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SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OR
THE SECURITIES EXCHANGE ACT OF 1934
(NO FEE REQUIRED)
For the Transition period from ________ to _________
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Commission File Number 1-4393
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PUGET SOUND ENERGY, INC.
(Exact name of registrant as specified in its charter)
Washington 91-0374630
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
411 - 108th Avenue N.E., Bellevue, Washington 98004-5515
(Address of principal executive offices)
(425) 454-6363
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) or the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file for such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No ____
The number of shares of registrant's common stock outstanding at June 30, 1999
was 84,560,539.
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<PAGE>
Table of Contents
Page
Number
Part I. Financial Information
Item 1. Financial Statements
Consolidated Statements of Income - three month
periods ended June 30, 1999 and 1998 3
Consolidated Statements of Income - six month
periods ended June 30, 1999 and 1998 4
Consolidated Statements of Comprehensive Income -
three month periods ended June 30, 1999 and 1998 5
Consolidated Statements of Comprehensive Income -
six month periods ended June 30, 1999 and 1998 5
Consolidated Balance Sheets - June 30, 1999
and December 31, 1998 6
Consolidated Statements of Cash Flows -
six month periods ended June 30, 1999 and 1998 8
Notes to Consolidated Financial Statements 9
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 12
Item 3. Quantitative & Qualitative Disclosures About
Market Risk 20
Part II. Other Information
Item 1. Legal Proceedings 22
Item 4. Submission of Matters to a Vote of Security Holders 22
Item 6. Exhibits and Reports on Form 8-K 22
Signature 23
2
<PAGE>
PART I FINANCIAL INFORMATION
Item 1 Financial Statements
<TABLE>
PUGET SOUND ENERGY, INC
CONSOLIDATED STATEMENTS OF INCOME
For the Three Month Periods Ended June 30
(Thousands except per share amounts)
(Unaudited)
<CAPTION>
1999 1998
--------- ----------
<S> <C> <C>
OPERATING REVENUES:
Electric $ 336,895 $ 286,913
Gas 94,173 76,752
Other 4,371 6,562
--------- ----------
Total operating revenues 435,439 370,227
--------- ----------
OPERATING EXPENSES:
Energy costs:
Purchased electricity 176,116 137,397
Purchased gas 38,822 32,598
Electric generation fuel 11,178 9,500
Residential Exchange (8,631) (12,063)
Utility operations and maintenance 60,297 59,229
Other operations and maintenance 5,522 6,704
Depreciation and amortization 42,899 40,446
Taxes other than federal income taxes 41,982 36,877
Federal income taxes 12,357 9,850
--------- ----------
Total operating expenses 380,542 320,538
--------- ----------
OPERATING INCOME 54,897 49,689
OTHER INCOME 13,102 3,862
--------- ----------
INCOME BEFORE INTEREST CHARGES 67,999 53,551
INTEREST CHARGES, net of AFUDC 36,934 34,009
--------- ----------
NET INCOME 31,065 19,542
Less: Preferred stock dividends accrual 3,013 3,250
--------- ----------
INCOME FOR COMMON STOCK $ 28,052 $ 16,292
========= ==========
COMMON SHARES OUTSTANDING - WEIGHTED AVERAGE 84,561 84,561
========= ==========
BASIC & DILUTED EARNINGS PER COMMON SHARE: $ 0.33 $ 0.19
========= ==========
The accompanying notes are an integral part of the financial statements.
</TABLE>
3
<PAGE>
<TABLE>
PUGET SOUND ENERGY, INC
CONSOLIDATED STATEMENTS OF INCOME
For the Six Month Periods Ended June 30
(Thousands except per share amounts)
(Unaudited)
<CAPTION>
1999 1998
---------- ----------
<S> <C> <C>
OPERATING REVENUES:
Electric $ 737,709 $ 655,509
Gas 265,017 224,574
Other 14,658
---------- ----------
8,046
Total operating revenues 1,010,772 894,741
---------- ----------
OPERATING EXPENSES:
Energy costs:
Purchased electricity 361,272 306,655
Purchased gas 117,079 100,526
Electric generation fuel 21,055 20,741
Residential Exchange (20,315) (27,570)
Utility operations and maintenance 122,847 119,763
Other operations and maintenance 13,211 12,388
Depreciation and amortization 85,520 81,182
Taxes other than federal income taxes 92,598 82,475
Federal income taxes 60,678 50,211
---------- ----------
Total operating expenses 853,945 746,371
---------- ----------
OPERATING INCOME 156,827 148,370
OTHER INCOME 16,849 5,625
---------- ----------
INCOME BEFORE INTEREST CHARGES 173,676 153,995
INTEREST CHARGES, net of AFUDC 72,855 68,449
---------- ----------
NET INCOME 100,821 85,546
Less: Preferred stock dividends accrual 5,889 6,558
----------- ----------
INCOME FOR COMMON STOCK $ 94,932 $ 78,988
========== ==========
COMMON SHARES OUTSTANDING - WEIGHTED AVERAGE 84,561 84,561
========== ==========
BASIC & DILUTED EARNINGS PER COMMON SHARE: $ 1.12 $ 0.93
========== ==========
The accompanying notes are an integral part of the financial statements.
</TABLE>
4
<PAGE>
<TABLE>
PUGET SOUND ENERGY, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Three Month Periods Ended June 30
(Dollars in Thousands)
(Unaudited)
<CAPTION>
1999 1998
--------- ---------
<S> <C> <C>
Net Income $ 31,065 $ 19,542
--------- ---------
Other comprehensive income, net of tax:
Unrealized holding gains (losses) arising during period 4,262 (3,639)
Reclassification adjustment for gains included in net income (12,284) --
---------
---------
Other comprehensive income (8,022) (3,639)
--------- ---------
Comprehensive Income $ 23,043 $ 15,903
========= =========
</TABLE>
<TABLE>
PUGET SOUND ENERGY, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Six Month Periods Ended June 30
(Dollars in Thousands)
(Unaudited)
<CAPTION>
1999 1998
---------- ---------
<S> <C> <C>
Net Income $ 100,821 $ 85,546
---------- ---------
Other comprehensive income, net of tax:
Unrealized holding gains arising during period 3,482 780
Reclassification adjustment for gains included in net income (12,284) --
----------
---------
Other comprehensive income (8,802) 780
---------- ---------
Comprehensive Income $ 92,019 $ 86,326
========== =========
The accompanying notes are an integral part of the financial statements.
