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 March 31, 1994
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
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Commission File No. 1-2348
PACIFIC GAS AND ELECTRIC COMPANY
-------------------------------------------
(Exact name of registrant as specified in its charter)
California 94-0742640
- - ---------------------------- -------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
77 Beale Street, P.O. Box 770000, San Francisco, California 94177
-----------------------------------------------------------------
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (415) 973-7000
Indicate by check mark whether the registrant (1) has 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) has 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.
Class Outstanding at April 29, 1994
--------------- ------------------------------
Common Stock, $5 par value 430,885,607 shares
Form 10-Q
---------
TABLE OF CONTENTS
-----------------
PART I. FINANCIAL INFORMATION Page
- - ------------------------------ ----
Item 1. Consolidated Financial Statements and Notes
Statement of Consolidated Income........................ 1
Consolidated Balance Sheet.............................. 2
Statement of Consolidated Cash Flows.................... 4
Note 1: General
Basis of Presentation........................ 5
Decommissioning Costs........................ 5
Postemployment Benefits...................... 6
Note 2: Reasonableness Proceedings..................... 6
Note 3: Investments in Debt and Equity Securities...... 8
Note 4: Contingencies
Helms Pumped Storage Plant................... 10
Nuclear Insurance............................ 10
Environmental Remediation.................... 11
Legal Matters................................ 12
Item 2. Management's Discussion and Analysis of Consolidated
Results of Operations and Financial Condition
Results of Operations
Earnings Per Common Share............................. 14
Operating Revenues.................................... 14
Operating Expenses.................................... 15
Changing Competitive and Regulatory Environment....... 15
Rate Proceedings...................................... 20
Reasonableness Proceedings............................ 22
Legal Matters......................................... 23
Adoption of New Accounting Standards.................. 25
Liquidity and Capital Resources
Sources of Capital.................................... 25
Environmental Remediation............................. 26
Sale of Subsidiary.................................... 26
PART II. OTHER INFORMATION Page
- - --------------------------- ----
Item 1. Legal Proceedings
Franchise Fees Litigation............................. 27
Item 4. Submission of Matters to a Vote of Security-Holders..... 27
Item 5. Other Information
Ratios of Earnings to Fixed Charges and Ratios of
Earnings to Combined Fixed Charges and Preferred
Stock Dividends....................................... 29
Item 6. Exhibits and Reports on Form 8-K........................ 29
SIGNATURE.......................................................... 31
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<TABLE>
PART 1. FINANCIAL INFORMATION
Item 1. Consolidated Financial Statements
---------------------------------
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED INCOME
(unaudited)
<CAPTION>
- - --------------------------------------------------------------------------------------------
Three months ended March 31,
---------------------------
(in thousands, except per share amounts) 1994 1993
- - --------------------------------------------------------------------------------------------
<S> <C> <C>
OPERATING REVENUES
Electric $1,815,977 $1,722,289
Gas 698,294 741,529
---------- ----------
Total operating revenues 2,514,271 2,463,818
---------- ----------
OPERATING EXPENSES
Cost of electric energy 546,961 435,463
Cost of gas 316,818 348,218
Distribution 57,063 55,232
Transmission 17,260 47,259
Customer accounts and services 90,114 88,486
Maintenance 113,656 118,166
Depreciation and decommissioning 348,433 318,454
Administrative and general 195,169 264,592
Income taxes 249,710 197,813
Property and other taxes 80,815 83,047
Other 83,598 86,760
---------- ----------
Total operating expenses 2,099,597 2,043,490
---------- ----------
OPERATING INCOME 414,674 420,328
---------- ----------
OTHER INCOME AND (INCOME DEDUCTIONS)
Interest income 19,440 23,465
Allowance for equity funds used during construction 4,679 9,703
Other--net (8,363) (10,840)
---------- ----------
Total other income and (income deductions) 15,756 22,328
---------- ----------
INCOME BEFORE INTEREST EXPENSE 430,430 442,656
---------- ----------
INTEREST EXPENSE
Interest on long-term debt 155,724 175,286
Other interest charges 41,741 26,708
Allowance for borrowed funds used during construction (3,987) (15,002)
---------- ----------
Net interest expense 193,478 186,992
---------- ----------
NET INCOME 236,952 255,664
Preferred dividend requirement 14,458 16,760
---------- ----------
EARNINGS AVAILABLE FOR COMMON STOCK $ 222,494 $ 238,904
========== ==========
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING 428,531 428,426
EARNINGS PER COMMON SHARE $.52 $.56
DIVIDENDS DECLARED PER COMMON SHARE $.49 $.47
- - --------------------------------------------------------------------------------------------
<F/N>
The accompanying Notes to Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET
(unaudited)
<CAPTION>
- - --------------------------------------------------------------------------------------------
March 31, December 31,
(in thousands) 1994 1993
- - --------------------------------------------------------------------------------------------
<S> <C> <C>
ASSETS
PLANT IN SERVICE
Electric
Nonnuclear $16,848,704 $16,633,772
Diablo Canyon 6,522,552 6,518,413
Gas 7,215,766 7,146,741
----------- -----------
Total plant in service (at original cost) 30,587,022 30,298,926
Accumulated depreciation and decommissioning (11,543,555) (11,235,519)
----------- -----------
Net plant in service 19,043,467 19,063,407
----------- -----------
CONSTRUCTION WORK IN PROGRESS 526,205 620,187
OTHER NONCURRENT ASSETS
Oil and gas properties 561,649 573,523
Decommissioning funds 588,050 536,544
Other assets 533,048 497,689
----------- -----------
Total other noncurrent assets 1,682,747 1,607,756
----------- -----------
CURRENT ASSETS
Cash and cash equivalents 181,962 61,066
Accounts receivable
Customers 1,122,707 1,264,907
Other 121,684 123,255
Allowance for uncollectible accounts (24,221) (23,647)
Regulatory balancing accounts receivable 1,074,337 992,477
Inventories
Materials and supplies 240,455 239,856
Gas stored underground 108,645 170,345
Fuel oil 97,604 109,615
Nuclear fuel 135,096 134,411
Prepayments 46,643 56,062
----------- -----------
Total current assets 3,104,912 3,128,347
----------- -----------
DEFERRED CHARGES
Income tax-related deferred charges 1,140,407 1,246,890
Diablo Canyon costs 415,333 419,775
Unamortized loss net of gain on reacquired debt 391,926 395,659
Workers' compensation and disability claims recoverable 282,417 192,203
Other 425,117 488,302
----------- -----------
Total deferred charges 2,655,200 2,742,829
----------- -----------
TOTAL ASSETS $27,012,531 $27,162,526
=========== ===========
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<F/N>
(continued on next page)
</TABLE>
<TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET
(unaudited)
<CAPTION>
- - --------------------------------------------------------------------------------------------
March 31, December 31,
(in thousands) 1994 1993
- - --------------------------------------------------------------------------------------------
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common stock $ 2,145,391 $ 2,136,095
Additional paid-in capital 3,708,610 3,666,455
Reinvested earnings 2,638,586 2,643,487
----------- -----------
Total common stock equity 8,492,587 8,446,037
Preferred stock without mandatory redemption provision 732,995 807,995
Preferred stock with mandatory redemption provision 137,500 75,000
Long-term debt 9,084,132 9,292,100
----------- -----------
Total capitalization 18,447,214 18,621,132
----------- -----------
OTHER NONCURRENT LIABILITIES
Customer advances for construction 154,003 152,872
Workers' compensation and disability claims 249,000 157,000
Other 314,773 246,950
----------- -----------
Total other noncurrent liabilities 717,776 556,822
----------- -----------
CURRENT LIABILITIES
Short-term borrowings 392,073 764,163
Long-term debt 327,440 221,416
Accounts payable
Trade creditors 392,100 472,985
Other 389,362 389,065
Accrued taxes 505,581 303,575
Deferred income taxes 348,820 315,584
Interest payable 165,563 82,105
Dividends payable 225,125 203,923
Other 366,276 487,809
----------- -----------
Total current liabilities 3,112,340 3,240,625
----------- -----------
DEFERRED CREDITS
Deferred income taxes 3,855,244 3,978,950
Deferred investment tax credits 406,135 410,969
Other 473,822 354,028
----------- -----------
Total deferred credits 4,735,201 4,743,947
CONTINGENCIES (Notes 2 and 4) - -
----------- -----------
TOTAL CAPITALIZATION AND LIABILITIES $27,012,531 $27,162,526
=========== ===========
- - --------------------------------------------------------------------------------------------
<F/N>
The accompanying Notes to Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED CASH FLOWS
(unaudited)
<CAPTION>
- - --------------------------------------------------------------------------------------------
Three months ended March 31,
---------------------------
(in thousands) 1994 1993
- - --------------------------------------------------------------------------------------------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 236,952 $ 255,664
Adjustments to reconcile net income to
net cash provided by operating activities
Depreciation and decommissioning 348,433 318,454
Amortization 16,039 19,407
Deferred income taxes and investment tax credits--net (7,870) (41,844)
Allowance for equity funds used during construction (4,679) (9,703)
Net effect of changes in operating assets
and liabilities
Accounts receivable 144,345 124,464
Regulatory balancing accounts receivable (81,860) 153,374
Inventories 72,427 41,785
Accounts payable (80,588) (107,370)
Accrued taxes 211,585 258,029
Other working capital (28,656) 263,123
Other deferred charges 29,058 (125,110)
Other noncurrent liabilities 4,944 (14,296)
Other deferred credits 120,525 (17,254)
Other--net (4,132) 3,071
--------- ----------
Net cash provided by operating activities 976,523 1,121,794
--------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES
Construction expenditures (235,253) (459,556)
Allowance for borrowed funds used during construction (3,987) (15,002)
Nonregulated expenditures (29,300) (42,840)
Other--net 29,790 (8,199)
--------- ----------
Net cash used by investing activities (238,750) (525,597)
--------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES
Common stock issued 61,548 72,461
Common stock repurchased (553) (534)
Preferred stock issued 62,312 75,000
Preferred stock redeemed (82,965) (84,269)
Long-term debt issued 20,485 521,956
Long-term debt matured or reacquired (125,627) (97,687)
Short-term debt redeemed--net (372,090) (241,877)
Dividends paid (217,910) (205,625)
Other--net 37,923 (6,051)
--------- ----------
Net cash provided (used) by financing activities (616,877) 33,374
--------- ----------
NET CHANGE IN CASH AND CASH EQUIVALENTS 120,896 629,571
CASH AND CASH EQUIVALENTS AT JANUARY 1 61,066 97,592
--------- ----------
CASH AND CASH EQUIVALENTS AT MARCH 31 $ 181,962 $ 727,163
========= ==========
Supplemental disclosures of cash flow information
Cash paid for
Interest (net of amounts capitalized) $ 92,088 $ 10,102
Income taxes 67,758 25,005
- - --------------------------------------------------------------------------------------------
<F/N>
The accompanying Notes to Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
NOTE 1: GENERAL
- - ----------------
Basis of Presentation:
- - ---------------------
The accompanying unaudited consolidated financial statements of
Pacific Gas and Electric Company (PG&E) and its wholly owned and
majority-owned subsidiaries (collectively, the Company) have been
prepared in accordance with the interim period reporting requirements
of Form 10-Q. This information should be read in conjunction with
the Consolidated Financial Statements and Notes to Consolidated
Financial Statements incorporated by reference in the 1993 Annual
Report on Form 10-K.
