Puget Sound Energy 10-Q 2004 Q4 Quarterly report

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 endedSeptember 30, 2004
                                                  OR

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

       For the Transition period from ________ to _________

Commission File Number	Exact name of registrant as specified in its charter, state of incorporation, address of principal executive offices, telephone number	I.R.S. Employer Identification Number
1-16305	PUGET ENERGY, INC. A Washington Corporation 10885 N.E. 4th Street, Suite 1200 Bellevue, Washington 98004-5591 (425) 454-6363	91-1969407
1-4393	PUGET SOUND ENERGY, INC. A Washington Corporation 10885 N.E. 4th Street, Suite 1200 Bellevue, Washington 98004-5591 (425) 454-6363	91-0374630

Indicate by check mark whether the registrants: (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
	Yes   X    No

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

Indicate by check mark whether Puget Sound Energy, Inc. is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).
	Yes       No   X

As of October 28, 2004, (i) the number of shares of Puget Energy, Inc. common stock outstanding was 99,684,604 ($.01 par value) and (ii) all of the outstanding shares of Puget Sound Energy, Inc. common stock were held by Puget Energy, Inc.

Table of Contents
Filing Format
Forward-Looking Statements
Part I.	Financial Information
Item 1.	Financial Statements
	Puget Energy, Inc.
	Consolidated Statements of Income - Three and Nine Months Ended
	September 30, 2004 and 2003
	Consolidated Statements of Comprehensive Income - Three and Nine Months Ended
	September 30, 2004 and 2003
	Consolidated Balance Sheets - September 30, 2004 and December 31, 2003
	Consolidated Statements of Cash Flows - Nine Months Ended
	September 30, 2004 and 2003
	Puget Sound Energy, Inc.
	Consolidated Statements of Income - Three and Nine Months Ended
	September 30, 2004 and 2003
	Consolidated Statements of Comprehensive Income - Three and Nine Months Ended
	September 30, 2004 and 2003
	Consolidated Balance Sheets - September 30, 2004 and December 31, 2003
	Consolidated Statements of Cash Flows - Nine Months Ended
	September 30, 2004 and 2003
	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
Signatures
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, Inc. (Puget Energy) and Puget Sound Energy, Inc. (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 and 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, maintenance and construction of electric generating facilities, distribution and transmission facilities (gas and electric), licensing of hydro operations and gas storage facilities, recovery of other capital investments, recovery of power and gas costs, recovery of regulatory assets, and present or prospective wholesale and retail competition;

• financial difficulties and energy supply disruptions 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;

• wholesale market disruption, which may result in a deterioration in market liquidity, increase the risk of counterparty default, affect the regulatory and legislative process in unpredictable ways, limit the availability of and access to capital credit markets, affect wholesale energy prices and/or impede PSE’s ability to manage its energy portfolio risks;

• the effect of wholesale market structures (including, but not limited to, new market design such as Grid West, a regional transmission organization, 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 receivables from the California Independent System Operator (CAISO) and other parties, and the amount of refunds found to be due from PSE to the CAISO or other parties;

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

• general economic conditions in the Pacific Northwest, including any associated impact on PSE’s accounts receivable;

• 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 of gas or electric plant to operate as intended, which if not in proper operating condition or design could limit the capacity of the operating plant;

• gas pipeline failure, whether PSE’s or others’, which may impact PSE’s ability to adequately deliver gas supply to its customers and create other legal or regulatory issues;

• the ability to renew contracts for electric and gas supply and the price of renewal;

• blackouts or large curtailments of transmission systems, whether PSE’s or others’, which can have an impact on PSE’s ability to deliver load to its customers; and

• the ability to relicense 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 within 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, including those 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 conditions and results; and

• 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;

• 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;

• the ability to recover changes in enacted federal, state or local tax laws through revenue in a timely manner;

• changes in, adoption of, and compliance with laws and regulations including 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 or other intellectual property rights to generate revenue;

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

• the impacts of natural disasters such as earthquakes, hurricanes, floods, fires or landslides.

        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
(Dollars in Thousands except per share amounts)
(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
		2004			2003			2004			2003
Operating Revenues:
Electric	$	322,669		$	318,161		$	1,018,256		$	1,014,234
Gas		89,432			78,171			484,603			382,706
Non-utility construction services		99,925			93,142			267,496			256,162
Other		2,925			784			4,005			1,853
Total operating revenues		514,951			490,258			1,774,360			1,654,955
Operating Expenses:
Energy costs:
Purchased electricity		147,589			149,628			517,803			512,542
Purchased gas		44,574			35,469			270,683			179,795
Electric generation fuel		25,130			21,252			60,132			47,415
Residential Exchange		(34,014	)		(32,894	)		(123,799	)		(122,550	)
Unrealized (gain) loss on derivative instruments		1,894			905			(1,042	)		383
Utility operations and maintenance		67,093			67,682			214,149			211,632
Other operations and maintenance		87,361			81,435			232,908			229,072
Depreciation and amortization		62,204			59,159			183,614			176,424
Conservation amortization		4,747			9,897			17,746			23,914
Taxes other than income taxes		46,024			43,176			159,138			147,787
Income taxes		8,524			160			44,307			36,358
Total operating expenses		461,126			435,869			1,575,639			1,442,772
Operating Income		53,825			54,389			198,721			212,183
Other income, net of tax		318			2,663			1,968			5,614
Income before interest charges and minority interest		54,143			57,052			200,689			217,797
Interest Charges:
AFUDC		(1,650	)		(1,034	)		(3,807	)		(2,352	)
Interest charges		44,484			45,879			133,310			140,843
Mandatorily redeemable securities interest expense		23			1,048			68			1,048
Total interest charges		42,857			45,893			129,571			139,539
Minority interest in earnings of consolidated subsidiary		162			156			408			106
Net income before cumulative effect of accounting change		11,124			11,003			70,710			78,152
Cumulative effect of implementation of an accounting change, net of tax		--			--			--			169
Net income		11,124			11,003			70,710			77,983
Less: preferred stock dividends accrual		--			1,118			--			4,779
Income for common stock	$	11,124		$	9,885		$	70,710		$	73,204
Basic common shares outstanding - weighted average		99,580			94,125			99,373			93,930
Diluted common shares outstanding - weighted average		100,043			94,635			99,836			94,440
Basic earnings per common share before cumulative effect of
accounting change	$	0.11		$	0.10		$	0.71		$	0.78
Cumulative effect of accounting change		--			--			--			--
Basic earnings per common share	$	0.11		$	0.10		$	0.71		$	0.78
Diluted earnings per common share before cumulative effect of accounting
change	$	0.11		$	0.10		$	0.71		$	0.77
Cumulative effect of accounting change		--			--			--			--
Diluted earnings per common share	$	0.11		$	0.10		$	0.71		$	0.77

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

PUGET ENERGY, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in Thousands)
(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
		2004			2003			2004			2003
Net income	$	11,124		$	11,003		$	70,710		$	77,983
Other comprehensive income, net of tax:
Unrealized holding losses arising on marketable securities
during the period		--			--			--			(45	)
Reclassification adjustment for realized gains on
marketable securities included in net income		--			30			--			(1,518	)
Foreign currency translation adjustment		(5	)		3			235			65
Unrealized gains on derivative instruments during the period		17			153			11,577			4,212
Reversal of unrealized (gain) loss on derivative
instruments settled during the period		(2,829	)		(2,784	)		(6,910	)		1,535
Deferral related to PCA mechanism		(5,501	)		--			(8,187	)		--
Other comprehensive income (loss)		(8,318	)		(2,598	)		(3,285	)		4,249
Comprehensive income	$	2,806		$	8,405		$	67,425		$	82,232

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

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

ASSETS

	September 30, 2004			December 31, 2003
Utility Plant: (at original cost, including construction work in progress of
$162,090 and $121,622, respectively)
Electric	$	4,361,504		$	4,265,908
Gas		1,845,141			1,749,102
Common		406,395			390,622
Less: Accumulated depreciation and amortization		(2,424,162	)		(2,325,405	)
Net utility plant		4,188,878			4,080,227
Other property and investments:
Investment in Bonneville Exchange Power Contract		44,964			47,609
Goodwill, net		133,069			133,302
Intangibles, net		17,239			18,707
Non-utility property, net		95,024			91,932
Other		108,703			110,543
Total other property and investments		398,999			402,093
Current assets:
Cash		21,211			27,481
Restricted cash		3,777			2,537
Accounts receivable, net of allowance for doubtful accounts		202,423			227,115
Unbilled revenue		75,928			131,798
Purchased gas receivable		18,172			--
Materials and supplies, at average cost		117,081			85,128
Current portion of unrealized gain on derivative instruments		33,386			7,593
Prepayments and other		23,360			12,200
Total current assets		495,338			493,852
Other long-term assets:
Regulatory asset for deferred income taxes		135,662			142,792
Regulatory asset for PURPA contract buyout costs		215,369			227,753
Unrealized gain on derivative instruments		25,076			8,624
PCA mechanism		--			3,605
Other		386,090			315,739
Total other long-term assets		762,197			698,513
Total assets	$	5,845,412		$	5,674,685
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, 2004			December 31, 2003
Capitalization:
Common shareholders' investment:
Common stock $0.01 par value, 250,000,000 shares authorized, 99,676,388
and 99,074,070 shares outstanding, respectively	$	997		$	991
Additional paid-in capital		1,617,164			1,603,901
Earnings reinvested in the business		54,462			58,217
Accumulated other comprehensive loss - net of tax		(11,348	)		(8,063	)
Total shareholders' equity		1,661,275			1,655,046
Redeemable securities and long-term debt:
Preferred stock subject to mandatory redemption		1,889			1,889
Junior subordinated debentures of the corporation payable to a
subsidiary trust holding mandatorily redeemable preferred securities		280,250			280,250
Long-term debt		2,218,042			1,969,489
Total redeemable securities and long-term debt		2,500,181			2,251,628
Total capitalization		4,161,456			3,906,674
Minority interest in a consolidated subsidiary		12,121			11,689
Current liabilities:
Accounts payable		165,052			214,357
Short-term debt		24,511			13,893
Current maturities of long-term debt		90,305			246,829
Purchased gas liability		--			11,984
Accrued expenses:
Taxes		26,568			77,451
Salaries and wages		12,594			12,712
Interest		41,018			32,954
Current portion of unrealized loss on derivative instruments		4,270			3,636
Tenaska disallowance reserve		11,212			--
Other		46,498			46,378
Total current liabilities		422,028			660,194
Long-term liabilities:
Deferred income taxes		808,991			755,235
Other deferred credits		440,816			340,893
Total long-term liabilities		1,249,807			1,096,128
Total capitalization and liabilities	$	5,845,412		$	5,674,685
The accompanying notes are an integral part of the financial statements

PUGET ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)

	Nine Months Ended September 30,
	2004			2003
Operating activities:
Net income	$	70,710		$	77,983
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		183,614			176,424
Deferred income taxes and tax credits - net		65,294			45,339
Net unrealized (gain) loss on derivative instruments		(1,042	)		383
Cash collateral received from energy suppliers		8,520			5,887
Increase (decrease) in Residential Exchange Program		8,452			(18,587	)
Gain on sale of securities		--			(2,889	)
Other		20,588			(1,125	)
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue		80,563			88,759
Materials and supplies		(31,952	)		(20,668	)
Prepayments and other		(11,159	)		(13,614	)
Purchased gas receivable/liability		(30,157	)		(77,034	)
Accounts payable		(49,305	)		(45,704	)
Taxes payable		(50,884	)		(20,334	)
Tenaska disallowance reserve		11,212			--
Accrued expenses and other		7,619			5,237
Net cash provided by operating activities		282,073			200,057
Investing activities:
Construction and capital expenditures-excluding equity AFUDC		(324,292	)		(214,295	)
Energy conservation expenditures		(13,301	)		(11,858	)
Acquisitions by InfrastruX, net of cash acquired		--			(10,590	)
Refundable cash received for customer construction projects		9,497			6,058
Cash received from sale of securities		--			3,161
Restricted cash		(1,240	)		18,832
Other		1,193			2,505
Net cash used by investing activities		(328,143	)		(206,187	)
Financing activities:
Change in short-term debt - net		10,618			(20,782	)
Dividends paid		(65,050	)		(66,273	)
Issuance of common stock		3,914			2,607
Redemption of mandatorily redeemable preferred stock		--			(41,273	)
Issuance of bonds and long-term debt		336,000			320,459
Redemption of trust preferred securities		--			(19,750	)
Redemption of bonds and long-term debt		(243,982	)		(306,446	)
Issuance costs of bonds and other		(1,700	)		(10,995	)
Net cash provided (used) by financing activities		39,800			(142,453	)
Net decrease in cash		(6,270	)		(148,583	)
Cash at beginning of year		27,481			176,669
Cash at end of period	$	21,211		$	28,086
Supplemental cash flow information:
Cash payments for:
Interest (net of capitalized interest)	$	125,262		$	136,205
Income taxes		1,294			(3,777	)
The accompanying notes are an integral part of the financial statements

PUGET SOUND ENERGY, INC.
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in Thousands)
(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
Operating revenues:
Electric	$	322,669		$	318,161		$	1,018,256		$	1,014,234
Gas		89,432			78,171			484,603			382,706
Other		2,925			784			4,005			1,853
Total operating revenues		415,026			397,116			1,506,864			1,398,793
Operating expenses:
Energy costs:
Purchased electricity		147,589			149,628			517,803			512,542
Purchased gas		44,574			35,469			270,683			179,795
Electric generation fuel		25,130			21,252			60,132			47,415
Residential Exchange		(34,014	)		(32,894	)		(123,799	)		(122,550	)
Unrealized (gain) loss on derivative instruments		1,894			905			(1,042	)		383
Utility operations and maintenance		67,093			67,682			214,149			211,632
Other operations and maintenance		277			240			850			761
Depreciation and amortization		57,598			54,942			170,036			164,248
Conservation amortization		4,747			9,897			17,746			23,914
Taxes other than income taxes		42,711			40,228			149,486			138,038
Income taxes		7,064			(1,279	)		40,908			35,515
Total operating expenses		364,663			346,070			1,316,952			1,191,693
Operating income		50,363			51,046			189,912			207,100
Other income, net of tax		356			2,620			1,994			5,620
Income before interest charges		50,719			53,666			191,906			212,720
Interest charges:
AFUDC		(1,650	)		(1,034	)		(3,807	)		(2,352	)
Interest charges		42,699			44,164			128,639			136,653
Mandatorily redeemable securities interest expense		23			1,048			68			1,048
Total interest charges		41,072			44,178			124,900			135,349
Net income before cumulative effect of accounting change		9,647			9,488			67,006			77,371
Cumulative effect of implementation of an accounting change, net of tax		--			--			--			169
Net income		9,647			9,488			67,006			77,202
Less: preferred stock dividends accrual		--			1,118			--			4,779
Income for common stock	$	9,647		$	8,370		$	67,006		$	72,423
The accompanying notes are an integral part of the financial statements

