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 June 30, 2003
OR

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

For the transition period from __________ to __________

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

1-16305	PUGET ENERGY, INC.	91-1969407
	A Washington Corporation.
	10885 N.E. 4th Street
	Bellevue, Washington 98004-5515
	(425) 454-6363

1-4393	PUGET SOUND ENERGY, INC.	91-0374630
	A Washington Corporation.
	10885 N.E. 4th Street
	Bellevue, Washington 98004-5515
	(425) 454-6363

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

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

As of June 30, 2003, (i) the number of shares of Puget Energy, Inc. (Puget Energy) common stock outstanding was 94,031,408 ($.01 par value) and (ii) all of the outstanding shares of Puget Sound Energy, Inc. (PSE) common stock were held by Puget Energy.

Table of Contents

Filing Format

Forward-Looking Statements

Part I.	Financial Information
Item 1.	Financial Statements

	Puget Energy, Inc.
	Consolidated Statements of Income - 3 months ended June 30, 2003 and 2002
	Consolidated Statements of Income - 6 months ended June 30, 2003 and 2002
	Consolidated Statements of Comprehensive Income - 3 months ended
	June 30, 2003 and 2002
	Consolidated Statements of Comprehensive Income - 6 months ended
	June 30, 2003 and 2002
	Consolidated Balance Sheets - June 30, 2003 and December 31, 2002
	Consolidated Statements of Cash Flows - 6 months ended
	June 30, 2003 and 2002

	Puget Sound Energy, Inc. (PSE)
	Consolidated Statements of Income - 3 months ended June 30, 2003 and 2002
	Consolidated Statements of Income - 6 months ended June 30, 2003 and 2002
	Consolidated Statements of Comprehensive Income - 3 months ended
	June 30, 2003 and 2002
	Consolidated Statements of Comprehensive Income - 6 months ended
	June 30, 2003 and 2002
	Consolidated Balance Sheets - June 30, 2003 and December 31, 2002
	Consolidated Statements of Cash Flows - 6 months ended
	June 30, 2003 and 2002
	Notes:
	Combined Notes to Consolidated Financial Statements

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

Item 3.	Quantitative and Qualitative Disclosure About Market Risk

Item 4.	Controls and Procedures

Part II.	Other Information
Item 1.	Legal Proceedings
Item 4.	Submission of Matters to a Vote of Security Holders
Item 6.	Exhibits and Reports on Form 8-K

Signature
Exhibit Index

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

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

Risks relating to the regulated utility business (PSE)

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

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

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

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

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

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

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

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

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

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

• general economic conditions in the Pacific Northwest;

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

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

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

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

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

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

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

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

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

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

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

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

Risks relating to both the regulated and non-regulated businesses

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

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

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

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

• legal and regulatory proceedings;

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

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

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

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

PART I FINANCIAL INFORMATION

Item 1. Financial Statements

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

	2003			2002
Operating Revenues:
Electric	$	348,196		$	316,122
Gas		116,747			144,384
Non-utility construction services		92,343			76,122
Other		570			4,191

Total operating revenues		557,856			540,819

Operating Expenses:
Energy costs:
Purchased electricity		191,600			127,924
Purchased gas		57,372			88,520
Electric generation fuel		11,088			14,680
Residential Exchange		(36,977	)		(30,964	)
Unrealized gain on derivative instruments		(44	)		(252	)
Utility operations and maintenance		73,895			73,630
Other operations and maintenance		77,117			62,087
Depreciation and amortization		59,321			57,357
Conservation amortization		6,295			3,605
Taxes other than income taxes		46,950			53,757
Income taxes		4,832			13,642

Total operating expenses		491,449			463,986

Operating Income		66,407			76,833
Other income		2,247			3,441

Income Before Interest Charges and Minority Interest		68,654			80,274
Interest charges, net of AFUDC		45,980			48,682
Minority interest in earnings of consolidated subsidiary		282			223

Net Income		22,392			31,369
Less: preferred stock dividends accrual		1,794			1,940

Income for Common Stock	$	20,598		$	29,429

Basic common shares outstanding - weighted average		93,928			87,448
Diluted common shares outstanding - weighted average		94,440			87,646

Basic and diluted earnings per share	$	0.22		$	0.34

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

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

	2003			2002
Operating Revenues:
Electric	$	765,194		$	679,371
Gas		304,535			458,875
Non-utility construction services		163,020			136,883
Other		1,069			4,750

