FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
----------------------------------
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended JuneSeptember 30, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________to ___________
Exact Name of
Commission Registrant State or other IRS Employer
File as specified Jurisdiction of Identification
Number in its charter Incorporation Number
- ----------- -------------- --------------- --------------
1-12609 PG&E Corporation California 94-3234914
1-2348 Pacific Gas and California 94-0742640
Electric Company
Pacific Gas and Electric Company PG&E Corporation
77 Beale Street One Market, Spear Tower
P.O. Box 770000 Suite 2400
San Francisco, California 94177 San Francisco,
California 94105
- ----------------------------------------------------------------------------------------------------------------------------------------
(Address of principal executive offices) (Zip Code)
Pacific Gas and Electric Company PG&E Corporation
(415) 973-7000 (415) 267-7000
- ----------------------------------------------------------------------------------------------------------------------------------------
Registrant's telephone number, including area code
Indicate by check mark whether the registrants (1) have
filed all reports required to be filed by Section 13 or
15(d) of the Securities Exchange Act of 1934 during the
preceding twelve months (or for such shorter period that the
registrant was required to file such reports), and (2) have
been subject to such filing requirements for the past 90
days.
Yes X No
_________---------- ---------
Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the latest practicable date.
Common Stock Outstanding July 28,October 6, 1999:
PG&E Corporation 383,949,779383,979,721 shares
Pacific Gas and Electric Company Wholly owned by PG&E Corporation
PG&E CORPORATION
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED JUNESEPTEMBER 30, 1999
TABLE OF CONTENTS
PAGE
PART I. FINANCIAL INFORMATION
ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS
PG&E CORPORATION
STATEMENT OF CONSOLIDATED INCOME........................1
CONSOLIDATED BALANCE SHEET..............................2
STATEMENT OF CONSOLIDATED CASH FLOWS ...................4
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED INCOME........................5
CONDSOLIDATED BALANCE SHEET.............................6
STATEMENT OF CONSOLIDATED CASH FLOWS....................8
NOTE 1: GENERAL...........................................9
NOTE 2: CALIFORNIA ELECTRIC INDUSTRY RESTRUCTURING........9
NOTE 3: PRICE RISK MANAGEMENT AND FINANCIAL INSTRUMENTS..15INSTRUMENTS..16
NOTE 4: ACQUISITIONS AND SALES...........................16SALES...........................17
NOTE 5: UTILITY OBLIGATED MANDATORILY REDEEMABLE
PREFERRED SECURITIES OF TRUST HOLDING
SOLELY UTILITY SUBORDINATED DEBENTURES...........17DEBENTURES...........18
NOTE 6: COMMITMENTS AND CONTINGENCIES....................17CONTINGENCIES....................18
NOTE 7: SEGMENT INFORMATION..............................20INFORMATION..............................21
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS. ....................22....................23
COMPETITIVE AND REGULATORY ENVIRONMENT....................23ENVIRONMENT....................24
The Competitive Environment in the Evolving
Energy Industry........................................23Industry........................................24
California Industry Restructuring......................24Restructuring......................25
New England Electricity Market.........................30Market.........................32
Regulatory Matters.....................................31Matters.....................................33
RESULTS OF OPERATIONS.....................................34OPERATIONS.....................................37
LIQUIDITY AND FINANCIAL RESOURCES.........................40RESOURCES.........................43
ENVIRONMENTAL MATTERS.....................................42MATTERS.....................................45
YEAR 2000.................................................422000.................................................46
PRICE RISK MANAGEMENT ACTIVITIES..........................44ACTIVITIES..........................47
LEGAL MATTERS.............................................44MATTERS.............................................48
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK.........................................45RISK.........................................49
PART II. OTHER INFORMATION
ITEM 4. LEGAL PROCEEDINGS.........................................50
ITEM 5. OTHER INFORMATION.........................................46INFORMATION.........................................50
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K..........................46
SIGNATURE..........................................................488-K..........................51
SIGNATURE..........................................................52
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 June 30, SixNine months ended
JuneSeptember 30, September 30,
1999 1998 1999 1998
-------- -------- -------- --------
Operating Revenues
Utility $ 2,2332,587 $ 2,1172,563 $ 4,3186,905 $ 4,1436,706
Energy commodities and services 2,587 2,670 5,759 4,9973,793 2,744 9,552 7,741
-------- -------- -------- --------
Total operating revenues 4,820 4,787 10,077 9,1406,380 5,307 16,457 14,447
-------- -------- -------- --------
Operating Expenses
Cost of energy for utility 664 576 1,319 1,258864 724 2,183 1,982
Cost of energy commodities and services 2,365 2,472 5,286 4,6243,556 2,560 8,842 7,184
Operating and maintenance, net 774 770 1,572 1,571788 759 2,360 2,330
Depreciation, amortization, and decommissioning 563 412 1,004 666680 737 1,684 1,403
-------- -------- -------- --------
Total operating expenses 4,366 4,230 9,181 8,1195,888 4,780 15,069 12,899
-------- -------- -------- --------
Operating Income 454 557 896 1,021492 527 1,388 1,548
Interest expense, net 192 196 393 393(191) (193) (584) (586)
Other income, net 39 (8) 60 720 18 80 25
-------- -------- -------- --------
Income Before Income Taxes 301 353 563 635321 352 884 987
Income taxes 121 179 227 322138 142 365 464
-------- -------- -------- --------
Net Income $ 180183 $ 174210 $ 336519 $ 313523
======== ======== ======== ========
Weighted Average Common Shares
Outstanding 367 382 370369 382
Earnings Per Common Share, Basic $ .49.50 $ .46.55 $ .911.41 $ .821.37
Earnings Per Common Share, Diluted $ .46.50 $ .46.55 $ .831.40 $ .821.37
Dividends Declared Per Common Share $ .30 $ .30 $ .60.90 $ .60.90
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 JuneSeptember 30, December 31,
1999 1998
------------- ------------
ASSETS
Current Assets
Cash and cash equivalents $ 284269 $ 286
Short-term investments 37 55
Accounts receivable
Customers, net 1,5691,631 1,856
Energy marketing 571770 507
Price Risk Management 716707 1,416
Inventories and prepayments 770799 835
-------- --------
Total current assets 3,9474,213 4,955
Property, Plant, and Equipment
Utility 22,65822,783 23,996
Wholesale and retail unregulated business operationsNon-utility
Electric generation 1,9001,906 1,967
Gas transmission 3,3873,391 3,347
Construction work in progress 398425 407
Other 171177 127
-------- --------
Total property, plant, and equipment (at original cost) 28,51428,682 29,844
Accumulated depreciation and decommissioning (11,038)(11,179) (12,026)
-------- --------
Net property, plant, and equipment 17,47617,503 17,818
Other Noncurrent Assets
Regulatory assets 5,5205,363 6,347
Nuclear decommissioning funds 1,2381,225 1,172
Other 3,2453,182 2,942
-------- --------
Total noncurrent assets 10,0039,770 10,461
-------- --------
TOTAL ASSETS $ 31,42631,486 $ 33,234
======== ========
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 JuneSeptember 30, December 31,
1999 1998
------------ ------------
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings $ 877962 $ 1,644
Current portion of long-term debt 549537 338
Current portion of rate reduction bonds 282286 290
Accounts payable
Trade creditors 775777 1,001
Other 543540 443
Regulatory balancing accounts 685934 79
Energy marketing 475660 381
Accrued taxes 738412 103
Price risk management 708725 1,412
Other 8731,017 1,064
-------- --------
Total current liabilities 6,5056,850 6,755
Noncurrent Liabilities
Long-term debt 6,8956,845 7,422
Rate reduction bonds 2,1812,108 2,321
Deferred income taxes 3,2633,223 3,861
Deferred tax credits 251241 283
Other 3,8363,669 3,746
-------- --------
Total noncurrent liabilities 16,42616,086 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, 5,391no par value, authorized 800,000,000 shares,
issued 384,033,110 and 382,603,564 shares 5,904 5,862
Common stock held by subsidiary, at cost, 16,600,000 shares (531) -
Reinvested earnings 2,3242,397 2,204
-------- --------
Total common stockholders' equity 7,7157,770 8,066
Commitments and Contingencies (Notes 2 and 6) - -
-------- --------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 31,42631,486 $ 33,234
======== ========
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 sixnine months ended JuneSeptember 30, 1999 1998
---------- ----------
Cash Flows From Operating Activities
Net income $ 336519 $ 313523
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, amortization and decommissioning 1,004 6661,684 1,403
Deferred income taxes and tax credits-net (630) (31)(652) (309)
Other deferred charges and noncurrent liabilities (401) (74)(729) (682)
Loss on sale of assets - 2122
Net effect of changes in operating assets
and liabilities:
Accounts receivable - trade 287 100(225) 704
Regulatory balancing accounts payable 606 365855 618
Inventories and prepayments 65 4236 (45)
Price risk management assets and liabilities, net (4) (24)22 2
Accounts payable - trade (226) (187)(224) (118)
Accrued taxes 635 165309 501
Other working capital (56) (135)64 (101)
Other-net 21 29346 (3)
--------- ---------
Net cash provided by operating activities 1,637 1,2502,005 2,515
--------- ---------
Cash Flows From Investing Activities
Capital expenditures (740) (925)(1,058) (1,262)
Proceeds from the sale of assets 1,014 -58
Other-net - 14108 (190)
--------- ---------
Net cash used by investing activities 274 (911)64 (1,394)
--------- ---------
Cash Flows From Financing Activities
Net (repayments) borrowings (repayments) under credit facilities (767) 473(682) 507
Long-term debt issued - 199137
Long-term debt matured, redeemed, or repurchased (491) (644)(611) (1,295)
Preferred stock redeemed or repurchased - (63)(105)
Common stock issued 32 3344 48
Common stock repurchased (503) (1,123)(534) (1,159)
Dividends paid (225) (240)(335) (377)
Other-net 23 (21)14 37
--------- ---------
Net cash used by financing activities (1,931) (1,386)(2,104) (2,207)
--------- ---------
Net Change in Cash and Cash Equivalents (20) (1,047)(35) (1,086)
Cash and Cash Equivalents at January 1 341 1,397
--------- ---------
Cash and Cash Equivalents at JuneSeptember 30 $ 321306 $ 350311
========= =========
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized) $ 385518 $ 394527
Income taxes 87 209(net of refunds) 589 264
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 June 30, SixNine months ended
JuneSeptember 30, September 30,
1999 1998 1999 1998
-------- -------- -------- ---------------
Electric utility $ 1,8282,189 $ 1,7082,226 $ 3,3615,550 $ 3,2705,496
Gas utility 405 409 957 873398 337 1,355 1,210
-------- -------- -------- --------
Total operating revenues 2,233 2,117 4,318 4,1432,587 2,563 6,905 6,706
-------- -------- -------- --------
Operating Expenses
Cost of electric energy 526 453 935 927746 650 1,681 1,577
Cost of gas 138 123 384 331118 74 502 405
Operating and maintenance, net 608 672 1,234 1,370615 632 1,849 2,002
Depreciation, amortization, and decommissioning 509 375 891 597622 695 1,513 1,292
-------- -------- -------- --------
Total operating expenses 1,781 1,623 3,444 3,2252,101 2,051 5,545 5,276
-------- -------- -------- --------
Operating Income 452 494 874 918486 512 1,360 1,430
Interest expense, net 148 159 302 321(148) (154) (450) (475)
Other income, net 11 27 22 648 15 30 79
-------- -------- -------- -------
Income Before Income Taxes 315 362 594 661346 373 940 1,034
Income taxes 137 169 263 312161 168 424 480
-------- -------- -------- -------
Net Income 178 193 331 349185 205 516 554
Preferred dividend requirement 6 7 12 156 18 21
-------- -------- -------- -------
Income Available for Common Stock $ 172179 $ 186199 $ 319498 $ 334533
======== ======== ======== =======
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
JuneSeptember 30, December 31,
1999 1998
------------ -----------
ASSETS
Current Assets
Cash and cash equivalents $ 8584 $ 73
Short-term investments 1820 17
Accounts receivable
Customers, net 1,1441,255 1,383
Related parties 295 14
Inventories
Fuel oil and nuclear fuel 159163 187
Gas stored underground 156152 130
Materials and supplies 165163 159
Prepayments 3436 50
--------- ---------
Total current assets 1,7901,878 2,013
Property, Plant, and Equipment
Electric 15,49315,592 16,924
Gas 7,1657,191 7,072
Construction work in progress 211202 273
--------- ---------
Total property, plant, and equipment (at original cost) 22,86922,985 24,269
Accumulated depreciation and decommissioning (10,315)(10,409) (11,397)
--------- ---------
Net property, plant, and equipment 12,55412,576 12,872
Other Noncurrent Assets
Regulatory assets 5,4655,306 6,288
Nuclear decommissioning funds 1,2381,225 1,172
Other 673756 605
-------- --------
Total noncurrent assets 7,3767,287 8,065
-------- --------
TOTAL ASSETS $ 21,72021,741 $ 22,950
======== ========
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
JuneSeptember 30, December 31,
1999 1998
------------ -----------
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings $ -77 $ 668
Current portion of long-term debt 453443 260
Current portion of rate reduction bonds 282286 290
Accounts payable
Trade creditors 526618 718
Related parties 6550 60
Regulatory balancing accounts 685934 79
Other 338355 374
Accrued taxes 585233 2
Deferred income taxes 26 3
Other 484 561564 558
-------- -------
Total current liabilities 3,4183,586 3,012
Noncurrent Liabilities
Long-term debt 5,0515,025 5,444
Rate reduction bonds 2,1812,108 2,321
Deferred income taxes 2,4242,280 3,060
Deferred tax credits 250241 283
Other 2,2122,233 2,045
-------- -------
Total noncurrent liabilities 12,11811,887 13,153
Preferred Stock With Mandatory Redemption Provisions
6.30% and 6.57%, outstanding 5,500,000 shares, due 2002-2009 137 137
Company Obligated Mandatorily Redeemable Preferred Securities of
Trust Holding Solely Utility Subordinated Debentures
7.90%, 12,000,000 shares due 2025 300 300
Stockholders' Equity
Preferred stock without mandatory redemption provisions
Nonredeemable - 5% to 6%, outstanding 5,784,825 shares 145 145
Redeemable - 4.36% to 7.04%, outstanding 5,973,456 shares 142 142
Common stock, $5 par value, authorized 800,000,000 shares,
issued and outstanding 321,314,760 and 341,353,455 1,607 1,707
Additional paid in capital 1,971 2,094
Reinvested earnings 1,8821,966 2,260
-------- --------
Total stockholders' equity 5,7475,831 6,348
Commitments and Contingencies (Notes 2 and 6) - -
-------- --------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 21,72021,741 $ 22,950
======== ========
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 sixnine months ended JuneSeptember 30, 1999 1998
----------- -----------
Cash Flows From Operating Activities
Net income $ 331516 $ 349554
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, amortization, and decommissioning 891 5971,513 1,292
Deferred income taxes and tax credits-net (669) (79)(799) (297)
Other deferred charges and noncurrent liabilities (189) 327(496) 162
Net effect of changes in operating assets
and liabilities:
Accounts receivable 239 43128 339
Regulatory balancing accounts payable 606 (138)855 269
Inventories and prepayments 12 197
Accounts payable - trade (192) (45)(100) 116
Accrued taxes 583 154231 265
Other working capital (71) (58)(10) 24
Other-net 27 1376 24
--------- ---------
Net cash provided by operating activities 1,568 1,1821,926 2,755
--------- ---------
Cash Flows From Investing Activities
Capital expenditures (600) (671)(848) (963)
Proceeds from sale of assets 1,014 -
Other-net - 8321 297
--------- ---------
Net cash usedprovided (used) by investing activities 414 (588)187 (666)
--------- ---------
Cash Flows From Financing Activities
Net repayments under credit facilities (668)(591) -
Long-term debt matured, redeemed, or repurchased (369) (618)(474) (1,175)
Preferred stock redeemed or repurchased - (63)(107)
Common stock repurchased (725) (800)(1,600)
Dividends paid (208) (230)
Other-net 1 (8)(309) (337)
--------- ---------
Net cash used by financing activities (1,969) (1,719)(2,099) (3,219)
--------- ---------
Net Change in Cash and Cash Equivalents 13 (1,125)14 (1,130)
Cash and Cash Equivalents at January 1 90 1,223
--------- ---------
Cash and Cash Equivalents at JuneSeptember 30 $ 103104 $ 9893
========= =========
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized) $ 282363 $ 315401
Income taxes 226 260(net of refunds) 852 587
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.10-K, and the Corporation's and the
Utility's other reports filed with the Securities and Exchange Commission
since their 1998 Form 10-K was filed.
