PUGET ENERGY INC /WA - 10-Q 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 ended March 31, 2005

[ ]	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 NE 4^th Street, Suite 1200

Bellevue, Washington 98004-5591

(425) 454-6363

91-1969407

1-4393

PUGET SOUND ENERGY, INC.

A Washington Corporation

10885 NE 4^th 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

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 April 22, 2005, (i) the number of shares of Puget Energy, Inc. common stock outstanding was 100,050,643 ($.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

Definitions
Filing Format

Forward Looking Statements

Part I.	Financial Information
Item 1.	Financial Statements

	Puget Energy, Inc.
	Consolidated Statements of Income - Three Months Ended March 31, 2005 and 2004
	Consolidated Statements of Comprehensive Income - Three Months Ended March 31, 2005 and 2004
	Consolidated Balance Sheets - March 31, 2005 and December 31, 2004
	Consolidated Statements of Cash Flows - Three Months Ended March 31, 2005 and 2004

	Puget Sound Energy, Inc.
	Consolidated Statements of Income - Three Months Ended March 31, 2005 and 2004
	Consolidated Statements of Comprehensive Income - Three Months Ended March 31, 2005 and 2004
	Consolidated Balance Sheets - March 31, 2005 and December 31, 2004
	Consolidated Statements of Cash Flows - Three Months Ended March 31, 2005 and 2004

	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

Table of Contents

DEFINITIONS

APB	Accounting Principles Board
CAISO	California Independent System Operator
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN	Financial Accounting Standards Board Interpretation
FPA	Federal Power Act
InfrastruX	InfrastruX Group, Inc.
LIBOR	London Interbank Offered Rate
MMS	Mineral Management Service of the United States Department of the Interior
MW	Megawatts (one MW equals one thousand kW)
MWh	Megawatt Hours (one MWh equals one thousand kWh)
PCA	Power Cost Adjustment
PCORC	Power Cost Only Rate Case
PGA	Purchased Gas Adjustment
PG&E	Pacific Gas & Electric Company
PSE	Puget Sound Energy, Inc.
Puget Energy	Puget Energy, Inc.
SFAS	Statement of Financial Accounting Standards
WECO	Western Energy Company
Washington Commission	Washington Utilities and Transportation Commission

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.

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FORWARD-LOOKING STATEMENTS

Puget Energy and Puget Sound Energy (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 that 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, cost recovery, 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, operation of distribution and transmission facilities (gas and electric), licensing of hydroelectric 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 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 and/or impact delivery of energy to PSE from its suppliers;

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

·	the effect of wholesale market structures (including, but not limited to, regional market designs such as Grid West, or federal initiatives such as Standard Market Design);

·	PSE electric or gas distribution system failure, which may impact PSE’s ability to adequately deliver gas supply to its customers;

·	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;

·	variable hydroelectric conditions, which can impact streamflow and PSE’s ability to generate electricity from hydroelectric facilities;

·	plant outages, which can have an adverse impact on PSE’s expenses as it procures adequate supplies to replace the lost energy or dispatches a more expensive resource;

·	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;

·	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;

·	the ability to restart generation following a regional transmission disruption;

·	failure of the interstate gas pipeline delivering to PSE’s system, which may impact PSE’s ability to adequately deliver gas supply to its customers;

·	the ability to relicense FERC hydroelectric projects at a cost-effective level;

·	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, which might impact customer consumption or affect PSE’s accounts receivable; and

·	the loss of significant customers or changes in the business of significant customers, which may result in changes in demand for PSE’s services.

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

·	the ability of Puget Energy to complete a sale of its interests in InfrastruX to a third party under reasonable terms;

·	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 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 quality or lower in price;

·	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;

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

·	the perception of risk associated with its business due to a challenging business environment.

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;

·	the impacts of natural disasters such as earthquakes, hurricanes, floods, fires or landslides;

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

·	the ability to maintain effective internal controls over financial reporting; and

·	the ability to maintain customers and employees.

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.

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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 March 31
	2005			2004
Operating Revenues:
Electric	$	420,090		$	392,495
Gas		321,129			275,692
Other		434			527
Total operating revenues		741,653			668,714
Operating Expenses:
Energy costs:
Purchased electricity		208,178			196,367
Electric generation fuel		20,448			13,988
Residential exchange		(55,046	)		(54,423	)
Purchased gas		201,744			162,407
Unrealized (gain) loss on derivative instruments		509			(87	)
Utility operations and maintenance		75,522			73,855
Other operations and maintenance		741			484
Depreciation and amortization		58,077			55,870
Conservation amortization		5,162			8,190
Taxes other than income taxes		69,700			64,224
Income taxes		46,084			39,097
Total operating expenses		631,119			559,972
Operating Income		110,534			108,742
Other income (deductions):
Other income		1,164			68
Interest charges:
AFUDC		1,462			1,078
Interest expense		(41,044	)		(43,121	)
Mandatorily redeemable securities interest expense		(23	)		(23	)
Income from continuing operations		72,093			66,744
Loss from discontinued operations, net of tax		(1,018	)		(379	)
Net income	$	71,075		$	66,365
Common shares outstanding weighted average (in thousands)		99,953			99,169
Diluted common shares outstanding weighted average (in thousands)		100,446			99,637
Basic and diluted earnings per common share from continuing operations	$	0.72		$	0.67
Basic and diluted earnings per common share from discontinued operations		(0.01	)		--
Basic and diluted earnings per common share	$	0.71		$	0.67

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

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PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in thousands)

(Unaudited)

	Three Months Ended March 31
	2005			2004
Net income	$	71,075		$	66,365
Other comprehensive income, net of tax:
Foreign currency translation adjustment		3			265
Unrealized gains on derivative instruments during the period		15,658			7,305
Reversal of unrealized gains on derivative instruments settled during the period		(1,817	)		(2,570	)
Deferral related to power cost adjustment mechanism		(5,563	)		(4,687	)
Other comprehensive income		8,281			313
Comprehensive income	$	79,356		$	66,678

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

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PUGET ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

(Unaudited)

ASSETS

	March 31, 2005			March 31, 2004
Utility Plant: (at original cost, including construction work in progress of $179,518 and $129,966, respectively)
Electric	$	4,441,017		$	4,389,882
Gas		1,911,542			1,881,768
Common		417,343			409,677
Less: Accumulated depreciation and amortization		(2,480,458	)		(2,452,969	)
Net utility plant		4,289,444			4,228,358
Other property and investments		160,830			157,670
Current assets:
Cash		13,984			12,955
Restricted cash		1,146			1,633
Accounts receivable, net of allowance for doubtful accounts		268,977			137,659
Unbilled revenue		111,992			140,391
Purchased gas adjustment receivable		22,331			19,088
Materials and supplies, at average cost		87,231			97,578
Unrealized gain on derivative instruments		65,431			14,791
Prepayments and other		11,819			6,858
Deferred income taxes		--			1,415
Current assets of discontinued operations		107,487			110,922
Total current assets		690,398			543,290
Other long-term assets:
Regulatory asset for deferred income taxes		136,122			127,252
Regulatory asset for PURPA contract buyout costs		206,223			211,241
Unrealized gain on derivative instruments		22,223			21,315
Power cost adjustment mechanism		15,020			--
Other		339,505			401,795
Long-term assets of discontinued operations		165,335			160,298
Total other long-term assets		884,428			921,901
Total assets	$	6,025,100		$	5,851,219

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

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PUGET ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

(Unaudited)

CAPITALIZATION AND LIABILITIES

	March 31, 2005			December 31, 2004
Capitalization:
Common shareholders’ investment:
Common stock $0.01 par value, 250,000,000 shares authorized, 100,039,422 and 99,868,368 shares outstanding, respectively	$	1,000		$	999
Additional paid-in capital		1,625,844			1,621,756
Earnings reinvested in the business		59,960			13,853
Accumulated other comprehensive loss, net of tax		(6,051	)		(14,332	)
Total shareholders’ equity		1,680,753			1,622,276
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		2,069,360			2,069,360
Total redeemable securities and long-term debt		2,351,499			2,351,499
Total capitalization		4,032,252			3,973,775
Minority interest in discontinued operations		4,651			4,648
Current liabilities:
Accounts payable		202,613			226,478
Short-term debt		97,051			--
Current maturities of long-term debt		31,000			31,000
Accrued expenses:
Taxes		113,136			81,315
Salaries and wages		13,341			13,829
Interest		40,335			29,005
Unrealized loss on derivative instruments		17,185			26,581
Deferred income taxes		5,109			--
Tenaska disallowance reserve		--			3,156
Other		36,060			34,918
Current liabilities of discontinued operations		54,847			51,892
Total current liabilities		610,677			498,174
Long-term liabilities:
Deferred income taxes		807,786			795,291
Long-term portion of unrealized loss on derivative instruments		--			385
Other deferred credits		387,419			395,236
Long-term liabilities of discontinued operations		182,315			183,710
Total long-term liabilities		1,377,520			1,374,622
Total capitalization and liabilities	$	6,025,100		$	5,851,219

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

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PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)

(Unaudited)

	Three Months Ended March 31
	2005			2004
Operating activities:
Net income	$	71,075		$	66,365
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		60,074			60,288
Deferred income taxes and tax credits - net		6,075			21,112
Net unrealized (gain) loss on derivative instruments		509			(87	)
Cash collateral received from energy suppliers		3,100			--
Decrease in residential exchange program		(11,159	)		(10,296	)
Other		(2,929	)		(2,798	)
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue		(97,786	)		(26,122	)
Materials and supplies		10,702			11,188
Prepayments and other		(8,656	)		(2,994	)
Purchased gas receivable		(3,242	)		(11,083	)
Accounts payable		(23,352	)		(29,958	)
Taxes payable		31,720			15,703
Tenaska disallowance reserve		(3,156	)		--
Accrued expenses and other		12,679			15,621
Net cash provided by operating activities		45,654			106,939
Investing activities:
Construction and capital expenditures-excluding equity AFUDC		(124,376	)		(71,489	)
Energy efficiency expenditures		(4,738	)		(4,440	)
Refundable cash received for customer construction projects		3,582			2,199
Restricted cash		486			1,365
Other		5,515			(1,924	)
Net cash used by investing activities		(119,531	)		(74,289	)
Financing activities:
Change in short-term debt - net		100,035			(155	)
Dividends paid		(21,924	)		(21,604	)
Issuance of common stock		1,017			1,208
Issuance of bonds and notes		--			625
Redemption of bonds and notes		(2,946	)		(23,356	)
Issuance costs of bonds and other		(737	)		1,434
Net cash provided (used) by financing activities		75,445			(41,848	)
Net increase (decrease) in cash		1,568			(9,198	)
Change in cash from discontinued operations		(539	)		7,687
Cash at beginning of year		12,955			14,778
Cash at end of period	$	13,984		$	13,267
Supplemental cash flow information:
Cash payments for:
Interest (net of capitalized interest)	$	32,511		$	35,982
Income taxes		22,000			16,174