Total operating revenues		1,233,818			1,279,879

Operating Expenses:
Energy costs:
Purchased electricity		432,036			309,911
Purchased gas		144,326			293,318
Electric generation fuel		26,162			79,860
Residential Exchange		(89,656	)		(73,711	)
Unrealized gain on derivative instruments		(521	)		(11,748	)
Utility operations and maintenance		143,950			139,571
Other operations and maintenance		147,637			116,708
Depreciation and amortization		117,266			113,306
Conservation amortization		14,017			5,769
Taxes other than income taxes		104,611			118,914
Income taxes		36,198			34,577

Total operating expenses		1,076,026			1,126,475

Operating Income		157,792			153,404
Other income		2,952			3,825

Income Before Interest Charges and Minority Interest		160,744			157,229
Interest charges, net of AFUDC		93,645			99,080
Minority interest in earnings of consolidated subsidiary		(50	)		302

Income Before Cumulative Effect of Accounting Change		67,149			57,847
Cumulative effect of implementation of an accounting change, net of tax		169			--

Net Income		66,980			57,847
Less: preferred stock dividends accrual		3,661			3,952

Income for Common Stock	$	63,319		$	53,895

Basic common shares outstanding - weighted average		93,833			87,309
Diluted common shares outstanding - weighted average		94,346			87,508

Basic earnings per share before cumulative effect of accounting change	$	0.68		$	0.62
Cumulative effect of accounting change		--			--

Basic earnings per share	$	0.68		$	0.62

Diluted earnings per share before cumulative effect of accounting change	$	0.67		$	0.62
Cumulative effect of accounting change		--			--

Diluted earnings per share	$	0.67		$	0.62

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

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

	2003			2002
Net Income	$	22,392		$	31,369

Other comprehensive income, net of tax:
Unrealized holding losses arising on marketable securities during the		(30	)		(377	)
period
Reclassification adjustment for realized gains on marketable securities		(1,548	)		--
included in net income
Foreign currency translation adjustment		16			96
Unrealized gains (losses) on derivative instruments during		3,029			(3,513	)
the period
Reversal of unrealized losses on derivative instruments settled during the		2,003			1,347
period

Other comprehensive income (loss)		3,470			(2,447	)

Comprehensive Income	$	25,862		$	28,922

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

	2003			2002
Net Income	$	66,980		$	57,847

Other comprehensive income, net of tax:
Unrealized holding losses arising on marketable securities during the		(45	)		(526	)
period
Reclassification adjustment for realized gains on marketable securities		(1,548	)		(724	)
included in net income
Foreign currency translation adjustment		62			(116	)
Unrealized gains (losses) on derivative instruments during the period		4,059			(2,102	)
Reversal of unrealized losses on derivative instruments settled during the		4,319			32,834
period

Other comprehensive income		6,847			29,366

Comprehensive Income	$	73,827		$	87,213

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

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

ASSETS

	June 30, 2003			December 31, 2002
Utility Plant: (at original cost, including construction work in progress of
$140,696 and $108,658 respectively)
Electric	$	4,238,524		$	4,229,352
Gas		1,691,231			1,645,865
Common		387,407			378,844
Less: Accumulated depreciation and amortization		(2,384,914	)		(2,337,832	)

Net utility plant		3,932,248			3,916,229

Other Property and Investments:
Goodwill, net		132,162			125,555
Intangibles, net		18,220			18,652
Non-utility		91,852			80,855
Other assets		165,134			153,068

Total other property and investments		407,368			378,130

Current Assets:
Cash		140,504			176,669
Restricted cash		12,267			18,871
Accounts receivable, net		259,607			279,623
Unbilled revenue		58,866			112,115
Materials and supplies, at average cost		78,614			70,402
Current portion of unrealized gain on derivative instruments		11,218			3,741
Prepayments and other		15,480			11,323

Total current assets		576,556			672,744

Other Long-Term Assets:
Regulatory asset for deferred income taxes		163,526			167,058
Regulatory asset for PURPA contract buyout costs		236,977			243,584
Unrealized gain on derivative instruments		8,636			9,870
Power cost adjustment mechanism		4,085			--
Other		297,206			269,876

Total other long-term assets		710,430			690,388

Total Assets	$	5,626,602		$	5,657,491

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

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

CAPITALIZATION AND LIABILITIES

	June 30, 2003		December 31, 2002
Capitalization:
Common shareholders' investment:
Common stock $0.01 par value, 250,000,000 shares authorized,
94,031,408 and 93,642,659 shares outstanding	$	940	$	936
Additional paid-in capital		1,492,717		1,484,615
Earnings reinvested in the business		52,770		36,396
Accumulated other comprehensive income		8,687		1,840
Preferred stock not subject to mandatory redemption		60,000		60,000
Preferred stock subject to mandatory redemption		35,639		43,162
Corporation obligated, mandatorily redeemable preferred securities of
subsidiary trust holding solely junior subordinated debentures of the
corporation		280,250		300,000
Long-term debt		2,007,062		2,149,733

