CONFORMED
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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 September 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 September 30,
1999 was 84,560,536.
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1
<PAGE>
Table of Contents
Page
Number
Part I. Financial Information
Item 1. Financial Statements
Consolidated Statements of Income -
three month periods ended September 30, 1999 and 1998 3
Consolidated Statements of Income -
nine month periods ended September 30, 1999 and 1998 4
Consolidated Statements of Comprehensive Income -
three month and nine month periods ended
September 30, 1999 and 1998 5
Consolidated Balance Sheets - September 30, 1999 and December 31, 1998 6
Consolidated Statements of Cash Flows -
nine month periods ended September 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 21
Part II. Other Information
Item 1. Legal Proceedings 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 September 30
(Thousands except per share amounts)
(Unaudited)
<CAPTION>
1999 1998
---- ----
<S> <C> <C>
OPERATING REVENUES:
Electric $ 345,257 $ 375,398
Gas 57,705 49,955
Other 8,073 3,157
--------- ---------
Total operating revenues 411,035 428,510
--------- ---------
OPERATING EXPENSES:
Energy costs:
Purchased electricity 178,815 211,226
Purchased gas 22,185 17,174
Electric generation fuel 11,531 15,661
Residential Exchange (7,554) (11,763)
Utility operations and maintenance 60,538 51,077
Other operations and maintenance 4,862 6,618
Depreciation and amortization 43,191 41,988
Conservation amortization 1,684 1,136
Taxes other than federal income taxes 36,434 33,146
Federal income taxes 7,901 11,413
--------- ---------
Total operating expenses 359,587 377,676
--------- ---------
OPERATING INCOME 51,448 50,834
OTHER INCOME - net 9,801 4,184
--------- ---------
INCOME BEFORE INTEREST CHARGES 61,249 55,018
INTEREST CHARGES, net of AFUDC 36,337 33,927
--------- ---------
NET INCOME 24,912 21,091
Less: Preferred stock dividends accrual 2,800 3,226
--------- ---------
INCOME FOR COMMON STOCK $ 22,112 $ 17,865
========= =========
COMMON SHARES OUTSTANDING - WEIGHTED AVERAGE 84,561 84,561
========= =========
BASIC & DILUTED EARNINGS PER COMMON SHARE: $ 0.26 $ 0.21
========= =========
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 Nine Month Periods Ended September 30
(Thousands except per share amounts)
(Unaudited)
<CAPTION>
1999 1998
---- ----
<S> <C> <C>
OPERATING REVENUES:
Electric $ 1,082,966 $ 1,030,907
Gas 322,722 274,529
Other 16,312 17,815
----------- ----------
Total operating revenues 1,422,000 1,323,251
----------- ----------
OPERATING EXPENSES:
Energy costs:
Purchased electricity 540,088 517,881
Purchased gas 139,263 117,700
Electric generation fuel 32,586 36,402
Residential Exchange (27,869) (39,333)
Utility operations and maintenance 179,968 168,161
Other operations and maintenance 18,247 19,161
Depreciation and amortization 128,775 123,171
Conservation amortization 5,080 3,815
Taxes other than federal income taxes 129,058 115,623
Federal income taxes 68,526 61,688
----------- ----------
Total operating expenses 1,213,722 1,124,269
----------- ----------
OPERATING INCOME 208,278 198,982
OTHER INCOME - net 26,648 9,650
----------- ----------
INCOME BEFORE INTEREST CHARGES 234,926 208,632
INTEREST CHARGES, net of AFUDC 109,193 102,038
----------- ----------
NET INCOME 125,733 106,594
Less: Preferred stock dividends accrual 8,689 9,784
----------- ----------
INCOME FOR COMMON STOCK $ 117,044 $ 96,810
=========== ==========
COMMON SHARES OUTSTANDING - WEIGHTED AVERAGE 84,561 84,561
=========== ==========
BASIC & DILUTED EARNINGS PER COMMON SHARE: $ 1.38 $ 1.14
=========== ==========
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
September 30
(Dollars in Thousands)
(Unaudited)
<CAPTION>
1999 1998
---- ----
<S> <C> <C>
Net Income $ 24,912 $ 21,091
--------- ---------
Other comprehensive income, net of tax:
Unrealized holding losses arising during period -- (6,586)
Reclassification adjustment for gains included
in net income -- --
--------- ---------
Other comprehensive income -- (6,586)
--------- ---------
Comprehensive Income $ 24,912 $ 14,505
========= =========
PUGET SOUND ENERGY, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Nine Month Periods Ended
September 30
(Dollars in Thousands)
(Unaudited)
<CAPTION>
1999 1998
---- ----
<S> <C> <C>
Net Income $ 125,733 $ 106,594
--------- ---------
Other comprehensive income, net of tax:
Unrealized holding gains (losses) arising
during period 3,482 (5,806)
Reclassification adjustment for gains included
in net income (12,284) --
--------- ---------
Other comprehensive income (8,802) (5,806)