PG&E Corporation and the Utility believe that the accompanying statements
reflect all adjustments that are necessary to present a fair statement of the
consolidated financial position and results of operations for the interim
periods. All material adjustments are of a normal recurring nature unless
otherwise disclosed in this Form 10-Q. All significant intercompany
transactions have been eliminated from the consolidated financial statements.
Certain amounts in the prior year's consolidated financial statements have
been reclassified to conform to the 1999 presentation. Results of operations
for interim periods are not necessarily indicative of results to be expected
for a full year.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions. These estimates and assumptions affect the reported amounts of
revenues, expenses, assets, and liabilities and the disclosure of
contingencies. Actual results could differ from these estimates.
NOTE 2: CALIFORNIA ELECTRIC INDUSTRY RESTRUCTURING
In 1998, California became one of the first states in the country to
implement electric industry restructuring legislation and establish a
competitive market for electric generation. In a transition to a competitive
market, the restructuring legislation recognized that market-based revenues
may not be sufficient to recover (that is, collect from customers) all of the
Utility's generation costs. The restructuring legislation provides the
California investor-owned utilities the opportunity to recover such
uneconomic generation costs (called transition costs) until the earlier of
December 31, 2001, or when the utilities have recovered their authorized
transition costs as determined by the California Public Utilities Commission
(CPUC). The period during which transition costs may be recovered is called
the transition period. The legislation permits certain transition costs to
be recovered after the transition period.
The restructuring legislation has four principal elements: (1) the
establishment of a competitive market framework, (2) an electric rate freeze
and rate reduction, (3) the recovery of transition costs, and (4) divestiture
of utility-owned generation facilities. Each element is discussed below.
Competitive Market Framework:
- -----------------------------
To create a competitive generation market, a Power Exchange (PX) and an
Independent System Operator (ISO) began operating on March 31, 1998. During
the transition period, the Utility is required to bid or schedule into the PX
and ISO markets all of the electricity generated by its power plants and
electricity acquired under contractual agreements with unregulated
generators. Also during the transition period, the Utility is required to
buy from the PX all electricity needed to provide service to retail customers
that continue to choose the Utility as their electricity supplier. The ISO
schedules delivery of electricity for all market participants. The Utility
continues to own and maintain a portion of the transmission system, but the
ISO controls the operation of the system.
Among other changes to the ISO and PX market structure, on October 1,
1999, the ISO increased the price limitation on acceptable bids for
electricity and ancillary services (standby power and miscellaneous services)
from $250 per megawatt hour to $750 per megawatt hour. The increased price
limitation may increase the price volatility of energy and ancillary services
purchased in ISO and PX markets. The ISO's authority to impose price
limitations on acceptable bids will expire on November 15, 1999, unless
extended by the Federal Energy Regulatory Commission (FERC). The Utility's
cost of energy is recovered from retail customers under the terms of the
restructuring plan.
For the three- and six-monthnine-month periods ended JuneSeptember 30, 1999 and 1998,
the cost of electric energy for the Utility, reflected on the Statement of
Consolidated Income, is comprised of the cost of PX purchases, ancillary
services (standby power and miscellaneous services) purchased from the ISO, cost of transmission, and the cost of
Utility generation, net of sales to the PX as follows:
Three months ended June 30, SixNine months ended
JuneSeptember 30, September 30,
1999 1998 1999 1998
-------- -------- -------- --------
(in millions)
Cost of electric generation $ 398409 $ 490562 $ 7681,177 $ 9641,526
Cost of purchases from the PX 174 110 326 110384 380 710 490
Cost of ancillary services 111 86 221 86170 179 391 265
Proceeds from sales to the PX (157) (233) (380) (233)(217) (471) (597) (704)
-------- -------- -------- --------
Cost of electric energy $ 526746 $ 453650 $ 9351,681 $ 9271,577
-------- -------- -------- --------
The Utility's cost of energy is recovered from retail customers under the
terms of the restructuring plan.
Rate Freeze and Rate Reduction:
- -------------------------------
Legislation required an electric rate freeze and an electric rate reduction
to extend throughout the transition period. The Utility has held rates for
its larger customers at 1996 levels, and it will hold their rates at that
level until the end of the transition period. On January 1, 1998, the
Utility reduced electric rates for its residential and small commercial
customers by 10 percent from 1996 levels, and it will hold their rates at
that level until the end of the transition period. Collectively, these
actions are called a rate freeze.
To pay for the 10 percent rate reduction, the Utility refinanced $2.9
billion of its transition costs with the proceeds from rate reduction bonds.
The bonds allow for the rate reduction by lowering the carrying cost on a
portion of the transition costs and by deferring recovery of a portion of
these transition costs until after the transition period. During the rate
freeze, the rate reduction bond debt service will not increase the Utility
customers' electric rates. If the transition period ends before December 31,
2001, the Utility will be obligated to return a portion of the bond proceeds
to customers. The timing and exact amount of such portion, if any, has not
yet been determined.
The frozen rates include a component for transition cost recovery.
Transition costs are being recovered from all Utility distribution customers
through a nonbypassable charge regardless of the customer's choice of
electricity supplier. As the customer charge for transition costs is
nonbypassable, the Utility believes that the availability of choice to its
customers will not have a material impact on its ability to recover
transition costs.
Revenues from frozen electric rates provide for the recovery of authorized
Utility costs, including transmission and distribution service, public
purpose programs, nuclear decommissioning, and rate reduction bond debt
service. To the extent the revenues from frozen rates exceed authorized
Utility costs, the remaining revenues constitute the competitive transition
charge (CTC), which recovers the transition costs. These CTC revenues are
subject to seasonal fluctuations in the Utility's sales volumes and certain
other factors.
Transition Cost Recovery:
- -------------------------
Market-based revenues through sales to the PX may not be sufficient to
recover all of the Utility's generation costs. Under the California
restructuring legislation, the Utility has the opportunity to recover its
transition costs until the earlier of December 31, 2001, or when the Utility
has recovered its authorized transition costs as determined by the CPUC,
although certain transition costs can be recovered after the transition
period. At the conclusion of the transition period, the Utility will be at
risk to recover any of its remaining generation costs through market-based
revenues.
Transition costs consist of: (1) above-market sunk costs (costs associated
with Utility-owned generation assets that are fixed and unavoidable and
currently included in the Utility customers' electric rates) and future costs, such as
costs related to removal of Utility-owned generation facilities, (2) costs
associated with the Utility's long-term contracts to purchase power at above-marketabove-
market prices from qualifying facilities and other power suppliers, and (3)
generation-related regulatory assets and obligations. (In general,
regulatory assets are expenses deferred in the current or prior periods, to
be included in rates in subsequent periods.)
Above-market sunk costs result when the book value of a facility is in
excess of its market value. Conversely, below-market sunk costs result when
the market value of a facility is in excess of its book value. The total
amount of generation facility costs to be included as transition costs will
be based on the aggregate of above-market and below-market values. The
above-market portion of these costs is eligible for recovery as a transition
cost. The below-market portion of these costs will reduce other unrecovered
transition costs. These above- and below-market sunk costs are related to
generating facilities that are classified as either non-nuclear or nuclear
sunk costs.
The Utility cannot determine the exact amount of above-market non-nuclear
sunk costs that will be recoverable as transition costs until a market
valuation process (through appraisal, sale, or other valuation method) is
completed for each of its non-nuclear generation facilities. Several of
these valuations occurred in 1997 and 1998, when the Utility agreed to sell
seven of its electric generation plants to third parties. The total market
value of these facilities resulted in sales proceeds that exceeded the book
value and therefore has reduced the amount of transition costs remaining to
be recovered. The remainder of the valuation process is expected to be
completed by December 31, 2001. The Utility's remaining non-nuclear
generation facilities consist primarily of its hydroelectric generation
system. On September 30, 1999, the Utility filed an application with the
CPUC to determine the market value of its hydroelectric generating facilities
and related assets through an open, competitive auction. The Utility plans
to use an auction process similar to the one previously approved by the CPUC
and successfully used in the sale of the Utility's fossil and geothermal
plants. If the market value of the Utility's hydroelectric facilities is
determined based upon any method other than a sale of the facilities to a
third party, a material charge to Utility earnings could result. Any excess
of market value over book value would be used to reduce other transition
costs. (See Generation Divestiture below.)
Nuclear generation sunk costs were determined separately through a CPUC
proceeding and were subject to a final verification audit that was completed
in August 1998. The audit of the Utility's Diablo Canyon Nuclear Power Plant
(Diablo Canyon) accounts at December 31, 1996, resulted in the issuance of an
unqualified opinion. The audit verified that Diablo Canyon sunk costs at
December 31, 1996, were $3.3 billion of the total $7.1 billion construction
costs. The independent accounting firm also issued an agreed-upon special
procedures report, requested by the CPUC, that questioned $200 million of the
$3.3 billion sunk costs. The CPUC will review any proposed adjustments to
Diablo Canyon's recoverable costs that resulted from the report. At this
time, the Utility cannot predict what actions, if any, the CPUC may take
regarding the audit report.
Costs associated with the Utility's long-term contracts to purchase
electric power at above-market prices are included as transition costs. Over
the remaining life of these contracts the Utility estimates that it will
purchase 322 million megawatt-hours of electric power. To the extent that
the individual contract prices are above the market price, the Utility is
collecting the difference between the contract price and the market price
from customers, as a transition cost, over the term of the contract. The
contracts expire at various dates through 2028. The total amount of the
above-market costs under long-term contracts will be based on several
variables, including the capacity factors of the related generating
facilities and future market prices for electricity. During the six-monthnine-month
period ended JuneSeptember 30, 1999, the average price paid per kilowatt-hour
(kWh) under the Utility's long-term contracts for electric power was 6.16.4
cents per kWh. The average cost of electric energy for energy purchased at
market rates from the PX for the six-monthnine-month period ended JuneSeptember 30, 1999,
was 2.63.3 cents per kWh.
Generation-related regulatory assets and obligations (net generation-
related regulatory assets) are included as transition costs. At JuneSeptember
30, 1999, the Utility's generation-related net regulatory assets totaled $4.5$4.4
billion.
Most transition costs can be recovered until December 31, 2001. This
recovery period is significantly shorter than the recovery period of the
generation assets prior to restructuring and is referred to as accelerated
recovery. Accordingly, the Utility is amortizing its transition costs,
including most generation-related regulatory assets over the transition
period. During the transition period, the Utility is receiving a reduced
return on common equity for all of its generation assets, including those
generation assets reclassified to regulatory assets. The reduced return on
common equity is 6.77 percent.
Certain transition costs can be recovered through a non-bypassable charge
to distribution customers after December 31, 2001.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, (3) up
to $95 million of transition costs after the transition period to the extent
that the recovery of such costs during the transition period was displaced by
the recovery of electric industry restructuring implementation costs, and (4)
transition costs financed by the rate reduction bonds. Transition costs
financed by the issuance of rate reduction bonds are expected to be recovered
over the term of the bonds. In addition, the Utility's nuclear
decommissioning costs are being recovered through a CPUC-authorized charge,
which will extend until sufficient funds exist to decommission the nuclear
facility. During the rate freeze the charge for these costs will not
increase the Utility customers' electric rates. Excluding these exceptions,
the Utility will write off any transition costs not recovered during the
transition period.
Revenues provided for the recovery of most non-nuclear transition costs
are based upon the acceleration of such costs within the transition period.
For Diablo Canyon transition costs, revenues provided for transition cost
recovery are based on: (1) an established incremental cost incentive price
(ICIP) per kWh generated by Diablo Canyon to recover certain ongoing costs
and capital additions, and (2) the accelerated recovery of the investment in
Diablo Canyon from a period ending in 2016 to a five-year period ending
December 31, 2001. InOn September 1, 1999, a pending proceeding,proposed decision was issued by
an administrative law judge of the CPUC is currently
considering whetherthat, among other matters, would
terminate the Utility mayUtility's ability to continue to recover revenues related to
Diablo Canyon based on the ICIP through December 31, 2001, or must cease recovery of such revenues if itonce the Utility has completed recovery of
all other utility generation-relatedUtility-owned generation related transition costs priorcosts. The Utility had
argued that it should be entitled to rely on the CPUC decision establishing
the ICIP mechanism which stated that date.the ICIP mechanism would continue
through December 31, 2001. The proposed decision is subject to comment by
the parties and change by the full CPUC before a final decision is issued.
The CPUC is expected to issue a final decision in the near future.
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 sixnine months ended JuneSeptember 30, 1999, regulatory
assets related to electric utility restructuring decreased by $813$954 million,
which reflects the recovery of eligible transition costs.
During the transition period, the CPUC reviews the Utility's compliance
with the accounting methods established in the CPUC's decisions governing
transition cost recovery and the amount of transition costs requested for
recovery. The CPUC is currently reviewing non-nuclear transition costs
amortized during the first six months of 1998.
Generation Divestiture:
- -----------------------
In 1998, the Utility completed the sale of three fossil-fueled generation
plants for $501 million. These three fossil-fueled plants had a combined
book value at the time of the sale of $346 million and had a combined
capacity of 2,645 megawatts (MW).
On April 16, 1999, the Utility sold three other fossil-fueled generation
plants for $801 million. At the time of sale, these three fossil-fueled
plants had a combined book value of $256 million and had a combined capacity
of 3,065 MW.
On May 7, 1999, the Utility sold its complex of geothermal generation
facilities for $213 million. At the time of sale, these facilities had a
combined book value of $244 million and had a combined capacity of 1,224 MW.
The Utility will retainhas retained 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 which it has or will sell.sold. 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.
AnyThe gains from the sale of the Utility-ownedfossil-fueled generation plants will bewere used
to offset other transition costs. Likewise, any lossesthe loss from the sale of Utility-ownedthe
complex of geothermal generation plants are recoverablefacilities is being recovered as a
transition costs.cost.
On September 30, 1999, the Utility filed an application with the CPUC to
determine the market value of its hydroelectric generating facilities and
related assets through an open, competitive auction. The Utility proposes to
use an auction process similar to the one previously approved by the CPUC and
successfully used in the sale of the Utility's fossil and geothermal plants.
Under the process proposed in the application, another subsidiary of PG&E
Corporation, does not believe sales of any generation facilitiesPG&E Generating Company (PG&EGen), would be permitted to
a third
party will have a material impactparticipate in the auction on its results of operations.
In May 1998, the Utility notified thesame basis as other bidders.
The proposed auction process is estimated to take at least 21 weeks after
CPUC that it does not plan to retain
its hydroelectric generation assets as partapproval of the Utility. In December
1998,process. The CPUC proceedings related to the Utility filed with the CPUC its proposed
appraisal process for
valuing its hydroelectric facilities. The Utility withdrew its proposal in
March 1999 when the CPUC clarified that the CPUC proceeding would only apply
to assetsauction are likely to be retained in the Utility.contentious and involve many interested parties.
The Utility currently is evaluating
alternative strategies with respect to the valuation and disposition of its
hydroelectric facilities, including a potential transfer of the facilities to
another PG&E Corporation affiliate. Meanwhile, the California legislature is
reviewing legislative proposals that would address hydroelectric facilities
valuation and divestiture issues on an interim or permanent basis. If
legislation setting a valuation were enacted and the legislated valuation was
materially higher than the value ultimately recognized in connection with the
sale or other disposition of the assets, the Utility could suffer a material
loss upon the sale or other disposition of the hydroelectric assets. Iffacilities would be subject to certain
conditions, including the approval of the FERC and other agencies to the
transfer or re-issuance of various permits and licenses. In addition, FERC
must approve assignment of the Utility's Reliability Must Run Contract with
the ISO for any facility subject to such legislation were enacted, we expect thatcontract. Under the proposed
purchase and sale agreement, the CPUC's approval of the proposed sale on
terms acceptable to the Utility would challenge the
legality of legislation adopting such excess or interim valuation. Although
legislation could be passed priorin its sole discretion is also a condition
precedent to the close of the legislative session in
September 1999, the Corporation and Utility are unable to predict the nature
or likelihood of enactmentclosing of any such legislation.sale.
