FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
----------------------------------
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________to ___________
Exact Name of
Commission Registrant State or other IRS Employer
File as specified Jurisdiction of Identification
Number in its charter Incorporation Number
- ----------- -------------- --------------- --------------
1-12609 PG&E Corporation California 94-3234914
1-2348 Pacific Gas and California 94-0742640
Electric Company
Pacific Gas and Electric Company PG&E Corporation
77 Beale Street One Market, Spear Tower
P.O. Box 770000 Suite 2400
San Francisco, California 94177 San Francisco,
California 94105
- -----------------------------------------------------------------------
(Address of principal executive offices) (Zip Code)
Pacific Gas and Electric Company PG&E Corporation
(415) 973-7000 (415) 267-7000
- -----------------------------------------------------------------------
Registrant's telephone number, including area code
Indicate by check mark whether the registrants (1) have filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding twelve
months (or for such shorter period that the registrant was required
to file such reports), and (2) have been subject to such filing
requirements for the past 90 days.
Yes X No _________
Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the latest practicable date.
Common Stock Outstanding July 28, 1999:
PG&E Corporation 383,949,779 shares
Pacific Gas and Electric Company Wholly owned by PG&E Corporation
<PAGE>
PG&E CORPORATION
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 1999
TABLE OF CONTENTS
PAGE
PART I. FINANCIAL INFORMATION
ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS
PG&E CORPORATION
STATEMENT OF CONSOLIDATED INCOME........................1
CONSOLIDATED BALANCE SHEET..............................2
STATEMENT OF CONSOLIDATED CASH FLOWS ...................4
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED INCOME........................5
CONDSOLIDATED BALANCE SHEET.............................6
STATEMENT OF CONSOLIDATED CASH FLOWS....................8
NOTE 1: GENERAL...........................................9
NOTE 2: CALIFORNIA ELECTRIC INDUSTRY RESTRUCTURING........9
NOTE 3: PRICE RISK MANAGEMENT AND FINANCIAL INSTRUMENTS..15
NOTE 4: ACQUISITIONS AND SALES...........................16
NOTE 5: UTILITY OBLIGATED MANDATORILY REDEEMABLE
PREFERRED SECURITIES OF TRUST HOLDING
SOLELY UTILITY SUBORDINATED DEBENTURES...........17
NOTE 6: COMMITMENTS AND CONTINGENCIES....................17
NOTE 7: SEGMENT INFORMATION..............................20
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS. ....................22
COMPETITIVE AND REGULATORY ENVIRONMENT....................23
The Competitive Environment in the Evolving
Energy Industry........................................23
California Industry Restructuring......................24
New England Electricity Market.........................30
Regulatory Matters.....................................31
RESULTS OF OPERATIONS.....................................34
LIQUIDITY AND FINANCIAL RESOURCES.........................40
ENVIRONMENTAL MATTERS.....................................42
YEAR 2000.................................................42
PRICE RISK MANAGEMENT ACTIVITIES..........................44
LEGAL MATTERS.............................................44
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK.........................................45
PART II. OTHER INFORMATION
ITEM 5. OTHER INFORMATION.........................................46
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K..........................46
SIGNATURE..........................................................48
<PAGE>
PART I. FINANCIAL INFORMATION
ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
PG&E CORPORATION
STATEMENT OF CONSOLIDATED INCOME
(in millions, except per share amounts)
<CAPTION>
Three months ended June 30, Six months ended June 30,
1999 1998 1999 1998
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Operating Revenues
Utility $ 2,233 $ 2,117 $ 4,318 $ 4,143
Energy commodities and services 2,587 2,670 5,759 4,997
-------- -------- -------- --------
Total operating revenues 4,820 4,787 10,077 9,140
-------- -------- -------- --------
Operating Expenses
Cost of energy for utility 664 576 1,319 1,258
Cost of energy commodities and services 2,365 2,472 5,286 4,624
Operating and maintenance, net 774 770 1,572 1,571
Depreciation and decommissioning 563 412 1,004 666
-------- -------- -------- --------
Total operating expenses 4,366 4,230 9,181 8,119
-------- -------- -------- --------
Operating Income 454 557 896 1,021
Interest expense, net 192 196 393 393
Other income, net 39 (8) 60 7
-------- -------- -------- --------
Income Before Income Taxes 301 353 563 635
Income taxes 121 179 227 322
-------- -------- -------- --------
Net Income $ 180 $ 174 $ 336 $ 313
======== ======== ======== ========
Weighted Average Common Shares
Outstanding 367 382 370 382
Earnings Per Common Share, Basic $ .49 $ .46 $ .91 $ .82
Earnings Per Common Share, Diluted $ .46 $ .46 $ .83 $ .82
Dividends Declared Per Common Share $ .30 $ .30 $ .60 $ .60
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<PAGE>
<TABLE>
PG&E CORPORATION
CONSOLIDATED BALANCE SHEET (in millions)
<CAPTION>
Balance at June 30, December 31,
1999 1998
------------- ------------
<S> <C> <C>
ASSETS
Current Assets
Cash and cash equivalents $ 284 $ 286
Short-term investments 37 55
Accounts receivable
Customers, net 1,569 1,856
Energy marketing 571 507
Price Risk Management 716 1,416
Inventories and prepayments 770 835
-------- --------
Total current assets 3,947 4,955
Property, Plant, and Equipment
Utility 22,658 23,996
Wholesale and retail unregulated business operations
Electric generation 1,900 1,967
Gas transmission 3,387 3,347
Construction work in progress 398 407
Other 171 127
-------- --------
Total property, plant, and equipment (at original cost) 28,514 29,844
Accumulated depreciation and decommissioning (11,038) (12,026)
-------- --------
Net property, plant, and equipment 17,476 17,818
Other Noncurrent Assets
Regulatory assets 5,520 6,347
Nuclear decommissioning funds 1,238 1,172
Other 3,245 2,942
-------- --------
Total noncurrent assets 10,003 10,461
-------- --------
TOTAL ASSETS $ 31,426 $ 33,234
======== ========
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<PAGE>
<TABLE>
PG&E CORPORATION
CONSOLIDATED BALANCE SHEET (in millions)
<CAPTION>
Balance at June 30, December 31,
1999 1998
------------ ------------
<S> <C> <C>
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings $ 877 $ 1,644
Current portion of long-term debt 549 338
Current portion of rate reduction bonds 282 290
Accounts payable
Trade creditors 775 1,001
Other 543 443
Regulatory balancing accounts 685 79
Energy marketing 475 381
Accrued taxes 738 103
Price risk management 708 1,412
Other 873 1,064
-------- --------
Total current liabilities 6,505 6,755
Noncurrent Liabilities
Long-term debt 6,895 7,422
Rate reduction bonds 2,181 2,321
Deferred income taxes 3,263 3,861
Deferred tax credits 251 283
Other 3,836 3,746
-------- --------
Total noncurrent liabilities 16,426 17,633
Preferred Stock of Subsidiaries 480 480
Utility Obligated Mandatorily Redeemable Preferred Securities of
Trust Holding Solely Utility Subordinated Debentures 300 300
Common Stockholders' Equity
Common stock 5,391 5,862
Reinvested earnings 2,324 2,204
-------- --------
Total common stockholders' equity 7,715 8,066
Commitments and Contingencies (Notes 2 and 6) - -
-------- --------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 31,426 $ 33,234
======== ========
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<PAGE>
<TABLE>
PG&E CORPORATION
STATEMENT OF CONSOLIDATED CASH FLOWS (in millions)
<CAPTION>
For the six months ended June 30, 1999 1998
---------- ----------
<S> <C> <C>
Cash Flows From Operating Activities
Net income $ 336 $ 313
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, amortization and decommissioning 1,004 666
Deferred income taxes and tax credits-net (630) (31)
Other deferred charges and noncurrent liabilities (401) (74)
Loss on sale of assets - 21
Net effect of changes in operating assets
and liabilities:
Accounts receivable - trade 287 100
Regulatory balancing accounts payable 606 365
Inventories and prepayments 65 42
Price risk management assets and liabilities, net (4) (24)
Accounts payable - trade (226) (187)
Accrued taxes 635 165
Other working capital (56) (135)
Other-net 21 29
--------- ---------
Net cash provided by operating activities 1,637 1,250
--------- ---------
Cash Flows From Investing Activities
Capital expenditures (740) (925)
Proceeds from the sale of assets 1,014 -
Other-net - 14
--------- ---------
Net cash used by investing activities 274 (911)
--------- ---------
Cash Flows From Financing Activities
Net borrowings (repayments) under credit facilities (767) 473
Long-term debt issued - 199
Long-term debt matured, redeemed, or repurchased (491) (644)
Preferred stock redeemed or repurchased - (63)
Common stock issued 32 33
Common stock repurchased (503) (1,123)
Dividends paid (225) (240)
Other-net 23 (21)
--------- ---------
Net cash used by financing activities (1,931) (1,386)
--------- ---------
Net Change in Cash and Cash Equivalents (20) (1,047)
Cash and Cash Equivalents at January 1 341 1,397
--------- ---------
Cash and Cash Equivalents at June 30 $ 321 $ 350
========= =========
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized) $ 385 $ 394
Income taxes 87 209
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<PAGE>
<TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED INCOME (in millions)
<CAPTION>
Three months ended June 30, Six months ended June 30,
1999 1998 1999 1998
-------- -------- -------- -------
<S> <C> <C> <C> <C>
Electric utility $ 1,828 $ 1,708 $ 3,361 $ 3,270
Gas utility 405 409 957 873
-------- -------- -------- --------
Total operating revenues 2,233 2,117 4,318 4,143
-------- -------- -------- --------
Operating Expenses
Cost of electric energy 526 453 935 927
Cost of gas 138 123 384 331
Operating and maintenance, net 608 672 1,234 1,370
Depreciation, amortization, and decommissioning 509 375 891 597
-------- -------- -------- --------
Total operating expenses 1,781 1,623 3,444 3,225
-------- -------- -------- --------
Operating Income 452 494 874 918
Interest expense, net 148 159 302 321
Other income, net 11 27 22 64
-------- -------- -------- -------
Income Before Income Taxes 315 362 594 661
Income taxes 137 169 263 312
-------- -------- -------- -------
Net Income 178 193 331 349
Preferred dividend requirement 6 7 12 15
-------- -------- -------- -------
Income Available for Common Stock $ 172 $ 186 $ 319 $ 334
======== ======== ======== =======
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<PAGE>
<TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET (in millions)
<CAPTION>
Balance at
June 30, December 31,
1999 1998
------------ -----------
<S> <C> <C>
ASSETS
Current Assets
Cash and cash equivalents $ 85 $ 73
Short-term investments 18 17
Accounts receivable
Customers, net 1,144 1,383
Related parties 29 14
Inventories
Fuel oil and nuclear fuel 159 187
Gas stored underground 156 130
Materials and supplies 165 159
Prepayments 34 50
--------- ---------
Total current assets 1,790 2,013
Property, Plant, and Equipment
Electric 15,493 16,924
Gas 7,165 7,072
Construction work in progress 211 273
--------- ---------
Total property, plant, and equipment (at original cost) 22,869 24,269
Accumulated depreciation and decommissioning (10,315) (11,397)
--------- ---------
Net property, plant, and equipment 12,554 12,872
Other Noncurrent Assets
Regulatory assets 5,465 6,288
Nuclear decommissioning funds 1,238 1,172
Other 673 605
-------- --------
Total noncurrent assets 7,376 8,065
-------- --------
TOTAL ASSETS $ 21,720 $ 22,950
======== ========
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<PAGE>
<TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET (in millions)
<CAPTION>
Balance at
June 30, December 31,
1999 1998
------------ -----------
<S> <C> <C>
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings $ - $ 668
Current portion of long-term debt 453 260
Current portion of rate reduction bonds 282 290
Accounts payable
Trade creditors 526 718
Related parties 65 60
Regulatory balancing accounts 685 79
Other 338 374
Accrued taxes 585 2
Other 484 561
-------- -------
Total current liabilities 3,418 3,012
Noncurrent Liabilities
Long-term debt 5,051 5,444
Rate reduction bonds 2,181 2,321
Deferred income taxes 2,424 3,060
Deferred tax credits 250 283
Other 2,212 2,045
-------- -------
Total noncurrent liabilities 12,118 13,153
Preferred Stock With Mandatory Redemption Provisions 137 137
Company Obligated Mandatorily Redeemable Preferred Securities of
Trust Holding Solely Utility Subordinated Debentures 300 300
Stockholders' Equity
Preferred stock without mandatory redemption provisions
Nonredeemable 145 145
Redeemable 142 142
Common stock 1,607 1,707
Additional paid in capital 1,971 2,094
Reinvested earnings 1,882 2,260
-------- --------
Total stockholders' equity 5,747 6,348
Commitments and Contingencies (Notes 2 and 6) - -
-------- --------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 21,720 $ 22,950
======== ========
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<PAGE>
<TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED CASH FLOWS (in millions)
<CAPTION>
For the six months ended June 30, 1999 1998
----------- -----------
<S> <C> <C>
Cash Flows From Operating Activities
Net income $ 331 $ 349
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, amortization, and decommissioning 891 597
Deferred income taxes and tax credits-net (669) (79)
Other deferred charges and noncurrent liabilities (189) 327
Net effect of changes in operating assets
and liabilities:
Accounts receivable 239 43
Regulatory balancing accounts payable 606 (138)
Inventories and prepayments 12 19
Accounts payable - trade (192) (45)
Accrued taxes 583 154
Other working capital (71) (58)
Other-net 27 13
--------- ---------
Net cash provided by operating activities 1,568 1,182
--------- ---------
Cash Flows From Investing Activities
Capital expenditures (600) (671)
Proceeds from sale of assets 1,014 -
Other-net - 83
--------- ---------
Net cash used by investing activities 414 (588)
--------- ---------
Cash Flows From Financing Activities
Net repayments under credit facilities (668) -
Long-term debt matured, redeemed, or repurchased (369) (618)
Preferred stock redeemed or repurchased - (63)
Common stock repurchased (725) (800)
Dividends paid (208) (230)
Other-net 1 (8)
--------- ---------
Net cash used by financing activities (1,969) (1,719)
--------- ---------
Net Change in Cash and Cash Equivalents 13 (1,125)
Cash and Cash Equivalents at January 1 90 1,223
--------- ---------
Cash and Cash Equivalents at June 30 $ 103 $ 98
========= =========
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized) $ 282 $ 315
Income taxes 226 260
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<PAGE>
PG&E CORPORATION AND PACIFIC GAS AND ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1: GENERAL
Basis of Presentation:
- ----------------------
This Quarterly Report on Form 10-Q is a combined report of PG&E Corporation
and Pacific Gas and Electric Company (the Utility), a regulated subsidiary of
PG&E Corporation. The Notes to Consolidated Financial Statements apply to
both PG&E Corporation and the Utility. PG&E Corporation's consolidated
financial statements include the accounts of PG&E Corporation and its wholly
owned and controlled subsidiaries, including the Utility (collectively, the
Corporation). The Utility's consolidated financial statements include its
accounts as well as those of its wholly owned and controlled subsidiaries.