--------- ---------
Comprehensive Income $ 116,931 $ 100,788
========= =========
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>
September 30, December 31,
1999 1998
------------- ------------
<S> <C> <C>
UTILITY PLANT: (at original cost, including
construction work in progress
of $299,644 and $266,242
respectively)
Electric $ 3,710,981 $ 3,694,593
Gas 1,343,569 1,278,275
Common 290,675 179,140
Less: Accumulated depreciation and
amortization 1,816,782 1,721,096
------------- ------------
Net utility plant 3,528,443 3,430,912
------------- ------------
OTHER PROPERTY AND INVESTMENTS 253,273 260,087
------------- ------------
CURRENT ASSETS:
Cash 72,160 28,216
Accounts receivable 147,017 189,638
Unbilled revenue 66,973 126,740
Materials and supplies, at average cost 69,154 58,534
Purchased gas receivable 33,995 5,492
Prepayments and other 20,497 7,990
------------- ------------
Total current assets 409,796 416,610
------------- ------------
LONG-TERM ASSETS:
Regulatory asset for deferred income taxes 223,762 241,406
Deferred PURPA power contract buydown costs 225,501 221,802
Other 153,260 138,870
------------- ------------
Total long-term assets 602,523 602,078
------------- ------------
TOTAL ASSETS $ 4,794,035 $ 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>
September 30, December 31,
1999 1998
------------- ------------
<S> <C> <C>
CAPITALIZATION:
Common shareholders' investment:
Common stock, $10 stated value,
150,000,000 shares authorized,
84,560,536 and 84,560,561 shares
outstanding $ 845,605 $ 845,606
Additional paid-in capital 450,837 450,724
Earnings reinvested in the business 47,650 47,548
Accumulated other comprehensive income -- 8,802
Preferred stock not subject to
mandatory redemption 60,000 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 1,689,770 1,475,106
------------- ------------
Total capitalization 3,259,524 3,096,023
------------- ------------
CURRENT LIABILITIES:
Accounts Payable 138,660 163,141
Short-term debt 413,878 450,905
Current maturities of long-term debt 85,000 107,000
Accrued expenses:
Taxes 63,361 59,764
Salaries and wages 20,001 18,650
Interest 36,765 39,062
Other 21,169 23,150
------------- ------------
Total current liabilities 778,834 861,672
------------- ------------
DEFERRED INCOME TAXES 619,281 628,554
------------- ------------
OTHER DEFERRED CREDITS 136,396 123,438
------------- ------------
TOTAL CAPITALIZATION AND LIABILITIES $ 4,794,035 $ 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 Nine Month Periods Ended
September 30
(Dollars in Thousands)
(Unaudited)
<CAPTION>
1999 1998
---- ----
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income $ 125,733 $ 106,594
Adjustments to reconcile net income
to net cash provided by operating activities:
Depreciation and amortization 128,775 123,171
Deferred income taxes and tax credits - net 8,371 2,223
Gain from sale of investment in Cabot common stock (18,899) --
Gain from sale of Homeguard Security Services (11,659) --
Other 21,143 50,023
Change in certain current assets
and liabilities (Note 3) 26,947 (4,681)
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Net Cash Provided by Operating Activities 280,411 277,330
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INVESTING ACTIVITIES:
Construction expenditures - excluding equity AFUDC (244,754) (230,744)
Additions to energy conservation program (4,111) (4,730)
Loans to CellNet Data Services (25,800) --
Proceeds from sale of investment in Cabot common stock 37,353 --
Proceeds from sale of Homeguard Security Services 13,399 --
Other 1,951 (3,885)
- --------------------------------------------------------------------------------
Net Cash Used by Investing Activities (221,962) (239,359)
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FINANCING ACTIVITIES:
Change in short-term debt, net (37,027) (13,797)
Dividends paid (125,476) (127,037)
Redemption of preferred stock (42,575) (5,236)
Issuance of bonds 250,000 200,000
Redemption of bonds and notes (57,370) (81,068)
Issue costs of bonds and stock (2,057) (2,167)
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Net Cash Used by Financing Activities (14,505) (29,305)
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- --------------------------------------------------------------------------------
Net Increase in cash 43,944 8,666
Cash at Beginning of year 28,216 10,729
================================================================================
Cash at End of Period $ 72,160 $ 19,395
================================================================================
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 nine months
ended September 30, 1999 and 1998.
