||||||
Unrecognized
net transition obligation
|
179
|
205
|
179
|
205
|
|||||||||
Accrued
benefit cost
|
$
|
(11
|
)
|
$
|
(14
|
)
|
$
|
(11
|
)
|
$
|
(14
|
)
|
|
Prepaid
benefit cost
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
-
|
|||||
Accrued
benefit liability
|
(11
|
)
|
(14
|
)
|
(11
|
)
|
(14
|
)
|
|||||
Additional
minimum liability
|
-
|
-
|
-
|
-
|
|||||||||
Accrued
benefit cost
|
$
|
(11
|
)
|
$
|
(14
|
)
|
$
|
(11
|
)
|
$
|
(14
|
)
|
Pension
Benefits
|
Other
Benefits
|
||||||||||||
2005
|
2004
|
2005
|
2004
|
||||||||||
(in
millions)
|
|||||||||||||
PG&E
Corporation:
|
|||||||||||||
Projected
benefit obligation
|
$
|
(9,249
|
)
|
$
|
(8,557
|
)
|
$
|
(1,339
|
)
|
$
|
(1,399
|
)
|
|
Accumulated
benefit obligation
|
(8,276
|
)
|
(7,638
|
)
|
-
|
-
|
|||||||
Fair
value of plan assets
|
8,049
|
7,614
|
1,146
|
1,069
|
|||||||||
Utility:
|
|||||||||||||
Projected
benefit obligation
|
$
|
(9,211
|
)
|
$
|
(8,551
|
)
|
$
|
(1,339
|
)
|
$
|
(1,399
|
)
|
|
Accumulated
benefit obligation
|
(8,246
|
)
|
(7,632
|
)
|
-
|
-
|
|||||||
Fair
value of plan assets
|
8,049
|
7,614
|
1,146
|
1,069
|
December
31,
|
||||||||||
2005
|
2004
|
2003
|
||||||||
(in
millions)
|
||||||||||
Service
cost for benefits earned
|
$
|
215
|
$
|
194
|
$ |
170
|
||||
Interest
cost
|
500
|
482
|
446
|
|||||||
Expected
return on plan assets
|
(623
|
)
|
(563
|
)
|
(507
|
)
|
||||
Amortized
prior service cost
|
55
|
63
|
56
|
|||||||
Amortization
of unrecognized loss
|
29
|
6
|
46
|
|||||||
Settlement
loss
|
-
|
-
|
1
|
|||||||
Net
periodic benefit cost
|
$
|
176
|
$
|
182
|
$ |
212
|
December
31,
|
||||||||||
2005
|
2004
|
2003
|
||||||||
(in
millions)
|
||||||||||
Service
cost for benefits earned
|
$
|
30
|
$
|
32
|
$ |
29
|
||||
Interest
cost
|
74
|
84
|
79
|
|||||||
Expected
return on plan assets
|
(85
|
)
|
(76
|
)
|
(61
|
)
|
||||
Amortized
prior service cost
|
37
|
38
|
28
|
|||||||
Amortization
of unrecognized loss (gain)
|
(1
|
)
|
-
|
1
|
||||||
Net
periodic benefit cost
|
$
|
55
|
$
|
78
|
$ |
76
|
Pension
Benefits
|
Other
Benefits
|
||||||||||||||||||
December
31,
|
December
31,
|
||||||||||||||||||
2005
|
2004
|
2003
|
2005
|
2004
|
2003
|
||||||||||||||
Discount
rate
|
5.60
|
%
|
5.80
|
%
|
6.25
|
%
|
5.20
- 5.65
|
%
|
5.80
|
%
|
6.25
|
%
|
|||||||
Average
rate of future compensation increases
|
5.00
|
%
|
5.00
|
%
|
5.00
|
%
|
-
|
-
|
-
|
||||||||||
Expected
return on plan assets
|
|||||||||||||||||||
Pension
benefits
|
8.00
|
%
|
8.10
|
%
|
8.10
|
%
|
-
|
-
|
-
|
||||||||||
Other
benefits:
|
|||||||||||||||||||
Defined
benefit—medical plan bargaining
|
-
|
-
|
-
|
8.40
|
%
|
8.50
|
%
|
8.50
|
%
|
||||||||||
Defined
benefit—medical plan non-bargaining
|
-
|
-
|
-
|
7.60
|
%
|
7.60
|
%
|
7.60
|
%
|
||||||||||
Defined
benefit—life insurance plan
|
-
|
-
|
-
|
8.40
|
%
|
8.50
|
%
|
8.50
|
%
|
(in
millions)
|
One-Percentage
Point Increase
|
One-Percentage
Point Decrease
|
|||||
Effect
on postretirement benefit obligation
|
$
|
68
|
$
|
(54
|
)
|
||
Effect
on service and interest cost
|
8
|
(7
|
)
|
Pension
Benefits
|
Other
Benefits
|
||||||||||||||||||
2006
|
2005
|
2004
|
2006
|
2005
|
2004
|
||||||||||||||
Equity
securities
|
|||||||||||||||||||
U.S.