Total capitalization		3,938,065		4,076,682

Minority interest in equity of a consolidated subsidiary		11,460		10,629

Current Liabilities:
Accounts payable		143,486		205,619
Short-term debt		53,393		47,295
Current maturities of long-term debt		269,657		73,206
Purchased gas liability		14,310		83,811
Accrued expenses:
Taxes		59,760		62,562
Salaries and wages		12,315		11,441
Interest		33,330		37,942
Other		52,234		50,171

Total current liabilities		638,485		572,047

Long-Term Liabilities:
Deferred income taxes		761,766		730,675
Other deferred credits		276,826		267,458

Total long-term liabilities		1,038,592		998,133

Total Capitalization and Liabilities	$	5,626,602	$	5,657,491

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

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

	2003			2002
Operating Activities:
Net Income	$	66,980		$	57,847
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization		117,266			113,256
Deferred federal and state income taxes and tax credits - net		34,623			28,771
Net unrealized gains on derivative instruments		(521	)		(11,748	)
Cash collateral received from energy supplier		13,268			8,340
Gain on sale of securities		(2,910	)		--
Other		(1,369	)		(143	)
Change in certain current assets and current liabilities:
Accounts receivable and unbilled revenue		78,314			95,630
Materials and supplies		(8,212	)		31,560
Prepayments and other		(4,020	)		1,161
Purchase gas receivable/liability		(69,500	)		128,613
Accounts payable		(63,824	)		(42,126	)
Taxes payable		(4,155	)		(4,773	)
Accrued expenses and other		(1,486	)		29,637

Net Cash Provided by Operating Activities		154,454			436,025

Investing Activities:
Construction and capital expenditures-excluding equity AFUDC		(141,427	)		(128,081	)
Additions to energy conservation program		(8,786	)		(4,434	)
Acquisitions by InfrastruX, net of cash acquired		(10,467	)		(40,261	)
Restricted cash		6,605			(5,869	)
Cash received from sale of securities		3,056			--
Investment in variable rate bonds		(14,055	)		--
Other		331			(7,266	)

Net Cash Used by Investing Activities		(164,743	)		(185,911	)

Financing Activities:
Change in short-term debt - net		6,098			(223,470	)
Dividends paid		(44,145	)		(56,145	)
Issuance of common stock		1,569			--
Redemption of preferred stock		(7,500	)		(7,500	)
Redemption of trust preferred securities		(19,773	)		--
Issuance of bonds and long-term debt		319,983			95,980
Redemption of bonds and long-term debt		(271,860	)		(60,000	)
Issuance costs of bonds and other		(10,248	)		(62	)

Net Cash Used by Financing Activities		(25,876	)		(251,197	)

Net Decrease in Cash		(36,165	)		(1,083	)
Cash at Beginning of Year		176,669			92,356

Cash at End of Period	$	140,504		$	91,273

Supplemental Cash Flow Information:
Cash payments for:
Interest (net of capitalized interest)	$	99,037		$	95,779
Income taxes		(5,874	)		1,238

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

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

	2003			2002
Operating Revenues:
Electric	$	348,196		$	316,122
Gas		116,747			144,384
Other		570			4,191

Total operating revenues		465,513			464,697

Operating Expenses:
Energy costs:
Purchased electricity		191,600			127,924
Purchased gas		57,372			88,520
Electric generation fuel		11,088			14,680
Residential Exchange		(36,977	)		(30,964	)
Unrealized gain on derivative instruments		(44	)		(252	)
Utility operations and maintenance		73,895			73,630
Other operations and maintenance		261			361
Depreciation and amortization		54,720			54,103
Conservation amortization		6,295			3,605
Taxes other than income taxes		42,890			49,003
Income taxes		2,293			11,363

Total operating expenses		403,393			391,973

Operating Income		62,120			72,724
Other income		2,309			3,455

Income Before Interest Charges		64,429			76,179
Interest charges, net of AFUDC		44,815			47,340

Net Income		19,614			28,839
Less: preferred stock dividends accrual		1,794			1,940

Income for Common Stock	$	17,820		$	26,899

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

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

	2003			2002
Operating Revenues:
Electric	$	765,194		$	679,371
Gas		304,535			458,875
Other		1,069			4,750