Diluted earnings per common share have been computed based on weighted
average common shares outstanding of 84,764,000 and 84,763,000 for the three and
nine months ended September 30, 1999, and 84,696,000 and 84,680,000 for the
three and nine months ended September 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>
Nine Months Ended September 30 1999 1998
- ------------------------------ ---- ----
<S> <C> <C>
Changes in current asset and current liabilities:
Accounts receivable and unbilled revenue $ 102,388 $ (17,807)
Materials and supplies (10,620) (7,090)
Prepayments and Other (12,507) (6,285)
Purchased gas receivable (28,503) 2,094
Accounts payable (24,481) 48,750
Accrued expenses and Other 670 (24,343)
================================================================== ===========
Net change in current assets and current liabilities $ 26,947 $ (4,681)
================================================================== ===========
Cash payments:
Interest (net of capitalized interest) $ 116,472 $ 103,495
Income taxes $ 47,750 $ 66,360
- ------------------------------------------------------------------ -----------
</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, 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 September 30, 1999 Utility Other Total
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Revenues $ 402,962 $ 8,073 $ 411,035
Net Income 18,136 6,776 24,912
Total Assets 4,670,657 123,378 4,794,035
- -------------------------------------------------------------------------------------------------------------------
Regulated
Three Months Ended September 30, 1998 Utility Other Total
- -------------------------------------------------------------------------------------------------------------------
Revenues $ 425,353 $3,157 $ 428,510
Net Income 23,829 (2,738) 21,091
Total Assets 4,525,054 109,786 4,634,840
- -------------------------------------------------------------------------------------------------------------------
(Dollars in Thousands) Regulated
Nine Months Ended September 30, 1999 Utility Other Total
- -------------------------------------------------------------------------------------------------------------------
Revenues $1,405,688 $ 16,312 $1,422,000
Net Income 113,052 12,681 125,733
Total Assets 4,670,657 123,378 4,794,035
- -------------------------------------------------------------------------------------------------------------------
Regulated
Nine Months Ended September 30, 1998 Utility Other Total
- -------------------------------------------------------------------------------------------------------------------
Revenues $1,305,436 $ 17,815 $1,323,251
Net Income 108,995 (2,401) 106,594
Total Assets 4,525,054 109,786 4,634,840
- -------------------------------------------------------------------------------------------------------------------
</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 would 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.. 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. On June 30, 1999, the Company
made the first loan under the loan agreement and as of September 30, 1999, there
were loans outstanding of $25.8 million. In September 1999, the Company
announced it was expanding its AMR network system from 800,000 meters to
1,325,000 meters and as a result increased the loan agreement amount to $72
million.
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.
On September 30, 1999, the Company announced an agreement to purchase a 160
megawatt natural gas-fired co-generation plant near Bellingham, Washington from
Encogen Northwest L.P. for $164 million. Under a power purchase contract signed
in 1990 pursuant to the Public Utility Regulatory Policies Act of 1978, the
Company was obligated to purchase the net output of the plant at prices above
current and projected future market prices. The contract had obligated the
Company to pay Encogen fixed and escalating fees through mid-2008 for the output
of the co-generation plant. Pursuant to an October 27, 1999 order from the
Washington Commission approving the purchase, the Company will depreciate the
original owner's net book value of the plant over the remaining 23 year useful
life of the project. The difference between the purchase price and the net book
value of the plant (approximately $71.1 million) will be amortized over 9 years
(the remaining term of the power purchase contract). The purchase is expected to
reduce the net cost of power from the co-generation project by approximately 17%
annually compared to existing contract prices.
