UNITED STATES
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, 2003
OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from __________ to __________

	Exact name of registrant as specified	I.R.S.
	in its charter, state of incorporation,	Employer
Commission	address of principal executive offices,	Identification
File Number	telephone number	Numbers

1-16305	PUGET ENERGY, INC.	91-1969407
	A Washington Corporation.
	10885 N.E. 4^th Street, Suite 1200
	Bellevue, Washington 98004-5591
	(425) 454-6363

1-4393	PUGET SOUND ENERGY, INC.	91-0374630
	A Washington Corporation.
	10885 N.E. 4^th Street, Suite 1200
	Bellevue, Washington 98004-5591
	(425) 454-6363

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 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 ____

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes X No ____

As of September 30, 2003, (i) the number of shares of Puget Energy, Inc. (Puget Energy) common stock outstanding was 94,221,064 ($.01 par value) and (ii) all of the outstanding shares of Puget Sound Energy, Inc. (PSE) common stock were held by Puget Energy.

Table of Contents

Filing Format

Forward-Looking Statements

Part I.	Financial Information
Item 1.	Financial Statements

	Puget Energy, Inc.
	Consolidated Statements of Income - 3 months ended September 30, 2003 and 2002
	Consolidated Statements of Income - 9 months ended September 30, 2003 and 2002
	Consolidated Statements of Comprehensive Income - 3 months ended
	September 30, 2003 and 2002
	Consolidated Statements of Comprehensive Income - 9 months ended
	September 30, 2003 and 2002
	Consolidated Balance Sheets - September 30, 2003 and December 31, 2002
	Consolidated Statements of Cash Flows - 9 months ended
	September 30, 2003 and 2002

	Puget Sound Energy, Inc. (PSE)
	Consolidated Statements of Income - 3 months ended September 30, 2003 and 2002
	Consolidated Statements of Income - 9 months ended September 30, 2003 and 2002
	Consolidated Statements of Comprehensive Income - 3 months ended
	September 30, 2003 and 2002
	Consolidated Statements of Comprehensive Income - 9 months ended
	September 30, 2003 and 2002
	Consolidated Balance Sheets - September 30, 2003 and December 31, 2002
	Consolidated Statements of Cash Flows - 9 months ended
	September 30, 2003 and 2002
	Notes:
	Combined Notes to Consolidated Financial Statements

Item 2.	Management's Discussion and Analysis of Financial Condition
	and Results of Operations

Item 3.	Quantitative and Qualitative Disclosure About Market Risk

Item 4.	Controls and Procedures

Part II.	Other Information
Item 1.	Legal Proceedings
Item 6.	Exhibits and Reports on Form 8-K

Signature
Exhibit Index

Filing Format
This Quarterly Report on Form 10-Q is a combined quarterly report being filed separately by two different registrants, Puget Energy and PSE. Any references in this report to the “Company” are to Puget Energy and PSE collectively. PSE makes no representation as to the information contained in this report relating to Puget Energy and the subsidiaries of Puget Energy other than PSE and its subsidiaries.

FORWARD-LOOKING STATEMENTS
        Puget Energy, Inc. (Puget Energy) and Puget Sound Energy, Inc. (PSE) are including the following cautionary statements in this Form 10-Q to make applicable and to take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by or on behalf of Puget Energy or PSE. This report includes forward-looking statements, which are statements of expectations, beliefs, plans, objectives, assumptions of future events or performance. Words or phrases such as “anticipates,” “believes,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” “will likely result,” “will continue” or similar expressions identify forward-looking statements.
        Forward-looking statements involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed. Puget Energy’s and PSE’s expectations, beliefs and projections are expressed in good faith and are believed by Puget Energy and PSE, as applicable, to have a reasonable basis, including without limitation, management’s examination of historical operating trends, data contained in records and other data available from third parties, but there can be no assurance that Puget Energy’s and PSE’s expectations, beliefs or projections will be achieved or accomplished.
        In addition to other factors and matters discussed elsewhere in this report, some important factors that could cause actual results or outcomes for Puget Energy and PSE to differ materially from those discussed in forward-looking statements include:

Risks relating to the regulated utility business (PSE)

•

governmental policies and regulatory actions, including those of the Federal Energy Regulatory Commission (FERC) and the Washington Utilities and Transportation Commission (Washington Commission), with respect to allowed rates of return, financings, industry and rate structures, transmission and generation business structures within PSE, acquisition and disposal of assets and facilities, operation and construction of electric generating facilities, distribution and transmission facilities, licensing of hydro operations, recovery of other capital investments, recovery of power and gas costs, and present or prospective wholesale and retail competition;

•	financial difficulties of other energy companies and related events, which may affect the regulatory and legislative process in unpredictable ways and also adversely affect the availability of and access to capital and credit markets;

•	default by counterparties in the wholesale natural gas and electricity markets that owe PSE money or energy;

•	deterioration of liquidity in the forward markets in which PSE transacts hedges to manage its energy portfolio risks which can limit PSE’s ability to enter into forward contracts and, therefore, its ability to manage its portfolio risks;

•

the stability and liquidity of wholesale energy markets generally, including the requirements for PSE to post collateral to support its energy portfolio transactions and the effect of price controls by FERC on the availability and price of wholesale energy purchases and sales in the western United States;

•	the effect of wholesale market structures (including, but not limited to, new market design such as RTO West and Standard Market Design);

•	weather, which can have a potentially serious impact on PSE’s revenues and its ability to procure adequate supplies of gas, fuel or purchased power to serve its customers and on the cost of procuring such supplies;

•	hydroelectric conditions, which can have a potentially serious impact on electric capacity and PSE’s ability to generate electricity;

•	the amount of collection, if any, of PSE’s receivable from the California Independent System Operator (CAISO) and the amount of refunds found to be due from PSE to the CAISO or others;

•	industrial, commercial and residential growth and demographic patterns in the service territories of PSE;

•	general economic conditions in the Pacific Northwest;

•	the loss of significant customers or changes in the business of significant customers, which may result in changes in demand for PSE's services;

•	plant outages which can have an impact on PSE's expenses and its ability to procure adequate supplies to replace the lost energy;

•	the ability to re-license FERC hydro projects at a cost effective level;

Risks relating to the non-regulated, utility service business (InfrastruX Group, Inc.)

•	the failure of InfrastruX to service its obligations under its credit agreement, in which case Puget Energy, as guarantor, may be required to satisfy these obligations, which could have a negative impact on Puget Energy’s liquidity and access to capital;

•

the inability to generate internal growth at InfrastruX, which could be affected by, among other factors, InfrastruX’s ability to expand the range of services offered to customers, attract new customers, increase the number of projects performed for existing customers, hire and retain employees and open additional facilities;

•	the ability of InfrastruX to integrate acquired companies with existing operations without substantial costs, delays or other operational or financial problems, which involves a number of special risks;

•	the effect of competition in the industry in which InfrastruX competes, including from competitors that may have greater resources than InfrastruX, which may enable them to develop expertise, experience and resources to provide services that are superior in both price and quality;

•	the extent to which existing electric power and gas companies or prospective customers will continue to outsource services in the future, which may be impacted by, among other things, regional and general economic conditions in the markets InfrastruX serves;

•	delinquencies associated with the financial conditions of InfrastruX's customers;

•	the impact of any goodwill impairments on the results of operations of InfrastruX arising from its acquisitions, which could have a negative effect on the results of operations of Puget Energy;

•	the impact of adverse weather conditions that negatively affect operating results;

•	the ability to obtain adequate bonding coverage and the cost of such bonding;

Risks relating to both the regulated and non-regulated businesses

•	the impact of acts of terrorism or similar significant events, such as the attack on September 11, 2001;

•	the ability of Puget Energy, PSE and InfrastruX to access the capital markets to support requirements for working capital, construction costs and the repayment of maturing debt;

•	capital market conditions, including changes in the availability of capital or interest rate fluctuations;

•	changes in Puget Energy’s or PSE’s credit ratings, which may have an adverse impact on the availability and cost of capital for Puget Energy, PSE and InfrastruX;

•	legal and regulatory proceedings;

•	changes in, and compliance with, environmental and endangered species laws, regulations, decisions, and policies concerning the environment, natural resources, and fish and wildlife (including the Endangered Species Act );

•	employee workforce factors, including strikes, work stoppages, availability of qualified employees, or the loss of a key executive;

•	the ability to obtain and keep patent rights to generate revenue; and

•	the ability to obtain adequate insurance coverage and the cost of such insurance.

Any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by law, Puget Energy and PSE undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

PART I FINANCIAL INFORMATION
Item 1. Financial Statements

PUGET ENERGY, INC.
CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended September 30
(Thousands except per share amounts)
(Unaudited)

	2003			2002
Operating Revenues:
Electric	$	343,470		$	299,443
Gas		78,171			65,788
Non-utility construction services		93,142			92,373
Other		784			872

Total operating revenues		515,567			458,476

Operating Expenses:
Energy costs:
Purchased electricity		174,937			132,820
Purchased gas		35,469			31,126
Electric generation fuel		21,252			16,856
Residential Exchange		(32,894	)		(26,427	)
Unrealized (gain)/loss on derivative instruments		905			(335	)
Utility operations and maintenance		67,682			68,933
Other operations and maintenance		81,435			76,316
Depreciation and amortization		59,159			57,190
Conservation amortization		9,897			4,216
Taxes other than income taxes		43,176			40,928
Income taxes		160			(245	)

Total operating expenses		461,178			401,378

Operating Income		54,389			57,098
Other income, net of tax		2,663			230

Income Before Interest Charges and Minority Interest		57,052			57,328

Interest Charges:
Interest charges, net of AFUDC		44,845			48,439
Mandatorily redeemable securities interest expense		1,048			--

Total interest charges		45,893			48,439

Minority interest in earnings of consolidated subsidiary		156			377

Net Income		11,003			8,512
Less: preferred stock dividends accrual		1,118			1,940

Income for Common Stock	$	9,885		$	6,572

Basic common shares outstanding - weighted average		94,125			87,618
Diluted common shares outstanding - weighted average		94,635			87,975

Basic and diluted earnings per share	$	0.10		$	0.07

The accompanying notes are an integral part of the financial statements.

PUGET ENERGY, INC.
CONSOLIDATED STATEMENTS OF INCOME
For the Nine Months Ended September 30
(Thousands except per share amounts)
(Unaudited)

	2003			2002
Operating Revenues:
Electric	$	1,108,664		$	978,814
Gas		382,706			524,663
Non-utility construction services		256,162			229,256
Other		1,853			5,622

Total operating revenues		1,749,385			1,738,355

Operating Expenses:
Energy costs:
Purchased electricity		606,972			442,731
Purchased gas		179,795			324,444
Electric generation fuel		47,415			96,716
Residential Exchange		(122,550	)		(100,139	)
Unrealized (gain)/loss on derivative instruments		383			(12,083	)
Utility operations and maintenance		211,632			208,505
Other operations and maintenance		229,072			193,025
Depreciation and amortization		176,424			170,495
Conservation amortization		23,914			9,985
Taxes other than income taxes		147,787			159,843
Income taxes		36,358			34,332

Total operating expenses		1,537,202			1,527,854

Operating Income		212,183			210,501
Other income, net of tax		5,614			4,055

Income Before Interest Charges and Minority Interest		217,797			214,556

Interest charges:
Interest charges, net of AFUDC		138,491			147,518
Mandatorily redeemable securities interest expense		1,048			--

Total interest charges		139,539			147,518

Minority interest in earnings of consolidated subsidiary		106			679

Income Before Cumulative Effect of Accounting Change		78,152			66,359
Cumulative effect of implementation of an accounting change, net of tax		169			--

Net Income		77,983			66,359
Less: preferred stock dividends accrual		4,779			5,892

Income for Common Stock	$	73,204		$	60,467

Basic common shares outstanding - weighted average		93,930			87,388
Diluted common shares outstanding - weighted average		94,440			87,737

Basic earnings per share before cumulative effect of accounting change	$	0.78		$	0.69
Cumulative effect of accounting change		--			--

Basic earnings per share	$	0.78		$	0.69

Diluted earnings per share before cumulative effect of accounting change	$	0.77		$	0.69
Cumulative effect of accounting change		--			--

Diluted earnings per share	$	0.77		$	0.69

The accompanying notes are an integral part of the financial statements.

PUGET ENERGY, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Three Months Ended September 30
(Dollars in Thousands)
(Unaudited)

	2003			2002
Net Income	$	11,003		$	8,512

Other comprehensive income, net of tax:
Unrealized holding losses arising on marketable securities during the		--			(439	)
period
Reclassification adjustment for realized loss on marketable securities		30			--
included in net income
Foreign currency translation adjustment		3			154
Unrealized gains on derivative instruments during the		153			5,515
period
Reversal of unrealized gains on derivative instruments settled during the		(2,784	)		(1,309	)
period

Other comprehensive income (loss)		(2,598	)		3,921

Comprehensive Income	$	8,405		$	12,433

PUGET ENERGY, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Nine Months Ended September 30
(Dollars in Thousands)
(Unaudited)

	2003			2002
Net Income	$	77,983		$	66,359

Other comprehensive income, net of tax:
Unrealized holding losses arising on marketable securities during the		(45	)		(966	)
period
Reclassification adjustment for realized gains on marketable securities		(1,518	)		(724	)
included in net income
Foreign currency translation adjustment		65			38
Unrealized gains on derivative instruments during the period		4,212			3,413
Reversal of unrealized losses on derivative instruments settled during the		1,535			31,525
period

Other comprehensive income		4,249			33,286

Comprehensive Income	$	82,232		$	99,645

The accompanying notes are an integral part of the financial statements.

PUGET ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)

ASSETS

	September 30, 2003			December 31, 2002
Utility Plant: (at original cost, including construction work in progress of
$152,123 and $108,658 respectively)
Electric	$	4,254,837		$	4,229,352
Gas		1,714,071			1,645,865
Common		389,073			378,844
Less: Accumulated depreciation and amortization		(2,406,507	)		(2,337,832	)

Net utility plant		3,951,474			3,916,229

Other Property and Investments:
Goodwill, net		134,692			125,555
Intangibles, net		17,813			18,652
Non-utility		91,432			80,855
Other assets		161,297			153,068

Total other property and investments		405,234			378,130

Current Assets:
Cash		28,086			176,669
Restricted cash		3,811			18,871
Accounts receivable, net		238,465			279,623
Unbilled revenue		69,459			112,115
Materials and supplies, at average cost		91,070			70,402
Current portion of unrealized gain on derivative instruments		3,957			3,741
Prepayments and other		25,076			11,323

Total current assets		459,924			672,744

Other Long-Term Assets:
Regulatory asset for deferred income taxes		158,655			167,058
Regulatory asset for PURPA contract buyout costs		233,558			243,584
Unrealized gain on derivative instruments		8,910			9,870
Power cost adjustment mechanism		4,129			--
Other		309,547			269,876

Total other long-term assets		714,799			690,388

Total Assets	$	5,531,431		$	5,657,491

The accompanying notes are an integral part of the financial statements.