The CPUC may approve the Utility's auction application or rule that some
other method of valuation is appropriate.
At JuneSeptember 30, 1999, the book value of the Utility's net investment in
hydroelectric generation assets was approximately $0.8 billion, excluding
approximately $0.5 billion of net investment reclassified as regulatory
assets recoverable as transition costs. The value of the hydroelectric
assets is expected to exceed their book value by a material amount. In
connection with legislative discussions concerningAny
excess of market value over the $0.8 billion book value would be used to
reduce transition costs, including the remaining $0.5 billion of regulatory
assets related to the hydroelectric assets,
some third parties have publicly speculated that the value of the
hydroelectric assets could be in excess of $3 billion.generation assets. If the market value
of the hydroelectric generation assets is determined by any method other than
a sale of the assets to a third party, or if the winning bidder for any of
the auctioned assets is PG&EGen, a material charge to Utility earnings could
result. Any excess of market value over the $0.8 billion book value
would be used to reduce other transition costs, including the remaining $0.5
billion of regulatory assets related to the hydroelectric generation assets. The timing and nature of any such charge is dependent upon the
valuation method and procedure adopted, and the method of implementation, whichimplementation.
While transfer or sale to an affiliated entity such as PG&EGen may result in
a material charge to income, 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.
If the value of the hydroelectric generation assets is significantly
higher than the book value, the transition period could occur as soon as the third quarter of 1999.end before December
31, 2001.
Financial Impact of Electric Industry Restructuring:
- ----------------------------------------------------
The Utility's ability to continue recovering its transition costs will be
dependent on several factors, including: (1) the continued application of the
regulatory framework established by the CPUC and state legislation, (2) the
amount of transition costs ultimately approved for recovery by the CPUC, (3)
the determined value of the Utility's hydroelectric generation facilities,
(4) future Utility sales levels, (5) future Utility fuel and operating costs,
(6) the extent to which the Utility's authorized revenues to recover
distribution and transmission costs are increased or decreased, and (7) the
market price of electricity. Given the current evaluation of these factors,
PG&E Corporation believes that the Utility will recover its transition costs
under the terms of the approved transition plan. However, a change in one or
more of these factors could affect the probability of recovery of transition
costs and result in a material charge.
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 JuneSeptember 30, 1999. Short
and long positions pertaining to derivative contracts used for hedging
activities as of JuneSeptember 30, 1999, are immaterial.
Maximum
Natural Gas, Electricity, Purchase Sale Term in
and Natural Gas Liquids Contracts (Long) (Short) Years
- ---------------------------------------------------------------------
(billions of MMBtu equivalents (1))
Non-Hedging Activities
Swaps 3.90 3.733.18 3.14 7
Options 1.14 0.961.13 0.99 5
Futures 0.29 0.340.30 2
Forward Contracts 2.93 2.98 91.95 1.59 12
(1) One MMBtu is equal to one million British thermal units. PG&E
Corporation's electric power contracts, measured in megawatts, were converted
to MMBtu equivalents using a conversion factor of 10 MMBtu's per 1 megawatt-
hour. PG&E Corporation's natural gas liquids contracts were converted to
MMBtu equivalents using an appropriate conversion factor for each type of
natural gas liquids product.
Volumes shown for swaps represent notional volumes that are used to
calculate amounts due under the agreements and do not represent volumes
exchanged. Moreover, notional amounts are indicative only of the volume of
activity and are not a measure of market risk.
PG&E Corporation's net gains (losses) on swaps, options, futures, and
forward contracts held during the three- and six-monthnine-month periods ended
JuneSeptember 30, 1999 are as follows:
For the three-three For the six-nine
months ended months ended
JuneSeptember 30, 1999 JuneSeptember 30, 1999
- -------------------------------------------------------------------------------------------------------------------------------------------------------
(in millions)
Swaps $(131) $ 2(7) $ (5)
Options (29) (35)30 (5)
Futures 22 (20)(3) (23)
Forward contracts 131 95(35) 60
------ -----------
Net gain (loss) $ (7)(15) $ 4227
The following table discloses the estimated fair values of price risk
management assets and liabilities as of JuneSeptember 30, 1999. The ending and
average fair values and associated carrying amounts of derivative contracts
used for hedging purposes are not material as of JuneSeptember 30, 1999.
Average Ending
Fair Value Fair Value
- --------------------------------------------------------------------------
(in millions)
Assets
Non-Hedging Activities
Swaps $ 890743 $ 248301
Options 107 74109 116
Futures 240 45207 106
Forward Contracts 744 743685 506
------ ------
Total $1,981 $1,110$1,744 $1,029
Noncurrent portion 394322
Current portion $ 716707
Liabilities
Non-Hedging Activities
Swaps $ 821685 $ 231278
Options 128 83116 79
Futures 272 59235 122
Forward Contracts 645 616587 412
------ ------
Total $1,866$1,623 $ 989891
Noncurrent portion 281166
Current portion $ 708725
The credit exposure of the five largest counterparties comprised
approximately $285$245 million of the total credit exposure associated with
financial instruments used to manage price risk. Counterparties considered to
be investment grade or higher comprise 6771 percent of the total credit
exposure.
NOTE 4: ACQUISITIONS AND SALES
In September 1998, PG&E Corporation, through its indirect subsidiary USGen New
England, Inc. (USGenNE), completed the acquisition of a portfolio of electric
generating assets and power supply contracts from the New England Electric
System (NEES). The acquisition has been accounted for using the purchase
method of accounting. Accordingly, the purchase price has been allocated to
the assets purchased and the liabilities assumed based upon a preliminaryan assessment of
the fair values at the date of acquisition.
Including fuel and other inventories and transaction costs, PG&E
Corporation's financing requirements for this acquisition were approximately
$1.8 billion, funded through an aggregate of $1.3 billion of PG&E Generating
Company (PG&E Gen)&EGen) and USGenNE debt and a $425 million equity contribution
from PG&E Corporation. (On June 1, 1999, U.S. Generating Company changed its
name to PG&E Generating Company). The net purchase price has been
preliminarily allocated
as follows: (1) electric generating assets of $2.3 billion classified as
property, plant, and equipment; (2) receivable for support payments of $0.8
billion; and (3) contractual obligations of $1.3 billion classified as
current liabilities and other noncurrent liabilities. The assets include
hydroelectric, coal, oil, and natural gas generation facilities with a
combined generating capacity of 4,000 MW. In addition, USGenNE assumed 23
multi-year power-purchase agreements representing an additional 800 MW of
production capacity. USGenNE entered into agreements with NEES as part of
the acquisition, which: (1) provide that NEES shall make support payments
over the next ten years to USGenNE for the purchase power agreements; and (2)
require that USGenNE provide electricity to NEES under contracts that expire
over the next six to eleven years.
NOTE 5: UTILITY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF TRUST
HOLDING SOLELY UTILITY SUBORDINATED DEBENTURES
The Utility, through its wholly owned subsidiary, PG&E Capital I (Trust), has
outstanding 12 million shares of 7.90 percent cumulative quarterly income
preferred securities (QUIPS), with an aggregate liquidation value of $300
million. Concurrent with the issuance of the QUIPS, the Trust issued to the
Utility 371,135 shares of common securities with an aggregate liquidation
value of approximately $9 million. The only assets of the Trust are
deferrable interest subordinated debentures issued by the Utility with a face
value of approximately $309 million, an interest rate of 7.90 percent, and a
maturity date of 2025.
NOTE 6: COMMITMENTS AND CONTINGENCIES
Nuclear Insurance:
- ------------------
The Utility has insurance coverage for property damage and business
interruption losses as a member of Nuclear Electric Insurance Limited (NEIL).
Under this insurance, if a nuclear generating facility suffers a loss due to
a prolonged accidental outage, the Utility may be subject to maximum
retrospective assessments of $17 million (property damage) and $5$6 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 Utilityit 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 Utilityit for the storage or
disposal of potentially hazardous materials. Under federal and California
laws, the Utilityit may be responsible for remediation of hazardous substances, even if
the Utilityit 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 JuneSeptember
30, 1999, of $294$296 million for hazardous waste remediation costs at
identified sites, including divested fossil-fueled power plants.
Of the $294$296 million liability, discussed above, the Utility has recovered
$136$137 million and expects to recover $129$127 million in future rates.
Additionally, the Utility is mitigating its costs by obtaining recovery of
its costs from insurance carriers and from other third parties as
appropriate.
Environmental remediation at identified sites may be as much as $482$481
million if, among other things, other potentially responsible parties are
not financially able to contribute to these costs or further investigation
indicates that the extent of contamination or necessary remediation is
greater than anticipated. The Utility estimated this upper limit of the
range of costs using assumptions least favorable to the Utility, based upon
a range of reasonably possible outcomes. Costs may be higher if the Utility
is found to be responsible for cleanup costs at additional sites or outcomes
change.
Further, as discussed in Generation Divestiture above, the Utility will
retain the pre-closing remediation liability associated with divested
generation facilities.
PG&E Corporation believes the ultimate outcome of these matters will not
have a material impact on its or the Utility's financial position or results
of operations.
Legal Matters:
- --------------
Chromium Litigation:
Several civil suits are pending against the Utility in California state
courts. The suits seek an unspecified amount of compensatory and punitive
damages for alleged personal injuries and, in some cases, property damage, resulting from alleged exposure to
chromium in the vicinity of the Utility's gas compressor stations at Hinkley,
Kettleman, and Topock, California. Two
of these suits on behalf of six individuals also name PG&E Corporation as a
defendant. Currently, there are claims pending on
behalf of approximately 1,7001,650 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 fivefour separate suits filed by various Texas cities.
Generally, these cities allege, among other things, that: (1) owners or
operators of pipelines occupied city property and conducted pipeline
operations without the cities' consent and without compensating the cities;
and (2) the gas marketers failed to pay the cities for accessing and
utilizing the pipelines located in the cities to flow gas under city streets.
Plaintiffs also allege various other claims against the defendants for
failure to secure the cities' consent. Damages are not quantified.
In 1998, a jury trial was held in the separate suit brought by the City of
Edinburg (the City). This suit involved, among other things, a particular
franchise agreement entered into by a former subsidiary of PG&E GTT (now
owned by Southern Union Gas Company (SU)) and the City and certain conduct of
the defendants.
On December 1, 1998, based on the jury verdict, the court entered a
judgment in the City's favor, and awarded damages of $5.3 million, and
attorneys' fees of up to $3.5 million plus interest. The court found that
various PG&E GTT and SU defendants were jointly and severally liable for $3.3
million of the damages and all the attorneys' fees. Certain PG&E GTT
subsidiaries were found solely liable for $1.4 million of the damages. The
court did not clearly indicate the extent to which the PG&E GTT defendants
could be found liable for the remaining damages. The PG&E GTT defendants are
in the process of appealing the judgment.
PG&E Corporation believes that the ultimate outcome of these matters
could have a material adverse impact on its financial position or its
results of operations.
The Utility's 1999 General Rate Case (GRC):
- -------------------------------------------
In December 1997, the Utility filed its 1999 GRC application with the CPUC.
During the GRC process, the CPUC examines the Utility's distribution costs to determine
the amount the Utility may charge customers. The Utility has requested
distribution revenue increases to maintain and improve gas and electric
distribution reliability, safety, and customer service. The requested
revenues, as updated, include an increase of $445 million in electric base
revenues and an increase of $377 million in gas base revenues over authorized
1998 revenues. The Office of Ratepayer Advocates (ORA) branch of the CPUC
has recommended a decrease of $80 million in electric revenues and an
increase of $104 million in gas base revenues. Recommendations by the ORA do
not represent the positions of the CPUC.
In December 1998, the CPUC issued a decision on interim rate relief in the
GRC. The decision granted the Utility's request to increase its electric
revenues by $445 million and its gas revenues by $377 million on an interim
basis pending a decision in the GRC. The decision allows the Utility to
reflect the revenue increases, resulting from the Utility request, in
regulatory assets recorded under regulatory adjustment mechanisms approved by
the CPUC. TheHowever, 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, theThe Utility's 1999 earnings are based on the authorized amount of
revenues in effect during 1998 and do not include any portion of the
requested revenue increase. When a final decision in the GRC is issued by
the CPUC, the Utility's regulatory assets and net income will be adjusted to
reflect any
differences between the amount of revenues currently being recognized and
the amountrevenue 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 has identified five reporting operating segments. The
Utility is one reportable operating segment and the other four are part of
PG&E Corporation's National Energy Group. These five reportable operating
segments provide different products and services and are subject to different
forms of regulation or jurisdictions. PG&E Corporation's reportable segments
are described below.
Utility: PG&E Corporation's Northern and Central California energy utility
subsidiary, Pacific Gas and Electric Company, provides natural gas and
electric service to one of every 20 Americans.
Wholesale Business Operations:National Energy Group: PG&E Corporation's wholesale business
operations consistNational Energy Group consists
of PG&E GenGenerating Company (PG&EGen) which develops, builds, operates, owns,
and manages power generation facilities that serve wholesale and industrial
customers; PG&E Gas Transmission (PG&E GT) which owns and operates
approximately 9,000 miles of natural gas pipelines, approximately 500 miles
of natural gas liquids pipelines, a storage facility, and natural gas
processing plants in the Pacific Northwest (PG&E GT NW) and Texas; andTexas (PG&E GTT);
PG&E Energy Trading (PG&E ET) which purchases and sells energy commodities
and provides risk management services to customers in major North American
markets, including, serving PG&E Corporation's other non-utility businesses,
unaffiliated utilities, marketers, municipalities, and large end-use
customers.
Retail Business Operations: PG&E Corporation's retail business operations
consist ofcustomers; and PG&E Energy Services (PG&E ES) which provides competitively
priced electricity, natural gas, and related services to industrial,
commercial, and institutional customers.