Total operating revenues		1,070,798			1,142,996

Operating Expenses:
Energy costs:
Purchased electricity		432,036			309,911
Purchased gas		144,326			293,318
Electric generation fuel		26,162			79,860
Residential Exchange		(89,656	)		(73,711	)
Unrealized gain on derivative instruments		(521	)		(11,748	)
Utility operations and maintenance		143,950			139,571
Other operations and maintenance		522			815
Depreciation and amortization		109,305			107,781
Conservation amortization		14,017			5,769
Taxes other than income taxes		97,810			112,232
Income taxes		36,794			31,742

Total operating expenses		914,745			995,540

Operating Income		156,053			147,456
Other income		3,000			3,764

Income Before Interest Charges		159,053			151,220
Interest charges, net of AFUDC		91,170			96,683

Income Before Cumulative Effect of Accounting Change		67,883			54,537
Cumulative effect of implementation of an accounting change, net of tax		169			--

Net Income		67,714			54,537
Less: preferred stock dividends accrual		3,661			3,952

Income for Common Stock	$	64,053		$	50,585

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

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

	2003			2002
Net Income	$	19,614		$	28,839

Other comprehensive income, net of tax:
Unrealized holding losses on marketable securities arising		(30	)		(377	)
during the period
Reclassification adjustment for realized gains on marketable		(1,548	)		--
securities included in net income
Unrealized gains (losses) on derivative instruments during the period		3,029			(3,513	)
Reversal of unrealized losses on derivative instruments		2,003			1,347
settled during the period

Other comprehensive income (loss)		3,454			(2,543	)

Comprehensive Income	$	23,068		$	26,296

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

	2003			2002
Net Income	$	67,714		$	54,537

Other comprehensive income, net of tax:
Unrealized holding losses on marketable securities arising		(45	)		(526	)
during the period
Reclassification adjustment for realized gains on marketable		(1,548	)		(724	)
securities included in net income
Unrealized gains (losses) on derivative instruments during the period		4,059			(2,102	)
Reversal of unrealized losses on derivative instruments		4,319			32,834
settled during the period

Other comprehensive income		6,785			29,482

Comprehensive Income	$	74,499		$	84,019

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

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

ASSETS

	June 30, 2003			December 31, 2002
Utility Plant: (at original cost, including construction work in progress of
$140,696 and $108,658 respectively)
Electric	$	4,238,524		$	4,229,352
Gas		1,691,231			1,645,865
Common		387,407			378,844
Less: Accumulated depreciation and amortization		(2,384,914	)		(2,337,832	)

Net utility plant		3,932,248			3,916,229

Other Property and Investments		167,279			154,757

Current Assets:
Cash		131,717			161,475
Restricted cash		12,267			18,871
Accounts receivable, net		180,716			208,702
Unbilled revenue		58,866			112,115
Materials and supplies, at average cost		71,120			63,563
Current portion of unrealized gain on derivative instruments		11,218			3,741
Prepayments and other		7,745			8,907

Total current assets		473,649			577,374

Other Long-Term Assets:
Regulatory asset for deferred income taxes		163,526			167,058
Regulatory asset for PURPA contract buyout costs		236,977			243,584
Unrealized gain on derivative instruments		8,636			9,870
Power cost adjustment mechanism		4,085			--
Other		297,135			269,876

Total other long-term assets		710,359			690,388

Total Assets	$	5,283,535		$	5,338,748

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

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

CAPITALIZATION AND LIABILITIES

	June 30, 2003		December 31, 2002
Capitalization:
Common shareholders' investment:
Common stock, $10 stated value, 150,000,000 shares
authorized, 85,903,791 shares outstanding	$	859,038	$	859,038
Additional paid-in capital		499,871		498,335
Earnings reinvested in the business		90,541		66,971
Accumulated other comprehensive income		8,562		1,777
Preferred stock not subject to mandatory redemption		60,000		60,000
Preferred stock subject to mandatory redemption		35,639		43,162
Corporation obligated, mandatorily redeemable preferred
securities of subsidiary trust holding solely junior
subordinated debentures of the corporation		280,250		300,000
Long-term debt		2,000,339		2,021,832

Total capitalization		3,834,240		3,851,115

Current Liabilities:
Accounts payable		131,991		193,602
Short-term debt		33,013		30,340
Current maturities of long-term debt		133,500		72,000
Purchased gas liability		14,310		83,811
Accrued expenses:
Taxes		64,663		64,433
Salaries and wages		12,315		11,441
Interest		33,330		37,942
Other		27,478		27,866

Total current liabilities		450,600		521,435

Long-Term Liabilities:
Deferred income taxes		740,829		715,579
Other deferred credits		257,866		250,619