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

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PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in thousands)

(Unaudited)

	Three Months Ended March 31
	2005			2004
Operating revenues:
Electric	$	420,090		$	392,495
Gas		321,129			275,692
Other		434			527
Total operating revenues		741,653			668,714
Operating expenses:
Energy costs:
Purchased electricity		208,178			196,367
Electric generation fuel		20,448			13,988
Residential exchange		(55,046	)		(54,423	)
Purchased gas		201,744			162,407
Unrealized (gain) loss on derivative instruments		509			(87	)
Utility operations and maintenance		75,522			73,855
Other operations and maintenance		259			300
Depreciation and amortization		58,077			55,870
Conservation amortization		5,162			8,190
Taxes other than income taxes		69,700			64,224
Income taxes		46,545			39,178
Total operating expenses		631,098			559,869
Operating income		110,555			108,845
Other income (deductions):
Other income, net of tax		1,164			68
Interest charges:
AFUDC		1,462			1,078
Interest expense		(40,976	)		(43,070	)
Mandatorily redeemable securities interest expense		(23	)		(23	)
Net income	$	72,182		$	66,898

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

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PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in thousands)

(Unaudited)

	Three Months Ended March 31
	2005			2004
Net income	$	72,182		$	66,898
Other comprehensive income, net of tax:
Unrealized gains on derivative instruments during the period		15,658			7,305
Reversal of unrealized gains on derivative instruments settled during the period		(1,817	)		(2,570	)
Deferral related to power cost adjustment mechanism		(5,563	)		(4,687	)
Other comprehensive income		8,278			48
Comprehensive income	$	80,460		$	66,946

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

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PUGET SOUND ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

(Unaudited)

ASSETS

	March 31, 2005			December 31, 2004
Utility plant: (at original cost, including construction work in progress of $179,518 and $129,966, respectively)
Electric	$	4,441,017		$	4,389,882
Gas		1,911,542			1,881,768
Common		417,343			409,677
Less: Accumulated depreciation and amortization		(2,480,458	)		(2,452,969	)
Net utility plant		4,289,444			4,228,358
Other property and investments		160,830			157,670
Current assets:
Cash		13,984			12,955
Restricted cash		1,146			1,633
Accounts receivable, net of allowance for doubtful accounts		269,251			138,792
Unbilled revenues		111,992			140,391
Purchased gas receivable		22,331			19,088
Materials and supplies, at average cost		87,231			97,578
Unrealized gain on derivative instruments		65,431			14,791
Prepayments and other		11,209			6,247
Deferred income taxes		--			1,415
Total current assets		582,575			432,890
Other long-term assets:
Regulatory asset for deferred income taxes		136,122			127,252
Regulatory asset for PURPA contract buyout costs		206,223			211,241
Unrealized gain on derivative instruments		22,223			21,315
Power cost adjustment mechanism		15,020			--
Other		338,806			401,030
Total other long-term assets		718,394			760,838
Total assets	$	5,751,243		$	5,579,756

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

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PUGET SOUND ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

(Unaudited)

CAPITALIZATION AND LIABILITIES

	March 31, 2005			December 31, 2005
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		610,368			609,467
Earnings reinvested in the business		187,807			138,678
Accumulated other comprehensive loss, net of tax		(6,472	)		(14,750	)
Total shareholder’s equity		1,650,741			1,592,433
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		2,064,360			2,064,360
Total redeemable securities and long-term debt		2,346,499			2,346,499
Total capitalization		3,997,240			3,938,932
Current liabilities:
Accounts payable		205,882			229,747
Short-term debt		97,051			--
Current maturities of long-term debt		31,000			31,000
Accrued expenses:
Taxes		114,477			81,634
Salaries and wages		13,341			13,829
Interest		40,335			29,005
Unrealized loss on derivative instruments		17,185			26,581
Tenaska disallowance reserve		--			3,156
Deferred income taxes		5,109			--
Other		34,342			34,918
Total current liabilities		558,722			449,870
Long-term liabilities:
Deferred income taxes		807,929			795,392
Unrealized loss on derivative instruments		--			385
Other deferred credits		387,352			395,177
Total long-term liabilities		1,195,281			1,190,954
Total capitalization and liabilities	$	5,751,243		$	5,579,756

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

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PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)

(Unaudited)

	Three Months Ended March 31
	2005			2004
Operating activities:
Net income	$	72,182		$	66,898
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		58,077			55,870
Deferred income taxes and tax credits, net		5,735			21,255
Net unrealized (gain) loss on derivative instruments		509			(87	)
Cash collateral received from energy suppliers		3,100			--
Decrease in residential exchange program		(11,159	)		(10,296	)
Other		(4,626	)		(1,856	)
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue		(102,060	)		(24,856	)
Materials and supplies		10,347			11,578
Prepayments and other		(4,962	)		448
Purchased gas receivable		(3,243	)		(11,083	)
Accounts payable		(23,865	)		(29,962	)
Taxes payable		32,843			14,361
Tenaska disallowance reserve		(3,156	)		--
Accrued expenses and other		10,263			15,431
Net cash provided by operating activities		39,985			107,701
Investing activities:
Construction expenditures - excluding equity AFUDC		(117,931	)		(65,786	)
Energy efficiency expenditures		(4,738	)		(4,440	)
Restricted cash		487			1,365
Refundable cash received for customer construction projects		3,582			2,199
Other		5,514			(2,501	)
Net cash used by investing activities		(113,086	)		(69,163	)
Financing activities:
Change in short-term debt, net		97,051			--
Dividends paid		(23,053	)		(22,431	)
Redemption of bonds and notes		--			(20,145	)
Issuance cost of bonds and other		132			2,527
Net cash provided (used) by financing activities		74,130			(40,049	)
Net increase (decrease) in cash		1,029			(1,511	)
Cash at beginning of year		12,955			14,778
Cash at end of period	$	13,984		$	13,267
Supplemental cash flow information:
Cash payments for:
Interest (net of capitalized interest)	$	30,549		$	34,583
Income taxes		22,000			16,174

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

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1)

Summary of Consolidation Policy

BASIS OF PRESENTATION

Puget Energy is an exempt public utility holding company under the Public Utility Holding Company Act of 1935. Puget Energy owns Puget Sound Energy (PSE) and 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 utility construction services company incorporated in the State of Washington, which provides construction services to the electric and gas utility industries 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. The financial position and results of operations for InfrastruX have been presented as a discontinued operation (see Note 2). 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. 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 management 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, 2004. Puget Energy previously had two reportable segments which included regulated utility operations (PSE) and utility construction services (InfrastruX). With the treatment of InfrastruX as a discontinued operation, Puget Energy now only has one reportable segment.

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

(2) Discontinued Operations (Puget Energy Only)

Following a strategic review of Puget Energy’s unregulated subsidiary, InfrastruX Group, Inc., on February 8, 2005 Puget Energy’s Board of Directors decided to exit the utility construction services sector. Puget Energy intends to monetize its interest in InfrastruX through a sale and to invest the proceeds of such monetization in its regulated utility subsidiary, PSE. This planned disposal meets the criteria established for recognition as a discontinued operation under Statement of Financial Accounting Standard (SFAS) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” and is expected to be completed during 2005.

The following amounts related to InfrastruX have been segregated from continuing operations and reflected as discontinued operations:

(DOLLARS IN THOUSANDS) THREE MONTHS ENDED MARCH 31		2005			2004
Revenues	$	77,692		$	74,756
Operating expenses (including interest expense)		79,433			75,564
Pre-tax loss		(1,741	)		(808	)
Income tax benefit		726			386
Minority interest in (income) loss of discontinued operations		(3	)		43
Loss from discontinued operations	$	(1,018	)	$	(379	)

Loss from discontinued operations for the three months ended March 31, 2005 includes a charge of $1.1 million after-tax related to the estimated loss upon disposal of InfrastruX. In accordance with SFAS No. 144, InfrastruX discontinued depreciation and amortization of its assets effective February 8, 2005. This discontinuation of depreciation and amoritization resulted in $2.6 million ($1.6 million after-tax) lower depreciation and amortization expense than otherwise would have been recorded as continuing operations.

InfrastruX’s summarized balance sheets, excluding intercompany balances eliminated in consolidation, are as follows:

(DOLLARS IN THOUSANDS)		March 31, 2005		December 31, 2004
Assets:
Cash	$	7,356	$	6,817
Accounts receivable		73,512		78,646
Other current assets		26,619		25,459
Total current assets		107,487		110,922
Goodwill		43,886		43,503
Intangibles		16,189		16,680
Non-utility property and other		105,260		100,115
Total long-term assets		165,335		160,298
Total assets	$	272,822	$	271,220
Liabilities:
Accounts payable	$	10,287	$	9,773
Short-term debt		11,281		8,297
Current maturities of long-term debt		6,796		7,933
Other current liabilities		26,483		25,889
Total current liabilities		54,847		51,892
Deferred income taxes		24,031		25,828
Long-term debt		141,363		143,172
Other deferred credits		16,921		14,710
Total long-term liabilities		182,315		183,710
Total liabilities	$	237,162	$	235,602

(3) 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 99,953,000 for the three months ended March 31, 2005 and 99,169,000 for the three months ended March 31, 2004.

Puget Energy’s diluted earnings per common share have been computed based on weighted average common shares outstanding of 100,446,000 for the three months ended March 31, 2005 and 99,637,000 for the three months ended March 31, 2004. These shares include the dilutive effect of securities related to employee and director equity plans.

(4) Accounting for Derivative Instruments and Hedging Activities

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 and interest rate exposure including forward physical and financial contracts, option contracts and swaps. The majority of these contracts qualify for the normal purchase normal sale exception. Those contracts that do not meet normal purchase normal sale exception 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,” for energy related derivatives due to the Power Cost Adjustment (PCA) mechanism.