PUGET SOUND ENERGY, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in Thousands)
(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
Net income	$	9,647		$	9,488		$	67,006		$	77,202
Other comprehensive income, net of tax:
Unrealized holding losses on marketable securities arising
during the period		--			--			--			(45	)
Reclassification adjustment for realized gains on
marketable securities included in net income		--			30			--			(1,518	)
Unrealized gains on derivative instruments
during the period		17			153			11,577			4,212
Reversal of unrealized (gain) loss on derivative
instruments settled during the period		(2,829	)		(2,784	)		(6,910	)		1,535
Deferral related to PCA mechanism		(5,501	)		--			(8,187	)		--
Other comprehensive income (loss)		(8,313	)		(2,601	)		(3,520	)		4,184
Comprehensive income	$	1,334		$	6,887		$	63,486		$	81,386
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, 2004			December 31, 2003
Utility plant: (at original cost, including construction work in
progress of $162,090 and $121,622, respectively)
Electric	$	4,361,504		$	4,265,908
Gas		1,845,141			1,749,102
Common		406,395			390,622
Less: Accumulated depreciation and amortization		(2,424,162	)		(2,325,405	)
Net utility plant		4,188,878			4,080,227
Other property and investments		155,911			160,280
Current assets:
Cash		14,698			14,778
Restricted cash		3,777			2,537
Accounts receivable, net of allowance for doubtful accounts		105,637			155,649
Unbilled revenues		75,928			131,798
Purchased gas receivable		18,172			--
Materials and supplies, at average cost		107,376			77,206
Current portion of unrealized gain on derivative instruments		33,386			7,593
Prepayments and other		13,558			6,285
Total current assets		372,532			395,846
Other long-term assets:
Regulatory asset for deferred income taxes		135,662			142,792
Regulatory asset for PURPA contract buyout costs		215,369			227,753
Unrealized gain on derivative instruments		25,076			8,624
PCA mechanism		--			3,605
Other		385,260			315,660
Total other long-term assets		761,367			698,434
Total assets	$	5,478,688		$	5,334,787
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, 2004			December 31, 2003
Capitalization:
Common shareholder's investment:
Common stock ($10 stated value) - 150,000,000 shares authorized,
85,903,791 shares outstanding	$	859,038		$	859,038
Additional paid-in capital		608,042			604,451
Earnings reinvested in the business		101,316			100,186
Accumulated other comprehensive loss - net of tax		(11,726	)		(8,206	)
Total shareholder's equity		1,556,670			1,555,469
Redeemable securities and long-term debt:
Preferred stock subject to mandatory redemption		1,889			1,889
Junior subordinated debentures of the corporation payable to a subsidiary
trust holding mandatorily redeemable preferred securities		280,250			280,250
Long-term debt		2,064,358			1,950,347
Total redeemable securities and long-term debt		2,346,497			2,232,486
Total capitalization		3,903,167			3,787,955
Current liabilities:
Accounts payable		153,951			206,465
Current maturities of long-term debt		82,211			102,658
Purchased gas liability		--			11,984
Accrued expenses:
Taxes		26,220			82,342
Salaries and wages		12,594			12,712
Interest		41,018			32,954
Current portion of unrealized loss on derivative instruments		4,270			3,636
Tenaska disallowance reserve		11,212			--
Other		23,504			26,514
Total current liabilities		354,980			479,265
Long-term liabilities:
Deferred income taxes		785,904			731,944
Other deferred credits		434,637			335,623
Total long-term liabilities		1,220,541			1,067,567
Total capitalization and liabilities	$	5,478,688		$	5,334,787
The accompanying notes are an integral part of the financial statements

PUGET SOUND ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)

	Nine Months Ended September 30,
	2004			2003
Operating activities:
Net income	$	67,006		$	77,202
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		170,036			164,248
Deferred income taxes and tax credits - net		65,498			36,701
Net unrealized (gain) loss on derivative instruments		(1,042	)		383
Cash collateral received from energy suppliers		8,520			5,887
Increase (decrease) in Residential Exchange Program		8,452			(18,587	)
Gain on sale of securities		--			(2,889	)
Other		21,827			689
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue		105,883			93,788
Materials and supplies		(30,170	)		(20,068	)
Prepayments and other		(7,272	)		(8,072	)
Purchased gas receivable/liability		(30,157	)		(77,034	)
Accounts payable		(52,514	)		(44,398	)
Taxes payable		(56,123	)		(17,159	)
Tenaska disallowance reserve		11,212			--
Accrued expenses and other		4,491			940
Net cash provided by operating activities		285,647			191,631
Investing activities:
Construction expenditures - excluding equity AFUDC		(311,408	)		(203,941	)
Energy conservation expenditures		(13,301	)		(11,858	)
Restricted cash		(1,240	)		18,832
Refundable cash received for customer construction projects		9,497			6,058
Cash received from sale of securities		--			3,161
Other		1,098			3,955
Net cash used by investing activities		(315,354	)		(183,793	)
Financing activities:
Change in short-term debt - net		--			(21,010	)
Dividends paid		(65,876	)		(66,273	)
Issuance of bonds		200,000			311,860
Redemption of mandatorily redeemable preferred stock		--			(41,273	)
Redemption of trust preferred securities		--			(19,750	)
Redemption of bonds		(106,447	)		(306,446	)
Issuance cost of bonds and other		1,950			(8,478	)
Net cash provided (used) by financing activities		29,627			(151,370	)
Net decrease in cash		(80	)		(143,532	)
Cash at beginning of year		14,778			161,475
Cash at end of period	$	14,698		$	17,943
Supplemental cash flow information:
Cash payments for:
Interest (net of capitalized interest)	$	120,615		$	132,026
Income taxes		1,294			(696	)
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, Inc. (Puget Energy) is an exempt public utility holding company under the Public Utility Holding Company Act of 1935. Puget Energy owns Puget Sound Energy, Inc. (PSE) and has a 90.9% ownership interest in InfrastruX Group, Inc. (InfrastruX). PSE is a public utility incorporated in the State of Washington and furnishes electric and gas services in a territory covering 6,000 square miles, primarily in the Puget Sound region. InfrastruX is a non-regulated construction service company incorporated in the State of Washington, which provides construction services to electric and gas utility companies located primarily in the midwest, Texas, south-central and eastern United States regions.
        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 90.9% 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, 2003.

(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 99,580,000 and 99,373,000 for the three and nine months ended September 30, 2004, respectively, and 94,125,000 and 93,930,000 for the three and nine months ended September 30, 2003, respectively.
        Puget Energy’s diluted earnings per common share have been computed based on weighted average common shares outstanding of 100,043,000 and 99,836,000 for the three and nine months ended September 30, 2004, respectively, and 94,635,000 and 94,440,000 for the three and nine months ended September 30, 2003, 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. One minor non-utility business segment, a PSE real estate investment and development subsidiary, is described as other. Reconciling items between segments are not material. Financial data for business segments are as follows:

(Dollars in Thousands) Three Months Ended September 30, 2004	PSE			InfrastruX		Other			Total
Revenues	$	412,101		$	99,925	$	2,925		$	514,951
Depreciation and amortization		57,534			4,606		64			62,204
Income tax		6,254			1,567		703			8,524
Operating income		48,738			3,607		1,480			53,825
Interest charges, net of AFUDC		41,072			1,730		55			42,857
Minority interest in earnings		--			162		--			162
Net income		8,126			1,677		1,321			11,124
Goodwill, net at September 30, 2004	$	--		$	133,069	$	--		$	133,069
Total assets at September 30, 2004		5,409,049			366,462		69,901			5,845,412
Three Months Ended September 30, 2003	PSE			InfrastruX		Other			Total
Revenues	$	396,332		$	93,142	$	784		$	490,258
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, net of AFUDC		44,178			1,662		53			45,893
Minority interest in earnings		--			156		--			156
Net income (loss)		9,396			1,616		(9	)		11,003
Nine Months Ended September 30, 2004	PSE			InfrastruX		Other			Total
Revenues	$	1,502,859		$	267,496	$	4,005		$	1,774,360
Depreciation and amortization		169,845			13,577		192			183,614
Income tax		40,153			3,685		469			44,307
Operating income		188,148			9,186		1,387			198,721
Interest charges, net of AFUDC		124,900			4,514		157			129,571
Minority interest in earnings		--			408		--			408
Net income		65,347			4,237		1,126			70,710
Nine Months Ended September 30, 2003	PSE			InfrastruX		Other			Total
Revenues	$	1,396,940		$	256,162	$	1,853		$	1,654,955
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, net of AFUDC		135,349			4,119		71			139,539
Minority interest in earnings		--			106		--			106
Net income		74,939			1,007		2,037			77,983
At December 31, 2003	PSE			InfrastruX		Other			Total
Goodwill, net	$	--		$	133,302	$	--		$	133,302
Total assets		5,257,157			342,332		75,196			5,674,685

(4)     Accounting for Derivative Instruments and Hedging Activities

        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, 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 normal sale exemption. Those contracts that do not meet normal purchase normal sale exemption or cash flow hedge criteria are marked-to-market to current earnings in the income statement, subject to deferral under SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation,” (SFAS No. 71) due to the Power Cost Adjustment (PCA) mechanism.
        During the three months ended September 30, 2004, 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 $1.9 million compared to a decrease in earnings of approximately $0.9 million for the three months ended September 30, 2003. In 2004, a portion of the total unrealized gain was deferred in accordance with SFAS No. 71 due to the Company expecting to reach the $40 million cap under the PCA mechanism in the fourth quarter of 2004. When these transactions are realized, they will be reflected in the PCA calculation.
        During the nine months ended September 30, 2004, the Company recorded an increase in earnings for the change in the market value of derivative instruments not meeting cash flow hedge criteria of approximately $1.0 million compared to a decrease in earnings of approximately $0.4 million for the nine months ended September 30, 2003.
        PSE has a contract with a counterparty whose debt ratings have been below investment grade since 2002. The contract, a physical gas supply contract for one of PSE’s electric generating facilities, was marked-to-market beginning in the fourth quarter of 2003. Although the counterparty continues to fully perform on the physical supply contract, the counterparty’s credit ratings have remained weak. Prior to October 1, 2003, the contract was designated as a normal purchase under SFAS No. 133. PSE has concluded that it is appropriate to reserve the mark-to-market gain on this contract due to the credit quality of the counterparty in accordance with SFAS No. 133 guidance, as management deemed that delivery is not probable through the term of the contract, which expires December 2008. There was no impact on earnings for the three and nine months ended September 30, 2004.
        In the first quarter of 2004, the counterparty of another physical gas supply contract for one of PSE’s electric generating facilities notified PSE that it would be unable to deliver physical gas supply beginning in November 2005 through the end of the contract in June 2008. Since physical delivery for the life of the contract was no longer probable, the contract no longer met the criteria for normal purchase exemption under SFAS No. 133. Therefore, the contract was marked-to-market in the first quarter of 2004, with an offsetting reserve for the portion of the mark-to-market gain applicable to the impaired period of November 2005 through June 2008. The unrealized gain to earnings, net of the reserve, was $0.7 million in the third quarter of 2004. In October 2004, PSE and the counterparty reached a settlement on the non-deliverable period of November 2005 through June 2008. The agreement allows PSE to recover a portion of the present value of the difference in future market prices of physical gas and the original contract price, for a total recovery of approximately $10.1 million. PSE filed a petition with the Washington Commission to defer the counterparty settlement amount as a regulatory liability and amortize the benefit over the period of November 2005 through June 2008 as a reduction in Electric Generation Fuel expense.
        In the third quarter 2004, the Company entered into two treasury lock contracts to hedge against potential rising interest rate exposure for a debt offering anticipated to be performed in the first half of 2005. A treasury lock is a financial arrangement between the Company and a counterparty whereby one of the parties will be required to make a payment to the other party on a specific valuation date based upon the change in value of a 30 year treasury bond. If interest rates rise related to the hedged debt from the date of issuance of the treasury lock instruments, the Company would receive a payment from the counterparty for the change in the bond value. Alternatively, if interest rates decrease related to the hedged debt from the date of issuance of the treasury lock instruments, the Company would pay the counterparty for the change in bond value. These treasury lock contracts were designated under SFAS No. 133 criteria as cash flow hedges, with all changes in market value for each reporting period being presented net of tax in other comprehensive income. When these treasury lock contracts are settled upon issuance of debt, any gain or loss will be amortized from other comprehensive income to interest expense over the 30 year life of the issued debt. At September 30, 2004, the unrealized loss associated with these two treasury lock contracts was $4.3 million, net of tax, and is included in other comprehensive income.

(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 four to 20 years. Identifiable intangible assets are as follows:

(Dollars in thousands) At September 30, 2004	Gross Intangibles		Accumulated Amortization		Net Intangibles
Covenant not to compete	$	4,178	$	2,524	$	1,654
Developed technology		14,190		2,986		11,204
Contractual customer relationships		4,702		1,256		3,446
Patents		1,025		90		935
Total	$	24,095	$	6,856	$	17,239

(Dollars in thousands) At December 31, 2003	Gross Intangibles		Accumulated Amortization		Net Intangibles
Covenant not to compete	$	4,178	$	2,009	$	2,169
Developed technology		14,190		2,454		11,736
Contractual customer relationships		4,702		747		3,955
Patents		915		68		847
Total	$	23,985	$	5,278	$	18,707

        The identifiable intangible asset amortization expense for the three and nine months ended September 30, 2004 was $0.5 million and $1.5 million, respectively, and $0.4 million and $1.4 million, respectively, for the same periods in 2003. The identifiable intangible assets amortization for future periods based on the current acquisitions will be:

(Dollars in thousands)	2004		2005		2006		2007		2008
Future Intangible Amortization	$	527	$	2,207	$	1,732	$	1,385	$	1,301

(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 the nine months ended September 30:

(Dollars in thousands) At September 30,	2004		2003
Asset retirement obligation at beginning of year	$	3,421	$	--
Liability recognized in the period		--		3,592
Liability settled in the period		--		(255	)
Accretion expense		71		67
Asset retirement obligation at September 30.	$	3,492	$	3,404

(7)     Stock Compensation (Puget Energy Only)

        The Company has various stock-based compensation plans which prior to 2003 were accounted for according to Accounting Principles Board (APB) No. 25, “Accounting for Stock Issued to Employees,” and related interpretations as allowed by SFAS No. 123, “Accounting for Stock-Based Compensation.” In 2003, the Company adopted the fair value based accounting of SFAS No. 123 using the prospective method under the guidance of SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure.” The Company is applying SFAS No. 123 accounting prospectively to stock compensation awards granted in 2003 and future years, while grants that were made in years prior to 2003 will continue to be accounted for using the intrinsic value method of APB No. 25. Had the Company used the fair value method of accounting specified by SFAS No. 123 for all grants at their grant date rather than prospectively implementing 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)	2004			2003			2004			2003
Income for common stock, as reported	$	11,124		$	9,885		$	70,710		$	73,204
Add: Total stock-based employee compensation expense included
in net income, net of tax		966			421			2,433			2,931
Less: Total stock-based employee compensation expense per the
fair value method of SFAS No. 123, net of tax		(976	)		(680	)		(2,653	)		(2,571	)
Pro forma income for common stock	$	11,114		$	9,626		$	70,490		$	73,564
Earnings per share:
Basic as reported	$	0.11		$	0.10		$	0.71		$	0.78
Diluted as reported	$	0.11		$	0.10		$	0.71		$	0.77
Basic and diluted pro forma	$	0.11		$	0.10		$	0.71		$	0.78

(8)     Retirement Benefits

        The following summarizes the net periodic benefit cost for the three months ended September 30.

	Pension Benefits						Other Benefits
(Dollars in thousands)	2004			2003			2004			2003
Service cost	$	2,586		$	2,071		$	42		$	44
Interest cost		6,021			6,102			376			456
Expected return on plan assets		(9,777	)		(9,720	)		(200	)		(234	)
Amortization of prior service cost		797			805			78			77
Recognized net actuarial (gain) loss		282			(672	)		(179	)		(85	)
Amortization of transition (asset) obligation		(276	)		(276	)		104			105
Special recognition of prior service costs		--			48			--			--
Net periodic benefit cost (income)	$	(367	)	$	(1,642	)	$	221		$	363

        The following summarizes the net periodic benefit cost for the nine months ended September 30.

	Pension Benefits						Other Benefits
(Dollars in thousands)	2004			2003			2004			2003
Service cost	$	7,757		$	6,213		$	142		$	131
Interest cost		18,062			18,305			1,252			1,371
Expected return on plan assets		(29,330	)		(29,160	)		(644	)		(701	)
Amortization of prior service cost		2,392			2,415			232			232
Recognized net actuarial (gain) loss		846			(2,016	)		(179	)		(256	)
Amortization of transition (asset) obligation		(828	)		(828	)		314			314
Special recognition of prior service costs		--			143			--			--
Net periodic benefit cost (income)	$	(1,101	)	$	(4,928	)	$	1,117		$	1,091

        The Company previously disclosed in its financial statements for the year ended December 31, 2003 that it expected pension plan contributions to be $11.1 million in 2004. During the three and nine months ended September 30, 2004, the actual cash contributions to the pension plans were $0.3 million and $1.3 million, respectively. In addition, some plan participants chose lump sum pension payments totaling $9.7 million and deferred them under the Company’s deferred compensation plan in the first quarter of 2004. Based on this activity, the Company anticipates contributing an additional $0.1 million to the Company’s non-qualified supplemental retirement plan in 2004.
        During the three and nine months ended September 30, 2004, actual other post-retirement medical benefit plan contributions were $0.5 million and $1.3 million, respectively, and the Company expects to make additional contributions of $0.2 million for a total of $1.5 million in 2004.