The Utility's financial position and results of operations are the
principal factors affecting the Corporation's consolidated financial position
and results of operations. This quarterly report should be read in conjunction
with the Corporation's and the Utility's Consolidated Financial Statements and
Notes to Consolidated Financial Statements incorporated by reference in their
combined 1998 Annual Report on Form 10-K.
PG&E Corporation and the Utility believe that the accompanying statements
reflect all adjustments that are necessary to present a fair statement of the
consolidated financial position and results of operations for the interim
periods. All material adjustments are of a normal recurring nature unless
otherwise disclosed in this Form 10-Q. All significant intercompany
transactions have been eliminated from the consolidated financial statements.
Certain amounts in the prior year's consolidated financial statements have
been reclassified to conform to the 1999 presentation. Results of operations
for interim periods are not necessarily indicative of results to be expected
for a full year.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions. These estimates and assumptions affect the reported amounts of
revenues, expenses, assets, and liabilities and the disclosure of
contingencies. Actual results could differ from these estimates.
NOTE 2: CALIFORNIA ELECTRIC INDUSTRY RESTRUCTURING
In 1998, California became one of the first states in the country to
implement electric industry restructuring legislation and establish a
competitive market for electric generation. In a transition to a competitive
market, the restructuring legislation recognized that market-based revenues
may not be sufficient to recover (that is, collect from customers) all of the
Utility's generation costs. The restructuring legislation provides the
California investor-owned utilities the opportunity to recover such
uneconomic generation costs (called transition costs) until the earlier of
December 31, 2001, or when the utilities have recovered their authorized
transition costs as determined by the California Public Utilities Commission
(CPUC). The period during which transition costs may be recovered is called
the transition period. The legislation permits certain transition costs to
be recovered after the transition period.
The restructuring legislation has four principal elements: (1) the
establishment of a competitive market framework, (2) an electric rate freeze
and rate reduction, (3) the recovery of transition costs, and (4) divestiture
of utility-owned generation facilities. Each element is discussed below.
<PAGE>
Competitive Market Framework:
- -----------------------------
To create a competitive generation market, a Power Exchange (PX) and an
Independent System Operator (ISO) began operating on March 31, 1998. During
the transition period, the Utility is required to bid or schedule into the PX
and ISO markets all of the electricity generated by its power plants and
electricity acquired under contractual agreements with unregulated
generators. Also during the transition period, the Utility is required to
buy from the PX all electricity needed to provide service to retail customers
that continue to choose the Utility as their electricity supplier. The ISO
schedules delivery of electricity for all market participants. The Utility
continues to own and maintain a portion of the transmission system, but the
ISO controls the operation of the system.
For the three- and six-month periods ended June 30, 1999 and 1998, the
cost of electric energy for the Utility, reflected on the Statement of
Consolidated Income, is comprised of the cost of PX purchases, ancillary
services (standby power and miscellaneous services) purchased from the ISO,
cost of transmission, and the cost of Utility generation, net of sales to the
PX as follows:
<TABLE>
<CAPTION>
Three months ended June 30, Six months ended June 30,
1999 1998 1999 1998
-------- -------- -------- --------
<S> <C> <C> <C> <C>
(in millions)
Cost of electric generation $ 398 $ 490 $ 768 $ 964
Cost of purchases from the PX 174 110 326 110
Cost of ancillary services 111 86 221 86
Proceeds from sales to the PX (157) (233) (380) (233)
-------- -------- -------- --------
Cost of electric energy $ 526 $ 453 $ 935 $ 927
-------- -------- -------- --------
</TABLE>
The Utility's cost of energy is recovered from retail customers under the
terms of the restructuring plan.
Rate Freeze and Rate Reduction:
- -------------------------------
Legislation required an electric rate freeze and an electric rate reduction
to extend throughout the transition period. The Utility has held rates for
its larger customers at 1996 levels, and it will hold their rates at that
level until the end of the transition period. On January 1, 1998, the
Utility reduced electric rates for its residential and small commercial
customers by 10 percent from 1996 levels, and it will hold their rates at
that level until the end of the transition period. Collectively, these
actions are called a rate freeze.
To pay for the 10 percent rate reduction, the Utility refinanced $2.9
billion of its transition costs with the proceeds from rate reduction bonds.
The bonds allow for the rate reduction by lowering the carrying cost on a
portion of the transition costs and by deferring recovery of a portion of
these transition costs until after the transition period. During the rate
freeze, the rate reduction bond debt service will not increase the Utility
customers' electric rates. If the transition period ends before December 31,
2001, the Utility will be obligated to return a portion of the bond proceeds
to customers. The timing and exact amount of such portion, if any, has not
yet been determined.
The frozen rates include a component for transition cost recovery.
Transition costs are being recovered from all Utility distribution customers
through a nonbypassable charge regardless of the customer's choice of
<PAGE>
electricity supplier. As the customer charge for transition costs is
nonbypassable, the Utility believes that the availability of choice to its
customers will not have a material impact on its ability to recover
transition costs.
Revenues from frozen electric rates provide for the recovery of authorized
Utility costs, including transmission and distribution service, public
purpose programs, nuclear decommissioning, and rate reduction bond debt
service. To the extent the revenues from frozen rates exceed authorized
Utility costs, the remaining revenues constitute the competitive transition
charge (CTC), which recovers the transition costs. These CTC revenues are
subject to seasonal fluctuations in the Utility's sales volumes and certain
other factors.
Transition Cost Recovery:
- -------------------------
Market-based revenues through sales to the PX may not be sufficient to
recover all of the Utility's generation costs. Under the California
restructuring legislation, the Utility has the opportunity to recover its
transition costs until the earlier of December 31, 2001, or when the Utility
has recovered its authorized transition costs as determined by the CPUC,
although certain transition costs can be recovered after the transition
period. At the conclusion of the transition period, the Utility will be at
risk to recover any of its remaining generation costs through market-based
revenues.
Transition costs consist of: (1) above-market sunk costs (costs associated
with Utility-owned generation assets that are fixed and unavoidable and
currently included in the Utility customers' electric rates) and future
costs, such as costs related to removal of Utility-owned generation
facilities, (2) costs associated with the Utility's long-term contracts to
purchase power at above-market prices from qualifying facilities and other
power suppliers, and (3) generation-related regulatory assets and
obligations. (In general, regulatory assets are expenses deferred in the
current or prior periods, to be included in rates in subsequent periods.)
Above-market sunk costs result when the book value of a facility is in
excess of its market value. Conversely, below-market sunk costs result when
the market value of a facility is in excess of its book value. The total
amount of generation facility costs to be included as transition costs will
be based on the aggregate of above-market and below-market values. The
above-market portion of these costs is eligible for recovery as a transition
cost. The below-market portion of these costs will reduce other unrecovered
transition costs. These above- and below-market sunk costs are related to
generating facilities that are classified as either non-nuclear or nuclear
sunk costs.
The Utility cannot determine the exact amount of above-market non-nuclear
sunk costs that will be recoverable as transition costs until a market
valuation process (through appraisal, sale, or other valuation method) is
completed for each of its non-nuclear generation facilities. Several of
these valuations occurred in 1997 and 1998, when the Utility agreed to sell
seven of its electric generation plants to third parties. The total market
value of these facilities resulted in sales proceeds that exceeded the book
value and therefore has reduced the amount of transition costs remaining to
be recovered. The remainder of the valuation process is expected to be
completed by December 31, 2001. The Utility's remaining non-nuclear
generation facilities consist primarily of its hydroelectric generation
system. If the market value of the Utility's hydroelectric facilities is
determined based upon any method other than a sale of the facilities to a
third party, a material charge to Utility earnings could result. Any excess
<PAGE>
of market value over book value would be used to reduce other transition
costs. (See Generation Divestiture below.)
Nuclear generation sunk costs were determined separately through a CPUC
proceeding and were subject to a final verification audit that was completed
in August 1998. The audit of the Utility's Diablo Canyon Nuclear Power Plant
(Diablo Canyon) accounts at December 31, 1996, resulted in the issuance of an
unqualified opinion. The audit verified that Diablo Canyon sunk costs at
December 31, 1996, were $3.3 billion of the total $7.1 billion construction
costs. The independent accounting firm also issued an agreed-upon special
procedures report, requested by the CPUC, that questioned $200 million of the
$3.3 billion sunk costs. The CPUC will review any proposed adjustments to
Diablo Canyon's recoverable costs that resulted from the report. At this
time, the Utility cannot predict what actions, if any, the CPUC may take
regarding the audit report.
Costs associated with the Utility's long-term contracts to purchase
electric power at above-market prices are included as transition costs. Over
the remaining life of these contracts the Utility estimates that it will
purchase 322 million megawatt-hours of electric power. To the extent that
the individual contract prices are above the market price, the Utility is
collecting the difference between the contract price and the market price
from customers, as a transition cost, over the term of the contract. The
contracts expire at various dates through 2028. The total amount of the
above-market costs under long-term contracts will be based on several
variables, including the capacity factors of the related generating
facilities and future market prices for electricity. During the six-month
period ended June 30, 1999, the average price paid per kilowatt-hour (kWh)
under the Utility's long-term contracts for electric power was 6.1 cents per
kWh. The average cost of electric energy for energy purchased at market
rates from the PX for the six-month period ended June 30, 1999, was 2.6 cents
per kWh.
Generation-related regulatory assets and obligations (net generation-
related regulatory assets) are included as transition costs. At June 30,
1999, the Utility's generation-related net regulatory assets totaled $4.5
billion.
Most transition costs can be recovered until December 31, 2001. This
recovery period is significantly shorter than the recovery period of the
generation assets prior to restructuring and is referred to as accelerated
recovery. Accordingly, the Utility is amortizing its transition costs,
including most generation-related regulatory assets over the transition
period. During the transition period, the Utility is receiving a reduced
return on common equity for all of its generation assets, including those
generation assets reclassified to regulatory assets. The reduced return on
common equity is 6.77 percent.
Certain transition costs can be recovered through a non-bypassable charge
to distribution customers after December 31, 2001. These costs include: (1)
certain employee-related transition costs, (2) above-market payments under
existing long-term contracts to purchase power, discussed above, (3) up to
$95 million of transition costs after the transition period to the extent
that the recovery of such costs during the transition period was displaced by
the recovery of electric industry restructuring implementation costs, and (4)
transition costs financed by the rate reduction bonds. Transition costs
financed by the issuance of rate reduction bonds are expected to be recovered
over the term of the bonds. In addition, the Utility's nuclear
decommissioning costs are being recovered through a CPUC-authorized charge,
which will extend until sufficient funds exist to decommission the nuclear
facility. During the rate freeze, the charge for these costs will not
<PAGE>
increase the Utility customers' electric rates. Excluding these exceptions,
the Utility will write off any transition costs not recovered during the
transition period.
Revenues provided for the recovery of most non-nuclear transition costs
are based upon the acceleration of such costs within the transition period.
For Diablo Canyon transition costs, revenues provided for transition cost
recovery are based on: (1) an established incremental cost incentive price
(ICIP) per kWh generated by Diablo Canyon to recover certain ongoing costs
and capital additions, and (2) the accelerated recovery of the investment in
Diablo Canyon from a period ending in 2016 to a five-year period ending
December 31, 2001. In a pending proceeding, the CPUC is currently
considering whether the Utility may continue to recover revenues based on the
ICIP through December 31, 2001, or must cease recovery of such revenues if it
has completed recovery of all other utility generation-related transition
costs prior to that date.
The Utility is amortizing its eligible transition costs, including
generation-related regulatory assets, over the transition period in
conjunction with the available CTC revenues. Effective January 1, 1998, the
Utility started collecting these eligible transition costs through the
nonbypassable CTC. For the six months ended June 30, 1999, regulatory assets
related to electric utility restructuring decreased by $813 million, which
reflects the recovery of eligible transition costs.
During the transition period, the CPUC reviews the Utility's compliance
with the accounting methods established in the CPUC's decisions governing
transition cost recovery and the amount of transition costs requested for
recovery. The CPUC is currently reviewing non-nuclear transition costs
amortized during the first six months of 1998.
Generation Divestiture:
- -----------------------
In 1998, the Utility completed the sale of three fossil-fueled generation
plants for $501 million. These three fossil-fueled plants had a combined
book value at the time of the sale of $346 million and had a combined
capacity of 2,645 megawatts (MW).
On April 16, 1999, the Utility sold three other fossil-fueled generation
plants for $801 million. At the time of sale, these three fossil-fueled
plants had a combined book value of $256 million and had a combined capacity
of 3,065 MW.
On May 7, 1999, the Utility sold its complex of geothermal generation
facilities for $213 million. At the time of sale, these facilities had a
combined book value of $244 million and had a combined capacity of 1,224 MW.
The Utility will retain a liability for required environmental remediation
related to all of its fossil-fueled generation and geothermal generation
plants of any pre-closing soil or groundwater contamination at the plants it
has or will sell. The Utility records its estimated liability for the
retained environmental remediation obligation as part of the determination of
the gain or loss on the sale of each plant.
Any gains from the sale of the Utility-owned generation plants will be
used to offset other transition costs. Likewise, any losses from the sale of
Utility-owned generation plants are recoverable as transition costs. PG&E
Corporation does not believe sales of any generation facilities to a third
party will have a material impact on its results of operations.
<PAGE>
In May 1998, the Utility notified the CPUC that it does not plan to retain
its hydroelectric generation assets as part of the Utility. In December
1998, the Utility filed with the CPUC its proposed appraisal process for
valuing its hydroelectric facilities. The Utility withdrew its proposal in
March 1999 when the CPUC clarified that the CPUC proceeding would only apply
to assets to be retained in the Utility. The Utility currently is evaluating
alternative strategies with respect to the valuation and disposition of its
hydroelectric facilities, including a potential transfer of the facilities to
another PG&E Corporation affiliate. Meanwhile, the California legislature is
reviewing legislative proposals that would address hydroelectric facilities
valuation and divestiture issues on an interim or permanent basis. If
legislation setting a valuation were enacted and the legislated valuation was
materially higher than the value ultimately recognized in connection with the
sale or other disposition of the assets, the Utility could suffer a material
loss upon the sale or other disposition of the hydroelectric assets. If such
legislation were enacted, we expect that the Utility would challenge the
legality of legislation adopting such excess or interim valuation. Although
legislation could be passed prior to the close of the legislative session in
September 1999, the Corporation and Utility are unable to predict the nature
or likelihood of enactment of any such legislation.
At June 30, 1999, the book value of the Utility's net investment in
hydroelectric generation assets was approximately $0.8 billion, excluding
approximately $0.5 billion of net investment reclassified as regulatory
assets recoverable as transition costs. The value of the hydroelectric
assets is expected to exceed their book value by a material amount. In
connection with legislative discussions concerning the hydroelectric assets,
some third parties have publicly speculated that the value of the
hydroelectric assets could be in excess of $3 billion. If the market value
of the hydroelectric generation assets is determined by any method other than
a sale of the assets to a third party, a material charge to Utility earnings
could result. Any excess of market value over the $0.8 billion book value
would be used to reduce other transition costs, including the remaining $0.5
billion of regulatory assets related to the hydroelectric generation assets.
The timing and nature of any such charge is dependent upon the valuation
method and procedure adopted, and the method of implementation, which could
occur as soon as the third quarter of 1999.