PUGET ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)

CAPITALIZATION AND LIABILITIES

	September 30, 2003		December 31, 2002
Capitalization:
Common shareholders' investment:
Common stock $0.01 par value, 250,000,000 shares authorized, 94,221,064
and 93,642,659 shares outstanding, respectively	$	942	$	936
Additional paid-in capital		1,496,872		1,484,615
Earnings reinvested in the business		38,435		36,396
Accumulated other comprehensive income		6,089		1,840
Preferred stock not subject to mandatory redemption		60,000		60,000

Total shareholders' equity		1,602,338		1,583,787

Redeemable securities and long term debt:
Preferred stock subject to mandatory redemption		1,889		43,162
Corporation obligated, mandatorily redeemable preferred securities of
subsidiary trust holding solely junior subordinated debentures of the corporation		280,250		300,000
Long-term debt		2,006,889		2,149,733

Total redeemable securities and long term debt		2,289,028		2,492,895

Total capitalization		3,891,366		4,076,682

Minority interest in equity of a consolidated subsidiary		11,616		10,629

Current Liabilities:
Accounts payable		162,188		205,619
Short-term debt		26,513		47,295
Current maturities of long-term debt		247,278		73,206
Purchased gas liability		6,777		83,811
Accrued expenses:
Taxes		43,712		62,562
Salaries and wages		11,751		11,441
Interest		43,110		37,942
Other		50,172		50,171

Total current liabilities		591,501		572,047

Long-Term Liabilities:
Deferred income taxes		767,611		730,675
Other deferred credits		269,337		267,458

Total long-term liabilities		1,036,948		998,133

Total Capitalization and Liabilities	$	5,531,431	$	5,657,491

The accompanying notes are an integral part of the financial statements.

PUGET ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30
(Dollars in Thousands)
(Unaudited)

	2003			2002
Operating Activities:
Net Income	$	77,983		$	66,359
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization		176,424			170,495
Deferred federal and state income taxes and tax credits - net		45,339			102,073
Net unrealized (gain)/loss on derivative instruments		383			(12,083	)
Cash collateral received from energy supplier		5,887			13,990
Gain on sale of securities		(2,889	)		--
Other		(13,654	)		31,487
Change in certain current assets and current liabilities:
Accounts receivable and unbilled revenue		88,759			134,634
Materials and supplies		(20,668	)		21,538
Prepayments and other		(13,614	)		(5,058	)
Purchase gas receivable/liability		(77,034	)		135,812
Accounts payable		(45,704	)		(19,298	)
Taxes payable		(20,334	)		(71,902	)
Accrued expenses and other		5,237			(1,304	)

Net Cash Provided by Operating Activities		206,115			566,743

Investing Activities:
Construction and capital expenditures-excluding equity AFUDC		(214,295	)		(192,177	)
Additions to energy conservation program		(11,858	)		(7,708	)
Acquisitions by InfrastruX, net of cash acquired		(10,590	)		(39,807	)
Restricted cash		18,832			(20,872	)
Cash received from sale of securities		3,161			--
Other		2,505			(9,635	)

Net Cash Used by Investing Activities		(212,245	)		(270,199	)

Financing Activities:
Change in short-term debt - net		(20,782	)		(210,246	)
Dividends paid		(66,273	)		(76,730	)
Issuance of common stock		2,607			--
Redemption of mandatorily redeemable preferred stock		(41,273	)		(7,500	)
Redemption of trust preferred securities		(19,750	)		--
Issuance of bonds and long-term debt		320,459			94,197
Redemption of bonds and long-term debt		(306,446	)		(92,000	)
Issuance costs of bonds and other		(10,995	)		(62	)

Net Cash Used by Financing Activities		(142,453	)		(292,341	)

Net Increase (Decrease) in Cash		(148,583	)		4,203
Cash at Beginning of Year		176,669			92,356

Cash at End of Period	$	28,086		$	96,559

Supplemental Cash Flow Information:
Cash payments for:
Interest (net of capitalized interest)	$	136,205		$	143,882
Income taxes		(3,777	)		(3,818	)

The accompanying notes are an integral part of the financial statements.

PUGET SOUND ENERGY, INC.
CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended September 30
(Dollars in Thousands)
(Unaudited)

	2003			2002
Operating Revenues:
Electric	$	343,470		$	299,443
Gas		78,171			65,788
Other		784			872

Total operating revenues		422,425			366,103

Operating Expenses:
Energy costs:
Purchased electricity		174,937			132,820
Purchased gas		35,469			31,126
Electric generation fuel		21,252			16,856
Residential Exchange		(32,894	)		(26,427	)
Unrealized (gain)/loss on derivative instruments		905			(335	)
Utility operations and maintenance		67,682			68,933
Other operations and maintenance		240			287
Depreciation and amortization		54,942			53,406
Conservation amortization		9,897			4,216
Taxes other than income taxes		40,228			37,586
Income taxes		(1,279	)		(3,732	)

Total operating expenses		371,379			314,736

Operating Income		51,046			51,367
Other income, net of tax		2,620			210

Income Before Interest Charges		53,666			51,577

Interest charges:
Interest charges, net of AFUDC		43,130			46,876
Mandatorily redeemable securities interest expense		1,048			--

Total interest charges		44,178			46,876

Net Income		9,488			4,701
Less: preferred stock dividends accrual		1,118			1,940

Income for Common Stock	$	8,370		$	2,761

The accompanying notes are an integral part of the financial statements.

PUGET SOUND ENERGY, INC.
CONSOLIDATED STATEMENTS OF INCOME
For the Nine Months Ended September 30
(Dollars in Thousands)
(Unaudited)

	2003			2002
Operating Revenues:
Electric	$	1,108,664		$	978,814
Gas		382,706			524,663
Other		1,853			5,622

Total operating revenues		1,493,223			1,509,099

Operating Expenses:
Energy costs:
Purchased electricity		606,972			442,731
Purchased gas		179,795			324,444
Electric generation fuel		47,415			96,716
Residential Exchange		(122,550	)		(100,139	)
Unrealized (gain)/loss on derivative instruments		383			(12,083	)
Utility operations and maintenance		211,632			208,505
Other operations and maintenance		761			1,102
Depreciation and amortization		164,248			161,187
Conservation amortization		23,914			9,985
Taxes other than income taxes		138,038			149,817
Income taxes		35,515			28,010

Total operating expenses		1,286,123			1,310,275

Operating Income		207,100			198,824
Other income, net of tax		5,620			3,974

Income Before Interest Charges		212,720			202,798

Interest charges:
Interest charges, net of AFUDC		134,301			143,559
Mandatorily redeemable securities interest expense		1,048			--

Total interest charges		135,349			143,559

Income Before Cumulative Effect of Accounting Change		77,371			59,239
Cumulative effect of implementation of an accounting change, net of tax		169			--

Net Income		77,202			59,239
Less: preferred stock dividends accrual		4,779			5,892

Income for Common Stock	$	72,423		$	53,347

The accompanying notes are an integral part of the financial statements.

PUGET SOUND ENERGY, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Three Months Ended September 30
(Dollars in Thousands)
(Unaudited)

	2003			2002
Net Income	$	9,488		$	4,701

Other comprehensive income, net of tax:
Unrealized holding losses on marketable securities arising		--			(439	)
during the period
Reclassification adjustment for realized loss on marketable		30			--
securities included in net income
Unrealized gains on derivative instruments during the period		153			5,515
Reversal of unrealized gains on derivative instruments		(2,784	)		(1,309	)
settled during the period

Other comprehensive income (loss)		(2,601	)		3,767

Comprehensive Income	$	6,887		$	8,468

PUGET SOUND ENERGY, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Nine Months Ended September 30
(Dollars in Thousands)
(Unaudited)

	2003			2002
Net Income	$	77,202		$	59,239

Other comprehensive income, net of tax:
Unrealized holding losses on marketable securities arising		(45	)		(966	)
during the period
Reclassification adjustment for realized gains on marketable		(1,518	)		(724	)
securities included in net income
Unrealized gains on derivative instruments during the period		4,212			3,413
Reversal of unrealized losses on derivative instruments settled during the		1,535			31,525
period

Other comprehensive income		4,184			33,248

Comprehensive Income	$	81,386		$	92,487

The accompanying notes are an integral part of the financial statements.

PUGET SOUND ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)

ASSETS

	September 30, 2003			December 31, 2002
Utility Plant: (at original cost, including construction work in progress of
$152,123 and $108,658 respectively)
Electric	$	4,254,837		$	4,229,352
Gas		1,714,071			1,645,865
Common		389,073			378,844
Less: Accumulated depreciation and amortization		(2,406,507	)		(2,337,832	)

Net utility plant		3,951,474			3,916,229

Other Property and Investments		163,366			154,757

Current Assets:
Cash		17,943			161,475
Restricted cash		3,811			18,871
Accounts receivable, net		157,570			208,702
Unbilled revenue		69,459			112,115
Materials and supplies, at average cost		83,631			63,563
Current portion of unrealized gain on derivative instruments		3,957			3,741
Prepayments and other		16,979			8,907

Total current assets		353,350			577,374

Other Long-Term Assets:
Regulatory asset for deferred income taxes		158,655			167,058
Regulatory asset for PURPA contract buyout costs		233,558			243,584
Unrealized gain on derivative instruments		8,910			9,870
Power cost adjustment mechanism		4,129			--
Other		309,460			269,876

Total other long-term assets		714,712			690,388

Total Assets	$	5,182,902		$	5,338,748

The accompanying notes are an integral part of the financial statements.

PUGET SOUND ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)

CAPITALIZATION AND LIABILITIES

	September 30, 2003		December 31, 2002
Capitalization:
Common shareholders' investment:
Common stock, $10 stated value, 150,000,000 shares authorized, 85,903,791
shares outstanding	$	859,038	$	859,038
Additional paid-in capital		500,765		498,335
Earnings reinvested in the business		77,901		66,971
Accumulated other comprehensive income		5,961		1,777
Preferred stock not subject to mandatory redemption		60,000		60,000

Total shareholders' equity		1,503,665		1,486,121

Redeemable securities and long term debt:
Preferred stock subject to mandatory redemption		1,889		43,162
Corporation obligated, mandatorily redeemable preferred securities of
subsidiary trust holding solely junior subordinated debentures of the corporation		280,250		300,000
Long-term debt		2,000,343		2,021,832

Total redeemable securities and long term debt		2,282,482		2,364,994

Total capitalization		3,786,147		3,851,115

Current Liabilities:
Accounts payable		149,204		193,602
Short-term debt		9,330		30,340
Current maturities of long-term debt		110,468		72,000
Purchased gas liability		6,777		83,811
Accrued expenses:
Taxes		47,274		64,433
Salaries and wages		11,751		11,441
Interest		43,110		37,942
Other		21,558		27,866

Total current liabilities		399,472		521,435

Long-Term Liabilities:
Deferred income taxes		743,877		715,579
Other deferred credits		253,406		250,619

Total long-term liabilities		997,283		966,198

Total Capitalization and Liabilities	$	5,182,902	$	5,338,748

The accompanying notes are an integral part of the financial statements.

PUGET SOUND ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30
(Dollars in Thousands)
(Unaudited)

	2003			2002
Operating Activities:
Net Income	$	77,202		$	59,239
Adjustments to reconcile net income
to net cash provided by operating activities:
Depreciation and amortization		164,248			161,187
Deferred federal income taxes and tax credits - net		36,701			95,509
Net unrealized (gain)/loss on derivative instruments		383			(12,083	)
Cash collateral received from energy supplier		5,887			13,990
Gain on sale of securities		(2,889	)		--
Other		(11,840	)		25,222
Change in certain current assets and current liabilities:
Accounts receivable and unbilled revenue		93,788			147,249
Materials and supplies		(20,068	)		19,642
Prepayments and other		(8,072	)		(7,314	)
Purchased gas receivable/liability		(77,034	)		135,812
Accounts payable		(44,398	)		(14,607	)
Taxes payable		(17,159	)		(69,263	)
Accrued expenses and other		940			(1,800	)

Net Cash Provided by Operating Activities		197,689			552,783

Investing Activities:
Construction expenditures - excluding equity AFUDC		(203,941	)		(168,744	)
Additions to energy conservation program		(11,858	)		(7,708	)
Restricted cash		18,832			(20,872	)
Cash received from sale of securities		3,161			--
Other		3,955			(7,987	)

Net Cash Used by Investing Activities		(189,851	)		(205,311	)

Financing Activities:
Change in short-term debt - net		(21,010	)		(216,954	)
Dividends paid		(66,273	)		(76,730	)
Issuance of bonds		311,860			--
Redemption of mandatorily redeemable preferred stock		(41,273	)		(7,500	)
Redemption of trust preferred securities		(19,750	)		--
Redemption of bonds		(306,446	)		(52,000	)
Issuance cost of bonds and other		(8,478	)		(108	)

Net Cash Used by Financing Activities		(151,370	)		(353,292	)

Net Decrease in Cash		(143,532	)		(5,820	)
Cash at Beginning of Year		161,475			82,708

Cash at End of Period	$	17,943		$	76,888

Supplemental Cash Flow Information:
Cash payments for:
Interest (net of capitalized interest)	$	132,026		$	139,574
Income taxes (net of refunds)		(696	)		(4,306	)

The accompanying notes are an integral part of the financial statements.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1)

Summary of Consolidation Policy

BASIS OF PRESENTATION
        Puget Energy is an exempt public utility holding company under the Public Utility Holding Company Act of 1935. Puget Energy owns Puget Sound Energy (PSE) and is a majority owner of InfrastruX Group, Inc. (InfrastruX), a Washington corporation.
        The consolidated financial statements of Puget Energy include the accounts of Puget Energy and its subsidiaries, PSE and InfrastruX. Puget Energy holds all the common shares of PSE and holds a majority interest in InfrastruX. The results of PSE and InfrastruX are presented on a consolidated basis. PSE’s consolidated financial statements include the accounts of PSE and its subsidiaries. Puget Energy and PSE are collectively referred to herein as “the Company”. The consolidated financial statements are presented after elimination of all significant intercompany items and transactions. Minority interests of InfrastruX’s operating results are reflected in Puget Energy’s consolidated financial statements. 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 respective opinions of the managements of Puget Energy and PSE, 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 audited financial statements (and the Combined Notes thereto) included in the combined Puget Energy and PSE annual report on Form 10-K for the year ended December 31, 2002, which is available at the Securities and Exchange Commission website at www.sec.gov or at Puget Energy’s website at www.pse.com.

(2)

Earnings per Common Share (Puget Energy Only)

Puget Energy’s basic earnings per common share have been computed based on weighted average common shares outstanding of 94,125,000 and 93,930,000 for the three and nine months ended September 30, 2003, respectively, and 87,618,000 and 87,388,000 for the three and nine months ended September 30, 2002, respectively.
Puget Energy’s diluted earnings per common share have been computed based on weighted average common shares outstanding of 94,635,000 and 94,440,000 for the three and nine months ended September 30, 2003, respectively, and 87,975,000 and 87,737,000 for the three and nine months ended September 30, 2002, respectively. These shares include the dilutive effect of securities related to employee and director equity plans.