(9)     Tenaska Disallowance

        The Washington Commission issued an order on May 13, 2004 determining that PSE did not prudently manage gas costs for the Tenaska electric generating plant and ordered PSE to adjust its PCA deferral account to reflect a one-time disallowance of $25.6 million for the PCA 1 period (July 1, 2002 through June 30, 2003), which was recorded by PSE as a Purchased Electricity expense in the second quarter of 2004. The order also established guidelines for future recovery of Tenaska costs. The amounts were determined to be a $25.6 million one-time disallowance for the PCA 1 period and an estimated disallowance of $11.3 million for the PCA 3 period (July 1, 2004 to June 30, 2005), based upon applying the Washington Commission’s methodology of 50% disallowance on the return on the Tenaska regulatory asset due to projected costs exceeding the benchmark during the period. For the PCA 3 period, approximately $5.6 million would be disallowed in the period July 1, 2004 through December 31, 2004, primarily as a reduction to Electric Operating Revenue, for a cumulative impact on earnings of $31.2 million in 2004 for the PCA 1 and 3 periods for PSE. The PCA 3 reduction in Electric Operating Revenue is the result of the Washington Commission’s order that reflected a reduction in rates of approximately $9.9 million annually. This reduction is to reflect the Washington Commission’s estimate of the Tenaska disallowance for the PCA 3 period. While the Washington Commission did not expressly address the disallowance for the PCA 2 period (July 1, 2003 through June 30, 2004), PSE estimates the disallowance for the PCA 2 period to be approximately $12.2 million if the Washington Commission were to follow the same methodology as they have ordered for the PCA 3 period. While PSE reserves the right to address the merits of any disallowance in its PCA 2 compliance filing, which is currently being reviewed by the Washington Commission staff, PSE recorded a $12.2 million disallowance to Purchased Electricity expense in the second quarter of 2004 for the 50% disallowance of the return on the Tenaska regulatory asset in accordance with the Washington Commission’s methodology discussed in their order of May 13, 2004. PSE anticipates the PCA 2 compliance filing to be concluded no later than the first quarter of 2005. As a result of the disallowance recorded, the PCA customer deferral of $17.6 million at March 31, 2004 was expensed and a reserve was established to offset future PCA customer deferrals. The reserve balance as of September 30, 2004 was $11.2 million, which is expected to be utilized over the remaining months in 2004 as the excess power costs are shared through the PCA mechanism. The Tenaska disallowance for the three months ended September 30, 2004 resulted in a reduction in Electric Operating Revenue of $2.8 million. The cumulative disallowance for the nine months ended September 30, 2004 was $40.6 million, which is comprised of a $4.1 million reduction in Electric Operating Revenue and a $36.5 million one-time disallowance recorded in Purchased Electricity expense. The total for 2004 is expected to be approximately $43.4 million ($28.1 million after-tax).
        Prior to the Tenaska disallowance, PSE’s excess power costs under the PCA mechanism exceeded the $40 million cap established whereas with the Tenaska disallowance the excess power costs at September 30, 2004 are $26.8 million. The excess power costs from September 30, 2004 until the PCA mechanism cap of $40 million is reached, which is expected in November 2004, will be offset by the Tenaska disallowance reserve of $11.2 million for the PCA 1 and 2 periods that was recorded in the second quarter of 2004. PSE does not expect earnings through year-end 2004, based on current market conditions, to be impacted by excess power costs due to the Tenaska disallowance reserve liability recorded in the second quarter of 2004.

        Below is a summary of the Tenaska disallowances by quarter through December 31, 2004:

(Dollars in millions) Quarter ending	7/02 - 6/03 PCA 1 (ordered/final)			7/03 - 6/04 PCA 2 (estimated)			7/04 - 12/04 PCA 3 (estimated)			Total
June 30, 2004	$	25	.6	$	12	.2	$	--		$	37	.8
September 30, 2004		--			--			2	.8		2	.8
December 31, 2004		--			--			2	.8		2	.8
Total	$	25	.6	$	12	.2	$	5	.6	$	43	.4

        In the May 13, 2004 order, the Washington Commission established guidelines and a benchmark to determine PSE’s recovery on the Tenaska regulatory asset starting with the PCA 3 period (July 1, 2004) through the expiration of the Tenaska contract in the year 2011. The benchmark is defined as the original cost of the Tenaska contract adjusted to reflect the 1.2% disallowance from a 1994 Prudence Order.

        The Washington Commission guidelines for determining future recovery of the Tenaska costs (gas costs, recovery of the Tenaska regulatory asset and return on the Tenaska regulatory asset) are as follows:

1. The Washington Commission will determine if PSE’s gas purchasing plan and gas purchases for Tenaska are prudent through the PCA compliance filings.

2. If PSE’s gas purchasing plan and gas purchases for Tenaska are prudent, and if PSE’s actual Tenaska costs fall at or below the benchmark, it will recover fully its Tenaska costs.

3. If PSE’s gas purchasing plan and gas purchases for Tenaska are prudent, but its actual Tenaska costs exceed the benchmark, PSE will only recover 50% of the lesser of:

a) Actual Tenaska costs that exceed the benchmark or;

b) The return on the Tenaska regulatory asset (return on the asset would be added last to all other relevant Tenaska costs).

4. If PSE’s gas purchasing plan or gas purchases are found to be imprudent in a future proceeding, PSE risks disallowance of any and all Tenaska costs.

        The Washington Commission confirmed that if the Tenaska gas costs are deemed prudent, PSE will recover the full amount of actual gas costs and the recovery of the Tenaska regulatory asset even if the benchmark is exceeded.

(10)     Colstrip Generating Facilities

        In September 2004, the owners of Colstrip Units 1 & 2 (PSE and PPL Montana) entered into a tentative settlement agreement with certain homeowners in the Colstrip town site area concerning a lawsuit filed in May 2003. The lawsuit alleged certain domestic water wells may have been contaminated by seepage from a Colstrip Units 1 & 2 effluent holding pond. The tentative settlement agreement would require extending municipal water to the homeowners and abandoning the existing wells. The total estimated cost of the settlement ranges from $1.4 million to $1.5 million. As a result of this tentative settlement agreement, PSE recorded in the third quarter of 2004 a reserve for its 50% ownership of the Colstrip Units 1 & 2 project of $0.7 million. The settlement agreement does not resolve certain other claims by residents within the city limits. PSE cannot predict the outcome or any potential financial impact of the claims by the residents within the city limits at this time.
        The nine months ended September 30, 2004 also includes a $6.9 million charge related to a binding arbitration settlement between PSE and Western Energy Company (WECO), the supplier of coal to Colstrip Units 1 & 2, which was recorded in the second quarter of 2004. The binding decision retroactively set a new baseline cost of coal per ton supplied from July 31, 2001, and is applicable for the remaining term of the coal supply agreement through December 2009. Of the second quarter charge of $6.9 million, $5.0 million is included in the PCA mechanism. PSE had previously accrued a reserve of $1.6 million in the fourth quarter 2003 related to the arbitration.
        The nine months ended September 30, 2004 also includes a loss reserve in the amount of $1.1 million recorded in the second quarter of 2004 related to an order issued by the Minerals Management Service of the United States Department of the Interior on April 29, 2004 to pay additional royalties to WECO concerning coal purchased by PSE for Colstrip Units 3 & 4. The order seeks payment of an additional $1.1 million in royalties for coal mined from federal lands between 1997 and June 30, 2000. During that period, PSE’s coal price was reduced by a settlement agreement entered into in February 1997 among PSE, WECO and Montana Power Company that resolved disputes that were then pending. The order seeks to impute the price charged to PSE based on the other Colstrip Units 3 & 4 owners’ contractual amounts. PSE is supporting WECO’s appeal of the order which was filed on October 1, 2004. The outcome of this matter cannot be predicted at this time.
        In addition, the Minerals Management Service of the United States Department of the Interior issued two orders to WECO in 2002 and 2003 to pay additional royalties concerning coal sold to Colstrip Units 3 & 4 owners. The orders assert that additional royalties are owed as a result of WECO not paying royalties in connection with revenue received by WECO from the Colstrip Units 3 & 4 owners under a coal transportation agreement during the period October 1, 1991 through December 31, 2001. PSE’s share of the alleged additional royalties is $1.8 million, which is equivalent to PSE’s 25% ownership interest in Colstrip Units 3 & 4. The transportation agreement provides for the construction and operation of a conveyor system that runs several miles from the mine to Colstrip Units 3 & 4. WECO has appealed these orders and PSE is monitoring the process. Based upon its review, PSE believes that the Colstrip Units 3 & 4 owners have reasonable defenses in this matter. Neither the outcome of this matter nor the associated costs can be predicted at this time.
        On December 5, 2003, Colstrip Units 1 & 2 and 3 & 4 received an information request from the Environmental Protection Agency (EPA) relating to their compliance with the Clean Air Act New Source Review regulations. PSE is currently in discussions with the EPA concerning the information request. Neither the outcome of this matter nor any potential associated costs can be predicted at this time.

(11)     Other

        On September 24, 2004, the Washington Commission approved PSE’s request for a Purchased Gas Adjustment (PGA) filed on August 31, 2004. The approved request will increase rates and revenues by approximately 17.6% or $121.7 million annually. The increase in PGA rates was to recover higher market prices of natural gas sold to customers. 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 change in PGA rates.
        On July 15, 2004, PSE issued $200 million in floating rate senior notes under its existing $500 million shelf registration statement, reducing the available balance for future issuances under the registration statement to $300 million. The notes float at the three-month LIBOR rate plus 0.30%, mature on July 14, 2006, and can be redeemed at any time after January 15, 2005. PSE used the net proceeds from the sale of the floating rate senior notes to repay outstanding amounts under its commercial paper and accounts receivable securitization programs, including amounts incurred to repay long-term debt. PSE also used the proceeds to redeem $55 million in principal of first mortgage bonds at a premium of 3.68% on August 14, 2004.
        In 2003, the Washington Commission’s Pipeline Safety staff conducted a natural gas standard inspection for three counties within Washington State in which PSE operates gas pipeline activities. The inspection included a review of procedures, records, and operations and maintenance activities. On June 29, 2004, the Washington Commission issued a complaint to PSE related to that inspection. The Washington Commission’s complaint alleges certain violations of Washington Commission regulations and determined a maximum aggregated fine for the violations of $4.5 million, although the Washington Commission’s Pipeline Safety staff recommended a fine of $1.3 million. PSE is reviewing this matter and has been meeting with the Pipeline Safety staff to review their allegations and develop a mutual resolution to this matter. Neither the outcome of this matter nor the associated costs, including potential fines, can be predicted at this time.
        In September 2004, a natural gas fire destroyed a home and took the life of a PSE customer. The cause of the fire remains under investigation by PSE, the Washington Commission and other parties. PSE has tendered the matter to its general liability insurer. Neither the potential regulatory or litigation outcomes of this matter nor the final associated costs can be predicted at this time.
        On April 5, 2004, PSE filed general tariff electric and gas rate cases with the Washington Commission. The rate cases propose increases of 5.8% or $82.8 million annually and 6.8% or $48.9 million annually for electric and gas customers, respectively. These increases are intended to recover costs associated with extending and upgrading facilities to serve a growing number of gas and electric customers as well as strengthen PSE financially to serve its customers. The Washington Commission staff and other intervenors responded to PSE’s general tariff electric and gas rate cases in the third quarter of 2004 and proposed an electric general rate case increase of $21.4 million annually and a gas general rate case increase of $8.1 million annually. PSE filed its rebuttal testimony to the intervenors’ testimony on November 3, 2004 in which PSE revised its proposed electric increase request to 7.3% or $103.3 million annually which reflects updated power costs for increases in natural gas pricing for generating plants. The gas rebuttal testimony revised the proposed gas increase request to 6.3% or $46.2 million annually. The resolution of the general rate cases may be up to an 11-month process from the time the general rate cases were filed.
        On April 23, 2004, the acquisition of a 49.85% interest in the Frederickson 1 generating facility was approved by FERC. Prior to that approval, on April 7, 2004, the Washington Commission had issued an order in PSE’s power cost only rate case granting approval for the acquisition of the Frederickson 1 generating facility. As a result of these approvals, PSE completed the acquisition in the second quarter of 2004 and added $80.8 million in utility plant. In its order, the Washington Commission found the acquisition to be prudent and the costs associated with the generating facility reasonable. The costs associated with the generating facility, including projected baseline gas costs, are approved for recovery in rates.
        On May 13, 2004, the Washington Commission also approved other adjustments to power costs that resulted in an increase of cost recovery in rates of $44.1 million annually, beginning May 24, 2004, which includes the ownership, operation and fuel costs of the Frederickson 1 generating facility.
        Early in 2003, the Colville Confederated Tribes (Colville Tribe) presented a claim to Douglas County PUD based upon allegedly unpaid past annual charges for the Wells Hydroelectric Project (the Project) for the use of Colville tribal lands, principally riverbed along the tribal reservation. The Colville Tribe further claimed that annual charges would be due for periods into the future. Beginning in April 2003, Douglas County PUD and Colville Tribe representatives discussed settlement of these issues. On November 1, 2004, the Douglas County PUD Commission approved entry into a settlement agreement with the Colville Tribe that, subject to FERC approval, will resolve all of the Tribe’s claims. The settlement would allocate 4.5% of the Project’s output to the Tribe effective upon FERC approval through 2018, when the allocation would increase to 5.5%. The allocation would last as long as the Project exists. In addition, under the settlement, Douglas County PUD would pay $13.5 million and convey certain real property to the Colville Tribe. Douglas County PUD would also market the Colville Tribe’s Project output on behalf of the Tribe for a period of time. PSE currently purchases 31.3% of the Project’s output. Upon approval, the settlement will slightly reduce the output available for PSE, and slightly increase the cost of PSE’s purchase under PSE’s existing contract with Douglas County PUD. PSE will support the Douglas County PUD filing for approval of the settlement. PSE cannot predict how long it will take FERC to act upon the application.