Financial Impact of Electric Industry Restructuring:
- ----------------------------------------------------
The Utility's ability to continue recovering its transition costs will be
dependent on several factors, including: (1) the continued application of the
regulatory framework established by the CPUC and state legislation, (2) the
amount of transition costs ultimately approved for recovery by the CPUC, (3)
the determined value of the Utility's hydroelectric generation facilities,
(4) future Utility sales levels, (5) future Utility fuel and operating costs,
(6) the extent to which the Utility's authorized revenues to recover
distribution and transmission costs are increased or decreased, and (7) the
market price of electricity. Given the current evaluation of these factors,
PG&E Corporation believes that the Utility will recover its transition costs
under the terms of the approved transition plan. However, a change in one or
more of these factors could affect the probability of recovery of transition
costs and result in a material charge.
<PAGE>
NOTE 3: PRICE RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
The following table is a summary of the contract or notional amounts and
maturities of PG&E Corporation's contracts used for non-hedging activities
related to commodity price risk management as of June 30, 1999. Short and
long positions pertaining to derivative contracts used for hedging activities
as of June 30, 1999, are immaterial.
Maximum
Natural Gas, Electricity, Purchase Sale Term in
and Natural Gas Liquids Contracts (Long) (Short) Years
- ---------------------------------------------------------------------
(billions of MMBtu equivalents (1))
Non-Hedging Activities
Swaps 3.90 3.73 7
Options 1.14 0.96 5
Futures 0.29 0.34 2
Forward Contracts 2.93 2.98 9
(1) One MMBtu is equal to one million British thermal units. PG&E
Corporation's electric power contracts, measured in megawatts, were converted
to MMBtu equivalents using a conversion factor of 10 MMBtu's per 1 megawatt-
hour. PG&E Corporation's natural gas liquids contracts were converted to
MMBtu equivalents using an appropriate conversion factor for each type of
natural gas liquids product.
Volumes shown for swaps represent notional volumes that are used to
calculate amounts due under the agreements and do not represent volumes
exchanged. Moreover, notional amounts are indicative only of the volume of
activity and are not a measure of market risk.
PG&E Corporation's net gains (losses) on swaps, options, futures, and
forward contracts held during the three- and six-month periods ended June 30,
1999 are as follows:
For the three- For the six-
months ended months ended
June 30, 1999 June 30, 1999
- --------------------------------------------------------------------------
(in millions)
Swaps $(131) $ 2
Options (29) (35)
Futures 22 (20)
Forward contracts 131 95
------ -----
Net gain (loss) $ (7) $ 42
<PAGE>
The following table discloses the estimated fair values of price risk
management assets and liabilities as of June 30, 1999. The ending and average
fair values and associated carrying amounts of derivative contracts used for
hedging purposes are not material as of June 30, 1999.
Average Ending
Fair Value Fair Value
- --------------------------------------------------------------------------
(in millions)
Assets
Non-Hedging Activities
Swaps $ 890 $ 248
Options 107 74
Futures 240 45
Forward Contracts 744 743
------ ------
Total $1,981 $1,110
Noncurrent portion 394
Current portion $ 716
Liabilities
Non-Hedging Activities
Swaps $ 821 $ 231
Options 128 83
Futures 272 59
Forward Contracts 645 616
------ ------
Total $1,866 $ 989
Noncurrent portion 281
Current portion $ 708
The credit exposure of the five largest counterparties comprised
approximately $285 million of the total credit exposure associated with
financial instruments used to manage price risk. Counterparties considered to
be investment grade or higher comprise 67 percent of the total credit
exposure.
NOTE 4: ACQUISITIONS AND SALES
In September 1998, PG&E Corporation, through its indirect subsidiary USGen New
England, Inc. (USGenNE), completed the acquisition of a portfolio of electric
generating assets and power supply contracts from the New England Electric
System (NEES). The acquisition has been accounted for using the purchase
method of accounting. Accordingly, the purchase price has been allocated to
the assets purchased and the liabilities assumed based upon a preliminary
assessment of the fair values at the date of acquisition.
Including fuel and other inventories and transaction costs, PG&E
Corporation's financing requirements for this acquisition were approximately
$1.8 billion, funded through an aggregate of $1.3 billion of PG&E Generating
Company (PG&E Gen) and USGenNE debt and a $425 million equity contribution
from PG&E Corporation. (On June 1, 1999, U.S. Generating Company changed its
name to PG&E Generating Company). The net purchase price has been
<PAGE>
preliminarily allocated as follows: (1) electric generating assets of $2.3
billion classified as property, plant, and equipment; (2) receivable for
support payments of $0.8 billion; and (3) contractual obligations of $1.3
billion classified as current liabilities and other noncurrent liabilities.
The assets include hydroelectric, coal, oil, and natural gas generation
facilities with a combined generating capacity of 4,000 MW. In addition,
USGenNE assumed 23 multi-year power-purchase agreements representing an
additional 800 MW of production capacity. USGenNE entered into agreements
with NEES as part of the acquisition, which: (1) provide that NEES shall make
support payments over the next ten years to USGenNE for the purchase power
agreements; and (2) require that USGenNE provide electricity to NEES under
contracts that expire over the next six to eleven years.
NOTE 5: UTILITY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF TRUST
HOLDING SOLELY UTILITY SUBORDINATED DEBENTURES
The Utility, through its wholly owned subsidiary, PG&E Capital I (Trust), has
outstanding 12 million shares of 7.90 percent cumulative quarterly income
preferred securities (QUIPS), with an aggregate liquidation value of $300
million. Concurrent with the issuance of the QUIPS, the Trust issued to the
Utility 371,135 shares of common securities with an aggregate liquidation
value of approximately $9 million. The only assets of the Trust are
deferrable interest subordinated debentures issued by the Utility with a face
value of approximately $309 million, an interest rate of 7.90 percent, and a
maturity date of 2025.
NOTE 6: COMMITMENTS AND CONTINGENCIES
Nuclear Insurance:
- ------------------
The Utility has insurance coverage for property damage and business
interruption losses as a member of Nuclear Electric Insurance Limited (NEIL).
Under this insurance, if a nuclear generating facility suffers a loss due to
a prolonged accidental outage, the Utility may be subject to maximum
retrospective assessments of $17 million (property damage) and $5 million
(business interruption), in each case per policy period, in the event losses
exceed the resources of NEIL.
The Utility has purchased primary insurance of $200 million for public
liability claims resulting from a nuclear incident. The Utility has
secondary financial protection which provides an additional $9.5 billion in
coverage, which is mandated by federal legislation. It provides for loss
sharing among utilities owning nuclear generating facilities if a costly
incident occurs. If a nuclear incident results in claims in excess of $200
million, then the Utility may be assessed up to $176 million per incident,
with payments in each year limited to a maximum of $20 million per incident.
Environmental Remediation:
- --------------------------
The Utility may be required to pay for environmental remediation at sites
where the Utility has been or may be a potentially responsible party under
the Comprehensive Environmental Response, Compensation and Liability Act and
similar state environmental laws. These sites include former manufactured
gas plant sites, power plant sites, and sites used by the Utility for the
storage or disposal of potentially hazardous materials. Under federal and
California laws, the Utility may be responsible for remediation of hazardous
substances, even if the Utility did not deposit those substances on the site.
<PAGE>
The Utility records a liability when site assessments indicate
remediation is probable and a range of reasonably likely cleanup costs can
be estimated. The Utility reviews its remediation liability quarterly for
each identified site. The liability is an estimate of costs for site
investigations, remediation, operations and maintenance, monitoring, and
site closure. The remediation costs also reflect (1) current technology,
(2) enacted laws and regulations, (3) experience gained at similar sites,
and (4) the probable level of involvement and financial condition of other
potentially responsible parties. Unless there is a better estimate within
this range of possible costs, the Utility records the lower end of this
range.
The cost of the hazardous substance remediation ultimately undertaken by
the Utility is difficult to estimate. A change in estimate may occur in the
near term due to uncertainty concerning the Utility's responsibility, the
complexity of environmental laws and regulations, and the selection of
compliance alternatives. The Utility had an accrued liability at June 30,
1999, of $294 million for hazardous waste remediation costs at identified
sites, including divested fossil-fueled power plants.
Of the $294 million liability, discussed above, the Utility has recovered
$136 million and expects to recover $129 million in future rates.
Additionally, the Utility is mitigating its costs by obtaining recovery of
its costs from insurance carriers and from other third parties as
appropriate.
Environmental remediation at identified sites may be as much as $482
million if, among other things, other potentially responsible parties are
not financially able to contribute to these costs or further investigation
indicates that the extent of contamination or necessary remediation is
greater than anticipated. The Utility estimated this upper limit of the
range of costs using assumptions least favorable to the Utility, based upon
a range of reasonably possible outcomes. Costs may be higher if the Utility
is found to be responsible for cleanup costs at additional sites or outcomes
change.
Further, as discussed in Generation Divestiture above, the Utility will
retain the pre-closing remediation liability associated with divested
generation facilities.
PG&E Corporation believes the ultimate outcome of these matters will not
have a material impact on its or the Utility's financial position or results
of operations.
Legal Matters:
- --------------
Chromium Litigation:
Several civil suits are pending against the Utility in California state
courts. The suits seek an unspecified amount of compensatory and punitive
damages for alleged personal injuries and, in some cases, property damage,
resulting from alleged exposure to chromium in the vicinity of the Utility's
gas compressor stations at Hinkley, Kettleman, and Topock, California. Two
of these suits on behalf of six individuals also name PG&E Corporation as a
defendant. Currently, there are claims pending on behalf of approximately
1,700 individuals.
The Utility is responding to the suits and asserting affirmative defenses.
The Utility will pursue appropriate legal defenses, including statute of
limitations or exclusivity of workers' compensation laws, and factual
<PAGE>
defenses, including lack of exposure to chromium and the inability of
chromium to cause certain of the illnesses alleged.
PG&E Corporation believes that the ultimate outcome of these matters will
not have a material impact on its or the Utility's financial position or
results of operations.
Texas Franchise Fee Litigation:
In connection with PG&E Corporation's acquisition of Valero Energy
Corporation, now known as PG&E Gas Transmission Texas (PG&E GTT), PG&E GTT
succeeded to the litigation described below.
PG&E GTT and various of its affiliates are defendants in at least two
class action suits and five separate suits filed by various Texas cities.
Generally, these cities allege, among other things, that: (1) owners or
operators of pipelines occupied city property and conducted pipeline
operations without the cities' consent and without compensating the cities;
and (2) the gas marketers failed to pay the cities for accessing and
utilizing the pipelines located in the cities to flow gas under city streets.
Plaintiffs also allege various other claims against the defendants for
failure to secure the cities' consent. Damages are not quantified.
In 1998, a jury trial was held in the separate suit brought by the City of
Edinburg (the City). This suit involved, among other things, a particular
franchise agreement entered into by a former subsidiary of PG&E GTT (now
owned by Southern Union Gas Company (SU)) and the City and certain conduct of
the defendants.
On December 1, 1998, based on the jury verdict, the court entered a
judgment in the City's favor, and awarded damages of $5.3 million, and
attorneys' fees of up to $3.5 million plus interest. The court found that
various PG&E GTT and SU defendants were jointly and severally liable for $3.3
million of the damages and all the attorneys' fees. Certain PG&E GTT
subsidiaries were found solely liable for $1.4 million of the damages. The
court did not clearly indicate the extent to which the PG&E GTT defendants
could be found liable for the remaining damages. The PG&E GTT defendants are
in the process of appealing the judgment.
PG&E Corporation believes that the ultimate outcome of these matters
could have a material adverse impact on its financial position or its
results of operations.
The Utility's 1999 General Rate Case (GRC):
- -------------------------------------------
In December 1997, the Utility filed its 1999 GRC application with the CPUC.
During the GRC process, the CPUC examines the Utility's distribution costs to
determine the amount the Utility may charge customers. The Utility has
requested distribution revenue increases to maintain and improve gas and
electric distribution reliability, safety, and customer service. The
requested revenues, as updated, include an increase of $445 million in
electric base revenues and an increase of $377 million in gas base revenues
over authorized 1998 revenues. The Office of Ratepayer Advocates (ORA)
branch of the CPUC has recommended a decrease of $80 million in electric
revenues and an increase of $104 million in gas base revenues.
Recommendations by the ORA do not represent the positions of the CPUC.
In December 1998, the CPUC issued a decision on interim rate relief in the
GRC. The decision granted the Utility's request to increase its electric
revenues by $445 million and its gas revenues by $377 million on an interim
basis pending a decision in the GRC. The decision allows the Utility to
<PAGE>
reflect the revenue increases, resulting from the Utility request, in
regulatory assets recorded under regulatory adjustment mechanisms approved by
the CPUC. The decision does not increase any electric or gas rates billed to
customers on an interim basis.
Due to a delay in the issuance of a decision in the Utility's GRC, the
Utility's 1999 earnings are based on the authorized amount of revenues in
effect during 1998 and do not include any portion of the requested revenue
increase. When a final decision in the GRC is issued by the CPUC, the
Utility's regulatory assets and net income will be adjusted to reflect any
differences between the amount of revenues currently being recognized and
the amount approved in the final decision. Any such adjustment could have a
material impact on the Utility's and PG&E Corporation's results of
operations.
NOTE 7: SEGMENT INFORMATION
PG&E Corporation's reportable operating segments provide different products
and services and are subject to different forms of regulation or
jurisdictions. PG&E Corporation's reportable segments are described below.
Utility: PG&E Corporation's Northern and Central California energy utility
subsidiary, Pacific Gas and Electric Company, provides natural gas and
electric service to one of every 20 Americans.
Wholesale Business Operations: PG&E Corporation's wholesale business
operations consist of PG&E Gen which develops, builds, operates, owns, and
manages power generation facilities that serve wholesale and industrial
customers; PG&E Gas Transmission (PG&E GT) which owns and operates
approximately 9,000 miles of natural gas pipelines, approximately 500 miles
of natural gas liquids pipelines, a storage facility, and natural gas
processing plants in the Pacific Northwest (PG&E GT NW) and Texas; and PG&E
Energy Trading (PG&E ET) which purchases and sells energy commodities and
provides risk management services to customers in major North American
markets, including, serving PG&E Corporation's other non-utility businesses,
unaffiliated utilities, marketers, municipalities, and large end-use
customers.
Retail Business Operations: PG&E Corporation's retail business operations
consist of PG&E Energy Services (PG&E ES) which provides competitively priced
electricity, natural gas, and related services to industrial, commercial, and
institutional customers.