equity
|
40
|
%
|
41
|
%
|
43
|
%
|
51
|
%
|
51
|
%
|
51
|
%
|
|||||||
Non-U.S.
equity
|
20
|
%
|
24
|
%
|
22
|
%
|
20
|
%
|
20
|
%
|
21
|
%
|
|||||||
Fixed
income securities
|
40
|
%
|
35
|
%
|
35
|
%
|
29
|
%
|
29
|
%
|
28
|
%
|
|||||||
Total
|
100
|
%
|
100
|
%
|
100
|
%
|
100
|
%
|
100
|
%
|
100
|
%
|
PG&E
Corporation
|
Utility
|
||||||
(in
millions)
|
|||||||
Pension
|
|||||||
2006
|
$
|
372
|
$ |
370
|
|||
2007
|
393
|
392
|
|||||
2008
|
417
|
415
|
|||||
2009
|
442
|
440
|
|||||
2010
|
468
|
466
|
|||||
2011-2015
|
2,756
|
2,743
|
|||||
Other
benefits
|
|||||||
2006
|
$
|
82
|
$
|
82
|
|||
2007
|
82
|
82
|
|||||
2008
|
84
|
84
|
|||||
2009
|
85
|
85
|
|||||
2010
|
87
|
87
|
|||||
2011-2015
|
474
|
474
|
(in
millions)
|
PG&E
Corporation
|
Utility
|
|||||
Year ended December 31, | |||||||
2005
|
$
|
43
|
$ |
42
|
|||
2004
|
40
|
39
|
|||||
2003
(1)
|
38
|
37
|
|||||
(1)
Includes
NEGT-related amounts within PG&E Corporation.
|
2005
|
2004
|
2003
|
||||||||
Expected
stock price volatility
|
40.6
|
%
|
45.0
|
%
|
45.0
|
%
|
||||
Expected
annual dividend payment
|
$
|
1.20
|
$
|
1.20
|
$
|
-
|
||||
Risk-free
interest rate
|
3.74
|
%
|
3.66
|
%
|
3.46
|
%
|
||||
Expected
life
|
5.9
years
|
6.5
years
|
6.5
years
|
2005
|
2004
|
2003
|
|||||||||||||||||
Shares
|
Weighted
Average
Option Price
|
Shares
|
Weighted
Average
Option Price
|
Shares
|
Weighted
Average
Option Price
|
||||||||||||||
Outstanding
at January 1
|
20,878,558
|
$
|
22.76
|
27,416,380
|
$
|
21.26
|
31,067,611
|
$
|
22.22
|
||||||||||
Granted
|
1,469,655
|
33.13
|
2,450,400
|
27.24
|
3,649,902
|
14.62
|
|||||||||||||
Exercised
|
(10,239,341
|
)
|
23.69
|
(8,173,864
|
)
|
18.39
|
(3,818,837
|
)
|
19.15
|
||||||||||
Cancelled
|
(209,813
|
)
|
22.21
|
(814,358
|
)
|
21.37
|
(3,482,296
|
)
|
25.18
|
||||||||||
Outstanding
at December 31
|
11,899,059
|
23.26
|
20,878,558
|
22.76
|
27,416,380
|
21.26
|
|||||||||||||
Exercisable
|
7,951,520
|
22.19
|
13,981,720
|
24.67
|
16,072,654
|
25.34
|
|
|
Outstanding
|
|
Exercisable
|
|
|||||||||||
Exercise
Price Range
|
|
Shares
|
|
Weighted
Average Exercise Price
|
|
Weighted
Average Remaining Contractual Life
|
|
Shares
|
|
Weighted
Average Exercise Price
|
|
|||||
$12.50
- 16.68
|
|
|
4,216,044
|
|
$
|
14.66
|
|
|
6.18
|
|
|
3,024,693
|
|
$
|
14.68
|
|
19.45
- 28.40
|
|
|
3,792,252
|
|
|
24.18
|
|
|
5.92
|
|
|
2,370,169
|
|
|
22.37
|
|
30.50
- 38.82
|
|
|
3,890,763
|
|
|
31.67
|
|
|
5.00
|
|
|
2,556,658
|
|
|
30.90
|
|
2005
|
2004
|
2003
|
|||||||||||||||||
Shares
|
Weighted
Average
Option Price
|
Shares
