FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
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(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
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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
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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
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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 May 7, 1999:
PG&E Corporation 383,567,880 shares
Pacific Gas and Electric Company Wholly owned by PG&E Corporation
PG&E CORPORATION
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 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..14
NOTE 4: ACQUISITIONS AND SALES...........................15
NOTE 5: UTILITY OBLIGATED MANDATORILY REDEEMABLE
PREFERRED SECURITIES OF TRUST HOLDING
SOLELY UTILITY SUBORDINATED DEBENTURES...........16
NOTE 6: COMMITMENTS AND CONTINGENCIES....................16
NOTE 7: SEGMENT INFORMATION..............................19
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS. ....................21
COMPETITIVE AND REGULATORY ENVIRONMENT....................22
The Competitive Environment in the Evolving
Energy Industry........................................22
California Transition Plan.............................23
New England Electricity Market.........................28
Regulatory Matters.....................................29
RESULTS OF OPERATIONS.....................................32
LIQUIDITY AND FINANCIAL RESOURCES.........................35
ENVIRONMENTAL MATTERS.....................................37
YEAR 2000.................................................37
PRICE RISK MANAGEMENT ACTIVITIES..........................39
LEGAL MATTERS.............................................39
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK.........................................40
PART II. OTHER INFORMATION
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.......41
ITEM 5. OTHER INFORMATION.........................................44
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K..........................44
SIGNATURE..........................................................46
PART I. FINANCIAL INFORMATION
ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS
PG&E CORPORATION
STATEMENT OF CONSOLIDATED INCOME
(in millions, except per share amounts)
Three months ended March 31,
1999 1998
--------- ---------
Operating Revenues
Utility $ 2,085 $ 2,025
Energy commodities and services 3,172 2,328
-------- --------
Total operating revenues 5,257 4,353
Operating Expenses
Cost of energy for utility 655 682
Cost of energy commodities and services 2,921 2,156
Operating and maintenance, net 798 799
Depreciation, amortization and decommissioning 441 253
-------- --------
Total operating expenses 4,815 3,890
-------- --------
Operating Income 442 463
Interest expense, net 201 197
Other income, net 21 14
-------- --------
Income Before Income Taxes 262 280
Income taxes 106 141
-------- --------
Net Income $ 156 $ 139
======== ========
Weighted Average Common Shares
Outstanding 373 381
Earnings Per Common Share, Basic $ .42 $ .36
Earnings Per Common Share, Diluted $ .37 $ .36
Dividends Declared Per Common Share $ .30 $ .30
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
PG&E CORPORATION
CONSOLIDATED BALANCE SHEET (in millions)
Balance at March 31, December 31,
1999 1998
------------ ------------
ASSETS
Current Assets
Cash and cash equivalents $ 245 $ 286
Short-term investments 34 55
Accounts receivable
Customers, net 1,523 1,856
Energy marketing 644 507
Price Risk Management 2,438 1,416
Inventories and prepayments 738 835
-------- --------
Total current assets 5,622 4,955
Property, Plant, and Equipment
Utility 24,282 23,996
Wholesale and retail unregulated business operations
Electric generation 1,957 1,967
Gas transmission 3,348 3,347
Construction work in progress 424 407
Other 159 127
-------- --------
Total property, plant, and equipment (at original cost) 30,170 29,844
Accumulated depreciation and decommissioning (12,307) (12,026)
-------- --------
Net property, plant, and equipment 17,863 17,818
Other Noncurrent Assets
Regulatory assets 6,106 6,347
Nuclear decommissioning funds 1,194 1,172
Other 3,323 2,942
-------- --------
Total noncurrent assets 10,623 10,461
-------- --------
TOTAL ASSETS $ 34,108 $ 33,234
======== ========
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
PG&E CORPORATION
CONSOLIDATED BALANCE SHEET (in millions)
Balance at March 31, December 31,
1999 1998
------------ ------------
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings $ 1,805 $ 1,644
Current portion of long-term debt 352 338
Current portion of rate reduction bonds 278 290
Accounts payable
Trade creditors 834 1,001
Other 598 443
Regulatory balancing accounts 291 79
Energy marketing 479 381
Accrued taxes 326 103
Price risk management 2,414 1,412
Other 910 1,064
-------- --------
Total current liabilities 8,287 6,755
Noncurrent Liabilities
Long-term debt 7,232 7,422
Rate reduction bonds 2,247 2,321
Deferred income taxes 3,694 3,861
Deferred tax credits 272 283
Other 3,969 3,746
-------- --------
Total noncurrent liabilities 17,414 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 5,379 5,862
Reinvested earnings 2,248 2,204
-------- --------
Total common stockholders' equity 7,627 8,066
Commitments and Contingencies (Notes 2 and 6) - -
-------- --------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 34,108 $ 33,234
======== ========
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
PG&E CORPORATION
STATEMENT OF CONSOLIDATED CASH FLOWS (in millions)
For the three months ended March 31, 1999 1998
---------- ----------
Cash Flows From Operating Activities
Net income $ 156 $ 139
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, amortization and decommissioning 441 253
Deferred income taxes and tax credits-net (178) (105)
Other deferred charges and noncurrent liabilities (125) 30
Net effect of changes in operating assets
and liabilities:
Accounts receivable - trade 333 19
Regulatory balancing accounts payable 212 296
Inventories and prepayments 97 78
Price risk management assets and liabilities, net (20) 5
Accounts payable - trade (167) 20
Accrued taxes 223 257
Other working capital 101 (147)
Other-net (69) 7
--------- ---------
Net cash provided by operating activities 1,004 852
--------- ---------
Cash Flows From Investing Activities
Capital expenditures (372) (506)
Acquisitions and investments in unregulated projects - (7)
Other-net 17 (3)
--------- ---------
Net cash used by investing activities (355) (516)
--------- ---------
Cash Flows From Financing Activities
Net borrowings (repayments) under credit facilities 161 32
Long-term debt issued - 158
Long-term debt matured, redeemed, or repurchased (283) (400)
Preferred stock redeemed or repurchased - (7)
Common stock issued 20 17
Common stock repurchased (503) (1,122)
Dividends paid (115) (134)
Other-net 9 (14)
--------- ---------
Net cash used by financing activities (711) (1,470)
--------- ---------
Net Change in Cash and Cash Equivalents (62) (1,134)
Cash and Cash Equivalents at January 1 341 1,397
--------- ---------