Segment information for the three- and six-monthnine-month periods ended JuneSeptember
30, 1999 and 1998, respectively, were as follows:
Wholesale Retail
---------------------------------- -------National Energy Group
----------------------------------------------------
PG&E GT ParentElimi-
---------------- nations & Elimi-
Utility PG&E Gen&EGen NW Texas PG&E ET PG&E ES nations(1)Other (1) Total
------- ------- ------- ------- ------- ------- ------- -------
(in millions)
For the three monththree-month period ended:
- ---------------------------------
JuneSeptember 30, 1999
Operating revenues $ 2,2312,584 $ 253273 $ 3942 $ 397 $1,767161 $3,151 $ 138163 $ (5)6 $ 4,8206,380
Intersegment revenues 3 2 1 13 39 257 4 (316)14 16 339 3 (377) -
------- ------- ------- ------- ------- ------- ------- -------
Total operating
revenues 2,233 254 52 436 2,024 142 (321) 4,8202,587 275 56 177 3,490 166 (371) 6,380
Net income 172179 19 13 (8) 1 (14) (3) 180
June18 (7) (17) (12) 3 183
September 30, 1998
Operating revenues $ 2,1162,562 $ 115151 $ 4645 $ 431 $1,983397 $2,053 $ 9299 $ 4- $ 4,7875,307
Intersegment revenues 1 - 12 91 77 - (181)4 13 56 103 9 (186) -
------- ------- ------- ------- ------- ------- ------- -------
Total operating
revenues 2,117 1152,563 155 58 522 2,060 92 (177) 4,787453 2,156 108 (186) 5,307
Net income 186 34 15 (19) 1 (14) (29) 174199 30 16 (22) - (15) 2 210
For the six monthnine-month period ended:
- -------------------------------
June--------------------------------
September 30, 1999
Operating revenues $ 4,3146,898 $ 541814 $ 85127 $ 710 $4,163871 $7,314 $ 269432 $ (5) $10,0771 $16,457
Intersegment revenues 7 4 2 25 83 492 8 (614)39 99 831 11 (991) -
------- ------- ------- ------- ------- ------- ------- -------
Total operating
revenues 4,318 543 110 793 4,655 277 (619) 10,0776,905 818 166 970 8,145 443 (990) 16,457
Net income 319 51 28 (32) (2) (22) (6) 336498 70 46 (39) (19) (34) (3) 519
Total assets at
JuneSeptember 30, 1999 21,720 3,868 1,158 2,587 2,067 192 (166) 31,426
June21,741 3,858 1,162 2,548 2,195 186 (204) 31,486
September 30, 1998
Operating revenues $ 4,1416,703 $ 199350 $ 94139 $1,261 $5,753 $ 864 $3,700 $ 135234 $ 7 $ 9,140$14,447
Intersegment revenues 2 - 25 173 137 - (337)3 4 38 229 240 9 (523) -
------- ------- ------- ------- ------- ------- ------- -------
Total operating
revenues 4,143 199 119 1,037 3,837 135 (330) 9,1406,706 354 177 1,490 5,993 243 (516) 14,447
Net income 334 43 30 (29)533 73 46 (51) - (25) (40) 313(38) 523
Total assets at
JuneSeptember 30, 1998 23,618 1,224 1,168 2,713 1,863 106 (501) 30,19122,468 4,326 1,167 2,715 2,053 177 (188) 32,718
(1) Net income on intercompany positions recognized by segments using mark to market accounting
is eliminated. Intercompany transactions are also eliminated. Corporation overhead is charged
to each subsidiary. Corporation interest expense and taxes are allocated to the National
Energy Group.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS
PG&E Corporation (the Corporation) is an energy-based holding company
headquartered in San Francisco, California. PG&E Corporation's businesses
provide energy services throughout North America. PG&E Corporation's
Northern and Central California energy utility subsidiary, Pacific Gas and
Electric Company (the Utility), provides natural gas and electric service to
one of every 20 Americans. PG&E Corporation's four other businesses, known
as the National Energy Group, provide a wide range of energy products and
services through its wholesale and retail business operations.
PG&E Corporation's wholesale business operations consistThe National Energy Group consists of PG&E Generating Company (PG&E Gen)&EGen),
formerly known as U.S. Generating Company, which develops, builds, operates,
owns, and manages power generation facilities that serve wholesale and
industrial customers; PG&E Gas Transmission (PG&E GT) which owns and operates
approximately 9,000 miles of natural gas pipelines, approximately 500 miles
of natural gas liquids pipelines, a storage facility, and natural gas
processing plants in the Pacific Northwest (PG&E GT NW) and Texas (PG&E GTT);
and PG&E Energy Trading (PG&E ET) which purchases and sells energy commodities
and provides risk management services to customers in major North American
markets, including, serving PG&E Corporation's other non-utility businesses,
unaffiliated utilities, marketers, municipalities, and large end-use
customers.
PG&E Corporation's retail business operations consist ofcustomers; and PG&E Energy Services (PG&E ES) which provides competitively
priced electricity, natural gas, and related services to industrial,
commercial, and institutional customers.
This is a combined Quarterly Report on Form 10-Q of PG&E Corporation and
Pacific Gas and Electric Company. It includes separate consolidated
financial statements for each entity. The consolidated financial statements
of PG&E Corporation reflect the accounts of PG&E Corporation, the Utility,
and PG&E Corporation's other wholly owned and controlled subsidiaries. The
consolidated financial statements of the Utility reflect the accounts of the
Utility and its wholly owned subsidiaries. This Management's Discussion and
Analysis (MD&A) should be read in conjunction with the consolidated financial
statements included herein. Further, this quarterly report should be read in
conjunction with the Corporation's and the Utility's Consolidated Financial
Statements and Notes to Consolidated Financial Statements incorporated by
reference in their combined 1998 Annual Report on Form 10-K.10-K and the
Corporation's and the Utility's other reports filed with the Securities and
Exchange Commission since their 1998 Form 10-K was filed.
This combined Quarterly Report on Form 10-Q, including this MD&A, contains
forward-looking statements about the future that are necessarily subject to
various risks and uncertainties. These statements are based on the beliefs
and assumptions of management which management believes are reasonable and on
information currently available to management. These forward-looking
statements are identified by words such as "estimates," "expects,"
"anticipates," "plans," "believes", "speculates", and other similar
expressions.
Factors that could cause future results to differ materially from those
expressed in or implied by the forward-looking statements or historical
results include the impact or outcome of:include:
- - the pace and extent of the ongoing restructuring of the electric and gas
industries across the United States;
- - the outcome of regulatory and legislative proceedings and operational changes related to industry restructuring, including the valuation of the
Utility's hydroelectric generation facilities and changes in
the Utility's business processes and systems;
- - the method and timing of disposition and valuation of the Utility's
hydroelectric generation assets;
- - any changes in the amount the Utility is allowed to collect (recover) from
its customers for certain costs which prove to be uneconomic under the new
competitive market (called transition costs) in accordance with the Utility's
plan for recovering those costs;;
- - the successful integration and performance of our recently acquired assets;
- - our ability to successfully compete outside our traditional regulated
markets;
- - internal and external Year 2000 software and hardware issues;
- - the outcome of the Utility's various regulatory proceedings, including: the
1999 general rate case; the proposal to adopt performance based ratemaking
(PBR); the proposal to auction the Utility's hydroelectric generation assets;
the transmission rate case applications; and post-transition period
ratemaking proceedings;
- - fluctuations in commodity gas and electric prices and our ability to
successfully manage such price fluctuations; and
- - the pace and extent of competition in the California generation market and
its impact on the Utility's costs and resulting collection of transition
costs.
Although the ultimate impacts of the above factors are uncertain, these
and other factors may cause future earnings to differ materially from results
or outcomes we currently seek or expect. Each of these factors is discussed
in greater detail in this MD&A.
In this MD&A, we first discuss our competitive and regulatory environment.
We then discuss earnings and changes in our results of operations for the
three- and six-monthnine-month periods ended JuneSeptember 30, 1999 and 1998. Finally, we
discuss liquidity and financial resources, various uncertainties that could
affect future earnings, and our risk management activities. Our MD&A applies
to both PG&E Corporation and the Utility.
Competitive and Regulatory Environment
This section provides a discussion of the competitive environment in the
evolving energy industry, the California electric industry restructuring, the
New England electricity market, and regulatory matters.
The Competitive Environment in the Evolving Energy Industry
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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 naturalregulated 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(often a local gas distribution
company) buys the gas commodity from the pipeline.
In the electric industry, the Public Utilities Regulatory Policies Act of
1978 specifically provided that unregulated companies could become wholesale
generators of electricity and that utilities were required to purchase and
use power generated by these unregulated companies in meeting their
customers' needs. The National Energy Policy Act of 1992 was designed to
increase competition in the wholesale unregulated generation market by
requiring access to electric utility transmission systems by all wholesale
unregulated generators, sellers, and buyers of electricity. Now, an
increasing number of states throughout the country either have implemented
plans or are considering proposals to separate the generation from the
transmission and distribution of electricity through some form of electric
industry restructuring.
To date, the states, not the federal government, have taken the initiative
on electric industry restructuring at the retail level. While at least five
bills mandating deregulation of the electric industry were introduced in the
U.S. Congress over the past two years, none have been passed. As a result,
the pace, extent, and methods for restructuring the electric industry vary
widely throughout the country. For instance, as of JuneSeptember 30, 1999,
twenty21 states have enacted electric industry restructuring legislation,
including California, Texas, Illinois, Pennsylvania, New Jersey,
Massachusetts, Rhode Island, and Connecticut. Other states, such as Oregon, are seriously
considering restructuring proposals. There also are some states
that have passed legislation precluding or significantly slowing down
deregulation. Differences in how individual states view electric industry
restructuring often relate to the existing unit cost of energy supplies
within each state. Generally, states having higher energy unit costs are
moving more quickly to deregulate energy supply markets.
Implementation of our national energy strategy depends, in part, upon the
opening of energy markets to provide customer choice of supplier. Undue
delays by states or federal legislation to deregulate the electric generation
and natural gas supply business could impact the pace of growth of our
wholesale and retail business operations.National Energy Group.
California Industry Restructuring
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The Electric Business:
In 1998, California became one of the first states in the country to
implement electric industry restructuring. Today, many Californians may
choose to purchase their electricity from investor-owned utilities such as
Pacific Gas and Electric Company, or unregulated retail electricity suppliers
(for example, marketers, including PG&E Energy Services, brokers, and
aggregators). The restructuring contemplates that the investor-owned
utilities, including the Utility, will continue to provide distribution
services to substantially all customers within their service territories,
including providing electricity to customers who choose not to be served by
another service provider.
The restructuring legislation recognized that market-based revenues may
not be sufficient to recover (that is, collect from customers) all of the
Utility's generation costs. The restructuring legislation provides the
California investor-owned utilities the opportunity to recover such
uneconomic generation costs (called transition costs) until the earlier of
December 31, 2001, or when the utilities have recovered their authorized
transition costs as determined by the California Public Utilities Commission
(CPUC). The period during which transition costs may be recovered is called
the transition period. The legislation permits certain transition costs to
be recovered after the transition period.
California electric industry restructuring legislation has four principal
elements: (1) the establishment of a competitive market framework, (2) an
electric rate freeze and rate reduction, (3) the recovery of transition
costs, and (4) divestiture of utility-owned generation facilities. Each
element is discussed below.
Competitive Market Framework: To create a competitive generation market, a
Power Exchange (PX) and an Independent System Operator (ISO) began operating
on March 31, 1998. During the transition period, the Utility is required to
bid or schedule into the PX and ISO markets all of the electricity generated
by its power plants and electricity acquired under contractual agreements
with unregulated generators. Also during the transition period, the Utility
is required to buy from the PX all electricity needed to provide service to
retail customers that continue to choose the Utility as their electricity
supplier. The ISO schedules delivery of electricity for all market
participants. The Utility continues to own and maintain a portion of the
transmission system, but the ISO controls the operation of the system.
Among other changes to the ISO and PX market structure, on October 1,
1999, the ISO increased the price limitation on acceptable bids for
electricity and ancillary services (standby power and miscellaneous services)
from $250 per megawatt-hour to $750 per megawatt-hour. The increased price
limitation may increase the price volatility of energy and ancillary services
purchased in ISO and PX markets. The ISO's authority to impose price
limitations on acceptable bids will expire on November 15, 1999, unless
extended by the FERC.
During 1998 and 1999, the Utility continued its efforts to develop and
implement changes to its business processes and systems, including the
customer information and billing system, to accommodate electric industry
restructuring. To the extent that the Utility is unable to develop and
implement such changes in a successful and timely manner, there could be an
adverse impact on the Utility's or PG&E Corporation's future results of
operations.
Rate Freeze and Rate Reduction: Legislation required an electric rate freeze
and an electric rate reduction to extend throughout the transition period.
The Utility has held rates for its larger customers at 1996 levels, and it
will hold their rates at that level until the end of the transition period.
On January 1, 1998, the Utility reduced electric rates for its residential
and small commercial customers by 10 percent from 1996 levels, and it will
hold their rates at that level until the end of the transition period.
Collectively, these actions are called a rate freeze.
To pay for the 10 percent rate reduction, the Utility refinanced $2.9
billion of its transition costs with the proceeds from rate reduction bonds.
The bonds allow for the rate reduction by lowering the carrying cost on a
portion of the transition costs and by deferring recovery of a portion of
these transition costs until after the transition period. During the rate
freeze, the rate reduction bond debt service will not increase the Utility
customers' electric rates. If the transition period ends before December 31,
2001, the Utility will be obligated to return a portion of the bond proceeds
to customers. The timing and exact amount of such portion, if any, has not
yet been determined.
The frozen rates include a component for transition cost recovery.
Transition costs are being recovered from all Utility distribution customers
through a nonbypassable charge regardless of the customer's choice of
electricity supplier. As the customer charge for transition costs is
nonbypassable, the Utility believes that the availability of choice to its
customers will not have a material impact on its ability to recover
transition costs.
Revenues from frozen electric rates provide for the recovery of authorized
Utility costs, including transmission and distribution service, public
purpose programs, nuclear decommissioning, and rate reduction bond debt
service. To the extent the revenues from frozen rates exceed authorized
Utility costs, the remaining revenues constitute the competitive transition
charge (CTC), which recovers the transition costs. These CTC revenues are
subject to seasonal fluctuations in the Utility's sales volumes and certain
other factors.
Transition Cost Recovery: Market-based revenues through sales to the PX may
not be sufficient to recover all of the Utility's generation costs. Under
the California restructuring legislation, the Utility has the opportunity to
recover its transition costs until the earlier of December 31, 2001, or when
the Utility has recovered its authorized transition costs as determined by
the CPUC, although certain transition costs can be recovered after the
transition period. At the conclusion of the transition period, the Utility
will be at risk to recover any of its remaining generation costs through
market-based revenues.
Transition costs consist of: (1) above-market sunk costs (costs associated
with Utility-owned generation assets that are fixed and unavoidable and
currently included in the Utility customers' electric rates) and future costs, such as
costs related to removal of Utility-owned generation facilities, (2) costs
associated with the Utility's long-term contracts to purchase power at above-marketabove-
market prices from qualifying facilities and other power suppliers, and (3)
generation-related regulatory assets and obligations. (In general,
regulatory assets are expenses deferred in the current or prior periods, to
be included in rates in subsequent periods.)
Above-market sunk costs result when the book value of a facility is in
excess of its market value. Conversely, below-market sunk costs result when
the market value of a facility is in excess of its book value. The total
amount of generation facility costs to be included as transition costs will
be based on the aggregate of above-market and below-market values. The
above-market portion of these costs is eligible for recovery as a transition
cost. The below-market portion of these costs will reduce other unrecovered
transition costs. These above- and below-market sunk costs are related to
generating facilities that are classified as either non-nuclear or nuclear
sunk costs.
The Utility cannot determine the exact amount of above-market non-nuclear
sunk costs that will be recoverable as transition costs until a market
valuation process (through appraisal, sale, or other valuation method) is
completed for each of its non-nuclear generation facilities. Several of
these valuations occurred in 1997 and 1998, when the Utility agreed to sell
seven of its electric generation plants to third parties. The total market
value of these facilities resulted in sales proceeds that exceeded the book
value and therefore has reduced the amount of transition costs remaining to
be recovered. The remainder of the valuation process is expected to be
completed by December 31, 2001. The Utility's remaining non-nuclear
generation facilities consist primarily of its hydroelectric generation
system. On September 30, 1999, the Utility filed an application with the
CPUC to determine the market value of its hydroelectric generating facilities
and related assets through an open, competitive auction. The Utility plans
to use an auction process similar to the one previously approved by the CPUC
and successfully used in the sale of the Utility's fossil and geothermal
plants. If the market value of the Utility's hydroelectric facilities is
determined based upon any method other than a sale of the facilities to a
third party, a material charge to Utility earnings could result. Any excess
of market value over book value would be used to reduce other transition
costs. (See Generation Divestiture below.)
Nuclear generation sunk costs were determined separately through a CPUC
proceeding and were subject to a final verification audit that was completed
in August 1998. The audit of the Utility's Diablo Canyon Nuclear Power Plant
(Diablo Canyon) accounts at December 31, 1996, resulted in the issuance of an
unqualified opinion. The audit verified that Diablo Canyon sunk costs at
December 31, 1996, were $3.3 billion of the total $7.1 billion construction
costs. The independent accounting firm also issued an agreed-
uponagreed-upon special
procedures report, requested by the CPUC, that questioned $200 million of the
$3.3 billion sunk costs. The CPUC will review any proposed adjustments to
Diablo Canyon's recoverable costs that resulted from the report. At this
time, the Utility cannot predict what actions, if any, the CPUC may take
regarding the audit report.