In the opinion of management, the accompanying statements reflect all
adjustments which are necessary to present a fair statement of the
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. Results of operations for
interim periods are not necessarily indicative of results to be
expected for a full year.
Decommissioning Costs:
- - ---------------------
The estimated total obligation for decommissioning costs is
approximately $1.1 billion in 1994 dollars (or $4.5 billion in
escalated dollars); this obligation is being recognized ratably over
the facilities' lives. This estimate considers the total cost
(including labor, materials and other costs) of decommissioning and
dismantling plant systems and structures and includes a contingency
factor for possible changes in regulatory requirements and waste
disposal cost increases.
The decommissioning method selected for Diablo Canyon anticipates the
equipment, structures, and portions of the facility and site
containing radioactive contaminants will be removed or decontaminated
to a level that permits the property to be released for unrestricted
use shortly after cessation of operations. Humboldt Bay Power Plant
is being decommissioned under a method which consists of placing and
maintaining the facility in protective storage until some future time
when dismantling can be initiated.
As of March 31, 1994, the Company had accumulated in external trust
funds $588 million at fair value to be used for the decommissioning
of its nuclear facilities. The average annualized escalation rate
and the assumed return on qualified trust assets used to calculate
the decommissioning obligation are approximately 5.5% and 5.25%
(6.25% on nonqualified trust assets), respectively.
Postemployment Benefits:
- - -----------------------
Effective January 1, 1994, the Company adopted Statement of Financial
Accounting Standards (SFAS) No. 112, "Employers' Accounting for
Postemployment Benefits," which requires employers to adopt accrual
accounting for benefits provided to former or inactive employees and
their beneficiaries and covered dependents, after employment but
before retirement. Due to current regulatory treatment, adoption of
SFAS No. 112 did not have a significant impact on the Company's
financial position or results of operations. Adoption of SFAS No.
112 resulted in an increase of approximately $90 million in
consolidated liabilities and consolidated assets as of January 1,
1994.
NOTE 2: Reasonableness Proceedings
- - -----------------------------------
Recovery of energy costs through the Company's regulatory balancing
account mechanisms is subject to a California Public Utilities
Commission (CPUC) determination that such costs were incurred
reasonably.
During reasonableness proceedings, the Division of Ratepayer Advocates
(DRA), a consumer advocacy branch of the CPUC staff, as well as other
groups (intervenors) may make recommendations to the CPUC. An
Administrative Law Judge (ALJ) will review testimony and issue a
proposed decision. Neither the DRA's recommendations nor the ALJ's
proposed decision constitute a CPUC decision. The CPUC can accept all,
part or none of the recommendations or the ALJ's proposed decision in
its final decision. Under the current regulatory framework, annual
reasonableness proceedings are conducted by the CPUC on a historic
calendar year basis.
1988-1990: In March 1994, the CPUC issued final decisions covering the
years 1988 through 1990, ordering a disallowance of $90 million of gas
costs, plus accrued interest of approximately $25 million for the
Company's Canadian gas procurement activities and $8 million for gas
inventory operations. The Company intends to contest the Canadian gas
cost disallowance.
The decision on the Company's Canadian gas procurement activities found
that the Company could have saved its customers money if it had
bargained more aggressively with its then-existing Canadian suppliers
or bought lower-priced gas from other Canadian sources. The decision
states that the disallowances previously recommended by the DRA and
other intervenors overstate the magnitude of savings which the Company
could have achieved. The DRA had recommended that the Company refund
$392 million based on its contention that the Company should have
purchased 50% of its Canadian gas supplies on the spot market instead
of relying on long-term contracts. The CPUC concluded that it was
appropriate for the Company to take about 70% of its daily customer gas
demand at the actual price charged under its then-existing Canadian gas
supply contracts, but that the Company could have met the remainder of
its daily demand with lower priced gas, either under those same
contracts or with purchases from other Canadian natural gas sources.
In its decision to disallow $8 million for gas inventory operations,
the CPUC found the Company's gas inventory operations during 1988
through 1990 to be reasonable except that the Company should have
withdrawn more gas from storage during December 1990 for use by the
Company's electric department. Earlier, the DRA recommended a
disallowance of $37 million contending that the Company should have
withdrawn additional gas from storage in the winter of 1989-1990 and
December 1990 rather than burning fuel oil, which was more expensive.
CPUC consideration of other issues which relate to purchased electric
energy and certain contracts with Southwestern gas producers has been
deferred. With respect to purchased electric energy costs, the DRA
recommended a disallowance of $18 million for the Company's purchased
power expenses from the Pacific Northwest. The Company purchased
electric energy when it was cheaper than its incremental fossil fuel
generation costs. The DRA argues that if cheaper Canadian gas supplies
had been used, the Company's incremental fossil fuel generation costs
would have been lower than the purchased power costs. The DRA also
indicated that it will be filing recommendations for the effects of any
imprudently incurred Canadian gas costs on the prices paid by the
Company for energy purchased from qualifying facilities (QFs) and
geothermal steam sources. The DRA has not yet addressed issues related
to certain contracts with Southwestern gas producers.
1991: The DRA issued a report on the reasonableness of the Company's
gas procurement and operating activities for 1991. The DRA recommended
that the Company refund $116 million, consisting of $105 million
related to Canadian gas purchases and $11 million related to gas
inventory operations and Southwestern gas procurement issues. The
DRA's recommendations are based on the same theories outlined in the
DRA's reports for 1988 through 1990, as discussed above. A CPUC final
decision in this proceeding is expected later in 1994 or early in 1995.
1992: The DRA issued a report on the reasonableness of the Company's
gas procurement and operating activities for 1992, recommending a
disallowance of $92 million. The recommended disallowance includes $61
million related to Canadian gas purchases and $8 million related to gas
inventory operations, based on the same theories outlined in prior DRA
reports. Also included are disallowances totaling $23 million related
to Southwest gas transportation and procurement issues. It is possible
that similar issues will be raised regarding the Company's Canadian gas
procurement activities during 1993. However, the Company estimates the
disallowance that the DRA may recommend for 1993 should be
significantly lower than those for prior years.
Affiliate Audit: In October 1993, the DRA issued a report on its
investigation of the operations of Alberta and Southern Gas Co. Ltd.
(A&S) for 1988 through 1991. The investigation was initiated in
connection with the reasonableness proceeding for 1991. The DRA
reviewed certain nongas costs, primarily Canadian pipeline charges and
A&S overhead costs, and recommended a penalty and disallowance of $50
million and $6 million, respectively. The recommended penalty and
disallowance are primarily related to the Company's alleged failure to
properly oversee its subsidiary's activities. Recommendations related
to 1992 activities may be made in a subsequent report. The DRA has
subsequently indicated that it will withdraw the $6 million
disallowance recommendation.
The Company filed a motion with the CPUC asking it to disregard the
recommended penalty and disallowance because prior federal rulings
approved such costs and thus preempt the issue. In December 1993, an
ALJ denied this motion.
In addition, the DRA has indicated that it will be issuing a
supplemental report addressing matters relating to the Company's former
affiliate, Alberta Natural Gas Company (ANG) and the implications, if
any, of ANG's status as an affiliate of the Company. The DRA has noted
that a substantial portion of ANG's profits were derived from the
operation of the Cochrane liquids extraction plant, and that the
plant's profitability contributed to the Company's pretax profit of $49
million from the sale of its ANG shares in 1992.