<PAGE>
Segment information for the three- and six-month periods ended June 30,
1999 and 1998, respectively, were as follows:
<TABLE>
<CAPTION>
Wholesale Retail
---------------------------------- -------
PG&E GT Parent
---------------- & Elimi-
Utility PG&E Gen NW Texas PG&E ET PG&E ES nations(1) Total
------- ------- ------- ------- ------- ------- ------- -------
(in millions)
For the three month period ended:
- ---------------------------------
June 30, 1999
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Operating revenues $ 2,231 $ 253 $ 39 $ 397 $1,767 $ 138 $ (5) $ 4,820
Intersegment revenues 2 1 13 39 257 4 (316) -
------- ------- ------- ------- ------- ------- ------- -------
Total operating
revenues 2,233 254 52 436 2,024 142 (321) 4,820
Net income 172 19 13 (8) 1 (14) (3) 180
June 30, 1998
Operating revenues $ 2,116 $ 115 $ 46 $ 431 $1,983 $ 92 $ 4 $ 4,787
Intersegment revenues 1 - 12 91 77 - (181) -
------- ------- ------- ------- ------- ------- ------- -------
Total operating
revenues 2,117 115 58 522 2,060 92 (177) 4,787
Net income 186 34 15 (19) 1 (14) (29) 174
For the six month period ended:
- -------------------------------
June 30, 1999
Operating revenues $ 4,314 $ 541 $ 85 $ 710 $4,163 $ 269 $ (5) $10,077
Intersegment revenues 4 2 25 83 492 8 (614) -
------- ------- ------- ------- ------- ------- ------- -------
Total operating
revenues 4,318 543 110 793 4,655 277 (619) 10,077
Net income 319 51 28 (32) (2) (22) (6) 336
Total assets at
June 30, 1999 21,720 3,868 1,158 2,587 2,067 192 (166) 31,426
June 30, 1998
Operating revenues $ 4,141 $ 199 $ 94 $ 864 $3,700 $ 135 $ 7 $ 9,140
Intersegment revenues 2 - 25 173 137 - (337) -
------- ------- ------- ------- ------- ------- ------- -------
Total operating
revenues 4,143 199 119 1,037 3,837 135 (330) 9,140
Net income 334 43 30 (29) - (25) (40) 313
Total assets at
June 30, 1998 23,618 1,224 1,168 2,713 1,863 106 (501) 30,191
<FN>
(1) Net income on intercompany positions recognized by segments using mark to market accounting
is eliminated. Intercompany transactions are also eliminated.
</TABLE>
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS
PG&E Corporation (the Corporation) is an energy-based holding company
headquartered in San Francisco, California. PG&E Corporation's businesses
provide energy services throughout North America. PG&E Corporation's
Northern and Central California energy utility subsidiary, Pacific Gas and
Electric Company (the Utility), provides natural gas and electric service to
one of every 20 Americans. PG&E Corporation's four other businesses provide a
wide range of energy products and services through its wholesale and retail
business operations.
PG&E Corporation's wholesale business operations consist of PG&E
Generating Company (PG&E Gen), formerly known as U.S. Generating Company,
which develops, builds, operates, owns, and manages power generation
facilities that serve wholesale and industrial customers; PG&E Gas
Transmission (PG&E GT) which owns and operates approximately 9,000 miles of
natural gas pipelines, approximately 500 miles of natural gas liquids
pipelines, a storage facility, and natural gas processing plants in the
Pacific Northwest (PG&E GT NW) and Texas (PG&E GTT); and PG&E Energy Trading
(PG&E ET) which purchases and sells energy commodities and provides risk
management services to customers in major North American markets, including,
serving PG&E Corporation's other non-utility businesses, unaffiliated
utilities, marketers, municipalities, and large end-use customers.
PG&E Corporation's retail business operations consist of PG&E Energy
Services (PG&E ES) which provides competitively priced electricity, natural
gas, and related services to industrial, commercial, and institutional
customers.
This is a combined Quarterly Report on Form 10-Q of PG&E Corporation and
Pacific Gas and Electric Company. It includes separate consolidated
financial statements for each entity. The consolidated financial statements
of PG&E Corporation reflect the accounts of PG&E Corporation, the Utility,
and PG&E Corporation's other wholly owned and controlled subsidiaries. The
consolidated financial statements of the Utility reflect the accounts of the
Utility and its wholly owned subsidiaries. This Management's Discussion and
Analysis (MD&A) should be read in conjunction with the consolidated financial
statements included herein. Further, this quarterly report should be read in
conjunction with the Corporation's and the Utility's Consolidated Financial
Statements and Notes to Consolidated Financial Statements incorporated by
reference in their combined 1998 Annual Report on Form 10-K.
This combined Quarterly Report on Form 10-Q, including this MD&A, contains
forward-looking statements about the future that are necessarily subject to
various risks and uncertainties. These statements are based on the beliefs
and assumptions of management which management believes are reasonable and on
information currently available to management. These forward-looking
statements are identified by words such as "estimates," "expects,"
"anticipates," "plans," "believes", "speculates", and other similar
expressions.
Factors that could cause future results to differ materially from those
expressed in or implied by the forward-looking statements or historical
results include the impact or outcome of:
- - the pace and extent of the ongoing restructuring of the electric and gas
industries across the United States;
- - the outcome of regulatory and legislative proceedings and operational
changes related to industry restructuring, including the valuation of the
Utility's hydroelectric generation facilities and changes in the Utility's
business processes and systems;
<PAGE>
- - any changes in the amount the Utility is allowed to collect (recover) from
its customers for certain costs which prove to be uneconomic under the new
competitive market (called transition costs) in accordance with the Utility's
plan for recovering those costs;
- - the successful integration and performance of our recently acquired assets;
- - our ability to successfully compete outside our traditional regulated
markets;
- - internal and external Year 2000 software and hardware issues;
- - the outcome of the Utility's various regulatory proceedings, including: the
1999 general rate case; the proposal to adopt performance based ratemaking
(PBR); the transmission rate case applications; and post-transition period
ratemaking proceedings;
- - fluctuations in commodity gas and electric prices and our ability to
successfully manage such price fluctuations; and
- - the pace and extent of competition in the California generation market and
its impact on the Utility's costs and resulting collection of transition
costs.
Although the ultimate impacts of the above factors are uncertain, these
and other factors may cause future earnings to differ materially from results
or outcomes we currently seek or expect. Each of these factors is discussed
in greater detail in this MD&A.
In this MD&A, we first discuss our competitive and regulatory environment.
We then discuss earnings and changes in our results of operations for the
three- and six-month periods ended June 30, 1999 and 1998. Finally, we
discuss liquidity and financial resources, various uncertainties that could
affect future earnings, and our risk management activities. Our MD&A applies
to both PG&E Corporation and the Utility.
Competitive and Regulatory Environment
This section provides a discussion of the competitive environment in the
evolving energy industry, the California electric industry restructuring, the
New England electricity market, and regulatory matters.
The Competitive Environment in the Evolving Energy Industry
- -----------------------------------------------------------
Historically, energy utilities operated as regulated monopolies within
specific service territories where they were essentially the sole suppliers
of natural gas and electricity services. Under this model, the energy
utilities owned and operated all of the businesses necessary to procure,
generate, transport, and distribute energy. These services were priced on a
combined (bundled) basis, with rates charged by the energy companies designed
to include all of the costs of providing these services. Now, energy
utilities face intensifying pressures to make competitive those activities
that are not natural monopoly services. The most significant of these
services are electricity generation and natural gas supply.
The driving forces behind these competitive pressures are customers who
believe they can obtain energy at lower unit prices and competitors who want
access to those customers. Regulators and legislators are responding to
those customers and competitors by providing more competition in the energy
industry. Regulators and legislators are requiring utilities to "unbundle"
rates (separate their various energy services and the prices of those
services). This allows customers to compare unit prices of the Utility and
other providers when selecting their energy service provider.
In the natural gas industry, Federal Energy Regulatory Commission (FERC)
Order 636 required interstate pipeline companies to divide their services
<PAGE>
into separate gas commodity sales, transportation, and storage services.
Under Order 636, interstate gas pipelines must provide transportation
service regardless of whether the customer (typically a local gas
distribution company) buys the gas commodity from the pipeline.
In the electric industry, the Public Utilities Regulatory Policies Act of
1978 specifically provided that unregulated companies could become wholesale
generators of electricity and that utilities were required to purchase and
use power generated by these unregulated companies in meeting their
customers' needs. The National Energy Policy Act of 1992 was designed to
increase competition in the wholesale unregulated generation market by
requiring access to electric utility transmission systems by all wholesale
unregulated generators, sellers, and buyers of electricity. Now, an
increasing number of states throughout the country either have implemented
plans or are considering proposals to separate the generation from the
transmission and distribution of electricity through some form of electric
industry restructuring.
To date, the states, not the federal government, have taken the initiative
on electric industry restructuring at the retail level. While at least five
bills mandating deregulation of the electric industry were introduced in the
U.S. Congress over the past two years, none have been passed. As a result,
the pace, extent, and methods for restructuring the electric industry vary
widely throughout the country. For instance, as of June 30, 1999, twenty
states have enacted electric industry restructuring legislation, including
California, Texas, Illinois, Pennsylvania, New Jersey, Massachusetts, Rhode
Island, and Connecticut. Other states, such as Oregon, are seriously
considering restructuring proposals. There also are some states that have
passed legislation precluding or significantly slowing down deregulation.
Differences in how individual states view electric industry restructuring
often relate to the existing unit cost of energy supplies within each state.
Generally, states having higher energy unit costs are moving more quickly to
deregulate energy supply markets.
Implementation of our national energy strategy depends, in part, upon the
opening of energy markets to provide customer choice of supplier. Undue
delays by states or federal legislation to deregulate the electric generation
and natural gas supply business could impact the pace of growth of our
wholesale and retail business operations.
California Industry Restructuring
- ---------------------------------
The Electric Business:
In 1998, California became one of the first states in the country to
implement electric industry restructuring. Today, many Californians may
choose to purchase their electricity from investor-owned utilities such as
Pacific Gas and Electric Company, or unregulated retail electricity suppliers
(for example, marketers, including PG&E Energy Services, brokers, and
aggregators). The restructuring contemplates that the investor-owned
utilities, including the Utility, will continue to provide distribution
services to substantially all customers within their service territories,
including providing electricity to customers who choose not to be served by
another service provider.
The restructuring legislation recognized that market-based revenues may
not be sufficient to recover (that is, collect from customers) all of the
Utility's generation costs. The restructuring legislation provides the
California investor-owned utilities the opportunity to recover such
uneconomic generation costs (called transition costs) until the earlier of
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December 31, 2001, or when the utilities have recovered their authorized
transition costs as determined by the California Public Utilities Commission
(CPUC). The period during which transition costs may be recovered is called
the transition period. The legislation permits certain transition costs to
be recovered after the transition period.
California electric industry restructuring legislation has four principal
elements: (1) the establishment of a competitive market framework, (2) an
electric rate freeze and rate reduction, (3) the recovery of transition
costs, and (4) divestiture of utility-owned generation facilities. Each
element is discussed below.
Competitive Market Framework: To create a competitive generation market, a
Power Exchange (PX) and an Independent System Operator (ISO) began operating
on March 31, 1998. During the transition period, the Utility is required to
bid or schedule into the PX and ISO markets all of the electricity generated
by its power plants and electricity acquired under contractual agreements
with unregulated generators. Also during the transition period, the Utility
is required to buy from the PX all electricity needed to provide service to
retail customers that continue to choose the Utility as their electricity
supplier. The ISO schedules delivery of electricity for all market
participants. The Utility continues to own and maintain a portion of the
transmission system, but the ISO controls the operation of the system.
During 1998 and 1999, the Utility continued its efforts to develop and
implement changes to its business processes and systems, including the
customer information and billing system, to accommodate electric industry
restructuring. To the extent that the Utility is unable to develop and
implement such changes in a successful and timely manner, there could be an
adverse impact on the Utility's or PG&E Corporation's future results of
operations.
Rate Freeze and Rate Reduction: Legislation required an electric rate freeze
and an electric rate reduction to extend throughout the transition period.
The Utility has held rates for its larger customers at 1996 levels, and it
will hold their rates at that level until the end of the transition period.
On January 1, 1998, the Utility reduced electric rates for its residential
and small commercial customers by 10 percent from 1996 levels, and it will
hold their rates at that level until the end of the transition period.
Collectively, these actions are called a rate freeze.
To pay for the 10 percent rate reduction, the Utility refinanced $2.9
billion of its transition costs with the proceeds from rate reduction bonds.
The bonds allow for the rate reduction by lowering the carrying cost on a
portion of the transition costs and by deferring recovery of a portion of
these transition costs until after the transition period. During the rate
freeze, the rate reduction bond debt service will not increase the Utility
customers' electric rates. If the transition period ends before December 31,
2001, the Utility will be obligated to return a portion of the bond proceeds
to customers. The timing and exact amount of such portion, if any, has not
yet been determined.
The frozen rates include a component for transition cost recovery.
Transition costs are being recovered from all Utility distribution customers
through a nonbypassable charge regardless of the customer's choice of
electricity supplier. As the customer charge for transition costs is
nonbypassable, the Utility believes that the availability of choice to its
customers will not have a material impact on its ability to recover
transition costs.
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Revenues from frozen electric rates provide for the recovery of authorized
Utility costs, including transmission and distribution service, public
purpose programs, nuclear decommissioning, and rate reduction bond debt
service. To the extent the revenues from frozen rates exceed authorized
Utility costs, the remaining revenues constitute the competitive transition
charge (CTC), which recovers the transition costs. These CTC revenues are
subject to seasonal fluctuations in the Utility's sales volumes and certain
other factors.
Transition Cost Recovery: Market-based revenues through sales to the PX may
not be sufficient to recover all of the Utility's generation costs. Under
the California restructuring legislation, the Utility has the opportunity to
recover its transition costs until the earlier of December 31, 2001, or when
the Utility has recovered its authorized transition costs as determined by
the CPUC, although certain transition costs can be recovered after the
transition period. At the conclusion of the transition period, the Utility
will be at risk to recover any of its remaining generation costs through
market-based revenues.
Transition costs consist of: (1) above-market sunk costs (costs associated
with Utility-owned generation assets that are fixed and unavoidable and
currently included in the Utility customers' electric rates) and future
costs, such as costs related to removal of Utility-owned generation
facilities, (2) costs associated with the Utility's long-term contracts to
purchase power at above-market prices from qualifying facilities and other
power suppliers, and (3) generation-related regulatory assets and
obligations. (In general, regulatory assets are expenses deferred in the
current or prior periods, to be included in rates in subsequent periods.)
Above-market sunk costs result when the book value of a facility is in
excess of its market value. Conversely, below-market sunk costs result when
the market value of a facility is in excess of its book value. The total
amount of generation facility costs to be included as transition costs will
be based on the aggregate of above-market and below-market values. The
above-market portion of these costs is eligible for recovery as a transition
cost. The below-market portion of these costs will reduce other unrecovered
transition costs. These above- and below-market sunk costs are related to
generating facilities that are classified as either non-nuclear or nuclear
sunk costs.
The Utility cannot determine the exact amount of above-market non-nuclear
sunk costs that will be recoverable as transition costs until a market
valuation process (through appraisal, sale, or other valuation method) is
completed for each of its non-nuclear generation facilities. Several of
these valuations occurred in 1997 and 1998, when the Utility agreed to sell
seven of its electric generation plants to third parties. The total market
value of these facilities resulted in sales proceeds that exceeded the book
value and therefore has reduced the amount of transition costs remaining to
be recovered. The remainder of the valuation process is expected to be
completed by December 31, 2001. The Utility's remaining non-nuclear
generation facilities consist primarily of its hydroelectric generation
system. If the market value of the Utility's hydroelectric facilities is
determined based upon any method other than a sale of the facilities to a
third party, a material charge to Utility earnings could result. Any excess
of market value over book value would be used to reduce other transition
costs. (See Generation Divestiture below.)