Cash and Cash Equivalents at March 31 $ 279 $ 263
========= =========
Supplemental disclosures of cash flow information
Cash paid (refunded) for:
Interest (net of amounts capitalized) $ 148 $ 141
Income taxes-net (2) 1
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED INCOME (in millions)
Three months ended March 31,
1999 1998
--------- ---------
Electric utility $ 1,533 $ 1,562
Gas utility 552 463
-------- --------
Total operating revenues 2,085 2,025
Operating Expenses
Cost of electric energy 409 474
Cost of gas 246 208
Operating and maintenance, net 626 698
Depreciation, amortization, and decommissioning 382 221
-------- --------
Total operating expenses 1,663 1,601
-------- --------
Operating Income 422 424
Interest expense, net 154 162
Other income, net 11 37
-------- --------
Income Before Income Taxes 279 299
Income taxes 126 144
-------- --------
Net Income 153 155
Preferred dividend requirement 6 7
-------- --------
Income Available for Common Stock $ 147 $ 148
======== ========
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
PACIFIC GAS AND ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET (in millions)
Balance at
March 31, December 31,
1999 1998
------------ -----------
ASSETS
Current Assets
Cash and cash equivalents $ 73 $ 73
Short-term investments 18 17
Accounts receivable
Customers, net 1,120 1,383
Related parties 13 14
Inventories
Fuel oil and nuclear fuel 180 187
Gas stored underground 102 130
Materials and supplies 163 159
Prepayments 27 50
--------- ---------
Total current assets 1,696 2,013
Property, Plant, and Equipment
Electric 17,141 16,924
Gas 7,141 7,072
Construction work in progress 246 273
--------- ---------
Total property, plant, and equipment (at original cost) 24,528 24,269
Accumulated depreciation and decommissioning (11,630) (11,397)
--------- ---------
Net property, plant, and equipment 12,898 12,872
Other Noncurrent Assets
Regulatory assets 6,050 6,288
Nuclear decommissioning funds 1,194 1,172
Other 617 605
-------- --------
Total noncurrent assets 7,861 8,065
-------- --------
TOTAL ASSETS $ 22,455 $ 22,950
======== ========
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
PACIFIC GAS AND ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET (in millions)
Balance at
March 31, December 31,
1999 1998
------------ -----------
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings $ 926 $ 668
Current portion of long-term debt 272 260
Current portion of rate reduction bonds 278 290
Accounts payable
Trade creditors 539 718
Related parties 58 60
Regulatory balancing accounts 291 79
Other 385 374
Accrued taxes 293 2
Other 484 561
-------- -------
Total current liabilities 3,526 3,012
Noncurrent Liabilities
Long-term debt 5,306 5,444
Rate reduction bonds 2,247 2,321
Deferred income taxes 2,877 3,060
Deferred tax credits 272 283
Other 2,121 2,045
-------- -------
Total noncurrent liabilities 12,823 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 1,804 2,260
-------- --------
Total stockholders' equity 5,669 6,348
Commitments and Contingencies (Notes 2 and 6) - -
-------- --------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 22,455 $ 22,950
======== ========
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED CASH FLOWS (in millions)
For the three months ended March 31, 1999 1998
----------- -----------
Cash Flows From Operating Activities
Net income $ 153 $ 155
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, amortization, and decommissioning 382 221
Deferred income taxes and tax credits-net (194) (114)
Other deferred charges and noncurrent liabilities (4) 354
Net effect of changes in operating assets
and liabilities:
Accounts receivable 263 (255)
Regulatory balancing accounts payable 212 (26)
Inventories and prepayments 54 42
Accounts payable - trade (179) 18
Accrued taxes 291 272
Other working capital 117 (61)
Other-net (2) 7
--------- ---------
Net cash provided by operating activities 1,093 613
--------- ---------
Cash Flows From Investing Activities
Capital expenditures (304) (331)
Other-net 18 (9)
--------- ---------
Net cash used by investing activities (286) (340)
--------- ---------
Cash Flows From Financing Activities
Net borrowings (repayments) under credit facilities 258 -
Long-term debt matured, redeemed, or repurchased (233) (389)
Preferred stock redeemed - (65)
Common stock repurchased (725) (800)
Dividends paid (106) (123)
Other-net - (6)
--------- ---------
Net cash used by financing activities (806) (1,383)
--------- ---------
Net Change in Cash and Cash Equivalents 1 (1,110)
Cash and Cash Equivalents at January 1 90 1,223
--------- ---------
Cash and Cash Equivalents at March 31 $ 91 $ 113
========= =========
Supplemental disclosures of cash flow information
Cash paid (refunded) for:
Interest (net of amounts capitalized) $ 91 $ 96
Income taxes-net (3) -
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
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 an electric industry restructuring plan. California electric
industry restructuring has two major components that impact the financial
statements: the competitive market framework and the California transition
plan, which are 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 to the transmission system. 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 months ended March 31, 1999, the cost of 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:
For the three-
months ended
March 31, 1999
- -----------------------------------------------------
(in millions)
Cost of fuel for electric generation $ 371
Cost of purchases from the PX 152
Net cost of ancillary services 110
Proceeds from sales to the PX (224)
------
Cost of electric energy $ 409
The Utility's cost of energy is recovered from retail customers under the
terms of the restructuring plan.
California Transition Plan:
- ---------------------------
Market-based revenues determined by the market through sales to the PX may
not be sufficient to recover (that is, to collect from customers) all of
the Utility's generation costs. To allow California investor-owned
utilities the opportunity to recover their transition costs (generation
costs that would not be recovered through market-based revenues) and to
ensure a smooth transition to a competitive market, the California
Legislature developed a transition plan in the form of state legislation
that was passed in 1996. The transition plan will remain in effect until
the earlier of December 31, 2001, or when the Utility has recovered its
authorized transition costs as determined by the California Public
Utilities Commission (CPUC), with provisions that 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. The transition
plan contains three principal elements: (1) an electric rate freeze and
rate reduction, (2) the recovery of transition costs, and (3) divestiture
of utility-owned generation facilities. Each element is discussed below.
Rate Freeze and Rate Reduction:
- -------------------------------
The first element of the transition plan is an electric rate freeze and an
electric rate reduction. 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 of 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.
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.