Financial Impact of Reasonableness Proceedings: The Company believes
that its gas procurement activities, transportation arrangements and
operations were prudent and will vigorously contest any disallowance or
penalty recommended by the DRA or other parties.
The Company recorded a reserve of $61 million in 1993 and has accrued
approximately $90 million in the first quarter of 1994 as a result of
the CPUC's disallowances in the gas reasonableness proceedings for 1988
through 1990 and the Company's assessment of how the CPUC's decisions
may impact the open reasonableness issues. The Company currently is
unable to estimate the ultimate outcome of the gas reasonableness
proceedings, including the affiliate audit, or predict whether such
outcome will have a significant adverse impact on its results of
operations.
NOTE 3: Investments in Debt and Equity Securities
- - --------------------------------------------------
Effective January 1, 1994, the Company adopted SFAS No. 115,
"Accounting for Certain Investments in Debt and Equity Securities,"
which established new financial accounting and reporting standards
for investments in debt and equity securities. Most of the Company's
debt and equity securities, which are included in Decommissioning
Funds, are classified as available-for-sale. These securities are
reported at fair value, with unrealized gains and losses recorded to
accumulated depreciation and decommissioning, net of tax. Included
in cash and cash equivalents are short-term investments in debt
securities which are classified as held-to-maturity and are accounted
for at amortized cost.
Due to the nature of the Company's investments, the adoption of SFAS
No. 115 did not have a significant impact on the Company's financial
position or results of operations. The year-to-date proceeds from
sales of securities held as available-for-sale were $75.3 million.
The year-to-date gross realized gains and gross realized losses on
sales of securities held as available-for-sale were $1.3 million and
$.3 million, respectively. The cost of equity securities sold is
determined by specific identification. The cost of debt securities
sold is based on a first-in-first-out method.
The following table provides a comparison of amortized cost and fair
value by major investment type for securities available-for-sale and
held-to-maturity:
<TABLE>
<CAPTION>
- - ------------------------------------------------------------------------------------------------
(in thousands) March 31, 1994
- - ------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Gross Gross
unrealized unrealized
Amortized holding holding Fair
cost gains losses value
--------- ---------- ---------- --------
Securities available-for-sale:
Debt securities issued by the U.S.
Treasury and other U.S. government
corporations and agencies $ 66,603 $ 530 $ (311) $ 66,822
Obligations of states and political
subdivisions 436,575 19,489 (736) 455,328
Equity securities 21,549 10,617 (74) 32,092
Other 33,823 - (15) 33,808
-------- ------- ------- --------
Total securities available-
for-sale 558,550 30,636 (1,136) 588,050
Other debt securities held-to-maturity 44,634 - - 44,634
-------- ------- ------- --------
Total investments in securities $603,184 $30,636 $(1,136) $632,684
======== ======= ======= ========
</TABLE>
The contractual principal maturities of all securities are as follows:
<TABLE>
<CAPTION>
- - ------------------------------------------------------------------------------------------------
(in thousands) March 31, 1994
- - ------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
One year Five years
One year to five to ten After ten
or less years years years Total
-------- ---------- ---------- --------- ----------
Securities available-
for-sale (at fair value):
Debt securities issued by
the U.S. Treasury and
other U.S. government
corporations and agencies $ 28,047 $ 3,684 $ 3,091 $ 32,000 $ 66,822
Obligations of states and
political subdivisions 15,088 65,210 120,908 254,122 455,328
Other 33,808 - - - 33,808
-------- ------- -------- -------- --------
Total securities
available-for-sale 76,943 68,894 123,999 286,122 555,958
Other debt securities held-
to-maturity (at amortized
cost) 44,634 - - - 44,634
-------- ------- -------- -------- --------
Total investments
in securities $121,577 $68,894 $123,999 $286,122 $600,592
======== ======= ======== ======== ========
</TABLE>
NOTE 4: Contingencies
- - ----------------------
Helms Pumped Storage Plant (Helms):
- - ----------------------------------
Helms, a three-unit hydroelectric combined generating and pumped
storage facility, completion of which was delayed due to a water
conduit rupture in 1982 and various start-up problems related to the
plant's generators, became commercially operable in 1984. As a
result of the damage caused by the rupture and the delay in the
operational date, the Company incurred additional costs which are
currently excluded from rate base and lost revenues during the period
the plant was under repair.
The Company has filed an application for rate recovery of the
remaining unrecovered Helms costs, the associated revenue requirement
on such costs since 1984 and lost revenues during the time the
generators were being repaired. The remaining net unrecovered costs
of Helms (after adjustment for depreciation) and revenues discussed
above totaled $105 million at March 31, 1994.
In June 1993, the DRA issued its report on the Company's 1991 Helms
application and recommended a disallowance of all requested costs and
revenues. The DRA recommended ratepayers should not be held
responsible for plant costs or losses incurred by a utility due to
contractor error, whether or not the utility was prudent, and cited
past CPUC action for this policy. The DRA also contended the Company
acted imprudently in the management of the project and failed to
adequately oversee the engineering and design of the generators. In
addition, the DRA argued that the Company should not recover any
revenue requirements associated with the generator costs for the
period since 1984 because those revenues were not authorized
previously by the CPUC and would constitute retroactive ratemaking.
With respect to the lost revenues and related recorded interest
during the time that Helms was out of service for the modification
and repair of the generators, the DRA asserted the Company failed to
establish that the outage was not caused by a problem first
identified during the precommercial testing program.
The Company filed its rebuttal testimony in January 1994 asserting
that it was prudent in managing and overseeing the project and
various issues raised by DRA were not based on facts or were
irrelevant to the application. The Company has commenced settlement
discussions with the DRA in an attempt to resolve the treatment of
Helms costs. The Company is uncertain whether, and to what extent,
any of the remaining costs and revenues will be recovered through the
ratemaking process.
Nuclear Insurance:
- - -----------------
The Company is a member of Nuclear Mutual Limited (NML) and Nuclear
Electric Insurance Limited (NEIL I and II). If the nuclear plant of
a member utility is damaged or increased costs for business
interruption are incurred due to a prolonged accidental outage, the
Company may be subject to maximum assessments of $21 million
(property damage) or $7 million (business interruption), in each case
per policy period, if losses exceed premiums, reserves and other
resources of NML, NEIL I or NEIL II.
The federal government has enacted laws that require all utilities
with nuclear generating facilities to share in payment for claims
resulting from a nuclear incident. The Price-Anderson Act limits
industry liability for third-party claims resulting from any nuclear
incident to $9.3 billion per incident. Coverage of the first $200
million is provided by a pool of commercial insurers. If a nuclear
incident results in public liability claims in excess of $200
million, the Company may be assessed up to $159 million per incident,
with payments in each year limited to a maximum of $20 million per
incident.
Environmental Remediation:
- - -------------------------
The Company assesses, on an ongoing basis, measures that may need to
be taken to comply with laws and regulations related to hazardous
materials and hazardous waste compliance and remediation activities.
The Company may be required to pay for remedial action at sites where
the Company has been or may be a potentially responsible party under
the Comprehensive Environmental Response, Compensation, and Liability
Act (CERCLA; federal Superfund law) or the California Hazardous
Substance Account Act (California Superfund law). These sites
include former manufactured gas plant sites or sites used by the
Company for the storage or disposal of materials which may be
determined to present a significant threat to human health or the
environment because of an actual or potential release of hazardous
substances. Under CERCLA, the Company's financial responsibilities
may include remediation of hazardous wastes, even if the Company did
not deposit those wastes on the site.
The overall costs of the hazardous materials and hazardous waste
compliance and remediation activities ultimately undertaken by the
Company are difficult to estimate due to uncertainty concerning the
Company's responsibility, the complexity of environmental laws and
regulations, and the selection of compliance alternatives. However,
based on the information currently available, the Company has an
accrued liability as of March 31, 1994, of $60 million for hazardous
waste remediation costs. The ultimate amount of such costs may be
significantly higher if, among other things, the Company is held
responsible for cleanup at additional sites, other potentially
responsible parties are not financially able to contribute to these
costs, or further investigation indicates that the extent of
contamination and affected natural resources is greater than
anticipated at sites for which the Company is responsible.
The Company believes that the ultimate outcome of these matters will
not have a significant adverse impact on its financial position or
results of operations.
Legal Matters:
- - -------------
Antitrust Litigation: In December 1993, the County of Stanislaus,
California, and a residential customer of PG&E, filed a complaint
against PG&E and Pacific Gas Transmission Company on behalf of
themselves and purportedly as a class action on behalf of all natural
gas customers of PG&E, for the period of February 1988 through
October 1993. The complaint alleges that the purchase of natural gas
in Canada by A&S was accomplished in violation of various antitrust
laws which resulted in increased prices of natural gas for PG&E's
customers.
The complaint alleges that the Company could have purchased as much
as 50% of its Canadian gas on the spot market instead of relying on
long-term contracts and that the damage to the class members is at
least as much as the price differential multiplied by the replacement
volume of gas, an amount estimated in the complaint as potentially
exceeding $800 million. The complaint indicates that the damages to
the class could include over $150 million paid by the Company to
terminate the contracts with the Canadian gas producers in November
1993. The complaint also seeks recovery of three times the amount of
the actual damages pursuant to antitrust laws.