Total long-term liabilities		998,695		966,198

Total Capitalization and Liabilities	$	5,283,535	$	5,338,748

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

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

	2003			2002
Operating Activities:
Net Income	$	67,714		$	54,537
Adjustments to reconcile net income
to net cash provided by operating activities:
Depreciation and amortization		109,305			107,731
Deferred federal income taxes and tax credits - net		28,782			25,670
Net unrealized gains on derivative instruments		(521	)		(11,748	)
Cash collateral received from energy supplier		13,268			8,340
Gain on sale of securities		(2,910	)		--
Other		(3,802	)		(3,109	)
Change in certain current assets and current liabilities:
Accounts receivable and unbilled revenue		81,236			107,282
Materials and supplies		(7,557	)		29,693
Prepayments and other		1,162			2,429
Purchased gas receivable/liability		(69,500	)		128,613
Accounts payable		(61,610	)		(36,650	)
Taxes payable		231			6,732
Accrued expenses and other		(2,097	)		9,129

Net Cash Provided by Operating Activities		153,701			428,649

Investing Activities:
Construction expenditures - excluding equity AFUDC		(134,622	)		(113,133	)
Additions to energy conservation program		(8,786	)		(4,434	)
Restricted cash		6,605			(5,869	)
Cash received from sale of securities		3,056			--
Investment in variable rate bonds		(14,055	)		--
Other		1,803			(5,888	)

Net Cash Used by Investing Activities		(145,999	)		(129,324	)

Financing Activities:
Change in short-term debt - net		2,673			(230,122	)
Dividends paid		(44,145	)		(56,145	)
Issuance of bonds		311,860			--
Redemption of preferred stock		(7,500	)		(7,500	)
Redemption of trust preferred securities		(19,773	)		--
Redemption of bonds		(271,860	)		(20,000	)
Issuance cost of bonds and other		(8,715	)		(107	)

Net Cash Used by Financing Activities		(37,460	)		(313,874	)

Net Decrease in Cash		(29,758	)		(14,549	)
Cash at Beginning of Year		161,475			82,708

Cash at End of Period	$	131,717		$	68,159

Supplemental Cash Flow Information:
Cash payments for:
Interest (net of capitalized interest)	$	96,580		$	93,033
Income taxes (net of refunds)		(2,321	)		809

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) Summary of Consolidation Policy

BASIS OF PRESENTATION
        Puget Energy is an exempt public utility holding company under the Public Utility Holding Company Act of 1935. Puget Energy owns Puget Sound Energy (PSE) and is a majority owner of InfrastruX Group, Inc. (InfrastruX), a Washington corporation.
        The consolidated financial statements of Puget Energy include the accounts of Puget Energy and its subsidiaries, PSE and InfrastruX. Puget Energy holds all the common shares of PSE and holds a majority interest in InfrastruX. The results of PSE and InfrastruX are presented on a consolidated basis. PSE’s consolidated financial statements include the accounts of PSE and its subsidiaries. Puget Energy and PSE are collectively referred to herein as “the Company”. The consolidated financial statements are presented after elimination of all significant intercompany items and transactions. Minority interests of InfrastruX’s operating results are reflected in Puget Energy’s consolidated financial statements. Certain amounts previously reported have been reclassified to conform with current year presentations with no effect on total equity or net income.
        The consolidated financial statements contained in this Form 10-Q are unaudited. In the respective opinions of the managements of Puget Energy and PSE, all adjustments necessary for a fair presentation of the results for the interim periods have been reflected and were of a normal recurring nature. These condensed financial statements should be read in conjunction with the audited financial statements (and the Combined Notes thereto) included in the combined Puget Energy and PSE annual report on Form 10-K for the year ended December 31, 2002, which is available at the Securities and Exchange Commission website at www.sec.gov or at Puget Energy’s website at www.pse.com.

(2) Earnings per Common Share (Puget Energy Only)

Puget Energy’s basic earnings per common share have been computed based on weighted average common shares outstanding of 93,928,000 and 93,833,000 for the three and six months ended June 30, 2003, respectively, and 87,448,000 and 87,309,000 for the three and six months ended June 30, 2002, respectively.
Puget Energy’s diluted earnings per common share have been computed based on weighted average common shares outstanding of 94,440,000 and 94,346,000 for the three and six months ended June 30, 2003, respectively, and 87,646,000 and 87,508,000 for the three and six months ended June 30, 2002, respectively. These shares include the dilutive effect of securities related to employee and director equity plans.

(3) Segment Information (Puget Energy Only)

Puget Energy operates in primarily two business segments: Regulated Utility Operations, or PSE, and Construction Services, or InfrastruX. Puget Energy’s regulated utility operation generates, purchases, transports and sells electricity, and purchases, transports and sells natural gas. The service territory of PSE covers approximately 6,000 square miles in Washington State. InfrastruX specializes in contracting services to other gas and electric utilities primarily in the Midwest, Texas and the eastern United States.
The other principal non-utility line of business, which is a PSE subsidiary, is a real estate investment and development company. Reconciling items between segments are not material.