|
Weighted
Average
Option Price
|
Shares
|
Weighted
Average
Option Price
|
||||||||||||||
Outstanding
at January 1
|
11,068,674
|
$
|
22.58
|
13,543,182
|
$
|
21.01
|
13,300,300
|
$
|
22.32
|
||||||||||
Granted
(1)
|
1,067,900
|
33.15
|
1,903,238
|
26.05
|
2,160,425
|
14.62
|
|||||||||||||
Exercised
|
(4,666,125
|
)
|
23.81
|
(4,146,084
|
)
|
19.00
|
(1,310,156
|
)
|
20.97
|
||||||||||
Cancelled
|
(98,688
|
)
|
28.55
|
(231,662
|
)
|
23.40
|
(607,387
|
)
|
27.05
|
||||||||||
Outstanding
at December 31
|
7,371,761
|
23.15
|
11,068,674
|
22.58
|
13,543,182
|
21.01
|
|||||||||||||
Exercisable
|
4,513,751
|
21.76
|
6,607,089
|
24.94
|
7,668,908
|
25.33
|
|||||||||||||
(1)
Includes
net stock options related to employee transfers to the
Utility.
|
Outstanding
|
Exercisable
|
|||||||||||||||
Exercise
Price Range
|
Shares
|
Weighted
Average Exercise Price
|
Weighted
Average Remaining Contractual Life
|
Shares
|
Weighted
Average Exercise Price
|
|||||||||||
$12.63
- 16.68
|
2,812,301
|
$
|
14.64
|
6.19
|
1,944,534
|
$
|
14.65
|
|||||||||
19.81
- 28.40
|
2,213,273
|
24.72
|
6.35
|
1,157,730
|
22.42
|
|||||||||||
30.50
- 38.82
|
2,346,187
|
31.87
|
5.50
|
1,411,487
|
31.00
|
(in
millions)
|
PG&E
Corporation
|
Utility
|
|||||
Year ended December 31, | |||||||
2005
|
$
|
3
|
$
|
1
|
|||
2004
|
3
|
1
|
|||||
2003
|
7
|
1
|
(in
millions)
|
PG&E
Corporation
|
Utility
|
|||||
Year ended December 31, | |||||||
2005
|
$
|
-
|
$
|
-
|
|||
2004
|
-
|
-
|
|||||
2003
|
63
|
38
|
Sources
|
Uses
|
|||||||||
(in
millions)
|
||||||||||
First
Mortgage Bonds
|
$
|
6,700
|
Payments
to Creditors
|
$
|
8,394
|
|||||
Term
Loans
|
799
|
Disputed
Claims Escrow
|
1,843
|
|||||||
Accounts
Receivable Financing Facility
|
350
|
|||||||||
Total
Debt Financing
|
7,849
|
|||||||||
Cash
Used to Pay Claims
|
2,388
|
|||||||||
Sources
of Funds for Claims
|
10,237
|
Uses
of Funds for Claims
|
10,237
|
|||||||
Reinstated
Pollution Control Bond-Related Obligations
|
814
|
Reinstated
Pollution Control Bond-Related Obligations
|
814
|
|||||||
Reinstated
Preferred Stock
|
421
|
Reinstated
Preferred Stock
|
421
|
|||||||
Cash
on Hand
|
225
|
Preferred
Dividends
|
93
|
|||||||
Environmental
Measures
|
10
|
|||||||||
Transaction
Costs
|
122
|
|||||||||
Total
Sources of Funds
|
$
|
11,697
|
Total
Uses of Funds
|
$
|
11,697
|
Year
Ended December 31,
|
Receivable
(Payable)
Balance
Outstanding at Year ended December 31,
|
|||||||||||||||
|
|
2005
|
|
2004
|
2003
|
2005
|
2004
|
|||||||||
( in millions) | ||||||||||||||||
Utility
revenues from:
|
||||||||||||||||