(12)     New Accounting Pronouncements

        In January 2003, FASB issued Financial Interpretation No. 46 “Consolidation of Variable Interest Entities” (FIN 46), as further revised in December 2003 with FIN 46R, which clarifies the application of Accounting Research Bulletin No. 51, “Consolidated Financial Statements,” to certain entities in which equity investors do not have a controlling interest or sufficient equity at risk for the entity to finance its activities without additional financial support. FIN 46 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 FIN 46 for all interests in variable interest entities created after January 31, 2003 was effective immediately. For variable interest entities created before February 1, 2003, it was effective July 1, 2003. The adoption of FIN 46R was effective March 31, 2004. The Company has evaluated its contractual arrangements and determined PSE’s 1995 conservation trust off-balance sheet financing transaction meets this guidance, and therefore it was consolidated in the third quarter of 2003. As a result, revenues increased while conservation amortization and interest expense increased by the corresponding amount with no impact on earnings. FIN 46R also impacted the treatment of the Company’s mandatorily redeemable preferred securities of a subsidiary trust holding solely junior subordinated debentures of the corporation (trust preferred securities). Previously, these trust preferred securities were consolidated into the Company’s operations. As a result of FIN 46R, these securities have been deconsolidated and were classified as junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities in the fourth quarter of 2003. This change had no impact on the Company’s results of operations. The Company evaluated its purchase power agreements and determined that three counterparties may be considered variable interest entities. As a result, PSE submitted requests for information to those parties; however, the parties have refused to submit to PSE the necessary information for PSE to determine whether they meet the requirements of a variable interest entity. PSE also determined it does not have a contractual right to such information. PSE will continue to submit requests for information in the future to determine if FIN 46R is applicable.
        For the three purchase power agreements that may be considered variable interest entities under FIN 46R, PSE is required to buy all the generation from these plants, subject to displacement by PSE, at rates set forth in the purchase power agreements. If at any time the counterparties cannot deliver energy to PSE, PSE would have to buy energy in the wholesale market at prices which could be higher or lower than the purchase power agreement prices. PSE’s Purchased Electricity expense for the three and nine months ended September 30, 2004 for these three entities was $70.9 million and $180.9 million, respectively.
        In December 2003, SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits” (SFAS No. 132R), was revised to include various additional disclosure requirements. SFAS No. 132R is effective for fiscal years ending after December 15, 2003.
        The Emerging Issues Task Force of the Financial Accounting Standards Board (EITF) at its July 2003 meeting came to a consensus concerning EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ as Defined in Issue No. 02-03.” The consensus reached was that determining realized gains and losses on physically settled derivative contracts not held for trading purposes reported in the income statement on a gross or net basis is a matter of judgment that depends on the relevant facts and circumstances. Based on the guidance in EITF No. 03-11, the Company determined that its non-trading derivative instruments should be reported net and implemented this treatment effective January 1, 2004. Consequently, both Electric Operating Revenues and Purchased Electricity for the three and nine months ended September 30, 2003 have been reduced by $25.3 million and $94.4 million, respectively, to reflect the netting addressed by EITF No. 03-11 with no effect on net income.
        In March 2004, the EITF came to a consensus concerning EITF Issue No. 03-16, “Accounting for Investments in Limited Liability Companies”. The consensus reached was that an investment in a limited liability company (LLC) should be accounted for using the equity method for investments greater than 3% to 5%. The adoption of EITF No. 03-16 is effective for reporting periods beginning after June 15, 2004, with any adjustments being accounted for as a cumulative effect of a change in accounting principle. The Company reviewed its investments and determined one investment held by PSE met the criteria established in EITF No. 03-16. The adoption of the equity method had no cumulative effect on earnings for the three and nine months ended September 30, 2004 as PSE had been carrying this investment at fair value, which represents the equity basis, since December 31, 2003.
        On June 17, 2004, FASB issued a proposed interpretation titled “Accounting for Conditional Asset Retirement Obligations” which is an interpretation of SFAS No. 143 “Accounting for Asset Retirement Obligations”. The proposed interpretation would address the issue of whether SFAS No. 143 requires an entity to recognize a liability for a legal obligation to perform asset retirement when the asset retirement activities are conditional on a future event, and if so, the timing and valuation of the recognition. This proposed interpretation could potentially have an impact on the Company as assets that were previously outside the scope of SFAS No. 143 may be subject to its terms based on the interpretation. Comments on the proposed interpretation were due on August 1, 2004. The FASB is in the process of reviewing the comment letters and anticipates issuing a final interpretation with an effective date for fiscal years ending after December 15, 2005.

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.

Overview

        Puget Energy is an energy services holding company and all of its operations are conducted through its two subsidiaries. These subsidiaries are PSE, a regulated electric and gas utility company, and InfrastruX, a utility construction and services company.

Puget Sound Energy
        PSE generates revenues from the sale of electric and gas services, mainly to residential and commercial customers within Washington State. A majority of PSE’s revenues are generated in the first and fourth quarters during the winter heating season in Washington State.
        As a regulated utility company, PSE is subject to Federal Energy Regulatory Commission (FERC) and Washington Utilities and Transportation Commission (Washington Commission) regulation which may impact a large array of business activities, including limitation of future rate increases; issuance of orders that may negatively impact earnings; licensing of PSE-owned generation facilities; and other FERC and Washington Commission directives that may impact PSE’s long-term goals. In addition, PSE is subject to risks inherent to the utility industry as a whole including weather changes affecting purchases and sales of energy; outages at owned and non-owned generation plants where energy is obtained; storms which can damage distribution and transmission lines; and energy trading and wholesale market stability over time.
        PSE’s main operational goal is to provide cost-effective and stable energy prices to its customers. To help accomplish this goal, PSE is attempting to be more self-sufficient in energy generation resources. Owning more generation resources rather than purchasing power through short-term contracts and on the wholesale market is intended to allow customers’ rates to remain stable. PSE has initiated the following transactions to increase its owned pool of generation resources during the nine months ended September 30, 2004:

• Purchased a 49.85% interest in a 250 MW capacity gas-fired generation facility within Western Washington, which went into service in May 2004.

• Signed a two-year purchase power agreement in the second quarter of 2004 with a utility for 85 MW of energy with delivery beginning January 1, 2005.

• Signed a non-binding letter of intent in September 2004 to purchase a wind generation facility with up to 220 MW of generation to be developed in central Washington State.

        These transactions are part of PSE’s long-term electric Least Cost Plan that was filed August 29, 2003 with the Washington Commission. The plan supports a strategy of diverse resource acquisitions including resources fueled by natural gas and coal, renewable resources and shared resources.

InfrastruX
        InfrastruX generates revenues mainly from maintenance services and construction contracts in the midwest, Texas, south-central and eastern United States regions. Generally, a majority of its revenues are generated during the second and third quarters, which are typically the most productive quarters for the construction industry due to longer daylight hours and generally better weather conditions.

        InfrastruX is subject to risks associated with the construction industry including the ability to adequately estimate costs of projects that are bid upon under fixed-fee contracts; continued economic downturn that limits the amount of projects available thereby reducing available profit margins from increased competition; the ability to integrate acquired companies within its operations without significant cost; and the ability to obtain adequate financing and bonding coverage to continue expansion and growth.
        InfrastruX’s goals are continued growth and expansion into underdeveloped utility construction markets and to utilize its acquired entities to capitalize on depth of expertise, asset base, geographical location and workforce to provide services that local contractors cannot. InfrastruX has acquired 12 entities since 2000 to fuel growth and diversify into these underdeveloped markets.
        Puget Energy is currently evaluating strategic options related to its investment in InfrastruX.

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, 2004 was $11.1 million on operating revenues of $515.0 million compared with net income of $11.0 million on operating revenues of $490.3 million for the same period in 2003. Income for common stock was $11.1 million for the three months ended September 30, 2004 compared to income for common stock of $9.9 million for the same period in 2003. Puget Energy’s basic and diluted earnings per common share was $0.11 for the three months ended September 30, 2004 compared to basic and diluted earnings per common share of $0.10 for the same period in 2003.
        Puget Energy’s income for common stock for the three months ended September 30, 2004 was positively impacted by higher electric margins, lower interest expense and lower preferred stock dividends offset by higher depreciation expense as compared to the same period in 2003. The three months ended September 30, 2003 was positively impacted by a federal tax benefit true-up and a gain on corporate-owned life insurance which did not recur in 2004.
        For the nine months ended September 30, 2004, Puget Energy’s net income was $70.7 million on operating revenues of $1.8 billion compared to net income of $78.0 million on operating revenues of $1.7 billion for the same period in 2003. Income for common stock was $70.7 million for the nine months ended September 30, 2004 compared to $73.2 million for the same period in 2003. Basic and diluted earnings per common share were $0.71 for the nine months ended September 30, 2004 and $0.78 and $0.77, respectively, for the same period in 2003.
        Puget Energy’s income for common stock for the nine months ended September 30, 2004 was negatively impacted by a decrease in Puget Sound Energy’s net income for common stock of $5.4 million. The negative change was due primarily to a $24.5 million after-tax disallowance of the return on the regulatory asset for the Tenaska gas supply buyout cost under PSE’s Power Cost Adjustment (PCA) mechanism as a result of a Washington Commission order in PSE’s Power Cost Only Rate Case (PCORC). See further details under PSE’s “Electric Rate Matters”. In addition, the nine months ended September 30, 2004 was not impacted by one-time federal tax benefits compared to the same period in 2003. These negative impacts were partially offset by higher retail energy sales resulting from more normal weather temperatures in the first quarter of 2004 as compared to warmer temperatures in the same period in 2003 and lower interest expense and preferred stock dividends. In addition, PSE was not impacted by excess power costs in 2004 compared to 2003 as a result of reaching the PCA mechanism cap in 2003. Puget Energy’s income for common stock was also positively impacted by a $3.2 million increase in earnings from InfrastruX (net of minority interest) for the nine months ended September 30, 2004 compared to the same period in 2003. This positive impact from InfrastruX was due in part to improved operating efficiencies and improvement in weather conditions compared to 2003, which positively impacted productivity.

Puget Sound Energy
        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, with temperature variations from historical normal levels in these quarters having a higher impact on margin and net income than in the second and third quarters. Varying wholesale electric prices and the amount of hydroelectric energy supplies available to PSE also make quarter-to-quarter comparisons difficult.
        To meet customer demand, PSE dispatches resources in its power supply portfolio primarily consisting of 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 Energy Risk Management Committee oversees energy portfolio exposures.
        Electric margin increased $9.7 million for the three months ended September 30, 2004 compared with the same period in 2003. This increase was primarily due to PSE not being impacted by excess power costs in the third quarter of 2004 as compared to excess power costs of $5.8 million for the same period in 2003. In addition, the PCORC tariff rate increase effective May 24, 2004 provided $2.4 million to electric margin for the three months ended September 30, 2004. The tariff rate increase was designed to recover operation and maintenance costs of the new Frederickson 1 generating facility. The higher electric margin for the three months ended September 30, 2004 was partially offset by $2.8 million in lower Electric Operating Revenue as a result of the Tenaska disallowance ordered by the Washington Commission in the PCORC.
        Electric margin decreased $6.5 million for the nine months ended September 30, 2004 compared to the same period in 2003 primarily as a result of the disallowance ordered by the Washington Commission in the PCORC. The disallowance resulted in $4.1 million lower Electric Operating Revenue and a one-time $36.5 million power cost disallowance. The lower electric margin for the nine months ended September 30, 2004 was partially offset by PSE not being impacted by excess power costs in 2004 as compared to excess power costs of $24.7 million in 2003 and by more normal temperatures in the first quarter of 2004 as compared to warmer than normal temperatures in the same period in 2003. In addition, the PCORC tariff rate increase, which is designed to recover operation and maintenance costs of the new Frederickson 1 generation facility, provided $3.3 million to the electric margin for the nine months ended September 30, 2004.
        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, 2004 and 2003 is detailed further as follows:

Electric Margin for the Three and Nine Months Ended
September 30, 2004 and September 30, 2003
(Dollars in Millions)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
Electric retail sales revenue	$	293	.7	$	279	.3	$	942	.1	$	912	.7
Electric transportation revenue		2	.7		2	.6		7	.3		9	.2
Other electric revenue-gas supply resale		1	.6		0	.3		5	.6		7	.9
Total electric revenue for margin		298	.0		282	.2		955	.0		929	.8
Adjustments for amounts included in revenue:
Pass-through tariff items		(5	.3)		(11	.0)		(19	.4)		(35	.4)
Pass-through revenue-sensitive taxes		(21	.3)		(20	.5)		(68	.3)		(65	.9)
Residential exchange credit		34	.0		32	.9		123	.8		122	.6
Net electric revenue for margin		305	.4		283	.6		991	.1		951	.1
Minus power costs:
Fuel		(25	.1)		(21	.3)		(60	.1)		(47	.4)
Purchased electricity, net of sales to other
utilities and marketers		(133	.4)		(122	.7)		(464	.2)		(449	.3)
Total electric power costs		(158	.5)		(144	.0)		(524	.3)		(496	.7)
Electric margin before PCA		146	.9		139	.6		466	.8		454	.4
Tenaska disallowance reserve through May 23, 2004			--			--		(36	.5)		--
Tenaska reserve turnaround		2	.4			--		2	.4		--
Power cost deferred under the PCA mechanism			--			--		19	.3		4	.1
Electric margin	$	149	.3	$	139	.6	$	452	.0	$	458	.5

        Gas margin increased $0.7 million and $1.6 million for the three and nine months ended September 30, 2004 compared to the same periods in 2003. The increase for the nine months ended September 30, 2004 was primarily a result of more normal temperatures in the first quarter of 2004 compared to warmer than normal temperatures in the first quarter of 2003 and increased customers.
        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, 2004 and 2003 is detailed further as follows:

Gas Margin for the Three and Nine Months Ended
September 30, 2004 and September 30, 2003
(Dollars in Millions)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
Gas retail revenue	$	83	.0	$	71	.9	$	465	.0	$	364	.0
Gas transportation revenue		3	.1		3	.6		9	.7		10	.5
Total gas revenue for margin		86	.1		75	.5		474	.7		374	.5
Adjustments for amounts included in revenue:
Gas revenue hedge		--			--			--			0	.2
Pass-through tariff items		(0	.4)		(0	.4)		(2	.0)		(2	.9)
Pass-through revenue-sensitive taxes		(6	.8)		(6	.0)		(39	.0)		(30	.6)
Net gas revenue for margin		78	.9		69	.1		433	.7		341	.2
Minus purchased gas costs		(44	.6)		(35	.5)		(270	.7)		(179	.8)
Gas margin	$	34	.3	$	33	.6	$	163	.0	$	161	.4

        The changes to items affecting net income for the three and nine months ended September 30, 2004, compared to the same periods in 2003, are summarized in the table below.

Comparative Three and Nine Months Ended
September 30, 2004 vs. September 30, 2003
Increase (Decrease)
(Dollars in Millions)

	Three Months Ended Change			Nine Months Ended Change
Operating revenue changes:
Electric:
Residential sales	$	7	.9	$	16	.8
Commercial sales		8	.6		17	.6
Industrial sales		0	.7		(1	.0)
Transportation sales		0	.1		(1	.9)
Sales to other utilities and marketers		(10	.3)		(28	.5)
Other		(2	.5)		1	.0
Total electric operating change		4	.5		4	.0
Gas:
Residential sales		5	.8		58	.7
Commercial sales		4	.5		36	.0
Industrial sales		0	.9		6	.3
Transportation sales		(0	.5)		(0	.8)
Other		0	.6		1	.7
Total gas operating change		11	.3		101	.9
Other revenues change		2	.1		2	.2
Total operating revenue change		17	.9		108	.1
Operating expense changes:
Energy costs:
Purchased electricity		(2	.0)		5	.3
Purchased gas		9	.1		90	.9
Electric generation fuel		3	.9		12	.7
Residential exchange power cost credit		(1	.1)		(1	.2)
Unrealized gain/loss on derivative instruments		1	.0		(1	.4)
Utility operations and maintenance:
Production operations and maintenance		0	.5		(0	.8)
Low income program pass through expenses		(1	.0)		(3	.7)
Other utility operations and maintenance		(0	.1)		7	.1
Depreciation and amortization		2	.7		5	.8
Conservation amortization		(5	.2)		(6	.2)
Taxes other than income taxes		2	.5		11	.4
Income taxes		8	.3		5	.4
Total operating expense change		18	.6		125	.3
Other income change (net of tax)		(2	.2)		(3	.6)
Interest charges change		(3	.1)		(10	.4)
Cumulative effect of an accounting change (net of tax)		--			(0	.2)
Net income change	$	0	.2	$	(10	.2)