In the third quarter of 1999, the Company sold the assets, liabilities and
trade name of its wholly-owned subsidiary, Homeguard Security Services, Inc. The
Company also sold in the third quarter of 1999, certain non-core assets and the
majority of the gas pipeline capacity rights and gas storage rights of
Washington Energy Gas Marketing ("WEGM", a wholly-owned subsidiary), in the
United States and the Province of Alberta, Canada. The Company recorded an after
tax gain of approximately $3.6 million related to the sale of non-core assets in
the quarter.
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 September 30, 1999, was $24.9 million
on operating revenues of $411.0 million, compared with net income of $21.1
million on operating revenues of $428.5 million for the same period in 1998.
Income for common stock was $22.1 million for the third quarter of 1999 and
$17.9 million for the third quarter of 1998. Basic and diluted earnings per
common share were $0.26 for the third quarter of 1999 compared to $0.21 for the
third quarter of 1998.
For the first nine months of 1999, net income was $125.7 million on
operating revenues of $1,422.0 million, compared with net income of $106.6
million on operating revenues of $1,323.3 million for the corresponding period
in 1998. Income for common stock was $117.0 million for the first nine months of
1999 and $96.8 million for the same period in 1998. Basic and diluted earnings
per common share were $1.38 for the nine months ended September 30, 1999, and
$1.14 for the same period in 1998.
Results from non-utility operations for the third quarter of 1999 were
positively impacted by the sale and assignment of certain non-core assets and
gas supply transportation contracts which resulted in an after-tax gain of
approximately $3.6 million. Results from non-utility operations for the nine
months ended September 30, 1999, were also positively impacted by approximately
$0.10 per share recorded in the second quarter of 1999 which was 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 increases in net income and earnings per share for the three and nine
months ended September 30, 1999, compared to the same periods in 1998 are also
the result of continued customer growth, temperatures that averaged near normal
as compared to warmer than normal during 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 2.9 billion in sales
to wholesale customers, for the third quarter of 1999, compared to 7.9 billion,
including 3.3 billion in sales to wholesale customers, for the third quarter of
1998. For the nine month periods ended September 30, 1999 and 1998, total
kilowatt-hour sales were 23.9 billion, including 8.3 billion in sales to
wholesale customers, and 21.8 billion, including 6.6 billion in sales to
wholesale customers, respectively.
12
<PAGE>
Total gas volumes were 149.3 million therms, including 50.8 million therms
in transportation volumes for the three months ended September 30, 1999,
compared to 127.7 million therms, including 53.5 million therms of
transportation, for the same period in 1998. For the nine months ended September
30, 1999, total gas volumes were 769.7 million therms, including 177.3 million
therms of transportation, compared to 678.6 million therms, including 192.3
million therms of transportation, for the same period in 1998.
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
wholesale customers 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 Nine Month Periods Ended
September 30, 1999 vs. September 30, 1998
Increase (Decrease)
<CAPTION>
Three Month Nine Month
Period Period
(In Millions)
---------- ----------
<S> <C> <C>
Operating revenue changes
General rate increase - electric $3.3 $11.0
Residential Exchange credits provided to customers (1.1) (4.7)
Sales to wholesale customers (32.1) 21.8
Electric load and other changes (0.3) 23.9
Gas revenue change 7.8 48.2
Other revenue changes 4.9 (1.5)
---------- ----------
Total operating revenue change (17.5) 98.7
---------- ----------
Operating expense changes Energy costs:
Purchased electricity (32.4) 22.2
Purchased gas 5.0 21.6
Electric generation fuel (4.1) (3.8)
Residential exchange credit 4.2 11.5
Utility operations and maintenance 9.5 11.7
Other operations and maintenance (1.8) (0.9)
Depreciation and amortization 1.2 5.6
Conservation amortization 0.5 1.3
Taxes other than federal income taxes 3.3 13.4
Federal income taxes (3.5) 6.8
---------- ----------
Total operating expense change (18.1) 89.4
---------- ----------
Other income 5.6 17.0
Interest charges 2.4 7.2
========== ==========
Net income change $3.8 $19.1
========== ==========
</TABLE>
The following is additional information pertaining to the changes outlined
in the above table.