Administrative
services provided to PG&E Corporation
|
$
|
5
|
$
|
8
|
$
|
8
|
$
|
2
|
$
|
1
|
||||||
Natural
gas transportation capacity services provided to NEGT ET
|
-
|
-
|
8
|
-
|
-
|
|||||||||||
Trade
deposit due from GTNW
|
-
|
-
|
3
|
-
|
-
|
|||||||||||
Utility
employee benefit assets due from PG&E Corporation
|
-
|
-
|
-
|
23
|
-
|
|||||||||||
Utility
expenses from:
|
||||||||||||||||
Administrative
services received from PG&E Corporation
|
$
|
111
|
$
|
81
|
$
|
183
|
$
|
(37
|
)
|
$
|
(20
|
)
|
||||
Interest
accrued on pre-petition liabilities due to PG&E
Corporation
|
-
|
2
|
6
|
-
|
-
|
|||||||||||
Administrative
services received from NEGT
|
-
|
-
|
2
|
-
|
-
|
|||||||||||
Software
purchases from NEGT ET
|
-
|
-
|
1
|
-
|
-
|
|||||||||||
Natural
gas commodity services received from NEGT ET
|
-
|
-
|
10
|
-
|
-
|
|||||||||||
Natural
gas transportation services received from GTNW
|
-
|
43
|
58
|
-
|
-
|
|||||||||||
Trade
deposit due to NEGT ET
|
-
|
-
|
(7
|
)
|
-
|
-
|
(in
millions)
|
2005
|
2004
|
2003
|
|||||||
Qualifying
facility energy payments
|
$
|
954
|
$
|
1,002
|
$
|
994
|
||||
Qualifying
facility capacity payments
|
486
|
487
|
499
|
|||||||
Irrigation
district and water agency payments
|
54
|
61
|
62
|
|||||||
Other
power purchase agreement payments
|
774
|
834
|
513
|
Qualifying
Facility
|
Irrigation
District &
Water
Agency
|
Other
|
||||||||||||||||||||
Energy
|
Capacity
|
Operations
& Maintenance
|
Debt
Service
|
Energy
|
Capacity
|
Total
|
||||||||||||||||
(in
millions)
|
||||||||||||||||||||||
2006
|
$
|
1,537
|
$
|
504
|
$
|
53
|
$
|
26
|
$
|
55
|
$
|
63
|
$
|
2,238
|
||||||||
2007
|
1,892
|
483
|
51
|
26
|
54
|
65
|
2,571
|
|||||||||||||||
2008
|
1,701
|
473
|
34
|
26
|
48
|
33
|
2,315
|
|||||||||||||||
2009
|
1,396
|
433
|
32
|
24
|
55
|
5
|
1,945
|
|||||||||||||||
2010
|
1,145
|
397
|
33
|
22
|
42
|
1
|
1,640
|
|||||||||||||||
Thereafter
|
7,666
|
3,067
|
151
|
95
|
587
|
3
|
11569
|
|||||||||||||||
Total
|
$
|
15,337
|
$
|
5,357
|
$
|
354
|
$
|
219
|
$
|
841
|
$
|
170
|
$
|
22,278
|
(in millions) | ||||
2006
|
$
|
1,447
|
||
2007
|
141
|
|||
2008
|
13
|
|||
2009
|
9
|
|||
2010
|
4
|
|||
Thereafter
|
-
|
|||
Total
|
$
|
1,614
|
(in millions) | ||||
2006
|
$
|
104
|
||
2007
|
60
|
|||
2008
|
53
|
|||
2009
|
42
|
|||
2010
|
23
|
|||
Thereafter
|
13
|
|||
Total
|
$
|
295
|
(in millions) | ||||
2006
|
$
|
146
|
||
2007
|
42
|
|||
2008
|
14
|
|||
2009
|
6
|
|||
2010
|
6
|
|||
Thereafter
|
12
|
|||
Total
|
$
|
226
|
·
|
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.