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:
- -------------------------
Transition costs consist of: (1) above-market sunk costs (sunk costs are
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. A valuation of a Utility-owned
generation facility where the market value exceeds the book value could
result in a material charge to Utility earnings if the valuation of the
facility is determined based upon any method other than a sale of the
facility to a third party. This is because any excess of market value over
book value would be used to reduce other transition costs.
The Utility will not be able to determine the exact amount of above-
market non-nuclear sunk costs that will be recoverable as transition costs
until a market valuation process (appraisal, spin, sale, or other valuation
method) is completed for each of its 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 market value
of these facilities resulted in sales proceeds which exceeded the book
value and therefore has reduced the amount of transition costs to be
recovered. In addition, the Utility will request that the CPUC allow it to
hire appraisers to set the value of its hydroelectric generation system.
(See Generation Divestiture below.) The remainder of the valuation process
is expected to be completed by December 31, 2001. Nuclear sunk costs were
separately determined through a CPUC proceeding and were subject to a final
verification audit. This audit was completed in August 1998, the results
of which are currently under review.
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 three
months ended March 31, 1999, the average price paid per kilowatt hour (kWh)
under the Utility's long-term contracts for electric power was 5.5 cents
per kWh. The average cost of electric energy for energy purchased at
market rates from the PX for the three months ended March 31, 1999, was 2.3
cents per kWh.
Generation-related regulatory assets and obligations (net generation-
related regulatory assets) are included as transition costs. At March 31,
1999, the Utility's generation-related net regulatory assets totaled $5.1
billion.
Under the transition plan, 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. The CPUC believes that the
transition plan reduces financial risks associated with recovery of all the
Utility's generation assets, including the Diablo Canyon Nuclear Power
Plant (Diablo Canyon) and the hydroelectric facilities. As a result,
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 costs can be included in a non-bypassable charge to distribution
customers after the transition period. These costs include: (1) certain
employee-related transition costs, (2) above-market payments under existing
long-term contracts to purchase power, discussed above, and (3) unrecovered
electric industry restructuring implementation costs. In addition,
transition costs financed by the issuance of rate reduction bonds are
expected to be recovered over the term of the bonds. If the recovery period
ends before December 31, 2001 the Utility will be obligated to return a
portion of the bond proceeds to customers. The exact amount and timing of
such portion, if any, has not yet been determined. Further, the Utility's
nuclear decommissioning costs are being recovered through a CPUC-authorized
charge, which will extend until sufficient funds exist to decommission our
nuclear facility. During the rate freeze, this charge and the rate
reduction bond debt service 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. In May 1999
the CPUC issued a decision approving a settlement agreement that provides
for the recovery of approximately $100 million in electric industry
restructuring implementation costs incurred in 1997 and 1998. This
settlement will not have a material impact on the Utility's financial
position or results of operations.
Under the terms of the transition plan, revenues provided for the
recovery of most non-nuclear transition costs are based upon the
acceleration of such costs within the transition period. For nuclear
transition costs, revenues provided for transition cost recovery are based
on: (1) an established incremental cost incentive price 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.
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 three months ended March 31, 1999, regulatory
assets related to electric utility restructuring decreased by $247 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.
In addition, in August 1998, an independent accounting firm retained by
the CPUC completed its financial verification audit of the Utility's Diablo
Canyon plant accounts at 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,
requested by the CPUC, 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.
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).
In April 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. As of March 31, 1999, these facilities had a
combined book value of $245 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.
The Utility is currently evaluating its options related to its remaining
non-nuclear generation facilities, primarily the hydroelectric generation
system. In May 1998, the Utility notified the CPUC that it does not plan
to retain the 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 process would only
apply to retained assets. The Utility plans to file a new application with
the CPUC to appraise its hydroelectric facilities and transfer them to a
non-regulated affiliate. Meanwhile, several bills have been introduced in
the California State Senate which address hydroelectric facilities
valuation and divestiture issues.
At March 31, 1999, the book value of the Utility's net investment in
hydroelectric generation assets was approximately $1.3 billion. If the
Utility decides to dispose of the hydroelectric generation assets by any
method other than a sale of the assets to a third party, a material charge
will result to the extent that the determined value of the assets exceeds
their book value. The value of the hydroelectric assets is expected to
exceed their book value by a material amount.
Financial Impact of Transition Plan:
- ------------------------------------
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 remaining Utility-owned 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 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.
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 March 31, 1999. Short and
long positions pertaining to derivative contracts used for hedging
activities as of March 31, 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 3.83 3.65 8
Options 1.08 0.99 5
Futures 0.55 0.57 3
Forward Contracts 2.62 2.67 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.
The following table discloses the estimated fair values of price risk
management assets and liabilities as of March 31, 1999. PG&E Corporation's
net gains (losses) on swaps, options, futures, and forward contracts held
during the quarter for non-hedging purposes were $133 million, $(6) million,
$(42) million, and $(36) million, respectively. The ending and average fair
values and associated carrying amounts of derivative contracts used for
hedging purposes are not material as of March 31, 1999.
Average Ending
Fair Value Fair Value
- -------------------------------------------------------------
(in millions)
Assets
Non-Hedging Activities
Swaps $1,211 $1,470
Options 124 93
Futures 338 525
Forward Contracts 738 975
------ ------
Total $2,411 $3,063
Noncurrent portion 625
Current portion $2,438
Liabilities
Non-Hedging Activities
Swaps $1,116 $1,323
Options 151 101
Futures 379 573
Forward Contracts 660 922
------ ------
Total $2,306 $2,919
Noncurrent portion 505
Current portion $2,414
The credit exposure of the five largest counterparties comprised
approximately $149 million of the total credit exposure associated with
financial instruments used to manage price risk. Counterparties considered
to be investment grade or higher comprise 56 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., 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 $1.3 billion of USGen debt and a
$425 million equity contribution from PG&E Corporation. The net purchase
price has been 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, U.S. Generating Company (USGen) assumed 23 multi-
year power-purchase agreements representing an additional 800 MW of
production capacity. USGen 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 USGen for the purchase power agreements; and (2)
require that USGen 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.
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 March 31,
1999, of $297 million for hazardous waste remediation costs at identified
sites, including divested fossil-fueled power plants.
Environmental remediation at identified sites may be as much as $430
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.
Of the $297 million liability, discussed above, the Utility has recovered
$111 million and expects to recover $149 million in future rates.
Additionally, the Utility mitigates its costs by seeking recovery of its
costs from insurance carriers and from other third parties as appropriate.