</TABLE>
5
<PAGE>
<TABLE>
PUGET SOUND ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)
ASSETS
<CAPTION>
June 30, December 31,
1999 1998
------------- -------------
<S> <C> <C>
UTILITY PLANT:
Electric $ 3,763,973 $ 3,694,593
Gas 1,324,628 1,278,275
Common 188,789 179,140
Less: Accumulated depreciation and amortization 1,788,752 1,721,096
------------- -------------
Net utility plant 3,488,638 3,430,912
------------- -------------
OTHER PROPERTY AND INVESTMENTS 262,712 260,087
------------- -------------
CURRENT ASSETS:
Cash 43,483 28,216
Accounts receivable 182,706 189,638
Unbilled revenue 62,801 126,740
Materials and supplies, at average cost 51,777 58,534
Purchased gas receivable 16,164 5,492
Prepayments and other 7,990
------------- -------------
9,168
Total current assets 366,099 416,610
------------- -------------
LONG-TERM ASSETS:
Regulatory asset for deferred income taxes 231,833 241,406
Deferred PURPA power contract buydown costs 224,268 221,802
Other 150,239 138,870
------------- -------------
Total long-term assets 606,340 602,078
------------- -------------
TOTAL ASSETS $ 4,723,789 $ 4,709,687
============= =============
The accompanying notes are an integral part of the financial statements.
</TABLE>
6
<PAGE>
<TABLE>
PUGET SOUND ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)
CAPITALIZATION AND LIABILITIES
<CAPTION>
June 30, December 31,
1999 1998
------------- -------------
<S> <C> <C>
CAPITALIZATION:
Common shareholders' investment:
Common stock, $10 stated value,
150,000,000 shares authorized,
84,560,539 and 84,560,561 shares outstanding $ 845,605 $ 845,606
Additional paid-in capital 450,836 450,724
Earnings reinvested in the business 64,441 47,548
Accumulated other comprehensive income -- 8,802
Preferred stock not subject to
mandatory redemption 90,000 95,075
Preferred stock subject to
mandatory redemption 65,662 73,162
Corporation obligated, mandatorily redeemable
preferred securities of subsidiary
trust holding solely junior subordinated
debentures of the corporation 100,000 100,000
Long-term debt 1,714,770 1,475,106
------------- -------------
Total capitalization 3,331,314 3,096,023
------------- -------------
CURRENT LIABILITIES:
Accounts Payable 131,231 163,141
Short-term debt 236,493 450,905
Current maturities of long-term debt 107,000 107,000
Accrued expenses:
Taxes 79,272 59,764
Salaries and wages 19,536 18,650
Interest 42,704 39,062
Other 23,150
22,567
Total current liabilities 638,803 861,672
------------- -------------
DEFERRED INCOME TAXES 626,034 628,554
------------- -------------
OTHER DEFERRED CREDITS 127,638 123,438
------------- -------------
TOTAL CAPITALIZATION AND LIABILITIES $ 4,723,789 $ 4,709,687
============= =============
The accompanying notes are an integral part of the financial statements.
</TABLE>
7
<PAGE>
<TABLE>
PUGET SOUND ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Month Periods Ended June 30
(Dollars in Thousands)
(Unaudited)
<CAPTION>
1999 1998
---------- ----------
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income $ 100,821 $ 85,546
Adjustments to reconcile net income
to net cash provided by operating activities:
Depreciation and amortization 85,520 81,182
Deferred income taxes and tax credits - net 7,053 405
Gain from sale of investment in Cabot common stock (18,899) --
Other 363 26,265
Change in certain current assets
and liabilities (Note 3) 57,321 39,327
- --------------------------------------------------------------------------------
Net Cash Provided by Operating Activities 232,179 232,725
- --------------------------------------------------------------------------------
INVESTING ACTIVITIES:
Construction expenditures - excluding equity AFUDC (163,013) (141,489)
Additions to energy conservation program (2,755) (2,301)
Proceeds from sale of investment in Cabot common stock 37,353 --
Loans to CellNet Data Services (20,500) --
Other 5,170 1,601
- --------------------------------------------------------------------------------
Net Cash Used by Investing Activities (143,745) (142,189)
- --------------------------------------------------------------------------------
FINANCING ACTIVITIES:
Change in short-term debt, net (214,412) (156,038)
Dividends paid (83,777) (84,422)
Redemption of preferred stock (12,575) (5,054)
Issuance of bonds 250,000 200,000
Redemption of bonds and notes (10,358) (45,044)
Issue costs of bonds and stock (2,045) (1,906)
- --------------------------------------------------------------------------------
Net Cash Used by Financing Activities (73,167) (92,464)
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Net Increase (Decrease) in cash 15,267 (1,928)
Cash at Beginning of year 28,216 10,729
================================================================================
Cash at End of Period $ 43,483 $ 8,801
================================================================================
The accompanying notes are an integral part of the financial statements.
</TABLE>
8
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Summary of Consolidation Policy
The consolidated financial statements include the accounts of Puget
Sound Energy, Inc. ("the Company") and its wholly-owned subsidiaries, after
elimination of all significant intercompany items and transactions. Certain
amounts previously reported have been reclassified to conform with current year
presentations with no effect on total equity or net income.
The consolidated financial statements contained in this Form 10-Q are
unaudited. In the opinion of management, all adjustments necessary for a fair
presentation of the results for the interim periods have been reflected and were
of a normal recurring nature. These condensed financial statements should be
read in conjunction with the Company's annual report on Form 10-K.
(2) Earnings per Common Share
Basic earnings per common share have been computed based on weighted
average common shares outstanding of 84,561,000 for the three and six months
ended June 30, 1999 and 1998.
Diluted earnings per common share have been computed based on weighted
average common shares outstanding of 84,813,000 and 84,815,000 for the three and
six months ended June 30, 1999, and 84,675,000 and 84,670,000 for the three and
six months ended June 30, 1998, respectively. These shares include the dilutive
effect of securities related to long-term employee compensation plans approved
by shareholders.