13
<PAGE>
Operating Revenues - Electric
Electric revenues were increased by $3.3 million and $11.0 million for the
three and nine months ended September 30, 1999, respectively, compared to the
same periods in 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 gives to customers related to 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 from BPA of approximately $235 million over an approximately five-year
period ending June 2001. These payments are recorded as a reduction of purchased
electricity expenses. Under the rate plan approved by the Washington Commission
in its merger order, the Company will continue to reflect, in customers' bills,
the level of Residential Exchange benefits in place at time of the merger. Over
the remainder of the Residential Exchange Termination Agreement from October
1999 through June 2001, it is projected that the Company will credit customers
approximately $120.6 million more than it will receive from BPA during the
following periods:
Dollars in
Period Millions
------ ----------
October - December 1999 $15.3
January - December 2000 68.4
January - June 2001 36.9
------
$120.6
======
The allocation of future benefits of low-cost federal power, for the
five-year BPA rate plan period 2002 to 2006 will be decided as part of the
current BPA rate case process. As part of its rate case, the BPA has a
"subscription plan" that spells out how the agency proposes to allocate the
low-cost federal power, or in some cases, the power's equivalent monetary
benefits. Following a public rate-hearing process, the BPA is expected to
publish a record of decision on final power rates and allocations in spring
2000.
Electric sales to wholesale customers decreased $32.1 million in the
quarter ended September 30, 1999, compared to the quarter ended September 30,
1998, primarily as a result of the termination of the power supply operating
alliance between the Company and Duke Energy Trading and Marketing ("DETM")
effective May 31, 1999 (See MD&A - Other).
Electric sales to wholesale customers increased $21.8 million in the
nine-month period ended September 30, 1999, compared to the same period in 1998
due to activities pursuant to the agreement with DETM. Related power cost
expenses for the nine-month period also increased as the Company generated and
purchased more power for these sales.
14
<PAGE>
Electric revenues were positively impacted in the three and nine months
ended September 30, 1999, by temperatures that averaged near normal during the
1999 periods as compared to warmer than normal 1998 periods and an increase of
approximately 2% in the number of electric customers.
Revenues in the three and nine months ended September 30, 1999 were also
reduced by the accrual of approximately $4.3 million in refunds related to
disputes with industrial customers under certain special contracts and an
Optional Large Power Sales Rate. (See discussion in "Other")
Operating Revenues - Gas
Gas operating revenues for the quarter ended September 30,1999, increased
$7.8 million or 15.5% from the prior year quarter. Total gas volumes increased
16.9% from 127.7 million therms to 149.3 million therms. The primary reasons for
the increase in gas sales volume and gas sales revenue in the quarter ended
September 30, 1999, was the 4.6% increase in gas customers and temperatures that
averaged near normal as compared warmer than normal in 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. Gas margin (regulated utility sales less the cost of gas sold) also
increased by $3.9 million, or 13.4 % in the third quarter of 1999 compared to
the same period in 1998. The increase in gas margin was due primarily to the
increase in gas customers and the recognition of incentive gains under the
Purchased Gas Adjustment ("PGA") Incentive Mechanism approved by the Washington
Commission in June 1998.
For the nine months ended September 30, 1999, gas operating revenues
increased $48.2 million or 17.6% from $274.5 million in the nine months ended
September 30, 1998, to $322.7 million while total gas volumes increased 13.4 %.
The increases in the period were primarily due to a 4.4% increase in gas
customers and the impact temperatures that averaged near normal as compared to
warmer than normal in 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. Gas margin in the nine months
ended September 30, 1999, also increased $27.7 million or 18.8% compared to the
same period in 1998. The increase in gas margin was due primarily to the
increase in gas customers and the recognition of incentive gains under the PGA
Incentive Mechanism approved by the Washington Commission in June 1998.
Other revenues increased $4.9 million in the three months ended September
30, 1999 compared to the three months ended September 30, 1998, due primarily to
increased property sales at the Company's real estate subsidiary. Other revenues
decreased $1.5 million in the nine months ended September 30, 1999, as compared
to the same period in 1998 due to decreased revenues at the Company's
subsidiaries.
Operating Expenses
Purchased electricity expenses decreased $32.4 million for the three-months
ended September 30, 1999, compared to the three-months ended September 30, 1998,
primarily as a result of the aforementioned termination of the power supply
operating alliance between the Company and DETM effective May 31, 1999.