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 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 can 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. However,
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, the
Utility's first quarter 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 Unregulated Business Operations: PG&E Corporation's wholesale
unregulated business operations consist of USGen which develops, builds,
operates, owns, and manages power generation facilities that serve
wholesale and industrial customers; PG&E Gas Transmission (PG&E GT) which
operates approximately 9,000 miles of natural gas pipelines, natural gas
storage facilities, 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 resells energy commodities and related financial instruments
in major North American markets, serving PG&E Corporation's other
unregulated businesses, unaffiliated utilities, and large end-use
customers.
Retail Unregulated Business Operations: PG&E Corporation's retail
unregulated business operations consist of PG&E Energy Services (PG&E ES)
which provides competitively priced electricity, natural gas, and related
services to lower overall energy costs for industrial, commercial, and
institutional customers.
Segment information for the three months ended March 31, 1999 and 1998,
respectively, was as follows:
Wholesale Retail
--------------------------------- -------
PG&E GT
---------------
Parent
& Elimi-
Utility USGen NW Texas PG&E ET PG&E ES nations(1) Total
------- ------- ------- ------- ------- ------- ------- -------
(in millions)
March 31, 1999
Operating revenues $ 2,083 $ 288 $ 46 $ 313 $2,396 $ 131 $ - $ 5,257
Intersegment revenues 2 1 12 44 235 4 (298) -
------- ------- ------- ------- ------- ------- ------- -------
Total operating
revenues 2,085 289 58 357 2,631 135 (298) 5,257
Net income 147 32 15 (24) (3) (8) (3) 156
Total assets at
quarter end 22,455 3,831 1,165 2,643 4,014 186 (186) 34,108
March 31, 1998
Operating revenues $ 2,025 $ 84 $ 48 $ 433 $1,717 $ 43 $ 3 $ 4,353
Intersegment revenues - - 13 82 60 - (155) -
------- ------- ------- ------- ------- ------- ------- -------
Total operating
revenues 2,025 84 61 515 1,777 43 (152) 4,353
Net income 148 9 15 (10) (1) (11) (11) 139
Total assets at
quarter end 24,054 1,167 1,156 2,749 1,139 63 (992) 29,336
<FN>
(1) Net income on intercompany positions recognized by segments using mark to market
accounting is eliminated. Intercompany transactions are also eliminated.
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 unregulated
businesses provide a wide range of energy products and services through its
wholesale and retail unregulated business operations.
PG&E Corporation's wholesale unregulated business operations consist of
U.S. Generating Company (USGen) which develops, builds, operates, owns, and
manages power generation facilities that serve wholesale and industrial
customers; PG&E Gas Transmission (PG&E GT) which operates approximately
9,000 miles of natural gas pipelines, natural gas storage facilities, 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
resells energy commodities and related financial instruments in major North
American markets, serving PG&E Corporation's other unregulated businesses,
unaffiliated utilities, and large end-use customers.
PG&E Corporation's retail unregulated business operations consist of
PG&E Energy Services (PG&E ES) which provides competitively priced
electricity, natural gas, and related services to lower overall energy
costs for 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 and on information currently
available to management. These forward-looking statements are identified
by words such as "estimates," "expects," "anticipates," "plans,"
"believes," 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;
- - 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 ongoing regulatory proceedings, including: the Utility's
cost of capital proceeding; the Utility's 1999 general rate case; the
Utility's proposal to adopt performance based ratemaking (PBR); and the
Utility's transmission rate case applications;
- - 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 quarters ended March 31, 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 transition plans, 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
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 have either
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
March 31, 1999, eighteen states have enacted electric industry
restructuring legislation, including California, Illinois, Pennsylvania,
New Jersey, Massachusetts, Rhode Island, and Connecticut. Other states,
including Texas, Ohio, and Oregon, are seriously considering restructuring
proposals. There are also 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 retail unregulated business operations.
California Transition Plan
- --------------------------
The Electric Business:
In 1998, California became one of the first states in the country to
implement an electric industry restructuring plan. 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 plan 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. California electric
industry restructuring has two major components: (1) the competitive market
frame-work, and (2) the electric transition plan, which are 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 to the transmission
system. 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.
Electric Transition Plan: Market-based revenues, determined by the market
through sales to the PX, may not be sufficient to recover (that is, to
collect from customers) all of the Utility's generation costs. To allow
California investor-owned utilities the opportunity to recover their tran-
sition costs (generation costs that would not be recovered through market-
based revenues) and to ensure a smooth transition to a competitive market,
the California Legislature developed a transition plan in the form of state
legislation that was passed in 1996. The transition plan will remain in
effect until the earlier of December 31, 2001, or when the Utility has
recovered its authorized transition costs as determined by the California
Public Utilities Commission (CPUC), with provisions that 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. The transition
plan contains three principal elements: (1) an electric rate freeze and
rate reduction, (2) the recovery of transition costs, and (3) divestiture
of utility-owned generation facilities. Each element is discussed below.
Rate Freeze and Rate Reduction: The first element of the transition plan is
an electric rate freeze and an electric rate reduction. 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 of 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.
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.
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: Transition costs consist of: (1) above-market
sunk costs (sunk costs are 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. A valuation of a Utility-owned
generation facility where the market value exceeds the book value could
result in a material charge to Utility earnings if the valuation of the
facility is determined based upon any method other than a sale of the
facility to a third party. This is because any excess of market value over
book value would be used to reduce other transition costs.
The Utility will not be able to determine the exact amount of above-
market non-nuclear sunk costs that will be recoverable as transition costs
until a market valuation process (appraisal, spin, sale, or other valuation
method) is completed for each of its 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 market value
of these facilities resulted in sales proceeds which exceeded the book
value and therefore has reduced the amount of transition costs to be
recovered. In addition, the Utility will request that the CPUC allow it to
hire appraisers to set the value of its hydroelectric generation system.
(See Generation Divestiture below.) The remainder of the valuation process
is expected to be completed by December 31, 2001. Nuclear sunk costs were
separately determined through a CPUC proceeding and were subject to a final
verification audit. This audit was completed in August 1998, the results
of which are currently under review. (See Regulatory Matters below for
further details.)
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 three
months ended March 31, 1999, the average price paid per kilowatt-hour (kWh)
under the Utility's long-term contracts for electric power was 5.5 cents
per kWh. The average cost of electric energy for energy purchased at
market rates from the PX for the three months ended March 31, 1999, was 2.3
cents per kWh.