(3)

Segment Information (Puget Energy Only)

Puget Energy operates in primarily two business segments: Regulated Utility Operations, or PSE, and Utility Construction Services, or InfrastruX. Puget Energy’s regulated utility operation generates, purchases, transports and sells electricity, and purchases, transports and sells natural gas. The service territory of PSE covers approximately 6,000 square miles in Washington State. InfrastruX specializes in contracting services to other gas and electric utilities located primarily in the Midwest, Texas/South Central and the Eastern United States.
The Other business segment includes two PSE subsidiaries, a real estate investment and development company and an owner of a small hydro electric generating facility designated as an exempt wholesale generator by FERC. The Other business segment also includes the expenses of Puget Energy, the public utility holding company. Reconciling items between segments are not material.

Financial data for business segments are as follows:

(Dollars in Thousands) Three Months Ended September 30, 2003	PSE			InfrastruX		Other			Total
Revenues	$	421,641		$	93,142	$	784		$	515,567
Depreciation and amortization		54,881			4,216		62			59,159
Income tax		(1,260	)		1,492		(72	)		160
Operating income		51,081			3,390		(82	)		54,389
Interest charges		44,178			1,662		53			45,893
Net income before minority interest		9,396			1,772		(9	)		11,159
Minority interest		--			156		--			156
Net income		9,396			1,616		(9	)		11,003
Goodwill, net		--			134,692		--			134,692
Total assets		5,104,096			348,998		78,337			5,531,431

Three Months Ended September 30, 2002	PSE			InfrastruX		Other		Total
Revenues	$	365,231		$	92,373	$	872	$	458,476
Depreciation and amortization		53,351			3,784		55		57,190
Income tax		(3,862	)		3,564		53		(245	)
Operating income		51,002			5,871		225		57,098
Interest charges		46,876			1,563		--		48,439
Net income before minority interest		4,335			4,329		225		8,889
Minority interest		--			377		--		377
Net income		4,335			3,952		225		8,512

Nine Months Ended September 30, 2003	PSE		InfrastruX		Other			Total
Revenues	$	1,491,370	$	256,162	$	1,853		$	1,749,385
Depreciation and amortization		164,074		12,176		174			176,424
Income tax		35,528		964		(134	)		36,358
Operating income		206,856		5,236		91			212,183
Interest charges		135,349		4,119		71			139,539
Net income before minority interest		74,939		1,113		2,037			78,089
Minority interest		--		106		--			106
Net income		74,939		1,007		2,037			77,983

Nine Months Ended September 30, 2002	PSE		InfrastruX		Other		Total
Revenues	$	1,503,477	$	229,256	$	5,622	$	1,738,355
Depreciation and amortization		161,024		9,308		163		170,495
Income tax		26,102		6,514		1,716		34,332
Operating income		196,021		12,034		2,446		210,501
Interest charges		143,558		3,960		--		147,518
Net income before minority interest		56,616		8,155		2,267		67,038
Minority interest		--		679		--		679
Net income		56,616		7,476		2,267		66,359

At December 31, 2002	PSE		InfrastruX		Other		Total
Goodwill, net	$	--	$	125,555	$	--	$	125,555
Total asset		5,208,487		319,248		129,756		5,657,491

(4)

Accounting for Derivative Instruments and Hedging Activities

        The Company has adopted Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended by SFAS No. 138 and SFAS No. 149. SFAS No. 133 requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair value. The Company enters into both physical and financial contracts to manage its energy resource portfolio including forward physical and financial contracts, option contracts and swaps. The majority of these contracts qualify for the normal purchase and normal sale exception.
        During the three months ended September 30, 2003 the Company recorded a decrease in earnings for the change in the market value of derivative instruments not meeting cash flow hedge criteria of approximately $0.9 million pre-tax ($0.6 million after-tax) compared to an increase of $0.3 million pre-tax ($0.2 million after-tax) for the three months ended September 30, 2002. During the nine months ended September 30, 2003 the Company recorded a decrease in earnings of approximately $0.4 million pre-tax ($0.2 after-tax) compared to an increase of $12.1 million pre-tax ($7.8 million after-tax) for the nine months ended September 30, 2002. The $12.1 million pre-tax gain in 2002 primarily represented the reversal of unrealized losses on gas hedge contracts that were de-designated in the fourth quarter of 2001 and the reversal of the mark-to-market unrealized loss on physical electric contracts at December 31, 2001 that were settled in 2002.
        The Company has two gas supply contracts outstanding with a counterparty whose senior unsecured debt ratings are currently below investment grade. The purpose of the contracts is to manage the fuel supply costs of the Company’s electric generating portfolio. The first contract is a fixed for floating price natural gas swap contract for which the Company has collected a collateral deposit in the amount of $27.3 million from the counterparty to guarantee performance. The financial contract will expire in June 2008 and is accounted for as a cash flow hedge under SFAS No. 133. The second is a physical gas supply contract expiring in December 2008, which has been designated as a normal purchase under SFAS No. 133. The counterparty has continuously performed on both contracts since the contracts were entered into in 2000 and the Company believes it is probable that the counterparty will continue to perform. The Company will continue to monitor the performance of the counterparty.
        In addition, the Company has adopted SFAS No. 149, “Amendment on Statement 133 on Derivative Instruments and Hedging Activities,” which is effective for all contracts entered into or modified after June 30, 2003 except for certain hedging relationships designated after June 30, 2003. SFAS No. 149 clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in contracts and for hedging activities under SFAS No. 133. The Company implemented SFAS 149 in the third quarter of 2003 with no significant impact on the financial statements.

(5)

Intangibles (Puget Energy Only)

Identifiable intangible assets acquired as a result of acquisitions of InfrastruX companies are amortized over the expected useful lives of the assets, which range from five to 20 years. During the nine months ended September 30, 2003 a total of $0.5 million was added to intangible assets as a result of an acquisition by InfrastruX during the second quarter of 2003. InfrastruX assigned $0.2 million to contractual customer relationships with an amortization period of approximately eight years and $0.3 million to covenant not to compete with an amortization period of five years. The total weighted average amortization period for the 2003 additions is approximately six years. Identifiable intangible assets are as follows:


At September 30, 2003 (Dollars in thousands)	Gross Intangibles		Accumulated Amortization		Net Intangibles
Covenant not to compete	$	4,178	$	1,691	$	2,487
Developed technology		14,190		2,234		11,956
Contractual customer relationships		3,242		656		2,586
Patents		853		69		784

Total	$	22,463	$	4,650	$	17,813


At December 31, 2002 (Dollars in thousands)	Gross Intangibles		Accumulated Amortization		Net Intangibles
Covenant not to compete	$	3,908	$	1,105	$	2,803
Developed technology		14,190		1,744		12,446
Contractual customer relationships		3,042		383		2,659
Patents		793		49		744

Total	$	21,933	$	3,281	$	18,652

The identifiable intangible asset amortization expense for the three and nine months ended September 30, 2003 was $0.4 million and $1.4 million, respectively, compared to $0.5 million and $1.2 million for the same periods of 2002. The identifiable intangible assets amortization for future periods based on the current acquisitions will be:

(Dollars in thousands)			2003			2004			2005			2006			2007			2008
Future Intangible Amortization			$	547		$	1,976		$	1,960		$	1,631		$	1,248		$	1,174

(6)

Asset Retirement Obligation

        On January 1, 2003 the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost is capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. The Company recorded an after-tax charge to income of $0.2 million in the first quarter of 2003 for the cumulative effect of the accounting change.
        The Company identified various asset retirement obligations at January 1, 2003, which were included in the cumulative effect of the accounting change. The Company has an obligation (1) to dismantle two leased electric generation turbine units and deliver the turbines to the nearest railhead at the termination of the lease in 2009; (2) to remove certain structures as a result of re-negotiations with the Department of Natural Resources of a now expired lease; (3) to replace or line all cast iron pipes in its service territory by 2007 as a result of a 1992 Washington Commission order; and (4) to restore ash holding ponds at a jointly-owned coal-fired electric generating facility in Montana.
        The following table describes all changes to the Company’s asset retirement obligation liability during 2003:

(Dollars in thousands) At September 30, 2003	Amount
Asset retirement obligation at December 31, 2002	$	--
Liability recognized in transition		3,592
Liability settled in the period		(255	)
Accretion expense		67

Asset retirement obligation at September 30, 2003	$	3,404

The pro forma asset retirement obligation liability balances as if SFAS No. 143 had been adopted on January 1, 1999 (rather than January 1, 2003) are as follows:

(Dollars in thousands)
Pro forma amounts of liability for asset retirement obligation at December 31, 1999	$	3,315
Pro forma amounts of liability for asset retirement obligation at December 31, 2000		3,405
Pro forma amounts of liability for asset retirement obligation at December 31, 2001		3,497
Pro forma amounts of liability for asset retirement obligation at December 31, 2002		3,592

The pro forma income statement effect as if SFAS No. 143 had been adopted on January 1, 1999 (rather than January 1, 2003) is as follows:

	Three Months Ended September 30					Nine Months Ended September 30
(Dollars in thousands, except per share)	2003		2002			2003		2002
Income for common stock, as reported	$	9,885	$	6,572		$	73,204	$	60,467
Add: FAS 143 transition adjustment, net of tax		--		--			169		--
Less: Pro forma accretion expense, net of tax		--		(16	)		--		(47	)

Pro forma income for common stock	$	9,885	$	6,556		$	73,373	$	60,420

Earnings per share:
Basic as reported	$	0.10	$	0.07		$	0.78	$	0.69
Diluted as reported	$	0.10	$	0.07		$	0.77	$	0.69
Basic pro forma	$	0.10	$	0.07		$	0.78	$	0.69
Diluted pro forma	$	0.10	$	0.07		$	0.77	$	0.69

(7)

Stock Compensation (Puget Energy only)

The Company has various stock compensation plans which, as allowed by SFAS No. 123, “Accounting for Stock-Based Compensation”, are accounted for in accordance with APB No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. The exercise price of stock option grants outstanding was the market value of the stock on the date of grant, so no compensation expense was recorded in the income statement for the options. There was, however, compensation expense related to other stock compensation plans. Had the Company used the fair value method of accounting specified by SFAS No. 123 net income and earnings per share would have been as follows:

	Three Months Ended September 30						Nine Months Ended September 30
(Dollar in thousands, except per share)	2003			2002			2003			2002
Income for common stock, as reported	$	9,885		$	6,572		$	73,204		$	60,467
Add: Total stock-based employee compensation expense		421			2,642			2,931			2,923
included in net income, net of tax
Less: Total stock-based employee compensation expense per		(680	)		(778	)		(2,571	)		(2,159	)
the fair value method of SFAS 123, net of tax

Pro forma income for common stock	$	9,626		$	8,436		$	73,564		$	61,231

Earnings per share:
Basic as reported	$	0.10		$	0.07		$	0.78		$	0.69
Diluted as reported	$	0.10		$	0.07		$	0.77		$	0.69
Basic pro forma	$	0.10		$	0.10		$	0.78		$	0.70
Diluted pro forma	$	0.10		$	0.10		$	0.78		$	0.70

(8)

New Accounting Pronouncements

        In January 2003, the Financial Accounting Standards Board (FASB) issued Interpretation No. 46 – “Consolidation of Variable Interest Entities” (FIN 46). FIN 46 clarifies the application of Accounting Research Bulletin No. 51 – “Consolidated Financial Statements” to certain entities in which equity investors do not have controlling interest or sufficient equity at risk for the entity to finance its activities without additional financial support. This Interpretation requires that if a business entity has a controlling financial interest in a variable interest entity, the financial statements must be included in the consolidated financial statements of the business entity. The adoption of this Interpretation for all interests in variable interest entities created after January 31, 2003 was effective on that date. For variable interest entities created before February 1, 2003, it is effective with the first fiscal year or interim period beginning after December 15, 2003 as amended by the FASB in September 2003. The Company has evaluated its contractual arrangements and determined PSE’s 1995 conservation trust off-balance sheet financing transaction meets this guidance. This transaction was consolidated in the third quarter of 2003. As a result, revenues increased $3.9 million while conservation amortization and interest expense increased by the corresponding amount with no impact on earnings. At September 30, 2003, the balance sheet assets and liabilities have been increased by $8.0 million.
        In May 2003, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 150 – “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity”. SFAS 150 establishes the requirements for classifying and measuring as liabilities certain financial instruments that embody obligations to redeem the financial instrument by the issuer. The adoption of SFAS 150 is effective with the first fiscal year or interim period beginning after June 15, 2003, however, on November 5, 2003 FASB deferred for an indefinite period certain mandatorily redeemable noncontrolling interests associated with finite-lived subsidiaries. The Comapny does not have any noncontrolling interests in subsidiaries and is therefore, not affected by the deferral. Prior periods will not be restated for the new presentation.
        SFAS 150 requires the Company to classify its mandatorily redeemable preferred stock and the corporation obligated, mandatorily redeemable preferred securities of a subsidiary trust holding solely junior subordinated debentures of the corporation (trust preferred securities) as liabilities. As a result, the corresponding dividends on the mandatorily redeemable preferred stock are classified as interest expense on the income statement with no impact on income for common stock. The Company previously classified the dividends associated with the trust preferred securities as interest expense.