Financial data for business segments are as follows:

(Dollars in Thousands) Three Months Ended June 30, 2003	PSE	InfrastruX	Other		Total

Revenues	$ 464,943	$ 92,343	$ 570		$ 557,856
Depreciation and amortization	54,661	4,601	59		59,321
Income tax	2,290	2,568	(26	)	4,832
Operating income	61,958	4,325	124		66,407
Interest charges, net of AFUDC	44,814	1,148	18		45,980
Net income	17,562	2,833	1,997		22,392
Goodwill, net	--	132,162	--		132,162
Total assets	5,154,879	343,562	128,161		5,626,602

Three Months Ended June 30, 2002	PSE	InfrastruX	Other	Total

Revenues	$460,506	$76,122	$4,191	$540,819
Depreciation and amortization	54,000	3,253	104	57,357
Income tax	9,874	2,315	1,453	13,642
Operating income	70,547	4,177	2,109	76,833
Interest charges, net of AFUDC	47,340	1,342	--	48,682
Net income	26,662	2,598	2,109	31,369

Six Months Ended June 30, 2003	PSE	InfrastruX		Other		Total

Revenues	$1,069,729	$ 163,020		$ 1,069		$1,233,818
Depreciation and amortization	109,194	7,960		112		117,266
Income tax	36,787	(528	)	(61	)	36,198
Operating income	155,773	1,846		173		157,792
Interest charges, net of AFUDC	91,170	2,457		18		93,645
Net income	65,543	(609	)	2,046		66,980

Six Months Ended June 30, 2002	PSE	InfrastruX	Other	Total

Revenues	$1,138,246	$136,883	$4,750	$1,279,879
Depreciation and amortization	107,673	5,525	108	113,306
Income tax	29,963	2,950	1,664	34,577
Operating income	145,021	6,162	2,221	153,404
Interest charges, net of AFUDC	96,683	2,397	--	99,080
Net income	52,280	3,524	2,043	57,847

At December 31, 2002	PSE	InfrastruX	Other	Total

Goodwill, net	$ --	$125,555	$ --	$ 125,555
Total assets	5,208,487	319,248	129,756	5,657,491

(4) Accounting for Derivative Instruments and Hedging Activities

        The Company has adopted Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended by SFAS No. 138. SFAS No. 133 requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair value. The Company enters into both physical and financial contracts to manage its energy resource portfolio including forward physical and financial contracts, option contracts and swaps. The majority of these contracts qualify for the normal purchase and normal sale exception.
        During the three months ended June 30, 2003 and 2002, the Company recorded an increase in earnings for the change in the market value of derivative instruments not meeting cash flow hedge criteria of approximately $44 thousand pre-tax ($29 thousand after-tax) and $0.3 million pre-tax ($0.2 million after-tax), respectively. During the six months ended June 30, 2003 and 2002, the Company recorded an increase in earnings of approximately $0.5 million pre-tax ($0.3 million after-tax) and $11.7 million pre-tax ($7.6 million after-tax), respectively. The $11.7 million pre-tax gain in 2002 represented the reversal of unrealized losses on gas hedge contracts that were de-designated in the fourth quarter of 2001 and the reversal of the mark-to-market unrealized loss on physical electric contracts at December 31, 2001 that were settled in 2002.
        The Company has two contracts outstanding with a counterparty whose senior unsecured debt ratings are below investment grade. The first contract is a fixed for floating price natural gas swap contract for which the Company has collected a collateral deposit in the amount of $30.7 million from the counterparty to guarantee performance. The financial contract will expire in June 2008 and is accounted for as a cash flow hedge under SFAS No. 133. The second is a physical gas supply contract expiring in December 2008, which has been designated as a normal purchase under SFAS No. 133. The counterparty has continuously performed on both contracts since the contracts were entered into in 2000 and the Company believes it is probable that the counterparty will continue to perform. The Company will continue to monitor the performance of the counterparty.