Generation-related regulatory assets and obligations (net generation-
related regulatory assets) are included as transition costs. At March 31,
1999, the Utility's generation-related net regulatory assets totaled $5.1
billion.
Under the transition plan, 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. The CPUC believes that the
transition plan reduces financial risks associated with recovery of all the
Utility's generation assets, including the Diablo Canyon Nuclear Power
Plant (Diablo Canyon) and the hydroelectric facilities. As a result,
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 costs can be included in a non-bypassable charge to distribution
customers after the transition period. These costs include: (1) certain
employee-related transition costs, (2) above-market payments under existing
long-term contracts to purchase power, discussed above, and (3) unrecovered
electric industry restructuring implementation costs. In addition,
transition costs financed by the issuance of rate reduction bonds are
expected to be recovered over the term of the bonds. If the recovery
period ends before December 31, 2001 the Utility will be obligated to
return a portion of the bond proceeds to customers. The exact amount and
timing of such portion, if any, has not yet been determined. Further, the
Utility's nuclear decommissioning costs are being recovered through a CPUC-
authorized charge, which will extend until sufficient funds exist to
decommission our nuclear facility. During the rate freeze, this charge and
the rate reduction bond debt service 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.
In May 1999 the CPUC issued a decision approving a settlement agreement
that provides for the recovery of approximately $100 million in electric
industry restructuring implementation costs incurred in 1997 and 1998.
This settlement will not have a material impact on the Utility's financial
position or results of operations.
Under the terms of the transition plan, revenues provided for the
recovery of most non-nuclear transition costs are based upon the
acceleration of such costs within the transition period. For nuclear
transition costs, revenues provided for transition cost recovery are based
on: (1) an established incremental cost incentive price 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.
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 three months ended March 31, 1999, regulatory
assets related to electric utility restructuring decreased by $247 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).
In April 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. As of March 31, 1999, these facilities had a
combined book value of $245 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.
The Utility is currently evaluating its options related to its remaining
non-nuclear generation facilities, primarily the hydroelectric generation
system. In May 1998, the Utility notified the CPUC that it does not plan
to retain the 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 process would only
apply to retained assets. The Utility plans to file a new application with
the CPUC to appraise its hydroelectric facilities and transfer them to a
non-regulated affiliate. Meanwhile, several bills have been introduced in
the California State Senate which address hydroelectric facilities
valuation and divestiture issues.
At March 31, 1999, the book value of the Utility's net investment in
hydroelectric generation assets was approximately $1.3 billion. If the
Utility decides to dispose of the hydroelectric generation assets by any
method other than a sale of the assets to a third party, a material charge
will result to the extent that the determined value of the assets exceeds
their book value. The value of the hydroelectric assets is expected to
exceed their book value by a material amount.
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
remaining Utility-owned 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 costs are
increased or decreased (see Regulatory Matters), and (7) the market price
of electricity. Given our current evaluation of these factors we believe
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.
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:
- -------------------------------
Three New England states where our unregulated 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., 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 $1.3 billion of USGen 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 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. USGen New England,
Inc., 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 which 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.
Regulatory Matters:
- -------------------
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, electric
transmission, the CPUC's gas strategy order instituting rulemaking, and the
Diablo Canyon sunk costs audit. These items are discussed below. Any
requested change in authorized 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.
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 can 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. However,
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, the
Utility's first quarter 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 Utility's 1999 Cost of Capital Proceeding:
The Utility filed its 1999 cost of capital application with the CPUC in May
1998. The Utility requested a return on equity (ROE) of 12.10 percent and
an overall return on rate base of 9.53 percent for its electric and gas
distribution assets, as opposed to its currently adopted 1998 bundled ROE
of 11.20 percent and overall return of 9.17 percent.
On March 23, 1999, an Administrative Law Judge (ALJ) of the CPUC issued
a proposed decision which recommends a ROE of 10.60 percent for the
Utility's electric distribution and gas distribution assets, and an overall
return on rate base of 8.75 percent in 1999. Also, on May 13, 1999, a CPUC
Commissioner issued an alternative proposed decision which recommends a ROE
of 10.80 percent for the Utility's electric distribution and gas
distribution assets, and an overall return on rate base of 8.84 percent in
1999. Neither of the proposed decisions recommends any change to the
currently authorized utility capital structure of 46.20 percent long-term
debt, 5.80 percent preferred stock, and 48 percent common equity.
Both proposed decisions provide that the changes would be retroactive to
January 1, 1999. The proposed decisions are subject to change prior to the
final vote of the CPUC. The CPUC may adopt all or part of a proposed
decision as written, amend, or modify it, or set it aside and prepare its
own decision.
Other parties, notably the CPUC's ORA, had recommended lower rates of
return than those requested by the Utility. The table below shows the
current authorized rates, the requested rates, ORA's recommended rates, and
the ALJ's proposed rates:
1998 1999 1999 ORA 1999 ALJ
Authorized Requested Recommendation Proposed
- ---------------------------------------------------------------------------
Long-term debt 7.36% 7.24% 7.19% 7.09%
Preferred stock 6.65% 6.50% 6.50% 6.55%
Common stock (ROE) 11.20% 12.10% 8.64% (1) 10.60% (2)
Overall Return
on Rate Base (3) 9.17% 9.53% 7.85% 8.75%
(1) For electric distribution only. ORA recommended a return on common
equity of 9.32 percent and an overall return on utility rate base of 8.17
percent for the Utility's gas distribution operations.
(2) For both electric and gas distribution.
(3) Based upon a Utility capital structure of 46.2 percent long-term debt,
5.8 percent preferred stock, and 48 percent common equity.
By itself, the ALJ's proposed decision would reduce the Utility's base
revenues in 1999, as compared to 1998, by $35.4 million and $12.3 million
for electric and gas distribution, respectively, based on the current
authorized rate base. However, the total change in the Utility's base
revenues in 1999 will be determined by a combination of the final outcomes
of the cost of capital proceeding, the GRC proceeding, and other CPUC
proceedings. In light of the current rate freeze, decreases in base
revenues would increase the amount of revenues available to recover
transition costs (certain generation-related costs which prove to be
uneconomic under the new competitive electric generation market).
The Utility's Distribution Performance Based Ratemaking (PBR) Application:
The Utility amended its distribution PBR proposal to 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 factors will be fixed for the five year duration of the
PBR. We have 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 CPUC is scheduled to have
hearings in the PBR proceeding in September 1999 and to issue a final
decision in the second quarter 2000. In this event, the Utility proposes
to implement the PBR-based distribution component rates retroactively to
January 1, 2000.