(9)

Other

        Effective April 10, 2003 and October 1, 2003, the Washington Commission approved increases in the Purchased Gas Adjustment (PGA) gas rates of approximately $103.6 million annually, or 20.1%, and $78.8 million annually, or 13.3%, respectively. The PGA mechanism passes through to customers increases or decreases in the gas supply portion of the natural gas service rates based upon changes in gas prices. PSE’s gas margin and net income are not affected by the changes in the PGA rates.
        PSE has minority ownership interests in two venture capital funds established as limited liability corporations that seek long-term capital appreciation by making capital investments in energy sector related businesses. The Company’s investment in these two venture capital funds totaled $10.1 million at September 30, 2003, recorded at the Company’s original cost. The managing members of the limited liability corporations have sole discretion over fund management and investment decisions of both funds. Although the Company is not aware of any significant matters that would impair the long-term value of its investments, the Emerging Issues Task Force of the Financial Accounting Standards Board is currently reviewing the definition of what constitutes an other-than temporary impairment and its application to certain investments recorded at cost. Under the terms of the limited liability corporation agreements establishing the funds, one fund will continue through December 31, 2003 and the other through December 31, 2007. The Company’s original cost in the fund that will terminate on December 31, 2003, was $2.1 million at September 30, 2003, or approximately the amount the Company believes it will receive in distributions from the fund in the fourth quarter of 2003. The book value of the Company’s members capital account in the second fund as reported by the fund manager is below the Company’s recorded original cost of the investment. The Company’s original cost in the second fund was $8.0 million at September 30, 2003 and the Company has a future funding obligation of $0.6 million. The fund manager continues to report that the Company’s original cost is within the projected range of the future anticipated fund value.
        PSE and Western Energy Company, the supplier of coal to PSE’s Colstrip power plants, are engaged in a dispute and binding arbitration process concerning the price of coal that PSE will pay under the contract for Colstrip Units 1 & 2 through the end of the contract in 2009. This arbitration is contemplated as a price adjustment mechanism in that contract. The parties are over $1 per ton apart on their view as to the proper price for coal under that contract, and the arbitration would resolve that question in the second quarter of 2004. Any price adjustment could be retroactive to July 30, 2001 and would apply through the rest of the term. A $1 per ton increase or decrease in the price of coal would have a corresponding effect on PSE’s power costs of approximately $1.4 million annually and if the price were retroactive to July 30, 2001, the corresponding effect on power costs would be $3.2 million. Fuel supply costs for electric generation after July 1, 2002 are part of PSE’s power cost adjustment mechanism.
        In October 2003, PSE received notice from Western Energy Company that the Montana Department of Revenue is alleging underpayment of royalties on coal purchased by PSE from Western Energy Company from 1997 to 2000. PSE used the coal as fuel for its Colstrip Units 3 & 4 generating plants. The dispute is likely to lead to a more formal process or litigation to review those purchases and to determine whether PSE may owe more royalties, taxes or penalties. The Montana Department of Revenue seeks a payment of approximately $1.1 million plus applicable Montana State taxes on such payments. PSE will defend this claim vigorously. PSE cannot predict the outcome of this issue at this early date.
        On October 24, 2003, PSE filed a power cost only rate case for an increase in its electric rates related to higher power costs and the proposed investment in a 275 MW power generating plant. PSE intends to acquire a 49.85% interest in the power generating plant. The acquisition and power cost only rate case is subject to regulatory approval from the Washington Commission. The proposed rate increase of 4.7% or $64.4 million annually, if approved, would go into effect in April 2004 after a five month regulatory review.
        In 2003 the Colville Confederated Tribes presented a claim to Douglas County PUD based upon allegedly due past annual charges for the Wells Hydroelectric Project for the use of Colville tribal lands. The Tribes claimed that annual charges would also be due for periods into the future. Since April of 2003, Douglas County PUD and Colville representatives have discussed settlement of this issue. PSE purchases 31.3% of the power generated by the Wells Project. A settlement of this claim could affect the amount of energy PSE receives under the terms of PSE’s purchased electricity contract or the price of the output of the Wells Hydroelectric Project purchased by PSE.
        The White River Hydroelectric Generation Project (the Project) was built in 1911 by PSE and has been in continuous operation ever since. The Project generates electricity to serve PSE’s retail electric customers with an annual average output of approximately 35 megawatts. In 1983, the Company applied for an original FERC License for this Project. In December of 1997, FERC issued a proposed license that was appealed by the Company and various natural resource agencies. The Company appealed the license because it contained terms and conditions that would render ongoing operations of the Project uneconomic relative to alternative resources. In 1998, 2001 and in 2003 FERC granted a stay of the license order (and related appeals) to afford interested parties the opportunity for settlement negotiations. This stay expires in January of 2004. If settlement has not been reached by the end of the stay, in order to keep the Project in operation the Company would likely be required to implement the license order pending FERC’s disposition of the Company’s appeal. Implementation of the license order would require the Company to make capital expenditures and incur annual operating costs that would make the Project uneconomic. The Company has concluded that it is unlikely that a settlement addressing the deficiencies of the 1997 FERC license will be reached before the stay expires, and anticipates advising FERC in January that it intends to withdraw its license application and retire the Project. To this end, the Company is negotiating with a consortium of municipalities interested in acquiring the Project as a source for a municipal water supply. The Company is also discussing an interim “non-power” operations agreement with the U.S. Army Corps of Engineers. This interim agreement would address the Corps’ interest in keeping the Project’s diversion dam in operation and thereby facilitate the Corps’ ongoing responsibilities to provide fish passage for the Corps’ upstream flood control project (Mud Mountain Dam). Keeping the Project in operation is also a matter of importance to the surrounding community that wants to preserve the reservoir for financial, recreational and aesthetic purposes. The outcome of these various negotiations and discussions is uncertain at this time, as is the magnitude of any financial impact on the Company associated therewith. However, in any event, it is unlikely that the Project will be in service as a generation resource of the Company after January of 2004. As a result, PSE will petition the Washington Commission for an accounting order in the fourth quarter of 2003. This petition will request authorization for the appropriate accounting and rate making disposition of this Project to be retired. At September 30, 2003, the White River Project net book value totals $69.0 million, which includes $47.6 million of net utility plant, $15.0 million of capitalized FERC licensing costs and $6.4 million of costs related to construction work in progress.

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion of the Company’s financial condition and results of operations contains forward-looking statements that involve risks and uncertainties, such as statements of the Company’s plans, objectives, expectations and intentions. Words such as “anticipate,” “believe,” “expect,” “future” and “intend” and similar expressions are used to identify forward-looking statements. However, these words are not the exclusive means of identifying such statements. In addition, any statements that refer to expectations, projections or other characterizations of future events or circumstances are forward-looking statements. The Company’s actual results could differ materially from those anticipated in these forward-looking statements for many reasons, including the factors described below and under the caption “Forward-Looking Statements” at the beginning of this report. You should not place undue reliance on these forward-looking statements, which apply only as of the date of this Form 10-Q.

Results of Operations

Puget Energy
        All of the operations of Puget Energy are conducted through its subsidiaries, PSE and InfrastruX. Puget Energy’s net income for the three months ended September 30, 2003 was $11.0 million on operating revenues of $515.6 million, compared with net income of $8.5 million on operating revenues of $458.5 million for the same period in 2002. Income for common stock was $9.9 million for the third quarter of 2003 compared to $6.6 million for the third quarter of 2002. Puget Energy’s basic and diluted earnings per share were $0.10 for the third quarter of 2003 compared to $0.07 for the third quarter of 2002.
        For the first nine months of 2003, Puget Energy’s net income was $78.0 million on operating revenues of $1.7 billion, compared to net income of $66.4 million on operating revenues of $1.7 billion for the corresponding period in 2002. Income for common stock was $73.2 million for the first nine months of 2003 and $60.5 million for the same period in 2002. Puget Energy’s basic and diluted earnings per common share were $0.78 and $0.77, respectively, for the nine months ended September 30, 2003 and $0.69 for the same period in 2002.
        Puget Energy’s income for common stock was impacted by PSE’s income for common stock for the three months ended September 30, 2003 of $8.4 million compared to $2.8 million for the same period in 2002. The improved results were due primarily to customer growth, improved gas margin, lower costs associated with long term equity incentive plans, gains from corporate owned life insurance and lower interest expense, partially offset by higher variable power costs. Puget Energy’s income for common stock was negatively impacted by a decrease in InfrastruX’s income for common stock (net of minority interest) of $2.3 million for the three months ended September 30, 2003 compared to the same period in 2002 due in part to fewer summer electric transmission repair and maintenance projects and a lower margin mix of work performed by InfrastruX companies.
        Puget Energy’s income for common stock was impacted by PSE’s income for common stock for the nine months ended September 30, 2003 of $72.4 million compared to $53.3 million for the same period in 2002. The improved results were due primarily to improved electric and gas margins resulting from general tariff rate increases implemented in the third quarter of 2002 and lower interest expense, partially offset by SFAS 133 unrealized gains decrease from the prior year. Puget Energy’s income for common stock was negatively impacted by a decrease in InfrastruX’s income for common stock (net of minority interest) of $6.5 million for the nine months ended September 30, 2003 compared to the same period in 2002 due to increased insurance costs, competitive pressures on profit margins, and unusually severe weather which affected revenues and productivity in the first half of 2003.

Puget Sound Energy
The table below sets forth changes in the results of operations for Puget Sound Energy and its subsidiaries.

Comparative Three and Nine Months Ended September 30, 2003 vs. September 30, 2002 Increase (Decrease) (Dollars in Millions)
	Three Month Period			Nine Month Period
Operating revenue changes:
Electric interim and general rate increase	$	--		$	10.5
BPA Residential Exchange Credit		(6.7	)		(23.4	)
Electric sales to other utilities and marketers		32.3			110.9
Electric conservation trust credit		2.8			1.0
Electric transportation revenue		(2.2	)		(3.6	)
Electric load and other		17.8			34.5

Total electric operating change		44.0			129.9

Gas PGA rate and load change		9.2			(166.6	)
Gas general rate increase in base rates		2.3			22.8
Gas transportation revenue and other		0.9			1.8

Total gas operating change		12.4			(142.0	)

Other operating revenue change		(0.1	)		(3.8	)

Total operating revenue change		56.3			(15.9	)

Operating expense changes:
Energy costs:
Purchased electricity		42.1			164.2
Purchased gas		4.3			(144.6	)
Electric generation fuel		4.4			(49.3	)
Residential exchange power cost credit		(6.5	)		(22.4	)
Unrealized gain decrease on derivative instruments		1.2			12.5
Utility operations and maintenance:
Production operations and maintenance		(1.0	)		(3.8	)
Personal energy management expenses		(1.4	)		(5.2	)
Low income program pass through expenses		0.3			4.8
Other utility operations and maintenance		0.9			7.3
Other operations and maintenance		--			(0.3	)
Depreciation and amortization		1.5			3.0
Conservation amortization		5.7			13.9
Taxes other than income taxes		2.6			(11.8	)
Income taxes		2.5			7.5

Total operating expense change		56.6			(24.2	)
Other income change (net of tax)		2.4			1.6
Interest charges change		(2.7	)		(8.2	)
Cumulative effect of an accounting change (net of tax)		--			0.1

Net income change	$	4.8		$	18.0

        PSE’s operating revenues and associated expenses are not generated evenly during the year. Variations in energy usage by consumers occur from season to season and from month to month within a season, primarily as a result of weather conditions. PSE normally experiences its highest retail energy sales during the heating season in the first and fourth quarters of the year. Varying wholesale electric prices and the amount of hydroelectric energy supplies available to PSE also make quarter-to-quarter comparisons difficult. The following is additional information pertaining to the changes outlined in the above table.
        Electric margin decreased $2.0 million for the three months ended September 30, 2003 compared to the same period in 2002 primarily as a result of underrecovered variable power costs of $5.8 million, offset by higher sales of electricity to retail customers. Electric margin increased $21.1 million for the nine months ended September 30, 2003 compared to the same period in 2002 due primarily to the non-recurrence of 2002 losses associated with the resale of excess gas supply for electricity generation. Electric margin is electric sales to retail and transportation customers less pass-through tariff items, revenue sensitive taxes, and the cost of generating and purchasing electric energy sold to customers including transmission costs to bring electric energy to PSE’s service territory.
        Electric margin for the three and nine months ended September 30, 2003 and September 30, 2002 is detailed further as follows:

Electric Margin for the Three and Nine Months Ended
September 30, 2003 and September 30, 2002
(Dollars in Millions)

	Three Months Ended September 30						Nine Months Ended September 30
		2003			2002			2003			2002

Electric retail sales revenue	$	279	.3	$	272	.1	$	912	.7	$	920	.3
Electric transportation revenue		2	.6		4	.8		9	.2		12	.9
Other electric revenue-gas supply resale		0	.3		(4	.4)		7	.9		(23	.0)

Total electric revenue for margin		282	.2		272	.5		929	.8		910	.2
Adjustments for amounts included in revenue:
Pass-through tariff items		(11	.0)		(8	.2)		(35	.4)		(19	.3)
Pass-through revenue-sensitive taxes		(20	.5)		(19	.2)		(65	.9)		(65	.0)
Residential Exchange Credit		32	.9		26	.4		122	.6		100	.1

Net electric revenue for margin		283	.6		271	.5		951	.1		926	.0
Minus Power Costs:
Fuel		(21	.2)		(16	.9)		(47	.4)		(96	.7)
Purchased electricity, net of sales to other		(122	.8)		(113	.0)		(445	.2)		(391	.9)
utilities and marketers

Total electric power costs		(144	.0)		(129	.9)		(492	.6)		(488	.6)

Electric Margin	$	139	.6	$	141	.6	$	458	.5	$	437	.4

Gas margin increased $6.5 million for the three months ended September 30, 2003 compared to the same period in 2002 due primarily to an increase of $2.3 million resulting from the $35 million annual, 5.8%, general gas tariff rate increase effective September 1, 2002. Gas margin increased $12.0 million for the nine months ended September 30, 2003 compared to the same period in 2002 due primarily to an increase of $22.8 million resulting from the 5.8% general gas tariff rate increase effective September 1, 2002 offset by gas therm sales declining 7.3% due to warmer weather in the first quarter of 2003. Gas margin is gas sales to retail and transportation customers less pass-through tariff items and revenue sensitive taxes, and the cost of gas purchased, including gas transportation costs to bring gas to PSE’s service territory.
Gas margin for the three and nine months ended September 30, 2003 and September 30, 2002 is detailed further as follows:

Gas Margin for the Three and Nine Months Ended
September 30, 2003 and September 30, 2002
(Dollars in Millions)

	Three Months Ended September 30						Nine Months Ended September 30
		2003			2002			2003			2002

Gas retail revenue	$	71	.9	$	60	.4	$	364	.0	$	507	.8
Gas transportation revenue		3	.6		3	.1		10	.5		9	.0

Total gas revenue for margin		75	.5		63	.5		374	.5		516	.8
Adjustments for amounts included in revenue:
Gas revenue hedge			--			--		0	.2			--
Pass-through tariff items		(0	.4)		(0	.3)		(2	.9)		(0	.9)
Pass-through revenue-sensitive taxes		(6	.0)		(5	.0)		(30	.6)		(42	.1)

Net gas revenue for margin		69	.1		58	.2		341	.2		473	.8
Minus Purchased Gas Costs		(35	.5)		(31	.1)		(179	.8)		(324	.4)