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 is not engaged in the business of assuming risk for the purpose of speculative trading revenues. Therefore, wholesale market transactions are focused on balancing the Company’s energy portfolio, reducing costs and risks where feasible, and reducing volatility in wholesale costs and margin in the portfolio. In order to manage risks effectively, the Company enters into physical and financial transactions, which are appropriate for the service territory of the Company and are relevant to its regulated electric and gas portfolios.

The Company’s energy risk management staff develops hedging strategies for the Company’s energy supply portfolio. The first priority is to obtain reliable supply for delivery to the Company’s retail customers. The second priority is to protect against unwanted risk exposure. The third priority is to optimize excess capacity or flexibility within the energy portfolio.

The Company has entered into master netting agreements with counterparties when available to mitigate credit exposure to those counterparties. The Company believes that entering into such agreements reduces risk of settlement default with the ability to make only one net payment. In addition, the Company believes risk is mitigated with an improved position in potential counterparty bankruptcy situations due to a consistent netting approach. The Company was subject to a range of netting provisions, including both stand alone agreements and the provisions associated with the Western Systems Power Pool agreement of which many energy suppliers in the western United States are a part.

During the three months ended March 31, 2005, the Company recorded a decrease in earnings for the change in the market value of derivative instruments not meeting cash flow hedge criteria of approximately $0.5 million compared to an increase in earnings of approximately $0.1 million for the three months ended March 31, 2004. At March 31, 2005, the Company had a net unrealized gain recorded in other comprehensive income of $1.7 million after-tax related to energy and financial contracts which meet the criteria for designation as cash flow hedges under SFAS No. 133. In 2005, a portion of the total unrealized gain on cash flow hedge transactions in other comprehensive income and the marked-to-market loss in the income statement were deferred in accordance with SFAS No. 71 due to the Company exceeding the $40 million cap under the PCA mechanism. When these transactions are realized, they will be reflected in the PCA calculation.

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 the 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 March 31, 2005 the Company recorded a liability associated with these two contracts in the amount of $16.3 million and an unrealized loss in the amount of $10.6 million, after-tax, which is included in other comprehensive income.

(5) Asset Retirement Obligations

SFAS No. 143, “Accounting for Asset Retirement Obligations,” requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time 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 identified various asset retirement obligations upon initial adoption of SFAS No. 143 on January 1, 2003, and identified an additional asset retirement obligation related to unprotected bare steel gas pipe in January 2005. Currently, 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; (4) to restore ash holding ponds at a jointly-owned coal-fired electric generating facility in Montana; and (5) to replace all unprotected bare steel gas pipe in its service territory by 2015 as a result of a January 31, 2005 Washington Commission order.

The following table describes all changes to the Company’s asset retirement obligation liability during the three months ended March 31:

(DOLLARS IN THOUSANDS)
AT MARCH 31		2005			2004
Asset retirement obligation at beginning of year	$	3,516		$	3,421
Liability recognized in the period		2,202			--
Liability settled in the period		(254	)		--
Accretion expense		47			22
Asset retirement obligation at March 31	$	5,511		$	3,443

(6)

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 from 2003 on, while grants that were made in years prior to 2003 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 March 31
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)	2005			2004
Net income , as reported	$	71,075		$	66,365
Add: Total stock-based employee compensation expense included in net income, net of tax		636			616
Less: Total stock-based employee compensation expense per the fair value method of SFAS No. 123, net of tax		(810	)		(528	)
Pro forma net income	$	70,901		$	66,453

Earnings per share:
Basic and diluted per common share as reported	$	0.71		$	0.67
Basic and diluted per common share pro forma	$	0.71		$	0.67

(7) Retirement Benefits

The following summarizes the net periodic benefit cost for the three months ended March 31:

	Pension Benefits						Other Benefits
(DOLLARS IN THOUSANDS)	2005			2004			2005			2004
Service cost	$	3,041		$	2,508		$	56		$	50
Interest cost		5,964			5,966			404			438
Expected return on plan assets		(9,513	)		(9,800	)		(219	)		(222	)
Amortization of prior service cost		756			805			77			77
Recognized net actuarial loss		743			282			--			--
Amortization of transition (asset) obligation		(41	)		(275	)		105			105
Net periodic benefit cost (income)	$	950		$	(514	)	$	423		$	448

The Company previously disclosed in its financial statements for the year ended December 31, 2004 that it expected contributions by the Company to fund the pension and other benefits plans for the year ended December 31, 2005 to be $2.0 million and $1.4 million, respectively. During the first quarter 2005, the actual cash contributions to the pension plans were $0.5 million. In addition, some plan participants chose lump sum pension payments totaling $0.6 million and deferred them under the Company’s deferred compensation plan in the first quarter 2005. Based on this activity, the Company anticipates contributing an additional $0.9 million to the Company’s pension plan in 2005. The full amount of the pension plan funding for 2005 is for the Company’s non-qualified supplemental retirement plan.

During the three months ended March 31, 2005, actual other post-retirement medical benefit plan contributions were $0.4 million, and the Company expects to make additional contributions of $1.0 million for a total of $1.4 million in 2005.

(8) Other

On February 18, 2005, the Washington Commission approved a 3.5% general tariff gas rate case increase and a 4.1% general tariff electric rate case increase which was clarified in an order of March 1, 2005. The increases of $26.3 million annually for gas customers and $57.7 million annually for electric customers were effective March 4, 2005. In the order, the Washington Commission also approved a capital structure of 43% common equity with a return on common equity of 10.3%.

On February 23, 2005, the Washington Commission issued an order concerning PSE’s compliance filing related to the PCA 2 period of July 1, 2003 through June 30, 2004. In its order, the Washington Commission determined that PSE was allowed to reflect additional power costs totaling $6.0 million during the PCA 2 period for the period July 1, 2003 through December 31, 2003. These costs represent an additional return on PSE’s regulatory assets for the Tenaska generating facility. These costs were deferred under the PCA mechanism, which resulted in a reduction in purchased electricity expense for the three month period ended March 31, 2005.

On November 1, 1999, PSE acquired Encogen Northwest, LP (Encogen) whose sole asset is a natural gas-fired cogeneration facility located in Washington State. With the approval of the Washington Commission, the Encogen facility has been operated as part of PSE’s least cost generation dispatch portfolio to serve its native load obligations since it was acquired in 1999. Two wholly-owned subsidiaries of PSE, GP Acquisition Corporation and LP Acquisition Corporation, are the general and limited partners of Encogen, respectively. On December 29, 2004, PSE filed an application with FERC pursuant to Section 203 of the Federal Power Act to transfer the Encogen facility to PSE and eliminate the various subsidiaries via an Agreement and Plan of Merger (Merger). On February 15, 2005, FERC issued an order authorizing the Encogen plant to be transferred to PSE. PSE anticipates completing the Merger in the second quarter of 2005.

On April 7, 2004 the Washington Commission approved PSE’s recovery on the amortized White River plant investment. At March 31, 2005, the White River project net book value totaled $65.0 million, which included $46.0 million of net utility plant, $14.7 million of capitalized FERC licensing costs, $3.2 million of costs related to construction work in progress and $1.1 million related to dam operation and safety. In its February 18, 2005 general rate case order, the Washington Commission approved a Washington Commission staff recommendation that PSE be allowed recovery of the White River net utility plant costs noted above, but defer recovery of other costs until all costs and any sales proceeds are known.

In January 2003, the Financial Accounting Standards Board (FASB) issued Interpretation No. 46R, “Consolidation of Variable Interest Entities” (FIN 46R). FIN 46R 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 Company has 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 that it does not have a contractual right to such information. PSE will continue to submit requests for information to the counterparties on a quarterly basis 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 months ended March 31, 2005 and 2004 for these three entities was $71.8 million and $67.5 million, respectively.

(9) New Accounting Pronouncements

In December 2004, FASB issued SFAS No. 123R, “Share-Based Payment”, which revises SFAS No. 123, “Accounting For Stock-Based Compensation.” SFAS No. 123R requires companies that issue share-based payment awards to employees for goods or services to recognize as compensation expense, the fair value of the expected vested portion of the award as of the grant date over the vesting period of the award. Forfeitures that occur before the award vesting date will be adjusted from the total compensation expense, but once the award vests, no adjustment to compensation expense will be allowed for forfeitures or unexercised awards. In addition, SFAS No. 123R would require recognition of compensation expense of all existing outstanding awards that are not fully vested for their remaining vesting period as of the effective date that were not accounted for under a fair value method of accounting at the time of their award. SFAS No. 123R was originally effective for interim reporting periods beginning after June 15, 2005. However, on April 14, 2005, the Securities and Exchange Commission delayed implementation of SFAS No. 123R to annual reporting periods beginning after June 15, 2005. The Company is currently evaluating what impact the application of SFAS No. 123R will have on its operations. The Company had adopted the fair value provisions of SFAS No. 123 “Accounting for Stock Based Compensation” in January 2003.

In March 2005, FASB issued FIN 47, which finalized a proposed interpretation of SFAS No. 143 titled “Accounting for Conditional Asset Retirement Obligations.” The interpretation addresses 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. The decision reached by FASB was that there are no instances where a law or regulation obligates an entity to perform retirement activities but then allows the entity to permanently avoid settling the obligation. The Company is currently evaluating what impact FIN 47 will have on potential asset retirement obligations. The adoption of FIN 47 is effective for fiscal years ending after December 15, 2005, and is required to be accounted for as a cumulative effect of an accounting change.

In December 2004, FASB issued FASB Staff Position No. 109-1, “Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004” (FSP No. 109-1). FSP No. 109-1 states that the staff position related to deductions as a result of the American Jobs Creation Act (the Act) should be treated as a “special deduction,” as described in SFAS No. 109, “Accounting For Income Taxes” and therefore has no effect on deferred tax assets or liabilities existing at the enactment date.

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. Following a strategic review of Puget Energy’s unregulated subsidiary, InfrastruX, on February 8, 2005 Puget Energy’s Board of Directors decided to exit the utility construction services sector. Puget Energy intends to monetize its interest in InfrastruX through a sale and to invest the proceeds of such monetization in its regulated utility subsidiary, PSE. See section titled “InfrastruX” for further discussion.

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 Utility and Transportation Commission (Washington Commission) regulation which may impact a large array of business activities, including limitation of future rate increases; directed accounting requirements 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 or other events which can damage electric distribution and transmission lines; and energy trading and wholesale market stability over time.