Nuclear generation sunk costs were determined separately through a CPUC
proceeding and were subject to a final verification audit that was completed
in August 1998. The audit of the Utility's Diablo Canyon Nuclear Power
Plant (Diablo Canyon) accounts at December 31, 1996, resulted in the issuance
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of an unqualified opinion. The audit verified that Diablo Canyon sunk costs
at December 31, 1996, were $3.3 billion of the total $7.1 billion
construction costs. The independent accounting firm also issued an agreed-
upon special procedures report, requested by the CPUC, that questioned $200
million of the $3.3 billion sunk costs. The CPUC will review any proposed
adjustments to Diablo Canyon's recoverable costs that resulted from the
report. At this time, the Utility cannot predict what actions, if any, the
CPUC may take regarding the audit report.
Costs associated with the Utility's long-term contracts to purchase
electric power at above-market prices are included as transition costs. Over
the remaining life of these contracts the Utility estimates that it will
purchase 322 million megawatt-hours of electric power. To the extent that
the individual contract prices are above the market price, the Utility is
collecting the difference between the contract price and the market price
from customers, as a transition cost, over the term of the contract. The
contracts expire at various dates through 2028. The total amount of the
above-market costs under long-term contracts will be based on several
variables, including the capacity factors of the related generating
facilities and future market prices for electricity. During the six-month
period ended June 30, 1999, the average price paid per kilowatt-hour (kWh)
under the Utility's long-term contracts for electric power was 6.1 cents per
kWh. The average cost of electric energy for energy purchased at market
rates from the PX for the six-month period ended June 30, 1999, was 2.6 cents
per kWh.
Generation-related regulatory assets and obligations (net generation-
related regulatory assets) are included as transition costs. At June 30,
1999, the Utility's generation-related net regulatory assets totaled $4.5
billion.
Most transition costs can be recovered until December 31, 2001. This
recovery period is significantly shorter than the recovery period of the
generation assets prior to restructuring and is referred to as accelerated
recovery. Accordingly, the Utility is amortizing its transition costs,
including most generation-related regulatory assets over the transition
period. During the transition period, the Utility is receiving a reduced
return on common equity for all of its generation assets, including those
generation assets reclassified to regulatory assets. The reduced return on
common equity is 6.77 percent.
Certain transition costs can be recovered through a non-bypassable charge
to distribution customers after December 31, 2001. These costs include: (1)
certain employee-related transition costs, (2) above-market payments under
existing long-term contracts to purchase power, discussed above, (3) up to
$95 million of transition costs after the transition period to the extent
that the recovery of such costs during the transition period was displaced by
the recovery of electric industry restructuring implementation costs, and (4)
transition costs financed by the rate reduction bonds. Transition costs
financed by the issuance of rate reduction bonds are expected to be recovered
over the term of the bonds. In addition, the Utility's nuclear
decommissioning costs are being recovered through a CPUC-authorized charge,
which will extend until sufficient funds exist to decommission the nuclear
facility. During the rate freeze the charge for these costs will not
increase the Utility customers' electric rates. Excluding these exceptions,
the Utility will write off any transition costs not recovered during the
transition period.
Revenues provided for the recovery of most non-nuclear transition costs
are based upon the acceleration of such costs within the transition period.
For Diablo Canyon transition costs, revenues provided for transition cost
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recovery are based on: (1) an established incremental cost incentive price
(ICIP) per kWh generated by Diablo Canyon to recover certain ongoing costs
and capital additions, and (2) the accelerated recovery of the investment in
Diablo Canyon from a period ending in 2016 to a five-year period ending
December 31, 2001. In a pending proceeding, the CPUC is currently
considering whether the Utility may continue to recover revenues based on the
ICIP through December 31, 2001, or must cease recovery of such revenues if it
has completed recovery of all other utility generation-related transition
costs prior to that date.
The Utility is amortizing its eligible transition costs, including
generation-related regulatory assets, over the transition period in
conjunction with the available CTC revenues. Effective January 1, 1998, the
Utility started collecting these eligible transition costs through the
nonbypassable CTC. For the six months ended June 30, 1999, regulatory assets
related to electric utility restructuring decreased by $813 million, which
reflects the recovery of eligible transition costs.
During the transition period, the CPUC reviews the Utility's compliance
with the accounting methods established in the CPUC's decisions governing
transition cost recovery and the amount of transition costs requested for
recovery. The CPUC is currently reviewing non-nuclear transition costs
amortized during the first six months of 1998.
Generation Divestiture: In 1998, the Utility completed the sale of three
fossil-fueled generation plants for $501 million. These three fossil-fueled
plants had a combined book value at the time of the sale of $346 million and
had a combined capacity of 2,645 megawatts (MW).
On April 16, 1999, the Utility sold three other fossil-fueled generation
plants for $801 million. At the time of sale, these three fossil-fueled
plants had a combined book value of $256 million and had a combined capacity
of 3,065 MW.
On May 7, 1999, the Utility sold its complex of geothermal generation
facilities for $213 million. At the time of sale, these facilities had a
combined book value of $244 million and had a combined capacity of 1,224 MW.
The Utility will retain a liability for required environmental remediation
related to all of its fossil-fueled generation and geothermal generation
plants of any pre-closing soil or groundwater contamination at the plants it
has or will sell. The Utility records its estimated liability for the
retained environmental remediation obligation as part of the determination of
the gain or loss on the sale of each plant.
Any gains from the sale of the Utility-owned generation plants will be
used to offset other transition costs. Likewise, any losses from the sale of
Utility-owned generation plants are recoverable as transition costs. PG&E
Corporation does not believe sales of any generation facilities to a third
party will have a material impact on its results of operations.
In May 1998, the Utility notified the CPUC that it does not plan to retain
its hydroelectric generation assets as part of the Utility. In December
1998, the Utility filed with the CPUC its proposed appraisal process for
valuing its hydroelectric facilities. The Utility withdrew its proposal in
March 1999 when the CPUC clarified that the CPUC proceeding would only apply
to assets to be retained in the Utility. The Utility currently is evaluating
alternative strategies with respect to the valuation and disposition of its
hydroelectric facilities, including a potential transfer of the facilities to
another PG&E Corporation affiliate. Meanwhile, the California legislature is
reviewing legislative proposals that would address hydroelectric facilities
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valuation and divestiture issues on an interim or permanent basis. If
legislation setting a valuation were enacted and the legislated valuation was
materially higher than the value ultimately recognized in connection with the
sale or other disposition of the assets, the Utility could suffer a material
loss upon the sale or other disposition of the hydroelectric assets. If such
legislation were enacted, we expect that the Utility would challenge the
legality of legislation adopting such excess or interim valuation. Although
legislation could be passed prior to the close of the legislative session in
September 1999, the Corporation and Utility are unable to predict the nature
or likelihood of enactment of any such legislation.
At June 30, 1999, the book value of the Utility's net investment in
hydroelectric generation assets was approximately $0.8 billion, excluding
approximately $0.5 billion of net investment reclassified as regulatory
assets recoverable as transition costs. The value of the hydroelectric
assets is expected to exceed their book value by a material amount. In
connection with legislative discussions concerning the hydroelectric assets,
some third parties have publicly speculated that the value of the
hydroelectric assets could be in excess of $3 billion. If the market value
of the hydroelectric generation assets is determined by any method other than
a sale of the assets to a third party, a material charge to Utility earnings
could result. Any excess of market value over the $0.8 billion book value
would be used to reduce other transition costs, including the remaining $0.5
billion of regulatory assets related to the hydroelectric generation assets.
The timing and nature of any such charge is dependent upon the valuation
method and procedure adopted, and the method of implementation, which could
occur as soon as the third quarter of 1999.
Financial Impact: The Utility's ability to continue recovering its transition
costs will be dependent on several factors including: (1) the continued
application of the regulatory framework established by the CPUC and state
legislation, (2) the amount of transition costs ultimately approved for
recovery by the CPUC, (3) the determined value of the Utility's hydroelectric
generation facilities, (4) future Utility sales levels, (5) future Utility
fuel and operating costs, (6) the extent to which the Utility's authorized
revenues to recover distribution and transmission costs are increased or
decreased, and (7) the market price of electricity. Given the current
evaluation of these factors, PG&E Corporation believes that the Utility will
recover its transition costs under the terms of the approved transition plan.
However, a change in one or more of these factors could affect the
probability of recovery of transition costs and result in a material charge.
The Gas Business:
Restructuring of the natural gas industry on both the national and the state
level has given choices to California utility customers to meet their gas
supply needs. The Gas Accord Settlement (Accord), a multi-party settlement
approved by the CPUC in 1997, continues the process of restructuring the gas
industry in California. The Accord was implemented in March 1998, and has
four principal elements:
1. The Accord separates or "unbundles" the rates for the Utility's gas
transportation system. The Utility now offers transmission, distribution,
and storage services as separate and distinct services to its noncore
customers. Unbundling gives these customers the opportunity to select from a
menu of services offered by the Utility and enables them to pay only for the
services that they use. Unbundling also makes access to the transmission
system possible for all gas marketers and shippers, as well as noncore end-
users. As a result, the Accord makes the Utility's transmission system more
accessible to a greater number of customers.
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2. The Accord increases the opportunity for the Utility's core customers to
select the commodity gas supplier of their choice. Greater customer choice
increases competition among suppliers providing gas to core customers and
reduces the Utility's role in purchasing gas for such customers. Despite
these changes, the Utility continues to purchase gas as a regulated supplier
for those who request it, serving a majority of core customers in its service
territory.
3. The Accord changes the way in which the Utility's costs of purchasing gas
for core customers through 2002 are regulated. The Accord replaces CPUC
reasonableness reviews with the core procurement incentive mechanism (CPIM),
a form of incentive ratemaking that provides the Utility a direct financial
incentive to procure gas and transportation services at the lowest reasonable
costs by comparing all procurement costs to an aggregate market-based
benchmark. If costs fall within a range (tolerance band) around the
benchmark, costs are considered reasonable and fully recoverable from
ratepayers. If procurement costs fall outside the tolerance band, ratepayers
and shareholders share savings or costs, respectively.
4. The Accord settled various regulatory issues involving the Utility and
various other parties. Resolution of these issues did not have a material
adverse impact on the Utility's or our financial position or results of
operations.
The Accord also establishes gas transmission rates within California for
the period from March 1998 through December 2002 for the Utility's core and
noncore customers and eliminates regulatory protection for variations in
sales volumes for noncore transmission revenues. As a result, the Utility is
at risk for variations between actual and forecasted noncore transmission
throughput volumes. However, we do not expect these variations to have a
material adverse impact on the Utility's or our financial position or results
of operations.
Rates for gas distribution services will continue to be set by the CPUC
and designed to provide the Utility an opportunity to recover its costs of
service and include a return on its investment. The regulatory mechanisms
for setting gas distribution rates are discussed below under Regulatory
Matters.
New England Electricity Market:
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Three New England states where our wholesale businesses operate electric
generation facilities (Massachusetts, New Hampshire, and Rhode Island) were,
like California, among the first states in the country to introduce electric
industry restructuring. Connecticut also has passed electric industry
restructuring legislation. As a result of this restructuring and certain
other regulatory initiatives, the wholesale unregulated electricity market in
New England features a bid-based market and an ISO.
In September 1998, PG&E Corporation, through its indirect subsidiary USGen
New England, Inc. (USGenNE), completed the acquisition of a portfolio of
electric generation assets and power supply contracts from New England
Electric System (NEES). The purchased assets include hydroelectric, coal,
oil, and natural gas generation facilities with a combined generating
capacity of about 4,000 MW.
Including fuel and other inventories and transaction costs, the financing
requirements for this transaction were approximately $1.8 billion, funded
through an aggregate of $1.3 billion of PG&E Gen and USGenNE debt and a $425
million equity contribution from PG&E Corporation. The net purchase price
has been allocated as follows: (1) electric generating assets of $2.3
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billion, (2) receivable for support payments of $0.8 billion, and (3) out of
market contractual obligations of $1.3 billion, relating to acquired power
purchase agreements, gas agreements and standard offer agreements.
As part of the New England electric industry restructuring, the local
utility companies providing service to retail customers were required to
offer Standard Offer Service (SOS) to their customers. Retail customers may
select alternative suppliers at any time. The SOS is intended to provide
customers with a price benefit (the commodity electric price offered to the
retail customer is expected to be less than the market price) for the first
several years, followed by a price disincentive that is intended to stimulate
the retail market.
Retail customers may continue to receive SOS through June 30, 2002, in New
Hampshire (subject to early termination on December 31, 2000, at the
discretion of the New Hampshire Public Service Commission), through December
31, 2004, in Massachusetts, and through December 31, 2009, in Rhode Island.
However, if any customers elect to have their electricity provided by an
alternate supplier, they are precluded from going back to the SOS.
In connection with the purchase of the generation assets, we entered into
agreements to supply the electric capacity and energy requirements necessary
for NEES to meet its SOS obligations. NEES is responsible for passing on to
us the revenues generated from the SOS. USGenNE, is currently serving the
SOS electric capacity and energy requirements for NEES, except for New
Hampshire's SOS. On March 1, 1999, Constellation Power Source, Inc. assumed
this component of the SOS upon winning a competitive bidding solicitation.
Like California utilities, the New England utilities entered into
agreements with unregulated companies to provide energy and capacity at
prices that are anticipated to be in excess of market prices. We assumed
NEES' contractual rights and duties under several of these power-purchase
agreements, which in aggregate provide for 800 MW of capacity. However, NEES
will make support payments to us toward the cost of these agreements. The
support payments by NEES total $1.1 billion in the aggregate (undiscounted)
and are due in monthly installments from September 1998 through January 2008.
In certain circumstances, with our consent, NEES may make a full or partial
lump sum accelerated payment.
Initially, approximately 90 percent of the acquired operating capacity,
including capacity and energy generated by other companies and provided to us
under power-purchase agreements, is dedicated to providing services to
customers receiving SOS. To the extent that customers eligible to receive
SOS chose alternate suppliers, this percentage will decrease. As customers
choose alternate suppliers, a greater proportion of the output of the
acquired operating capacity will be subject to market prices.
Regulatory Matters:
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The Utility is the only subsidiary with significant regulatory activity at
this time. Items affecting future Utility authorized revenues include: the
1999 general rate case, the 1999 cost of capital proceeding, the distribution
performance based ratemaking application, FERC transmission rate cases, the
CPUC's gas strategy order instituting rulemaking, the Diablo Canyon sunk
costs audit, and post transition period ratemaking proceeding. These items
are discussed below. Any requested change in authorized electric revenues
resulting from any of these proceedings would not impact the Utility's
customer electric rates through the transition period because these rates are
frozen in accordance with the electric transition plan. However, the amount
of remaining revenues providing for the recovery of transition costs would be
affected.
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The 1999 General Rate Case (GRC):
In December 1997, the Utility filed its 1999 GRC application with the CPUC.