The Company believes the case is without merit and has filed a motion
to dismiss the complaint. The Company believes that the ultimate
outcome of the antitrust litigation will not have a significant
adverse impact on its financial position.
Hinkley Litigation: In 1993, a complaint was filed in San Bernardino
County Superior Court on behalf of a number of individuals seeking
recovery of an unspecified amount of damages for personal injuries
and property damage allegedly suffered as a result of exposure to
chromium near the Company's Hinkley Compressor Station, as well as
punitive damages. The original complaint has been amended, and
additional complaints have been filed, to include additional
plaintiffs.
The plaintiffs contend that the Company discharged chromium-
contaminated wastewater into unlined ponds, which led to chromium
percolating into the groundwater of surrounding property. The
plaintiffs further allege that the Company discharged the chromium
into those ponds to avoid costly alternatives.
In 1987, the Company undertook an extensive project to remediate
potential groundwater chromium contamination. The Company has
incurred substantially all of the costs it currently deems necessary
to clean up the affected groundwater contamination. In accordance
with the remediation plan approved by the regional water quality
control board, the Company will continue to monitor the affected area
and periodically perform environmental assessments.
In November 1993, the parties engaged in private mediation sessions.
In December 1993, the plaintiffs filed an offer to compromise and
settle their claims against the Company for $250 million.
The Company is unable to estimate the ultimate outcome of this
matter, but such outcome could have a significant adverse impact on
the Company's results of operations. The Company believes that the
ultimate outcome of this matter will not have a significant adverse
impact on its financial position.
QF Transmission Litigation: The Company is a defendant in a lawsuit,
currently in trial, resulting from the termination of a power
purchase agreement. The plaintiff contends the Company
misrepresented to the CPUC and to QFs its transmission capacity and
that the existence of transmission constraints extended the deadline
for delivery of energy. The plaintiff also alleges the Company had
an obligation to build transmission upgrades at the Company's
expense, which it did not fulfill. The complaint seeks compensatory
and punitive damages of an unspecified amount. However, the
plaintiff's damage expert has testified that in his opinion, the
plaintiff's lost profits were $80 million. There are other similarly
situated QFs which might choose to file similar complaints depending
on the outcome of this litigation. The Company believes that the
matter has no merit and that the ultimate outcome will not have a
significant adverse impact on its financial position or results of
operations.
Franchise Fees Litigation: In March 1994, Santa Clara and Alameda
counties filed a class action suit against the Company on behalf of
themselves and 45 other counties in the Company's service area. This
lawsuit alleges that the Company underpaid franchise fees to the
counties for the right to use or occupy public streets or roads as a
result of incorrectly computing these payments. The amount of
damages for alleged underpayments for the years 1987 through 1993
could be as high as $104 million, plus accrued interest of $21
million as of March 31, 1994. The Company believes that the ultimate
outcome of the franchise fees litigation will not have a significant
adverse impact on its financial position or results of operations.
Item 2. Management's Discussion and Analysis of Consolidated
----------------------------------------------------
Results of Operations and Financial Condition
---------------------------------------------
RESULTS OF OPERATIONS
- - ---------------------
Pacific Gas and Electric Company (PG&E) and its wholly owned and
majority-owned subsidiaries (collectively, the Company) have three
types of operations: utility, Diablo Canyon Nuclear Power Plant
(Diablo Canyon) and nonregulated through PG&E Enterprises
(Enterprises). For the three months ended March 31, 1994 and 1993,
selected financial information for the three types of operations is
shown below:
<TABLE>
<CAPTION>
- - ------------------------------------------------------------------------------------------------
Utility Diablo Canyon Enterprises Total
(in millions, except ---------------- -------------- ------------- -----------------
per share amounts) 1994 1993 1994 1993 1994 1993 1994 1993
- - ------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
THREE MONTHS ENDED
MARCH 31
Operating revenues
Electric $ 1,381 $ 1,340 $ 435 $ 382 $ - $ - $ 1,816 $ 1,722
Gas 644 684 - - 54 58 698 742
------- ------- ------ ------ ------ ------ ------- -------
Total operating
revenues 2,025 2,024 435 382 54 58 2,514 2,464
Operating expenses 1,740 1,731 303 259 56 54 2,099 2,044
------- ------- ------ ------ ------ ------ ------- -------
Operating income (loss) $ 285 $ 293 $ 132 $ 123 $ (2) $ 4 $ 415 $ 420
======= ======= ====== ====== ====== ====== ======= =======
Net income $ 141 $ 172 $ 96 $ 75 $ - $ 9 $ 237 $ 256
Earnings per common
share $ .31 $ .38 $ .21 $ .16 $ - $ .02 $ .52 $ .56
Total assets at March 31 $19,723 $19,334 $6,195 $6,379 $1,095 $1,032 $27,013 $26,745
- - ------------------------------------------------------------------------------------------------
</TABLE>
Earnings Per Common Share:
- - -------------------------
Earnings per common share for the three months ended March 31, 1994,
were lower than for the comparable period of 1993. This decrease
reflects a charge against earnings of approximately $90 million, or
12 cents per share, as a result of the California Public Utilities
Commission's (CPUC) disallowances in the gas reasonableness
proceedings for 1988 through 1990 and the Company's assessment of how
the CPUC's decisions may impact the open reasonableness issues. Most
of this charge was recorded in Other Income and (Income Deductions).
(See the Reasonableness Proceedings section below and Note 2 of Notes
to Consolidated Financial Statements for further discussion.)
Operating Revenues:
- - ------------------
Operating revenues for the three months ended March 31, 1994,
increased $50 million compared with the same period of 1993. A
significant portion of the increase was due to an increase in Diablo
Canyon operating revenues resulting from the annual increase in the
price per kilowatthour (kWh) as provided in the Diablo Canyon rate
case settlement and increased generation due to fewer scheduled
refueling outage days in 1994.
Operating Expenses:
- - ------------------
Operating expenses for the three months ended March 31, 1994,
increased $55 million compared with the same period of 1993,
resulting from an increase of $111 million in the cost of electric
energy offset by a decrease of $69 million in administrative and
general expense. Most of the increase in the cost of electric energy
was due to an increase in the cost per kWh for purchased power and an
increase in the volume of gas used to provide electric energy. The
majority of the decrease in administrative and general expense was
due to benefit cost reductions and savings realized from the
Company's 1993 workforce reduction program.
Changing Competitive and Regulatory Environment:
- - -----------------------------------------------
Competitive and regulatory changes in the Company's gas and electric
businesses are occurring at an ever increasing rate. In response to
increasing competitive pressures on the Company's largest electric and
gas customers, the Company made several proposals in early 1994 to
modify the regulatory process in which it operates and to provide
additional pricing flexibility to those customers with the most
competitive options. These proposals are discussed below under the
Regulatory Reform Initiative (RRI) and the Long-Term Noncore Gas
Transportation Prices sections.
In April 1994, the California Public Utilities Commission (CPUC) issued
an order instituting a rulemaking and investigation (OIR/OII) on
electric industry restructuring. The proposal, which is subject to
comment and modification, involves two major changes in electric
industry regulation. The first would move electric utilities from
traditional cost-of-service to performance-based ratemaking. The
second would unbundle electric services and require the phase-in of
retail wheeling over a six-year period beginning in 1996. If adopted,
the proposals would require significant changes in the operation and
regulation of the Company's electric business. The CPUC's proposal is
discussed in more detail below.
CPUC Electric Industry Restructuring Proposal: The OIR/OII follows a
report issued by the CPUC's Division of Strategic Planning in February
1993, which concluded that the current regulatory approach is
incompatible with the emerging industry structure resulting from
technological change, competitive pressure and new market forces.
In the OIR/OII, the CPUC envisions two major changes in electric
industry regulation. First, traditional cost-of-service ratemaking,
which tends to base utility earnings on capital expenditures and
recovery of expenses, would be replaced by performance-based regulation
designed to provide stronger incentives for efficient utility
operations, management and investment. The CPUC indicated that the
ongoing utility incentive rate application proceedings, including the
Company's RRI, would be used to develop performance-based programs,
which may vary in detail among the utilities. Implementation of those
programs is scheduled to take effect by January 1996.
Second, electric services would be unbundled, with direct consumer
access to a range of electric generation providers, including the
utility. The utility would be obligated to provide transmission and
distribution services on a nondiscriminatory basis to these customers.
Coinciding with these changes, the CPUC foresees developing a
competitive spot market for electric generation, and an increasing need
for inter-regional coordination of the electric grid. Existing
resource planning and procurement approaches would be abolished. In
addition, the energy rate adjustment mechanism (ERAM) not related to
the energy efficiency programs and other balancing account mechanisms
would be discontinued for direct access customers. The CPUC stated
that its proposal seeks to put downward pressure on prices, encourage
an efficient, environmentally sound electric services infrastructure
and enhance California's competitiveness.
Under the OIR/OII, direct access to generation for the Company's
industrial customers representing 16% of its total retail electric
revenue would be phased in over a three-year period beginning in
January 1996. Commercial customers representing 39% of total retail
electric revenue would have direct access beginning in January 1999.
Beginning in January 2002, all remaining customers, primary
residential, representing 45% of total retail electric revenue, would
have direct access.