PSE’s main operational goal has been to provide reliable, safe and cost-effective energy 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 contracts and on the wholesale market is intended to allow customers’ rates to remain stable. PSE is continually exploring new electric-power resource generation and long-term purchase power agreements to meet this goal. During the three months ended March 31, 2005, PSE made progress in reaching this goal by completing its acquisition of the Hopkins Ridge wind project and issued a notice to proceed with construction of the project. The project is expected to provide up to 150 MW of capacity (52 average MW) and be completed by the end of 2005. In addition, PSE continues negotiations from its September 2004 non-binding letter of intent to acquire the Wild Horse wind project, which is anticipated to provide between 150 to 230 MW of capacity, and if acquired, be completed by the end of 2006.

The Hopkins Ridge wind project and proposed Wild Horse wind project 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. PSE is in the process of updating its Least Cost Plan and expects to file the updated plan with the Washington Commission in the first half of 2005.

Results of Operations

PUGET ENERGY

All the operations of Puget Energy are conducted through its subsidiaries, PSE and InfrastruX. Net income for the three months ended March 31, 2005 was $71.1 million on operating revenues of $741.7 million compared to $66.4 million on operating revenues of $668.7 million for the same period in 2004. Net income for both periods includes the results of discontinued operations for InfrastruX.

Basic and diluted earnings per share for the three months ended March 31, 2005 were $0.71 on 100.0 million weighted average common shares outstanding and 100.4 million weighted average diluted shares outstanding, respectively. Basic and diluted earnings per share for the three months ended March 31, 2004 were $0.67 on 99.2 million weighted average common shares outstanding and 99.6 million weighted average diluted shares outstanding, respectively. Included in the basic and diluted earnings per share for the three months ended March 31, 2005 was a $0.01 per share loss related to discontinued operations and estimated loss on disposal of InfrastruX. Discontinued operations did not have an earnings per share impact for the three months ended March 31, 2004.

Net income for the three months ended March 31, 2005 was positively impacted by an increased electric margin of $7.4 million compared to the same period in 2004 and lower interest expense at PSE of $2.5 million. Net income was negatively impacted by higher depreciation and amortization expense of $2.2 million for the three months ended March 31, 2005, primarily due to the acquisition of Frederickson 1 in April 2004 and other PSE transmission and distribution system infrastructure projects.

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. Varying wholesale electric prices and the amount of hydroelectric energy supplies available to PSE also make quarter-to-quarter comparisons difficult.

ENERGY MARGINS

The following table displays the details of electric margin changes for the three months ended March 31, 2005 compared to the same period in 2004.

	ELECTRIC MARGIN
(DOLLARS IN MILLIONS) THREE MONTHS ENDED MARCH 31	2005			2004			CHANGE			PERCENT CHANGE
Electric retail sales revenue	$	387.0		$	367.5		$	19.5			5.3	%
Electric transportation revenue		2.7			2.3			0.4			17.4	%
Other electric revenue-gas supply resale		4.2			3.3			0.9			27.3	%
Total electric revenue for margin		393.9			373.1			20.8			5.6	%
Adjustments for amounts included in revenue:
Pass-through tariff items		(6.5	)		(8.4	)		1.9			22.6	%
Pass-through revenue-sensitive taxes		(28.6	)		(26.1	)		(2.5	)		(9.6	)%
Residential exchange credit		55.0			54.4			0.6			1.1	%
Net electric revenue for margin		413.8			393.0			20.8			5.3	%
Minus power costs:
Fuel		(20.4	)		(14.0	)		(6.4	)		(45.7	)%
Purchased electricity, net of sales to other utilities and marketers		(209.8	)		(198.8	)		(11.0	)		(5.5	)%
Total electric power costs		(230.2	)		(212.8	)		(17.4	)		(8.2	)%
Electric margin before PCA		183.6			180.2			3.4			1.9	%
Tenaska reserve turnaround		5.3			--			5.3			*
Power cost deferred under the PCA mechanism		12.6			13.9			(1.3	)		(9.4	)%
Electric margin	$	201.5		$	194.1		$	7.4			3.8	%

_________________________________

* Percent change not applicable.

Electric margin increased $7.4 million for the three months ended March 31, 2005 compared to the same period in 2004, primarily due to final resolution and recovery of a $6.0 million return on the Tenaska Regulatory asset for the PCA 2 period, the effects of the Power Cost Only Rate Case (PCORC) for the Frederickson 1 generating facility that became effective May 24, 2004, and the effects of the electric general rate tariff case approved February 18, 2005 with an effective date of March 4, 2005. The PCORC and the electric general rate case contributed to electric margin $3.8 million and $2.7 million, respectively, for the three months ended March 31, 2005 compared to the same period in 2004, offset by a $2.8 million Tenaska disallowance for the three months ended March 31, 2005. In addition, retail customer kWh sales (residential, commercial and industrial customers) increased 0.5% in 2005 compared to 2004. These increases were partially offset by changes in customer class usage (residential, commercial and industrial). Electric margin is electric sales to retail and transportation customers less pass-through tariff items and 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.

The following table displays the details of gas margin changes for the three months ended March 31, 2005 compared to the same period in 2004.

	GAS MARGIN
(DOLLARS IN MILLIONS) THREE MONTHS ENDED MARCH 31	2005			2004			CHANGE			PERCENT CHANGE
Gas retail revenue	$	312.9		$	269.4		$	43.5			16.1	%
Gas transportation revenue		3.4			3.4			--			--
Total gas revenue for margin		316.3			272.8			43.5			15.9	%
Adjustments for amounts included in revenue:
Pass-through tariff items		(1.9	)		(1.0	)		(0.9	)		(90.0	)%
Pass-through revenue-sensitive taxes		(25.1	)		(22.3	)		(2.8	)		(12.6	)%
Net gas revenue for margin		289.3			249.5			39.8			16.0	%
Minus purchased gas costs		(201.7	)		(162.4	)		(39.3	)		(24.2	)%
Gas margin	$	87.6		$	87.1		$	0.5			0.6	%

Gas margin increased $0.5 million for the three months ended March 31, 2005 compared to the same period in 2004. Gas margin increased $2.2 million as a result of the gas general tariff rate case, which was approved February 18, 2005, with rates effective March 4, 2005. These increases were offset by decreased retail customer therm sales which decreased 3.2% in 2005 compared to 2004. The decreased usage was primarily due to overall warmer weather for the three months ended March 31, 2005 compared to the same period in 2004, with 3.5% less heating degree days for the three months ended March 31, 2005 compared to the same period in 2004. 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.

ELECTRIC OPERATING REVENUES

The table below sets forth changes in electric operating revenues for PSE for the three months ended March 31, 2005 compared to the same period in 2004.

(DOLLARS IN MILLIONS) THREE MONTHS ENDED MARCH 31	2005			2004			CHANGE			PERCENT CHANGE
Electric operating revenues:
Residential sales	$	211.8		$	204.4		$	7.4			3.6	%
Commercial sales		157.9			153.6			4.3			2.8	%
Industrial sales		22.1			22.4			(0.3	)		(1.3	)%
Other retail sales, including unbilled revenue		(4.8	)		(12.9	)		8.1			62.8	%
Total retail sales		387.0			367.5			19.5			5.3	%
Transportation sales		2.7			2.3			0.4			17.4	%
Sales to other utilities and marketers		16.3			11.5			4.8			41.7	%
Other		14.0			11.2			2.8			25.0	%
Total electric operating revenues	$	420.0		$	392.5		$	27.5			7.0	%

_________________________________

* Percent change not applicable.

Electric retail sales increased $19.5 million for the three months ended March 31, 2005 compared to the same period in 2004 due primarily to rate increases related to the PCORC and the electric general rate case, and increased retail customer usage. The PCORC and electric general rate case provided an additional $9.3 million and $9.6 million to electric operating revenues, respectively, for the three months ended March 31, 2005 compared to the same period in 2004. Retail electricity usage increased 28,331 MWh or 0.5% for the three months ended March 31, 2005 compared to the same period in 2004. The increase in electricity usage was mainly the result of a higher average number of customers served in the three month period ended March 31, 2005 compared to the same period in 2004.

During the three month period ended March 31, 2005, the benefits of the Residential and Farm Energy Exchange Benefit credited to customers reduced electric operating revenues by $57.6 million compared to $56.2 million for the same period in 2004. This credit also reduced power costs by a corresponding amount with no impact on earnings. See discussion under PSE Electric Regulation and Rates.

Sales to other utilities and marketers increased $4.8 million compared to the three month period ended March 31, 2004 primarily due to increased MWh sales of 76,174 MWh or $3.6 million related to excess generation available for sale on the wholesale market due to warmer temperatures in the first quarter 2005. In addition, $1.2 million of the increase related to higher wholesale market prices in the three months ended March 31, 2005 compared to the same period in 2004.

Other electric revenues increased $2.8 million for the three month period ended March 31, 2005 compared to the same period in 2004, primarily from the sale of excess non-core gas and electric transmission. Non-core gas sales are included in the PCA mechanism calculation.

GAS OPERATING REVENUES

The table below sets forth changes in gas operating revenues for PSE for the three months ended March 31, 2005 compared to the same period in 2004.

(DOLLARS IN MILLIONS) THREE MONTHS ENDED MARCH 31	2005		2004		CHANGE		PERCENT CHANGE
Gas operating revenues:
Residential sales	$	208.7	$	180.8	$	27.9		15.4	%
Commercial sales		91.2		77.5		13.7		17.7	%
Industrial sales		13.0		11.1		1.9		17.1	%
Total retail sales		312.9		269.4		43.5		16.1	%
Transportation sales		3.4		3.4		--		--
Other		4.8		2.9		1.9		65.5	%
Total gas operating revenues	$	321.1	$	275.7	$	45.4		16.5	%

Gas retail sales increased $43.5 million for the three months ended March 31, 2005 compared to the same period in 2004 due primarily to higher Purchased Gas Adjustment (PGA) mechanism rates in 2005 and approval of a 3.5% general gas rate increase in the gas general rate case effective March 4, 2005. The Washington Commission approved a PGA mechanism rate increase effective October 1, 2004 that increased rates 17.6% annually. The PGA mechanism passes through to customers increases or decreases in the gas supply portion of the natural gas service rates based upon changes in the price of natural gas purchased from producers and wholesale marketers or changes in gas pipeline transportation costs. PSE’s gas margin and net income are not affected by changes under the PGA mechanism. For the three months ended March 31, 2005, the effects of the PGA mechanism rate increases provided an increase of $46.4 million in gas operating revenues. In addition, the gas general rate case increased gas rates by 3.5%, which provided an additional $2.2 million in gas operating revenue for the three months ended March 31, 2005 compared to the same period in 2004. These rate increases were partially offset by lower therm sales due to 3.5% fewer heating degree days for the three months ended March 31, 2005 compared to the same period in 2004.