(3) Consolidated Statements of Cash Flows
The following provides additional information concerning cash flow
activities:
<TABLE>
<CAPTION>
Six Months Ended June 30 1999 1998
- ------------------------ ---- ----
<S> <C> <C>
Changes in current asset and current liabilities:
Accounts receivable and unbilled revenue $ 70,871 $ 70,737
Materials and supplies 6,757 2,972
Prepayments and Other (1,178) (1,221)
Purchased gas receivable (10,672) 10,647
Accounts payable (31,910) (41,997)
Accrued expenses and Other 23,453 (1,811)
==================================================== =========== ============
Net change in current assets and current liabilities $ 57,321 $ 39,327
==================================================== =========== ============
Cash payments:
Interest (net of capitalized interest) $ 71,987 $ 60,348
Income taxes $ 39,750 $ 50,743
- ---------------------------------------------------- ----------- ------------
</TABLE>
9
<PAGE>
(4) Segment Information
The Company primarily operates in one business segment, Regulated Utility
Operations. The Company's regulated utility operation generates, purchases,
transports and sells electricity and purchases, transports and sells natural
gas. The Company's service territory covers approximately 6,000 square miles in
the state of Washington.
Principal non-utility lines of business include real estate investment
and development, home security services, small hydro-electric project
development and energy-related services. Reconciling items between segments are
not material.
Financial data for business segments are as follows:
<TABLE>
<CAPTION>
(Dollars in Thousands) Regulated
Three Months Ended June 30, 1999 Utility Other Total
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Revenues $431,068 4,371 $435,439
Net Income 22,357 8,708 31,065
Total Assets 4,611,971 111,818 4,723,789
- --------------------------------------------------------------------------------
Regulated
Three Months Ended June 30, 1998 Utility Other Total
- --------------------------------------------------------------------------------
Revenues $ 363,665 6,562 $ 370,227
Net Income 20,460 (918) 19,542
Total Assets 4,349,775 106,093 4,455,868
- --------------------------------------------------------------------------------
(Dollars in Thousands) Regulated
Six Months Ended June 30, 1999 Utility Other Total
- --------------------------------------------------------------------------------
Revenues $ 1,002,726 8,046 $ 1,010,772
Net Income 94,917 5,904 100,821
Total Assets 4,611,971 111,818 4,723,789
- --------------------------------------------------------------------------------
Regulated
Six Months Ended June 30, 1998 Utility Other Total
- --------------------------------------------------------------------------------
Revenues $ 880,083 14,658 $894,741
Net Income 84,895 651 85,546
Total Assets 4,349,775 106,093 4,455,868
- --------------------------------------------------------------------------------
</TABLE>
(5) Other
In September 1998, the Company filed a shelf-registration statement with
the Securities and Exchange Commission for the offering, on a delayed or
continuous basis, of up to $500 million principal amount of Senior Notes secured
by a pledge of First Mortgage Bonds. On March 9, 1999, the Company issued $250
million principal amount of Senior Medium-Term Notes, Series B, which consisted
of $150 million principal amount due March 9, 2009, at an interest rate of 6.46%
and $100 million principal amount due March 9, 2029, at an interest rate of
7.0%.
10
<PAGE>
In March 1998, the Company entered into an agreement with CellNet Data
Services Inc. ("CellNet") under which the Company will lend CellNet up to $40
million in the form of multiple draws so that CellNet can finance an Automated
Meter Reading (AMR) network system to be deployed in the Company's service
territory. The Company's promissory note with CellNet calls for the network
system to serve as collateral for the loan. The term of the loan is five years
after the first loan under the agreement is made to CellNet. On June 30, 1999,
the Company made the first loan under the loan agreement in the amount of $20.5
million. The loan agreement provides for interest only payments during the five
year term, with the principal due at the end of the five year term.
During the first quarter of 1999, the Company adopted Issue 98-10,
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities" ("EITF 98-10") issued by the Emerging Issues Task Force of the
Financial Accounting Standards Board ("FASB"). EITF 98-10 addresses accounting
for the purchase and sale of energy trading contracts and is effective for
fiscal years beginning after December 15, 1998. The conclusion reached by the
EITF was that such contracts should be recorded at fair value when entered into
for trading activities with the mark-to-market gains or losses recorded in
current earnings. The Company does not consider its current operations to meet
the definition of trading activities as described by EITF 98-10. Accordingly,
the adoption of EITF 98-10 did not have an impact on the Company's financial
position or results of operations.
In June 1998, the FASB issued Statement of Financial Accounting Standards
No. 133, "Accounting for Derivative Instruments and Hedging Activities"
("Statement No. 133"). In July 1999, the FASB issued Statement of Financial
Accounting Standards No. 137 which delayed the effective date of Statement No.
133 for one year, to fiscal years beginning after June 15, 2000. Statement No.
133 requires that all derivative instruments be recorded on the balance sheet at
their fair value. Changes in the fair value of derivatives are recorded each
period in current earnings or other comprehensive income, depending on whether a
derivative is designated as part of a hedge transaction and, if it is, the type
of hedge transaction. The Company has not yet determined the impact that the
adoption of Statement No. 133 will have on its financial statements.
11
<PAGE>
Item 2 Management's Discussion and Analysis of Financial Condition and Results
of Operations
The following discussion of the Company's business includes some
forward-looking statements that involve risks and uncertainties. Words such as
"estimates," "expects," "anticipates," "plans," and similar expressions identify
forward-looking statements involving risks and uncertainty. Those risks and
uncertainties include, but are not limited to, the ongoing restructuring of the
electric and gas industries and the outcome of regulatory proceedings related to
that restructuring. The ultimate impacts of both increased competition and the
changing regulatory environment on future results are uncertain, but are
expected to fundamentally change how the Company conducts its business. The
outcome of these changes and other matters discussed below may cause future
results to differ materially from historic results, or from results or outcomes
currently expected or sought by the Company.
Results of Operations
Net income for the three months ended June 30, 1999, was $31.1 million on
operating revenues of $435.4 million, compared with net income of $19.5 million
on operating revenues of $370.2 million for the same period in 1998. Income for
common stock was $28.1 million for the second quarter of 1999 and $16.3 million
for the second quarter of 1998. Basic and Diluted earnings per common share were
$0.33 for the second quarter of 1999 compared to $0.19 for the second quarter of
1998.
For the first six months of 1999, net income was $100.8 million on
operating revenues of $1,011 million, compared with net income of $85.5 million
on operating revenues of $894.7 million for the corresponding period in 1998.
Income for common stock was $94.9 million for the first half of 1999 and $79.0
million for the same period in 1998. Basic and diluted earnings per common share
were $1.12 for the six months ended June 30, 1999, and $0.93 for the same period
in 1998.
Results from non-utility operations for the three months ended June 30,
1999, were positively impacted by approximately $0.10 per share, the result of a
gain from the sale of the Company's investment in common stock of Cabot Oil &
Gas Corporation, offset in part by the cost of a wholly-owned subsidiary's
exiting certain product lines. The increase in net income and earnings per share
for the three and six months ended June 30, 1999, compared to the same periods
in 1998 are also the result of continued customer growth, cooler weather than
the same period last year and the positive contribution of favorable
hydroelectric conditions to electric margins.