Gas Margin	$	33	.6	$	27	.1	$	161	.4	$	149	.4

Operating Revenues — Electric
        Electric operating revenues for the three months ended September 30, 2003 were $343.5 million, an increase of $44.0 million compared to the same period in 2002 due primarily to wholesale electric sales to other utilities and marketers which increased $32.3 million from greater surplus volumes due in part to hedging expected hydro shortfall in energy production and higher prices in the wholesale electricity market. These wholesale sales revenues are a part of the Company’s Power Cost Adjustment (PCA) mechanism. Wholesale sales volumes increased by 188.6 million kWh or 18.4% to 1.2 billion kWh as a result of warmer temperatures compared to the same period in 2002 in the Pacific Northwest which provided excess electric energy supplies for sales to the wholesale market as a result of lower than expected retail sales and a slight improvement in the forecast of adverse hydro conditions, providing more hydro production than was originally forecasted. Retail sales revenue increased $7.2 million due primarily to increased commercial customer sales. Retail sales volume increased 3.4% to 4.3 billion kWh from 4.2 billion kWh for the same period in 2002.
        Electric operating revenues for the nine months ended September 30, 2003 were $1.1 billion, an increase of $129.9 million compared to the same period in 2002, due primarily to wholesale electric sales to other utilities and marketers which increased $110.9 million from greater surplus volumes due in part to hedging expected hydro shortfall in energy production, and to higher prices in the wholesale electricity market. Wholesale sales volumes increased by 1.9 billion kWh or 80.5% to 4.3 billion kWh as a result of warmer-than-normal temperatures in the Pacific Northwest which provided excess electric energy supplies for sales to the wholesale market as a result of excess generation from the combustion turbines and higher than expected hydro production. Temperatures based on heating-degree-days measured at Seattle-Tacoma airport during the nine month period ended September 30, 2003 were 7.7% warmer than normal as compared to heating-degree-days being 8.3% cooler than normal during the nine month period ended September 30, 2002. Retail sales revenue decreased $7.6 million due primarily to $25 million of interim rate relief ended June 30, 2002 and warmer temperatures in 2003 offset by the effect of a 4.6% electric general rate increase effective July 1, 2002 that increased electric revenue by approximately $10.5 million in the first nine months of 2003. Retail sales volume was 14.1 billion kWh, up slightly from the equivalent period in 2002.
        On June 20, 2002, the Washington Commission approved and adopted the settlement stipulation in the general rate case, putting new rates into effect on July 1, 2002. PSE established a Power Cost Adjustment (PCA) mechanism in the rate case settlement. The PCA mechanism will account for differences in PSE’s modified actual power costs relative to a power cost baseline. The mechanism will account for a sharing of costs and benefits that are graduated over four levels of power cost variances, with an overall cap of $40 million (+/-) over the four year period July 1, 2002 through June 30, 2006 plus 1% of the excess over $40 million. PSE’s share of the costs through September 30, 2003 was $29.9 million, $24.7 million of which was incurred in the first nine months of 2003. PSE expects to reach the $40 million cap by the end of 2003. Utility customers’ share of the costs, which were deferred for later recovery, through September 30, 2003 was $4.1 million, all of which was incurred in the second quarter of 2003.
        On June 11, 2001, PSE and BPA entered into an amended settlement agreement regarding the Residential Purchase and Sale Program, under which PSE’s residential and small farm customers would continue to receive benefits of federal power. Completion of this agreement enabled PSE to continue to provide a Residential and Farm Energy Exchange Benefit credit to residential and small farm customers. The amended settlement agreement provides that, for its residential and small farm customers, PSE will receive (a) cash payment benefits during the period July 1, 2001 through September 30, 2006 and (b) benefits in the form of power or cash payments during the period October 1, 2006 through September 30, 2011.
        Under the Residential Purchase and Sale Program, PSE reduces residential and small farm customers revenue on a per kWh basis through the Residential and Farm Energy Exchange Benefit credit. The credit has no impact on PSE’s electric margin or net income as a corresponding reduction is included in purchased electricity expenses. The Residential Purchase and Sale Program provides PSE’s residential and small farm customers benefits of lower-cost federal power.
        On June 17, 2002, PSE entered into an agreement with BPA which amended the payment provisions of the amended settlement agreement to provide for conditional deferral of payment by BPA of certain amounts to be paid under the original agreement. Under the modified agreement, BPA deferred paying a portion of the benefits it would have otherwise paid. The amount of benefits deferred was $3.5 million each month for the eight-month period beginning February 2003, for a total deferral of $27.7 million. Contemporaneously with entering into this agreement with PSE, BPA entered into other agreements similar to the agreement with PSE through which other investor-owned utilities and BPA agreed to BPA’s deferral of payments in their fiscal year 2003. The total cumulative amount deferred under the agreement with PSE and other such agreements equals $55 million. Absent certain adjustments tied to a BPA rate adjustment clause, BPA is to begin paying back the amount deferred with interest over the sixty-month period beginning October 1, 2006. In January 2003, PSE filed revised tariff sheets with the Washington Commission to reflect this modification to the agreement between PSE and BPA. The Washington Commission accepted the tariff changes and the BPA credit was changed to $0.01740 per kWh, from $0.01817 per kWh, for the period February 15, 2003 through September 30, 2006. On June 30, 2003, BPA adopted its final Record of Decision in the February 2003 rate case, which established a formula under the BPA rate adjustment clause to be used in adjusting the rate which will affect the level of residential exchange benefits for PSE’s customers. The adjustment under the formula went into effect on October 1, 2003, resulting in both a reduction of benefits of $1.2 million a month for a twelve month period and, under the modified agreement mentioned above, an offsetting acceleration of the payment of the above-described $27.7 million deferral. The net result is no change in the cash being received from BPA for the twelve month period, but a reduction in the total benefits to be received in the October 1, 2003 through September 30, 2011 period.
        For the three and nine months ended September 30, 2003, the benefits of the Residential and Farm Energy Exchange Benefit credited to customers were $34.3 million and $128.1 million, respectively, with a related offset to power costs. PSE received payments from BPA in the amount of $33.5 million and $104.0 million during the three and nine months ended September 30, 2003, respectively. The difference between the customers’ credit and the amount received from BPA reduces the previously deferred amount owed to customers. The aggregated deferred amount is recorded on PSE’s balance sheet as restricted cash. Absent certain adjustments tied to a BPA rate adjustment clause described above, the modified amended settlement agreement will provide for payments from BPA in the amount of $630.6 million for the period January 2003 through September 2006 and for pass-through of the same amount to eligible residential and small farm customers.
        On October 23, 2003, PSE signed conditional settlement agreements including a Stipulation and Agreement for Settlement, a Waiver and Covenant Not to Sue, and an Amendment No. 1 to the amended settlement agreement. These conditional settlement agreements, which will be void unless certain conditions are satisfied, include provisions for the dismissal of certain lawsuits regarding residential exchange benefits, an elimination of the adjustment mentioned above for the twelve month period commencing October 1, 2003, the deferral of the receipt of certain benefits, a change in the methodology used to calculate residential benefits in the October 1, 2006 through September 30, 2011 period, and elimination of a risk premium that would otherwise have been payable by BPA under certain conditions under the amended settlement agreement. The conditions which would render the conditional settlement agreements void include a condition that approximately 70 public agency utilities sign a Waiver and Covenant Not to Sue by January 21, 2004, and that no party withdraws its signature by February 20, 2004. Under the conditional settlement agreements, the reduction in benefits mentioned above of $1.2 million a month for twelve months will be eliminated and PSE will defer a total of $37.6 million in the eight month period beginning February 2004, and $27.6 million a year for the two year period beginning October 2004, for a total deferral of $92.9 million. This money will be returned with interest in equal payments over the 60 month period beginning October 2006. If the conditional settlement agreements signed October 23, 2003 are not voided, the benefits to be received from BPA will be reduced, absent certain adjustments tied to a BPA rate adjustment clause, for the January 2003 through September 2006 period from $630.6 million to $537.7 million with the remaining $92.9 million being paid, plus interest, in the October 2006 through September 2011 period.
        There are several actions in the U.S. Ninth Circuit Court of Appeals against BPA, in which the petitioners assert that BPA acted contrary to law or without authority in deciding to enter into, or in entering into or performing, a number of contracts, including the contract between BPA and PSE. BPA rates used in such contract between BPA and PSE for determining the amounts of money to be paid to PSE as residential exchange benefits during the period October 1, 2001 through September 30, 2006 have been confirmed, approved and allowed to go into effect by FERC. There are also several actions in the U.S. Ninth Circuit Court of Appeals against BPA, in which petitioners assert that BPA acted contrary to law in adopting or implementing the rates or rate adjustment clause upon which the benefits received or to be received from BPA during the October 1, 2001 through September 30, 2006 period are based. It is not clear what impact, if any, review of such rates and the above-described U.S. Ninth Circuit Court of Appeals actions may have on PSE. PSE cannot presently predict whether or not the above described conditional settlement agreements will be rendered void or result in the dismissal of any or all of the above described U. S. Ninth Circuit Court of Appeals actions.
        To meet customer demand, PSE dispatches resources in its power supply portfolio such as fossil-fuel generation, owned and contracted hydro capacity and energy, and long-term contracted power. However, depending principally upon availability of hydroelectric energy, plant availability, fuel prices and/or changing load as a result of weather, PSE may sell surplus power or purchase deficit power in the wholesale market. PSE manages its core energy portfolio through short and intermediate-term off-system physical purchases and sales, and through other risk management techniques. A PSE Risk Management Committee oversees energy portfolio exposures.
        During the six months ended June 30, 2003, PSE collected in its electric general rate tariff and remitted to a grantor trust $7.7 million as compared to $5.8 million for the same period in 2002 as a result of PSE’s 1995 sale of future electric revenues associated with its investment in conservation assets. The impact of the sale of revenue was offset by reductions in conservation amortization and interest expenses. The principal amount owed by the trust to its bondholders was $11.6 million at June 30, 2003. PSE’s 1995 conservation trust transaction was consolidated in the third quarter of 2003 to meet the guidance of FASB Interpretation No.46 (FIN 46) and, as a result, revenues increased $3.9 million while conservation amortization and interest expense increased by a corresponding amount with no impact on earnings. At September 30, 2003, the balance sheet assets and liabilities have increased by $8.0 million.
        PSE operates within the western wholesale market and has made sales into the California energy market. During the fourth quarter of 2000, PSE made such sales to the California energy market on which the receivable amount is still outstanding. At September 30, 2003, PSE’s receivable from the California Independent System Operators (CAISO) and other counter-parties, net of reserves, was $24.1 million. See the discussion of the CAISO receivable and California proceedings under “Proceedings Relating to the Western Power Market”.

Operating Revenues — Gas
        Retail gas revenue for the three and nine month periods ended September 30, 2003 increased by $11.5 million and decreased by $143.8 million from the same periods in 2002, respectively, which included the effect of a $35 million annual or 5.8%, gas general rate increase effective September 1, 2002 that increased gas revenue by approximately $2.3 million and $22.8 million for the three and nine month periods ended September 30, 2003, respectively. Retail gas sales volumes increased 10.0% from 78.1 million therms for the three months ended September 30, 2002 to 85.9 million therms for the three months ended September 30, 2003 and decreased 9.9% from 583.6 million therms for the nine months ended September 30, 2002 to 525.9 million therms for the nine months ended September 30, 2003 due primarily to warmer temperatures in the Pacific Northwest in the first quarter of 2003.
        Purchased Gas Adjustment (PGA) rates charged to customers were lower in the three and nine month periods ended September 30, 2003 compared to the same periods in 2002 as a result of rate decreases of 7.3% and 12.5% which took effect September 1, 2002 and November 1, 2002, respectively, offset by a rate increase of 20.1% which took effect April 10, 2003. On September 24, 2003 the Washington Commission approved the PGA rate increase of an annual average of 13.3% across all groups of customers effective October 1, 2003. The PGA mechanism passes through to customers increases or decreases in the gas supply portion of the natural gas service rates based upon changes in the price of natural gas purchased from producers and wholesale marketers or changes in gas pipeline transportation costs.
        PSE’s gas margin (gas sales to retail and transportation customers less pass-through tariff items and revenue sensitive taxes, and the cost of gas purchased, including gas transportation costs to bring gas to PSE’s service territory) and net income are not affected by changes under the PGA.

Operating Expenses
        Purchased electricity expenses increased $42.1 million and $164.2 million for the three and nine month periods ended September 30, 2003 compared to the same periods in 2002. PSE’s hydroelectric production and related power costs in 2003 have been negatively impacted by below normal winter precipitation and snow pack in the Pacific Northwest region associated with an El Nino weather condition. The October 2, 2003 Columbia Basin Runoff Summary published by the National Weather Service Northwest River Forecast Center indicated that the total observed runoff above Grand Coulee reservoir for the period January through September 2003 was 84% of normal. This compares to 102% of normal for the same period in 2002. The Company anticipates reaching the $40 million cumulative cap under the PCA mechanism by the end of 2003 primarily due to increased power costs and adverse hydro conditions. Under the PCA mechanism, further increases in variable power costs through June 30, 2006 would be apportioned 99% to customers and 1% to PSE. PSE’s share of power costs, in excess of those set in rates, through September 30, 2003 was $29.9 million.
        Purchased gas expenses increased $4.3 million and decreased $144.6 million for the three and nine month periods ended September 30, 2003 compared to the same periods in 2002. The three month ended increase was primarily due to an increase in gas market prices from the third quarter of 2002 to the third quarter of 2003. The nine month ended decrease was due to lower consumption volumes as a result of warmer than normal temperatures and the impact of decreased gas costs, which were passed through to customers through the PGA mechanism. The PGA allows PSE to recover expected gas costs. PSE defers, as a receivable or liability, any gas costs that exceed or fall short of the amount in PGA rates and accrues interest under the PGA. The PGA balance was a liability at September 30, 2003 of $6.8 million compared to a liability balance at September 30, 2002 of $98.6 million.
        Electric generation fuel expense increased $4.4 million and decreased $49.3 million for the three and nine month periods ended September 30, 2003 compared to the same periods in 2002. The three month increase is due to higher gas supply costs and increased generation from our combustion turbine units from 2002 to 2003. The nine month decrease is due to lower fuel costs for PSE controlled gas-fired generation facilities which were not operated due to lower cost of wholesale power supply.
        Residential exchange credits associated with the Residential Purchase and Sale Agreement with BPA increased $6.5 million and $22.4 million for the three and nine month periods ended September 30, 2003 when compared to the same periods in 2002, due to an increase in the Residential and Farm Energy Exchange credit rate in January, March, and October of 2002. For further details, see the amended Residential Purchase and Sale Agreement between PSE and BPA discussion in Operating Revenues – Electric.
        Unrealized gain on derivative instruments decreased $1.2 million and $12.5 million for the three and nine month periods ended September 30, 2003 compared to the same periods in 2002 due to changes in the market value of derivative instruments and the reversal of previously recorded unrealized gains when underlying energy supply contracts were settled. During the three months ended September 30, 2003 the Company recorded a decrease in earnings for the change in the market value of derivative instruments not meeting cash flow hedge criteria of approximately $0.9 million pre-tax ($0.6 million after-tax) compared to an increase of $0.3 million pre-tax ($0.2 million after-tax), for the same period in 2002. During the nine months ended September 30, 2003 the Company recorded a decrease in earnings of approximately $0.4 million pre-tax ($0.2 million after-tax) compared to an increase of $12.1 million pre-tax ($7.8 million after-tax) for the same period in 2002. An $11.7 million pre-tax gain in 2002 represented the reversal of unrealized losses on gas hedge contracts that were de-designated in the fourth quarter of 2001 and the reversal of the mark-to-market unrealized loss on physical electric contracts at December 31, 2001 that were settled in 2002.
        The Company has two contracts outstanding with a counterparty whose senior unsecured debt ratings are currently below investment grade. The first contract is a fixed for floating price natural gas swap contract for which the Company has collected a collateral deposit in the amount of $27.3 million from the counterparty to guarantee performance. The financial contract will expire in June 2008 and is accounted for as a cash flow hedge under SFAS No. 133. The second is a physical gas supply contract expiring in December 2008, which has been designated as a normal purchase under SFAS No. 133. The counterparty has continuously performed on both contracts since the contracts were entered into in 2000 and the Company believes it is probable that the counterparty will continue to perform. The Company will continue to monitor the performance of the counterparty.
        Production operations and maintenance cost decreased $1.0 million and $3.8 million for the three and nine month periods ended September 30, 2003 compared to the same periods in 2002. The three month decrease is primarily attributable to $0.8 million in electric generating facility maintenance inspections of combustion turbines during 2002 that did not recur in 2003. The nine month decrease is due primarily to a $4.0 million pre-tax charge in the second quarter of 2002 related to an industrial accident at Colstrip Units 1 and 2 (of which PSE is a 50% owner) which did not recur in 2003.
        PSE’s Personal Energy Management^TMenergy-efficiency program costs decreased $1.4 million and $5.2 million for the three and nine month periods ended September 30, 2003 compared to the same periods in 2002, reflecting a cancellation of the Company’s Time of Use program in November 2002.
        A Low-income Program approved by the Washington Commission in the general rate case settlement began in July 2002, which resulted in increased costs of $0.3 million and $4.8 million for the three and nine months ended September 30, 2003 compared to the same periods in 2002. These costs are fully recovered through a surcharge in retail rates beginning at the program’s inception on July 1, 2002 for electric and September 1, 2002 for gas.
        Other utility operations and maintenance costs increased $0.9 million and $7.3 million for the three and nine months ended September 30, 2003 compared to the same periods in 2002 due primarily to an increase in electric overhead and underground line costs, gas distribution main costs, administrative and general salaries, and meter reading expenses.
        Depreciation and amortization expense for PSE increased $1.5 million and $3.0 million for the three and nine months ended September 30, 2003 compared to the same periods in 2002 due primarily to the effects of new plant placed into service during the past year.
        Conservation amortization expense increased $5.7 million and $13.9 million for the three and nine months ended September 30, 2003 compared to the same periods in 2002 due to increased conservation expenditures and the result of consolidating the off-balance sheet conservation trust beginning July 1, 2003 in accordance with FIN 46, “Consolidation of Variable Interest Entities”. Pass-through conservation costs are recovered through an electric conservation rider, a gas conservation tracker mechanism and a conservation trust rate schedule with no impact to earnings.
        Taxes other than income taxes increased $2.6 million and decreased $11.8 million for the three and nine months ended September 30, 2003 compared to the same periods in 2002 primarily due to lower municipal and state excise taxes which are revenue based. In addition, PSE reached a settlement with the Oregon State Department of Revenue related to a property tax dispute resulting in a $1.4 million reduction in the second quarter of 2003 of amounts previously accrued as expense.
        Income taxes increased $2.5 million and $7.5 million for the three and nine months ended September 30, 2003 compared to the same periods in 2002. Included in the three months ended September 30, 2003 and 2002 were true-ups related to filing the prior year’s income tax returns that reduced income tax expense by $3.0 million and $3.5 million respectively. The nine months ended September 30, 2003 includes a $6.2 million reduction in tax expense related to a favorable resolution of a federal income tax matter from 1997 to 2002 in the second quarter of 2003.