The following gas rate adjustments were approved by the Washington Commission in 2005 and 2004:

TYPE OF RATE ADJUSTMENT	EFFECTIVE DATE	PERCENTAGE INCREASE IN RATES		ANNUAL INCREASE IN REVENUES (DOLLARS IN MILLIONS)
PGA	October 1, 2004	17.6	%	$	121.7
Gas General Rate Case	March 4, 2005	3.5	%		26.3

OPERATING EXPENSES

The table below sets forth significant changes in operating expenses for PSE and its subsidiaries for the three months ended March 31, 2005 compared to the same period in 2004.

(DOLLARS IN MILLIONS) THREE MONTHS ENDED MARCH 31	2005		2004		CHANGE			PERCENT CHANGE
Purchased electricity	$	208.2	$	196.4	$	11.8			6.0	%
Electric generation fuel		20.4		14.0		6.4			45.7	%
Purchased gas		201.7		162.4		39.3			24.2	%
Utility operations and maintenance		75.5		73.8		1.7			2.3	%
Depreciation and amortization		58.1		55.9		2.2			3.9	%
Conservation amortization		5.2		8.2		(3.0	)		(36.6	)%
Taxes other than income taxes		69.7		64.2		5.5			8.6	%
Income taxes		46.5		39.2		7.3			18.6	%

Purchased electricity expenses increased $11.8 million for the three months ended March 31, 2005 compared to the same period in 2004 as a result of lower generation at PSE-controlled hydroelectric facilities and higher wholesale market prices. Higher wholesale market prices increased purchased electricity by $14.2 million as compared to the same period in 2004. In addition, on February 23, 2005, the Washington Commission issued an order concerning PSE’s compliance filing related to the PCA 2 period of July 1, 2003 through June 30, 2004. In its order, the Washington Commission determined that PSE was allowed to reflect additional power costs totaling $6.0 million during the PCA 2 period of July 1, 2003 through December 31, 2003. These costs were deferred under the PCA mechanism, which resulted in a reduction in purchased electricity expense for the three month period ended March 31, 2005.

PSE’s hydroelectric production and related power costs in 2005 and 2004 have continued to be negatively impacted by below-normal winter precipitation and reduced snow pack in the Pacific Northwest region. The April 11, 2005 Columbia Basin Runoff Forecast published by the National Weather Service Northwest River Forecast Center indicated that the total forecasted runoff above Grand Coulee Reservoir for the period January through July 2005 would be 83% of normal, which compares to 84% of normal for the same period in 2004. PSE cannot determine if this trend of lower than normal runoff will continue in future years nor what impact such a trend may have on the amount of electricity that will need to be purchased.

PSE had reached the $40 million cumulative cap under the PCA mechanism in February 2005 primarily due to increased wholesale power costs and adverse hydroelectric conditions. In 2004, PSE had reached and then fell below the $40 million cumulative cap due to the Tenaska disallowance ordered in May 2004. Under the PCA mechanism, excess power costs and further increases in variable power costs through June 30, 2006 will be apportioned 99% to customers and 1% to PSE. For further discussion see - Electric Regulation and Rates.

To meet customer demand, PSE economically dispatches resources in its power supply portfolio such as fossil-fuel generation, owned and contracted hydroelectric 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-term and intermediate-term off-system physical purchases and sales, and through other risk management techniques.

Electric generation fuel expense increased $6.4 million for the three months ended March 31, 2005 compared to the same period in 2004 as a result of higher fuel costs for PSE-controlled gas-fired generation facilities and increased generation at PSE-controlled generating facilities compared to the same period in 2004, including the addition of the Frederickson 1 generating facility, which was purchased and went into service in April 2004.

Purchased gas expenses increased $39.3 million for the three months ended March 31, 2005 compared to the same period in 2004 primarily due to an increase in PGA rates as approved by the Washington Commission. The PGA mechanism allows PSE to recover expected gas costs, and defer, as a receivable or liability, any gas costs that exceed or fall short of this expected gas cost amount in PGA mechanism rates, including accrued interest. The PGA mechanism receivable balance at March 31, 2005 and December 31, 2004 was $22.3 million and $19.1 million, respectively. A receivable balance in the PGA mechanism reflects a current underrecovery of market gas cost through rates.

Utility operations and maintenance expense increased $1.7 million in 2005 compared to 2004 which includes an increase of $1.9 million related to low-income program costs that are passed-through in retail rates with no impact on earnings. As a result, the pre-tax impact on net income from utility operations and maintenance was a decrease of $0.2 million. PSE anticipates operation and maintenance expense to increase in future years as PSE invests in new generating resources and energy delivery infrastructure. The timing and amounts of increases will vary depending on when new generating resources come into service.

Depreciation and amortization expense increased $2.2 million for the three months ended March 31, 2005 compared to the same period in 2004. The increase was due to the effects of new plant placed in service during 2004, including $80.8 million in costs for the Frederickson 1 generating facility in April 2004 and $32.8 million for the Everett Delta gas transmission line late in 2004. PSE anticipates depreciation expense will increase in future years as PSE invests in new generating resources and energy delivery infrastructure.

Conservation amortization decreased $3.0 million for the three months ended March 31, 2005 compared to the same period in 2004 due to the conservation trust assets being fully amortized in September 2004. Conservation amortization is a pass-through tariff item with no impact on earnings.

Taxes other than income taxes increased $5.5 million for the three months ended March 31, 2005 compared to the same period in 2004 due to increases in revenue-based Washington State excise tax and municipal tax due to increased operating revenues. Revenue sensitive excise and municipal taxes have no impact on earnings.

Income taxes increased $7.3 million for the three months ended March 31, 2005 compared to the same period in 2004 as a result of higher taxable income and a higher effective federal income tax rate.

OTHER INCOME AND INTEREST CHARGES

The table below sets forth significant changes in other income, interest charges and preferred stock dividends for PSE and its subsidiaries for the three months ended March 31, 2005 compared to the same period in 2004.

(DOLLARS IN MILLIONS) THREE MONTHS ENDED MARCH 31	2005		2004		CHANGE			PERCENT CHANGE
Other income (net of tax)	$	1.2	$	0.1	$	1.1			*
Interest charges		39.5		42.0		(2.5	)		(6.0	)%

_________________________________

* Percent change not applicable.

Other income increased $1.1 million (after-tax) for the three months ended March 31, 2005 compared to the same period in 2004 primarily due to increases in the surrender value of corporate-owned life insurance policies and a higher level of allowance for funds used during construction.

Interest charges decreased $2.5 million for the three months ended March 31, 2005 compared to the same period in 2004 due to the redemption of $137.5 million of long-term debt with rates ranging from 6.45% to 7.80% in 2004, partially offset by the issuance of $200 million of variable-rate senior notes in July 2004.

InfrastruX

Following a strategic review of Puget Energy's unregulated subsidiary, InfrastruX, on February 8, 2005, Puget Energy’s Board of Directors decided to exit the utility construction services sector. Puget Energy intends to monetize its interest in InfrastruX through a sale and to invest the proceeds of such monetization into its regulated utility subsidiary, PSE. This planned disposal meets the criteria established for recognition as a discontinued operation under SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” and is accounted for as such in Puget Energy’s consolidated financial statements. The disposal of InfrastruX is expected to be completed during 2005.

For the three months ended March 31, 2005, InfrastruX’s loss from discontinued operations (net of taxes and minority interest) totaled $1.0 million compared to a loss of $0.4 million (net of taxes and minority interest) for the three months ended March 31, 2004. The three months ended March 31, 2005 included a charge of $1.1 million after-tax related to the estimated loss on disposal of InfrastruX. In accordance with SFAS No 144, InfrastruX discontinued depreciation and amortization of its assets effective February 8, 2005. This discontinuation of depreciation and amortization resulted in $2.6 million ($1.6 million after-tax) lower depreciation and amortization expense than otherwise would have been recorded as continuing operations.

InfrastruX’s operations are dependent on a number of factors, including weather conditions and availability of projects and capital to be spent on utility construction projects. As such, Puget Energy cannot determine what income or loss InfrastruX will generate during the period of time that Puget Energy continues to hold its interest in InfrastruX, nor any ultimate gain or loss upon completion of the sale of the entity. It is not anticipated that any funding will be needed from Puget Energy to maintain operations at InfrastruX or to complete the sale transaction.

Capital Requirements

Contractual Obligations and Commercial Commitments

Puget Energy. The following are Puget Energy’s aggregate consolidated (including PSE) contractual and commercial commitments from continuing operations as of March 31, 2005:

Puget Energy			PAYMENTS DUE PER PERIOD
CONTRACTUAL OBLIGATIONS (DOLLARS IN MILLIONS)		TOTAL		2005		2006- 2007		2008- 2009		2010 & THEREAFTER
Long-term debt	$	2,100.4	$	31.0	$	411.0	$	337.5	$	1,320.9
Short-term debt		97.1		97.1		--		--		--
Junior subordinated debentures payable to a subsidiary trust ¹		280.3		--		--		--		280.3
Mandatorily redeemable preferred stock		1.9		--		--		--		1.9
Service contract obligations		177.5		16.8		54.1		53.2		53.4
Non-cancelable operating leases		132.1		9.9		33.0		27.6		61.6
Fredonia combustion turbines lease ²		64.0		3.3		8.6		8.3		43.8
Energy purchase obligations		5,038.8		865.4		1,675.4		1,211.9		1,286.1
Financial hedge obligations		73.3		45.1		25.3		2.9		--
Pension funding³		44.8		3.4		8.2		9.8		23.4
Total contractual cash obligations	$	8,010.2	$	1,072.0	$	2,215.6	$	1,651.2	$	3,071.4

			AMOUNT OF COMMITMENT EXPIRATION PER PERIOD
COMMERCIAL COMMITMENTS (DOLLARS IN MILLIONS)		TOTAL		2005		2006- 2007		2008- 2009		2010 & THEREAFTER
Guarantees ⁴	$	131.0	$	--	$	131.0	$	--	$	--
Liquidity facilities - available ⁵		552.4		150.0		--		--		402.4
Lines of credit - available ⁶		--		--		--		--		--
Energy operations letter of credit		0.5		--		0.5		--		--
Total commercial commitments	$	683.9	$	150.0	$	131.5	$	--	$	402.4

_______________________

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	Pension funding is based on an actuarial estimate.