Electric Transmission:
Since April 1, 1998, all electric transmission revenues are authorized by
FERC. During 1998, the FERC issued orders which 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.
The orders allowed the Utility to recover $176 million for the period of
April 1998 through October 1998, and $193 million for the period of
November 1998 through May 1999. 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. Also, on March 30, 1999, the Utility
requested that FERC approve rates to generate, on an annualized basis, $324
million of electric transmission revenues effective June 1, 1999. If the
FERC does not put into effect the rates requested in the March 30, 1999
filing, the Utility would continue to use the rates currently in effect.
The CPUC's Gas Strategy Order Instituting Rulemaking:
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. If the CPUC determines that further restructuring
for core customers is in the public interest, it shall submit its findings
to the Legislature. However, Senate Bill 1602 prohibits the CPUC from
enacting any such gas industry restructuring decisions prior to January 1,
2000.
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.
Results of Operations
In this section, we present the components of our results of operations for
the quarters ended March 31, 1999 and 1998. Due to a delay in the issuance
of a decision in the Utility's GRC, the Utility's first quarter 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 March 31, 1999 and 1998, respectively, certain
items from our Statement of Consolidated Income detailed by (1) Utility,
(2) wholesale and (3) retail business 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 from the quarter before for
1999 and 1998.
Wholesale Retail
--------------------------------- -------
PG&E GT
---------------
Parent
& Elimi-
Utility USGen NW Texas PG&E ET PG&E ES nations(1) Total
------- ------- ------- ------- ------- ------- ------- -------
(in millions)
March 31, 1999
Operating revenues $ 2,085 $ 289 $ 58 $ 357 $2,631 $ 135 $ (298) $ 5,257
Operating expenses 1,663 247 27 383 2,636 150 (291) 4,815
------- ------- ------- ------- ------- ------- ------- -------
Operating income (loss) 422 42 31 (26) (5) (15) (7) 442
Other income, net 21
Interest expense 201
Income taxes 106
Net income 156
March 31, 1998
Operating revenues $ 2,025 $ 84 $ 61 $ 515 $1,777 $ 43 $ (152) $ 4,353
Operating expenses 1,601 66 25 513 1,777 60 (152) 3,890
------- ------- ------- ------- ------- ------- ------- -------
Operating income (loss) 424 18 36 2 - (17) - 463
Other income, net 14
Interest expense 197
Income taxes 141
Net income 139
<FN>
(1) Net income on intercompany positions recognized by segments using mark to market
accounting is eliminated. Intercompany transactions are also eliminated.
Overall Results:
- ----------------
Net income increased to $156 million from $139 million for the three-month
period ended March 31, 1999, as compared to the same period in 1998
primarily due to the operations of the New England assets acquired in
September 1998 and a lower effective tax rate partially offset by continued
losses at PG&E GTT.
Operating Revenues:
- -------------------
Utility:
Utility operating revenues increased $60 million for the three-month period
ended March 31, 1999, as compared to the same period in 1998 primarily due
to $96 million in higher residential gas sales and $36 million in higher
residential electricity sales resulting from cooler weather. The increased
sales were partially offset by a decrease of $51 million in sales to medium
and large electric customers, many of whom are now purchasing their
electricity directly from unregulated power generators.
Wholesale Unregulated Business Operations:
Operating revenues associated with wholesale unregulated business
operations increased $898 million for the three-month period ended March
31, 1999, as compared to the same period in 1998. This increase is due to
the operating revenues of USGen, which increased $205 million as a result
of its acquisition of a portfolio of electric generating assets and power
supply contracts from NEES in the third quarter of 1998, and PG&E ET's
operating revenues which increased $854 million as a result of increased
electric and gas commodity trading. These increases were offset by
decreases to PG&E GTT's operating revenues of $158 million during the first
quarter in 1999, as compared to the same period in 1998 due to declines in
the natural gas liquid prices and declines in shipped volumes of natural
gas.
Retail Unregulated Business Operations:
Operating revenues associated with the retail unregulated business
operations increased $92 million for the three-month period ended March 31,
1999, as compared to the same period in 1998. This increase is primarily
due to sales of electricity in California since March 31, 1998, when retail
direct access in California began.
Operating Expenses:
- -------------------
Utility:
Utility operating expenses increased $62 million for the three-month period
ended March 31, 1999, as compared to the same period in 1998 as a result of
higher purchased gas volumes from the increase in residential gas sales due
to cooler weather, 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. Also, there were lower storm response costs in
the first quarter of 1999 as compared to the same period in 1998.
Wholesale Unregulated Business Operations:
Operating expenses for the wholesale unregulated business operations
increased $912 million for the three-month period ended March 31, 1999, as
compared to the same period in 1998. This reflects increased PG&E ET
volumes of energy commodities purchased and operating costs associated with
our newly acquired New England assets at USGen. These increases were
partially offset by decreased operating expenses at PG&E GTT.
Retail Unregulated Business Operations:
Operating expenses for our retail unregulated business operations increased
$90 million for the three-month period ended March 31, 1999, as compared to
the same period in 1998. This increase is due to the increased electric
commodity sales and the continued expansion of our energy services
business.
Income Taxes:
- -------------
Income taxes decreased $35 million for the three-month period ended March
31, 1999, as compared to the same period in 1998. Tax expense decreased
due to a lower effective state tax rate resulting from our expanded
business operations.
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.
Liquidity and Financial Resources
Cash Flows from Operating Activities:
Net cash provided by PG&E Corporation's operating activities totaled $1,004
million and $852 million during the three-month period ended March 31, 1999
and 1998, respectively. Net cash provided by the Utility's operating
activities totaled $1,093 million and $613 million during the three-month
period ended March 31, 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 three-month period ended March 31, 1999 and 1998, we issued
$20 million and $17 million of common stock, respectively, primarily
through the Dividend Reinvestment Plan, the Stock Option Plan, and the
Long-Term Incentive Plan. During the three-month period ended March 31,
1999 and 1998, we paid dividends on our common stock of $115 million and
$126 million, respectively.
During the three-month period ended March 31, 1999 and 1998, we
repurchased $503 million and $1,122 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. This agreement caused the
$0.05 dilution 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 $490
million of commercial paper outstanding at March 31, 1999.