Operating Revenues — Electric
        Electric operating revenues for the three months ended September 30, 2004 were $322.7 million, an increase of $4.5 million compared to the same period in 2003, due primarily to higher sales to residential and commercial customers which increased by $7.9 million and $8.6 million, respectively. Included in the residential and commercial sales increase was the PCORC tariff rate increase effective May 24, 2004. The tariff rate increase provided an increase of $4.5 million and $4.8 million in residential and commercial sales revenue, respectively. Residential and commercial sales volumes for the three months ended September 30, 2004 increased by 75.9 million kWh and 87.9 million kWh, respectively, or 4.1% and 4.3%, respectively, compared to the same period in 2003. These volume increases were mainly attributable to slightly warmer temperatures in July and August 2004 as compared to 2003, which increased electric load. These increases were partially offset with lower sales to other utilities and marketers which decreased $10.3 million for the three months ended September 30, 2004. Sales to other utilities and marketers volumes decreased 244.8 million kWh or 39.2% compared to the same period in 2003. The sales to other utilities and marketers decreased mainly due to higher retail electric sales in 2004 compared to 2003 which reduced excess generation available for sale in the wholesale market. The hydro conditions for the three months ended September 30, 2003 improved slightly compared to the forecasted adverse hydro conditions providing more hydro generation than was originally forecasted. The result of these conditions in 2003 created excess generation to sell in the 2003 wholesale market.
        Electric operating revenues for the nine months ended September 30, 2004 were $1,018.3 million, an increase of $4.0 million compared to the same period in 2003, due primarily to higher sales to residential and commercial customers which increased $16.8 million and $17.6 million, respectively. Included in the residential and commercial sales increases was the PCORC tariff rate increase of $6.1 million and $6.4 million, respectively. Residential and commercial sales volumes for the nine months ended September 30, 2004 increased by 187.6 million kWh and 215.2 million kWh, respectively, or 2.6% and 3.5%, respectively, compared to the same period in 2003. These volumes were mainly attributable to more normal temperatures in the first quarter of 2004 as compared to warmer than normal temperatures in the same period in 2003, and slightly warmer temperatures in July and August of 2004 as compared to 2003. These increases were partially offset with lower sales to other utilities and marketers which decreased $28.5 million for the nine months ended September 30, 2004. Sales to other utilities and marketers volumes decreased 810.7 million kWh or 46.6% compared to the same period in 2003. The sales to other utilities and marketers decreased mainly due to lower generation available for sale in the wholesale market in 2004 compared to 2003. In 2003, warmer than normal temperatures, mainly in the first quarter, and improved hydro conditions as compared to the original hydro forecast provided excess energy supplies for sale to the wholesale market.
        PSE’s other electric operating revenues for the three and nine months ended September 30, 2004 compared to 2003 decreased $2.5 million and increased $1.0 million, respectively. The decrease for the three months ended September 30, 2004 was due primarily to changes in unbilled electric revenue. The increase for the nine months ended September 30, 2004 was due in part to the implementation of FIN 46R. FIN 46R required PSE to consolidate PSE’s 1995 conservation trust transaction in the third quarter of 2003. The consolidation increased revenues, while conservation amortization and interest expense increased by a corresponding amount with no impact on earnings. This revenue increase was partially offset with changes in unbilled electric revenue for the nine months ended September 30, 2004.
        For the three and nine months ended September 30, 2004, the benefits of the Residential and Farm Energy Exchange Benefit credited to customers were $34.0 million and $123.8 million, respectively, with a related offset to power costs. PSE received payments from the Bonneville Power Administration (BPA) in the amount of $44.0 million and $132.0 million during the three and nine months ended September 30, 2004, respectively. The difference between the customers’ credit and the amount received from BPA either increases or decreases the previously deferred amount owed to customers and the aggregated deferred amount is recorded on PSE’s balance sheet as restricted cash. Absent certain adjustments tied to the BPA rate adjustment clause, the modified amended settlement agreement provides for payments from BPA in the amount of $630.6 million for the period January 2003 through September 2006 and for a pass-through of the same amount to eligible residential and small farm customers. See discussion under PSE’s “Electric Rate Matters” for additional residential exchange information.
        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, 2004, PSE’s receivable from the California Independent System Operators (CAISO) and other counterparties, net of reserves, was $21.3 million. See the discussion of the “California Receivable and California Refund Proceeding ” under “Proceedings Relating to the Western Power Market.”

Operating Revenues — Gas
        Gas operating revenues for the three and nine months ended September 30, 2004 were $89.4 million and $484.6 million, respectively, an increase of $11.3 million and $101.9 million, respectively, compared to the same periods in 2003. Increases in the purchased gas adjustment (PGA) rate increased revenues approximately $8.2 million and $90.0 million for the three and nine month periods ended September 30, 2004, respectively. The remaining increase of $3.1 million in gas revenues for the three months ended September 30, 2004 was attributable to higher gas therm sales volumes from customer growth and slightly cooler temperatures in September 2004 as compared to the same period in 2003. Gas sales volumes increased 0.8 million therms or 0.6%, and customer base increased by 3.9%. The remaining increase of $11.9 million in gas revenues for the nine months ended September 30, 2004 was mainly attributable to an increase in commercial customers and customers switching from transportation tariffs. Volumes to retail commercial customers increased 4.8 million therms or 2.7%. These customer increases were a result of previous transportation only customers becoming retail commercial customers. Retail commercial volume increases sales revenue since retail commercial tariff rates include the cost of gas in the tariff rate compared to transportation tariff rates which do not include the cost of gas.
        PSE has a PGA mechanism in retail gas rates to recover expected gas costs (gas supply and transportation costs) by deferring as a receivable or liability any gas costs that exceed or fall short of the amount in PGA rates and accrues interest on any deferred balances under the PGA. Therefore, PSE’s gas margin and net income are not affected by changes in the PGA rates. The PGA had a receivable balance at September 30, 2004 of $18.2 million and a liability balance of $12.0 million at December 31, 2003.
        The following rate adjustments were approved by the Washington Commission in relation to the PGA during 2003 that affect changes in gas revenue for the three and nine months ended September 30, 2004 compared to the same periods in the prior year:

Effective Date	Percentage Increase in Rates	Annual Increase in Revenues (Dollars in millions)
October 1, 2003	13.3 %	$	78	.8
April 10, 2003	20.1 %		103	.6

Operating Expenses
        Purchased electricity expenses decreased $2.0 million and increased $5.3 million for the three and nine months ended September 30, 2004, respectively, compared to the same periods in 2003. The increase for the nine months ended September 30, 2004 was primarily due to a $37.8 million disallowance of the return on the Tenaska gas supply regulatory asset. The increase was partially offset by lower purchases due to increased generation at PSE generating facilities in the third quarter of 2004 compared to the same period in 2003, and lower wholesale electricity prices in the first quarter of 2004 compared to the same period in 2003.
        The August 5, 2004 Columbia Basin Runoff Forecast published by the National Weather Service Northwest River Forecast Center indicated that the total observed runoff into the Grand Coulee reservoir for the period January through September 2004 was 84% of normal. The actual runoff for the same period in 2003 was also 84% of normal. Hydroelectric power is a large percentage of PSE’s power portfolio.
        Purchased gas expenses increased $9.1 million and $90.9 million for the three and nine months ended September 30, 2004, respectively, compared to the same periods in 2003. The increase was primarily due to increased usage as a result of more normal temperatures in the first quarter of 2004 and higher PGA rates compared to the same periods in 2003. Gas costs are passed through to customers through the PGA mechanism with no impact on gas margin or net income.
        Electric generation fuel expense increased $3.9 million and $12.7 million for the three and nine months ended September 30, 2004, respectively, compared to the same periods in 2003. The increase for the three months ended September 30, 2004 was primarily due to higher cost of gas and coal, despite lower thermal generation (gas and coal) at PSE generating facilities. Thermal generation for the three months ended September 30, 2004 decreased 60.3 million kWh or 3.7%. The increase for the nine months ended September 30, 2004 was primarily due to increased generation at PSE generation facilities, including Frederickson 1, which went in service in May 2004, and the higher cost of natural gas and coal in 2004. Thermal generation for the nine months ended September 30, 2004 increased 110.3 million kWh or 2.6%. Electric generation fuel costs can vary quarter to quarter and month to month within a quarter based on several factors, including the cost of gas and other fuel, secondary market prices of electricity, and hydroelectric water conditions.
        The nine months ended September 30, 2004 also includes a $6.9 million charge in June 2004 related to a binding arbitration settlement between PSE and Western Energy Company (WECO), the supplier of coal to Colstrip Units 1 & 2, which was recorded in the second quarter of 2004. The binding decision retroactively set a new baseline cost of coal per ton supplied from July 31, 2001, and is applicable for the remaining term of the coal supply agreement through December 2009. Of the second quarter charge of $6.9 million, $5.0 million is included in the PCA mechanism. PSE had previously accrued a reserve of $1.6 million in the fourth quarter of 2003 related to the arbitration.
        The nine months ended September 30, 2004 also includes a loss reserve of $1.1 million recorded in the second quarter of 2004 related to an order issued by the Minerals Management Service of the United States Department of the Interior on April 29, 2004 to pay additional royalties to WECO concerning coal purchased by PSE for Colstrip Units 3 & 4. The order seeks payment of an additional $1.1 million in royalties for coal mined from federal lands between 1997 and June 30, 2000. During that period, PSE’s coal price was reduced by a settlement agreement entered into in February 1997 among PSE, WECO and Montana Power Company that resolved disputes that were then pending. The order seeks to impute the price charged to PSE based on the other Colstrip Units 3 & 4 owners’ contractual amounts. PSE is supporting WECO’s appeal of the order which was filed on October 1, 2004. The outcome of this matter cannot be predicted at this time.
        In addition, the Minerals Management Service of the United States Department of the Interior issued two orders to WECO in 2002 and 2003 to pay additional royalties concerning coal sold to Colstrip Units 3 & 4 owners. The orders assert that additional royalties are owed as a result of WECO not paying royalties in connection with revenue received by WECO from the Colstrip Units 3 & 4 owners under a coal transportation agreement during the period October 1, 1991 through December 31, 2001. PSE’s share of the alleged additional royalties is $1.8 million, which is equivalent to PSE’s 25% ownership interest in Colstrip Units 3 & 4. The transportation agreement provides for the construction and operation of a conveyor system that runs several miles from the mine to Colstrip Units 3 & 4. WECO has appealed these orders and PSE is monitoring the process. Based upon its review, PSE believes that the Colstrip Units 3 & 4 owners have reasonable defenses in this matter. Neither the outcome of this matter nor the associated costs can be predicted at this time.
        Residential exchange credits associated with the Residential Purchase and Sale Agreement with BPA increased $1.1 million and $1.2 million for the three and nine months ended September 30, 2004, respectively, when compared to the same periods in 2003. The overall increase for the three months ended September 30, 2004 was a result of increased residential electric load. The residential exchange credit is a pass-through tariff item with a corresponding credit in electric operating revenue. It has no impact on electric margin or net income.
        Unrealized gain on derivative instruments for the three and nine months ended September 30, 2004 decreased $1.0 million and increased $1.4 million, respectively, compared with the same periods in 2003. SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138 and SFAS No. 149, 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 normal sale exemption. Those contracts that do not meet normal purchase normal sale exemption or cash flow hedge criteria are marked-to-market to current earnings in the income statement, subject to deferral under SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation,” (SFAS No. 71) due to the PCA mechanism.
        PSE has a contract with a counterparty whose debt ratings have been below investment grade since 2002. The contract, a physical gas supply contract for one of PSE’s electric generating facilities, was marked-to-market beginning in the fourth quarter of 2003. Although the counterparty continues to fully perform on the physical supply contract, the counterparty’s credit ratings have remained weak. Prior to October 1, 2003, the contract was designated as a normal purchase under SFAS No. 133. PSE has concluded that it is appropriate to reserve the marked-to-market gain on this contract due to the credit quality of the counterparty in accordance with SFAS No. 133 guidance, as management deemed that delivery is not probable through the term of the contract, which expires December 2008. There was no impact on earnings for the three and nine months ended September 30, 2004.
        In the first quarter of 2004, the counterparty of another physical gas supply contract for one of PSE’s electric generating facilities notified PSE that it would be unable to deliver physical gas supply beginning in November 2005 through the end of the contract in June 2008. Since physical delivery for the life of the contract was no longer probable, the contract no longer met the criteria for normal purchase normal sale exemption under SFAS No. 133. Therefore, the contract was marked-to-market in the first quarter of 2004, with an offsetting reserve for the portion of the mark-to-market gain applicable to the period of November 2005 through June 2008. The unrealized gain to earnings, net of the reserve, was $0.7 million in the third quarter of 2004. In October 2004, PSE and the counterparty reached a settlement on the non-deliverable period of November 2005 through June 2008. The agreement allows PSE to recover a portion of the present value of the difference in future market prices of physical gas and the original contract price, for a total recovery of approximately $10.1 million. PSE filed a petition with the Washington Commission to defer the counterparty settlement amount as a regulatory liability and amortize the benefit over the period of November 2005 through June 2008 as a reduction in Electric Generation Fuel expense.
        Production operations and maintenance expense increased $0.5 million for the three months ended September 30, 2004 compared with the same period in 2003, primarily as a result of increased expenses related to the Frederickson 1 generating facility placed in service in May 2004. Production operations and maintenance expense decreased $0.8 million for the nine months ended September 30, 2004 compared to the same period in 2003. This decrease was primarily a result of lower overhaul maintenance performed on Colstrip Units 1 & 2 in the second quarter 2004 compared to the same period in 2003, offset by the expense associated with the Frederickson 1 generating facility.
        Low-income Program costs, which are a pass-through tariff item, decreased $1.0 million and $3.7 million for the three and nine months ended September 30, 2004, respectively, compared to the same periods in 2003. Low-income program costs are dependent upon the amount collected from customers through rates.
        Other utility operations and maintenance costs decreased $0.1 million and increased $7.1 million for the three and nine months ended September 30, 2004, respectively, compared to the same periods in 2003. The increase for the nine months ended September 30, 2004 was due primarily to a $6.5 million increase in storm damage costs associated with electric system repairs following a severe ice storm in January 2004 that occurred in the Pacific Northwest.
        Depreciation and amortization expense increased $2.7 million and $5.8 million for the three and nine months ended September 30, 2004, respectively, compared to the same periods in 2003 due primarily to the effects of new plant placed into service during 2004 and the latter half of 2003.
        Taxes other than income taxes increased $2.5 million and $11.4 million for the three and nine months ended September 30, 2004, respectively, compared to the same periods in 2003. The increase for the three months ended September 30, 2004 was due to higher municipal and state excise taxes of $1.6 million, which are revenue based, and a $0.7 million increase in property taxes. The increase for the nine months ended September 30, 2004 was primarily due to higher revenue based municipal and state excise taxes of $10.7 million.
        Income taxes increased $8.3 million and $5.4 million for the three and nine months ended September 30, 2004, respectively, compared to the same periods in 2003. The increase for the three months ended September 30, 2004 was the result of one time federal income tax true-ups of the Company’s 2003 and 2002 federal income tax returns, which increased income tax expense by $3.5 million, and the result of higher taxable income. The increase for the nine months ended September 30, 2004 was the result of the aforementioned third quarter federal income tax return true-ups, and the non-recurrence of a one-time tax benefit of $6.2 million recorded in the second quarter 2003 related to a favorable resolution of a federal income tax matter from 1997 to 2002. These increases were partially offset with reduced income tax expense associated with lower taxable income for the nine months ended September 30, 2004 compared with the same period in 2003.
        Other income decreased $2.2 million and $3.6 million for the three and nine months ended September 30, 2004, respectively, compared to the same periods in 2003. The decrease for the three months ended September 30, 2004 was primarily due to a gain on corporate-owned life insurance policies in the third quarter 2003 of $1.7 million that did not recur in 2004. In addition to the non-recurrence of the gain on corporate-owned life insurance, the decrease for the nine months ended September 30, 2004 included the non-recurrence of a $1.9 million gain on the sale of securities in the second quarter 2003.
        Interest charges decreased $3.1 million and $10.4 million for the three and nine months ended September 30, 2004, respectively, compared to the same periods in 2003. This decrease was primarily due to the redemption or maturity of $164.3 million of Medium-Term Notes with interest rates ranging from 6.07% to 7.80% since September 30, 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% in March 2003. The decrease in interest expense was partially offset by the issuance of $200 million of variable rate Senior Notes in July 2004 and the consolidation of the conservation trust bonds due to FIN 46R.
        Also included in earnings per share are preferred stock dividend accrual expenses. During the three and nine months ended September 30, 2004, preferred stock dividend accrual expense decreased $1.1 million and $4.8 million, respectively, compared with the same periods in 2003. This decrease was due to the redemption of $41.3 million of $100 par value 7.75% preferred stock in August 2003 and $60.0 million of $25 par value 7.45% preferred stock in November 2003.

InfrastruX
        The changes to items affecting net income for the three and nine months ended September 30, 2004 in comparison with the same periods in 2003 are summarized in the table below.