Costs associated with the Utility's long-term contracts to purchase
electric power at above-market prices are included as transition costs. Over
the remaining life of these contracts the Utility estimates that it will
purchase 322 million megawatt-hours of electric power. To the extent that
the individual contract prices are above the market price, the Utility is
collecting the difference between the contract price and the market price
from customers, as a transition cost, over the term of the contract. The
contracts expire at various dates through 2028. The total amount of the
above-market costs under long-term contracts will be based on several
variables, including the capacity factors of the related generating
facilities and future market prices for electricity. During the six-monthnine-month
period ended JuneSeptember 30, 1999, the average price paid per kilowatt-hour
(kWh) under the Utility's long-term contracts for electric power was 6.16.4
cents per kWh. The average cost of electric energy for energy purchased at
market rates from the PX for the six-monthnine-month period ended JuneSeptember 30, 1999,
was 2.63.3 cents per kWh.
Generation-related regulatory assets and obligations (net generation-
related regulatory assets) are included as transition costs. At JuneSeptember
30, 1999, the Utility's generation-related net regulatory assets totaled $4.5$4.4
billion.
Most transition costs can be recovered until December 31, 2001. This
recovery period is significantly shorter than the recovery period of the
generation assets prior to restructuring and is referred to as accelerated
recovery. Accordingly, the Utility is amortizing its transition costs,
including most generation-related regulatory assets over the transition
period. During the transition period, the Utility is receiving a reduced
return on common equity for all of its generation assets, including those
generation assets reclassified to regulatory assets. The reduced return on
common equity is 6.77 percent.
Certain transition costs can be recovered through a non-bypassable charge
to distribution customers after December 31, 2001.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, (3) up
to $95 million of transition costs after the transition period to the extent
that the recovery of such costs during the transition period was displaced by
the recovery of electric industry restructuring implementation costs, and (4)
transition costs financed by the rate reduction bonds. Transition costs
financed by the issuance of rate reduction bonds are expected to be recovered
over the term of the bonds. In addition, the Utility's nuclear
decommissioning costs are being recovered through a CPUC-authorized charge,
which will extend until sufficient funds exist to decommission the nuclear
facility. During the rate freeze the charge for these costs will not
increase the Utility customers' electric rates. Excluding these exceptions,
the Utility will write off any transition costs not recovered during the
transition period.
Revenues provided for the recovery of most non-nuclear transition costs
are based upon the acceleration of such costs within the transition period.
For Diablo Canyon transition costs, revenues provided for transition cost
recovery are based on: (1) an established incremental cost incentive price
(ICIP) per kWh generated by Diablo Canyon to recover certain ongoing costs
and capital additions, and (2) the accelerated recovery of the investment in
Diablo Canyon from a period ending in 2016 to a five-year period ending
December 31, 2001. InOn September 1, 1999, a pending proceeding,proposed decision was issued by
an administrative law judge of the CPUC is currently
considering whetherthat, among other matters, would
terminate the Utility mayUtility's ability to continue to recover revenues related to
Diablo Canyon based on the ICIP through December 31, 2001, or must cease recovery of such revenues if itonce the Utility has completed recovery of
all other utility generation-relatedUtility-owned generation related transition costs priorcosts. The Utility had
argued that it should be entitled to rely on the CPUC decision establishing
the ICIP mechanism which stated that date.the ICIP mechanism would continue
through December 31, 2001. The proposed decision is subject to comment by
the parties and change by the full CPUC before a final decision is issued.
The CPUC is expected to issue a final decision in the near future.
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 sixnine months ended JuneSeptember 30, 1999, regulatory
assets related to electric utility restructuring decreased by $813$954 million,
which reflects the recovery of eligible transition costs.
During the transition period, the CPUC reviews the Utility's compliance
with the accounting methods established in the CPUC's decisions governing
transition cost recovery and the amount of transition costs requested for
recovery. The CPUC is currently reviewing non-nuclear transition costs
amortized during the first six months of 1998.
Generation Divestiture: In 1998, the Utility completed the sale of three
fossil-fueled generation plants for $501 million. These three fossil-fueled
plants had a combined book value at the time of the sale of $346 million and
had a combined capacity of 2,645 megawatts (MW).
On April 16, 1999, the Utility sold three other fossil-fueled generation
plants for $801 million. At the time of sale, these three fossil-fueled
plants had a combined book value of $256 million and had a combined capacity
of 3,065 MW.
On May 7, 1999, the Utility sold its complex of geothermal generation
facilities for $213 million. At the time of sale, these facilities had a
combined book value of $244 million and had a combined capacity of 1,224 MW.
The Utility will retainhas retained 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 which it has or will sell.sold. 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.
AnyThe gains from the sale of the Utility-ownedfossil-fueled generation plants will bewere used
to offset other transition costs. Likewise, any lossesthe loss from the sale of Utility-ownedthe
complex of geothermal generation plants are recoverablefacilities is being recovered as a
transition costs.cost.
On September 30, 1999, the Utility filed an application with the CPUC to
determine the market value of its hydroelectric generating facilities and
related assets through an open, competitive auction. The Utility proposes to
use an auction process similar to the one previously approved by the CPUC and
successfully used in the sale of the Utility's fossil and geothermal plants.
Under the process proposed in the application, another subsidiary of PG&E
Corporation, does not believe sales of any generation facilitiesPG&EGen, would be permitted to a third
party will have a material impactparticipate in the auction on its results of operations.
In May 1998, the
Utility notified thesame basis as other bidders.
The proposed auction process is estimated to take at least 21 weeks after
CPUC that it does not plan to retain
its hydroelectric generation assets as partapproval of the Utility. In December
1998,process. The CPUC proceedings related to the Utility filed with the CPUC its proposed
appraisal process for
valuing its hydroelectric facilities. The Utility withdrew its proposal in
March 1999 when the CPUC clarified that the CPUC proceeding would only apply
to assetsauction are likely to be retained in the Utility.contentious and involve many interested parties.
The Utility currently is evaluating
alternative strategies with respect to the valuation and disposition of its
hydroelectric facilities, including a potential transfer of the facilities to
another PG&E Corporation affiliate. Meanwhile, the California legislature is
reviewing legislative proposals that would address hydroelectric facilities
valuation and divestiture issues on an interim or permanent basis. If
legislation setting a valuation were enacted and the legislated valuation was
materially higher than the value ultimately recognized in connection with the
sale or other disposition of the assets, the Utility could suffer a material
loss upon the sale or other disposition of the hydroelectric assets. Iffacilities would be subject to certain
conditions, including the approval of the FERC and other agencies to the
transfer or re-issuance of various permits and licenses. In addition, FERC
must approve assignment of the Utility's Reliability Must Run Contract with
the ISO for any facility subject to such legislation were enacted, we expect thatcontract. Under the proposed
purchase and sale agreement, the CPUC's approval of the proposed sale on
terms acceptable to the Utility would challenge the
legality of legislation adopting such excess or interim valuation. Although
legislation could be passed priorin its sole discretion is also a condition
precedent to the close of the legislative session in
September 1999, the Corporation and Utility are unable to predict the nature
or likelihood of enactmentclosing of any such legislation.sale.
The CPUC may approve the Utility's auction application or rule that some
other method of valuation is appropriate.
At JuneSeptember 30, 1999, the book value of the Utility's net investment in
hydroelectric generation assets was approximately $0.8 billion, excluding
approximately $0.5 billion of net investment reclassified as regulatory
assets recoverable as transition costs. The value of the hydroelectric
assets is expected to exceed their book value by a material amount. In
connection with legislative discussions concerningAny
excess of market value over the $0.8 billion book value would be used to
reduce transition costs, including the remaining $0.5 billion of regulatory
assets related to the hydroelectric assets,
some third parties have publicly speculated that the value of the
hydroelectric assets could be in excess of $3 billion.generation assets. If the market value
of the hydroelectric generation assets is determined by any method other than
a sale of the assets to a third party, or if the winning bidder for any of
the auctioned assets is PG&EGen, a material charge to Utility earnings could
result. Any excess of market value over the $0.8 billion book value
would be used to reduce other transition costs, including the remaining $0.5
billion of regulatory assets related to the hydroelectric generation assets. The timing and nature of any such charge is dependent upon the
valuation method and procedure adopted, and the method of implementation, whichimplementation.
While transfer or sale to an affiliated entity such as PG&EGen may result in
a material charge to income, 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.
If the value of the hydroelectric generation assets is significantly
higher than the book value, the transition period could occur as soon as the third quarter of 1999.end before December
31, 2001.
Financial Impact: The Utility's ability to continue recovering its transition
costs will be dependent on several factors including: (1) the continued
application of the regulatory framework established by the CPUC and state
legislation, (2) the amount of transition costs ultimately approved for
recovery by the CPUC, (3) the determined value of the Utility's hydroelectric
generation facilities, (4) future Utility sales levels, (5) future Utility
fuel and operating costs, (6) the extent to which the Utility's authorized
revenues to recover distribution and transmission costs are increased or
decreased, and (7) the market price of electricity. Given the current
evaluation of these factors, PG&E Corporation believes that the Utility will
recover its transition costs under the terms of the approved transition plan.
However, a change in one or more of these factors could affect the
probability of recovery of transition costs and result in a material charge.
The Gas Business:
Restructuring of the natural gas industry on both the national and the state
level has given choices to California utility customers to meet their gas
supply needs. The Gas Accord Settlement (Accord), a multi-party settlement
approved by the CPUC in 1997, continues the process of restructuring the gas
industry in California. The Accord was implemented in March 1998, and has
four principal elements:
1. The Accord separates or "unbundles" the rates for the Utility's gas
transportation system. The Utility now offers transmission, distribution, and storage
services as separate and distinct services to its noncore customers.
Unbundling gives these customersCustomers have the opportunity to select from a menu of services offered by
the Utility and enables them tothey pay only for the services that they use. Unbundling also makes accessAccess to the
transmission system is 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.end-users.
The Accord increases the opportunity for the Utility's core customers tocan 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,However, the Utility continues to purchase gas as a regulated
supplier for those core customers who request it, serving a majority of3.8 million 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 withregulated by 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. TheUnder the terms of the Gas Accord settled various regulatory issues involvingsettlement agreement, approved by 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 establishesCPUC in 1997, gas transmission rates within California for the period from
March 1998 through December 2002 for the Utility's core and noncore customers
were established and eliminates regulatory protection was eliminated for variations in
sales volumes for
noncore transmission revenues. As a result, the Utility is at risk for
variations between actual and forecasted noncore transmission throughput volumes.
However, we do not expect these variations to have a material adverse impact
on the Utility's or our financial position or results of operations.
Rates for gas distribution services will continue to be set by the CPUC
and designed to provide the Utility an opportunity to recover its costs of
service and include a return on its investment. The regulatory mechanisms
for setting gas distribution rates are discussed below under Regulatory
Matters.
New England Electricity Market:
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ThreeCertain New England states where our wholesale businesses operateNational Energy Group operates electric
generation facilities (Massachusetts, New Hampshire, and Rhode Island) were, like California, among the first states in the
country to introduce electric industry restructuring. Connecticut also has passed electric industry
restructuring legislation. As a result of this
restructuring and certain other regulatory initiatives, the wholesale
unregulated electricity market in New England features a bid-based market and
an ISO.
In September 1998, PG&E Corporation, through its indirect subsidiary USGen
New England, Inc. (USGenNE), completed the acquisition of a portfolio of
electric generation assets and power supply contracts from New England
Electric System (NEES). The purchased assets include hydroelectric, coal,
oil, and natural gas generation facilities with a combined generating
capacity of about 4,000 MW.
Including fuel and other inventories and transaction costs, the financing
requirements for this transaction were approximately $1.8 billion, funded
through an aggregate of $1.3 billion of PG&E Gen&EGen and USGenNE debt and a $425
million equity contribution from PG&E Corporation. The net purchase price
has been allocated as follows: (1) electric generating assets of $2.3
billion, (2) receivable for support payments of $0.8 billion, and (3) out of
market contractual obligations of $1.3 billion, relating to acquired power
purchase agreements, gas agreements and standard offer agreements.
As part of the New England electric industry restructuring, the local
utility companies providing service to retail customers were required to
offer Standard Offer Service (SOS) to their customers. Retail customers may
select alternative suppliers at any time. The SOS is intended to provide
customers with a price benefit (the commodity electric price offered to the
retail customer is expected to be less than the market price) for the first
several years, followed by a price disincentive that is intended to stimulate
the retail market.
Retail customers may continue to receive SOS through June 30, 2002, in New
Hampshire (subject to early termination on December 31, 2000, at the
discretion of the New Hampshire Public Service Commission), through December
31, 2004, in Massachusetts, and through December 31, 2009, in Rhode Island.
However, if any customers elect to have their electricity provided by an
alternate supplier, they are precluded from going back to the SOS.
In connection with the purchase of the generation assets, we entered into
agreements to supply the electric capacity and energy requirements necessary
for NEES to meet its SOS obligations. NEES is responsible for passing on to
us the revenues generated from the SOS. USGenNE, is currently serving the
SOS electric capacity and energy requirements for NEES, except for New
Hampshire's SOS. On March 1, 1999, Constellation Power Source, Inc. assumed
this component of the SOS upon winning a competitive bidding solicitation.
Like California utilities, the New England utilities entered into
agreements with unregulated companies to provide energy and capacity at
prices that are anticipated to be in excess of market prices. We assumed
NEES' contractual rights and duties under several of these power-purchase
agreements, which in aggregate provide for 800 MW of capacity. However, NEES
will make support payments to us toward the cost of these agreements. The
support payments by NEES total $1.1 billion in the aggregate (undiscounted)
and are due in monthly installments from September 1998 through January 2008.
In certain circumstances, with our consent, NEES may make a full or partial
lump sum accelerated payment.
Initially, approximately 90 percent of the acquired operating capacity,
including capacity and energy generated by other companies and provided to us
under power-purchase agreements, is dedicated to providing services to
customers receiving SOS. To the extent that customers eligible to receive
SOS chose alternate suppliers, this percentage will decrease. As customers
choose alternate suppliers, a greater proportion of the output of the
acquired operating capacity will be subject to market prices.
Regulatory Matters:
- -------------------
The Utility is the only subsidiary with significant regulatory activity at
this time. ItemsSome of the items affecting future Utility authorized revenues
include: the 1999 general rate case, the 1999 cost of capital proceeding, the distribution performance based
ratemaking application, FERC transmission rate cases, the CPUC's catastrophic
events memorandum account proceeding, the CPUC's gas strategy order instituting rulemaking, the
Diablo Canyon sunk costs audit, andthe post transition period ratemaking
proceeding, and the Electric Base Revenue Increase proceeding. These items
are discussed below. Any requested change in authorized electric revenues
resulting from any of these proceedings would not impact the Utility's
customer electric rates through the transition period because these rates are
frozen in accordance with the electric transition plan. However, the amount
of remaining revenues providing for the recovery of transition costs would be
affected.
The 1999 General Rate Case (GRC):
In December 1997, the Utility filed its 1999 GRC application with the CPUC.
During the GRC process, the CPUC examines the Utility's distribution costs to determine
the amount the Utility may charge customers. The Utility has requested
distribution revenue increases to maintain and improve gas and electric
distribution reliability, safety, and customer service. The requested
revenues, as updated, include an increase of $445 million in electric base
revenues and an increase of $377 million in gas base revenues over authorized
1998 revenues. The Office of Ratepayer Advocates (ORA) branch of the CPUC
has recommended a decrease of $80 million in electric revenues and an
increase of $104 million in gas base revenues. Recommendations by the ORA do
not represent the positions of the CPUC.
In December 1998, the CPUC issued a decision on interim rate relief in the
GRC. The decision granted the Utility's request to increase its electric
distribution revenues by $445 million and its gas distribution 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. TheHowever, the decision does not increase any
electric or gas rates billed to customers on an interim basis.
DueThe GRC application also contained a proposal for an Attrition Rate
Adjustment (ARA) to adjust revenues in 2000 and 2001 if a delay inPerformance Based
Ratemaking (PBR) mechanism, as discussed below, is not adopted for 2000 or
2001. Since the issuance ofCPUC has not issued a decision in the Utility's GRC, exceptpending
PBR application on October 1, the Utility filed a request for revenue
increases in the 2000 ARA. The Utility's proposal would increase electric
distribution revenues by $118 million and gas distribution revenues by $23
million based on the Utility's requested revenues in its 1999 GRC.