With respect to electric services, the CPUC will open at least two
investigation proceedings to examine (1) cost allocations of and the
potential for uneconomic utility generating assets, and (2) unbundling
and pricing of utility services for direct access. Direct access
customers who purchase electricity from another source would continue
to secure some services from the utility, including distribution,
transmission, system control and coordination, and other required
services. Utilities would be given the pricing flexibility to compete
effectively for direct access customers. Prices negotiated between the
utility and direct access customers could not exceed the tariffed rate
or fall below the utility's marginal cost of providing the service.
The CPUC proposes that discounts given to direct access customers would
be absorbed by the Company's shareholders.
To ensure an orderly transition that maintains the financial integrity
of the utilities, the CPUC proposed that stranded costs of utility
generating assets be recovered through a "competition transition
charge." All consumers, including direct access consumers, would
contribute to recovery of these costs. To the extent that uneconomic
costs are passed on to all ratepayers through a transition mechanism,
the CPUC proposes not to allow any customer class' overall allocation
of generation costs or amortization schedules to exceed current levels,
in order to avoid a shift of those costs among customer classes or
across generations of customers. The OIR/OII states that utilities
would not be at risk for recovery of the uneconomic portion of the
utilities' generating assets. The CPUC's investigation into uneconomic
generating assets will include consideration of any costs relating to
existing utility obligations under certain electric purchase contracts
as well as long-term fuel contracts. The Diablo Canyon rate case
settlement is not specifically addressed in the OIR/OII.
The utility would remain the provider of last resort for all customers.
Direct access customers would be permitted to return to utility service
on 12-months' notice, or, if a customer chooses to return in less than
12 months, the utility would be allowed to charge incremental costs
until the 12-month period has expired.
Initial comments on the proposal are due in June 1994. The CPUC has
scheduled a full panel hearing in June 1994 to hear public comments and
intends to hold further hearings. The CPUC anticipates adopting a
final policy statement in August 1994. The two companion
investigations described above are expected to be completed by June
1995 so that eligible customers may commence service in January 1996.
The CPUC will open a further investigation in July 1996 to assess the
direct access program and determine whether and how to expand
eligibility to other customers.
RRI: In March 1994, the Company filed an application with the CPUC
requesting it adopt the Company's proposed RRI and approve 1995
electric and gas base revenue requirements. The Company's proposal is
the result of discussions with the CPUC, customers and other interested
parties concerning various reforms to the current regulatory approach
to setting rates.
The Company's RRI has three components: (1) performance based
ratemaking (PBR) for determining base revenues; (2) establishment of
the large electric manufacturing class (LEMC) of customers; and (3) use
of market benchmarks to evaluate gas procurement costs. Specific
proposals regarding the third component are not included in the
Company's March 1994 filing but are expected to be filed at a later
date.
In its filing, the Company proposes a schedule calling for hearings
beginning in June and a final CPUC decision by the end of 1994. The
Company has requested that the RRI become effective on January 1, 1995.
Under the Company's PBR proposal, electric and natural gas base
revenues would be determined annually by formula rather than through
General Rate Cases, Attrition Rate Adjustments and Cost of Capital
proceedings. Base revenues are intended to recover the Company's fixed
costs and nonfuel variable costs and provide a return on invested
capital.
The PBR mechanism will not apply to the base revenue associated with
Diablo Canyon, including Diablo Canyon decommissioning costs, which
will continue to be determined pursuant to the Diablo Canyon rate case
settlement, or with the LEMC customers.
Revenues to offset fuel and fuel-related costs would still be
determined in the Energy Cost Adjustment Clause (ECAC) proceeding for
electric operations and the Biennial Cost Allocation Proceeding (BCAP)
for gas operations.
The Company's proposed PBR mechanism would determine the base revenues
by multiplying the base revenues authorized for the prior year by an
index consisting of inflation plus customer growth less a productivity
factor. Those revenues would also be adjusted up or down depending on
the Company's achievement relative to four performance standards:
Customer Energy Efficiency (CEE) programs, Energy Bills, Customer
Satisfaction and Electric Service Reliability. The adjustments related
to the Company's performance in these four areas would be one-time
modifications to that year's base revenues. The adjustments for CEE
incentives would be determined under existing ratemaking procedures.
The maximum adjustment that the Company could earn or lose related to
Energy Bills and Customer Satisfaction is $25 million per year for
each, and the maximum for Electric Service Reliability is $19 million
per year. Under PBR, the Company could also apply for an adjustment to
base revenues due to the occurrence of certain extraordinary events
outside the Company's control.
The PBR proposal provides for the sharing between ratepayers and
shareholders of earnings above or below a target utility return on
equity (ROE) that would be computed annually. To the extent actual ROE
varies more than 200 basis points above or below the target ROE, the
difference would be shared equally with ratepayers through a reduction
or increase in the next year's base revenue. If actual ROE was more
than 500 basis points above or below the target ROE, then the Company
and the CPUC would each have the option to initiate a proceeding to
reexamine the PBR formula.
The Company is proposing that base revenue indexing begin in 1995.
However, the Company proposes to forgo any increase in the electric
base revenue for 1995 determined under the PBR mechanism. Instead,
1995 electric base revenue would be held at the 1994 level.
In its filing, the Company proposes that the RRI remain in place
indefinitely. The Company recommends that after five years the CPUC
review the PBR mechanism and make any necessary adjustments, but not
return to the use of traditional rate cases to set rates.
As proposed by the Company, the LEMC would consist of the Company's
largest electric accounts engaged in manufacturing. Currently,
approximately 120 accounts would qualify for inclusion in the LEMC.
The Company proposes to reduce rates for the LEMC customers in the
first year of the RRI by $27 million compared to current rates.
LEMC customers would be removed from cost-of-service ratemaking.
Standard LEMC prices would be determined every year by an index
formula, similar to that used in the PBR mechanism, which is intended
to reflect inflation less a productivity factor. In addition, several
long-term pricing options designed to respond to these customers'
competitive alternatives would be offered to the LEMC. The Company
also seeks authorization to negotiate and enter into customized
contracts with LEMC customers. In some cases, the customized contracts
would become effective without prior approval or subsequent review by
the CPUC of the contract terms.
Generally, the Company proposes to separate the costs allocated to the
LEMC and bear the risk of cost recovery if sales to these customers
decline over time. The Company's shareholders would also bear the risk
of LEMC costs that increase faster than the LEMC price index.
Long-Term Noncore Gas Transportation Prices: In March 1994, the
Company filed a proposal with the CPUC requesting authorization to
implement an alternative long-term noncore gas transportation price.
This price would be offered to the Company's largest industrial and
cogeneration gas transport customers under a standard ten-year service
agreement.
The proposed prices are intended to enable the Company to more
effectively meet intensified competition by allowing it to offer a
long-term competitive price without having to obtain CPUC approval on a
contract-by-contract basis as is currently required under the Expedited
Application Docket (EAD) procedure (the existing competitive gas
transportation contract procedure).
The proposed prices are within the range of prices negotiated under
existing EAD contracts and will exceed the marginal cost of serving the
customers eligible for the new prices. The Company's shareholders will
bear the risk of any revenue shortfalls attributable to any differences
between the long-term price option and the customer's otherwise
applicable price. The Company has requested that the proposed price
changes become effective no later than June 1, 1994. If approved, the
prices would be offered to existing qualifying customers over a two-
month subscription period commencing on that date.
Financial Impact of the Changing Competitive and Regulatory
Environment: Based on the regulatory framework in which it operates,
the Company currently accounts for the economic effects of regulation
in accordance with the provisions of Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types
of Regulation." As a result of applying the provisions of SFAS No. 71,
the Company has accumulated approximately $3 billion of regulatory
assets including balancing accounts as of March 31, 1994.
In the event that recovery of specific costs through rates becomes
unlikely or uncertain for a portion or all of the Company's utility
operations, whether resulting from the expanding effects of competition
or specific regulatory actions which move the Company away from cost-
of-service ratemaking, SFAS No. 71 would no longer apply.
Discontinuation of SFAS No. 71 would cause the write-off of applicable
portions of regulatory assets, including regulatory balancing accounts
receivable and those regulatory assets included in deferred charges,
which could have a significant adverse impact on the Company's
financial position or results of operations.
It is anticipated that as proposed, the PBR component of the RRI will
act as a surrogate for traditional cost-of-service ratemaking. As
such, the Company would continue to apply SFAS No. 71 to the majority
of its electric and gas operations.
However, if the LEMC component of the RRI and the long-term noncore gas
transportation pricing are adopted as proposed, they would deviate from
cost-of-service ratemaking and the Company would discontinue
application of SFAS No. 71 for those customers receiving these new
rates. The resulting aggregate write-off upon discontinuation of SFAS
No. 71 for these two groups of customers is currently estimated at $90
million. The estimated amount related to the affected electric and gas
customers is based on the base revenue allocation currently used in
setting rates; the actual amount could vary depending on the allocation
method adopted by the CPUC.
In addition to the potential write-offs associated with discontinuation
of SFAS No. 71 discussed above, the Company may be subject to
additional write-offs attributable to those regulatory mechanisms
proposed to be discontinued as part of the RRI.