Total kilowatt-hour sales were 7.6 billion, including 2.7 billion in
sales to other utilities, for the second quarter of 1999, compared to 6.3
billion, including 1.5 billion in sales to other utilities, for the second
quarter of 1998. For the six month periods ended June 30, 1999 and 1998, total
kilowatt-hour sales were 16.3 billion, including 5.4 billion in sales to other
utilities, and 13.9 billion, including 3.3 billion in sales to other utilities,
respectively.
Total gas volumes were 228.2 million therms, including 57.4 million
therms in transportation volumes for the three months ended June 30, 1999,
compared to 199.0 million therms, including 63.1 million therms of
transportation, for the same period in 1998. For the six months ended June 30,
1999, total gas volumes were 620.4 million therms, including 126.5 million
therms of transportation, compared to 551.0 million therms, including 138.9
million therms of transportation, for the same period in 1998.
12
<PAGE>
The Company's operating revenues and associated expenses are not
generated evenly during the year. Variations in energy usage by customers occur
from season to season and from month to month within a season, primarily as a
result of changing weather conditions. The Company normally experiences its
highest energy sales in the first and fourth quarters of the year. Electric
sales to other utilities also vary by quarter and year depending principally
upon water conditions for the generation of hydroelectric power, customer usage
and the energy requirements of other utilities.
<TABLE>
Results of Operations
Comparative Three and Six Month Periods Ended
June 30, 1999 vs. June 30, 1998
Increase (Decrease)
<CAPTION>
Three Month Period Six Month Period
------------------ ----------------
(In Millions)
<S> <C> <C>
Operating revenue changes
General rate increase - electric $ 3.9 $ 7.8
BPA Residential Purchase & Sale Agreement (1.5) (3.6)
Sales to other utilities and marketers 38.8 53.9
Electric load and other changes 8.8 24.1
Gas revenue change 17.4 40.4
Other revenue changes (2.2) (6.6)
-------- --------
Total operating revenue change 65.2 16.0
-------- --------
Operating expense changes Energy costs:
Purchased electricity 38.7 54.6
Purchased gas 6.2 16.6
Electric generation fuel 1.7 0.3
Residential exchange credit 3.4 7.2
Utility operations and maintenance 1.1 3.1
Other operations and maintenance (1.2) 0.8
Depreciation and amortization 2.5 4.3
Taxes other than federal income taxes 5.1 10.1
Federal income taxes 2.5 10.5
-------- --------
Total operating expense change 60.0 07.5
-------- --------
Other income 9.2 11.2
Interest charges 2.9 4.4
======== ========
Net income change $ 11.5 $ 15.3
======== ========
The following is additional information pertaining to the changes
outlined in the above table.
</TABLE>
13
<PAGE>
Operating Revenues - Electric
Electric revenues for the quarter ended June 30, 1999, were $336.9
million, up $50.0 million or 17.4% over the same period in 1998. Revenues in the
second quarter of 1999 increased $3.9 million compared to the second quarter of
1998 due to a general electric rate increase that averaged 1.2% effective
January 1, 1999.
Electric revenues for the six months ended June 30, 1999, were $737.7
million, up $82.2 million or 12.5% over the same period in 1998. Revenues in the
first half of 1999 increased $7.8 million compared to the first half of 1998 due
to a general electric rate increase that averaged 1.2% effective January 1,
1999.
Revenues in 1999 and 1998 were reduced because of the credit that the
Company received through the Residential Purchase and Sale Agreement with the
Bonneville Power Administration ("BPA"). The agreement enables the Company's
residential and small farm customers to receive the benefits of lower-cost
federal power. On January 29, 1997, the Company and BPA signed a Residential
Exchange Termination Agreement. The Termination Agreement ends the Company's
participation in the Residential Purchase and Sale agreement with BPA. As part
of the Termination Agreement, the Company will receive payments by the BPA of
approximately $235 million over an approximately five-year period ending June
2001. Under the rate plan approved by the Washington Commission in its merger
order, the Company will continue to reflect, in customers' bills, the current
level of Residential Exchange benefits. Over the remainder of the Residential
Exchange Termination Agreement from July 1999 through June 2001, it is projected
that the Company will credit customers approximately $132.1 million more than it
will receive from BPA during the following periods:
<TABLE>
<CAPTION>
Dollars in
Period Millions
------ ----------
<S> <C>
July- December 1999 $26.9
January - December 2000 68.3
January - June 2001 36.9
----
$132.1
</TABLE>
Electric sales to other utilities and marketers increased $38.8 million
and $53.9 million in the quarter and six months ended June 30, 1999,
respectively, over the same periods in 1998 as wholesale sales to marketers have
increased. Related power cost expenses for the periods also increased as the
Company generated and purchased more power for these sales.
Also contributing to the increase in electric revenues in the three and
six months ended June 30, 1999, when compared to the previous year were colder
temperatures during the 1999 periods and a 2% increase in the number of electric
customers. Temperatures during the six months ended June 30, 1999, averaged
slightly colder than normal.
Operating Revenues - Gas
Gas operating revenues for the quarter ended June 30,1999, increased
$17.4 million or 22.7% from the prior year quarter. Total gas volumes increased
14.6% from 199.0 million therms to 228.2 million therms. Gas margin (regulated
utility sales less the cost of gas sold) also increased by $11.1 million, or
26.9% in the second quarter of 1999 compared to the same period in 1998. The
primary reasons for the increase in gas sales volume, gas sales revenue and
margin in the quarter ended June 30, 1999, was the 4.5% increase in gas
customers and cooler temperatures than the prior year. A larger percentage of
firm gas sales with higher prices and less transportation sales volumes in 1999
when compared to last year also contributed to increased revenues.
14
<PAGE>
For the six months ended June 30, 1999, gas operating revenues increased
$40.4 million or 18.0% from $224.6 million in the six months ended June 30,
1998, to $265.0 million while total gas volumes increased 12.6%. The increase in
the period was primarily due to a 4.4% increase in gas customers and the impact
of cooler weather on the Company's gas heating load during the first two
quarters of 1999 compared to 1998. A larger percentage of firm gas sales with
higher prices and less transportation sales volumes in 1999 when compared to
last year also contributed to increased revenues. Gas margin in the six months
ended June 30, 1999, also increased $23.8 million or 20.1%.