Purchased electricity expenses increased $22.2 million for the nine-months ended
September 30, 1999, compared to the nine-months ended September 30, 1998. The
increase during this period was due primarily to increased secondary power
purchases to support wholesale sales and the increased load due to temperatures
that averaged near normal as compared to warmer than normal in 1998 and a
greater number of electric customers in 1999 compared to 1998.
15
<PAGE>
Purchased gas expenses increased $5.0 million and $21.6 million for the
three and nine month periods ended September 30, 1999, respectively, as compared
to the same periods in 1998 due to both increased volumes of purchases as a
result of higher heating load and the increase in gas service customers.
Fuel expense decreased $4.1 million and $3.8 million for the three and nine
month periods ended September 30, 1999, respectively, compared to the same
periods in 1998 due primarily to the Company generating less electricity at
Company-owned combustion turbines.
Residential exchange credits associated with the Residential Purchase and
Sale Agreement with BPA decreased $4.2 million and $11.5 million in the three
and nine month periods ended September 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 $9.5 million and
$11.7 million for the three and nine month periods ended September 30, 1999,
respectively, compared to the same periods in 1998. The primary reasons for the
nine month period increase were increased storm-repair costs of $8.6 million and
increased expenditures for Year 2000 remediation efforts of $5.4 million.
Increased storm repair costs and expenditures for Year 2000 remediation efforts
also contributed to the three month period increase as well as a $2.1 million
increase in coal plant non-fuel expense as a result of the major overhaul of
Colstrip Unit 1.
Depreciation and amortization expense increased $1.2 million and $5.6
million for the three and nine month periods September 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 $3.3 million and $13.4
million for the three and nine month periods ended September 30, 1999, compared
to the same periods in 1998 due primarily to increases in municipal taxes, state
excise taxes and state property taxes.
Federal income taxes decreased $3.5 million for the three month period
ended September 30, 1999, compared to the same period in 1998 as a result of a
$2.4 million true-up which resulted in lower federal income tax and an increase
in interest expense during the period. Federal income taxes increased $6.8
million for the nine-month period ended September 30, 1999, from the same period
in 1998 primarily due to higher pre-tax operating income for the period.
Other Income
Other income, net of federal income tax, increased $5.6 million for the
three month period ending September 30, 1999, compared to the same period in
1998. The increase was primarily the result of the sale and assignment of
certain non-core assets and gas supply transportation contracts which resulted
in an after-tax gain of approximately $3.6 million.
Other income for the nine month period ended September 30, 1999, increased
$17.0 million when compared to the same period in 1998 due primarily to the
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 as well as the aforementioned gain of $3.6 million in the
third quarter of 1999.
16
<PAGE>
Interest Charges
Interest charges, which consist of interest and amortization on long-term
debt and other interest, increased $2.4 million and $7.2 million for the three
and nine month periods ended September 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 $108 million in Secured Medium-Term Notes since February 1998 and
the redemption of $30 million 9.14% Secured Medium-Term Notes, Series A, in June
1998. Other interest expense decreased $1.1 million and $3.0 million for the
three and nine months ended September 30, 1999, respectively, compared to the
same periods in 1998 as a result of lower weighted average interest rates.
Capital Expenditures, Capital Resources and Liquidity
Capital expenditures, which include energy conservation expenditures and
exclude AFUDC, for the third quarter of 1999 were $80.3 million compared to
$89.3 million for the third quarter of 1998. Year-to-date capital expenditures
totaled $241.4 million compared to $229.7 million for the same period in 1998.
Capital 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 capital expenditures (excluding AFUDC) was 5% and 0% for the
third quarters of 1999 and 1998, respectively. Cash provided by operations (net
of dividends and AFUDC) as a percentage of capital expenditures (excluding
AFUDC) was 61% and 63% for the nine month periods ended September 30, 1999 and
1998, respectively. Capital expenditure estimates are subject to periodic review
and adjustment.
On September 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 $162.3 million, reducing the available borrowing
capacity under these lines of credit to $212.7 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.
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 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 fourth quarter.
Project Approach and Progress
The number of people working full time and part time on the Company's Year
2000 project has fluctuated between 125 and 150. The Company 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 took 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 engaged outside consultants
and technicians to aid in formulating and implementing its plan. All business
units have completed the inventory, assessment, remediation, testing,
implementation and contingency planning phases.