The CPUC's OIR/OII could impact the Company's recovery of its costs and
investments in electric utility assets, Diablo Canyon rate case
settlement and continued application of SFAS No. 71. The final
determination of the impact will be dependent upon the form of
regulation, including transition mechanisms, if any, ultimately adopted
by the CPUC, and the effects of competition. The Company is unable to
predict the ultimate effect of the OIR/OII on its financial position or
results of operations.
Rate Proceedings:
- - ----------------
In addition to the RRI and the long-term noncore gas transportation
price proposals discussed above, the following rate proceedings are
also in progress.
Electric Fuel and Sales Balancing Accounts: In the 1993 ECAC decision,
the CPUC approved the Company's request to defer beyond 1994 $255
million of estimated undercollections in the ECAC/ERAM balancing
accounts. The actual ECAC/ERAM net undercollection at December 31,
1993, was $525 million. With the stated objective of providing
additional incentives for cost containment, the CPUC refused to allow
the Company to collect interest on the revenue requirement deferral and
ordered the reinstatement of the Annual Energy Rate (AER) mechanism.
The reinstatement of the AER places the Company at risk for nine
percent of the variations between actual and forecasted energy
expenses.
In April 1994, the Company filed an application with the CPUC proposing
an electric rate increase of two percent due to a net increase in the
ECAC/AER/ERAM/Low Income Rate Assistance electric revenue requirement.
If adopted, the requested rate increase of two percent would result in
an estimated net electric revenue requirement increase of $157 million,
effective January 1, 1995.
The Company's proposal limits the requested increase to two percent by
including only partial recovery of the projected balance of the ECAC
undercollection of $521 million at December 31, 1994, and deferring
cost recovery of approximately $275 million of ECAC undercollection
beyond 1995. The filing also proposes to forgo collection of interest
on the ECAC deferral and to eliminate the AER mechanism beginning
January 1, 1995. In its application, the Company argues that the RRI
recently proposed by the Company includes significant new energy cost
control incentives which are better than the AER, and therefore
requests the CPUC eliminate the AER. (See the Changing Competitive and
Regulatory Environment section for further discussion of the RRI and
these incentives.)
BCAP: In March 1994, the Company submitted an update to its core
(residential and smaller commercial customers) trigger filing which was
originally submitted in September 1993. A trigger filing is permitted
under the BCAP mechanism to set new rates in the second year of the
BCAP if overcollections or undercollections in certain balancing
accounts would change core rates by more than 5%. The March update
filing, as revised in May, reflects the implementation of interstate
capacity brokering and includes February 28, 1994, account balances
which would result in an increase of $162 million (9.3 percent) in core
rates over rates currently in effect. The Company requests that the
proposed increase in rates become effective on June 15, 1994. The DRA
and certain intervenors have protested the Company's request for an
adjustment. A CPUC decision is expected in June 1994.
Cost of Capital: In May 1994, the Company filed an application with
the CPUC in the 1995 Cost of Capital proceeding requesting the
following:
Utility
Capital Weighted
Structure Cost/Return Cost
Common equity 48.00% 12.50% 6.00%
Preferred stock 5.50 8.12 .45
Long-term debt 46.50 7.53 3.50
----- ----- ----
Total requested return
on average utility
rate base 9.95%
====
The requested return on common equity and common equity ratio is an
increase from the 11.00% and 47.50%, respectively, authorized in 1994.
These increases reflect higher interest rates and increased regulatory
and competitive risks. An additional 75 basis points was included in
the Company's requested return on common equity in order to address, in
particular, the added risks associated with the CPUC's proposed OIR/OII
on electric industry restructuring. If adopted, the Company's request
would result in an annual revenue requirement increase of $131 million
for electric rates and $41 million for gas rates, effective January
1995.
Reasonableness Proceedings:
- - --------------------------
As discussed in Note 2 of Notes to Consolidated Financial Statements,
the CPUC reviews the reasonableness of the Company's energy costs on an
annual basis. As part of this review, recommendations may be made by
the Division of Ratepayer Advocates (DRA), a consumer advocacy branch
of the CPUC, as well as other groups (intervenors). An Administrative
Law Judge (ALJ) of the CPUC will review testimony and issue a proposed
decision. The CPUC can accept all, part or none of the recommendations
or the ALJ's proposed decision in its final decision.
In March 1994, the CPUC issued final decisions covering the years 1988
through 1990, ordering a disallowance of $90 million of gas costs, plus
accrued interest of approximately $25 million for the Company's
Canadian gas procurement activities and $8 million for gas inventory
operations. The Company intends to contest the Canadian gas cost
disallowance.
The decision on the Company's Canadian gas procurement activities found
that the Company could have saved its customers money if it had
bargained more aggressively with its then-existing Canadian suppliers
or bought lower-priced gas from other Canadian sources.
The CPUC's decision on the Company's gas inventory operations during
1988 through 1990 found that the Company should have withdrawn more gas
from storage during December 1990 for use by the Company's electric
department. CPUC consideration of issues which relate to purchased
electrical energy and certain contracts with Southwestern gas producers
during 1988 through 1990 has been deferred.
The DRA has contended that the Company overpaid for Canadian gas by
$105 million and $61 million in 1991 and 1992, respectively. It is
possible that similar issues will be raised regarding the Company's
Canadian gas procurement activities during 1993. In addition, the DRA
recommended disallowances of $11 million and $31 million for 1991 and
1992, respectively, relating to gas inventory operations and Southwest
gas issues.
The DRA also issued a report on its investigation of the operations of
Alberta and Southern Gas Co. Ltd. (A&S) recommending a penalty and
disallowance of $50 million and $6 million, respectively, for 1988
through 1991. The investigation was initiated in connection with the
reasonableness proceeding for 1991. The recommended penalty and
disallowance are primarily related to the Company's alleged failure to
properly oversee its subsidiary's activities. The DRA has subsequently
indicated that it will withdraw the $6 million disallowance
recommendation. Recommendations related to 1992 activities may be made
in a subsequent report.
In addition, the DRA has indicated that it will be issuing a
supplemental report addressing matters relating to the Company's former
affiliate, Alberta Natural Gas Company (ANG) and the implications, if
any, of ANG's status as an affiliate of the Company. The DRA has noted
that a substantial portion of ANG's profits were derived from the
operation of the Cochrane liquids extraction plant, and that the
plant's profitability contributed to the Company's pretax profit of $49
million from the sale of its ANG shares in 1992.
The Company believes that its gas procurement activities,
transportation arrangements and operations were prudent and will
vigorously contest any disallowance or penalty recommended by the DRA
or other parties.
The Company recorded a reserve of $61 million in 1993 and has accrued
approximately $90 million in the first quarter of 1994 as a result of
the CPUC's disallowances in the gas reasonableness proceedings for 1988
through 1990 and the Company's assessment of how the CPUC's decisions
may impact the open reasonableness issues. The Company currently is
unable to estimate the ultimate outcome of the gas reasonableness
proceedings, including the affiliate audit, or predict whether such
outcome will have a significant adverse impact on its results of
operations.
Legal Matters:
- - -------------
Antitrust Litigation: In December 1993, the County of Stanislaus,
California and a residential customer of PG&E, filed a complaint
against PG&E and Pacific Gas Transmission Company on behalf of
themselves and purportedly as a class action on behalf of all natural
gas customers of PG&E for the period of February 1988 through October
1993. The complaint alleges that the purchase of natural gas in
Canada by A&S was accomplished in violation of various antitrust laws
which resulted in increased prices of natural gas for PG&E's
customers.
The complaint alleges that the Company could have purchased as much
as 50% of its Canadian gas on the spot market instead of relying on
long-term contracts and that the damage to the class members is at
least as much as the price differential multiplied by the replacement
volume of gas, an amount estimated in the complaint as potentially
exceeding $800 million. The complaint indicates that the damages to
the class could include over $150 million paid by the Company to
terminate the contracts with the Canadian gas producers in November
1993. The complaint also seeks recovery of three times the amount of
the actual damages pursuant to antitrust laws.
The Company believes the case is without merit and has filed a motion
to dismiss the complaint. The Company believes that the ultimate
outcome of the antitrust litigation will not have a significant
adverse impact on its financial position.
Hinkley Litigation: In 1993, a complaint was filed on behalf of a
number of individuals seeking recovery of an unspecified amount of
damages for personal injuries and property damage allegedly suffered
as a result of exposure to chromium near the Company's Hinkley
Compressor Station, as well as punitive damages. The original
complaint has been amended, and additional complaints have been
filed, to include additional plaintiffs.
In 1987, the Company undertook an extensive project to remediate
potential groundwater chromium contamination. The Company has
incurred substantially all of the costs it currently deems necessary
to clean up the affected groundwater contamination. In accordance
with the remediation plan approved by the regional water quality
board, the Company will continue to monitor the affected area and
perform environmental assessments.
In November 1993, the parties engaged in private mediation sessions.
In December 1993, the plaintiffs filed an offer to compromise and
settle their claims against the Company for $250 million.
The Company is unable to estimate the ultimate outcome of this
matter, but such outcome could have a significant adverse impact on
the Company's results of operations. The Company believes that the
ultimate outcome of this matter will not have a significant adverse
impact on its financial position. (See Note 4 of Notes to
Consolidated Financial statements for further discussion).