Comparative Three and Nine Months Ended
September 30, 2004 vs. September 30, 2003
Increase (Decrease)
(Dollars in Millions)

	Three Months Ended Change			Nine Months Ended Change
Operating revenue change:
Non-utility construction services	$	6	.8	$	11	.3
Operating expense changes:
Other operations and maintenance		5	.7		3	.4
Depreciation and amortization		0	.4		1	.4
Taxes other than income taxes		0	.4		(0	.1)
Income taxes		--			2	.7
Total operating expense change		6	.5		7	.4
Other income change		(0	.1)		--
Interest charges change		0	.1		0	.4
Minority interest change		--			0	.3
Net income change	$	0	.1	$	3	.2

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

        InfrastruX revenue increased $6.8 million and $11.3 million for the three and nine months ended September 30, 2004, respectively, compared to the same periods in 2003. The increase for the three months ended September 30, 2004 as compared to 2003 was due to stronger gas and electric transmission service revenues in the Texas and south-central region. For the nine months ended September 30, 2004, the increase in revenues was primarily due to the acquisition of one company late in the second quarter of 2003, which contributed an increase of $12.4 million to revenues. The increase was partially offset by lower revenues from existing companies as a result of exiting unprofitable business activities and the completion of a large project in 2003 that was not repeated in 2004. InfrastruX operations are seasonal, with its highest revenues typically in the second and third quarters of the year.
        InfrastruX operations and maintenance expenses increased $5.7 million and $3.4 million for the three and nine months ended September 30, 2004, respectively, compared to the same periods in 2003. The increase for the three months ended September 30, 2004 was a result of the revenue growth for the same period. The increase for the nine months ended September 30, 2004 was due primarily to the acquisition of one company late in the second quarter of 2003, which contributed an additional $11.8 million in operations and maintenance expenses. This was partially offset by an $8.0 million reduction of operation and maintenance expenses as a result of stringent cost control measures implemented as well as exiting unprofitable business activities.
        Depreciation and amortization expense increased $0.4 million and $1.4 million for the three and nine months ended September 30, 2004, respectively, compared to the same periods in 2003. The increases were primarily due to an increase in assets through a company acquisition late in the second quarter of 2003 and implementation of an integrated information technology platform across InfrastruX.
        Income taxes changed by an insignificant amount and increased $2.7 million during the three and nine months ended September 30, 2004, respectively, compared to the same periods in 2003 due primarily to higher operating income in the first quarter of 2004.

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, 2004:

Puget Energy				Payments Due Per Period
Contractual Obligations (Dollars in millions)	Total			2004			2005- 2006			2007- 2008			2009 and Thereafter
Short-term debt	$	24	.5	$		--	$	24	.5	$		--	$		--
Long-term debt		2,308	.3		53	.2		330	.9		445	.1		1,479	.1
Junior subordinated debentures payable
to a subsidiary trust (1)		280	.3			--			--			--		280	.3
Mandatorily redeemable preferred stock		1	.9			--			--			--		1	.9
Service contract obligations		174	.1		5	.5		43	.5		50	.5		74	.6
Capital lease obligations		7	.4		0	.5		4	.0		2	.6		0	.3
Non-cancelable operating leases		95	.6		23	.4		31	.4		26	.6		14	.2
Fredonia combustion turbines lease (2)		66	.2		1	.1		8	.7		8	.5		47	.9
Energy purchase obligations		5,302	.8		341	.7		1,842	.4		1,296	.1		1,822	.6
Financial hedge obligations		(38	.7)		(5	.4)		(24	.5)		(8	.8)			--
Non-qualified pension funding		27	.8		0	.3		3	.1		4	.5		19	.9
Total contractual cash obligations	$	8,250	.2	$	420	.3	$	2,264	.0	$	1,825	.1	$	3,740	.8

				Amount of Commitment Expiration Per Period
Commercial Commitments (Dollars in millions)	Total			2004		2005- 2006			2007- 2008			2009 and Thereafter
Guarantees (3)	$	136	.0	$	--	$		--	$	136	.0	$	--
Liquidity facilities – available (4)		410	.5		--			--		410	.5		--
Lines of credit – available (5)		32	.4		--		22	.2		10	.2		--
Energy operations letter of credit		0	.5		--		0	.5			--		--
Total commercial commitments	$	579	.4	$	--	$	22	.7	$	556	.7	$	--

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

(3) In May 2004, InfrastruX signed a three-year credit agreement with a group of banks to provide up to $150 million in financing. Under the credit agreement, Puget Energy is the guarantor of the line of credit. Certain InfrastruX subsidiaries also have certain borrowing capacities for working capital purposes of which Puget Energy is not a guarantor.

(4) At September 30, 2004, PSE had available a three-year $350 million unsecured credit agreement and a three-year $150 million receivables securitization facility. At September 30, 2004, PSE had $61.0 million of receivables available for sale under its receivables securitization facility. See “Accounts Receivable Securitization Program” under “Off-Balance Sheet Arrangements” below for further discussion. The credit agreement and securitization facility provide credit support for an outstanding letter of credit totaling $0.5 million, thereby effectively reducing the available borrowing capacity under these liquidity facilities to $410.5 million.

(5) Puget Energy has a $15 million line of credit with a bank. At September 30, 2004, $5.0 million was outstanding, reducing the available borrowing capacity under this line of credit to $10.0 million. InfrastruX has $186.7 million in lines of credit with various banks to fund capital credit requirements of InfrastruX and its subsidiaries. InfrastruX and its subsidiaries had $160.5 million outstanding under their credit agreements and letters of credit of $3.8 million at September 30, 2004, effectively reducing the available borrowing capacity under these lines of credit to $22.4 million.

        Puget Sound Energy. The following are PSE’s aggregate contractual obligations and commercial commitments as of September 30, 2004:

Puget Sound Energy				Payments Due Per Period
Contractual Obligations (Dollars in millions)	Total			2004			2005- 2006			2007- 2008			2009 and Thereafter
Long-term debt	$	2,146	.6	$	51	.2	$	312	.0	$	304	.5	$	1,478	.9
Junior subordinated debentures payable
to a subsidiary trust (1)		280	.3			--			--			--		280	.3
Mandatorily redeemable preferred stock		1	.9			--			--			--		1	.9
Service contract obligations		174	.1		5	.5		43	.5		50	.5		74	.6
Non-cancelable operating leases		78	.7		16	.1		24	.0		24	.4		14	.2
Fredonia combustion turbines lease (2)		66	.2		1	.1		8	.7		8	.5		47	.9
Energy purchase obligations		5,302	.8		341	.7		1,842	.4		1,296	.1		1,822	.6
Financial hedge obligations		(38	.7)		(5	.4)		(24	.5)		(8	.8)			--
Non-qualified pension funding		27	.8		0	.3		3	.1		4	.5		19	.9
Total contractual cash obligations	$	8,039	.7	$	410	.5	$	2,209	.2	$	1,679	.7	$	3,740	.3

				Amount of Commitment Expiration Per Period
Commercial Commitments (Dollars in millions)	Total			2004		2005- 2006			2007- 2008			2009 and Thereafter
Liquidity facilities – available (3)	$	410	.5	$	--	$		--	$	410	.5	$	--
Energy operations letter of credit		0	.5		--		0	.5			--		--
Total commercial commitments	$	411	.0	$	--	$	0	.5	$	410	.5	$	--

(1) See note (1) above.

(2) See note (2) above.

(3) See note (4) above.

Off-Balance Sheet Arrangements
Accounts Receivable Securitization Program. In order to provide a source of liquidity to PSE at an attractive cost, PSE entered into a Receivables Sales Agreement with Rainier Receivables, Inc., a wholly owned subsidiary of PSE in December 2002. Pursuant to the Receivables Sales Agreement, 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 a third party. The Receivables Purchase Agreement allows Rainier Receivables to sell the receivables purchased from PSE to the third party. 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 eligible 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 revolving line of credit secured by receivables. In the event Rainier Receivables elects to sell receivables under the Receivables Purchase Agreement, Rainier Receivables is required to pay fees to the purchasers that are comparable to interest rates on a revolving line of credit. As receivables are collected by PSE as agent for the receivables purchasers, the outstanding amount of receivables held 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, 2004, Rainier Receivables had an outstanding eligible receivable balance of $122.0 million. Of that amount, $61.0 million of accounts receivable had been sold and the maximum receivables available for sale was $61.0 million.
        During the three and nine months ended September 30, 2004, Rainier Receivables sold a cumulative $81.0 million and $348.0 million of receivables. No amounts were sold for the same periods in 2003.

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 August 2004. Payments under the lease vary with changes in the London Interbank Offered Rate (LIBOR). At September 30, 2004, PSE’s outstanding balance under the lease was $57.0 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.

New Generation Resources
        In April 2004, PSE completed the purchase of a 49.85% interest in a gas-fired electric generating station located within Western Washington (Frederickson 1). The purchase has added $80.8 million in utility plant and approximately 124 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 cost of the new generating facility and other power costs. The acquisition of Frederickson 1 was approved by the Washington Commission on April 7, 2004 and was also approved by FERC under the Federal Power Act on April 23, 2004.
        In September 2004, PSE signed a non-binding letter of intent to obtain a 100% ownership interest in the proposed Wild Horse wind power project (Wild Horse Project) to be located in central Washington State. The Wild Horse Project is expected to have approximately 100 to 133 wind turbines and generate from 150 to 220 MW of power, depending on the final design agreement. The project will require final binding agreement between PSE and the developer, which is anticipated to be signed in the fourth quarter of 2004 with an anticipated in-service date in 2006. To fund the proposed project, PSE anticipates issuing a combination of short and long-term debt as well as using its existing liquidity arrangements.
        In addition to the above projects, PSE has issued requests for proposals to acquire up to 355 average MW of electric power resources, including generation energy from additional wind power for its electric-resource portfolio and is continuing to evaluate responses.

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), totaled $311.4 million for the nine months ended September 30, 2004. PSE estimates construction expenditures will total approximately $408 million in 2004, which includes the acquisition of the 49.85% interest in the Frederickson 1 generating facility. Expenditures in 2005 and 2006 are expected to be $387 million and $357 million, respectively, excluding amounts for new generating resources currently under evaluation. Construction expenditure estimates are subject to periodic review and adjustment in light of changing economic, regulatory, environmental and conservation factors.

Other Additions
        Other property, plant and equipment additions were $12.9 million for the nine months ended September 30, 2004. Puget Energy expects InfrastruX’s capital additions to be $16.7 million in 2004, $18.0 million in 2005, and $20.0 million in 2006. Capital addition estimates are subject to periodic review and adjustment in light of changing economic and regulatory factors.

Capital Resources
Cash From Operations. Cash generated from operations for the nine months ended September 30, 2004 was $282.1 million. During the period, $68.9 million in cash was used for AFUDC and payment of dividends. Consequently, cash flows available for utility construction expenditures and other capital expenditures were $213.2 million or 63.9% of the $333.8 million in construction expenditures (net of AFUDC) and other capital expenditure requirements for the period. For the same period in 2003, cash generated from operations was $200.1 million, $68.6 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 months ended September 30, 2003 were $131.5 million or 58.8% of the $223.8 million in construction expenditures (net of AFUDC). The overall increase in cash generated from operating activity for the nine months ended September 30, 2004 was $82.0 million as compared to the same period in 2003. The increase in cash from operating activity was the result of increases in PGA rates in April and October 2003, combined with lower cash paid to customers under the PGA mechanism for liability balances in 2003 for a total positive cash flow of $46.9 million between the periods. Cash from operating activity also increased $27.0 million due to higher cash payments received from BPA than provided to customers under the residential exchange program compared to 2003 when PSE provided customers more cash than BPA paid to PSE. In addition, changes in deferred taxes contributed $20.0 million to positive cash flow. These increases were partially offset by a reduction in current tax liabilities of $30.6 million.
        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 are 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 2004 and 2005 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, 2004, PSE could issue:

• approximately $633.0 million of first mortgage bonds, as PSE has approximately $1.1 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 at an assumed interest rate of approximately 4.90% on a thirty-year first mortgage bond. PSE’s interest coverage ratio at September 30, 2004 was 2.8 times net earnings available for interest. PSE currently has $3.7 billion in electric and gas ratebase to support the interest coverage ratio limitation test for net earnings available for interest;

• approximately $326.2 million of additional preferred stock at an assumed dividend rate of 6.63%; and

• approximately $275.5 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 interest rate spreads over the index and commitment fee increase as PSE’s secured long-term debt ratings decline. An interest rate 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, respectively. 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 October 28, 2004 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	(P)Baa2
Trust preferred securities	BB	Ba1
Preferred stock	BB	Ba2
Commercial paper	A-3	P-2
Revolving credit facility	*	Baa3
Ratings outlook	Positive	Stable
Puget Energy
Corporate credit/issuer rating	BBB-	Ba1

* Standard & Poor's does not rate credit facilities.

Shelf Registrations. In January 2004, 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.

        On July 15, 2004, PSE issued $200 million in floating rate senior notes under its existing $500 million shelf registration statement, reducing the available balance for issuance under the shelf registration statement to $300 million. The notes float at the three-month LIBOR rate plus 0.30%, mature on July 14, 2006, and can be redeemed at par any time after January 15, 2005. PSE used the net proceeds from the sale of the floating rate senior notes to repay outstanding amounts under its commercial paper and accounts receivable securitization programs, including amounts incurred to repay long-term debt, and also used the proceeds to redeem $55 million in principal of first mortgage bonds at a premium of 3.68% on August 14, 2004. It is anticipated the $200 million in senior notes will be paid off with a combination of long-term debt and internally generated funds.

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.
        In May 2004, PSE entered into a three-year, $350 million unsecured credit agreement with a group of banks which replaced its previous $250 million unsecured credit agreement. PSE also has 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, 2004, PSE had available $350 million in the unsecured credit agreement and $61.0 million available from the receivable securitization facility (net of $61.0 million sold), which provide credit support for outstanding commercial paper and outstanding letters of credit. At September 30, 2004, there was $0.5 million outstanding under a letter of credit, effectively reducing the available borrowing capacity under the liquidity facilities to $410.5 million.
        In May 2004, InfrastruX entered into a three-year, $150 million credit agreement with a group of banks, replacing its previous $150 million credit agreement. Puget Energy is the guarantor of the line of credit. In addition, InfrastruX’s subsidiaries have an additional $36.7 million in lines of credit with various banks, for a total capacity for InfrastruX and its subsidiaries of $186.7 million under their line of credit agreements. Borrowings available for InfrastruX are used to fund acquisitions and working capital requirements of InfrastruX and its subsidiaries. At September 30, 2004, InfrastruX and its subsidiaries had $160.5 million outstanding under their credit agreements and letters of credit of $3.8 million, effectively reducing the available borrowing capacity under these lines of credit to $22.4 million.
        In May 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 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. Puget Energy has $5.0 million outstanding under the credit agreement at September 30, 2004.

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 $3.8 million (176,227 shares) and $11.6 million (530,430 shares) for the three and nine months ended September 30, 2004 compared to $4.0 million (184,870 shares) and $11.6 million (554,441 shares) for the same periods in 2003.

Common Stock Offering Programs. To provide additional financing options, Puget Energy entered into agreements in July 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.

Other

FERC Hydroelectric Licenses
Baker River Project. The Baker River Project is located upstream of the confluence of the Baker and Skagit Rivers in Whatcom and Skagit Counties and consists of the Lower Baker Development (constructed in 1925) and the Upper Baker Development (constructed in 1959). The Baker River Project’s current license expires on April 30, 2006, and PSE submitted an application for a new license to FERC on April 30, 2004. In addition, PSE continues to work with numerous interested participants to achieve a comprehensive settlement agreement to be submitted to FERC during the fall of 2004.

Snoqualmie Falls Project. The Snoqualmie Falls Project, built in 1898, had its original license issued May 13, 1975, which was made effective retroactively to March 1, 1956, and expired on December 31, 1993. PSE filed its application to relicense the project on November 25, 1991, and has been operating the project pursuant to annual licenses issued by FERC since the original license expired. On June 29, 2004, FERC granted PSE a new 40-year operating license for the Snoqualmie Falls Project. PSE estimates that the investment required to implement the conditions of the new license agreement will cost approximately $44 million. These conditions include modified operating procedures and various project upgrades that include better protection of fish, development of riparian habitat to promote fish propagation, increased minimum flows in the Snoqualmie River during low-water periods and the development of recreational amenities near the down-river power house. PSE accepted the FERC license in July 2004. On July 29, 2004, the Snoqualmie Tribe and certain other parties filed a request for rehearing and request for stay with FERC. FERC issued a subsequent order indicating it would respond in the fall of 2004.