⁴

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. Of the $150 million available to InfrastruX, $131.0 was outstanding at March 31, 2005.

⁵

At March 31, 2005, PSE had available a $500 million unsecured credit agreement expiring in April 2010 and a $150 million receivables securitization facility that expires in December 2005. At March 31, 2005, PSE had no amounts sold 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 outstanding commercial paper of $97.1 million and a letter of credit totaling $0.5 million, thereby effectively reducing the available borrowing capacity under these liquidity facilities to $552.4 million.

⁶	Puget Energy has a $5 million line of credit with a bank. At March 31, 2005, $5.0 million was outstanding, leaving no amounts available to borrow under the agreement. Puget Energy reduced the borrowing capacity under this line of credit from $15.0 million to $5.0 million on February 1, 2005.

Puget Sound Energy. The following are PSE’s aggregate contractual and commercial commitments as of March 31, 2005:

Puget Sound Energy			PAYMENTS DUE PER PERIOD
CONTRACTUAL OBLIGATIONS (DOLLARS IN MILLIONS)		TOTAL		2005		2006- 2007		2008- 2009		2010 & THEREAFTER
Long-term debt	$	2,095.4	$	31.0	$	406.0	$	337.5	$	1,320.9
Short-term debt		97.1		97.1		--		--		--
Junior subordinated debentures payable to a subsidiary trust ¹		280.3		--		--		--		280.3
Mandatorily redeemable preferred stock		1.9		--		--		--		1.9
Service contract obligations		177.5		16.8		54.1		53.2		53.4
Non-cancelable operating leases		132.1		9.9		33.0		27.6		61.6
Fredonia combustion turbines lease ²		64.0		3.3		8.6		8.3		43.8
Energy purchase obligations		5,038.8		865.4		1,675.4		1,211.9		1,286.1
Financial hedge obligations		73.3		45.1		25.3		2.9		--
Pension funding³		44.8		3.4		8.2		9.8		23.4
Total contractual cash obligations	$	8,005.2	$	1,072.0	$	2,210.6	$	1,651.2	$	3,071.4

			AMOUNT OF COMMITMENT EXPIRATION PER PERIOD
COMMERCIAL COMMITMENTS (DOLLARS IN MILLIONS)		TOTAL		2005		2006- 2007		2008- 2009		2010 & THEREAFTER
Liquidity facilities - available⁴	$	552.4	$	150.0	$	--	$	--	$	402.4
Energy operations letter of credit		0.5		--		0.5		--		--
Total commercial commitments	$	552.9	$	150.0	$	0.5	$	--	$	402.4

_______________________

¹	See note 1 above.

²	See note 2 above.

3	See note 3 above.

⁴	See note 5 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 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 expires in December 2005, but is terminable by PSE and Rainier Receivables upon notice to the receivables purchasers. At March 31, 2005, Rainier Receivables had no amounts sold under the receivables securitization facility, leaving a maximum amount of receivables available to be sold under the program of $150.0 million. During the three months ended March 31, 2004, Rainier Receivables sold a cumulative $122.0 million of receivables. During the three months ended March 31, 2005, Rainier sold no additional receivables under the receivables securitization program since the $150.0 million sold under the program at December 31, 2004.

FREDONIA 3 AND 4 OPERATING LEASE

PSE leases two combustion turbines for its Fredonia 3 and 4 electric generating facility pursuant to a master operating lease that was amended for this purpose in April 2001. The lease has a term expiring in 2011, but can be canceled by PSE at any time. Payments under the lease vary with changes in the London Interbank Offered Rate (LIBOR). At March 31, 2005, PSE’s outstanding balance under the lease was $56.1 million. The expected residual value under the lease is the lesser of $37.4 million or 60% of the cost of the equipment. In the event the equipment is sold to a third party upon termination of the lease and the aggregate sales proceeds are less than the unamortized value of the equipment, PSE would be required to pay the lessor contingent rent in an amount equal to the deficiency up to a maximum of 87% of the unamortized value of the equipment.

UTILITY CONSTRUCTION PROGRAM

Utility construction expenditures for generation, transmission and distribution are designed to meet continuing customer growth and to improve efficiencies of PSE’s energy delivery systems. Construction expenditures, excluding equity Allowance for Funds Used During Construction (AFUDC), were $117.9 million for the three months ended March 31, 2005. Utility construction expenditures in 2005, 2006 and 2007 are anticipated to be approximately $580 million, $400 million and $384 million, respectively, including the new Hopkins Ridge wind project, but excluding amounts for new generation resources currently under evaluation. New generation resources under evaluation consist of the Wild Horse wind project that is anticipated to be completed in 2006. The Wild Horse wind project, if completed in 2006, is anticipated to have a total cost range of approximately $300 to $350 million. The proposed utility construction expenditures and new generation resource expenditures, if acquired, are anticipated to be funded with a combination of short-term debt, long-term debt and equity. Construction expenditure estimates, including the new generation resources, are subject to periodic review and adjustment in light of changing economic, regulatory, environmental and efficiency factors.

NEW GENERATION RESOURCES

On March 11, 2005, PSE completed the acquisition of the Hopkins Ridge wind project from Blue Sky Wind, LLC and issued its key contractor, RES America Construction, Inc. a notice to proceed with construction of the project. Hopkins Ridge is situated on 11,000 acres of remote, open wheat fields in southeastern Washington State. The Hopkins Ridge wind project will feature approximately 80 Vestas 1.8-MW wind turbines providing up to 150 MW of capacity, or 52 average MW. Upon completion of construction, which is expected to take approximately nine months, the energy will be delivered to PSE’s service territory by BPA’s transmission system via an interconnection. PSE anticipates spending approximately $200 million on the project, which it solely owns. Included in the $200 million estimate is $180 million to acquire and construct the wind plant, $10 million to fund upgrades to the transmission systems of the Bonneville Power Administration and other regional transmission providers, and the balance for development, transaction and financing costs.

In September 2004, PSE signed a non-binding letter of intent to obtain a 100% ownership interest in the proposed Wild Horse wind project. The project is located in central Washington State. The Wild Horse project is expected to have approximately 100 to 130 wind turbines and generate from 150 to 230 MW of power or 77 average MW, depending on the final design agreement. The final agreement to purchase the Wild Horse wind project is anticipated to be executed in 2005.

CAPITAL RESOURCES

CASH FROM OPERATIONS

Cash generated from operations for the three months ended March 31, 2005 was $45.7 million. During that period, $23.4 million in cash was used for AFUDC and payment of dividends. Consequently, cash flows available for utility construction expenditures and other capital expenditures were $22.3 million or 18.0% of the $124.1 million in construction expenditures (net of AFUDC and customer refundable contributions) and other capital expenditure requirements for the three months ended March 31, 2005. For the three months ended March 31, 2004, cash generated from operations was $106.9 million, $22.7 million of which was used for AFUDC and payment of dividends. Therefore, cash flows available for utility construction expenditures and other capital expenditures were $84.2 million, or 115.8% of the $72.7 million in construction expenditures (net of AFUDC and customer refundable contributions) and other capital expenditure requirements for the three month period ended March 31, 2004. The overall cash generated from operating activities for the three month period ended March 31, 2005 decreased $61.2 million compared to the same period in 2004. The decrease was primarily the result of changes in the utilization of sales of accounts receivables to Rainier Receivables under the accounts receivable securitization program which contributed $76.0 million of the decrease in cash generated from operations. The decrease was partially offset by increases in the PGA mechanism rates in October 2004, which provided a positive cash flow of $7.8 million, and changes in cash flow from accounts payable, which provided $6.6 million positive cash flow for the three months ended March 31, 2005 compared to the same period in 2004.

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.

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 March 31, 2005, PSE could issue:

approximately $281 million of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately $468 million of electric bondable property available for issuance, subject to an interest coverage ratio limitation of 2.0 times net earnings available for interest, which PSE exceeded at March 31, 2005;

approximately $192 million of additional first mortgage bonds under PSE’s gas mortgage indenture based on approximately $320 million of gas bondable property available for issuance, subject to an interest coverage ratio limitation of 1.75 times net earnings available for interest, which PSE exceeded at March 31, 2005;

·	approximately $510 million of additional preferred stock at an assumed dividend rate of 6.75%; and

·	approximately $185 million of unsecured long-term debt.

At March 31, 2005, PSE had approximately $3.6 billion in electric and gas ratebase to support the interest coverage ratio limitation test for net earnings available for interest.

CREDIT RATINGS

Neither Puget Energy nor PSE has had any rating downgrade triggers that would accelerate the maturity dates of outstanding debt. However, a downgrade in the companies’ credit ratings could adversely affect their ability to renew existing, or obtain access to new, credit facilities and could increase the cost of such facilities. For example, under PSE’s revolving credit facility, the spreads over the index and commitment fee increase as PSE’s secured long-term debt ratings decline. A downgrade in commercial paper ratings could preclude PSE’s ability to issue commercial paper under its current programs. The marketability of PSE commercial paper is currently limited by the A-3/P-2 ratings by Standard & Poor’s and Moody’s Investors Service. In addition, downgrades in any or a combination of PSE’s debt ratings may prompt 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 April 22, 2005, 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, LONG-TERM DEBT AND COMMON STOCK ACTIVITY

On April 19, 2005, 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 $850 million of:

·	common stock of Puget Energy, and

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

The shelf registration statement, effective as of May 4, 2005, replaces Puget Energy and PSE's previous $500 million shelf registration statement. The new shelf registration statement provides the Company with additional capacity and flexibility when funding anticipated capital projects and meeting maturing debt obligations.

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. In March 2005, PSE amended this credit agreement, increasing the total borrowing capacity from $350 million to $500 million, and extending the expiration date from June 2007 to April 2010. Under the terms of the credit agreement, PSE pays a floating interest rate on outstanding borrowings based either on the agent bank’s prime rate or on LIBOR plus a marginal rate based on the Company’s long-term credit rating at the time of borrowing. PSE pays a commitment fee on any unused portion of the credit agreement also based on long-term credit ratings of the Company. PSE also has a $150 million receivables securitization program which expires in December 2005. At March 31, 2005, PSE had available $500 million in the unsecured credit agreement and $150 million under its receivables securitization facility, both of which provide credit support for outstanding commercial paper and letters of credit. At March 31, 2005, there was $97.1 million in commercial paper outstanding and $0.5 million outstanding under a letter of credit, effectively reducing the available borrowing capacity under these liquidity facilities to $552.4 million.