Other revenues decreased $2.2 million and $6.6 million in the three
months and six months ended June 30, 1999, respectively, as compared to the same
periods in 1998 due to decreased revenues at the Company's subsidiaries.
Operating Expenses
Purchased electricity expenses increased $38.7 million and $54.6 million
for the three and six month periods ended June 30, 1999, respectively, compared
to the same periods in 1998. The increases were due primarily to increased
secondary power purchases to support wholesale sales and the increased load due
to cooler temperatures than in the prior year and a greater number of electric
customers in 1999.
Purchased gas expenses increased $6.2 million and $16.6 million for the
three and six month periods ended June 30, 1999, respectively, due to both
increased volumes of purchases as a result of higher heating load and the
increase in gas service customers.
Fuel expense increased $1.7 million in the second quarter of 1999
compared to the same period in 1998 due to the Company generating more
electricity at Company-owned combustion turbines.
Residential exchange credits associated with the Residential Purchase and
Sale Agreement with BPA decreased $3.4 million and $7.2 million in the three and
six month periods ended June 30, 1999, compared to the prior year periods,
primarily as a result of the 1997 Residential Exchange Termination Agreement
discussed in "Operating Revenues - Electric."
Utility operations and maintenance expenses increased slightly for the
three and six month periods ended June 30, 1999, compared to the same periods in
1998 due primarily to an increase in storm-repair costs of approximately $6.2
million in the six-month period ended June 30, 1999, compared to the same period
in 1998. The increase in storm restoration costs was partially offset by
decreases in vegetation management expenses of $.9 million and $3.4 million in
the three and six month periods ended June 30, 1999, compared to the same
periods in 1998. The Company performed the majority of vegetation management
work in 1998 during the first six months of the year due to the availability of
contractors, favorable weather conditions and in anticipation of beginning a new
"Tree Watch" program under which trees are removed outside of the Company's
right of ways after obtaining customer permission. Utility operations and
maintenance expenditures in 1999 also include costs of $5.3 million for Year
2000 remediation efforts.
15
<PAGE>
Depreciation and amortization expense increased $2.5 million and $4.3
million for the three and six month periods June 30, 1999, respectively, from
the same periods in 1998 due primarily to the effects of new plant placed into
service during the past year.
Taxes other than federal income taxes increased $5.1 million and $10.1
million for the three and six month periods ended June 30, 1999, compared to the
same periods in 1998 due primarily to increases in municipal and state excise
taxes which are revenue based and increased state property taxes.
Federal income taxes increased $2.5 million and $10.5 million for the
three month and six month periods ended June 30, 1999, primarily due to higher
pre-tax operating income for the periods.
Other Income
Other income, net of federal income tax, increased $9.2 million and $11.2
million for the three month and six month periods ending June 30, 1999,
respectively, compared to the same periods in 1998. The increases in both
periods were due primarily to the net after-tax gain of $12.3 million as a
result of the sale of the Company's investment in the common stock of Cabot Oil
and Gas Corporation in May 1999, offset in part by the cost of ConnexT, a
wholly-owned subsidiary, exiting certain product lines.
Interest Charges
Interest charges, which consist of interest and amortization on long-term
debt and other interest, increased $2.9 million and $4.4 million for the three
and six month periods ended June 30, 1999, respectively, compared to the same
periods in 1998 as a result of the issuance of $200 million 6.74% Senior
Medium-Term Notes, Series A, in June 1998 and $250 million Senior Medium-Term
Notes, Series B, in March 1999. These increases were partially offset by the
repayment of $61 million in Secured Medium-Term Notes since February 1999 and
the redemption of $30 million 9.14% Secured Medium-Term Notes, Series A, in June
1998. Other interest expense decreased $1.9 million for the three and six months
ended June 30, 1999, compared to the same periods in 1998 as a result of lower
weighted average interest rates and lower average daily short-term borrowings.
Construction, Capital Resources and Liquidity
Construction expenditures, which include energy conservation expenditures
and exclude AFUDC, for the second quarter of 1999 were $70.8 million compared to
$73.2 million for the second quarter of 1998. Year-to-date construction
expenditures totaled $161.1 million compared to $140.4 million for the same
period in 1998. Construction expenditures for 1999 and 2000 are expected to be
$303 million and $259 million, respectively. Cash provided by operations (net of
dividends and AFUDC) as a percentage of construction expenditures (excluding
AFUDC) was 51% and 32% for the second quarters of 1999 and 1998, respectively.
Cash provided by operations (net of dividends and AFUDC) as a percentage of
construction expenditures (excluding AFUDC) was 89% and 103% for the six month
periods ended June 30, 1999 and 1998, respectively. Construction expenditure
estimates are subject to periodic review and adjustment.
On June 30, 1999, the Company had available $375.0 million in lines of
credit with various banks, which provide credit support for outstanding
commercial paper borrowing of $62.5 million, reducing the available borrowing
capacity under these lines of credit to $312.5 million. In addition, the Company
has agreements with several banks to borrow on an uncommitted, as available,
basis at money-market rates quoted by the banks. There are no costs, other than
interest, for these arrangements.
16
<PAGE>
Year 2000 Conversion
Background
The Year 2000 issue results from the use of two digits rather than four
digits in computer hardware and software to define the applicable year. If not
corrected on computer systems that must process dates both before and after
January 1, 2000, two-digit year fields may create processing errors or system
failures. The Company believes that all mission-critical operational systems, as
defined by the North American Electric Reliability Council ("NERC"), are Year
2000 ready. Project work, including remediation and testing is substantially
complete for the Company's other priority business systems. Follow-up for a
limited number of non-critical systems and certain vendors will continue into
the third quarter.
Project Approach and Progress
The number of people working full time and part time on the Company's
Year 2000 project fluctuates between 125 and 150. The Company has established a
central project team to coordinate all Year 2000 activities and identified
exposure in three categories: information technology; embedded chip technology;
and external non-compliance by customers and suppliers. The project team is
taking a phased approach in conducting the Year 2000 project for its internal
systems. The phases include inventory, assessment, remediation, testing,
implementation and contingency planning. In addition, the Company has engaged
outside consultants and technicians to aid in formulating and implementing its
plan. All business units have completed the inventory, assessment, remediation,
testing and implementation phases with the exception of the Company's Customer
Information System ("CIS") discussed below.
The Company has been upgrading mainframe and client server financial and
business applications since 1997 and replacing many of its business systems as
part of its business plans following its merger in 1997. In September 1998, the
Company implemented a Systems, Applications, Products in Data Processing ("SAP")
business system which includes essentially all of the Company's business
applications with the exception of its CIS. This SAP system is Year 2000
compliant.