|
Quarter
ended
|
|||||||||||||
December
31
|
September
30
|
June
30
|
March
31
|
||||||||||
(in
millions, except per share amounts)
|
|||||||||||||
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
|
|||||||||
2004
(1)
|
|||||||||||||
PG&E
CORPORATION
|
|||||||||||||
Operating
revenues
|
$
|
2,986
|
$
|
2,623
|
$
|
2,749
|
$
|
2,722
|
|||||
Operating
income
(2)(3)
|
584
|
509
|
672
|
5,353
|
|||||||||
Income
from continuing operations
|
187
|
228
|
372
|
3,033
|
|||||||||
Net
income
(4)
|
871
|
228
|
372
|
3,033
|
|||||||||
Earnings
per common share from continuing operations, basic
|
0.45
|
0.55
|
0.89
|
7.36
|
|||||||||
Earnings
per common share from continuing operations, diluted
|
0.44
|
0.53
|
0.88
|
7.15
|
|||||||||
Net
income per common share, basic
|
2.07
|
0.55
|
0.89
|
7.36
|
|||||||||
Net
income per common share, diluted
|
2.04
|
0.53
|
0.88
|
7.15
|
|||||||||
Common
stock price per share:
|
|||||||||||||
High
|
34.46
|
30.40
|
30.32
|
29.35
|
|||||||||
Low
|
30.32
|
27.50
|
25.90
|
26.47
|
|||||||||
UTILITY
|
|||||||||||||
Operating
revenues
|
$
|
2,986
|
$
|
2,623
|
$
|
2,749
|
$
|
2,722
|
|||||
Operating
income
(2)(3)
|
584
|
516
|
682
|
5,362
|
|||||||||
Net
income
|
248
|
248
|
412
|
3,074
|
|||||||||
Income
available for common stock
|
243
|
244
|
408
|
3,066
|
|||||||||
(1)
The
operating results of NEGT through July 7, 2003 have been excluded
from
continuing operations and reported as discontinued operations for
all
periods. Effective July 8, 2003, NEGT and its subsidiaries are no
longer
consolidated by PG&E Corporation in its Consolidated Financial
Statements. See Note 7 of the Notes to the Consolidated Financial
Statements for further discussion.
|
|||||||||||||
(2)
Operating
income for first quarter 2004, as part of the implementation of its
plan
of reorganization, includes the Utility's recognition of a $2.2 billion,
after-tax ($3.7 billion, pre-tax) Settlement Regulatory Asset and
$0.7
billion, after-tax ($1.2 billion, pre-tax), for the Utility's retained
generation regulatory assets. See Note 15 of the Notes to the Consolidated
Financial Statements for further discussion.
|
|||||||||||||
(3)
Operating
income for the second quarter 2004, includes the net impact of the
2003
General Rate Case decision of approximately $432 million, pre-tax.
As a
result the Utility recorded various regulatory assets and liabilities
associated with revenue requirement increases, recovery of retained
generation assets, and unfunded taxes, depreciation, and
decommissioning.
|
|||||||||||||
(4)
Net
income for the fourth quarter 2004, includes a gain on disposal of
NEGT of
approximately $684 million, net of tax. On October 29, 2004, the
effective
date of NEGT's plan of reorganization, PG&E Corporation's equity
ownership in NEGT was cancelled. See Note 7 of the Notes to the
Consolidated Financial Statements for further
discussion.
|
Parent
of Significant Subsidiary
|
Name
of Significant Subsidiary
|
Jurisdiction
of Formation of Subsidiary
|
Names
under which Significant Subsidiary does
business
|
|||
PG&E
Corporation
|
Pacific
Gas and Electric Company
|
CA
|
Pacific
Gas and Electric Company
PG&E
|
|||
Pacific
Gas and Electric Company
|
PG&E
Energy Recovery Funding LLC
|
DE
|
PG&E
Energy Recovery Funding LLC
|
/s/
DAVID R. ANDREWS
|
|
/s/
MARYELLEN C. HERRINGER
|
David
R. Andrews
|
|
Maryellen
C. Herringer
/s/
MARY S. METZ
|
Leslie
S. Biller
/s/
DAVID A. COULTER
|
|
Mary
S. Metz
/s/
BARBARA L. RAMBO
|
David
A. Coulter
/s/
C. LEE COX
|
|
Barbara
L. Rambo
/s/
BARRY LAWSON WILLIAMS
|
C.