During the GRC process, the CPUC examines the Utility's distribution costs to
determine the amount the Utility may charge customers. The Utility has
requested distribution revenue increases to maintain and improve gas and
electric distribution reliability, safety, and customer service. The
requested revenues, as updated, include an increase of $445 million in
electric base revenues and an increase of $377 million in gas base revenues
over authorized 1998 revenues. The Office of Ratepayer Advocates (ORA)
branch of the CPUC has recommended a decrease of $80 million in electric
revenues and an increase of $104 million in gas base revenues.
Recommendations by the ORA do not represent the positions of the CPUC.
In December 1998, the CPUC issued a decision on interim rate relief in the
GRC. The decision granted the Utility's request to increase its electric
revenues by $445 million and its gas revenues by $377 million on an interim
basis pending a decision in the GRC. The decision allows the Utility to
reflect the revenue increases, resulting from the Utility request, in
regulatory assets recorded under regulatory adjustment mechanisms approved by
the CPUC. The decision does not increase any electric or gas rates billed to
customers on an interim basis.
Due to a delay in the issuance of a decision in the Utility's GRC, except
for the impacts of the cost of capital decision, discussed below, the
Utility's 1999 earnings are based on the authorized amount of revenues in
effect during 1998 and do not include any portion of the requested revenue
increase. When a final decision in the GRC is issued by the CPUC, the
Utility's regulatory assets and net income will be adjusted to reflect any
differences between the amount of revenues currently being recognized and
the amount approved in the final decision. Any such adjustment could have a
material impact on the Utility's and PG&E Corporation's results of
operations.
The 1999 Cost of Capital Proceeding:
In June 1999, the CPUC issued a final decision in the Utility's 1999 Cost of
Capital proceeding. The decision adopts a return on common equity (ROE) of
10.6 percent for the Utility's electric distribution and gas distribution
assets, and an overall return on utility rate base of 8.75 percent in 1999.
These are reductions from the Utility's 1998 authorized ROE of 11.2 percent
and overall return of 9.17 percent.
The decision maintains the Utility's authorized capital structure for 1999
at 46.2 percent long-term debt, 5.8 percent preferred stock, and 48 percent
common equity. The decision is retroactive to January 1, 1999. The decision
has reduced the Utility's base revenues for the six-months ended June 30,
1999 as compared to the six-months ended June 30, 1998, by $23.1 million and
$7.3 million for electric and gas distribution, respectively.
The Distribution Performance Based Ratemaking (PBR) Application:
The Utility filed an amended distribution PBR proposal with the CPUC in
February 1999. If approved as filed, the distribution PBR will determine the
Utility's gas and electric distribution revenues for the years 2000 through
2004. Under the Utility's proposal, distribution revenues for the years 2000
through 2004 would be determined by multiplying total distribution revenues
by a rate formula. The rate formula would be based principally on inflation
less a proposed productivity factor of 1.1 percent and 0.82 percent for
electric distribution and gas distribution, respectively. These productivity
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factors will be fixed for the five year duration of the PBR. The Utility has
proposed different rate formulas for gas customers, small electric customers
(principally residential and commercial customers) and large electric
customers.
The proposal also includes a sharing mechanism for earnings that are
significantly above or below the authorized weighted average cost of capital.
In addition, the proposed PBR includes rewards and penalties that will depend
upon the Utility's ability to achieve performance standards for electric
distribution reliability; maintenance, repair, and replacement; customer
service; and employee safety. The procedural schedule in the PBR proceeding
has been suspended pending the issuance of a proposed decision in the
Utility's 1999 GRC proceeding. A final decision in the PBR proceeding is not
expected to be issued until mid-2000. The Utility has applied for interim
relief, which would make the final decision effective on January 1, 2000.
FERC Transmission Rate Cases:
Since April 1, 1998, all electric transmission revenues are authorized by
FERC. During 1998, the FERC issued orders that put into effect various rates
to recover electric transmission costs from the Utility's former bundled rate
transmission customers. These rates are subject to refund. On April 14,
1999, the Utility filed a settlement with FERC which, if approved, allows the
Utility to recover $168 million for the period of April 1998 through October
1998, and $177 million for the period of November 1998 through May 1999. The
Utility does not expect a material impact on its financial position or
results of operations resulting from the settlement. On May 27, 1999, FERC
approved, subject to refund, the Utility's March 30, 1999, request to begin
recovering, as of May 31, 1999, $324 million annually in revenues from its
former bundled retail transmission customers.
The CPUC's Gas Strategy Order Instituting Rulemaking:
In January 1998, the CPUC opened a rulemaking proceeding to explore changes
in the natural gas industry, including the possible further unbundling of
services to promote competition, streamlining regulation for noncompetitive
services, mitigating the potential for anti-competitive behavior, and
establishing appropriate consumer protections. In 1998, the Governor of
California signed Senate Bill 1602, allowing the CPUC to investigate issues
associated with the further restructuring of natural gas services but
prohibiting the CPUC from enacting any such gas industry restructuring
decisions prior to January 1, 2000. On July 8, 1999, the CPUC issued a
decision identifying options for restructuring the natural gas industry. In
the decision, the CPUC reaffirmed the structure of the Gas Accord and stated
that it seeks to explore that market structure that maintains the utilities'
traditional role of providing fully integrated default service to core
customers while removing obstacles to competitive offering of gas commodity,
transmission, storage, balancing, and certain other services. The CPUC
requested all interested parties to try to settle various issues raised in
the decision within 60 days, and if that effort is unsuccessful, to move to
hearings on the costs, benefits, and other factors affecting these proposals,
with initial testimony due in late September 1999. The CPUC closed the
existing rule-making proceedings and opened a new investigative proceeding to
explore in more detail the anticipated costs and benefits associated with the
different market structure options the CPUC has identified. The CPUC's goal
is to submit a final report to the California Legislature on gas
restructuring possibly in the first quarter of next year.
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The Diablo Canyon Sunk Costs Audit:
In August 1998, an independent accounting firm retained by the CPUC completed
a financial verification audit of the Utility's Diablo Canyon plant accounts
as of December 31, 1996. The audit resulted in the issuance of an
unqualified opinion. The audit verified that Diablo Canyon sunk costs at
December 31, 1996, were $3.3 billion of the total $7.1 billion construction
costs. (Sunk costs are costs associated with Utility-owned generating
facilities that are fixed and unavoidable and currently included in the
Utility customers' electric rates.) The independent accounting firm also
issued an agreed-upon special procedures report which questioned $200 million
of the $3.3 billion sunk costs. The CPUC will review any proposed
adjustments to Diablo Canyon's recoverable costs, which resulted from the
report. At this time, the Utility cannot predict what actions, if any, the
CPUC may take regarding the audit report.
Post-Transition Period Ratemaking Proceeding:
In a pending proceeding, the CPUC currently is considering the ratemaking
mechanism under which the Utility's transition cost recovery would be
completed, the rate freeze would end, and post-transition rates would be
established, consistent with the electric industry restructuring legislation
and the Utility's transition cost recovery plan. In this proceeding, the CPUC
is considering whether the Utility may continue to recover revenues for its
Diablo Canyon nuclear transition costs based on the incremental cost incentive
price (ICIP) through December 31, 2001, or must cease recovery of such
revenues if the Utility has completed recovery of all other generation related
transition costs before that date. The ICIP was established effective January
1, 1997, as a performance-based mechanism to recover Diablo Canyon's variable
and other operating costs and capital addition costs. The ICIP mechanism
establishes a rate per kWh generated by the facility. This rate is based upon
a fixed forecast of ongoing costs, capital additions, and capacity factors for
the period 1997 through 2001. The fixed forecast of ICIP for 1999, 2000, and
2001 is $3.37 per Kwh, $3.43 per kWh, and $3.49 per kWh, respectively. The
ICIP revenues, based on an assumed capacity factor of 83.6%, for 1999, 2000,
and 2001, are projected to be $532 million, $542 million, and $552 million,
respectively. If the ICIP mechanism is discontinued before December 31, 2001,
the price for Diablo Canyon generation may be lower or higher than the ICIP
prices depending on market conditions, which would result in lower or higher
revenues than the projected ICIP revenues. The average cost of electric energy
for energy purchased at market rates from the PX for the six-months ended June
30, 1999, was 2.6 cents per kWh.
Results of Operations
In this section, we present the components of our results of operations for
the three- and six-month periods ended June 30, 1999 and 1998. Due to a
delay in the issuance of a decision in the Utility's GRC, except for the
impacts of the cost of capital decisions, discussed above, the Utility's
1999 earnings are based on the authorized amount of revenues in effect
during 1998 and do not include any portion of the requested revenue
increase. When a final decision in the GRC is issued by the CPUC, the
Utility's regulatory assets and net income will be adjusted to reflect any
differences between the amount of revenues currently being recognized and
the amount approved in the final decision. Any such adjustment could have a
material impact on the Utility's and PG&E Corporation's results of
operations.
The table below shows for the three- and six-month periods ended June 30,
1999 and 1998, respectively, certain items from our Statement of Consolidated
Income detailed by (1) Utility, (2) wholesale, and (3) retail business
<PAGE>
operations of PG&E Corporation. (In the "Total" column, the table shows the
combined results of operations for these three groups.) The information for
PG&E Corporation (the "Total" column) excludes transactions between its
subsidiaries (such as the purchase of natural gas by the Utility from the
unregulated business operations). Following this table we discuss earnings
and explain why the components of our results of operations varied for the
three- and six-month periods ended June 30, 1999, as compared to the same
periods in 1998.
<PAGE>
<TABLE>
<CAPTION>
Wholesale Retail
--------------------------------- -------
PG&E GT Parent
---------------- & Elimi-
Utility PG&E Gen NW Texas PG&E ET PG&E ES nations(1) Total
------- ------- ------- ------- ------- ------- ------- -------
(in millions)
For the three-month period ended:
- ---------------------------------
June 30, 1999
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Operating revenues $ 2,233 $ 254 $ 52 $ 436 $2,024 $ 142 $ (321) $ 4,820
Operating expenses 1,781 247 23 444 2,024 165 (318) 4,366
Operating income 454
Other income, net 39
Interest expense, net 192
Income taxes 121
Net income 180
EBITDA (2) 954 42 40 12 2 (21) (6) 1,023
June 30, 1998
Operating revenues $ 2,117 $ 115 $ 58 $ 522 $2,060 $ 92 $ (177) $ 4,787
Operating expenses 1,623 55 23 532 2,058 114 (175) 4,230
Operating income 557
Other income, net (8)
Interest expense, net 196
Income taxes 179
Net income 174
EBITDA (2) 867 63 45 5 4 (21) (21) 942
For the six-month period ended:
- ----------------------------------------------
June 30, 1999
Operating revenues $ 4,318 $ 543 $ 110 $ 793 $4,655 $ 277 $ (619) $10,077
Operating expenses 3,444 494 50 827 4,660 315 (609) 9,181
Operating income 896
Other income, net 60
Interest expense, net 393
Income taxes 227
Net income 336
EBITDA (2) 1,749 108 81 5 (1) (33) (13) 1,896
June 30, 1998
Operating revenues $ 4,143 $ 199 $ 119 $1,037 $3,837 $ 135 $ (330) $ 9,140
Operating expenses 3,225 121 48 1,045 3,835 174 (329) 8,119
Operating income 1,021
Other income, net 7
Interest expense, net 393
Income taxes 322
Net income 313
EBITDA (2) 1,505 86 94 18 4 (37) (17) 1,653
<FN>
(1) Net income on intercompany positions recognized by segments using mark to market accounting
is eliminated. Intercompany transactions are also eliminated.
(2) EBITDA measures earnings (after preferred dividends) before interest expense (net of
interest income), income taxes, depreciation and amortization.
</TABLE>
<PAGE>
Overall Results:
- ----------------
Net income increased $6 million for the three-month period ended June 30,
1999, as compared to the same period in 1998 primarily because in the second
quarter of 1998, the Corporation recognized a $.06 per share charge related to
the disposition of its investment in its Australian holdings resulting from
the 22 percent currency devaluation of the Australian dollar against the U.S.
dollar. In addition, 1999 results continue to reflect a decrease in the
effective income tax rate resulting from the expansion of business activities
outside of California. These increases in net income were partially offset by
a reduction in Utility net income due to the disposition of its generating
assets in 1998 and 1999, the cost of capital decision discussed above, and a
decrease in PG&E Gen's income resulting from a decrease in portfolio
management activity compared to 1998 levels.
Net income for the six-month period ended June 30, 1999, was $336 million
compared to $313 million for the same period in 1998. This increase was
attributable to the fact that, in 1998, the Corporation recognized a non-
recurring charge related to the disposition of its Australian holdings
discussed above. Utility earnings were less in 1999 than the comparable
period in 1998 as result of the disposition of its generating facilities,
discussed below, and a lower authorized cost of capital on its distribution
business.
Operating Revenues:
- -------------------
Utility:
Utility operating revenues increased by $116 million for the three-month
period ended June 30, 1999, as compared to the same period in 1998. Most of
the increase is attributed to a $43 million increase in revenues from
residential and small commercial electric customers reflecting customer
growth. In addition, 1998 revenues were $30 million less than 1999 revenues
due to abnormally high rainfall, which reduced demand for irrigation water
pumping in the second quarter of 1998.
Utility operating revenues increased by $175 million for the six-month
period ended June 30, 1999, as compared to the same period in 1998. This
increase is primarily due to: (1) a $79 million increase in revenues from
residential and small commercial electric customers reflecting customer
growth, (2) a $110 million increase in gas residential sales reflecting cooler
temperatures, particularly during the first three months of 1999, and (3) a
$30 million increase in commercial and agricultural electric sales, discussed
above. Partially offsetting these increases is $54 million of lower sales to
medium and large electric customers leaving for direct access.
Wholesale Business Operations:
Operating revenues associated with wholesale business operations increased by
$11 million for the three-month period ended June 30, 1999, as compared to the
same period in 1998. The increase principally relates to increased revenues
from PG&E Gen's acquisition of a portfolio of electric generating assets and
power supply contracts from NEES in the third quarter of 1998. This increase
was partially offset by a decline in the proportion of natural gas volumes
shipped for resale at PG&E GTT, lower interruptible sales at PG&E GT NW, and
lower gas commodity trading at PG&E ET.
<PAGE>
Operating revenues associated with wholesale business operations increased
$909 million for the six-month period ended June 30, 1999, as compared to the
same period in 1998. This increase was a result of increased gas and electric
commodity trading at PG&E ET and PG&E Gen's acquisition of a portfolio of
electric generating assets and power supply contracts from NEES in the third
quarter of 1998. These increases were partially offset by a decline in
operating revenues resulting from declines in proportion of natural gas
volumes shipped for resale at PG&E GTT and lower interruptable sales at PG&E
GT NW.
Retail Business Operations:
Operating revenues associated with the retail business operations increased
$50 million and $142 million for the three- and six-month periods ended June
30, 1999, as compared to the same period in 1998. These increases were
primarily due to sales of electricity in California.
Operating Expenses:
- -------------------
Utility:
Utility operating expenses increased $158 million and $219 million for the
three- and six-month periods ended June 30, 1999, respectively, as compared to
the same periods in 1998 as a result of higher purchased gas volumes from the
increase in residential gas sales due to cooler weather in the first quarter,
ISO Grid Management charges in the current year, and increased recovery of
stranded costs (transition costs). Partially offsetting this increase is
decreased fuel, depreciation, and environmental costs due to plant sales.