A new CIS, which is designed to be Year 2000 compliant, is currently
being developed by the Company. Development is expected to continue in 1999. The
Company has also begun implementation activities with respect to the new system
which will continue during 1999. The Company has also elected to remediate
critical elements of its existing CIS for Year 2000 compliance purposes. The
Company has formed a specialized team which has completed the inventory,
assessment and remediation activities for the existing system. Testing and
implementation activities for the existing system are expected to be completed
in the third quarter of 1999.
A specialized embedded systems team has been formed by the Company to
inventory, assess and remediate microprocessor technology in its generation,
transmission and distribution systems for both gas and electric operations. The
inventory, assessment, remediation, testing and implementation phases for all
mission critical embedded systems are complete. Contingency planning specific to
the Year 2000 issue began in November 1998, and contingency plans were submitted
on June 30, 1999, to the Washington Commission and NERC. These plans will be
refined and updated as remediation and test results are analyzed.
The Company sent letters to its suppliers, financial institutions and
other business partners to coordinate Year 2000 conversion and determine the
extent to which the Company is exposed to third party compliance failures. All
significant vendors and suppliers have been contacted to date. All third party
assessment was completed in June 1999. If the Company identified concerns, it
followed up with third parties by telephone. In addition, the Company held
meetings with critical vendors described below in order to assess and monitor
compliance measures. All critical vendors and suppliers have responded to the
Company's written requests and follow up telephone calls. They have indicated
either that they are Year 2000 compliant or that they expect to be compliant
later in 1999. Where appropriate company line managers have developed alternate
sources or other contingency plans for critical vendors and suppliers.
17
<PAGE>
The Company depends upon third parties for a significant portion of its
energy supply and transportation. The majority of the high voltage transmission
facilities used by the Company are owned and operated by Bonneville Power
Administration and the Company's natural gas supplies are transported to its
service area by natural gas pipelines in the western United States and Canada.
The Company purchases 100% of its natural gas supplies and approximately 75% of
its electric power supplies. Major energy suppliers and transporters are
considered critical vendors because their failure to supply or deliver energy to
the Company could adversely affect the reliability of the Company's electric or
gas service to its customers.
In addition, the Company is working with various industry groups
including NERC and the regional reliability council, the Western Systems
Coordinating Council ("WSCC") during the millennium transition. The United
States Department of Energy has asked NERC to assume a leadership role in
preparing the U.S. electric industry for the transition to the Year 2000.
Costs
While the replacement of business systems under business plans developed as
a result of the Merger are not included in the Company's Year 2000 project,
those replacements substantially reduce the number of internal business
applications that require remediation. In addition to the costs of replacing new
business systems, the Company estimates that total Year 2000 project costs will
approximate $14 million, exclusive of internal labor costs, of which $9.7
million has been expended through June 30, 1999.
Risk Assessment
The electric power supply systems of North America are connected into
three major interconnections called grids. The western grid covers the western
third of the U.S., western Canada and parts of Mexico. The BPA is the largest
supplier of transmission services in the Pacific Northwest. The Company's
reasonably likely worst case scenario is that operational component failures of
any entity connected to the grid could cause other failures in that grid. Such
failures would adversely affect the Company's ability to provide reliable
service to its customers and correspondingly reduce revenues. The Company will
need to continue to assess this risk as the millennium approaches to evaluate
the likelihood of power failures and develop approaches for mitigating the risk
of failures.
Much of the natural gas and electric distribution systems are comprised
of wires, poles and pipes containing no embedded chips. However, these systems
do employ some computer components that could be affected by the Year 2000
transition. Since many of the components used by the Company exist in multiple
sub-station locations, there is a risk that a component could be missed, a
component manufacturer could provide erroneous information, or the component
(while deemed and tested compliant) could fail in a specific configuration found
at the Company. The Company has formed a special team to handle these types of
components (embedded systems), and has retained an independent engineering firm
with specific utility experience to assist in the effort. Results of assessment
to date reveal that there are fewer components that are not Year 2000 ready than
initially thought. This is consistent with industry findings published in the
NERC report to the Department of Energy dated January 11, 1999.
18
<PAGE>
The failure to correct a material Year 2000 problem could result in an
interruption in, or a failure of, Company business activities or operations.
Such failures could materially and adversely affect the Company's results of
operations, liquidity and financial condition. Due to the general uncertainty
inherent in the Year 2000 problem, resulting in part from the uncertainty of the
Year 2000 readiness of third-party suppliers and customers, the Company is
unable to determine at this time whether the consequences of Year 2000 failures
will have a material impact on the Company's results of operations, liquidity or
financial condition. The Year 2000 project is expected to significantly reduce
the Company's level of uncertainty about the Year 2000 problem and the Year 2000
readiness of its material vendors. The Company believes that, with the
implementation of new business systems and completion of the project as
scheduled, the possibility of significant interruptions of normal operations
should be reduced.
Contingency Plans
The Company is identifying various scenarios that could occur in the
event that Year 2000 issues are not resolved in a timely manner. These efforts
will build upon the work in scenario development and contingency planning that
is being done by the WSCC contingency planning task force. A specialized team
has been formed that has developed contingency plans and updated existing
emergency preparedness plans to identify and address risk scenarios for the
Company. Contingency plans were sent to the Washington Commission and NERC on
June 30, 1999. These plans will be refined and updated as remediation and test
results are analyzed.
Forward Looking Statements
Readers are cautioned that forward-looking statements contained in the
Year 2000 update are based on management's best estimates and may be influenced
by factors that could cause actual outcomes and results to be materially
different than projected. Specific factors that might cause differences between
the estimates and actual results include, but are not limited to, the
availability and cost of personnel trained in these areas, the ability to locate
and correct all relevant computer code, timely responses to and corrections by
third-parties and suppliers, the ability to implement new systems in a timely
manner, the ability to implement interfaces between the new systems and the
systems not being replaced, and similar uncertainties. Due to the general
uncertainty inherent in the Year 2000 problem, resulting in part from the
uncertainty of the Year 2000 readiness of third-parties and the interconnection
of global businesses, the Company cannot ensure its ability to timely and
cost-effectively resolve problems associated with Year 2000 issues that may
affect its operations and business, or expose it to third-party liability.
Other
On April 30, 1999, the Company filed a registration statement and
prospectus for the formation of a holding company structure. The holding company
proposal was approved by shareholders at the Company's annual meeting on June
23, 1999. The proposed holding company structure is also subject to regulatory
approval by the Washington Utilities and Transportation Commission and the
Federal Energy Regulatory Commission.