USGen maintains two credit facilities of $550 million each. One
agreement expires in August 1999 and the other in 2003. The total amount
outstanding at March 31, 1999, backed by the facilities, was $824 million
in commercial paper. Of these loans, $550 million is classified as
noncurrent in the consolidated balance sheet.
At March 31, 1999, PG&E GTT had $115 million of outstanding short-term
bank borrowings related to three separate credit facilities. These lines
are cancelable upon demand and bear interest at each respective bank's
quoted money market rate. The borrowings are unsecured and unrestricted as
to use.
PG&E GT NW maintains a $200 million revolving credit facility which
expires in the year 2000. At March 31, 1999 and 1998, PG&E GT NW had
outstanding commercial paper balances of $96 million and $108 million,
respectively, supported by this revolving facility. These balances were
classified as noncurrent obligations in the consolidated balance sheet.
Utility:
During the three-month period ended March 31, 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 three month period ended March 31, 1999 and 1998,
the Utility paid dividends on its common stock to PG&E Corporation of $100
million and $115 million, respectively. In April 1999, the Utility
declared and paid dividends on its common stock of $95 million to PG&E
Corporation.
The Utility's long-term debt that either matured, was redeemed, or was
repurchased during the three-month period ended March 31, 1999 totaled $212
million. Of this amount, (1) $73 million related to the Utility's
redemption of its 8.8 percent mortgage bonds due May 1, 2024; (2) $31
million related to the Utility's repurchase of various other mortgage
bonds; (3) $10 million related to the Utility's redemption of its various
medium term notes; (4) $13 million related to the maturity of the Utility's
6.98 percent medium term note; and (5) $85 million related to rate
reduction bonds maturing.
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. At March 31, 1999, the Utility had $566 million of
commercial paper and $357 million of bank notes outstanding. No amounts
were outstanding at March 31, 1998.
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 estimated capital spending for 1999 is $1.7 billion.
Utility capital expenditures are based on estimates prepared for the
Utility's GRC, but exclude capital expenditures for divested fossil and
geothermal power plants. These estimates may be reduced if the CPUC
authorized base revenues are significantly lower than those requested by
the Utility in its GRC filing.
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.
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 March 31, 1999, the Utility expects to spend $297 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 $430 million. Of the $297 million, the Utility has recovered $111
million (including remediation of generation plants divested, discussed
above) and expects to recover another $149 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
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.
Our Year 2000 project is generally proceeding on schedule. The
following table indicates our Year 2000 progress as of May 3, 1999. The
percentages in this table are rounded to the nearest percent and reflect
approximations based on a standardized reporting system that combines
subsidiary results to provide a consistent, company-wide view.
Year 2000 Readiness of Mission-Critical Items
Remediation Testing Certification
Completed Completed Completed
- ----------------------------------------------------------------------
In-house software 100% 98% 23%
Vendor software 100% 90% 56%
Embedded systems 100% 97% 77%
Computer hardware 100% 100% 13%
Changes in company 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. Also, the completion of
these phases does not address external interdependencies that could affect
our or the Utility's ability to be Year 2000 ready. Even after systems are
certified, we are continuing various kinds of testing and quality assurance
efforts, and may do so through the end of 1999.
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 another
phased approach. The primary phases for dealing with external parties are:
(1) inventory, (2) action planning, (3) risk assessment, and (4)
contingency planning.
We have completed our inventory, action planning and risk assessment
phases for mission-critical external parties. We expect to complete the
contingency planning phase by July 1999.
Although we expect our efforts and those of our external parties to be
largely successful, we recognize that with the complex interaction of
today's computing and communications systems, we cannot be certain we will
be completely successful. Therefore, contingency plans for Year 2000
readiness are being developed and tested throughout 1999 to address our
external dependencies as well as any significant schedule delays of
mission-critical system work, should they occur.
As of March 31, 1999, we estimate total costs to address Year 2000
problems to be $229 million, of which $98 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 March 1999, we spent approximately $139 million, of which $82
million was capitalized. The remaining $57 million was expensed. Future
costs, including contingency funds, to address Year 2000 issues are
expected to be $90 million, of which $38 million will be capitalized. The
remaining $52 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.
We believe the most reasonably likely worst case Year 2000 scenarios
that could affect us or the Utility mainly involve public overreaction
before and during the New Year period that could create localized telephone
problems due to congestion, 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 whom we have significant business relationships,
fail to achieve 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 March 31, 1999, is $4.9 million for trading
activities and $0.4 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.
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.
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.)
PART II. OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security Holders
---------------------------------------------------
PG&E Corporation:
On April 21, 1999, PG&E Corporation held its annual meeting of
shareholders. At that meeting, the shareholders voted as
indicated below on the following matters:
1. Election of the following directors to serve until the next
annual meeting of shareholders or until their successors are
elected and qualified:
For Withheld
---------- ----------
Richard A. Clarke 290,792,975 6,157,488
Harry M. Conger 291,587,450 5,363,013
David A. Coulter 290,805,944 6,144,519
Lee Cox 291,508,166 5,442,297
William S. Davila 291,562,677 5,387,786
Robert D. Glynn, Jr. 291,668,526 5,281,937
David M. Lawrence, MD 291,367,569 5,582,894
Richard B. Madden 291,587,579 5,362,884
Mary S. Metz 291,541,426 5,409,037
Rebecca Q. Morgan 291,561,003 5,389,460
Carl E. Reichardt 291,410,525 5,539,938
John C. Sawhill 291,537,720 5,412,743
Barry Lawson Williams 291,661,213 5,289,250
2. Ratification of the appointment of Deloitte & Touche LLP as
independent public accountants for the year 1999:
For: 292,715,545
Against: 1,623,212
Abstain: 2,611,706
The proposal was approved by a majority of the shares present
and voting (including abstentions) which shares voting
affirmatively also constituted a majority of the required
quorum.
3. Management proposal to increase the number of shares of PG&E
Corporation common stock available for issuance under the
PG&E Corporation Long-Term Incentive Program:
For: 269,594,220
Against: 22,427,884
Abstain: 4,921,883
The proposal was approved by a majority of the shares present
and voting (including abstentions) which shares voting
affirmatively also constituted a majority of the required
quorum.