(5) Intangibles (Puget Energy Only)

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


At June 30, 2003 (Dollars in thousands)	Gross Intangibles	Accumulated Amortization	Net Intangibles
Covenant not to compete	$ 4,178	$1,485	$ 2,693
Developed technology	14,190	2,124	12,066
Contractual customer relationships	3,242	569	2,673
Patents	851	63	788

Total	$22,461	$4,241	$18,220


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

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

The identifiable intangible asset amortization expense for the three and six months ended June 30, 2003 was $0.5 million and $1.0 million, respectively, compared to $0.4 million and $0.7 million for the same periods of 2002. The identifiable intangible assets amortization for future periods based on the current acquisitions will be:

(Dollars in thousands)			2003			2004			2005			2006			2007			2008
Future Intangible Amortization			$	920		$	1,976		$	1,960		$	1,631		$	1,248		$	1,179

(6) Asset Retirement Obligation

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

(Dollars in thousands) At June 30, 2003	Amount
Asset retirement obligation at December 31, 2002	$	--
Liability recognized in transition		3,592
Accretion expense		45

Asset retirement obligation at June 30, 2003	$	3,637

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

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

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

	Three Months Ended June 30					Six Months Ended June 30
(Dollars in thousands, except per share)	2003		2002			2003		2002
Income for common stock, as reported	$	20,598	$	29,429		$	63,319	$	53,895
Add: FAS 143 transition adjustment, net of tax		--		--			169		--
Less: Pro forma accretion expense, net of tax		--		(15	)		--		(31	)

Pro forma income for common stock	$	20,598	$	29,414		$	63,488	$	53,864

Earnings per share:
Basic as reported	$	0.22	$	0.34		$	0.68	$	0.62
Diluted as reported	$	0.22	$	0.34		$	0.67	$	0.62
Basic pro forma	$	0.22	$	0.34		$	0.68	$	0.62
Diluted pro forma	$	0.22	$	0.34		$	0.67	$	0.62

(7) Stock Compensation

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

	Three Months Ended June 30						Six Months Ended June 30
(Dollars in thousands, except per share)	2003			2002			2003			2002
Income for common stock, as reported	$	20,598		$	29,429		$	63,319		$	53,895
Add: Total stock-based employee compensation expense		1,953			83			2,510			281
included in net income, net of tax
Less: Total stock-based employee compensation expense per		(999	)		(711	)		(1,891	)		(1,381	)
the fair value method of SFAS 123, net of tax

Pro forma income for common stock	$	21,552		$	28,801		$	63,938		$	52,795

Earnings per share:
Basic as reported	$	0.22		$	0.34		$	0.68		$	0.62
Diluted as reported	$	0.22		$	0.34		$	0.67		$	0.62
Basic pro forma	$	0.23		$	0.33		$	0.68		$	0.60
Diluted pro forma	$	0.23		$	0.33		$	0.68		$	0.60

(8) New Accounting Pronouncements

        In January 2003, the Financial Accounting Standards Board (FASB) issued Interpretation No. 46 – “Consolidation of Variable Interest Entities” (FIN 46). FIN 46 clarifies the application of Accounting Research Bulletin No. 51 – “Consolidated Financial Statements” to certain entities in which equity investors do not have controlling interest or sufficient equity at risk for the entity to finance its activities without additional financial support. This Interpretation requires that if a business entity has a controlling financial interest in a variable interest entity the financial statements must be included in the consolidated financial statements of the business entity. The adoption of this Interpretation for all interests in variable interest entities created after January 31, 2003 was effective on that date. For variable interest entities created before February 1, 2003, it is effective with the first fiscal year or interim period beginning after June 15, 2003. The Company has evaluated its contractual arrangements and determined PSE’s 1995 conservation trust off-balance sheet financing transaction meets this guidance. This transaction will increase the balance sheet assets and liabilities of Puget Energy and PSE by approximately $11.6 million beginning July 2003 with no impact on earnings.
        In May 2003, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 150 – “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity”. SFAS 150 establishes the requirements for classifying and measuring as liabilities certain financial instruments that embody obligations to redeem the financial instrument by the issuer. The adoption of SFAS 150 is effective with the first fiscal year or interim period beginning after June 15, 2003, however, prior periods will not be restated for the new presentation.
        SFAS 150 will require the Company to classify its mandatorily redeemable preferred stock and the corporation obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely junior subordinated debentures of the corporation (trust preferred securities) as liabilities. As a result, the corresponding dividends on the mandatorily redeemable preferred stock will be classified as interest expense on the income statement. The Company currently classifies the dividends associated with the trust preferred securities as interest expense.
        In April 2003, the FASB issued SFAS No. 149, “Amendment on Statement 133 on Derivative Instruments and Hedging Activities,” which is effective for all contracts entered into or modified after June 30, 2003 except for certain hedging relationships designated after June 30, 2003. SFAS No. 149 clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in contracts and for hedging activities under SFAS No. 133. The Company does not expect that SFAS No. 149 will have any significant impact on its financial statements.
        The Emerging Issues Task Force of the Financial Accounting Standards Board (EITF or Task Force) at its June 2002 meeting came to a consensus on one of three items included in EITF Issue 02-3 “Accounting for Contracts Involved in Energy Trading and Risk Management Activities”. The Task Force has agreed that all mark-to-market gains and losses on energy trading contracts whether realized or unrealized will be shown net in the income statement (costs offset against revenues), irrespective of whether the contract is physically settled. The presentation is applicable to financial statements for periods ending after July 15, 2002. The Company performs risk management activities to optimize the value of energy supply and transmission assets and to ensure that physical energy supply is available to meet the customer demand loads. The Company also purchases energy when demand exceeds available supplies in its portfolio; likewise the Company makes sales to other utilities and marketers when surplus energy is available. These transactions are part of the Company’s normal operations to meet retail load. The Company has reclassified all settled transactions that meet the definition of optimization (trading transactions that optimize hydro resources, and purchases and sales between trading points) net in the income statement to conform to the new presentation required under EITF 02-3. The Company previously reported these transactions when settled in a gross manner in the income statement in electric operating revenue and purchased electricity expense. Unrealized gains or losses on derivative instruments that are required to be marked-to-market remain reflected in unrealized (gain) loss on derivative instruments on Puget Energy’s and PSE’s income statement as required by SFAS No. 133. The adoption of EITF 02-3 does not have any impact on the previously reported net income of the Company.