Lee Cox
/s/
PETER A. DARBEE
|
|
Barry
Lawson Williams
|
Peter
A. Darbee
|
|
|
|
|
|
/s/
DAVID R. ANDREWS
|
/s/
MARYELLEN C. HERRINGER
|
|
David
R. Andrews
|
Maryellen
C. Herringer
/s/
THOMAS B. KING
|
|
Leslie
S. Biller
/s/
DAVID A. COULTER
|
Thomas
B. King
/s/
MARY S. METZ
|
|
David
A. Coulter
/s/
C. LEE COX
|
Mary
S. Metz
/s/
BARBARA L. RAMBO
|
|
C.
Lee Cox
/s/
PETER A. DARBEE
|
Barbara
L. Rambo
/s/
BARRY LAWSON WILLIAMS
|
|
Peter
A. Darbee
|
Barry
Lawson Williams
|
|
|
1. |
I
have reviewed this Annual Report on Form 10-K for the year ended
December
31, 2005 of PG&E Corporation;
|
2. |
Based
on my knowledge, this report does not contain any untrue statement
of a
material fact or omit to state a material fact necessary to make
the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report;
|
3. |
Based
on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects
the
financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this report;
|
4. |
The
registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal
control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)
)
for
the registrant and have:
|
a. |
Designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to
ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is
being
prepared;
|
b. |
Designed
such internal control over financial reporting, or caused such internal
control over financial reporting to be designed under our supervision,
to
provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting
principles;
|
c. |
Evaluated
the effectiveness of the registrant's disclosure controls and procedures
and presented in this report our conclusions about the effectiveness
of
the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation;
and
|
d. |
Disclosed
in this report any change in the registrant’s internal control over
financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth quarter in the case of an annual
report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial
reporting; and
|
5. |
The
registrant's other certifying officer and I have disclosed, based
on our
most recent evaluation of internal control over financial reporting,
to
the registrant's auditors and the audit committee of registrant's
board of
directors (or persons performing the equivalent
functions):
|
a. |
All
significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant's ability to
record,
process, summarize and report financial information;
and
|
b. |
Any
fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
control
over financial reporting.
|
1. |
I
have reviewed this Annual Report on Form 10-K for the year ended
December
31, 2005 of PG&E Corporation;
|
2. |
Based
on my knowledge, this report does not contain any untrue statement
of a
material fact or omit to state a material fact necessary to make
the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report;
|
3. |
Based
on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects
the
financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this report;
|
4. |
The
registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e))
and
internal control over financial reporting (as defined in Exchange
Act
Rules 13a-15(f) and 15d-15(f))
for
the registrant and have:
|
a. |
Designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to
ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is
being
prepared;
|
b. |
Designed
such internal control over financial reporting, or caused such internal
control over financial reporting to be designed under our supervision,
to
provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting
principles;
|
c. |
Evaluated
the effectiveness of the registrant's disclosure controls and procedures
and presented in this report our conclusions about the effectiveness
of
the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation;
and
|
d. |
Disclosed
in this report any change in the registrant’s internal control over
financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth quarter in the case of an annual
report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial
reporting; and
|
5. |
The
registrant's other certifying officer and I have disclosed, based
on our
most recent evaluation of internal control over financial reporting,
to
the registrant's auditors and the audit committee of registrant's
board of
directors (or persons performing the equivalent
functions):
|
a. |
All
significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant's ability to
record,
process, summarize and report financial information;
and
|
b. |
Any
fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
control
over financial reporting.
|
1. |
I
have reviewed this Annual Report on Form 10-K for the year ended
December
31, 2005 of Pacific Gas and Electric
Company;
|
2. |
Based
on my knowledge, this report does not contain any untrue statement
of a
material fact or omit to state a material fact necessary to make
the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report;
|
3. |
Based
on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects
the
financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this report;
|
4. |
The
registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal
control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)
)
for
the registrant and have:
|
a. |
Designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to
ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is
being
prepared;
|
b. |
Designed
such internal control over financial reporting, or caused such internal
control over financial reporting to be designed under our supervision,
to
provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting
principles;
|
c. |
Evaluated
the effectiveness of the registrant's disclosure controls and procedures
and presented in this report our conclusions about the effectiveness
of
the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation;
and
|
d. |
Disclosed
in this report any change in the registrant’s internal control over
financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth quarter in the case of an annual
report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial
reporting; and
|
5. |
The
registrant's other certifying officer and I have disclosed, based
on our
most recent evaluation of internal control over financial reporting,
to
the registrant's auditors and the audit committee of registrant's
board of
directors (or persons performing the equivalent
functions):
|
a. |
All
significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant's ability to
record,
process, summarize and report financial information;
and
|
b. |
Any
fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
control
over financial reporting.