4. Consideration of a shareholder proposal to appoint
independent directors to key Board committees:
For: 65,289,721
Against: 180,879,296
Abstain: 7,467,534
Broker non-votes:(1) 43,307,436
This shareholder proposal was defeated as the number of shares
voting affirmatively on the proposal constituted less than a
majority of the shares voting and present (including abstentions
but excluding broker non-votes) with respect to the proposal.
5. Consideration of a shareholder proposal regarding super
majority voting:
For: 134,948,487
Against: 111,558,656
Abstain: 7,135,884
Broker non-votes:(1) 43,307,436
This shareholder proposal was approved as the number of shares
voting affirmatively on the proposal constituted more than a
majority of the shares voting and present (including abstentions
but excluding broker non-votes) with respect to the proposal,
and the affirmative votes constituted a majority of the required
quorum.
6. Consideration of a shareholder proposal regarding the method
of tabulation of proxies received by management.
For: 34,956,995
Against: 207,843,397
Abstain: 10,842,635
Broker non-votes:(1) 43,307,436
This shareholder proposal was defeated as the number of shares
voting affirmatively on the proposal constituted less than a
majority of the shares voting and present (including abstentions
but excluding broker non-votes) with respect to the proposal.
7. Consideration of a shareholder proposal regarding cumulative
voting:
For: 46,369,049
Against: 170,366,088
Abstain: 36,907,890
Broker non-votes:(1) 43,307,436
This shareholder proposal was defeated as the number of shares
voting affirmatively on the proposal constituted less than a
majority of the shares voting and present (including abstentions
but excluding broker non-votes) with respect to the proposal.
- --------------------
(1) A non-vote occurs when a broker or other nominee holding
shares for a beneficial owner indicates a vote on one or more
proposals, but does not indicate a vote on other proposals
because the broker or other nominee does not have discretionary
voting power as to such proposals and has not received voting
instructions from the beneficial owner as to such proposals.
8. Consideration of a proposal regarding the payment of
compensation contingent upon a change in control:
For: 33,236,110
Against: 212,025,872
Abstain: 8,381,045
Broker non-votes:(1) 43,307,436
This shareholder proposal was defeated as the number of shares
voting affirmatively on the proposal constituted less than a
majority of the shares voting and present (including abstentions
but excluding broker non-votes) with respect to the proposal.
Pacific Gas and Electric Company:
On April 21, 1999, Pacific Gas and Electric Company held its
annual meeting of shareholders. Shares of capital stock of
Pacific Gas and Electric Company consist of shares of common
stock and shares of first preferred stock. PG&E Corporation, as
owner of all of the 326,926,667 outstanding shares of common
stock, holds approximately 95% of the combined voting power of
the outstanding capital stock of Pacific Gas and Electric
Company. PG&E Corporation voted all of its shares of common
stock for the nominees named in the joint proxy statement, and
for the ratification of the appointment of Deloitte & Touche LLP
as independent public accountants for the year 1999. The balance
of the votes shown below were cast by holders of shares of first
preferred stock. At the annual meeting, the shareholders voted
as indicated below on the following matters:
1. Election of the following directors to serve until the next
annual meeting of shareholders or until their successors are
elected and qualified:
For Withheld
----------- -----------
Richard A. Clarke 339,677,829 128,510
Harry M. Conger 339,679,932 126,407
David A. Coulter 339,679,979 126,360
C. Lee Cox 339,697,378 108,961
William S. Davila 339,695,300 111,039
Robert D. Glynn, Jr. 339,688,109 118,230
David M. Lawrence, MD 339,695,772 110,567
Richard B. Madden 339,682,727 123,612
Mary S. Metz 339,691,603 114,736
Rebecca Q. Morgan 339,700,325 106,014
Carl E. Reichardt 339,682,444 123,895
John C. Sawhill 339,691,382 115,144
Gordon R. Smith 339,696,509 114,957
Barry Lawson Williams 339,696,509 109,830
2. Ratification of the appointment of Deloitte & Touche LLP as
independent public accountants for the year 1999:
For: 339,644,746
Against: 41,103
Abstain: 120,490
- --------------------
(1) A non-vote occurs when a broker or other nominee holding
shares for a beneficial owner indicates a vote on one or more
proposals, but does not indicate a vote on other proposals
because the broker or other nominee does not have discretionary
voting power as to such proposals and has not received voting
instructions from the beneficial owner as to such proposals.
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 three months ended March 31, 1999 was 2.66.
Pacific Gas and Electric Company's earnings to combined fixed
charges and preferred stock dividends ratio for the three months
ended March 31, 1999 was 2.53. 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 3.1 Bylaws of PG&E Corporation, dated April 21,1999
Exhibit 3.2 Bylaws of Pacific Gas and Electric Company, dated
April 21, 1999
Exhibit 10 PG&E Corporation Long-Term Incentive Program
(incorporated by reference from Exhibit 99
to Registration Statement on Form S-8, No.
333-77149)
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 quarter ended
March 31, 1999 for PG&E Corporation
Exhibit 27.2 Financial Data Schedule for the quarter ended
March 31, 1999 for Pacific Gas and Electric
Company
(b) Reports on Form 8-K during the first quarter of 1999 and
through the date hereof (1):
1. January 20, 1999
Item 5. Other Events
A. 1998 Consolidated Earnings (unaudited)
B. 1999 Outlook
C. Share Repurchase Program
2. February 17, 1999
Item 4. Changes in Registrant's Certifying Accountant
Item 5. Other Events
Share Repurchase Program
Item 7. Financial Statements, Pro Forma Financial Information+,
and Exhibits
3. March 24, 1999
Item 5. Other Events
Pacific Gas and Electric Company's 1999 Cost of Capital
Proceeding
4. April 15, 1999
Item 5. Other Events
Announcement of postponement in scheduled release of first
quarter earnings.
(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)
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
May 17, 1999 By _______________________
CHRISTOPHER P. JOHNS
Vice President and Controller
(PG&E Corporation)
Vice President and Controller
(Pacific Gas and Electric Company)
Exhibit Index
Exhibit No. Description of Exhibit
3.1 Bylaws of PG&E Corporation, dated April 21, 1999
3.2 Bylaws of Pacific Gas and Electric Company, dated
April 21, 1999
10 PG&E Corporation Long-Term Incentive Program
(incorporated by reference from Exhibit 99 to
Registration Statement on Form S-8, No. 333-
77149)
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 quarter ended
March 31, 1999 for PG&E Corporation
27.2 Financial Data Schedule for the quarter ended
March 31, 1999 for Pacific Gas and Electric
Company