17
<PAGE>
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 Customer Information System ("CIS"). The
SAP system is Year 2000 compliant.
A new CIS, which is designed to be Year 2000 compliant, is currently being
developed by the Company. The Company has also remediated critical elements of
its existing CIS for Year 2000 compliance purposes.
A specialized embedded systems team was 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. All third party assessment was
completed in June 1999. When 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 where appropriate company line managers have
developed alternate sources or other contingency plans.
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 BPA 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 reduced 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
approximately $0.5 million related to contingency planning has yet to be
expended.
18
<PAGE>
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 has continued to
assess this risk as the millennium approaches and evaluated the likelihood of
power failures and continues to 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 formed a special team to handle these types of
components (embedded systems), and retained an independent engineering firm with
specific utility experience to assist in the effort. Results of assessment
revealed 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.
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 has significantly reduced 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 has
been reduced.
Contingency Plans
A specialized team was formed that developed contingency plans and updated
existing emergency preparedness plans to identify and address risk scenarios for
the Company. 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. Contingency plans were successfully tested
during the NERC September 8th and 9th 1999 drill. Additional internal drills are
planned during the last two months of 1999.
19
<PAGE>
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 reliance upon 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 Commission and the Federal Energy Regulatory
Commission.
A 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 effective 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.
On September 1, 1999, the Company redeemed all outstanding shares of its
8.5% Preferred Stock, Series III, at the redemption price of $25 per share plus
accrued dividends.
The Company has an Optional Large Power Sales Rate and certain "special
contracts" for its largest customers. The Company has been involved in disputes
with a number of industrial customers regarding their claims that the Company
was incorrectly billing for energy under the Optional Large Power Sales Rate and
special contracts. In the third quarter of 1999, the Company accrued refunds of
approximately $4.3 million related to these disputes. In November 1999, the
disputes with industrial customers with respect to the Optional Large Power
Sales Rate were resolved.
In the third quarter of 1999, the Company sold the assets, liabilities and
trade name of its wholly-owned subsidiary, Homeguard Security Services, Inc. The
Company also sold in the third quarter of 1999, certain non-core assets and the
majority of the gas pipeline capacity rights and gas storage rights of
Washington Energy Gas Marketing ("WEGM", a wholly-owned subsidiary), in the
United States and the Province of Alberta, Canada. The Company recorded an after
tax gain of approximately $3.6 million related to the sale of non-core assets in
the quarter.
For a discussion of the purchase of a 160 megawatt natural gas-fired
co-generation plant from Encogen Northwest L.P. see Note 5 to the Consolidated
Financial Statements.
On October 27, 1999, the Washington Commission approved the Company's PGA
and deferral amortization (true-up) filings effective November 1, 1999. The PGA
filing allows the Company to recover an expected increase in annual gas costs
and the deferral amortization filing allows the Company to recover prior period
gas cost undercollections. The filings replaced the PGA and deferral
amortization refund that had been effective since April 1, 1998. The combined
filings increased gas rates to all sales customers by an average of 16.3%.
20
<PAGE>
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.
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 September 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 September 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 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
September 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 September 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
September 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.