Except for the impacts of the cost of capital decision, discussed below,
the Utility's 1999 earnings are based on the authorized amount of revenues
in effect during 1998 and do not include any portion of the requested
revenue increase. When a final decision in the GRC is issued by the CPUC,
the Utility's regulatory assets and net income will be adjusted to reflect
any
differences between the amount of revenues currently being recognized and
the amount approved in the final decision. Any such adjustment could have
a material impact on the Utility's and PG&E Corporation's results of
operations.
The 1999 Cost of Capital Proceeding:
In June 1999, the CPUC issued a final decision in the Utility's 1999 Cost of
Capital proceeding. The decision adopts a return on common equity (ROE) of
10.6 percent for the Utility's electric distribution and gas distribution
assets, and an overall return on utility rate base of 8.75 percent in 1999.
These are reductions from the Utility's 1998 authorized ROE of 11.2 percent
and overall return of 9.17 percent.
The decision maintains the Utility's authorized capital structure for 1999
at 46.2 percent long-term debt, 5.8 percent preferred stock, and 48 percent
common equity. The decision is retroactive to January 1, 1999. The decision
has reduced the Utility's base revenues for the six-months ended June 30,
1999 as compared to the six-months ended June 30, 1998, by $23.1 million and
$7.3 million for electric and gas distribution, respectively.
The Distribution Performance Based Ratemaking (PBR) Application:
The Utility filed an amended distribution PBR proposal with the CPUC in
February 1999. If approved as filed, the distribution PBR will determine the
Utility's gas and electric distribution revenues for the years 2000 through
2004. Under the Utility's proposal, distribution revenues for the years 2000
through 2004 would be determined by multiplying total distribution revenues
by a rate formula. The rate formula would be based principally on inflation
less a proposed productivity factor of 1.1 percent and 0.82 percent for
electric distribution and gas distribution, respectively. These productivity
factors will be fixed for the five year duration of the PBR. The Utility has
proposed different rate formulas for gas customers, small electric customers
(principally residential and commercial customers) and large electric
customers.
The proposal also includes a sharing mechanism for earnings that are
significantly above or below the authorized weighted average cost of capital.
In addition, the proposed PBR includes rewards and penalties that will depend
upon the Utility's ability to achieve performance standards for electric
distribution reliability; maintenance, repair, and replacement; customer
service; and employee safety. The procedural schedule in the PBR proceeding
has been suspended pending the issuance of a proposed decision in the
Utility's 1999 GRC proceeding. A final decision in the PBR proceeding is not
expected to be issued until mid-2000. The Utility has applied for interim
relief, which would make the final decision effective on January 1, 2000.
FERC Transmission Rate Cases:
Since April 1, 1998, all electric transmission revenues are authorized by
FERC. During 1998, the FERC issued orders that put into effect various rates
to recover electric transmission costs from the Utility's former bundled rate
transmission customers. These rates are subject to refund. On April 14,
1999, the Utility filed a settlement with FERC which, if approved, allows the
Utility to recover $168 million for the period of April 1998 through October
1998, and $177 million for the period of November 1998 through May 1999. The
Utility does not expect a material impact on its financial position or
results of operations resulting from the settlement. On May 27, 1999, FERC
approved, subject to refund, the Utility's March 30, 1999, request to begin
recovering, as of May 31, 1999, $324 million annually in revenues from its
former bundled retail transmission customers. On September 1, 1999, the
Utility filed a request to increase future revenues by $46 million annually
to $370 million for its former bundled retail transmission customers. FERC
has not yet acted upon the Utility's request.
Catastrophic Events Memorandum Account Proceeding:
On September 10, 1999, PG&E Corporation entered into a Settlement Agreement
with the ORA and other parties, in a proceeding addressing the Catastrophic
Events Memorandum Account. The settlement calls for a $70 million increase
in revenues effective January 1, 2000. Of the $70 million, $59 million is
electric and $11 million is gas distribution. The increase is to compensate
the Utility for service restoration following several events beginning with
the Berkeley Hills fire of 1991 and ending with the storms of February 1998.
A CPUC decision is expected in early 2000.
The CPUC's Gas Strategy Order Instituting Rulemaking:
In January 1998, the CPUC opened a rulemaking proceeding to explore changes
in the natural gas industry, including the possible further unbundling of
services to promote competition, streamlining regulation for noncompetitive
services, mitigating the potential for anti-competitive behavior, and
establishing appropriate consumer protections. In 1998, the Governor of
California signed Senate Bill 1602, allowing the CPUC to investigate issues
associated with the further restructuring of natural gas services but
prohibiting the CPUC from enacting any such gas industry restructuring
decisions prior to January 1, 2000. On July 8, 1999, the CPUC issued a
decision identifying options for restructuring the natural gas industry. In
the decision, the CPUC reaffirmed the structure of the Gas Accord and stated
that it seeks to explore that market structure that maintains the utilities'
traditional role of providing fully integrated default service to core
customers while removing obstacles to competitive offering of gas commodity,
transmission, storage, balancing, and certain other services. The CPUC
requested all interested parties to try to settle various issues raised in
the decision within 60 days, and if that effort is unsuccessful, to move to
hearings on the costs, benefits, and other factors affecting these proposals,
with initial testimony due in late September 1999.decision. The CPUC closed the existing rule-making proceedings and
opened a new investigative proceeding to explore in more detail the
anticipated costs and benefits associated with the different market structure
options the CPUC has identified. The CPUC's goal is to submit a final report
to the California Legislature on gas restructuring possibly in the first
quarter of next year. On September 8, 1999, a CPUC administrative law judge
granted the parties an approximately 45-day extension to try to settle the
various issues before filing cost/benefit testimony.
The Diablo Canyon Sunk Costs Audit:
In August 1998, an independent accounting firm retained by the CPUC completed
a financial verification audit of the Utility's Diablo Canyon plant accounts
as of December 31, 1996. The audit resulted in the issuance of an
unqualified opinion. The audit verified that Diablo Canyon sunk costs at
December 31, 1996, were $3.3 billion of the total $7.1 billion construction
costs. (Sunk costs are costs associated with Utility-owned generating
facilities that are fixed and unavoidable and currently included in the
Utility customers' electric rates.) The independent accounting firm also
issued an agreed-upon special procedures report which questioned $200 million
of the $3.3 billion sunk costs. The CPUC will review any proposed
adjustments to Diablo Canyon's recoverable costs, which resulted from the
report. At this time, the Utility cannot predict what actions, if any, the
CPUC may take regarding the audit report.
Post-Transition Period Ratemaking Proceeding:
In a pending proceeding, the CPUC currently is considering the ratemaking mechanism
under which the Utility's transition cost recovery would be completed, the
current electric rate freeze would end, and post-transition period rates would
be established, consistent with the electric industry restructuring
legislation and the Utility's transition cost recovery plan. InOn September 1,
1999, a proposed decision was issued by an administrative law judge in this
proceeding that, among other matters, would terminate the CPUC
is considering whether the Utility mayUtility's ability to
continue to recover revenues for itsrelated to Diablo Canyon nuclear transition costs based on the incremental
cost incentive price (ICIP) through December 31, 2001, or must cease recovery of such
revenues ifonce the Utility has completed recovery of all
otherUtility-owned generation related transition costs beforecosts. The Utility had argued
that date.it should be entitled to rely on the CPUC decision establishing the ICIP
mechanism which stated that the ICIP mechanism would continue through December
31, 2001.
The ICIP was established effective January 1, 1997, as a performance-based
mechanism to recover Diablo Canyon's variable and other operating costs and
capital addition costs. The ICIP mechanism establishes a rate per kWh
generated by the facility. This rate isfacility based upon a fixed forecast of ongoing costs,
capital additions, and capacity factors for the period 1997 through 2001. The
fixed forecast of ICIP for 1999, 2000, and 2001 is $3.373.37 cents per Kwh, $3.43kWh, 3.43
cents per kWh, and $3.493.49 cents per kWh, respectively. The
ICIP revenues, based on an assumed capacity factor of 83.6%, for 1999, 2000,
and 2001, are projected to be $532 million, $542 million, and $552 million,
respectively. IfIn contrast, the ICIP mechanism is discontinued before December 31, 2001,
the price for Diablo Canyon generation may be lower or higher than the ICIP
prices depending on market conditions, which would result in lower or higher
revenues than the projected ICIP revenues. The average
cost of electric energy for energy purchased at market rates from the PX for
the six-monthstwelve-months ended JuneSeptember 30, 1999 was 2.63.26 cents per kWh. Further,
with the end of the transition period, the Utility will be required to begin
sharing the net benefits of operating Diablo Canyon on a fifty-fifty basis
with ratepayers. The ultimate financial impact of the end of the ICIP
mechanism will depend on when Utility-owned generation-related transition
costs are recovered and the current electric rate freeze ends, future Diablo
Canyon operating costs, future electricity prices, and other variables the
Utility is unable to predict.
The proposed decision would also prohibit the Utility from collecting after
the rate freeze any electric costs incurred during the rate freeze but not
recovered during the rate freeze, even costs that are not transition costs and
are not related to generation assets. The utimate financial impact of this
provision will depend on the amount of any electric non-transition costs that
have been incurred but not recovered as of the end of the transition period,
the timing of various regulatory proceedings, future electicity prices, other
future costs, and other variables the Utility is unable to predict. PG&E
Corporation believes that this prohibition would be illegal if implemented
and PG&E Corporation would vigorously challenge it if adopted by the CPUC.
The proposed decision is subject to comment by the parties and change by
the full CPUC before a final decision is issued. The CPUC is expected to
issue a final decision in the near future.
Electric Base Revenue Increase Proceeding:
Section 368(e) of the California Public Utilities Code, adopted as part of the
California electric industry restructuring legislation, provided for an
increase in the Utility's electric base revenues for 1997 and 1998, for
enhancement of transmission and distribution system safety and reliability.
In accordance with Section 368(e), the CPUC authorized a 1997 base revenue
increase of $164 million. For 1998, the CPUC authorized an additional base
revenue increase of $77 million, for a total authorized base revenue increase
for 1997 and 1998 of $406 million. Under Section 368(e), any underspending of
the 1997 revenue requirement would be carried over into 1998. Any
overspending during either 1997 and 1998 would not be recoverable from
ratepayers. Section 368(e) expenditures are subject to review by the CPUC.
In March 1999, the Utility filed its report on 1998 expenditures and
resubmitted its report on 1997 expenditures (originally submitted in May 1998)
as part of its application for consolidated review of its Section 368(e)
expenditures.
On July 16, 1999, the ORA filed its report on the Utility's 1998 Section
368(e) expenditures recommending a disallowance of $44.5 million. In its
report, the ORA recommended a disallowance for 1997 of $43.9 million
(increased from the previously reported $31 million recommended disallowance).
In total, the ORA recommends a disallowance related to 1997 and 1998 Section
368(e)expenditures of $88.4 million. In August 1999, The Utility Reform
Network (TURN) recommended a $14 million disallowance for both 1997 and 1998
Section 368(e) expenditures in addition to the ORA's $88.4 million
recommendation for a total recommended disallowance for 1997 and 1998
expenditures of $102.4 million. Of this amount, approximately $18 million
may be recoverable in other CPUC proceedings.
The Utility's response to the recommended disallowances was filed on
October 4, 1999 and hearings are scheduled to begin October 18, 1999. A
proposed decision is not expected before the first quarter of 2000. Any
proposed decision would be subject to comment by the parties and change by
the full CPUC before a final decision is issued.
Results of Operations
In this section, we present the components of our results of operations for
the three- and six-monthnine-month periods ended JuneSeptember 30, 1999 and 1998. Due to a
delay in the issuance of a decision in the Utility's GRC, exceptExcept
for the impacts of the cost of capital decisions, discussed above, the
Utility's 1999 earnings are based on the authorized amount of revenues in
effect during 1998 and do not include any portion of the requested revenue
increase. When a final decision in the GRC is issued by the CPUC, the
Utility's regulatory assets and net income will be adjusted to reflect any
differences between the
amount of revenues currently being recognized and
the amountrevenue approved in the final decision. Any such adjustment could have a
material impact on the Utility's and PG&E Corporation's results of
operations.
The table below shows for the three- and six-monthnine-month periods ended
JuneSeptember 30, 1999 and 1998, respectively, certain items from our Statement
of Consolidated Income detailed by (1) Utility (2) wholesale, and (3) retail business
National Energy Group
operations of PG&E Corporation. (In the "Total" column, the table shows the
combined results of operations for these three groups.) The information for PG&E
Corporation (the "Total" column) excludes transactions between its
subsidiaries (such as the purchase of natural gas by the Utility from the
unregulated business operations). Following this table we discuss earnings
and explain why the components of our results of operations varied for the
three- and six-monthnine-month periods ended JuneSeptember 30, 1999, as compared to the
same periods in 1998.
Wholesale Retail
--------------------------------- -------National Energy Group
----------------------------------------------------
PG&E GT ParentElimi-
---------------- nations & Elimi-
Utility PG&E Gen&EGen NW Texas PG&E ET PG&E ES nations(1)Other (1) Total
------- ------- ------- ------- ------- ------- ------- -------
(in millions)
For the three-month period ended:
- ---------------------------------
JuneSeptember 30, 1999
Operating revenues $ 2,2332,587 $ 254275 $ 5256 $ 436 $2,024177 $3,490 $ 142166 $ (321)(371) $ 4,8206,380
Operating expenses 1,781 247 23 444 2,024 165 (318) 4,3662,101 259 26 174 3,521 186 (379) 5,888
Operating income 454492
Other income, net 3920
Interest expense, net 192191
Income taxes 121138
Net income 180183
EBITDA (2) 954 42 40 12 2 (21) (6) 1,023
June1,097 38 47 17 (29) (18) 10 1,162
September 30, 1998
Operating revenues $ 2,1172,563 $ 115155 $ 58 $ 522 $2,060453 $2,156 $ 92108 $ (177)(186) $ 4,7875,307
Operating expenses 1,623 55 23 532 2,058 114 (175) 4,2302,051 118 25 478 2,159 135 (186) 4,780
Operating income 557527
Other income, net (8)18
Interest expense, net 196193
Income taxes 179142
Net income 174210
EBITDA (2) 867 631,199 49 45 5(11) (3) (26) 4 (21) (21) 9421,257
For the six-monthnine-month period ended:
- ----------------------------------------------
June--------------------------------
September 30, 1999
Operating revenues $ 4,3186,905 $ 543818 $ 110166 $ 793 $4,655970 $8,145 $ 277443 $ (619) $10,077(990) $16,457
Operating expenses 3,444 494 50 827 4,660 315 (609) 9,1815,545 753 76 1,001 8,181 501 (988) 15,069
Operating income 8961,388
Other income, net 6080
Interest expense, net 393584
Income taxes 227365
Net income 336519
EBITDA (2) 1,749 108 81 5 (1) (33) (13) 1,896
June2,845 146 128 22 (30) (51) (3) 3,057
September 30, 1998
Operating revenues $ 4,1436,706 $ 199354 $ 119 $1,037 $3,837177 $1,490 $5,993 $ 135243 $ (330) $ 9,140(516) $14,447
Operating expenses 3,225 121 48 1,045 3,835 174 (329) 8,1195,276 239 73 1,524 5,994 309 (516) 12,899
Operating income 1,0211,548
Other income, net 725
Interest expense, net 393586
Income taxes 322464
Net income 313523
EBITDA (2) 1,505 86 94 18 4 (37) (17) 1,6532,704 137 138 15 2 (63) (22) 2,911
(1) Net income on intercompany positions recognized by segments using mark to market accounting
is eliminated. Intercompany transactions are also eliminated.
(2) EBITDA measures earnings (after preferred dividends) before interest expense (net of
interest income), income taxes, depreciation and amortization.
Overall Results:
- ----------------
Net income increased $6decreased $27 million and $4 million for the three-month periodthree- and nine-month
periods ended JuneSeptember 30, 1999, as compared to the same periodperiods in 1998.