Other Income
Other income increased $2.4 million and $1.6 million for the three and nine months ended September 30, 2003 compared to the same periods in 2002 due primarily to lower costs for long-term equity incentive plans and gains received on corporate owned life insurance.

Interest Charges
Interest charges decreased $2.7 million for the three months ended and $8.2 million for the nine months ended September 30, 2003 compared to the same periods in 2002. Interest on long-term debt decreased $3.0 million for the three months ended and $9.2 million for the nine months ended September 30, 2003, compared to the same periods in 2002. The decrease in interest expense is primarily due to the maturity of $25 million of 7.625% Medium Term Notes in the fourth quarter of 2002, maturity of $58 million of Medium Term Notes with interest rates ranging from 6.23% to 7.02% during 2003, the early redemption of $19.7 million of 8.231% Capital Trust I Preferred Securities, the early redemption of $83 million of Medium Term Notes with interest rates ranging from 7.190% to 8.59% during 2003, and the refinancing of $161.9 million of Pollution Control Bonds with interest rates ranging from 5.875% to 7.25% to rates ranging from 5.00% to 5.10%. The decrease in interest expense was partially offset by the issuance of $150 million of 3.363% Senior Notes in May 2003.

InfrastruX
The table below sets forth changes in the results of operations for InfrastruX, net of minority interest.

Comparative Three and Nine Months Ended
September 30, 2003 vs. September 30, 2002
Increase (Decrease)
(Dollars in Millions)

	Three Month Period			Nine Month Period
Operating revenue change:
Other operating revenue	$	0	.8	$	26	.9

Operating expense changes:
Other operations and maintenance		5	.3		36	.7
Depreciation and amortization		0	.4		2	.8
Taxes other than income taxes		(0	.4)		(0	.3)
Income taxes		(2	.1)		(5	.5)

Total operating expense change		3	.2		33	.7
Other Income (net of tax) change			--		(0	.1)
Interest charges change		0	.1		0	.2
Minority interest change		(0	.2)		(0	.6)

Net income change	$	(2	.3)	$	(6	.5)

The following is additional information pertaining to the changes outlined in the above table.

        InfrastruX revenue increased $0.8 million and $26.9 million for the three and nine month periods ended September 30, 2003 compared to the same periods in 2002 due primarily to acquisitions of several companies during 2002 and one in 2003, which contributed an increase of $10.5 million and $35.3 million, respectively. Revenues from existing companies decreased overall for the three and nine month periods ended September 30, 2003 by $9.8 million and $8.4 million, respectively, due primarily to a reduction in summer electric transmission work in the Southwest/South Central region.
        InfrastruX operation and maintenance expenses increased $5.3 million and $36.7 million for the three and nine month periods ended September 30, 2003 compared to the same periods in 2002 due to the additional costs related to acquired companies, weather-related problems in the first half of 2003 that impacted efficiency and productivity and increases in insurance costs.
        Depreciation and amortization expense increased by $0.4 million and $2.8 million for the three and nine month periods ended September 30, 2003 compared to the same periods in 2002 due to acquisitions during 2002 and additional assets placed in service to support growth as well as to replace aging equipment.
        Income taxes decreased $2.1 million during the three month period ended September 30, 2003 compared to the same period in 2002 due primarily to lower operating income contributed from acquired companies. Income taxes decreased $5.5 million for the nine month period ended September 30, 2003 compared to the same period in 2002 due to a decrease in revenue.

Capital Expenditures, Capital Resources and Liquidity

Capital Requirements
Contractual Obligations and Commercial Commitments
Puget Energy. The following are Puget Energy's aggregate consolidated (including PSE) contractual obligations and commercial commitments as of September 30, 2003:

Puget Energy	Payments Due Per Period
Contractual Obligations (Dollars in millions)	Total				2003			2004-2005			2006-2007			2008 and Thereafter
Long-term debt	$	2,254	.1	$	19	.4	$	315	.0	$	206	.3	$	1,713	.4
Short-term debt		26	.5		26	.5			--			--			--
Trust preferred securities (1)		280	.3			--			--			--		280	.3
Mandatorily redeemable preferred stock		1	.9			--			--			--		1	.9
Preferred stock and preferred dividends (2)		61	.5		61	.5			--			--			--
Service contract obligations		175	.6		4	.8		40	.7		43	.4		86	.7
Capital lease obligations		25	.9		2	.2		14	.2		8	.4		1	.1
Non-cancelable operating leases		70	.7		7	.7		31	.3		21	.1		10	.6
Fredonia combustion turbines lease (3)		70	.8		1	.2		8	.9		8	.6		52	.1
Energy purchase obligations		4,685	.1		290	.4		1,370	.5		954	.2		2,070	.0
Financial hedge obligations		20	.0		1	.8		11	.3		6	.0		0	.9

Total contractual cash obligations	$	7,672	.4	$	415	.5	$	1,791	.9	$	1,148	.0	$	4,217	.0

	Amount of Commitment Expiration Per Period
Commercial Commitments (Dollars in millions)	Total				2003			2004-2005			2006-2007			2008 and Thereafter
Guarantees (4)	$	136	.0	$		--	$	136	.0	$		--	$		--
Liquidity facilities – available (5)		329	.0		240	.2		88	.8			--			--
Lines of credit – available (6)		34	.4			--		24	.4		10	.0			--
Energy operations letter of credit (7)		0	.5			--		0	.5			--			--

Total commercial commitments	$	499	.9	$	240	.2	$	249	.7	$	10	.0	$		--

(1)

In 1997 and 2001, PSE formed Puget Sound Energy Capital Trust I and Puget Sound Energy Capital Trust II, respectively, for the sole purpose of issuing and selling preferred securities (Trust Securities) to investors and issuing common securities to PSE. The proceeds from the sale of Trust Securities were used by the Trusts to purchase Junior Subordinated Debentures (Debentures) from PSE. The Debentures are the sole assets of the Trusts and PSE owns all common securities of the Trusts.

(2)

On July 7, 2003, the Board of Directors of PSE declared a dividend payable on October 1, 2003 for preferred stock outstanding on September 1, 2003. The preferred stock was redeemed at par for $60 million on November 1, 2003, and PSE paid dividends for the period between October 1, 2003 and November 1, 2003.

(3)

See “Fredonia 3 and 4 Operating Lease” under “Off-Balance Sheet Arrangements” below.

(4)

In June 2001, InfrastruX signed a three-year credit agreement with several banks to provide up to $150 million in financing. Under the credit agreement, Puget Energy is the guarantor of the line of credit.

(5)

At September 30, 2003, PSE had available a $250 million unsecured credit agreement and a three year $150 million receivables securization facility. At September 30, 2003, PSE had available $88.8 million of receivables for sale under its receivables securitization facility. See “Accounts Receivable Securitization Program” under “Off-Balance Sheet Arrangements” below. The credit agreement and securitization facility provide credit support for outstanding commercial paper totaling $9.3 million and an outstanding letter of credit totaling $0.5 million, thereby effectively reducing the available borrowing capacity under these liquidity facilities to $329.0 million.

(6)

Puget Energy has a $15 million line of credit with a bank. At September 30, 2003, $5 million was outstanding, reducing the available borrowing capacity under this line of credit to $10 million. InfrastruX has $31.7 million in lines of credit with various banks, and a $150 million line of credit guaranteed by Puget Energy, which fund capital requirements of InfrastruX and its subsidiaries. InfrastruX and its subsidiaries had outstanding loans of $153.2 million and letters of credit of $4.1 million at September 30, 2003, effectively reducing the available borrowing capacity under these lines of credit to $24.4 million.

(7)

In May 2002, PSE provided an energy trading counterparty a letter of credit in the amount of $0.5 million to satisfy the counterparty’s credit requirements following PSE’s senior unsecured debt downgrade in October 2001. The letter of credit has been renewed and expires on March 15, 2004.

Puget Sound Energy. The following are PSE’s aggregate contractual obligations and commercial commitments as of September 30, 2003:

Puget Sound Energy	Payments Due Per Period
Contractual Obligations (Dollars in millions)	Total				2003			2004-2005			2006-2007			2008 and Thereafter
Long-term debt	$	2,110	.8	$	14	.0	$	177	.4	$	206	.0	$	1,713	.4
Short-term debt		9	.3		9	.3			--			--			--
Trust preferred securities (1)		280	.3			--			--			--		280	.3
Mandatorily redeemable preferred stock		1	.9			--			--			--		1	.9
Preferred stock and preferred dividends (2)		61	.5		61	.5			--			--			--
Service contract obligations		175	.6		4	.8		40	.7		43	.4		86	.7
Non-cancelable operating leases		51	.7		5	.4		19	.2		17	.7		9	.4
Fredonia combustion turbines lease (3)		70	.8		1	.2		8	.9		8	.6		52	.1
Energy purchase obligations		4,685	.1		290	.4		1,370	.5		954	.2		2,070	.0
Financial hedge obligations		20	.0		1	.8		11	.3		6	.0		0	.9

Total contractual cash obligations	$	7,467	.0	$	388	.4	$	1,628	.0	$	1,235	.9	$	4,214	.7

	Amount of Commitment Expiration Per Period
Commercial Commitments (Dollars in millions)	Total				2003			2004-2005			2006-2007			2008 and Thereafter
Liquidity facilities – available (4)	$	329	.0	$	240	.2	$	88	.8	$		--	$		--
Energy operations letter of credit (5)		0	.5			--		0	.5			--			--

Total commercial commitments	$	329	.5	$	240	.2	$	89	.3	$		--	$		--

(1) See note (1) above.
(2) See note (2) above.
(3) See note (3) above.
(4) See note (5) above.
(5) See note (7) above.

Off-Balance Sheet Arrangements
Accounts Receivable Securitization Program. In order to provide a source of liquidity for PSE at attractive cost of capital rates, in December 2002, PSE entered into a Receivables Sales Agreement with Rainier Receivables, Inc., a wholly owned subsidiary of PSE, pursuant to which PSE sold all of its utility customers accounts receivable and unbilled utility revenues to Rainier Receivables. Concurrently with entering into the Receivables Sales Agreement, Rainier Receivables entered into a Receivables Purchase Agreement with PSE and several financial institutions. The Receivables Purchase Agreement allows Rainier Receivables to sell the receivables purchased from PSE to the financial institutions. The amount of receivables sold by Rainier Receivables is not permitted to exceed $150 million at any time. However, the maximum amount may be less than $150 million depending on the outstanding amount of PSE’s receivables which fluctuate with the seasonality of energy sales to customers.
The receivables securitization facility is the functional equivalent of a secured revolving line of credit. In the event Rainier Receivables elects to sell receivables under the Receivables Purchase Agreement, Rainier Receivables is required to pay the purchasers of the receivables fees that are analogous to interest on a revolving line of credit. As receivables are collected by PSE as agent for the receivables purchasers, the outstanding amount of receivables purchased by the purchasers declines until Rainier Receivables elects to sell additional receivables to the purchasers.
The receivables securitization facility has a three year term, but is terminable by PSE and Rainier Receivables upon notice to the receivables purchasers. At September 30, 2003, Rainier Receivables had sold $7.0 million of accounts receivable and the maximum receivables available for sale was $88.8 million.