Wholesale Business Operations:
Operating expenses for the wholesale business increased $70 million for the
three-month period ended June 30, 1999, as compared to the same period in
1998. This increase reflects increased operating costs at PG&E Gen resulting
from the acquisition of the New England assets discussed above. The increase
was partially offset by a decline in the volumes of gas commodities purchased
at PG&E ET and decreased operating expenses at PG&E GTT, resulting from a
decline in gas purchased for resale.
Operating expenses for the wholesale business operations increased $982
million for the six-month period ended June 30, 1999, as compared to the same
period in 1998. This increase reflects increased volumes of energy
commodities purchased at PG&E ET and operating costs associated with the New
England assets at PG&E Gen. These increases were partially offset by
decreased operating expenses at PG&E GTT. The year to date operating expenses
include approximately $6 million of restructuring and severance costs at the
Gas Transmission business unit.
Retail Business Operations:
Operating expenses for our retail business operations increased $51 million
and $141 million for the three- and six-month periods ended June 30, 1999,
respectively, as compared to the same periods in 1998. This increase is due
to the increased electric commodity sales of our energy services business.
Income Taxes:
- -------------
Income taxes decreased $58 million and $95 million for the three- and six-
month periods ended June 30, 1999, as compared to the same periods in 1998,
<PAGE>
due to a lower effective state income tax rate resulting from our expanded
business operations outside of California.
EBITDA:
- -------
Utility:
EBITDA increased $87 million and $244 million for the three- and six-month
periods ended June 30, 1999, respectively, as compared to the same periods in
1998. This increase is generally due to an increase in operating revenues as
discussed above, partially offset by an increase in operating expenses
resulting from higher purchased gas volumes for increased residential gas
sales in the first quarter; and ISO grid management charges in the current
year.
Wholesale:
EBITDA decreased $21 million for the three-month period ended June 30, 1999,
as compared to the same period in 1998. This decrease is a result of lower
interruptable sales at PG&E GT NW and reduced portfolio management activity at
PG&E Gen, partially offset by an increase in natural gas liquids sales margins
at PG&E GTT.
For the six-month period ended June 30, 1999, EBITDA decreased by $9
million as compared to the same period in 1998. This decrease is due to a
decline in operating revenues resulting from declines in the proportion of
natural gas volumes shipped for resale at PG&E GTT and lower interruptable
sales at PG&E GT NW. The decrease in EBITDA is partially offset by higher
revenues resulting from PG&E Gen's acquisition of a portfolio of electric
generating assets and power supply contracts from NEES in the third quarter of
1998.
Stock Dividend:
- ---------------
We base our common stock dividend on a number of financial considerations,
including sustainability, financial flexibility, and competitiveness with
investment opportunities of similar risk. Our current quarterly common stock
dividend is $.30 per common share, which corresponds to an annualized
dividend of $1.20 per common share. We continually review the level of our
common stock dividend taking into consideration the impact of the changing
regulatory environment throughout the nation, the resolution of asset
dispositions, the operating performance of our business units, and our
capital and financial resources in general.
The CPUC requires the Utility to maintain its CPUC-authorized capital
structure, potentially limiting the amount of dividends the Utility may pay
PG&E Corporation. During 1999, the Utility has been in compliance with its
CPUC-authorized capital structure. PG&E Corporation and the Utility believe
that this requirement will not affect PG&E Corporation's ability to pay
common stock dividends. However, depending on the outcome of the legislative
and regulatory process surrounding the valuation and divestiture of the
Utility's hydroelectric facilities discussed in "Generation Divestiture"
above, certain valuation or disposition methodologies, other than a sale of
the facilities to a third party, could necessitate a waiver of the CPUC's
authorized capital structure in order to permit PG&E Corporation or the
Utility to continue paying common stock dividends at the current level.
<PAGE>
Liquidity and Financial Resources
Cash Flows from Operating Activities:
Net cash provided by PG&E Corporation's operating activities totaled $1,637
million and $1,250 million during the six-month period ended June 30, 1999
and 1998, respectively. Net cash provided by the Utility's operating
activities totaled $1,568 million and $1,182 million during the six-month
period ended June 30, 1999 and 1998, respectively.
Cash Flows from Financing Activities:
PG&E Corporation:
We fund investing activities from cash provided by operations after capital
requirements and, to the extent necessary, external financing. Our policy is
to finance our investments with a capital structure that minimizes financing
costs, maintains financial flexibility, and, with regard to the Utility,
complies with regulatory guidelines. Based on cash provided from operations
and our investing and disposition activities, we may repurchase equity and
long-term debt in order to manage the overall size and balance of our capital
structure.
During the six-month period ended June 30, 1999 and 1998, we issued $32
million and $33 million of common stock, respectively, primarily through the
Dividend Reinvestment Plan and the stock option plan component of the Long-
Term Incentive Program. During the six-month period ended June 30, 1999 and
1998, we declared dividends on our common stock of $220 million and $229
million, respectively.
During the six-month period ended June 30, 1999 and 1998, we repurchased
$503 million and $1,123 million of our common stock, respectively. These
repurchases were executed through accelerated share repurchase programs.
Under the most recent agreement, PG&E Corporation purchased 16.6 million
shares of its common stock. PG&E Corporation retains the risk of increases
and the benefit of decreases in the price of the common shares purchased by
the counterparty. The counterparty may make purchases on the open market or
through privately negotiated transactions until the counterparty has replaced
the shares sold to PG&E Corporation. PG&E Corporation may elect to settle
its obligations under such arrangement with either cash or shares of its
common stock. For the three- and six-month periods ended June 30, 1999, this
agreement caused the $0.03 and $0.08 dilution, respectively, reflected in
PG&E Corporation's diluted earnings per share. This dilution will be
eliminated when the associated forward contract is settled.
We maintain a number of credit facilities throughout our organization to
support commercial paper programs, letters of credit, and other short term
liquidity requirements. At PG&E Corporation, we maintain two $500 million
revolving credit facilities, one of which expires in November 1999 and the
other in 2002. The PG&E Corporation credit facilities are used to support
the commercial paper program and other liquidity needs. The facility
expiring in 1999 may be extended annually for additional one-year periods
upon agreement between the lending institutions and us. There was $516
million of commercial paper outstanding at June 30, 1999.
PG&E Gen maintains two credit facilities of $550 million each. One
agreement expires in August 1999 and the other in 2003. The total amount
outstanding at June 30, 1999, backed by the facilities, was $858 million in
commercial paper. Of these loans, $550 million is classified as noncurrent
in the consolidated balance sheet.
<PAGE>
At June 30, 1999, PG&E GTT had $54 million of outstanding short-term bank
borrowings related to three separate credit facilities. These lines may be
cancelled upon demand and bear interest at each respective bank's quoted
money market rate. The borrowings are unsecured and unrestricted as to use.
On June 30, 1999, PG&E GTT redeemed $69 million of its senior notes,
resulting in a gain on redemption of approximately $1.7 million.
PG&E GT NW maintains a $100 million revolving credit facility which
expires in the year 2002, but has a one-year renewal option. PG&E GT NW also
maintains a $50 million 364-day credit facility which expires in the year
2000, but can be extended for successive 364-day periods. No amounts were
outstanding under either of these credit facilities at June 30, 1999. At
June 30, 1999, PG&E GT NW had an outstanding commercial paper balance of $97
million, which is classified as noncurrent.
Utility:
During the six-month period ended June 30, 1999, the Utility repurchased 20
million shares of its common stock from PG&E Corporation for an aggregate
purchase price of $725 million to maintain its authorized capital structure.
During the six-month period ended June 30, 1999 and 1998, the Utility
declared dividends on its common stock of $195 million and $100 million.
The Utility's long-term debt that either matured, was redeemed, or was
repurchased during the six-month period ended June 30, 1999 totaled $348
million. Of this amount, (1) $148 million related to the Utility's rate
reduction bonds maturing; (2) $109 million related to the Utility's
repurchase of various mortgage bonds; (3) $67 million related to the
Utility's maturity of the Utility's 5.5 percent mortgage bonds; and (4) $24
million related to the maturities and redemption of various of the Utility's
medium term notes.
The Utility maintains a $1 billion revolving credit facility, which
expires in 2002. The Utility may extend the facility annually for additional
one-year periods upon agreement with the banks. This facility is used to
support the Utility's commercial paper program and other liquidity
requirements. The Utility did not have any outstanding debt related to this
credit facility at June 30, 1999. Additionally, no commercial paper or bank
notes were outstanding at June 30, 1999.
Cash Flows from Investing Activities:
The primary uses of cash for investing activities are additions to property,
plant, and equipment; unregulated investments in partnerships; and
acquisitions.
The Utility's GRC application contained estimates of capital spending for
1999 in the amount of $1.6 billion, excluding capital expenditures for
divested fossil and geothermal power plants. These estimates were reflected
in the amount of base revenues requested by the Utility in its GRC filing.
If the CPUC ultimately authorizes base revenues that are significantly lower
than those requested by the Utility, the Utility's level of prospective
capital expenditures will be reduced and actual expenditures could differ
materially.
The Utility has sold its remaining fossil generation facilities and its
geothermal generation facilities. These sales closed in April and May 1999.
The sales generated proceeds of $1,014 million.
<PAGE>
Environmental Matters:
We are subject to laws and regulations established to both maintain and
improve the quality of the environment. Where our properties contain
hazardous substances, these laws and regulations require us to remove those
substances or remedy effects on the environment.
At June 30, 1999, the Utility expects to spend $294 million over the next
30 years for cleanup costs at identified sites. If other responsible parties
fail to pay or expected outcomes change, then these costs may be as much as
$482 million. Of the $294 million, the Utility has recovered $136 million
(including remediation of generation plants divested, discussed above) and
expects to recover another $129 million in future rates. The Utility
mitigates its cost by seeking recovery from insurance carriers and other
third parties.
The cost of the hazardous substance remediation ultimately undertaken by
the Utility is difficult to estimate. A change in the estimate may occur in
the near term due to uncertainty concerning the Utility's responsibility, the
complexity of environmental laws and regulations, and the selection of
compliance alternatives. The Utility estimated costs using assumptions least
favorable to the Utility, based upon a range of reasonably possible outcomes.
Costs may be higher if the Utility is found to be responsible for cleanup
costs at additional sites or expected outcomes change.
Year 2000:
The Year 2000 issue exists because many computer programs use only two digits
to refer to a year, and were developed without considering the impact of the
upcoming change in the century. If PG&E Corporation's mission-critical
computer systems fail or function incorrectly due to not being made Year 2000
ready, they could directly and adversely affect our ability to generate or
deliver our products and services or could otherwise affect revenues, safety,
or reliability for such a period of time as to lead to unrecoverable
consequences.
Our plan to address the Year 2000 issues focuses primarily on mission-
critical systems whose components are categorized as in-house software,
vendor software, embedded systems, and computer hardware.
The four primary phases of our plan to address these systems are inventory
and assessment, remediation, testing, and certification. Certification
occurs when mission-critical systems are formally determined to be Year 2000
ready. "Year 2000 ready" means that a system is suitable for continued use
into the year 2000. Once Year 2000 ready, additional standards and processes
are imposed to prevent systems from being compromised.
Our Year 2000 project is generally proceeding on schedule. The following
table indicates our Year 2000 progress as of July 26, 1999.
Year 2000 Readiness of Mission-Critical Items
Remediation Testing Certification
Completed Completed Completed
- ----------------------------------------------------------------------
In-house software 100% 99% 99%
Vendor software 100% 100% 100%
Embedded systems 100% 100% 81%
Computer hardware 100% 100% 100%
<PAGE>
The percentages above reflect approximations based on a uniform reporting
system that combines subsidiary results to provide a consistent, corporate-
wide view and are derived using standard rounding conventions. Even where
100% is reported, there may be remaining items. Moreover, changes in
inventories, or issues uncovered in subsequent phases for an item previously
reported as completed, may lead to downward adjustments in percentages from
period to period. Even after systems are certified, we are continuing
various kinds of validation and quality assurance efforts, and may do so into
the year 2000.
The Utility routinely reports Year 2000 progress to the CPUC, North
American Electric Reliability Council (NERC), and the Nuclear Regulatory
Commission (NRC). The Utility has notified NERC and the NRC that it is Year
2000 ready, with limited exceptions.
In addition to internal systems, we also depend upon external parties,
including customers, suppliers, business partners, gas and electric system
operators, government agencies, and financial institutions to support the
functioning of our business. To the extent that any of these parties are
considered mission-critical to our business and experience Year 2000 problems
in their systems, our mission-critical business functions may be adversely
affected. To deal with this vulnerability, we have a four phased approach
for dealing with external parties: (1) inventory, (2) action planning, (3)
risk assessment, and (4) contingency planning. The contingency planning
process also addresses exposures that could result from failures in our own
essential business systems. Contingency plans will be revised throughout
1999 as necessary.
The Utility's contingency plans are being incorporated into its emergency
plans and may include measures such as emergency back-up and recovery
procedures, augmenting automated applications with manual processes, and
identification of alternate suppliers. Electric transmission and generation
plans are coordinated with those of the ISO and PX and are consistent with
Western Systems Coordinating Council and NERC recommendations and NRC
guidelines. The plans will be tested in Utility and electric-industry drills
in which the Utility participates throughout 1999, and updated as necessary.
As of June 30, 1999, we estimate total costs to address Year 2000 problems
to be $223 million, of which $97 million is attributed to the Utility.
Included are systems replaced or enhanced for general business purposes and
whose implementation schedules are critical to our Year 2000 readiness.
Through June 1999, we spent approximately $166 million, of which $91
million was capitalized. The remaining $75 million was expensed. Future
costs, including contingency funds, to address Year 2000 issues are expected
to be $57 million, of which $23 million will be capitalized. The remaining
$34 million will be expensed.
Based on our current schedule for the completion of Year 2000 tasks, we
expect to secure Year 2000 readiness of our mission-critical systems by the
end of the third quarter of 1999. However, as our current schedule is
partially dependent on the efforts of third parties, their delays and other
factors we are not able to predict, may cause our schedule to change.
Although we expect our efforts and those of our external parties to be
successful, given the complex interaction of today's computing and
communications systems, we cannot be certain we will be completely
successful. Accordingly, we have considered the most reasonably likely worst
case Year 2000 scenarios that could affect us or the Utility, and we believe
that they mainly involve public overreaction before and during the New Year
period that could create localized telephone problems due to congestion,
<PAGE>
temporary gasoline shortages, and curtailment of natural gas usage by
customers. In addition, it is reasonably likely that there will be minor
technical failures such as localized telephone outages and small isolated
malfunctions in our computer systems that will be immediately repaired. None
of these reasonably likely scenarios are expected to have a material adverse
impact on the Utility's or our financial position, results of operations, or
cash flows. Nevertheless, if we, or third parties with which we have
significant business relationships, fail to achieve and sustain Year 2000
readiness of mission-critical systems, there could be a material adverse
impact on the Utility and our financial position, results of operations, and
cash flows.
Price Risk Management Activities:
PG&E Corporation's daily value-at-risk for commodity price sensitive
derivative instruments as of June 30, 1999, is $4.8 million for trading
activities and $0.7 million for non-trading activities.