QF Transmission Litigation: The Company is a defendant in a lawsuit,
currently in trial, resulting from the termination of a power
purchase agreement. The plaintiff contends the Company
misrepresented to the CPUC and to QFs its transmission capacity and
that the existence of transmission constraints extended the deadline
for delivery of energy. The plaintiff also alleges the Company had
an obligation to build transmission upgrades at the Company's
expense, which it did not fulfill. The complaint seeks compensatory
and punitive damages of an unspecified amount. However, the
plaintiff's damage expert has testified that in his opinion, the
plaintiff's lost profits were $80 million. There are other similarly
situated QFs which might choose to file similar complaints depending
on the outcome of this litigation. The Company believes that the
matter has no merit and that the ultimate outcome will not have a
significant adverse impact on its financial position or results of
operations.
Franchise Fees Litigation: In March 1994, Santa Clara and Alameda
counties filed a class action suit against the Company on behalf of
themselves and 45 other counties in the Company's service area. This
lawsuit alleges that the Company underpaid franchise fees to the
counties for the right to use or occupy public streets or roads as a
result of incorrectly computing these payments. Should plaintiffs
prevail, the Company currently estimates that its annual system-wide
county franchise fees could increase by approximately $15 million.
The amount of damages for alleged underpayments for the years 1987
through 1993 could be as high as $104 million, plus accrued interest
of $21 million as of March 31, 1994. The Company believes that the
ultimate outcome of the franchise fees litigation will not have a
significant adverse impact on its financial position or results of
operations.
Adoption of New Accounting Standards:
- - ------------------------------------
Postemployment Benefits: SFAS No. 112, "Employers' Accounting for
Postemployment Benefits, requires employers to adopt accrual
accounting for benefits provided to former or inactive employees and
their beneficiaries and covered dependents, after employment but
before retirement. Due to current regulatory treatment, adoption of
SFAS No. 112 did not have a significant impact on the Company's
financial position or results of operations. Adoption of SFAS No.
112 resulted in an increase of approximately $90 million in
consolidated liabilities and consolidated assets as of January 1,
1994. (See Note 1 of Notes to Consolidated Financial Statements for
further discussion of postemployment benefits.)
Investment in Debt and Equity Securities: SFAS No. 115 established
new financial accounting and reporting standards for investments in
debt and equity securities. The adoption of SFAS No. 115 did not
have a significant impact on the Company's financial position or
results of operations. (See Note 3 of Notes to Consolidated
Financial Statements for further discussion.)
LIQUIDITY AND CAPITAL RESOURCES
- - -------------------------------
Sources of Capital:
- - ------------------
The following debt and equity securities were issued, reacquired or
redeemed through March 31, 1994:
Debt:
(in thousands)
Redeemed Interest Rates Amount
- - -------- -------------- --------------
Mortgage bonds 7.50% $80,000
Medium-term notes 10.05% and 10.10% 40,000
Equity:
Issued Dividend Rates Amount
- - ------ -------------- --------
Preferred stock 6.30% $62,500
Common stock
Savings Fund Plan N/A 37,895
Dividend Reinvestment
Plan N/A 22,968
Long-term Incentive
Plan N/A 685
Redeemed
- - --------
Preferred stock 8.16% $75,000
In addition, the Company issued approximately $30 million of medium-
term notes with interest rates ranging from 6.50% to 7.88% in April
1994.
Proceeds from the issuance of securities were used for capital
expenditures, refundings and other general corporate purposes.
Environmental Remediation:
- - -------------------------
The Company assesses, on an ongoing basis, measures that may need to
be taken to comply with laws and regulations related to hazardous
materials and hazardous waste compliance and remediation activities.
Although the ultimate amount of costs that will be incurred by the
Company in connection with its compliance and remediation activities
is difficult to estimate due to uncertainty concerning the Company's
responsibility and the extent of contamination, the complexity of
environmental laws and regulations and the selection of compliance
alternatives, the Company has an accrued liability as of March 31,
1994, of $60 million for hazardous waste remediation costs. (See
further discussion of the accrued liability for hazardous waste
remediation costs in Note 4 of Notes to Consolidated Financial
Statements.)
Sale of Subsidiary:
- - -------------------
In April 1994, the Company announced that it has deferred its plan to
divest PG&E Resources Company (Resources), a wholly owned indirect
subsidiary of PG&E Enterprises. The Company is reevaluating the
strategic value of Resources in light of the CPUC's proposal in April
on electric industry restructuring and current market conditions.
Resources, which is engaged in oil and gas exploration, is
headquartered in Dallas, Texas.
PART II. OTHER INFORMATION
---------------------------
Item 1. Legal Proceedings
-----------------
Franchise Fees Litigation
On March 31, 1994, the Counties of Alameda and Santa Clara filed a
complaint in Santa Clara County Superior Court against the Company on
behalf of themselves and purportedly as a class action on behalf of 47
counties with which the Company has gas or electric franchise contracts.
Franchise contracts require the Company to pay fees on an annual basis
to cities and counties for the right to use or occupy public streets and
roads. The complaint alleges that, since at least 1988, the Company has
intentionally underpaid its franchise fees to the counties in an
unspecified amount.
The complaint cites two reasons for the alleged underpayment of
fees. The plaintiffs allege that the Company has been using the wrong
methodology to compute the franchise fees payable to the plaintiff
counties. The plaintiffs also allege that fees have been underpaid due
to incorrect calculations under the methodology used by the Company.
Based on limited investigation thus far, should the counties prevail on
the issue of franchise fee calculation methodology, the Company's annual
system-wide county franchise fees could increase by approximately $15
million. The complaint also seeks damages for alleged underpayments for
the years 1987 through 1993, which could be as much as $104 million,
plus interest estimated at approximately $21 million through March 31,
1994.
The Company believes that the ultimate outcome of the franchise fees
litigation will not have a significant adverse impact on its financial
position or results of operations.
Item 4. Submission of Matters to a Vote of Security-Holders
----------------------------------------------------
On April 20, 1994, the Company held its regular annual meeting of
shareholders. At that meeting, the following matters were voted as
indicated:
1. Election of the following directors to serve until the next annual
meeting of shareholders or until their successors shall be elected
and qualified:
For Withheld
---------- -----------
Richard A. Clarke 337,373,474 10,219,488
Harry M. Conger 338,891,203 8,701,758
William S. Davila 337,896,954 9,696,007
Melvin B. Lane 338,244,512 9,348,449
Leslie L. Luttgens 338,061,351 9,531,611
Richard B. Madden 338,844,437 8,748,524
George A. Maneatis 338,406,205 9,186,757
Mary S. Metz 338,277,505 9,315,455
William F. Miller 338,736,365 8,856,595
John B.M. Place 338,669,295 8,923,666
Samuel T. Reeves 338,895,156 8,697,805
Carl E. Reichardt 338,187,768 9,405,193
John C. Sawhill 338,737,463 8,855,498
Alan Seelenfreund 337,904,939 9,688,023
Stanley T. Skinner 338,244,411 9,348,550
Barry Lawson Williams 338,342,029 9,250,932
2. Ratification of the selection of Arthur Andersen & Co. as
independent public accountants for the year 1994:
For: 339,300,651
Against: 3,623,687
Abstain: 4,669,250
Broker non-votes*: 0
3. Approval of a shareholder proposal to limit the chief executive
officer's salary to 25 times the average employee's 1992 salary
with adjustments tied to the Company's 10-year average performance:
For: 26,052,336
Against: 245,688,451
Abstain: 11,408,664
Broker non-votes*: 64,444,137
- - ----------------------------------
* A non-vote occurs when a nominee holding shares for a beneficiary
owner votes on one proposal, but does not vote on another proposal
because the nominee does not have discretionary voting power and has not
received instructions from the beneficial owner.
Item 5. Other Information
-----------------
Ratios of Earnings to Fixed Charges and Ratios of Earnings to Combined
Fixed Charges and Preferred Stock Dividends
The Company's earnings to fixed charges ratio for the three months ended
March 31, 1994 was 3.43. The Company's earnings to combined fixed
charges and preferred stock dividends ratio for the three months ended
March 31, 1994 was 3.00. Statements setting forth the computation of
the foregoing ratios are filed herewith as Exhibits 12.1 and 12.2 to
Registration Statement Nos. 33-62488, 33-64136 and 33-50707.