Electric Rate Matters
        On April 5, 2004, PSE filed a general tariff electric rate case with the Washington Commission. The electric rate case proposes a 5.8% or $82.8 million annual increase to electric rates to recover costs associated with extending and upgrading facilities to serve a growing number of electric customers as well as strengthen PSE financially to serve its customers. The Washington Commission staff and other intervenors responded to PSE’s general tariff electric rate case in the third quarter of 2004, and the Washington Commission staff proposed an electric rate case increase of $21.4 million. PSE filed its rebuttal testimony to the intervenors’ testimony on November 3, 2004 in which PSE revised its proposed electric increase request to 7.3% or $103.3 million annually which reflects updated power costs for increases in natural gas pricing for generating plants. The resolution of the electric general rate case may be up to an 11-month process from the time the electric general rate case was filed.
        On April 23, 2004, the acquisition of a 49.85% interest in the Frederickson 1 generating facility was approved by FERC. Prior to that approval, on April 7, 2004, the Washington Commission had issued an order in PSE’s power cost only rate case granting approval for the acquisition of the Frederickson 1 generating facility as well. As a result of these approvals, PSE completed the acquisition in the second quarter of 2004. In its order, the Washington Commission found the acquisition to be prudent and the cost associated with the generating facility reasonable. The costs associated with the generating facility, including projected baseline gas costs, are approved for recovery in rates.
        On May 13, 2004, the Washington Commission also approved other adjustments to power costs that resulted in an increase of cost recovery in rates of $44.1 million annually, beginning May 24, 2004, which includes the ownership, operation and fuel costs of the Frederickson 1 generating facility.
        In December 2003, PSE notified FERC that it rejected the 1997 license for the White River Project because the 1997 license contained terms and conditions that rendered ongoing operations of the project uneconomical relative to alternative resources. As a result of rejecting the license, generation of electricity ceased at the White River Project on January 15, 2004. The Company is actively seeking to sell the project to one or more entities interested in maintaining the reservoir for commercial purposes.
        In the April 7, 2004 proceeding described above, the Washington Commission also approved PSE’s recovery on the unamortized White River plant investment. At September 30, 2004, the White River Project net book value totaled $65.1 million, which included $46.8 million of net utility plant, $14.5 million of capitalized FERC licensing costs, $3.2 million of costs related to construction work in progress, and $0.6 million related to dam operations and safety. PSE is seeking recovery of the relicensing, other construction work in progress and dam operations and safety costs totaling $18.3 million in its general rate filing of April 2004, over a 10-year amortization period. In the third quarter of 2004, the Washington Commission staff recommended that PSE be allowed recovery of the White River net utility plant costs noted above, but defer any amortization of the FERC licensing and other costs until all costs and any sales proceeds are known. The outcome of this matter is expected no later than the first quarter of 2005.
        In June 2003, the Washington State Department of Ecology (WSDE) approved an application for new municipal water rights related to the White River Project reservoir. This approval was sought in connection with PSE’s ongoing efforts to sell the White River Project to be used for commercial purposes. An appeal of WSDE’s decision approving the new municipal water rights was subsequently filed with the Washington State Pollution Control Hearings Board. In July 2004, this decision was remanded back to WSDE for further analysis of non-hydropower operations. The Company has been advised by WSDE that WSDE anticipates issuing a revised decision by the end of the year; however, no firm date has been set for any such revised decision. Any proceeds from the sale of the White River water rights will reduce the balance of the deferred regulatory asset.
        In May 2004, the Puyallup Indian Tribe gave PSE notice of intent to sue for an alleged violation of water quality laws associated with the release of water from the White River Project reservoir. No such lawsuit has been filed and PSE is in discussion with the Puyallup Indian Tribe regarding their concerns. Additionally, PSE has sought, and is awaiting, further direction from the WSDE as to whether any additional actions are necessary to maintain compliance with applicable water quality laws.
        In March 2004, the Company entered into an agreement with certain homeowner associations that addresses, in part, the concerns of these homeowner associations with regard to preserving the project reservoir. In September 2004, the Company renewed its contract with the United States Army Corps of Engineers (COE) to maintain operation of the White River diversion dam to support the COE’s ongoing operation of its Mud Mountain Dam fish passage facilities. The agreement provides for reimbursement of a portion of the Company’s operating costs and directs the Company to operate the diversion dam in accordance with measures determined by federal agencies to be necessary to protect listed species and habitat.
        In June 2001, PSE and the Bonneville Power Administration (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 payment during the period October 1, 2006 through September 30, 2011. The payments received from BPA and the credits provided to residential and small farm customers have no impact on earnings.
        In June 2002, PSE entered into an agreement with BPA, which modified the payment provisions of the June 2001 amended settlement agreement to provide for conditional deferral of payment by BPA of certain amounts to be paid under the original agreement for an eight month period beginning February 2003, for a total deferral of $27.7 million. Absent certain adjustments tied to a BPA rate adjustment clause, BPA is to begin paying back the amount deferred with interest over a 60-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, which was approved by the Washington Commission.
        In June 2003, BPA adopted its final Record of Decision in its February 2003 rate case, which established a formula under the BPA rate adjustment clause to be used in adjusting the rate that would affect the level of residential exchange benefits for PSE’s customers. The adjustment was approved by FERC on an interim basis and went into effect October 1, 2003. FERC issued final approval of this formula in May 2004.
        In May 2004, PSE and BPA entered into an agreement that modified the payment of Residential Exchange Program benefits for the period October 1, 2006 through September 30, 2011. The agreement provides that all benefits in this period will be in the form of cash payments only and defined a new methodology to be used to calculate the residential benefits. In addition, PSE agreed to waive payment of approximately one-half of an available reduction-in-risk discount and deferred payment of the other half of the discount, plus interest, until October 2007.
        There are several actions in the U.S. Ninth Circuit Court of Appeals against BPA, in which the petitioners assert or may assert that BPA acted contrary to law or without authority in deciding to enter into, or in entering into or performing or implementing, a number of contracts, including the above-described amended settlement agreement, the conditional deferral agreement between BPA and PSE, and the May 2004 agreement between BPA and PSE. 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 contracts and the above-described U.S. Ninth Circuit Court of Appeals actions may have on PSE.

Tenaska Disallowance. The Washington Commission issued an order on May 13, 2004 determining that PSE did not prudently manage gas costs for the Tenaska electric generating plant and ordered PSE to adjust its PCA deferral account to reflect a one-time disallowance of $25.6 million for the PCA 1 period (July 1, 2002 through June 30, 2003), which was recorded by PSE as a Purchased Electricity expense in the second quarter of 2004. The order also established guidelines for future recovery of Tenaska costs. The amounts were determined to be a $25.6 million one-time disallowance for the PCA 1 period and an estimated disallowance of $11.3 million for the PCA 3 period (July 1, 2004 to June 30, 2005), based upon applying the Washington Commission’s methodology of 50% disallowance on the return on the Tenaska regulatory asset due to projected costs exceeding the benchmark during the period. For the PCA 3 period, approximately $5.6 million would be disallowed in the period July 1, 2004 through December 31, 2004, primarily as a reduction to Electric Operating Revenue, for a cumulative impact on earnings of $31.2 million in 2004 for the PCA 1 and 3 periods for PSE. The PCA 3 reduction in Electric Operating Revenue is the result of the Washington Commission’s order that reflected a reduction in rates of approximately $9.9 million annually. This reduction is to reflect the Washington Commission estimate of the Tenaska disallowance for the PCA 3 period. While the Washington Commission did not expressly address the disallowance for the PCA 2 period (July 1, 2003 through June 30, 2004), PSE estimates the disallowance for the PCA 2 period to be approximately $12.2 million if the Washington Commission were to follow the same methodology as they have ordered for the PCA 3 period. While PSE reserves the right to address the merits of any disallowance in its PCA 2 compliance filing, which is currently being reviewed by the Washington Commission staff, PSE recorded a $12.2 million disallowance to Purchased Electricity expense in the second quarter of 2004 for the 50% disallowance of the return on the Tenaska regulatory asset in accordance with the Washington Commission’s methodology discussed in their order of May 13, 2004. PSE anticipates the PCA 2 compliance filing to be concluded by no later than the end of the first quarter 2005. As a result of the disallowance recorded, the PCA customer deferral of $17.6 million at March 31, 2004 was expensed and a reserve was established to offset future PCA customer deferrals. The reserve balance as of September 30, 2004 was $11.2 million, which is expected to be utilized over the remaining months in 2004 as the excess power costs are shared through the PCA mechanism. The cumulative disallowance for the nine months ended September 30, 2004 was $40.6 million which is comprised of a $4.1 million reduction in Electric Operating Revenue and a $36.5 million one-time disallowance recorded in Purchased Electricity expense. The total for 2004 is expected to be approximately $43.4 million ($28.1 million after-tax).
        Prior to the Tenaska disallowance, PSE’s excess power costs under the PCA mechanism exceeded the $40 million cap established whereas with the Tenaska disallowance the excess power costs at September 30, 2004 are $26.8 million. The excess power cost from September 30, 2004 until the PCA mechanism cap of $40 million is reached, which is expected in November 2004, will be offset by the Tenaska disallowance reserve of $11.2 million for the PCA 1 and 2 periods that was recorded in the second quarter of 2004. PSE does not expect earnings through year-end 2004, based on current market conditions, to be impacted by excess power costs due to the Tenaska disallowance reserve recorded in the second quarter of 2004.
        Below is a summary of the Tenaska disallowances by quarter through December 31, 2004:

(Dollars in millions) Quarter ending	7/02 - 6/03 PCA 1 (ordered/final)			7/03 - 6/04 PCA 2 (estimated)			7/04 - 12/04 PCA 3 (estimated)			Total
June 30, 2004	$	25	.6	$	12	.2	$	--		$	37	.8
September 30, 2004		--			--			2	.8		2	.8
December 31, 2004		--			--			2	.8		2	.8
Total	$	25	.6	$	12	.2	$	5	.6	$	43	.4

        In the May 13, 2004 order, the Washington Commission established guidelines and a benchmark to determine PSE’s recovery on the Tenaska regulatory asset starting with the PCA 3 period (July 1, 2004) through the expiration of the Tenaska contract in the year 2011. The benchmark is defined as the original cost of the Tenaska contract adjusted to reflect the 1.2% disallowance from a 1994 Prudence Order.

        The Washington Commission guidelines for determining future recovery of the Tenaska costs (gas costs, recovery of the Tenaska regulatory asset and return on the Tenaska regulatory asset) are as follows:

1. The Washington Commission will determine if PSE’s gas purchasing plan and gas purchases for Tenaska are prudent through the PCA compliance filings.

2. If PSE’s gas purchasing plan and gas purchases for Tenaska are prudent, and if PSE’s actual Tenaska costs fall at or below the benchmark, it will recover fully its Tenaska costs.

3. If PSE’s gas purchasing plan and gas purchases for Tenaska are prudent, but its actual Tenaska costs exceed the benchmark, PSE will only recover 50% of the lesser of:

a) Actual Tenaska costs that exceed the benchmark or;

b) The return on the Tenaska regulatory asset (return on the asset would be added last to all other relevant Tenaska costs).

4. If PSE’s gas purchasing plan or gas purchases are found to be imprudent in a future proceeding, PSE risks disallowance of any and all Tenaska costs.

        The Washington Commission confirmed that if the Tenaska gas costs are deemed prudent, PSE will recover the full amount of actual gas costs and the recovery of the Tenaska regulatory asset even if the benchmark is exceeded. The projected costs and projected benchmark costs for Tenaska have been updated as of September 30, 2004 to reflect higher forward gas prices and are as follows:

(Dollars in millions)	Remainder 2004			2005			2006			2007			2008			2009			2010			2011
Projected Tenaska costs (*)	$	51	.7	$	199	.4	$	199	.2	$	190	.8	$	183	.8	$	178	.6	$	172	.3	$	171	.8
Projected Tenaska benchmark costs		41	.7		159	.6		167	.9		175	.2		182	.2		189	.5		197	.2		213	.8
Over (under) benchmark costs	$	10	.0	$	39	.8	$	31	.3	$	15	.6	$	1	.6	$	(10	.9)	$	(24	.9)	$	(42	.0)
Projected 50% disallowance based on
Washington Commission methodology	$	2	.8	$	10	.7	$	9	.2	$	6	.2	$	1	.8	$		--	$		--	$		--

_________________

* Projection will change based on market conditions of gas and replacement power costs.

Gas Rate Matters
        On September 24, 2004, the Washington Commission approved PSE’s request for a PGA filed on August 31, 2004. The approved request will increase rates and revenues by approximately 17.6% or $121.7 million annually. The increase in PGA rates was to recover higher market prices of natural gas sold to customers. 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 change in PGA rates.
        On April 5, 2004, PSE filed a general tariff gas rate case with the Washington Commission. The gas rate case proposes a 6.8% or $48.9 million annual increase to gas rates to recover costs associated with extending and upgrading facilities to serve a growing number of gas customers as well as strengthen PSE financially to serve its customers. The Washington Commission staff and other intervenors responded to PSE’s general tariff gas rate case in the third quarter 2004 and the Washington Commission staff proposed a gas rate case increase of $8.1 million. PSE filed its rebuttal testimony on November 3, 2004 in which PSE revised its proposed increase request to 6.3% or $46.2 million annually for gas customers. The resolution of the gas general rate case may be up to an 11-month process from the time the gas general rate case was filed.
        In 2003, the Washington Commission’s Pipeline Safety staff conducted a natural gas standard inspection for three counties within Washington State in which PSE operates gas pipeline activities. The inspection included a review of procedures, records, and operations and maintenance activities. On June 29, 2004, the Washington Commission issued a complaint to PSE related to that inspection. The Washington Commission’s complaint alleges certain violations of Washington Commission regulations and determined a maximum aggregated fine for the violations of $4.5 million, although the Washington Commission’s Pipeline Safety staff recommended a fine of $1.3 million. PSE is reviewing this matter and has been meeting with the Pipeline Safety staff to review their allegations and develop a mutual resolution to this matter. Neither the outcome of this matter nor the associated costs, including potential fines, can be predicted at this time.
        In September 2004, a natural gas fire destroyed a home and took the life of a PSE customer. The cause of the fire remains under investigation by PSE, the Washington Commission and other parties. PSE has tendered the matter to its general liability insurer. Neither the potential regulatory or litigation outcomes of this matter nor the final associated costs can be predicted at this time.

Colstrip Generating Facilities
        In September 2004, the owners of Colstrip Units 1 & 2 (PSE and PPL Montana) entered into a tentative settlement agreement with certain homeowners in the Colstrip town site area concerning a lawsuit filed in May 2003. The lawsuit alleged certain domestic water wells may have been contaminated by seepage from a Colstrip Units 1 & 2 effluent holding pond. The tentative settlement agreement would require extending municipal water to the homeowners and abandoning the existing wells. The total estimated cost of the settlement ranges from $1.4 million to $1.5 million. As a result of this tentative settlement agreement, PSE recorded in the third quarter of 2004 a reserve for its 50% ownership of the Colstrip Units 1 & 2 project of $0.7 million. The settlement agreement does not resolve certain other claims by residents within the city limits. PSE cannot predict the outcome or any potential financial impact of the claims by the residents within the city limits at this time.
        On December 5, 2003, Colstrip Units 1 & 2 and 3 & 4 received an information request from the Environmental Protection Agency (EPA) relating to their compliance with the Clean Air Act New Source Review regulations. PSE is currently in discussions with the EPA concerning the information request. Neither the outcome of this matter nor any potential associated costs can be predicted at this time.