The power supply operating alliance between the Company and Duke Energy
Trading and Marketing ("DETM"), whereby the Company participated in the Western
market activities of DETM, was terminated as of May 31, 1999. Going forward the
Company will perform the functions of minimizing the cost of, and optimizing the
value inherent in, its core power supply portfolio. The Company will overlay its
traditional supply management activities with an energy price risk hedging
capability. Termination of the agreement may result in a reduction in the
Company's volume of nonfirm and short term firm wholesale sales.
19
<PAGE>
On July 1, 1999, the Company called for redemption all outstanding shares
of its 8.5% Preferred Stock, Series III. The shares will be redeemed on
September 1, 1999, at the redemption price of $25 per share plus accrued
dividends.
On July 29, 1999, the Company was served a lawsuit by Tacoma Power, a
Washington municipal corporation. The anti-trust claim seeks modification of a
service area agreement for electrical power and unspecified damages. The Company
is currently evaluating the claim.
The Company has an Optional Large Power Sales Rate and certain "special
contracts" for its largest customers. Customers who elect the Optional Large
Power Sales Rate are no longer considered "core" customers, and the Company no
longer has an obligation to plan for future resources to serve their needs. The
non-core customers receive access to electric energy that is priced at current
market cost and pay a charge for energy delivery (including a charge for
conservation programs) and a transition charge (representing the difference
between the Company's present cost and the current market cost of electric
energy and capacity). The transition charge will be phased out before the end of
the year 2000. Non-core customers also take on the risk that market costs could
become volatile and that electricity could be unavailable on the open market. In
November 1998, a number of industrial customers filed a complaint with the
Washington Commission that the Company was incorrectly billing for energy under
the Optional Large Power Sales Rate. On August 3, 1999, the Company received an
order from the Washington Commission requiring the Company to refund
approximately $2.8 million to five customers. This amount includes disputed
amounts back to June 1, 1998, plus interest. The Company is considering its
options with respect to the order, including appeal and has not recorded a
reserve for this amount.
Item 3 Quantitative and Qualitative Disclosures About Market Risk
The Company is exposed to market risks, including changes in commodity
prices and interest rates.
Commodity Price Risk
The prices of energy commodities and transportation services are subject
to fluctuations due to unpredictable factors including weather, transportation
congestion and other factors which impact supply and demand. This commodity
price risk is a consequence of purchasing energy at fixed and variable prices
and providing deliveries at different tariff and variable prices. Costs
associated with ownership and operation of production facilities are another
component of this risk. The Company may use forward delivery agreements and
option contracts for the purpose of hedging commodity price risk. Unrealized
changes in the market value of these derivatives are deferred and recognized
upon settlement along with the underlying hedged transaction. In addition, the
Company believes its current rate design, including its Optional Large Power
Sales Rate, various special contracts and the PGA mechanism mitigate a portion
of this risk.
Market risk is managed subject to parameters established by the Board of
Directors. A Risk Management Committee separate from the units that create these
risks monitors compliance with the Company's policies and procedures. In
addition, the Audit Committee of the Company's Board of Directors has oversight
of the Risk Management Committee.
20
<PAGE>
Interest rate risk
The Company believes interest rate risks of the Company primarily relate
to the use of short-term debt instruments and new long-term debt financing
needed to fund capital requirements. The Company manages its interest rate risk
through the issuance of mostly fixed-rate debt of various maturities. The
Company does utilize bank borrowings, commercial paper and line of credit
facilities to meet short-term cash requirements. These short-term obligations
are commonly refinanced with fixed rate bonds or notes when needed and when
interest rates are considered favorable. The Company may enter into swap
instruments to manage the interest rate risk associated with these debts, and
one interest rate swap was outstanding as of June 30, 1999.
21
<PAGE>
PART II OTHER INFORMATION
Item 1 Legal Proceedings
Contingencies arising out of the normal course of the Company's
business exist at June 30, 1999. The ultimate resolution of these issues is not
expected to have a material adverse impact on the financial condition, results
of operations or liquidity of the Company.
Item 4 Submission of Matters to a Vote of Security Holders
At the annual meeting of shareholders held on June 23, 1999, the
following proposals were adopted by the margins indicated:
(a) Approve a proposal to adopt a holding company structure, to be
implemented through a plan of exchange whereby each share of Puget Sound Energy,
Inc. Common stock will be automatically exchanged for one share of Puget Energy,
Inc. Common stock.
For 56,442,280
Against 6,734,870
Abstain 1,580,486
(b) To elect four directors to hold office until the annual meeting of
shareholders in 2002, or until their successors are elected and qualified.
Number of Shares
For Withheld
Charles W. Bingham 75,699,485 1,321,248
Robert L. Dryden 75,653,121 1,367,611
John D. Durbin 75,706,964 1,313,769
Sally G. Narodick 75,538,299 1,482,434
Broker non-votes were not readily available.
Item 6 Exhibits and Reports on Form 8-K
(a) Exhibits
The following exhibits are filed herewith:
12-a Statement setting forth computation of ratios of earnings
to fixed charges (1994 through 1998 and 12 months ended
June 30, 1999)
12-b Statement setting forth computation of ratios of earnings
to combined fixed charges and preferred stock dividends
(1994 through 1998 and 12 months ended June 30, 1999)
27 Financial Data Schedule
(b) Reports of Form 8-K
The Company did not file any reports on Form 8-K during the
quarter ended June 30, 1999.
22
<PAGE>
SIGNATURES
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.
PUGET SOUND ENERGY, INC.