/s/ James W. Eldredge
---------------------
James W. Eldredge
Corporate Secretary and Controller
Date: November 12, 1999 Chief accounting officer and officer duly
authorized to sign this report on behalf
of the registrant
23
<PAGE>
<TABLE>
Exhibit 12a
STATEMENT SETTING FORTH COMPUTATIONS OF RATIOS OF
EARNINGS TO FIXED CHARGES
(Dollars in Thousands)
<CAPTION>
12 Months
Ending Year Ended December 31,
September
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 $ 187,825 $ 169,612 $ 125,698 $ 167,351 $ 128,382 $ 79,312
Federal income taxes 111,220 107,904 47,725 107,747 91,519 74,816
Federal income taxes charged
to other income - net 6,903 1,807 11,876 (1,608) (12,068) 22,687
Capitalized interest (4,677) (1,782) (360) (600) (660) (400)
Undistributed (earnings) or
losses of less-than-
fifty-percent-owned
entities -- -- (608) 460 8,325 743
- -------------------------------- --------- --------- --------- --------- --------- ---------
Total $ 301,271 $ 277,541 $ 184,331 $ 273,350 $ 215,498 $ 177,158
- -------------------------------- --------- --------- --------- --------- --------- ---------
Fixed charges:
Interest expense $ 155,108 $ 146,140 $ 123,439 $ 122,635 $ 131,346 $ 126,555
Other interest 4,677 1,782 360 600 660 400
Portion of rentals
representative of the
interest factor 4,214 2,878 3,143 4,187 5,150 5,555
- -------------------------------- --------- --------- --------- --------- --------- ---------
Total $ 163,999 $ 150,800 $ 126,942 $ 127,422 $ 137,156 $ 132,510
- -------------------------------- --------- --------- --------- --------- --------- ---------
Earnings available for
combined fixed charges $ 465,270 $ 428,341 $ 311,273 $ 400,772 $ 352,654 $ 309,668
RATIO OF EARNINGS TO
FIXED CHARGES 2.84x 2.84x 2.45x 3.15x 2.57x 2.34x
</TABLE>
1
<PAGE>
<TABLE>
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,
September
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 $ 187,825 $ 169,612 $ 125,698 $ 167,351 $ 128,382 $ 79,312
Federal income taxes 111,220 107,904 47,725 107,747 91,519 74,816
Federal income taxes charged
to other income - net 6,903 1,807 11,876 (1,608) (12,068) 22,687
Subtotal 305,948 279,323 185,299 273,490 207,833 176,815
Capitalized interest (4,677) (1,782) (360) (600) (660) (400)
Undistributed (earnings) or
losses of less-than-fifty-
percent-owned entities -- -- (608) 460 8,325 743
- -------------------------------------------- --------- --------- --------- --------- ---------
Total $ 301,271 $ 277,541 $ 184,331 $ 273,350 $ 215,498 $ 177,158
- -------------------------------------------- --------- --------- --------- --------- ---------
Fixed charges:
Interest expense $ 155,108 $ 146,140 $ 123,439 $ 122,635 $ 131,346 $ 126,555
Other interest 4,677 1,782 360 600 660 400
Portion of rentals
representative of the
interest factor 4,214 2,878 3,143 4,187 5,150 5,555
- -------------------------------------------- --------- --------- --------- --------- ---------
Total $ 163,999 $ 150,800 $ 126,942 $ 127,422 $ 137,156 $ 132,510
- -------------------------------------------- --------- --------- --------- --------- ---------
Earnings available for
combined fixed charges
and preferred dividend
requirements $ 465,270 $ 428,341 $ 311,273 $ 400,772 $ 352,654 $ 309,668
DIVIDEND REQUIREMENT:
Fixed charges above $ 163,999 $ 150,800 $ 126,942 $ 127,422 $ 137,156 $ 132,510
Preferred dividend
requirements below 19,395 21,414 26,250 36,249 36,674 45,441
- -------------------------------------------- --------- --------- --------- --------- ---------
Total $ 183,394 $ 172,214 $ 153,192 $ 163,671 $ 173,830 $ 177,951
- -------------------------------------------- --------- --------- --------- --------- ---------
</TABLE>
2
<PAGE>
<TABLE>
<CAPTION>
12 Months
Ending Year Ended December 31,
September
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 2.54 2.49 2.03 2.45 2.03 1.74
COMPUTATION OF PREFERRED
DIVIDEND REQUIREMENTS:
(a) Pre-tax income $305,948 $ 279,323 $ 185,299 $ 273,490 $ 207,833 $ 176,815
(b) Income from continuing
operations $187,825 $ 169,612 $ 125,698 $ 167,351 $ 128,382 $ 79,312
(c) Ratio of (a) to (b) 1.6289 1.6468 1.4742 1.6342 1.6189 2.2294
(d) Preferred dividends $ 11,907 $ 13,003 $ 17,806 $ 22,181 $ 22,654 $ 20,383
Preferred dividend
requirements
[(d) multiplied by (c)] $ 19,395 $ 21,414 $ 26,250 $ 36,249 $ 36,674 $ 45,441
</TABLE>
3
<PAGE>
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<NAME> PUGET SOUND ENERGY
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<TOTAL-NET-UTILITY-PLANT> 3,528,443
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65,662
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<TOTAL-OPERATING-EXPENSES> 1,213,722
<OPERATING-INCOME-LOSS> 208,278
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<CASH-FLOW-OPERATIONS> 284,237
<EPS-BASIC> 1.38
<EPS-DILUTED> 1.38
</TABLE>