|
1. |
I
have reviewed this Annual Report on Form 10-K for the year ended
December
31, 2005 of Pacific Gas and Electric
Company;
|
2. |
Based
on my knowledge, this report does not contain any untrue statement
of a
material fact or omit to state a material fact necessary to make
the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report;
|
3. |
Based
on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects
the
financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this report;
|
4. |
The
registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e))
and
internal control over financial reporting (as defined in Exchange
Act
Rules 13a-15(f) and 15d-15(f))
for
the registrant and have:
|
a. |
Designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to
ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is
being
prepared;
|
b. |
Designed
such internal control over financial reporting, or caused such internal
control over financial reporting to be designed under our supervision,
to
provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting
principles;
|
c. |
Evaluated
the effectiveness of the registrant's disclosure controls and procedures
and presented in this report our conclusions about the effectiveness
of
the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation;
and
|
d. |
Disclosed
in this report any change in the registrant’s internal control over
financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth quarter in the case of an annual
report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial
reporting; and
|
5. |
The
registrant's other certifying officer and I have disclosed, based
on our
most recent evaluation of internal control over financial reporting,
to
the registrant's auditors and the audit committee of registrant's
board of
directors (or persons performing the equivalent
functions):
|
a. |
All
significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant's ability to
record,
process, summarize and report financial information;
and
|
b. |
Any
fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
control
over financial reporting.
|
(1)
|
such
Annual Report on Form 10-K of PG&E Corporation for the year ended
December 31, 2005, fully complies with the requirements of section
13(a)
or 15(d) of the Securities Exchange Act of 1934; and
|
|
|
(2)
|
the
information contained in such Annual Report on Form 10-K of PG&E
Corporation for the year ended December 31, 2005, fairly presents,
in all
material respects, the financial condition and results of operations
of
PG&E Corporation.
|
/s/
PETER A. DARBEE
|
||
PETER
A. DARBEE
|
||
Chairman,
Chief Executive Officer and President
|
||
(1)
|
such
Annual Report on Form 10-K of PG&E Corporation for the year ended
December 31, 2005, fully complies with the requirements of section
13(a)
or 15(d) of the Securities Exchange Act of 1934; and
|
|
|
(2)
|
the
information contained in such Annual Report on Form 10-K of PG&E
Corporation for the year ended December 31, 2005, fairly presents,
in all
material respects, the financial condition and results of operations
of
PG&E Corporation.
|
|
/s/
CHRISTOPHER P. JOHNS
|
||
CHRISTOPHER
P. JOHNS
|
||
Senior
Vice President,
|
||
Chief
Financial Officer and Treasurer
|
||
|
(1)
|
such
Annual Report on Form 10-K of Pacific Gas and Electric Company
for the
year ended December 31, 2005, fully complies with the requirements
of
section 13(a) or 15(d) of the Securities Exchange Act of 1934;
and
|
|
|
(2)
|
the
information contained in such Annual Report on Form 10-K of Pacific
Gas
and Electric Company for the year ended December 31, 2005, fairly
presents, in all material respects, the financial condition and
results of
operations of Pacific Gas and Electric
Company.
|
/s/
THOMAS B.
KING
|
|
THOMAS
B. KING
|
|
President
and Chief Executive Officer
|
(1)
|
such
Annual Report on Form 10-K of Pacific Gas and Electric Company
for the
year ended December 31, 2005, fully complies with the requirements
of
section 13(a) or 15(d) of the Securities Exchange Act of 1934;
and
|
|
|
(2)
|
the
information contained in such Annual Report on Form 10-K of Pacific
Gas
and Electric Company for the year ended December 31, 2005, fairly
presents, in all material respects, the financial condition and
results of
operations of Pacific Gas and Electric
Company.
|
/s/ CHRISTOPHER P. JOHNS | |
CHRISTOPHER
P. JOHNS
|
|
Senior
Vice President, Chief Financial Officer
|
|
and
Treasurer
|