James W. Eldredge
---------------------------------
James W. Eldredge
Corporate Secretary and Controller
Date: August 13, 1999 Chief accounting officer and officer
duly authorized to sign this report
on behalf of the registrant
23
<PAGE>
<TABLE>
STATEMENT SETTING FORTH COMPUTATIONS OF RATIOS OF
EARNINGS TO FIXED CHARGES
(Dollars in Thousands)
<CAPTION>
12 Months
Ending Year Ended December 31,
June 30, 1999 1998 1997 1996 1995 1994
- -------------------------------------- ------------------- ------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C> <C>
EARNINGS AVAILABLE FOR
FIXED CHARGES
Pre-tax income:
Income from continuing
operations per statement
of income $184,888 $169,612 $125,698 $167,351 $128,382 $ 79,312
Federal income taxes 115,528 107,904 47,725 107,747 91,519 74,816
Federal income taxes charged
to other income - net 9,218 1,807 11,876 (1,608) (12,068) 22,687
Capitalized interest (3,958) (1,782) (360) (600) (660) (400)
Undistributed (earnings) or
losses of less-than-
fifty-percent-owned
entities -- -- (608) 460 8,325 743
- -------------------------------------- ------------------- ------------ ------------ ------------ ------------ ------------
Total $305,676 $277,541 $184,331 $273,350 $215,498 $177,158
- -------------------------------------- ------------------- ------------ ------------ ------------ ------------ ------------
Fixed charges:
Interest expense $152,299 $146,140 $123,439 $122,635 $131,346 $126,555
Other interest 3,958 1,782 360 600 660 400
Portion of rentals
representative of the
interest factor 3,626 2,878 3,143 4,187 5,150 5,555
- -------------------------------------- ------------------- ------------ ------------ ------------ ------------ ------------
Total $159,883 $150,800 $126,942 $127,422 $137,156 $132,510
- -------------------------------------- ------------------- ------------ ------------ ------------ ------------ ------------
Earnings available for
combined fixed charges $465,559 $428,341 $311,273 $400,772 $352,654 $309,668
RATIO OF EARNINGS TO
FIXED CHARGES 2.91x 2.84x 2.45x 3.15x 2.57x 2.34x
</TABLE>
<PAGE>
<TABLE>
Exhibit 12b
STATEMENT SETTING FORTH COMPUTATIONS OF RATIOS OF
EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
(Dollars in Thousands)
<CAPTION>
12 Months
Ending Year Ended December 31,
June 30, 1999 1998 1997 1996 1995 1994
- -------------------------------------- ---------------------- ------------ ----------- ------------ ------------ ------------
<S> <C> <C> <C> <C> <C> <C>
EARNINGS AVAILABLE FOR COMBINED
FIXED CHARGES AND PREFERRED
DIVIDEND REQUIREMENTS
Pretax income:
Income from continuing
operations per statement
of income $184,888 $169,612 $125,698 $167,351 $128,382 $ 79,312
Federal income taxes 115,528 107,904 47,725 107,747 91,519 74,816
Federal income taxes charged
to other income - net 9,218 1,807 11,876 (1,608) (12,068) 22,687
Subtotal 309,634 279,323 185,299 273,490 207,833 176,815
Capitalized interest (3,958) (1,782) (360) (600) (660) (400)
Undistributed (earnings) or
losses of less-than-fifty-
percent-owned entities -- -- (608) 460 8,325 743
- -------------------------------------- ---------------------- ------------ ----------- ------------ ------------ ------------
Total $305,676 $277,541 $184,331 $273,350 $215,498 $177,158
- -------------------------------------- ---------------------- ------------ ----------- ------------ ------------ ------------
Fixed charges:
Interest expense $152,299 $146,140 $123,439 $122,635 $131,346 $126,555
Other interest 3,958 1,782 360 600 660 400
Portion of rentals
representative of the
interest factor 3,626 2,878 3,143 4,187 5,150 5,555
- -------------------------------------- ---------------------- ------------ ----------- ------------ ------------ ------------
Total $159,883 $150,800 $126,942 $127,422 $137,156 $132,510
- -------------------------------------- ---------------------- ------------ ----------- ------------ ------------ ------------
Earnings available for
combined fixed charges
and preferred dividend
requirements $465,559 $428,341 $311,273 $400,772 $352,654 $309,668
DIVIDEND REQUIREMENT:
Fixed charges above $159,883 $150,800 $126,942 $127,422 $137,156 $132,510
Preferred dividend
requirements below 20,654 21,414 26,250 36,249 36,674 45,441
- -------------------------------------- ---------------------- ------------ ----------- ------------ ------------ ------------
Total $180,537 $172,214 $153,192 $163,671 $173,830 $177,951
- -------------------------------------- ---------------------- ------------ ----------- ------------ ------------ ------------
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
12 Months
Ending Year Ended December 31,
June 30, 1999 1998 1997 1996 1995 1994
- ----------------------------------- -------------------- ----------- ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C> <C>
RATIO OF EARNINGS TO COMBINED
FIXED CHARGES AND PREFERRED
DIVIDEND REQUIREMENTS 2.58 2.49 2.03 2.45 2.03 1.74
COMPUTATION OF PREFERRED
DIVIDEND REQUIREMENTS:
(a) Pre-tax income $309,634 $279,323 $185,299 $273,490 $207,833 $176,815
(b) Income from continuing
operations $184,888 $169,612 $125,698 $167,351 $128,382 $ 79,312
(c) Ratio of (a) to (b) 1.6747 1.6468 1.4742 1.6342 1.6189 2.2294
(d) Preferred dividends $ 12,333 $ 13,003 $ 17,806 $ 22,181 $ 22,654 $ 20,383
Preferred dividend
requirements
[(d) multiplied by (c)] $ 20,654 $ 21,414 $ 26,250 $ 36,249 $ 36,674 $ 45,441
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<CIK> 0000081100
<NAME> PUGET SOUND ENERGY
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> JUN-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 3,488,638
<OTHER-PROPERTY-AND-INVEST> 262,712
<TOTAL-CURRENT-ASSETS> 366,099
<TOTAL-DEFERRED-CHARGES> 0
<OTHER-ASSETS> 606,340
<TOTAL-ASSETS> 4,723,789
<COMMON> 845,605
<CAPITAL-SURPLUS-PAID-IN> 450,836
<RETAINED-EARNINGS> 64,441
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,360,882
65,662
90,000
<LONG-TERM-DEBT-NET> 1,714,770
<SHORT-TERM-NOTES> 174,000
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 62,493
<LONG-TERM-DEBT-CURRENT-PORT> 107,000
0
<CAPITAL-LEASE-OBLIGATIONS> 0
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<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,148,982
<TOT-CAPITALIZATION-AND-LIAB> 4,723,789
<GROSS-OPERATING-REVENUE> 1,010,772
<INCOME-TAX-EXPENSE> 60,678
<OTHER-OPERATING-EXPENSES> 793,267
<TOTAL-OPERATING-EXPENSES> 853,945
<OPERATING-INCOME-LOSS> 156,827
<OTHER-INCOME-NET> 16,849
<INCOME-BEFORE-INTEREST-EXPEN> 173,676
<TOTAL-INTEREST-EXPENSE> 72,855
<NET-INCOME> 100,821
5,889
<EARNINGS-AVAILABLE-FOR-COMM> 94,932
<COMMON-STOCK-DIVIDENDS> 77,796
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