The decreases are a result of declines in net income of $20 million and $35
million at the Utility; $11 million and $3 million at PG&EGen; and $17 million
and $19 million at PG&E ET, for the three- and nine-months ended September 30,
1999 and 1998, respectively. The Utility's decreases in net income are a
result of its disposition of a significant portion of its generating assets in
1998 primarily becauseand 1999, and the reduced authorized cost of capital from 11.2 percent in
1998 to 10.6 percent in 1999. The decreased net income at PG&EGen reflects
the negative impact of a fire at its 400 MW Salem Harbor Unit 4 power plant
which took the facility out of service for 32 days during a peak period of
summer demand; and mild weather in the Northeast United States for the
remainder of the quarter. PG&E ET experienced losses resulting from trading
positions in its United States and Canadian gas trading operations, and
increased infrastructure investment. These declines in net income were
partially offset by increased income at PG&E GT, whose financial performance
was positively impacted by the continued recovery in the natural gas liquids
markets, where the price spread between natural gas liquids and natural gas
increased from approximately five cents per gallon in the third quarter of
1998 to an average of 14 cents per gallon in the third quarter of 1999. PG&E
GT also benefited from decreased operating costs resulting from a
restructuring of operations in the first half of 1999.
In addition, during the second quarter of 1998, the Corporation recognized
a non-recurring charge of $.06 per share charge related to the disposition of its
investment in its Australian holdings resultingholdings. The charge resulted from the 22 percent currency
devaluation of the Australian dollar against the U.S. dollar.
In addition, 1999 results continue to reflect a decrease in the
effective income tax rate resulting from the expansion of business activities
outside of California. These increases in net income were partially offset by
a reduction in Utility net income due to the disposition of its generating
assets in 1998 and 1999, the cost of capital decision discussed above, and a
decrease in PG&E Gen's income resulting from a decrease in portfolio
management activity compared to 1998 levels.
Net income for the six-month period ended June 30, 1999, was $336 million
compared to $313 million for the same period in 1998. This increase was
attributable to the fact that, in 1998, the Corporation recognized a non-
recurring charge related to the disposition of its Australian holdings
discussed above. Utility earnings were less in 1999 than the comparable
period in 1998 as result of the disposition of its generating facilities,
discussed below, and a lower authorized cost of capital on its distribution
business.
Operating Revenues:
- -------------------
Utility:
Utility operating revenues increased by $116$24 million for the three-month period
ended JuneSeptember 30, 1999, as compared to the same period in 1998. MostThe
majority of the increase is attributed to a $43$30 million increase in
revenues from
residential and small commercial electric customersgas revenues reflecting customer
growth.a higher average cost of
gas. In addition, 1998 revenuescommercial and agricultural electric sales were $30$9 million
less than 1999 revenues
due tohigher reflecting the impact of abnormally high rainfall in 1998, which
reduced demand for irrigation water pumping in the secondthird quarter of 1998.
Partially offsetting these increases was an $18 million decrease in
residential and small commercial electric customer sales due to the mild
weather experienced in California during the third quarter compared to the
prior year.
Utility operating revenues increased by $175$199 million for the six-monthnine-month
period ended JuneSeptember 30, 1999, as compared to the same period in 1998. This
increase is primarily due to: (1) a $79 million increase in revenues from
residential and small commercial electric customers reflecting customer
growth, (2) a $110$135 million increase in gas residential
sales reflecting cooler temperatures, particularly during the first three
months of 1999, (2) a $61 million increase in revenues from residential and
small commercial electric customers reflecting customer growth, and (3) a $30$40
million increase in commercial and agricultural electric sales, as discussed
above. Partially offsetting these increases is $54$55 million of lower sales to
medium and large electric customers leaving for direct access.
Wholesale Business Operations:
National Energy Group:
Operating revenues associated with wholesale business operationsthe National Energy Group increased by
$11$1,234
million and $2,285 million for the three-month periodthree- and nine-month periods ended
JuneSeptember 30, 1999, as compared to the same periods in 1998. PG&EGen's
revenue increase for the three- and nine-month periods ended September 30,
1999, compared to the same period in 1998. The increase principally relates to increased revenues1998, include revenue increases of $128
million and $541 million, respectively, from PG&E Gen's acquisition of aits portfolio of electric
generating assets and power supply contracts acquired from NEESNew England
Electric System in the third quarter ofSeptember 1998. This increase
was partially offset by a decline in the proportion of natural gas volumes
shipped for resale at
PG&E GTT, lower interruptible sales at PG&E GT NW,ET's operating revenues increased $1,334 million and lower gas commodity trading at PG&E ET.
Operating revenues associated with wholesale business operations increased
$909$2,152 million
for the six-month periodthree- and nine-month periods ended JuneSeptember 30, 1999, as compared to
the same periodperiods in 1998. This increase wasThese increases were a result of increased gas andtrading
activity in each of PG&E ET's commodity markets. PG&E ET increased its
electric commodity trading at PG&E ET and PG&E Gen's acquisition of a portfolio of
electric generating assets and power supply contracts from NEES in the third
quarter of 1998. These increases were partially offsetrevenues by a decline in
operating revenues resulting from declines in proportion of natural gas
volumes shipped for resale at PG&E GTT and lower interruptable sales at PG&E
GT NW.
Retail Business Operations:
Operating revenues associated with the retail business operations increased
$50$1,017 million and $142$2,049 million, and its gas
commodity revenues by $317 million and $103 million, for the three- and six-monthnine-
month periods ended JuneSeptember 30, 1999 as compared to the same period in 1998. These increases were
primarily due to sales of electricity in California.
Operating Expenses:
- -------------------
Utility:
Utilityand 1998, respectively.
PG&E ES' operating expensesrevenues increased $158$58 million and $219$200 million for the
three- and six-monthnine-month periods ended JuneSeptember 30, 1999, respectively, as compared to the
same periods in 1998, as a result of increases of $73 million and $194
million, respectively, in its electricity commodity sales portfolio in
California and New England. The increases in this quarter's electric
commodity sales were partially offset by a decrease in revenues from gas
sales.
The increases in operating revenues at PG&EGen, PG&E ET and PG&E ES were
partially offset by the decline in operating revenues at PG&E GT. PG&E GT's
operating revenues declined $278 million and $531 million for the three- and
nine-month periods ended September 30, 1999 compared to the same periods in
1998. The declines are a result of a decrease in the proportion of natural
gas volumes shipped for resale to transport-only volumes at PG&E GTT, and
lower interruptible transportation volumes at PG&E GT NW.
Operating Expenses:
- -------------------
Utility:
Operating expenses at the Utility increased $50 million and $269 million for
the three- and nine-month periods ended September 30, 1999, as compared to the
same periods in 1998. These increases resulted from increased ISO grid
management charges in the current year; increased recovery of stranded costs
(transition costs); and higher purchased gas volumes fromfor the increase in
residential gas sales due to the cooler weather in the first quarter,
ISO Grid Management charges in the current year, and increased recovery of
stranded costs (transition costs). Partially offsetting this increase isquarter. These
increases were partially offset by decreased fuel, depreciation, and
environmental costs due to plant sales.
Wholesale Business Operations:National Energy Group:
Operating expenses for the wholesale businessNational Energy Group increased $70$1,251 million and
$2,373 million for the three-month periodthree- and nine-month periods ended JuneSeptember 30, 1999
as compared to the same periodperiods in 1998. This increase reflectsPG&EGen's operating expenses
increased operating costs at PG&E Gen resulting
from theas a result of its September 1998 acquisition of the New Englandelectric
generating assets and power supply contracts discussed above. The increase
wasPG&E ET's
operating expenses increased as a result of its increased electric and gas
commodity purchasing activities in support of the trading activities described
above and its increased investment in information technology systems and
personnel to manage the commodity pricing risk of the National Energy Group
businesses. PG&E ES's operating expenses increased as a result of increased
purchases of electricity to support the electric sales discussed above. These
increases were partially offset by decreases in PG&E GT's operating expenses
due to a decline in the volumes of gas commodities purchased
at PG&E ET and decreased operating expenses at PG&E GTT, resulting from a
decline in gas purchased for resale. Operating expenses for the wholesale business operations increased $982
million for the six-month period ended June 30, 1999, as compared to the same
period in 1998. This increase reflects increased volumes of energy
commodities purchased at PG&E ET and operating costs associated with the New
England assets at PG&E Gen. These increases were partially offset by
decreasedThe year-to-date
operating expenses at PG&E GTT. The year to date operating expenses
includeincludes approximately $6 million of restructuring and
severance costs at the Gas Transmission business unit.
Retail Business Operations:
Operating expenses for our retail business operations increased $51 million
and $141 million for the three- and six-month periods ended June 30, 1999,
respectively, as compared to the same periods in 1998. This increase is due
to the increased electric commodity sales of our energy services business.
Income Taxes:
- -------------
Income taxes decreased $58$4 million and $95$99 million for the three- and six-nine-
month periods ended JuneSeptember 30, 1999 as compared to the same periods in
1998, due to a lower effective state income tax rate resulting from our
expanded business operations outside of California.
EBITDA:
- -------
Utility:
The Utility's EBITDA increased $87 million and $244 million for the three- and six-month
periods ended June 30, 1999, respectively, as compared to the same periods in
1998. This increase is generally due to an increase in operating revenues as
discussed above, partially offset by an increase in operating expenses
resulting from higher purchased gas volumes for increased residential gas
sales in the first quarter; and ISO grid management charges in the current
year.
Wholesale:
EBITDA decreased $21declined $102 million for the three-month period ended
JuneSeptember 30, 1999,
as compared to the same period in 1998. The Utility's
disposition of its fossil-fueled power plants reduced its sales to the PX for
the third quarter of 1999 by $254 million over the third quarter of 1998.
This decrease is a result of lower
interruptable sales at PG&E GT NW and reduced portfolio management activity at
PG&E Gen,reduction was partially offset by an increasea $153 million decrease in natural gas liquids sales margins
at PG&E GTT.
For the six-monthcost of
electric generation resulting from those same power plant sales.
The Utility's EBITDA for the nine-month period ended JuneSeptember 30, 1999,
EBITDA decreasedincreased by $9$141 million as compared toover the same period in 1998 as a result of
increased revenues from residential and small commercial electric customers
reflecting customer growth and increased residential gas sales reflecting
cooler temperatures, particularly during the first three months of 1999. In
addition, the Utility's sale of its fossil-fueled power plants resulted in a
decrease in the cost of electric generation. These changes were partially
offset by increased costs of gas to meet the increased sales demand, increases
in the cost of ancillary services and electricity purchased from the PX and a
reduction in the sales of electricity to the PX.
National Energy Group:
EBITDA for the National Energy Group increased $7 million and $5 million for
the three- and nine-month periods ended September 30, 1999, compared to
similar periods in 1998. This decrease is due toPG&E GTT's EBITDA increased $28 million and $7
million, respectively, for the three- and nine-month periods, as a result of
the increased price spread between the price of natural gas liquids and
natural gas, and a decline in operating revenuesexpenses resulting from declinesa
restructuring of operations in the proportionfirst half of natural gas volumes shipped1999. In addition, PG& ES'
EBITDA increased by $8 and $12 million for resale at PG&E GTTthe three- and lower interruptablenine-month periods
ended September 30, 1999 over 1998. These increases are a result of increased
sales at PG&E GT NW. The decrease in EBITDA isvolume and operating margin on its electric commodity and value-added
services sales. These increases were partially offset by higher
revenues resulting fromdeclines at PG&E Gen's acquisitionET,
whose EBIDTA decreased $26 million and $32 million, respectively, for the
three- and nine-month periods ended September 30, 1999, compared to 1998.
These declines are a result of a portfolio of electric
generating assetsthe losses on its trading positions in its
United States and power supply contracts from NEES in the third quarter of
1998.Canadian gas operations and increased infrastructure
investment.
Stock Dividend:
- ---------------
We base our common stock dividend on a number of financial considerations,
including sustainability, financial flexibility, and competitiveness with
investment opportunities of similar risk. Our current quarterly common stock
dividend is $.30 per common share, which corresponds to an annualized
dividend of $1.20 per common share. We continually review the level of our
common stock dividend taking into consideration the impact of the changing
regulatory environment throughout the nation, the resolution of asset
dispositions, the operating performance of our business units, and our
capital and financial resources in general.
The CPUC requires the Utility to maintain its CPUC-authorized capital
structure, potentially limiting the amount of dividends the Utility may pay
PG&E Corporation. During 1999, the Utility has been in compliance with its
CPUC-authorized capital structure. PG&E Corporation and the Utility believe
that this requirement will not affect PG&E Corporation's ability to pay
common stock dividends. However, depending on the timing and outcome of the
legislative
and regulatory process surrounding the valuation and divestiture of the Utility's hydroelectric facilities discussed in "Generation
Divestiture" above, certain valuation or disposition methodologies, other than a sale of
the facilities to a third party,methods could necessitate a waiver of
the CPUC's authorized capital structure in order to permit PG&E Corporation
or the Utility to continue paying common stock dividends at the current
level.
Liquidity and Financial Resources
Cash Flows from Operating Activities:
Net cash provided by PG&E Corporation's operating activities totaled $1,637$2,005
million and $1,250$2,515 million during the six-monthnine-month period ended JuneSeptember 30,
1999 and 1998, respectively. Net cash provided by the Utility's operating
activities totaled $1,568$1,926 million and $1,182$2,755 million during the six-monthnine-month
period ended JuneSeptember 30, 1999 and 1998, respectively.
Cash Flows from Financing Activities:
PG&E Corporation:
We fund investing activities from cash provided by operations after capital
requirements and, to the extent necessary, external financing. Our policy is
to finance our investments with a capital structure that minimizes financing
costs, maintains financial flexibility, and, with regard to the Utility,
complies with regulatory guidelines. Based on cash provided from operations
and our investing and disposition activities, we may repurchase equity and
long-term debt in order to manage the overall size and balance of our capital
structure.
During the six-monthnine-month period ended JuneSeptember 30, 1999 and 1998, we issued
$32$44 million and $33$48 million of common stock, respectively, primarily through
the Dividend Reinvestment Plan and the stock option plan component of the
Long-
TermLong-Term Incentive Program. During the six-monthnine-month period ended JuneSeptember
30, 1999 and 1998, we declared dividends on our common stock of $220$325 million
and $229$343 million, respectively.
During the six-monthnine-month period ended JuneSeptember 30, 1999 and 1998, we
repurchased $503$534 million and $1,123$1,159 million of our common stock,
respectively. These repurchases were executed through accelerated share
repurchase programs. Under the most recent agreement, PG&E Corporation
purchasedrepurchased in a specific transaction 16.6 million shares of its common
stock. In connection with this transaction, 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.entered into a
forward contract with an investment institution. PG&E Corporation may elect to settle
its obligations under such arrangement with either cash or shares of its
common stock. Forsettled
the three- and six-month periods ended June 30, 1999, this
agreement caused the $0.03 and $0.08 dilution, respectively, reflected in
PG&E Corporation's diluted earnings per share. This dilution will be
eliminated when the associated forward contract is settled.and its additional obligation of $29 million in
September 1999. There are no more outstanding shares to be repurchased.
We maintain a number of credit facilities throughout our organization to
support commercial paper programs, letters of credit, and other short term
liquidity requirements. At PG&E Corporation, we maintain two $500 million
revolving credit facilities, one of which expires in November 1999 and the
other in 2002. The PG&E Corporation credit facilities are used to support
the commercial paper program and other liquidity needs. The facility
expiring in 1999 may be extended annually for additional one-year periods
upon agreement between the lending institutions and us. There was $516$261
million of commercial paper outstanding at JuneSeptember 30, 1999. PG&E
GenCorporation introduced a $200 million Extendible Commercial Note (ECN)
program during the third quarter of 1999. The ECN program supplements PG&E
Corporation's short-term borrowing capability. There was $89 million of
extendible commercial notes outstanding at September 30, 1999, which are not
supported by the credit facilities.
PG&EGen maintains two credit facilities of $550 million each. One
agreement expiresexpired in August 1999 and thewas immediately renewed for a 364 day
period which expires in August 2000. The other facility will expire in
2003. The total amount outstanding at JuneSeptember 30, 1999, backed by the
facilities, was $858$910 million in commercial paper. Of these loans, $550
million is classified as noncurrent in the consolidated balance sheet.