Fredonia 3 and 4 Operating Lease. PSE leases two combustion turbines for its Fredonia 3 and 4 electric generation facility pursuant to a master lease that was amended for this purpose in April 2001. The lease has a term expiring in 2011, but can be canceled by PSE after three years from the inception date of August 1, 2001. Payments under the lease vary with changes in the London inter-bank offered rate (LIBOR). At September 30, 2003, PSE’s outstanding balance under the lease was $59.5 million. The expected residual value under the lease is the lesser of $37.4 million or 60% of the cost of the equipment. In the event the equipment is sold to a third party upon termination of the lease and the aggregate sales proceeds are less than the unamortized value of the equipment, PSE would be required to pay the lessor contingent rent in an amount equal to the deficiency up to a maximum of 87% of the unamortized value of the equipment.

Utility Construction Program. Current utility construction expenditures for generation, transmission and distribution are designed to meet continuing customer growth and to improve efficiencies of PSE’s energy delivery systems. Construction expenditures, excluding equity Allowance for Funds Used During Construction (AFUDC), were $203.9 million for the nine months ended September 30, 2003. PSE expects construction expenditures will be approximately $272 million in 2003 and will be larger in 2004. PSE anticipates spending approximately $80 million in 2004 for new generating resources and a substantially larger amount in 2005, subject to regulatory approval of the resources and related new revenue requirements. The 2004 resources will be funded initially with short-term debt. Construction expenditure estimates are subject to periodic review and adjustment in light of changing economic, regulatory, environmental and conservation factors.

New Generation Resources. In October 2003, PSE completed negotiations to purchase a 49.85% interest in a 275 MW gas fired electric generating station located within PSE’s service territory. The purchase will add approximately 137 MW of electric generation capacity to serve PSE’s retail customers. PSE submitted a power cost only rate case in October 2003 to the Washington Commission to recover the approximately $80 million cost of the new generating facility and other power costs. The power cost only rate case is expected to last approximately five months. Accordingly, the acquisition of the plant, subject to favorable approval by the Washington Commission, could be completed by the end of the first quarter of 2004.
In addition, PSE has issued a draft request for proposals (RFP) to acquire approximately 50 average MWs of energy from wind power for its electric-resource portfolio. PSE plans to issue an RFP for approximately 300 MWs of thermal generation in early 2004.

Other Additions. Other property, plant and equipment additions were $10.4 million for the nine months ended September 30, 2003. Puget Energy expects InfrastruX’s capital additions to be $13.0 million in 2003. Construction expenditure estimates are subject to periodic review and adjustment in light of changing economic, regulatory, environmental, and conservation factors.

Capital Resources
Cash From Operations. Cash generated from operations for the nine month period ended September 30, 2003 was $206.1 million. During the period, $66.8 million in cash was used for AFUDC and payment of dividends. Consequently, cash flows available for utility construction expenditures and other capital expenditures was $139.3 million or 61.7% of the $225.6 million in construction expenditures (net of AFUDC) and other capital expenditure requirements for the period. PSE funded these 2003 expenditures primarily by drawing upon its cash reserves which were $161.5 million at the end of 2002. For the same period in 2002, cash generated from operations was $566.7 million, $78.1 million of which was used for AFUDC and payment of dividends. Therefore, cash flows available for utility construction expenditures and other capital expenditures for the nine month period ended September 30, 2002 was $488.6 million. The reduction in cash generated from operations in 2003 is primarily due to refunds reducing the PGA balance. In the nine months ended September 30, 2002, PSE received $135.8 million in excess of actual gas costs from customers through the PGA mechanism compared to refunds to customers through the PGA mechanism of $77.0 million for the nine months ended September 30, 2003. Cash from accounts receivables and unbilled revenues decreased by $45.9 million due primarily to colder than normal temperatures in the nine months ended September 30, 2002 compared to warmer than normal temperatures in 2003. Cash from materials and supplies decreased $42.2 million due predominantly to higher gas injections in 2003 as compared to 2002 in order to build up storage levels. Cash from other operating activities also decreased due to an $11.2 million decrease in accrued purchases from 2002 to 2003 and a $27.7 million increase in the amount of cash used to offset customers bills compared to cash received from BPA for the Residential Exchange Program.
Puget Energy and PSE expect to continue financing the utility construction program and other capital expenditure requirements with internally generated funds and externally financed capital.

Financing Program. Financing utility construction requirements and operational needs is dependent upon the cost and availability of external funds through capital markets and from financial institutions. Access to funds is dependent upon factors such as general economic conditions, regulatory authorizations and policies, and Puget Energy’s and PSE’s credit ratings. The Company expects to meet capital and operational needs for the balance of 2003 and 2004 with cash generated from operations and borrowings under its liquidity facilities.

Restrictive Covenants. In determining the type and amount of future financing, PSE may be limited by restrictions contained in its electric and gas mortgage indentures, articles of incorporation and certain loan agreements. Under the most restrictive tests, at September 30, 2003, PSE could issue:

•

approximately $983.8 million of first mortgage bonds, as PSE has approximately $1.3 billion of electric and gas bondable property available for use, subject to the interest coverage ratio limitation of 2.0 times net earnings available for interest. PSE’s interest coverage ratio at September 30, 2003 was 2.7 times net earnings available for interest which would allow issuance of approximately $783.2 million of additional first mortgage bonds, at an assumed interest rate of approximately 6% on a ten-year first mortgage bond;

•

approximately $415.6 million of additional preferred stock at an assumed dividend rate of 7.75%; and

•

approximately $262.2 million of unsecured long-term debt.

Credit Ratings. Neither Puget Energy nor PSE has any rating downgrade triggers that would accelerate the maturity dates of outstanding debt. However, a downgrade in the credit ratings could adversely affect the Companies’ ability to renew existing, or obtain access to new credit facilities and could increase the cost of such facilities. For example, under PSE’s revolving credit facility, the spreads over the index and commitment fee increase as PSE’s secured long-term debt ratings decline. A downgrade in commercial paper ratings could preclude PSE’s ability to issue commercial paper under its current programs. The marketability of PSE commercial paper is currently limited by the A-3/P-2 ratings by Standard & Poor’s and Moody’s Investors Service. A further downgrade in commercial paper ratings could preclude entirely PSE’s ability to issue commercial paper. In addition, downgrades in any or a combination of PSE’s debt ratings may allow counterparties on a contract by contract basis in the wholesale electric, wholesale gas and financial derivative markets to require PSE to post a letter of credit or other collateral, make cash prepayments, obtain a guarantee agreement or provide other mutually agreeable security.
The ratings of Puget Energy and PSE as of November 10, 2003 were:

	Ratings
	Standard & Poor’s	Moody’s
Puget Sound Energy
Corporate credit/issuer rating	BBB-	Baa3
Senior secured debt	BBB	Baa2
Shelf debt senior secured	BBB	Baa2
Senior unsecured	*	*
Preferred stock	BB	Ba2
Commercial paper	A-3	P-2
Subordinate	**	Ba1
Revolving credit facility	**	Baa3
Ratings outlook	Stable	Negative
Puget Energy
Corporate credit/issuer rating	BBB-	Ba1

No ratings provided. S&P and Moody’s have placed an indicative rating of BB+ and Baa3, respectively, on senior unsecured debt were the Company to issue any pursuant to its shelf registration filed in February 2002. To date, the Company has not issued any senior unsecured debt.

No ratings provided.

Moody’s Investors Service has stated that its negative outlook is based upon uncertainty about the outcome of investigations by FERC of the Western power markets. Moody’s Investors Service has stated that it would consider a stable outlook if FERC approves the recent agreement reached between PSE and the FERC trial staff. See “Proceedings Relating to the Western Power Market – Orders to Show Cause”.

Shelf Registrations. In February 2002, Puget Energy and PSE 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 of:

•

common stock of Puget Energy,

•

senior notes of PSE, secured by a pledge of PSE’s first mortgage bonds,

•

unsecured debentures of PSE, and

•

trust preferred securities of Puget Sound Energy Capital Trust III.

On November 5, 2003, Puget Energy completed the sale of 4.55 million shares of common stock directly to funds managed by Franklin Advisers, Inc. for $100.1 million. The sale of these shares are expected to be non-dilutive for 2003 and 2004 earnings per share as the common stock replaces high cost preferred stock. Of the net proceeds of the sale, $93.75 million will be invested in PSE to fund redemptions of the preferred stock and $6.25 million balance will be used by PSE for general corporate purposes. Approximately $128.5 million of securities remain available for issuance under the shelf registration at November 5, 2003.

Liquidity Facilities and Commercial Paper. PSE’s short-term borrowings and sales of commercial paper are used to provide working capital and funding of utility construction programs.
        PSE has a $250 million unsecured credit agreement with various banks which expires in June 2004 and a $150 million 3-year receivables securitization program which expires in December 2005. The receivables available for sale under the securitization program may be less than $150 million depending on the outstanding amount of PSE’s receivables which fluctuate with the seasonality of energy sales to customers. At September 30, 2003, PSE had available $250 million in the unsecured credit agreement and $88.8 million available from the receivable securitization facility (net of $7.0 million sold), which provide credit support for outstanding commercial paper of $9.3 million and outstanding letters of credit of $0.5 million, effectively reducing the available borrowing capacity under the liquidity facilities to $329.0 million.
        In June 2001, InfrastruX signed a three-year credit agreement with several banks to provide up to $150 million in financing. Puget Energy is the guarantor of the line of credit. In addition, InfrastruX’s subsidiaries have an additional $31.7 million in lines of credit with various banks. Borrowings available for InfrastruX are used to fund acquisitions and working capital requirements of InfrastruX and its subsidiaries. At September 30, 2003, InfrastruX and its subsidiaries had outstanding loans of $153.2 million and letters of credit of $4.1 million, effectively reducing the available borrowing capacity under these lines of credit to $24.4 million.
        On May 27, 2003, Puget Energy entered into a $15 million, three-year credit agreement with a bank. Under the terms of the agreement, Puget Energy will pay a floating interest rate on borrowings based on the London inter-bank offered rate (LIBOR). The interest rate is set for one, two, or three-month periods at the option of Puget Energy with interest due at the end of each period. Puget Energy will also pay a commitment fee on any unused portion of the credit facility. On May 30, 2003, Puget Energy borrowed $5 million under the credit agreement. The proceeds of the loan were invested in InfrastruX, which used the proceeds to acquire a construction services company in New Mexico.

Stock Purchase and Dividend Reinvestment Plan. Puget Energy has a stock purchase and dividend reinvestment plan pursuant to which shareholders and other interested investors may invest cash and cash dividends in shares of Puget Energy’s common stock. Since new shares of common stock may be purchased directly from Puget Energy, funds received may be used for general corporate purposes. Puget Energy issued common stock from the Stock Purchase and Dividend Reinvestment Plan of $4.0 million (184,870 shares) and $11.6 million (554,441 shares) for the three and nine months ended September 30, 2003 compared to $3.2 million (149,545 shares) and $13.0 million (619,655 shares) for the same periods in 2002. The decrease in the shares issued under the Stock Purchase and Dividend Reinvestment Plan from the nine month period ended September 30, 2003 compared to the nine month period ended September 30, 2002 was largely attributable to the reduction of the common stock dividend on May 15, 2002 to a quarterly dividend of $0.25 per share.

Common Stock Offering Programs. To provide additional financing options, Puget Energy entered into agreements on July 10, 2003 with two financial institutions under which Puget Energy may offer and sell shares of its common stock from time to time through these institutions as sales agents, or as principals. Sales of the common stock, if any, may be made by means of negotiated transactions or in transactions that may be deemed to be “at-the-market” offerings as defined in Rule 415 promulgated under the Securities Act of 1933, including in ordinary brokers’ transactions on the New York Stock Exchange at market prices. On October 14, 2003, Puget Energy sold 100,600 shares of common stock under its program with Cantor Fitzgerald & Company. Puget Energy received approximately $2.3 million in net proceeds from these sales, after deducting an underwriter’s commission of $45,000 and estimated offering expenses payable by Puget Energy.

Proceedings Relating to the Western Power Market
California Independent System Operator (CAISO) Receivable and California Proceedings
Puget Energy’s and PSE’s Annual Report on Form 10-K for the year ended December 31, 2002 and Quarterly Report on Form 10-Q for the quarters ended March 31, 2003 and June 30, 2003 include summaries of the Western power market proceedings described below. The following discussion provides a summary of material developments in these proceedings that occurred during the period covered by this report and of any material new proceedings instituted during the last quarter. While PSE cannot predict the outcome of any of the individual ongoing proceedings relating to the Western power markets, PSE generally is pleased that FERC appears to be narrowing the issues under review in the cases pending before it. The narrowing of issues allows PSE to compare the allegations in the various proceedings with PSE’s relevant records and to better anticipate the likely outcome of each case. In the aggregate, PSE does not expect the ultimate resolution of the issues and cases discussed below to have a material adverse impact on the financial condition, results of operations or liquidity of the Company.

California Independent System Operator (CAISO) Receivable. In 2001, PG&E and Southern California Edison defaulted on payment obligations owed to various energy suppliers, including the CAISO. The CAISO in turn defaulted on its payment obligations to various energy suppliers, including obligations to PSE relating to sales made by PSE into the California energy market during the fourth quarter of 2000 through the CAISO. After deducting a bad debt reserve and a transaction fee reserve totaling $41.5 million, PSE has a net receivable from the CAISO at September 30, 2003 of $24.1 million. On October 16, 2003, FERC issued its Order on Rehearing in this docket and expressly adopted and approved a stipulation that confirmed two PSE “non-spot market” transactions were not subject to refund. The total gross revenue associated with the transactions is approximately $26.0 million. On October 17, 2003, PSE sent a demand letter to the CAISO seeking payment of the amount due.

California Refund Proceeding. On July 25, 2001, FERC ordered an evidentiary hearing (Docket No. EL00-95) to determine the amount of refunds due to California energy buyers, including the CAISO, for purchases made in the spot markets operated by the CAISO during the period October 2, 2000 through June 20, 2001.
On March 26, 2003, FERC issued an Order on Proposed Findings on Refund Liability in Docket EL00-95 that substantially adopted the recommendations made by the Administrative Law Judge on December 12, 2002, except that the Order also substantially adopts the FERC Staff gas price recommendation from the Staff’s August 2002 report. On October 16, 2003, FERC issued its Order on Rehearing that largely leaves the refund calculations established by the March 26 Order unchanged, although the Order postpones resolution of the fuel cost allowance issues until later. Thus PSE’s filing to seek recovery of its actual fuel costs above the amount set using the “Staff methodology” remains pending. On May 21, 2003, the “California Parties” filed a motion to reject all fuel cost adjustment filings, including the filing made by PSE. The Order on Rehearing gives the CAISO a deadline to perform its cost re-runs (which are expected to establish actual amounts owing and owed) of five months from October 16, 2003. PSE anticipates that the net results of the re-run and the application of the refund calculation will extinguish the CAISO receivable apart from the amount associated with the two non-spot market transactions described in 1 above.

Pacific Northwest Refund Proceeding. On June 25, 2003, FERC issued an order terminating the Pacific Northwest refund proceeding, Docket EL01-10, largely on procedural, jurisdictional and equitable grounds. Various parties filed rehearing requests on July 25, 2003. On November 10, 2003, FERC denied the rehearing requests.