Douglas County PUD
        Early in 2003, the Colville Confederated Tribes (Colville Tribe) presented a claim to Douglas County PUD based upon allegedly unpaid past annual charges for the Wells Hydroelectric Project (the Project) for the use of Colville tribal lands, principally riverbed along the tribal reservation. The Colville Tribe further claimed that annual charges would be due for periods into the future. Beginning in April 2003, Douglas County PUD and Colville Tribe representatives discussed settlement of these issues. On November 1, 2004, the Douglas County PUD Commission approved entry into a settlement agreement with the Colville Tribe that, subject to FERC approval, will resolve all of the Tribe’s claims. The settlement would allocate 4.5% of the Project’s output to the Tribe effective upon FERC approval through 2018, when the allocation would increase to 5.5%. That allocation would last as long as the Project exists. In addition, under the settlement, Douglas County PUD would pay $13.5 million and convey certain real property to the Colville Tribe. Douglas County PUD would also market the Colville Tribe’s Project output on behalf of the Tribe for a period of time. PSE currently purchases 31.3% of the Project’s output. Upon approval, the settlement will slightly reduce the output available for PSE, and slightly increase the cost of PSE’s purchase under PSE’s existing contract with Douglas County PUD. PSE will support the Douglas County PUD filing for approval of the settlement. PSE cannot predict how long it will take FERC to act upon the application.

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, 2003 includes a summary 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 period covered by this report. While PSE cannot predict the outcome of any of the individual ongoing proceedings relating to the Western power markets, 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.

1. California Receivable and California Refund Proceeding. In 2001, PG&E and Southern California Edison failed to pay the California Independent System Operator Corporation (CAISO) and the California PX for energy purchases. The CAISO in turn failed to pay various energy suppliers, including PSE, for energy sales made by PSE into the California energy market during the fourth quarter of 2000. Both PG&E and the California PX filed for bankruptcy in 2001, further constraining PSE’s ability to receive payments due to bankruptcy court controls placed on the distribution of funds by the California PX and due to the fact that all funds are still owed directly to the CAISO for purchases during the fourth quarter of 2000.

a. 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 for purchases made in the spot markets operated by the CAISO and the California PX during the period October 2, 2000 through June 20, 2001 (refund period). The CAISO continues its efforts to recalculate costs and charges for spot market sales to California during the refund period and currently estimates that it will complete the initial refund calculations between mid-December 2004 and mid-January 2005, and the financial clearing as to “who owes what to whom” in February 2005. On September 2, 2004, FERC issued an order selecting Ernst & Young LLP as the independent auditor of fuel cost allowance claims made by sellers, including PSE, subject to refund orders. FERC issued a subsequent order on September 24, 2004 addressing rehearing requests related to the calculation methodology for fuel cost allowances. On October 7, 2004, FERC held a technical conference on issues raised by the two orders, as well as by an August 17, 2004 CAISO proposal to allocate fuel cost allowance claims, and a September 13, 2004 CAISO template for the submission of fuel cost allowance claims. PSE filed protests to both the CAISO allocation proposal and the CAISO template, and submitted additional comments at the technical conference. PSE has also commenced working with Ernst & Young LLP on the audit of PSE’s fuel claims and awaits further directives from FERC on the issues addressed at the October 7, 2004 technical conference. Many of the numerous orders that FERC issued in Docket No. EL00-95 are on appeal and have been consolidated before the United States Court of Appeals for the Ninth Circuit. On September 21, 2004, the Ninth Circuit held a case management conference to identify issues to be raised and to consider whether some issues could be severed from the consolidated proceedings and decided separately. On October 22, 2004, the Ninth Circuit lifted a stay that had held the proceeding in abeyance for more than two years, and directed that FERC file the record by November 22, 2004. The Ninth Circuit also established an additional case management conference for November 9, 2004, required that issues be briefed in two phases, and required that briefing on phase one issues be completed by March 1, 2005.
        Over the course of the last six months, settlement agreements with the California parties have been filed at FERC by each of the following: the Williams Companies, Dynegy, Inc. and Duke Energy, Inc. Each settlement resolves most issues between the settling parties and any other party willing to opt in to the settlement. PSE elected to opt into the Williams Companies settlement and specifically reserved its rights against the settling parties other than the Williams Companies. PSE is entitled to a nominal deemed distribution (approximately $4,382) from this settlement agreement. FERC approved the Williams Companies settlement on July 2, 2004, and the Dynegy, Inc. settlement on October 25, 2004, but has not yet approved the Duke Energy, Inc. settlement. FERC staff held a settlement conference on June 30, 2004 to facilitate further settlement discussions in this proceeding. No other settlements other than the Williams Companies, Dynegy, Inc. and Duke Energy, Inc. settlements have been announced.

b. CAISO Receivable. PSE has a bad debt reserve and a transaction fee reserve applied to the CAISO receivable, such that PSE’s net receivable from the CAISO as of September 30, 2004 is approximately $21.3 million. PSE estimates the range for the receivable to be between $21.3 million and $22.2 million, which includes estimated credits for fuel and power purchase costs and interest. In its October 16, 2003 Order on Rehearing in this docket, FERC expressly adopted and approved a stipulation that confirmed that two of PSE’s “non-spot market” transactions are not subject to mitigation in the Refund Proceeding. On October 17, 2003, PSE formally presented CAISO with a request that payment be made on these amounts. The CAISO responded to the letter on November 13, 2003, expressing an unwillingness to take the issue up separately or in advance of its cost re-run activities. PSE continues to pursue the issue in filings through FERC processes.
        On May 6, 2004, the Los Angeles Department of Water and Power filed a motion at FERC in Docket No. EL00-95 requesting that FERC issue an order permitting monies to be disbursed from the California PX Settlement Clearing Account and an escrow account established as part of PG&E’s bankruptcy proceeding. The bulk of the monies owed by the CAISO, including the monies owed to PSE, are held in those two accounts. PSE filed an answer in support of the motion on May 21, 2004, and awaits an order from FERC.

2. Pacific Northwest Refund Proceeding. On June 25, 2003, FERC issued an order terminating the Pacific Northwest refund proceeding, Docket No. 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. Seven petitions for review are now pending before the United States Court of Appeals for the Ninth Circuit. On September 29, 2004, the court denied the Port of Seattle’s request to adduce additional evidence brought to light in the Enron proceedings. On October 21, 2004, the Ninth Circuit established an updated briefing schedule. PSE’s initial brief is due on November 19, 2004.

3. 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 order (Docket Nos. EL03-180, et seq.) seeks to investigate approximately 26 entities that allegedly had potential “partnerships” with Enron. PSE was not named in that show cause order. In an order dismissing many of the already-named respondents in the “partnerships” proceeding on January 22, 2004, FERC states that it does not intend to proceed further against other parties.
        The second show cause order (Docket Nos. EL03-137, et seq.) named PSE (Docket No. EL03-169) and approximately 54 other entities that allegedly had engaged in potential “gaming” practices in the CAISO and California PX markets. 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 $17,092 to settle all claims. FERC approved the settlement on January 22, 2004. The California parties filed for rehearing of that order, repeating arguments that have already been addressed by FERC. On March 17, 2004, PSE filed a motion to dismiss the California parties’ rehearing request, and awaits FERC action on that motion. PSE continues to believe that the orders to show cause do not raise new issues or concerns and will not have a material adverse impact on the financial condition, results of operation or liquidity of the Company.

4. Port of Seattle Suit. On May 21, 2003, the Port of Seattle commenced suit in federal court in Seattle against 22 energy sellers, alleging that their conduct during 2000 and 2001 constituted market manipulation, violated antitrust laws and damaged the Port of Seattle. The Port had a contract to purchase its energy supply from PSE at the time. The Port’s contract 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. On May 12, 2004 the district court dismissed the lawsuit. The Port of Seattle filed an appeal to the United States Court of Appeals for the Ninth Circuit, and on September 13, 2004, filed a brief in the Ninth Circuit arguing that the district court erred in dismissing its claims. Responses to the Port’s brief were filed November 2, 2004.

5. Wah Chang Suit. In June 2004, Puget Energy and PSE were served a federal summons and complaint by Wah Chang, an Oregon company. Wah Chang claims that during 1998 through 2001 the Company and other energy companies (and in a separate complaint, energy marketers) engaged in various fraudulent and illegal activities including the transmittal of electronic wire communications to transmit false or misleading information to manipulate the California energy market. The claims include submitting false information such as energy schedules and bids to the California PX, CAISO, electronic trading platforms and publishers of energy indexes. The complaint is similar to the allegations made by the Port of Seattle currently on appeal in the Ninth Circuit. The Judicial Panel on Multi District Litigation consolidated this case with another pending Multi District case and transferred it to Federal District Court in San Diego on August 20, 2004. The defendants in both cases filed motions to dismiss on October 25, 2004.

6. California Litigation.Attorney General Cases. On September 9, 2004, the Ninth Circuit issued a decision on the California Attorney General’s challenge to the validity of FERC’s market-based rate system.(Lockyer v. FERC). This case was originally presented to FERC. The Ninth Circuit upheld FERC’s authority to authorize sales of electric energy at market based rates, but found the requirement that all sales at market-based rates be contained in quarterly reports filed with FERC to be integral to a market-based rate tariff. The California parties, among others, have interpreted the decision as providing authority to FERC to order refunds for different time frames and based on different rationales than are currently pending in the California Refund Proceedings, discussed above in “California Refund Proceedings”. The decision itself defers the question of whether to seek refunds to FERC. PSE, along with other defendants in the proceeding, sought rehearing of the Ninth Circuit’s decision on October 25, 2004.
        In addition, the day after the initial FERC decision in theLockyer case, the California Attorney General filed similar claims in state court in California, including one suit against PSE. These complaints alleged that the wholesale seller defendants in the California energy market engaged in anti-competitive behavior in violation of the California Business Practices Act for sales in the California energy market(Lockyer v. Transalta). Those cases were removed to federal court and dismissed. On October 12, 2004, the Ninth Circuit issued a decision affirming the dismissal of all thirteen complaints filed by the California Attorney General, including a complaint against PSE. The Ninth Circuit decision concluded that the opinions inPeople of the State of California ex rel. Bill Lockyer v. Dynegy, et al. andPublic Utility District No. 1 of Snohomish County v. Dynegy Power Marketing, Inc., decided earlier this year by the Ninth Circuit, controlled the outcome of the matters and warranted dismissal. It has been reported that the California Attorney General plans to seek a rehearing.
        California Class Actions. In May 2002, PSE was served with two cross-complaints, by Reliant Energy Services and Duke Energy Trading & Marketing, respectively, in six consolidated class actions filed in Superior Court in San Diego, California. Plaintiffs in the lawsuit seek, among other things, restitution of all funds acquired by means that violate the law and payment of treble damages, interest and penalties. The cross complaints asserted essentially that the cross-defendants, including PSE, were also participants in the California energy market at the relevant times, and that any remedies ordered against some market participants should be ordered against all. Reliant and Duke also seek indemnification and conditional relief as buyers in transactions involving cross-defendants should the plaintiffs prevail. The case was removed to federal court and some of the newly added defendants, including PSE, moved to dismiss the action. In December 2002, the federal district court remanded the proceeding to state court, an action which Duke and Reliant later appealed to the Ninth Circuit. The appeal stayed further action in the state court proceeding pending the outcome of the appeal. The cross complaints and the addition of the 40 new defendants raised issues of foreign sovereign immunity, jurisdiction and indemnity in the case, all of which are now part of the appeal. In June 2003, PSE and other defendants filed motions to respond to the indemnity issues. On May 13, 2004, the Ninth Circuit issued an order granting PSE status as a cross appellant but did not permit PSE to participate in the oral argument heard on June 14, 2004. The parties await the court’s ruling on the appeal.

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 exposes 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:

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

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

• Maximize 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. Portfolio exposure is managed in accordance with Company polices and procedures. The Energy 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 Energy 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 tariffs 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 the use of forward price instruments.
        The PGA and the PCA mechanisms 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 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. The Company has hedged a significant portion of its 2004 – 2005 winter energy supply for both electric and gas portfolios at prices below current market prices. Hedging costs are passed through in the PGA and PCA mechanisms. The majority of these hedges are normal purchase or cash flow hedges under SFAS No. 133.
        At September 30, 2004, the Company had a SFAS No. 133 after-tax net asset of approximately $25.2 million of energy contracts designated as qualifying cash flow hedges and a corresponding unrealized gain recorded in other comprehensive income. Of the amount in other comprehensive income, 99% of the mark-to-market gain beginning November 2004 has been reclassified out of other comprehensive income to a deferred account in accordance with SFAS No. 71 due to the Company expecting to reach the $40 million cap under the PCA mechanism. The Company also had energy contracts that were marked-to-market at a loss of $1.2 million after-tax through current earnings for the three months ended September 30, 2004 and at a gain of $0.7 million for the nine months ended September 30, 2004. These mark-to-market adjustments were primarily the result of excluding certain contracts from the normal purchase normal sale exemption under SFAS No. 133. A portion of the mark-to-market adjustments beginning November 2004 has been reclassified to a deferred account in accordance with SFAS No. 71 due to the Company expecting to reach the $40 million cap under the PCA mechanism. 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 $4.9 million after-tax and would increase current earnings for those contracts marked-to-market in earnings by an insignificant amount as a result of applying SFAS No. 71 for the portion that exceeds the $40 million PCA mechanism cap.

Counterparty Credit Risk. The Company is subject to credit risk from counterparties based on transactions it enters into during the normal course of business. The Company is exposed to risk to the extent that counterparties fail to perform on their contractual obligations. These counterparties include other utilities, energy trading companies, financial institutions and natural gas production companies. The Company mitigates its exposure by transacting with counterparties that meet minimum credit thresholds, setting credit limits and obtaining master agreements. Credit exposures are reviewed daily to ensure transactions continually meet the Company’s standards. The Company monitors both utilization of open credit, as well as potential credit exposure to its counterparties. The majority of the Company’s counterparties are investment grade rated.

Interest Rate Risk. The Company believes its interest rate risk primarily relates to the use of short-term debt instruments, variable rate notes and 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 utilizes bank borrowings, commercial paper, line of credit facilities and accounts receivable securitization 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 or other financial hedge instruments to manage the interest rate risk associated with these debts.
        In the third quarter 2004, the Company entered into two treasury lock contracts to hedge against potential rising interest rate exposure for a debt offering anticipated to be performed in the first half of 2005. A treasury lock is a financial arrangement between the Company and a counterparty whereby one of the parties will be required to make a payment to the other party on a specific valuation date based upon the change in value of a 30 year treasury bond. If interest rates rise related to the hedged debt from the date of issuance of the treasury lock instruments, the Company would receive a payment from the counterparty for the change in the bond value. Alternatively, if interest rates decrease related to the hedged debt from the date of issuance of the treasury lock instruments, the Company would pay the counterparty for the change in bond value. These treasury lock contracts were designated under SFAS No. 133 criteria as cash flow hedges, with all changes in market value for each reporting period being presented net of tax in other comprehensive income. All financial hedge contracts of this type are reviewed by senior management and presented to the Securities Pricing Committee of the Board of Directors, and are approved prior to execution. At September 30, 2004, the unrealized loss associated with the two treasury lock contracts was $4.3 million net of tax, and is included in other comprehensive income. When these treasury lock contracts are settled upon issuance of debt, any gain or loss will be amortized from other comprehensive income to interest expense over the 30 year life of the issued debt. A hypothetical 10% decrease in the price of a 30 year treasury note would result in an additional loss of $14.0 million net of tax in other comprehensive income.

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’ President and Chief Executive Officer and Senior Vice President 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 President and Chief Executive Officer and Senior Vice President 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.

        Pursuant to Section 404 of the Sarbanes-Oxley Act and related Securities and Exchange Commission rules, Puget Energy will be required to furnish a report of management’s assessment of the effectiveness of its internal controls as part of its Annual Report on Form 10-K for the fiscal year ending December 31, 2004. Puget Energy’s auditors will be required to attest to and report on management’s assessment. To issue the report, Puget Energy management must document both the design for its internal controls and the testing processes that support management’s evaluation and conclusion. Puget Energy has begun the necessary processes and procedures for issuing its report on internal controls. There can be no assurance, however, that Puget Energy will be able to complete the work necessary to issue its report in a timely manner or that management or its auditors will conclude that internal controls are effective.

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, 2004. 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

See Exhibit Index for list of exhibits.

SIGNATURES

        Pursuant to the requirements of Section 13 or 15(d) 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 4, 2004	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 (1999 through 2003 and 12 months ended September 30, 2004) for Puget Energy.

12.2 Statement setting forth computation of ratios of earnings to fixed charges (1999 through 2003 and 12 months ended September 30, 2004) 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.