Item 6. Exhibits and Reports on Form 8-K
---------------------------------
(a) Exhibits:
Exhibit 11 Computation of Earnings Per Common Share
Exhibit 12.1 Computation of Ratios of Earnings to Fixed Charges
Exhibit 12.2 Computation of Ratios of Earnings to Combined Fixed
Charges and Preferred Stock Dividends
(b) Reports on Form 8-K during the first quarter of 1994 and through
the date hereof:
1. January 10, 1994
Item 5. Other Events
A. Performance Incentive Plan - 1994 Target
B. California Public Utilities Commission Proceedings
- Electric Fuel and Sales Balancing Accounts
- 1994 Attrition Rate Adjustment
2. January 24, 1994
Item 5. Other Events
A. Performance Incentive Plan - 1993 Financial Results
B. 1993 Consolidated Earnings (unaudited)
C. Common Stock Dividend
D. Potential Sale of PG&E Resources Company
E. Hinkley Compressor Station Litigation
3. March 2, 1994
Item 5. Other Events
A. California Public Utilities Commission Proceedings
- PGT/PG&E Pipeline Expansion Project
- 1992 Reasonableness Proceeding - Division of
Ratepayer Advocates Recommendation
- 1988-1990 Reasonableness Proceeding - Non-Canadian
Gas Phase
- Canadian Affiliates Audit
Item 7. Financial Statements, Pro Forma Financial Information
and Exhibits
A. 1993 Financial Statements
B. Ratios of Earnings to Fixed Charges and Ratios of
Earnings to Combined Fixed Charges and Preferred Stock
Dividends
4. March 11, 1994
Item 5. Other Events
A. Performance Incentive Plan - Year-to-Date Financial
Results
B. California Public Utilities Commission Proceedings
- Regulatory Reform Initiative
- 1988-1990 Reasonableness Proceeding - Canadian
Issues
- 1988-1990 Reasonableness Proceeding - Non-Canadian
Issues
5. March 25, 1994
Item 5. Other Events
A. California Public Utilities Commission Proceedings
- Gas Reasonableness Proceedings
B. Preferred Stock Offering
Item 7. Financial Statements, Pro Forma Financial Information
and Exhibits
6. April 21, 1994
Item 5. Other Events
A. Performance Incentive Plan - Year-to-Date Financial
Results
B. California Public Utilities Commission Proceedings
- Electric Fuel and Sales Balancing Accounts -
ECAC/ERAM
- Biennial Cost Allocation Proceeding
- Electric Industry Restructuring
C. Franchise Fees Litigation
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
PACIFIC GAS AND ELECTRIC COMPANY
May 13, 1994 By THOMAS C. LONG
______________________________
THOMAS C. LONG
Controller
EXHIBIT INDEX
Exhibit
Number Exhibit
- - ------- ---------------------------------
11 Computation of Earnings Per
Common Share
12.1 Computation of Ratios of Earnings
to Fixed Charges
12.2 Computation of Ratios of Earnings
to Combined Fixed Charges and Preferred
Stock Dividends
<TABLE>
EXHIBIT 11
PACIFIC GAS AND ELECTRIC COMPANY
COMPUTATION OF EARNINGS PER COMMON SHARE
<CAPTION>
- - --------------------------------------------------------------------------------------------
Three months ended March 31,
---------------------------
(in thousands, except per share amounts) 1994 1993
- - --------------------------------------------------------------------------------------------
<S> <C> <C>
EARNINGS PER COMMON SHARE (EPS) AS SHOWN
IN THE STATEMENT OF CONSOLIDATED INCOME
Net income $236,952 $255,664
Less preferred dividends 14,458 16,760
-------- --------
Net income for calculating EPS for
Statement of Consolidated Income $222,494 $238,904
======== ========
Average common shares outstanding 428,531 428,426
======== ========
EPS as shown in the Statement of
Consolidated Income $ .52 $ .56
======== ========
PRIMARY EPS (1)
Net income $236,952 $255,664
Less preferred dividends 14,458 16,760
-------- --------
Net income for calculating primary EPS $222,494 $238,904
======== ========
Average common shares outstanding 428,531 428,426
Add exercise of options, reduced by the
number of shares that could have been
purchased with the proceeds from
such exercise (at average market price) 1,262 1,404
-------- --------
Average common shares outstanding as
adjusted 429,793 429,830
======== ========
Primary EPS $ .52 $ .56
======== ========
FULLY DILUTED EPS (1)
Net income $236,952 $255,664
Less preferred dividends 14,458 16,760
-------- --------
Net income for calculating fully diluted EPS $222,494 $238,904
======== ========
Average common shares outstanding 428,531 428,426
Add exercise of options, reduced by the
number of shares that could have been
purchased with the proceeds from such
exercise (at the greater of average or
ending market price) 1,262 1,713
-------- --------
Average common shares outstanding as
adjusted 429,793 430,139
======== ========
Fully diluted EPS $ .52 $ .56
======== ========
- - --------------------------------------------------------------------------------------------
<F/N>
(1) This presentation is submitted in accordance with Item 601(b)(11) of Regulation S-K.
This presentation is not required by APB Opinion No. 15, because it results in dilution
of less than 3%.
</TABLE>
<TABLE>
EXHIBIT 12.1
PACIFIC GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
<CAPTION>
- - ---------------------------------------------------------------------------------------------------
Three Months Year ended December 31,
Ended ----------------------------------------------------------
(dollars in thousands) March 31, 1994 1993 1992 1991 1990 1989
- - ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Earnings:
Net income $236,952 $1,065,495 $1,170,581 $1,026,392 $ 987,170 $ 900,628
Company's equity in
undistributed loss
(earnings) of
unconsolidated
affiliates - - (3,349) 26,671 (2,799) (4,352)
Income tax expense 208,967 901,890 895,126 851,534 881,647 669,885
Net fixed charges 183,041 730,708 758,333 760,957 788,889 821,982
-------- ---------- ---------- ---------- ---------- ----------
Total Earnings $628,960 $2,698,093 $2,820,691 $2,665,554 $2,654,907 $2,388,143
======== ========== ========== ========== ========== ==========
Fixed Charges:
Interest on long-
term debt $149,827 $ 642,408 $ 696,765 $ 682,811 $ 677,476 $ 712,607
Interest on short-
term debt 33,075 87,819 61,182 77,760 110,982 108,869
Interest on capital
leases 434 1,737 1,737 1,737 1,737 1,737
-------- ---------- ---------- ---------- ---------- ----------
Total Fixed
Charges $183,336 $ 731,964 $ 759,684 $ 762,308 $ 790,195 823,213
======== ========== ========== ========== ========== ==========
Ratios of Earnings to
Fixed Charges 3.43 3.69 3.71 3.50 3.36 2.90
- - ---------------------------------------------------------------------------------------------------
<F/N>
Note: For the purpose of computing the Company's ratios of earnings to fixed charges,
"earnings" represent net income adjusted for the Company's equity in undistributed
earnings or loss of unconsolidated affiliates, income taxes and fixed charges
(excluding capitalized interest). "Fixed charges" consist of interest on short-term
and long-term debt (including amortization of bond premium, discount and expense; and
excluding interest on decommissioning trust funds [for which an equal amount of
interest income is recorded] and amortization of the gain or loss on reacquired debt
securities) and interest on capital leases (including capitalized interest).
</TABLE>
<TABLE>
EXHIBIT 12.2
PACIFIC GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
COMPUTATION OF RATIOS OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
<CAPTION>
- - ---------------------------------------------------------------------------------------------------
Three Months Year ended December 31,
Ended ----------------------------------------------------------
(dollars in thousands) March 31, 1994 1993 1992 1991 1990 1989
- - ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Earnings:
Net income $236,952 $1,065,495 $1,170,581 $1,026,392 $ 987,170 $ 900,628
Company's equity in
undistributed loss
(earnings) of
unconsolidated
affiliates - - (3,349) 26,671 (2,799) (4,352)
Income tax expense 208,967 901,890 895,126 851,534 881,647 669,885
Net fixed charges 183,041 730,708 758,333 760,957 788,889 821,982
-------- ---------- ---------- ---------- ---------- ----------
Total Earnings $628,960 $2,698,093 $2,820,691 $2,665,554 $2,654,907 $2,388,143
======== ========== ========== ========== ========== ==========
Fixed Charges:
Interest on long-
term debt $149,827 $ 642,408 $ 696,765 $ 682,811 $ 677,476 $ 712,607
Interest on short-
term debt 33,075 87,819 61,182 77,760 110,982 108,869
Interest on capital
leases 434 1,737 1,737 1,737 1,737 1,737
-------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges 183,336 731,964 759,684 762,308 790,195 823,213
-------- ---------- ---------- ---------- ---------- ----------
Preferred Stock Dividends:
Tax deductible dividends 1,168 4,814 5,136 5,136 5,136 5,136
Pretax earnings required
to cover non-tax
deductible preferred
stock dividend
requirements 25,010 108,937 130,147 154,404 175,881 167,440
-------- ---------- ---------- ---------- ---------- ----------
Total Preferred
Stock Dividends 26,178 113,751 135,283 159,540 181,017 172,576
-------- ---------- ---------- ---------- ---------- ----------
Total Combined Fixed
Charges and
Preferred Stock
Dividends $209,514 $ 845,715 $ 894,967 $ 921,848 $ 971,212 $ 995,789
======== ========== ========== ========== ========== ==========
Ratios of Earnings to
Combined Fixed
Charges and Preferred
Stock Dividends 3.00 3.19 3.15 2.89 2.73 2.40
- - ---------------------------------------------------------------------------------------------------
<F/N>
Note: For the purpose of computing the Company's ratios of earnings to combined fixed
charges and preferred stock dividends, "earnings" represent net income adjusted for
the Company's equity in undistributed earnings or loss of unconsolidated affiliates,
income taxes and fixed charges (excluding capitalized interest). "Fixed charges"
consist of interest on short-term and long-term debt (including amortization of bond
premium, discount and expense; and excluding interest on decommissioning trust funds
[for which an equal amount of interest income is recorded] and amortization of the
gain or loss on reacquired debt securities) and interest on capital leases (including
capitalized interest). "Preferred stock dividends" represent the sum of requirements
for preferred stock dividends that are deductible for federal income tax purposes and
requirements for preferred stock dividends that are not deductible for federal income
tax purposes increased to an amount representing pretax earnings which would be
required to cover such dividend requirements.
</TABLE>