At JuneSeptember 30, 1999, PG&E GTT had $54$177 million of outstanding short-term
bank borrowings related to threefour separate credit facilities. These lines may
be cancelled upon demand and bear interest at each respective bank's quoted
money market rate. The borrowings are unsecured and unrestricted as to use.
On June 30, 1999, PG&E GTT redeemed the outstanding balance of $69 million of
its senior notes, resulting in a gain on redemption of approximately $1.7
million.
PG&E GT NW maintains a $100 million revolving credit facility which
expires in the year 2002, but has an annual renewal option allowing the
facility to maintain a one-year renewal option.three year duration. PG&E GT NW also maintains a $50
million 364-day credit facility which expires in the year 2000, but can be
extended for successive 364-day periods. No amounts were outstanding under
either of these credit facilities at JuneSeptember 30, 1999. At JuneSeptember 30,
1999, PG&E GT NW had an outstanding commercial paper balance of $97$87 million,
which is classified as noncurrent.
Utility:
During the six-monthnine-month period ended JuneSeptember 30, 1999, the Utility
repurchased 20 million shares of its common stock from PG&E Corporation for
an aggregate purchase price of $725 million to maintain its authorized
capital structure. During the six-monthnine-month period ended JuneSeptember 30, 1999 and
1998, the Utility declared dividends on its common stock of $195$290 million and
$100$200 million. In October 1999, the Utility declared a dividend of $125
million payable to PG&E Corporation in October 1999.
The Utility's long-term debt that either matured, was redeemed, or was
repurchased during the six-monthnine-month period ended JuneSeptember 30, 1999 totaled
$348$454 million. Of this amount, (1) $148$217 million related to the Utility's rate
reduction bonds maturing; (2) $109$134 million related to the Utility's
repurchase of various mortgage bonds; (3) $67 million related to the
Utility's maturity of the Utility's 5.5 percent mortgage bonds; and (4) $24$36
million related to the maturities and redemption of various of the Utility's
medium term notes.notes and other debt.
The Utility maintains a $1 billion revolving credit facility, which
expires in 2002. The Utility may extend the facility annually for additional
one-year periods upon agreement with the banks. This facility is used to
support the Utility's commercial paper program and other liquidity
requirements. The Utility did not have anytotal amount outstanding debt related toat September 30, 1999, backed by
this credit facility, at June 30, 1999. Additionally,was $77 million in commercial paper. There were no commercial paper or bank notes
were outstanding at JuneSeptember 30, 1999.
Cash Flows from Investing Activities:
The primary uses of cash for investing activities are additions to property,
plant, and equipment; unregulated investments in partnerships; and
acquisitions.
The Utility's GRC application contained estimates of capital spending for
1999 in the amount of $1.6 billion, excluding capital expenditures for
divested fossil and geothermal power plants. These estimates were reflected
in the amount of base revenues requested by the Utility in its GRC filing.
If the CPUC ultimately authorizes base revenues that are significantly lower
than those requested by the Utility, the Utility's level of prospective
capital expenditures will be reduced and actual expenditures could differ
materially.
The Utility has sold its remaining fossil generation facilities and its
geothermal generation facilities. These sales closed in April and May 1999.
The sales generated proceeds of $1,014 million.
Capital Investments:
PG&EGen is currently constructing two natural gas-fueled combined-cycle power
plants. These power plants, referred to as "merchant power plants", are being
built in New England and throughout the country for the purpose of selling
power as a commodity in the competitive marketplace without relying on long-
term contracts. The electricity generated by these plants will be sold on a
wholesale basis to local utilities and power marketers, including PG&E ET,
who, in turn, sell it to industrial, commercial, and residential electricity
customers.
Millenium Power, a 360 MW power plant, is located in Massachusetts, and is
scheduled to be placed in service in August 2000. The estimated cost to
construct Millenium Power is approximately $200 million. Lake Road
Generating Plant, a 792 MW power plant, is located in Connecticut, and is
scheduled to be placed in service in the year 2001. The estimated cost to
construct Lake Road Generating Plant is approximately $490 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 JuneSeptember 30, 1999, the Utility expects to spend $294$296 million over the
next 30 years for cleanup costs at identified sites. If other responsible
parties fail to pay or expected outcomes change, then these costs may be as
much as $482$481 million. Of the $294$296 million, the Utility has recovered $136$137
million (including remediation of generation plants divested, discussed
above) and expects to recover another $129$127 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 (Y2K) issue exists because many computer programs use only two
digits to refer to a year, and were developed without considering the impact
of the upcoming change in the century. If PG&E Corporation's mission-criticalmission-
critical computer systems fail or function incorrectly due to not being made
Year 2000Y2K 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 2000Y2K issues focusesfocused primarily on mission-
criticalmission-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 arewere
inventory and assessment, remediation, testing, and certification.
Certification occurs when mission-critical systems are formally determined to
be Year 2000Y2K ready. "Year 2000"Y2K ready" means that a system is suitable for continued use
into the year 2000.
Once Year 2000PG&E Corporation's mission-critical items have been certified as Y2K ready
additional standardswith a few exceptions at PG&E Gas Transmission-Northwest. These exceptions
are scheduled to be resolved by replacement or retirement of non-Y2K ready
systems in November 1999. Contingency plans are in place to address any
unlikely delays or problems.
The Utility is certifying its readiness to the CPUC prior to the November
1 deadline, and processes
are imposedhas previously notified the North American Electric
Reliability Council (NERC), and Nuclear Regulatory Commission (NRC) that it
is Y2K ready.
"Clean management" practices have been implemented to prevent systems from
beingbecoming compromised.
Our Year 2000 project is generally proceeding on schedule. The following
table indicates our Year 2000 progress as of July 26, 1999.
Year 2000 Readiness of Mission-Critical Items
Remediation Testing Certification
Completed Completed Completed
- ----------------------------------------------------------------------
In-house software 100% 99% 99%
Vendor software 100% 100% 100%
Embedded systems 100% 100% 81%
Computer hardware 100% 100% 100%
The percentages above reflect approximations based on a uniform reporting
system that combines subsidiary results to provide a consistent, corporate-
wide view and are derived using standard rounding conventions. Even where
100% is reported, there may be remaining items. Moreover, changes in
inventories, or issues uncovered in subsequent phases for an item previously
reported as completed, may lead to downward adjustments in percentages from
period to period. Even after systems are certified as Y2K ready, we are
continuing various kinds of validation and quality assurance efforts and may
do so into the year 2000.
The Utility routinely reports Year 2000 progress to minimize the CPUC, North
American Electric Reliability Council (NERC), and the Nuclear Regulatory
Commission (NRC). The Utility has notified NERC and the NRC that it is Year
2000 ready, with limited exceptions.risk of any significant disruption.
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 2000Y2K problems in
their systems, our mission-critical business functions may be adversely
affected. To deal with this vulnerability, we haveour program used a four phased
approach for dealing withto address external parties: (1) inventory, (2) action planning, (3)
risk
assessment, and (4) contingency planning. The contingency planning process also
addresses exposures that could result from failures in our own essential
business systems. Contingency plans will beare continually revised throughout
1999 as necessary.
The Utility's contingency plans are beinghave been incorporated into its emergency
plans and may include measures such as emergency back-up and recovery procedures,
augmenting automated applications with manual processes, and identification
of alternate suppliers. Electric transmission and generation plans are
coordinated with those of the California ISO and PX, and are consistent with
Western Systems Coordinating Council and NERC recommendations and NRC
guidelines. The plans will bewere tested in Utility and electric-industrygas-and-electric industry
drills in which the Utility participatesparticipated throughout 1999, and will be updated
as necessary.
As of JuneSeptember 30, 1999, we estimate total costs to address Year 2000Y2K problems
to be $223$212 million, of which $97 million is attributed to the Utility.
Included are systems replaced or enhanced for general business purposes and
whose implementation schedules areis critical to our Year 2000Y2K readiness.
Through JuneSeptember 1999, we spent approximately $166$179 million, of which $91$94
million was capitalized. The remaining $75$85 million was expensed. Future
costs, including contingency funds, to address Year 2000Y2K issues are expected to be
$57$33 million, of which $23$13 million will be capitalized. The remaining $34$20
million will be expensed.
Based on our current schedule for the completion of Year 2000 tasks, we
expect to secure Year 2000 readiness of our mission-critical systems by the
end of the third quarter of 1999. However, as our current schedule is
partially dependent on the efforts of third parties, their delays and other
factors we are not able to predict, may cause our schedule to change.
Although we expect our efforts and those of our external parties to be
successful, given the complex interaction of today's computing and
communications systems, we cannot be certain we will be completely
successful. Accordingly, we have considered the most reasonably likely worst
case Year 2000Y2K scenarios that could affect us or the Utility, and we believe that
they mainly involve public overreaction before and during the New Year period
that could create localized telephone problems due to congestion, temporary
gasoline shortages, and curtailment of natural gas usage by customers. In
addition, it is reasonably likely that there will be minor technical failures
such as localized telephone outages and small isolated malfunctions in our
computer systems that will be immediately repaired. None of these reasonably
likely scenarios are expected to have a material adverse impact on the
Utility's or our financial position, results of operations, or cash flows.
Nevertheless, if we, or third parties with which we have significant business
relationships, fail to achieve and sustain Year 2000Y2K 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 JuneSeptember 30, 1999, is $4.8$1.3 million for trading
activities and $0.7$1.7 million for non-trading activities.
In November 1998, the Emerging Issues Task Force of the Financial
Accounting Standards Board released Issue 98-10, Accounting for Energy
Trading and Risk Management Activities. This Issue states that all energy-
related contracts entered into with the objective of generating profits on or
from exposure to shifts or changes in market prices be marked to market with
the gains and losses reflected in the income statement. The Task Force
stipulates implementation for fiscal years beginning after December 15, 1998.
PG&E Corporation adopted this standard on January 1, 1999. The effect of
adoption on earnings and the financial position of PG&E Corporation was
immaterial.
On July 8, 1999, the CPUC authorized the Utility to recover the costs of
participating in the California Power Exchange block forward market.
Legal Matters:
In the normal course of business, both the Utility and PG&E Corporation are
named as parties in a number of claims and lawsuits. (See Note 6 of Notes to
Consolidated Financial Statements for further discussion of significant
pending legal matters.
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 Price Risk Management
Activities, above.)
PART II. OTHER INFORMATION
Item 4. Legal Proceedings
-----------------
As previously disclosed in PG&E Corporation and Pacific Gas
and Electric Company's Annual Report on Form 10-K for the
year ended December 31, 1998, Pacific Gas and Electric
Company is currently a defendant in three civil actions
pending in California courts. These cases are (1) Aguayo v.
Pacific Gas and Electric Company, filed March 15, 1995, in
Los Angeles County Superior Court, (2) Aguilar v. Pacific
Gas and Electric Company, filed October 4, 1996, in Los
Angeles County Superior Court, and (3) Acosta, et al. v.
Betz Laboratories, Inc., et al., filed November 27, 1996, in
Los Angeles Superior Court. These cases are collectively
referred to as the "Aguayo Litigation." In September 1999,
two cases which also had named PG&E Corporation as a
defendant (Little and Mustafa v. Pacific Gas and Electric
Company and PG&E Corporation and Whipple, et al. v. Pacific
Gas and Electric Company and PG&E Corporation, et al.) were
dismissed.
Each of the complaints in the Aguayo Litigation alleges
personal injuries and seeks compensatory and punitive
damages in an unspecified amount arising out of alleged
exposure to chromium contamination in the vicinity of
Pacific Gas and Electric Company's gas compressor stations
at Kettleman, Hinkley, and Topock, California. The
plaintiffs in the Aguayo Litigation include current and
former Pacific Gas and Electric Company employees, relatives
of current and former Company employees, residents in the
vicinity of the compressor stations, and persons who visited
the gas compressor stations. The plaintiffs also include
spouses or children of these plaintiffs who claim only loss
of consortium or injury through the alleged exposure of
their spouses or parents. In June 1998, the court found
that preconception claims are not recognizable under
California law and ordered the dismissal of such claims.
Pursuant to stipulation of the parties, the court has
entered the dismissals of 611 plaintiffs who either had
failed to respond to discovery or whose claims were based on
preconception injuries, from the Acosta, Aguilar, and Aguayo
cases. As a result of these dismissals, there are currently
approximately 1,650 plaintiffs in the Aguayo Litigation.
Although the trial date for the 20 trial test plaintiffs in
the Aguayo, Acosta and Aguilar cases had been set for
November 16, 1999, in Los Angeles Superior Court, the
parties have requested the court to extend the trial date in
these cases to May 1, 2000.
PG&E Corporation believes that the ultimate outcome of this
matter will not have a material adverse impact on its or
Pacific Gas and Electric Company's financial position or
results of operations.
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 sixnine months ended JuneSeptember 30, 1999, was
2.84.2.94. Pacific Gas and Electric Company's earnings to
combined fixed charges and preferred stock dividends ratio
for the sixnine months ended JuneSeptember 30, 1999, was
2.70.
2.79. 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, 33-5070733-
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 10.1 Officer Severance Policy, amended as of
July 21, 1999
Exhibit 10.2 Description of Compensation Arrangement
between PG&E Corporation and Thomas G. Boren
Exhibit 10.3 Description of Compensation Arrangement
between PG&E Corporation and Peter Darbee
Exhibit 11 Computation of Earnings Per Common Share
Exhibit 12.1 Computation of Ratios of Earnings to
Fixed Charges for Pacific Gas and Electric
Company
Exhibit 12.2 Computation of Ratios of Earnings to
Combined Fixed Charges and Preferred Stock
Dividends for Pacific Gas and Electric Company
Exhibit 27.1 Financial Data Schedule for the six monthsquarter
ended JuneSeptember 30, 1999, for PG&E Corporation
Exhibit 27.2 Financial Data Schedule for the six monthsquarter
ended JuneSeptember 30, 1999, for Pacific Gas and
Electric Company
(b) The following Current Reports on Form 8-K were filed
during the secondthird quarter of 1999 and through the date hereof (1):
1. March 24,August 18, 1999
Item 5. Other Events
Announcement relating to legislative proposal regarding
Pacific Gas and Electric Company's hydroelectric assets
2. September 13, 1999
Item 5. Other Events
A. Valuation and Disposition of Hydroelectric Generating
Assets
B. Post-Transition Period Ratemaking Proceeding
C. Electric Base Revenue Increase
3. September 17, 1999 (Filed by PG&E Corporation only)
Item 5. Other Events
Change in management
4. October 1, 1999
Item 5. Other Events
Proposed decision in Pacific Gas and Electric
Company's CostAuction of Capital Proceeding
2. April 15, 1999
Item 5. Other Events
Announcement of postponement of scheduled release
of first quarter earnings.
3. June 10, 1999
Item 5. Other Events
Final decision in Pacific Gas and Electric
Company's Cost of Capital Proceeding
4. June 11, 1999 - Form 8-K/A to Form 8-K dated February 17, 1999
Item 4. Changes in Registrant's Certifying Accountants.
Item 7. Financial Statements, Pro Forma Financial Information,
and ExhibitsHydroelectric Generating Assets
(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(Pacific1-2348 (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
August 4,October 15, 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
10.1 Officer Severance Policy, amended as of July 21, 1999
10.2 Description of Compensation Arrangement between PG&E
Corporation and Thomas G. Boren
10.3 Description of Compensation Arrangement between PG&E
Corporation and Peter Darbee
11 Computation of Earnings Per Common Share
12.1 Computation of Ratio of Earnings to Fixed
Charges for Pacific Gas and Electric Company
12.2 Computation of Ratio of Earnings to Combined Fixed
Charges and Preferred Stock Dividends for
Pacific Gas and Electric Company
27.1 Financial Data Schedule for the six monthsquarter ended
JuneSeptember 30, 1999 for PG&E Corporation
27.2 Financial Data Schedule for the six monthsquarter ended
JuneSeptember 30, 1999 for Pacific Gas and
Electric Company