Orders to Show Cause. On June 25, 2003, FERC issued two show cause orders pertaining to its Western market investigations that commenced individual proceedings against many sellers. One show cause proceeding seeks to investigate approximately 26 entities that allegedly had potential “partnerships” with Enron. PSE is not named in that show cause order. The second show cause proceeding seeks to investigate approximately 55 entities that allegedly had engaged in potential “gaming” practices in the CAISO and California PX markets. PSE is one of the entities named in the “gaming” show cause order. Consistent with the show cause orders’ invitation to attempt settlement, PSE and FERC Staff filed a proposed settlement of all issues pending against PSE in those proceedings on August 28, 2003. The proposed settlement, which admits no wrongdoing on the part of PSE, would result in a payment of approximately $17,000 to settle all claims. The California Parties and a few others filed oppositions to PSE’s settlement (and all others) on September 30, 2003. PSE replied to those arguments on October 20, 2003. PSE continues to believe that the orders to show cause do not raise new issues or concerns or will have a material adverse impact on the financial condition, results of operation or liquidity of the Company. The presiding Administrative Law Judge is expected to determine whether to recommend the settlements to FERC before the end of the year.

Anomalous Bidding Investigation. On June 25, 2003, FERC issued an order commencing a new investigatory proceeding, Docket No. IN03-10, to be conducted through its Office of Market Oversight and Investigations (OMOI). That docket is to review each seller’s bids into the CAISO or California PX markets that exceeded $250/MWh during the period of May 1, 2000 to October 1, 2000. The OMOI is to determine if each such entity’s bids show a pattern or an effort to manipulate the market, and if they do, to consider whether the entity should be required to disgorge any improper profits earned as a result of such patterns or efforts. PSE received a data request from the OMOI in this proceeding about its bids and responded on July 24, 2003. There is no established timetable for this proceeding, but FERC expects to work diligently to review the practices of each seller and to resolve the matter expeditiously. PSE does not expect any material adverse impacts on the financial condition of the Company from this FERC investigation.

Port of Seattle Suit. On May 21, 2003, the Port of Seattle commenced suit in federal court in Seattle against 22 energy sellers into the California market, alleging that the conduct of those sellers during 2000 and 2001 constituted market manipulation, violated antitrust laws, and damaged the Port of Seattle, which had a contract to purchase its complete energy supply from PSE at the time. The Port’s contract with PSE linked the price of the energy sold to the Port to an index price for energy sold at wholesale at the Mid-Columbia trading hub. The Port alleged that the Mid-Columbia price was intentionally affected improperly by the defendants, including PSE. PSE has moved to dismiss this case; other defendants have moved to transfer the matter to a multi-district litigation panel in California. A conditional transfer order was issued in July 2003. PSE’s motion to dismiss remains on the docket but further proceedings are on hold pending determination of the multi-district litigation panel on or after November 20, 2003.

California Litigation. San Diego Cases. No material developments have occurred in the two San Diego class actions since previous reports. The plaintiffs allege that all wholesale sellers in the California energy market engaged in anti-competitive behavior in violation of California Business Practices Act. The motions to dismiss, and the appeals of the remand orders, remain pending. Attorney General Case. No material developments have occurred in the California Attorney General suit against PSE since previous reports. The suit filed against a number of sellers, including PSE, alleges that PSE failed to file rates for sales to the CAISO in advance of transactions and thereby violated the California Business Practices Act. The appeal of the order of dismissal remains pending.

Other
        On April 30, 2003, PSE filed its Least Cost Plan with the Washington Commission. This document provides a high level, diversified resource strategy to meet the Company’s growing energy needs. The Least Cost Plan was developed in consultation with numerous external key stakeholders, including staff of the Washington Commission. A Least Cost Plan Update was filed on August 29, 2003, which incorporated new information on conservation resource potentials. On October 3, 2003, the Washington Commission sent the Company a letter formally accepting the Company’s Least Cost Plan as meeting the Washington Commission’s requirements. The Company’s next Least Cost Plan filing is due by May 1, 2005.
        On September 14, 2003, NorthWestern Corporation (NorthWestern) filed a voluntary petition for relief under Chapter 11 of the U. S. Bankruptcy Code. PSE has several long-term contracts with NorthWestern under which PSE jointly owns facilities or purchases power or transmission services from NorthWestern. NorthWestern has indicated that it plans to continue to perform under those contracts.
        PSE and Western Energy Company, the supplier of coal to PSE’s Colstrip power plants, are engaged in a dispute and binding arbitration process concerning the price of coal that PSE will pay under the contract for Colstrip Units 1 & 2 through the end of the contract in 2009. This arbitration is contemplated as a price adjustment mechanism in that contract. The parties are over $1 per ton apart on their view as to the proper price for coal under that contract, and the arbitration would resolve that question in the second quarter of 2004. Any price adjustment could be retroactive to July 30, 2001 and would apply through the rest of the term. A $1 per ton increase or decrease in the price of coal would have a corresponding effect on PSE’s costs of approximately $1.4 million annually and if the price were retroactive to July 30, 2001, the corresponding effect on power costs would be $3.2 million. Fuel supply costs for electric generation after July 1, 2002 are a part of PSE’s power cost adjustment mechanism.
        In October 2003, PSE received notice from Western Energy Company that the Montana Department of Revenue is alleging underpayment of royalties on coal purchased by PSE from Western Energy Company from 1997 to 2000. PSE used the coal as fuel for its Colstrip Units 3 & 4 generating plants. The dispute is likely to lead to a more formal process or litigation to review those purchases and to determine whether PSE may owe more royalties, taxes or penalties. The Montana Department of Revenue seeks a payment of approximately $1.1 million plus applicable Montana State taxes on such payments. PSE will defend this claim vigorously. PSE cannot predict the outcome of this issue at this early date.
        In 2003 the Colville Confederated Tribes presented a claim to Douglas County PUD based upon allegedly due past annual charges for the Wells Hydroelectric Project for the use of Colville tribal lands. The Tribes claimed that annual charges would also be due for periods into the future. Since April of 2003, Douglas PUD and Colville representatives have discussed settlement of this issue. The settlement discussions may lead to a resolution of the claim. PSE purchases 31.3% of the power generated by the Wells Project. A settlement of this claim could affect the amount of energy PSE receives under the terms of PSE’s purchased electricity contract or the price of the output of the Wells Hydroelectric Project purchased by PSE.

White River Hydroelectric Generation Project, FERC No. 2494 (the Project). The Project was built in 1911 by PSE and has been in continuous operation ever since. The Project generates electricity to serve PSE’s retail electric customers with an annual average output of approximately 35 megawatts. In 1983, the Company applied for an original FERC License for this Project. In December of 1997, FERC issued a proposed license that was appealed by the Company and various natural resource agencies. The Company appealed the license because it contained terms and conditions that would render ongoing operations of the Project uneconomic relative to alternative resources. In 1998, 2001 and in 2003 FERC granted a stay of the license order (and related appeals) to afford interested parties the opportunity for settlement negotiations. This stay expires in January of 2004. If settlement has not been reached by the end of the stay, in order to keep the Project in operation the Company would likely be required to implement the license order pending FERC’s disposition of the Company’s appeal. Implementation of the license order would require the Company to make capital expenditures and incur annual operating costs that would make the project uneconomic. The Company has concluded that it is unlikely that a settlement addressing the deficiencies of the 1997 FERC license will be reached before the stay expires, and anticipates advising FERC in January that it intends to withdraw its license application and retire the Project. To this end, the Company is negotiating with a consortium of municipalities interested in acquiring the Project as a source for a municipal water supply. The Company is also discussing an interim “non-power” operations agreement with the U.S. Army Corps of Engineers. This interim agreement would address the Corps’ interest in keeping the Project’s diversion dam in operation and thereby facilitate the Corps’ ongoing responsibilities to provide fish passage for the Corps’ upstream flood control project (Mud Mountain Dam). Keeping the Project in operation is also a matter of importance to the surrounding community that wants to preserve the reservoir for financial, recreational and aesthetic purposes. The outcome of these various negotiations and discussions is uncertain at this time, as is the magnitude of any financial impact on the Company associated therewith. However, in any event, it is unlikely that the Project will be in service as a generation resource of the Company after January of 2004. As a result, PSE will petition the Washington Commission for an accounting order in the fourth quarter of 2003. This petition will request authorization for the appropriate accounting and rate making disposition of this Project to be retired. At September 30, 2003, the White River Project’s net book value totals $69.0 million, which includes $47.6 million of net utility plant, $15.0 million of capitalized FERC licensing costs and $6.4 million of costs related to construction work in progress.

Item 3. Quantitative and Qualitative Disclosure About Market Risk

The Company is exposed to market risks, including changes in commodity prices and interest rates.

Portfolio Management. The nature of serving regulated electric customers with its wholesale portfolio of owned and contracted resources does expose the Company and its customers to some volumetric and commodity price risks within the sharing mechanism of the PCA. The Company’s energy risk management function monitors and manages these risks using analytical models and tools. The Company manages its energy supply portfolio to achieve three primary objectives:

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Ensure that physical energy supplies are available to serve retail customer requirements;

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Manage portfolio risks to limit undesired impacts on the Company’s costs; and

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Optimize the value of the Company’s energy supply assets.

        The portfolio is subject to major sources of variability (e.g., hydro generation, outage risk, regional economic factors, temperature-sensitive retail sales, and market prices for gas and power supplies). At certain times, these sources of variability can mitigate portfolio imbalances; at other times they can exacerbate portfolio imbalances.
        The Company’s energy risk management staff develops hedging strategies for the Company’s energy supply portfolio. The first priority is to obtain reliable supply for delivery to the Company’s retail customers. The second priority is to protect against unwanted risk exposure. The third priority is to optimize excess capacity or flexibility within the wholesale portfolio. Most hedges can be implemented in ways that retain the Company’s ability to use its energy supply optimization opportunities. Other hedges are structured similarly to insurance instruments, where PSE pays an insurance premium to protect against certain extreme conditions.
        Portfolio exposure is managed in accordance with Company polices and procedures. The Risk Management Committee, which is composed of Company officers, provides policy level and strategic direction for management of the energy portfolio. The Audit Committee of the Company’s Board of Directors has oversight of the Risk Management Committee.
        The prices of energy commodities are subject to fluctuations due to unpredictable factors including weather, generation outages and other factors which impact supply and demand. The volumetric and 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 physical delivery agreements and financial derivatives for the purpose of hedging commodity price risk. Without jeopardizing the security of supply within its portfolio, the Company will also engage in optimizing the portfolio. Optimization may take the form of utilizing excess capacity, shaping flexible resources to capture their highest value, utilizing transmission capacity or capitalizing on market price movement. As a result, portions of the Company’s energy portfolio are monetized through use of forward price instruments.
        The regulatory mechanisms of the PGA and the PCA mitigate the impact of commodity price volatility upon the Company. The PGA mechanism passes through to customers increases and decreases in the cost of natural gas supply. The PCA mechanism provides for a sharing of costs and benefits that are graduated over four levels of power cost variances with an overall cap of $40 million (+/-) plus 1% of the excess over the $40 million cap over the four year period ending June 30, 2006.
        Transactions that qualify as hedge transactions under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, are recorded on the balance sheet at fair value. Changes in fair value of the Company’s derivatives are recorded each period in current earnings or other comprehensive income. Short-term derivative contracts for the purchase and sale of electricity are valued based upon daily quoted prices from an independent energy brokerage service. Valuations for short-term and medium-term natural gas financial derivatives are derived from a combination of quotes from several independent energy brokers and are updated daily. Long-term gas financial derivatives are valued based on published pricing from a combination of independent brokerage services and are updated monthly. Option contracts are valued using market quotes and a Monte Carlo simulation-based model approach.
        At September 30, 2003, the Company had an after-tax net asset of approximately $13.0 million of energy contracts designated as qualifying cash flow hedges and a corresponding unrealized gain amount in other comprehensive income. The Company also had energy contracts that were marked-to-market through current earnings for the third quarter of 2003 of $0.6 million after-tax. A hypothetical 10% increase in the market prices of natural gas and electricity would increase the fair value of qualifying cash flow hedges by approximately $9.9 million after-tax and would increase current earnings for those contracts marked-to-market in earnings by $0.6 million after-tax.

Interest Rate Risk. The Company believes its interest rate risk primarily relates to the use of short-term debt instruments, variable rate leases and 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 but did not have any swap instruments outstanding as of September 30, 2003.

Item 4. Controls and Procedures

Evaluation of disclosure controls and procedures. Under the supervision and with the participation of Puget Energy’s and PSE’s management, including the Companies’ Chief Executive Officer and Chief Financial Officer, Puget Energy and PSE have evaluated the effectiveness of the Companies’ disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of the end of the fiscal quarter covered by this report. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer of Puget Energy and PSE concluded that these disclosure controls and procedures are effective as of the end of the quarter.

Changes in internal controls over financial reporting. There have been no significant changes in Puget Energy’s or PSE’s internal control over financial reporting during the quarter covered by this report that have materially affected, or are reasonably likely to materially affect, Puget Energy’s or PSE’s internal control over financial reporting.

PART II OTHER INFORMATION

Item 1. Legal Proceedings

See the section titled “Proceedings Relating to the Western Power Market” under Item 2 “Management’s Discussion and Analysis of Financial Conditions and Results of Operations” of this Quarterly Report on Form 10-Q.
Contingencies arising out of the normal course of the Company’s business exist at September 30, 2003. The ultimate resolution of these issues in part or in the aggregate 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)	See Exhibit Index for list of exhibits.

	(b)	Reports on Form 8-K

		Filed by Puget Energy & Puget Sound Energy:

		Form 8-K dated July 23, 2003, Item 9 - Regulation FD Disclosure, related to the release of the second quarter earnings.

		Form 8-K dated September 2, 2003, Item 5 - Other Events, related to settlement agreement regarding FERC's June 25, 2003 show cause order.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on their behalf by the undersigned thereunto duly authorized.

	PUGET ENERGY, INC. PUGET SOUND ENERGY, INC.
	/S/ JAMES W. ELDREDGE
	James W. Eldredge Corporate Secretary and Chief Accounting Officer

Date: November 12, 2003	Chief accounting officer and officer duly authorized to sign this report on behalf of each registrant

EXHIBIT INDEX

The following exhibits are filed herewith:

12.1

Statement setting forth computation of ratios of earnings to fixed charges (1998 through 2002 and 12 months ended September 30, 2003) for Puget Energy.

12.2

Statement setting forth computation of ratios of earnings to fixed charges (1998 through 2002 and 12 months ended September 30, 2003) for PSE.

31.1

Chief Executive Officer certification of Puget Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2

Chief Financial Officer certification of Puget Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.3

Chief Executive Officer certification of Puget Sound Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.4

Chief Financial Officer certification of Puget Sound Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1

Chief Executive Officer certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2

Chief Financial Officer certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.