In February 2005, PSE entered into an uncommitted $20 million unsecured credit agreement with a bank. Under the terms of the credit agreement, PSE pays a varying interest rate on outstanding borrowings based on the terms entered into at the time of borrowing. At March 31, 2005, there were no amounts outstanding under this credit agreement.

Puget Energy previously had a $15 million credit agreement expiring in May 2006 with a bank. On February 1, 2005, Puget Energy reduced the borrowing capacity of this credit agreement to $5.0 million. Under the terms of the agreement, Puget Energy pays 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 also pays a commitment fee on any unused portion of the credit facility. Puget Energy had $5.0 million outstanding under the credit agreement at March 31, 2005.

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 $3.6 million (151,800 shares) for the three months ended March 31, 2005 compared to $3.9 million (175,600 shares) for the three months ended March 31, 2004.

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 PROJECTS AND LICENSES

Snoqualmie Falls project. The Snoqualmie Falls project, built in 1898, had its original license issued May 13, 1975, which was made effective retroactive to March 1, 1956, and expired on December 31, 1993. PSE filed its application to relicense the project on November 25, 1991, and operated 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. On July 29, 2004, the Snoqualmie Tribe and certain other parties filed a request for rehearing of the new license and a request to stay the FERC license. On March 1, 2005, FERC issued an Order on Rehearing and Dismissing Stay Request. The order requires additional flows at Snoqualmie Falls during certain times of the year. PSE requested rehearing of the order on the grounds that the order interferes with the State Department of Ecology’s authority to regulate water quality and that FERC arbitrarily and capriciously rebalanced the public interest without support of substantive evidence in the record.

ELECTRIC REGULATION AND RATES

FERC matter. PSE’s market-based rate tariff was accepted by FERC in an order dated January 29, 1999. Pursuant to this order, PSE is required to file an updated market power analysis every three years. On August 11, 2004, PSE filed an updated market power analysis with FERC as required by a FERC order dated May 13, 2004. The August 11, 2004 filing was supplemented by additional filings on September 24, 2004 and November 19, 2004. On December 20, 2004, FERC issued an order (December 20 order) finding that PSE had not provided sufficient information for FERC to determine if PSE had passed the generation market power screens with respect to wholesale sales within PSE’s control area. The order instituted an investigation under Section 206 of the Federal Power Act (FPA) and established a prospective refund date of February 27, 2005. Both the proceeding and the refund effective date affect only wholesale sales at market-based rates by PSE inside its own control area. On February 1, 2005, PSE submitted to FERC additional information in accordance with the December 20 order. On April 13, 2005, FERC issued an order terminating the Section 206 investigation and accepting PSE’s updated market power analysis.

Rate case. On February 18, 2005, the Washington Commission approved a 4.1% general tariff electric rate case increase to recover higher costs of providing electric service to customers. The rate increase will increase electric revenues by approximately $57.7 million annually effective March 4, 2005, as clarified in its order of March 1, 2005. In the order, the Washington Commission also approved a capital structure containing 43% common equity with a return on common equity of 10.3%.

White River project. 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.

On April 7, 2004 the Washington Commission approved PSE’s recovery on the unamortized White River plant investment. At March 31, 2005, the White River project net book value totaled $65.0 million, which included $46.0 million of net utility plant, $14.7 million of capitalized FERC licensing costs, $3.2 million of costs related to construction work in progress, and $1.1 million related to dam operations and safety. In its February 18, 2005 general rate case order, the Washington Commission approved a Washington Commission staff recommendation that PSE be allowed recovery of the White River net utility plant costs noted above, but defer recovery of other costs until all costs and any sales proceeds are known.

PCA Mechanism. PSE has a PCA mechanism that triggers if PSE’s costs to provide customers’ electricity falls outside certain bands from a normalized level of power costs established in the electric general rate case. The cumulative maximum pre-tax earnings exposure due to power cost variations over the four-year period ending June 30, 2006 is limited to $40 million plus 1% of the excess. Upon expiration of the $40 million cumulative cap, the annual power cost variability is subject to the bands in the table below. All significant variable power supply cost drivers are included in the PCA mechanism (hydroelectric generation variability, market price variability for purchased power and surplus power sales, natural gas and coal fuel price variability, generation unit forced outage risk and wheeling cost variability).

Upon expiration of the cumulative cap, the most significant risks are hydroelectric generation variability and wholesale market prices of natural gas and power. On an annual July through June basis, the PCA mechanism apportions increases or decreases in power costs, on a graduated scale, between PSE and its customers in the following manner:

Annual Power Cost Variability	Customers’ Share	Company’s Share ¹
+/- $20 million	0%	100%
+/- $20 - $40 million	50%	50%
+/- $40 - $120 million	90%	10%
+/- $120 million	95%	5%

__________________________

¹	Over the four-year period July 1, 2002 through June 30, 2006, the Company’s share of pre-tax power cost variations is capped at a cumulative $40 million plus 1% of the excess. Power cost variation after June 30, 2006 will be apportioned on an annual basis, based on the graduated scale.

Based on past activity under the PCA mechanism and volatility of power costs, it is possible that PSE could experience higher expenses associated with excess power based on the sharing arrangement once the cumulative $40 million cap expires on June 30, 2006. As such, the risk dynamics change for PSE and its customers. PSE is required by the Washington Commission to make a PCORC filing or general tariff filing by February 28, 2006 to reset the PCA power cost baseline rates effective July 1, 2006.

On February 23, 2005, the Washington Commission issued an order concerning PSE’s compliance filing related to the PCA 2 period of July 1, 2003 through June 30, 2004. In its order, the Washington Commission determined that PSE was allowed to reflect additional power costs totaling $6.0 million during the PCA 2 period of July 1, 2003 through December 31, 2003. These costs represent an additional return on PSE’s regulatory assets for the Tenaska generating facility. These costs were deferred under the PCA mechanism, which resulted in a reduction in purchased electricity expense for the three month period ended March 31, 2005.

Colstrip Matter. The Mineral Management Service of the United States Department of the Interior (MMS) issued two orders to Western Energy Company (WECO), the supplier of coal to Colstrip Units 3 & 4, 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 on 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. The State of Montana has made similar claims against WECO for taxes that would apply to the additional royalties if the MMS position prevails. WECO appealed the MMS orders to a board of appeals internal to the MMS. On March 30, 2005, the MMS issued a decision on the appeals, granting them in part but denying them in part, a result that reduced the royalty claim by $0.8 million based on PSE's 25% ownership interest in Colstrip Units 3 & 4. WECO will seek further review of the March 30, 2005 order by the Department of the Interior Board of Land Appeals, a process that will likely take another two years. After the reduction in amount claimed due to the statute of limitations ruling, PSE’s share of the alleged additional royalties is $1.1 million, which is based upon PSE’s 25% ownership interest in Colstrip Units 3 & 4. PSE’s share of the alleged additional State of Montana taxes would be $0.5 million. WECO is also appealing the State of Montana tax claims, and anticipates that process will take several years. PSE is monitoring the process and believes that the Colstrip Units 3 & 4 owners have reasonable defenses in this matter based upon its review. Neither the outcome of this matter nor the associated costs can be predicted at this time.

GAS REGULATION AND RATES

On February 18, 2005, the Washington Commission approved a 3.5% general tariff gas rate case increase to recover higher costs of providing natural gas service to customers. The rate increase will increase gas revenues by approximately $26.3 million annually, effective March 4, 2005. In the order, the Washington Commission also approved a capital structure containing 43% common equity with a return on common equity of 10.3%. In the proceeding, PSE had filed a request for an increase of 6.3% or $46.2 million annually on final rebuttal during the rate case for gas customers.

PROCEEDINGS RELATING TO THE WESTERN POWER MARKET

Puget Energy’s and PSE’s Annual Report on Form 10-K for the year ended December 31, 2004 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 new material proceedings instituted during the period covered by this report. PSE intends to vigorously defend against each of these cases and does not expect the ultimate resolution of these proceedings in the aggregate to have a material adverse impact on the financial condition, results of operations or liquidity of the Company. However, there can be no assurances in that regard because litigation is subject to numerous uncertainties and PSE is unable to predict the ultimate outcome of these matters. Accordingly, there can be no guarantee that these proceedings, either individually or in the aggregate, will not materially and adversely affect PSE’s financial condition, results of operations or liquidity.

California Receivable and California Refund Proceeding. In 2001, Pacific Gas & Electric (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 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 the escrow of funds owed by PG&E for purchases during the fourth quarter 2000 are owed by the California PX.

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 prepare revised settlement statements based on newly recalculated costs and charges for spot market sales to California during the refund period and currently estimates that it will determine “who owes what to whom” in early 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. A review of that claim is pending.

Many f 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. Last fall, the Ninth Circuit ordered that briefing proceed in two rounds. The first round is limited to three issues: (1) which parties are subject to FERC’s refund jurisdiction in light of the exemption for government-owned utilities in section 201(f) of the Federal Power Act (FPA); (2) the temporal scope of refunds under section 206 of the FPA; (3) which categories of transactions are subject to refunds. PSE joined the brief of the Competitive Supplier Group, which argued that FERC has proposed to require payment of refunds without proper notice to sellers, without proper limits on the type of transactions affected and without finding that the transactions subject to refund in fact produced prices that were just and reasonable. Oral argument was held on April 12 and 13, 2005 on the first round of issues. Procedures will be established for the remaining issues, if necessary, after the court’s disposition of the first round of issues.

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 March 31, 2005 is approximately $21.3 million. PSE estimates the range for the receivable to be between $21.3 million and $22.5 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. PSE has formally requested payment of these amounts from the CAISO and has pursued the issue in filing through FERC processes.

Pacific Northwest Refund Proceeding. On June 25, 2003, FERC issued an order terminating the proceeding, largely on procedural, jurisdictional and equitable grounds. Various parties filed rehearing requests, which were denied by FERC in an order affirming the termination of the Pacific Northwest Refund Proceeding, (Docket No. EL01-10). Seven petitions for review, including PSE’s, are now pending before the United States Court of Appeals for the Ninth Circuit. Opening briefs were filed on January 14, 2005. PSE’s opening brief addressed procedural flaws underlying the action of FERC. Specifically, PSE argued that because PSE’s complaint in the underlying docket was withdrawn as a matter of law on July 9, 2001, FERC erred in relying on it to serve as the basis to initiate a “preliminary” investigation into whether refunds for individually negotiated bilateral transactions in the Pacific Northwest were appropriate. Briefing is expected to be completed in the first half of 2005.