In November 1998, the Emerging Issues Task Force of the Financial
Accounting Standards Board released Issue 98-10, Accounting for Energy
Trading and Risk Management Activities. This Issue states that all energy-
related contracts entered into with the objective of generating profits on or
from exposure to shifts or changes in market prices be marked to market with
the gains and losses reflected in the income statement. The Task Force
stipulates implementation for fiscal years beginning after December 15, 1998.
PG&E Corporation adopted this standard on January 1, 1999. The effect of
adoption on earnings and the financial position of PG&E Corporation was
immaterial.
On July 8, 1999, the CPUC authorized the Utility to recover the costs of
participating in the California Power Exchange block forward market.
Legal Matters:
In the normal course of business, both the Utility and PG&E Corporation are
named as parties in a number of claims and lawsuits. (See Note 6 of Notes to
Consolidated Financial Statements for further discussion of significant
pending legal matters.
<PAGE>
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
PG&E Corporation's and Pacific Gas and Electric Company's primary market risk
results from changes in energy prices and interest rates. We engage in price
risk management activities for both non-hedging and hedging purposes.
Additionally, we may engage in hedging activities using futures, options, and
swaps to hedge the impact of market fluctuations on energy commodity prices,
interest rates, and foreign currencies. (See Risk Management Activities,
above.)
<PAGE>
PART II. OTHER INFORMATION
Item 5. Other Information
-----------------
A. Ratio of Earnings to Fixed Charges and Ratio of Earnings to
Combined Fixed Charges and Preferred Stock Dividends
Pacific Gas and Electric Company's earnings to fixed charges
ratio for the six months ended June 30, 1999 was 2.84.
Pacific Gas and Electric Company's earnings to combined
fixed charges and preferred stock dividends ratio for the
six months ended June 30, 1999 was 2.70. The statement of
the foregoing ratios, together with the statements of the
computation of the foregoing ratios filed as Exhibits 12.1
and 12.2 hereto, are included herein for the purpose of
incorporating such information and exhibits into
Registration Statement Nos. 33-62488, 33-64136, 33-50707 and
33-61959, relating to Pacific Gas and Electric Company's
various classes of debt and first preferred stock
outstanding.
Item 6. Exhibits and Reports on Form 8-K
--------------------------------
(a) Exhibits:
Exhibit 11 Computation of Earnings Per Common Share
Exhibit 12.1 Computation of Ratios of Earnings to Fixed
Charges for Pacific Gas and Electric Company
Exhibit 12.2 Computation of Ratios of Earnings to Combined
Fixed Charges and Preferred Stock Dividends for
Pacific Gas and Electric Company
Exhibit 27.1 Financial Data Schedule for the six months ended
June 30, 1999 for PG&E Corporation
Exhibit 27.2 Financial Data Schedule for the six months ended
June 30, 1999 for Pacific Gas and Electric
Company
(b) The following Current Reports on Form 8-K were filed
during the second quarter of 1999 and through the date
hereof (1):
1. March 24, 1999
Item 5. Other Events
Proposed decision in Pacific Gas and Electric
Company's Cost of Capital Proceeding
2. April 15, 1999
Item 5. Other Events
Announcement of postponement of scheduled release
of first quarter earnings.
3. June 10, 1999
Item 5. Other Events
Final decision in Pacific Gas and Electric
Company's Cost of Capital Proceeding
<PAGE>
4. June 11, 1999 - Form 8-K/A to Form 8-K dated February 17, 1999
Item 4. Changes in Registrant's Certifying Accountants.
Item 7. Financial Statements, Pro Forma Financial Information,
and Exhibits
(1) Unless otherwise noted, all Current Reports on Form 8-K
were filed under both Commission File Number 1-12609 (PG&E Corporation)
and Commission File Number 1-2348(Pacific Gas and Electric Company)
<PAGE>
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act
of 1934, the registrants have duly caused this report to be
signed on their behalf by the undersigned thereunto duly
authorized.
PG&E CORPORATION
and
PACIFIC GAS AND ELECTRIC COMPANY
CHRISTOPHER P. JOHNS
August 4, 1999 By ________________________
CHRISTOPHER P. JOHNS
Vice President and Controller
(PG&E Corporation)
Vice President and Controller
(Pacific Gas and Electric Company)
<PAGE>
Exhibit Index
Exhibit No. Description of Exhibit
11 Computation of Earnings Per Common Share
12.1 Computation of Ratio of Earnings to Fixed Charges for
Pacific Gas and Electric Company
12.2 Computation of Ratio of Earnings to Combined Fixed
Charges and Preferred Stock Dividends for Pacific
Gas and Electric Company
27.1 Financial Data Schedule for the six months ended
June 30, 1999 for PG&E Corporation
27.2 Financial Data Schedule for the six months ended
June 30, 1999 for Pacific Gas and Electric
Company
<PAGE>
<TABLE>
EXHIBIT 11
PG&E CORPORATION
COMPUTATION OF EARNINGS PER COMMON SHARE
<CAPTION>
- ----------------------------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,
-------------------- ------------------------
(in millions, except per share amounts) 1999 1998 1999 1998
- ----------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
BASIC EARNINGS PER SHARE (EPS)1
Earnings available for common stock $ 180 $ 174 $ 336 $ 313
========== ========== ========== ==========
Average common shares outstanding 367 382 370 382
========== ========== ========== ==========
Basic EPS $ 0.49 $ 0.46 $ 0.91 $ 0.82
========== ========== ========== ==========
DILUTED EARNINGS PER SHARE (EPS)1
Earnings available for common stock $ 180 $ 174 $ 336 $ 313
Less: assumed cash settlement of forward
contract that may be settled in Company
stock or cash 10 - 29 -
---------- ---------- ---------- ----------
Earnings available for common stock as
adjusted 170 174 307 313
========== ========== ========== ==========
Average common shares outstanding 367 382 370 382
Add: outstanding options, reduced by the
number of shares that could be
repurchased with the proceeds from
such exercise (at average market price) 2 1 1 1
---------- ---------- ---------- ----------
Average common shares outstanding as
adjusted 369 383 371 383
========== ========== ========== ==========
Diluted EPS $ 0.46 $ 0.46 $ 0.83 $ 0.82
========== ========== ========== ==========
- ----------------------------------------------------------------------------------------------
<FN>
1 This presentation is submitted in accordance with Item 601(b)(11) of Regulation S-K and Statement
of Financial Accounting Standards No. 128.
</TABLE>
<PAGE>
<TABLE>
EXHIBIT 12.1
PACIFIC GAS AND ELECTRIC COMPANY
COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
<CAPTION>
- ---------------------------------------------------------------------------------------------------
Six Months Year ended December 31,
ended -------------------------------------------------------
(dollars in millions) June 30, 1999 1998 1997 1996 1995 1994
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Earnings:
Net income $ 331 $ 729 $ 768 $ 755 $ 1,339 $1,007
Adjustments for minority
interests in losses of
less than 100% owned
affiliates and the
Company's equity in
undistributed losses
(income) of less than
50% owned affiliates - - - 3 4 (3)
Income tax expense 263 629 609 555 895 837
Net fixed charges 322 673 628 683 716 729
-------- -------- -------- -------- -------- --------
Total Earnings $ 916 $ 2,031 $ 2,005 $ 1,996 $ 2,954 $ 2,570
======== ======== ======== ======== ======== ========
Fixed Charges:
Interest on long-
term debt, net $ 265 $ 585 $ 485 $ 574 $ 616 $ 639
Interest on short-
term borrowings 41 50 101 75 83 77
Interest on capital leases - 2 2 3 3 2
Capitalized Interest - - 1 1 - 2
AFUDC Debt 4 12 16 7 11 11
Earnings required to
cover the preferred stock
dividend and preferred
security distribution
requirements of majority
owned trust 12 24 24 24 3 -
-------- -------- -------- -------- -------- --------
Total Fixed Charges $ 322 $ 673 $ 629 $ 684 $ 716 $ 731
======== ======== ======== ======== ======== ========
Ratios of Earnings to
Fixed Charges 2.84 3.02 3.19 2.92 4.13 3.52
- ----------------------------------------------------------------------------------------------------
<FN>
Note: For the purpose of computing Pacific Gas and Electric Company's ratios of earnings to
fixed charges, "earnings" represent net income adjusted for the minority interest in
losses of less than 100% owned affiliates, cash distributions from and equity in
undistributed income or loss of Pacific Gas and Electric Company's less than 50% owned
affiliates, income taxes and fixed charges (excluding capitalized interest). "Fixed
charges" include interest on long-term debt and short-term borrowings (including a
representative portion of rental expense), amortization of bond premium, discount and
expense, interest of subordinated debentures held by trust, interest on capital leases, and
earnings required to cover the preferred stock dividend requirements.
</TABLE>
<PAGE>
<TABLE>
EXHIBIT 12.2
PACIFIC GAS AND ELECTRIC COMPANY
COMPUTATION OF RATIOS OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
<CAPTION>
- ----------------------------------------------------------------------------------------------------
Six months Year ended December 31,
ended -------------------------------------------------------
(dollars in millions) June 30, 1999 1998 1997 1996 1995 1994
- ----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Earnings:
Net income $ 331 $ 729 $ 768 $ 755 $ 1,339 $ 1,007
Adjustments for minority
interests in losses of
less than 100% owned
affiliates and the
Company's equity in
undistributed losses
(income) of less than
50% owned affiliates - - - 3 4 (3)
Income tax expense 263 629 609 555 895 837
Net fixed charges 322 673 628 683 716 729
-------- -------- -------- -------- -------- --------
Total Earnings $ 916 $ 2,031 $ 2,005 $ 1,996 $ 2,954 $ 2,570
======== ======== ======== ======== ======== ========
Fixed Charges:
Interest on long-
term debt, net $ 265 $ 585 $ 485 $ 574 $ 616 $ 639
Interest on short-
term borrowings 41 50 101 75 83 77
Interest on capital leases - 2 2 3 3 2
Capitalized Interest - - 1 1 - 2
AFUDC Debt 4 12 16 7 11 11
Earnings required to
cover the preferred stock
dividend and preferred
security distribution
requirements of majority
owned trust 12 24 24 24 3 -
-------- -------- -------- -------- -------- --------
Total Fixed Charges $ 322 $ 673 $ 629 $ 684 $ 716 $ 731
-------- -------- -------- -------- -------- --------
Preferred Stock Dividends:
Tax deductible dividends $ 4 $ 9 $ 10 $ 10 $ 11 $ 5
Pretax earnings required
to cover non-tax
deductible preferred
stock dividend
requirements 14 31 39 39 100 96
-------- -------- -------- -------- -------- --------
Total Preferred
Stock Dividends $ 18 $ 40 $ 49 $ 49 $ 111 $ 101
-------- -------- -------- -------- -------- --------
Total Combined Fixed
Charges and Preferred
Stock Dividends $ 340 $ 713 $ 678 $ 733 $ 827 $ 832
======== ======== ======== ======== ======== ========
Ratios of Earnings to
Combined Fixed Charges and
Preferred Stock Dividends 2.70 2.85 2.96 2.72 3.57 3.09
- ---------------------------------------------------------------------------------------------------
<FN>
Note: For the purpose of computing Pacific Gas and Electric Company's ratios of earnings to
combined fixed charges and preferred stock dividends, "earnings" represent net income
adjusted for the minority interest in losses of less than 100% owned affiliates, cash
distributions from and equity in undistributed income or loss of Pacific
Gas and Electric Company's less than 50% owned affiliates, income taxes and fixed charges
(excluding capitalized interest). "Fixed charges" include interest on long-term debt and
short-term borrowings (including a representative portion of rental expense), amortization
of bond premium, discount and expense, interest on capital leases, interest of subordinated
debentures held by trust, and earnings required to cover the preferred stock dividend
requirements of majority owned subsidiaries. "Preferred stock dividends" represent pretax
earnings which would be required to cover such dividend requirements.
</TABLE>
<PAGE>
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PG&E
CORPORATION AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL
STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> JUN-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 17,476
<OTHER-PROPERTY-AND-INVEST> 1,775
<TOTAL-CURRENT-ASSETS> 3,947
<TOTAL-DEFERRED-CHARGES> 3,072
<OTHER-ASSETS> 5,156
<TOTAL-ASSETS> 31,426
<COMMON> 5,391
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 2,324
<TOTAL-COMMON-STOCKHOLDERS-EQ> 7,715
780
0
<LONG-TERM-DEBT-NET> 6,798
<SHORT-TERM-NOTES> 877
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 97
<LONG-TERM-DEBT-CURRENT-PORT> 549
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 14,610
<TOT-CAPITALIZATION-AND-LIAB> 31,426
<GROSS-OPERATING-REVENUE> 10,077
<INCOME-TAX-EXPENSE> 227
<OTHER-OPERATING-EXPENSES> 9,181
<TOTAL-OPERATING-EXPENSES> 9,181
<OPERATING-INCOME-LOSS> 896
<OTHER-INCOME-NET> 60
<INCOME-BEFORE-INTEREST-EXPEN> 956
<TOTAL-INTEREST-EXPENSE> 393
<NET-INCOME> 336
0
<EARNINGS-AVAILABLE-FOR-COMM> 336
<COMMON-STOCK-DIVIDENDS> 220
<TOTAL-INTEREST-ON-BONDS> 170
<CASH-FLOW-OPERATIONS> 1,637
<EPS-BASIC> 0.91
<EPS-DILUTED> 0.83
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PACIFIC GAS
AND ELECTRIC COMPANY AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH
FINANCIAL STATEMENTS.
</LEGEND>
<SUBSIDIARY>
<NUMBER> 01
<NAME> PACIFIC GAS AND ELECTRIC COMPANY
<MULTIPLIER> 1,000,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> JUN-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 12,554
<OTHER-PROPERTY-AND-INVEST> 0
<TOTAL-CURRENT-ASSETS> 1,790
<TOTAL-DEFERRED-CHARGES> 2,932
<OTHER-ASSETS> 4,444
<TOTAL-ASSETS> 21,720
<COMMON> 1,607
<CAPITAL-SURPLUS-PAID-IN> 1,971
<RETAINED-EARNINGS> 1,882
<TOTAL-COMMON-STOCKHOLDERS-EQ> 5,460
437
287
<LONG-TERM-DEBT-NET> 5,051
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 453
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 10,032
<TOT-CAPITALIZATION-AND-LIAB> 21,720
<GROSS-OPERATING-REVENUE> 4,318
<INCOME-TAX-EXPENSE> 263
<OTHER-OPERATING-EXPENSES> 3,444
<TOTAL-OPERATING-EXPENSES> 3,444
<OPERATING-INCOME-LOSS> 874
<OTHER-INCOME-NET> 22
<INCOME-BEFORE-INTEREST-EXPEN> 896
<TOTAL-INTEREST-EXPENSE> 302
<NET-INCOME> 331
12
<EARNINGS-AVAILABLE-FOR-COMM> 319
<COMMON-STOCK-DIVIDENDS> 195
<TOTAL-INTEREST-ON-BONDS> 170
<CASH-FLOW-OPERATIONS> 1,568
<EPS-BASIC> 0.00
<EPS-DILUTED> 0.00
</TABLE>