Wah Chang v. Avista Corp., PSE and others. 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, alleges damages of not less than $30 million and seeks treble and punitive damages, attorneys’ fees and costs. 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. Both cases were dismissed on the grounds that FERC has the exclusive jurisdiction over plaintiff’s claims and the filed rate doctrine and Federal preemption barred the court from hearing the plaintiff’s claims. On March 10, 2005, Wah Chang filed a notice of appeal to the United States Court of Appeals for the Ninth Circuit.

California Litigation. Attorney General Cases. On May 31, 2002, FERC conditionally dismissed a complaint filed on March 20, 2002 by the California Attorney General in Docket No. EL02-71 that alleged violations of the FPA by FERC and all sellers (including PSE) of electric power and energy into California. The complaint asserted that FERC’s adoption and implementation of market rate authority was flawed and, as a result, individual sellers such as PSE were liable for sales of energy at rates that were “unjust and unreasonable.” The condition for dismissal was that all sellers refile transaction summaries of sales to (and, after a clarifying order issued on June 28, 2001, purchases from) certain California entities during 2000 and 2001. PSE refiled such transaction summaries on July 1 and July 8, 2002. The order of dismissal went on appeal to the Ninth Circuit Court of Appeals. 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). 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 Proceeding.” 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. The Ninth Circuit has yet to issue an order on the rehearing request. Because the current Ninth Circuit decision may open new periods of transactions to refund claims under new theories, PSE cannot predict the scope, nature or ultimate resolution of this case. That additional uncertainty may make the outcomes of certain other western energy market cases less predictable than previously anticipated.

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 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. On December 8, 2004, the Ninth Circuit issued an opinion affirming the district court’s decision to remand the case to state court. Powerex filed a petition for rehearing which argues that although not immune from suit, as a government entity it should be allowed to litigate in federal, not state court. The court twice rejected attempts by Powerex to keep the case in federal court, first by denying Powerex’s request for rehearing and second by denying Powerex’s subsequent motion to recall the mandate. The case is now in the process of being remanded to state court.

Item 3. Quantitative and Qualitative Disclosure About Market Risk

ENERGY PORTFOLIO MANAGEMENT

The regulatory mechanisms of the PGA and the PCA mitigate the impact of commodity price volatility on the Company. The PGA mechanism passes through increases and decreases in the cost of natural gas supply to customers. 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.

The Company is focused on commodity price exposure and risks associated with volumetric variability in the gas portfolio and electric portfolio for its customers. Gas and electric portfolio exposure is managed in accordance with Company polices and procedures. The Risk Management Committee, which is composed of Company officers, provides policy-level and strategic direction for management of the energy portfolio. The Audit Committee of the Company’s Board of Directors periodically assesses risk management policies.

·	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 Company is not engaged in the business of assuming risk for the purpose of speculative trading revenues. Therefore wholesale market transactions are focused on balancing the Company’s energy portfolio, reducing costs and risks where feasible, and reducing volatility in wholesale costs and margin in the portfolio. In order to manage risks effectively, the Company enters into physical and financial transactions, which are appropriate for the service territory of the Company and are relevant to its regulated electric and gas portfolios.

The risk metrics the Company employs are aimed at assessing exposure for the purposes of developing strategies to reduce the potential exposure on a cost-effective basis in regulated utility gas and electric portfolios. Specifically, the amount of risk exposure is defined by time period and by portfolio. It is determined through statistical methods aimed at forecasting risk.

The energy risk management staff models forecasted load requirements and expected resource availability, and projects the net deficit or surplus position resulting from any imbalance between load requirements and existing resources. However, the portfolios are subject to major sources of variability (e.g., hydroelectric 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 and at other times they can exacerbate portfolio imbalances. Because of the volumetric and cost variability within the electric and gas portfolios, the Company runs market simulations to model potential risk scenarios. In this way, strategies can be developed to address the expected case as well as other potential scenarios. Resources in the gas portfolio include gas supply arrangements, gas storage and gas transportation contracts. Resources in the electric portfolio include power purchase agreements, generating resources and transmission contracts.

The Company’s energy risk management staff develops hedging strategies to manage deficit or surplus positions in the portfolios. The Company’s energy risk policy states that hedging and optimization strategies will be consistent with Company objectives. The Company relies on risk analysis, operational factors, professional judgment of its employees and fundamental analysis. The Company will engage in transactions that reduce risks in its electric and gas portfolios, and optimize unused capacity where possible. Cost and reliability factors are considered in its hedging strategies. The Company’s hedging activities are aimed at removing risks from the Company’s electric and gas portfolios, giving important consideration to cost of hedges and lost opportunity in order to find a balance between price stability and least cost. The hedge strategies for the gas and electric portfolios incorporate risk analysis, operational factors and professional judgment of its employees as well as fundamental analysis. Programmatic hedge plans are developed to ensure disciplined hedging, and discretion is used in hedging within specific guidelines of the programmatic hedge plans approved by the Risk Management Committee. Most hedges can be implemented in ways that retain the Company’s ability to use its energy supply optimization opportunities. Some hedges are structured similarly to insurance instruments, where the Company pays an insurance premium to protect against certain extreme conditions.

Without jeopardizing the security of supply within its portfolio, the Company also engages in optimizing the portfolio. Optimization may take the form of utilizing excess capacity, shaping flexible resources to capture their highest value and utilizing transmission capacity through third party transactions. As a result, portions of the Company’s energy portfolio are monetized through the use of forward price instruments which help reduce overall costs.

The Company has entered into master netting agreements with counterparties when available to mitigate credit exposure to those counterparties. The Company believes that entering into such agreements reduces risk of settlement default with the ability to make only one net payment. In addition, the Company believes risk is mitigated with an improved position in potential counterparty bankruptcy situations due to a consistent netting approach. At March 31, 2005, the Company was subject to a range of netting provisions, including both stand alone agreements and the provisions associated with the Western Systems Power Pool agreement of which many energy suppliers in the western United States are a part.

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 on daily quoted prices from an independent energy brokerage service. Valuations for short-term and medium-term natural gas financial derivatives are derived from a combination of quotes from several independent energy brokers and are updated daily. Long-term gas financial derivatives are valued based on published pricing from a combination of independent brokerage services and are updated monthly. Option contracts are valued using market quotes and a Monte Carlo simulation based model approach.

At March 31, 2005, the Company had an after-tax net asset of approximately $57.0 million of energy contracts designated as qualifying cash flow hedges and a corresponding unrealized gain of $37.0 million after-tax recorded in other comprehensive income. Of the amount in other comprehensive income, 99% of the mark-to-market gain beginning February 1, 2005 though June 30, 2006 has been reclassified out of other comprehensive income to a deferred account in accordance with SFAS No. 71 due to the Company reaching the $40 million cap under the PCA mechanism. Amounts settling after June 30, 2006 have not been deferred under the PCA mechanism as the $40 million cap expires at June 30, 2006, and the sharing band under the PCA mechanism reset. The Company also had energy contracts that were marked-to-market at a loss of $0.3 million after-tax through current earnings for the three months ended March 31, 2005. These mark-to-market adjustments were primarily the result of excluding certain contracts from the normal purchase normal sale exception under SFAS No. 133. A portion of the mark-to-market adjustments beginning April 1, 2005, has been reclassified to a deferred account in accordance with SFAS No. 71 due to the Company reaching the $40 million cap under the PCA mechanism. At March 31, 2005, the Company also has an asset of approximately $28.3 million related to the fair value of gas contracts. All mark-to-market adjustments relating to the natural gas business have been reclassified to a deferred account in accordance with SFAS No. 71 due to the PGA mechanism. The PGA mechanism passes on to customers increases and decreases in the cost of natural gas supply. 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 $11.3 million after-tax and would increase current earnings for those contracts marked-to-market in earnings by $0.4 million after-tax.

INTEREST RATE RISK

The Company believes its interest rate risk primarily relates to the use of short-term debt instruments, variable-rate 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 at times enter into variable rate long-term bonds to take advantage of lower interest rates. 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 March 31, 2005, the unrealized loss associated with the two treasury lock contracts was $10.6 million after-tax and is included in other comprehensive income. A hypothetical 10% decrease in the interest rate of a 30-year treasury note would result in an additional loss of $12.1 million after-tax in other comprehensive income. The treasury lock contracts will settle completely in 2005.

Item 4. Controls and Procedures

PUGET ENERGY

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Under the supervision and with the participation of Puget Energy’s management, including the President and Chief Executive Officer and Senior Vice President Finance and Chief Financial Officer, Puget Energy has evaluated the effectiveness of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of March 31, 2005, the end of the period covered by this report. Based upon that evaluation, the President and Chief Executive Officer and Senior Vice President Finance and Chief Financial Officer of Puget Energy concluded that these disclosure controls and procedures are effective.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There have been no changes in Puget Energy’s internal control over financial reporting during the quarter ended March 31, 2005 that have materially affected, or are reasonably likely to materially affect, Puget Energy’s internal control over financial reporting.

PUGET SOUND ENERGY

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Under the supervision and with the participation of PSE’s management, including the President and Chief Executive Officer and Senior Vice President Finance and Chief Financial Officer, PSE has evaluated the effectiveness of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of March 31, 2005, the end of the period covered by this report. Based upon that evaluation, the President and Chief Executive Officer and Senior Vice President Finance and Chief Financial Officer of PSE concluded that these disclosure controls and procedures are effective.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There have been no changes in PSE’s internal control over financial reporting during the quarter ended March 31, 2005, that have materially affected, or are reasonably likely to materially affect, 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 March 31, 2005. 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: May 4, 2005
	Chief accounting officer and officer duly authorized to sign this report on behalf of each registrant

Table of Contents

EXHIBIT INDEX

The following exhibits are filed herewith:

12.1	Statement setting forth computation of ratios of earnings to fixed charges (2000 through 2004 and 12 months ended March 31, 2005) for Puget Energy.

12.2	Statement setting forth computation of ratios of earnings to fixed charges (2000 through 2004 and 12 months ended March 31, 2005) 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.