(9) Other

On May 27, 2003, Puget Energy entered into a $15 million, three-year credit agreement with a bank. Under the terms of the agreement, Puget Energy will pay a floating interest rate on borrowings based on the London inter-bank offered rate (LIBOR). The interest rate is set for one, two, or three month periods at the option of Puget Energy with interest due at the end of each period. Puget Energy will also pay a commitment fee on any unused portion of the credit facility. On May 30, 2003, Puget Energy borrowed $5 million under the credit agreement. The proceeds of the loan were invested in InfrastruX, which used the proceeds to acquire a construction services company in New Mexico.
On April 9, 2003, the Washington Commission approved an increase in the Purchased Gas Adjusment (PGA) gas rates of approximately $103.6 million annually or 20.1%. The PGA mechanism passes through to customers increases or decreases in the gas supply portion of the natural gas service rates based upon changes in gas prices. PSE’s gas margin and net income is not affected by the change in the PGA rates. The PGA increase became effective April 10, 2003.

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

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

Results of Operations

Puget Energy
        All of the operations of Puget Energy are conducted through its subsidiaries, PSE and InfrastruX. Puget Energy’s net income for the three months ended June 30, 2003 was $22.4 million on operating revenues of $557.9 million, compared with net income of $31.4 million on operating revenues of $540.8 million for the same period in 2002. Net income for common stock was $20.6 million for the second quarter of 2003 compared to $29.4 million for the second quarter of 2002. Basic and diluted earnings per share were $0.22 for the second quarter of 2003 compared to $0.34 for the second quarter of 2002.
        For the first six months of 2003, net income was $67.0 million on operating revenues of $1.2 billion, compared to net income of $57.8 million on operating revenues of $1.3 billion for the corresponding period in 2002. Income for common stock was $63.3 million for the first half of 2003 and $53.9 million for the same period in 2002. Basic and diluted earnings per common share were $0.68 and $0.67, respectively, for the six months ended June 30, 2003 and $0.62 for the same period in 2002.
        Net income for common stock was negatively impacted by a decrease in PSE’s net income for common stock of $9.1 million for the three months ended June 30, 2003 compared to the same period in 2002 due primarily to the impact of $25 million of interim electric tariff rate increases effective April 1, 2002 through June 30, 2002 not recurring in 2003, offset by the favorable impact of general tariff rate increases that became effective on July 1, 2002 for PSE’s electric customers and September 1, 2002 for PSE’s gas customers. Net income for common stock was positively impacted by an increase in InfrastruX’s net income for common stock (net of minority interest) of $0.2 million for the three months ended June 30, 2003 compared to the same period in 2002 due to increased revenue from acquired companies in the second quarter of 2003 which were not part of InfrastruX during the entire second quarter of 2002.
        Net income for common stock was positively impacted by an increase in PSE’s net income for common stock of $13.5 million for the six months ended June 30, 2003 compared to the same period in 2002, due primarily to the favorable impact of general tariff rate increases that became effective on July 1, 2002 for PSE’s electric customers and September 1, 2002 for PSE’s gas customers. Net income for common stock was negatively impacted by a decrease in InfrastruX’s net income for common stock (net of minority interest) of $4.1 million for the six months ended June 30, 2003 compared to the same period in 2002 due to unusually severe weather which affected the first half of 2003 productivity and competitive pressures on profit margins.

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

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

	Three Month Period			Six Month Period
Operating revenue changes:
Electric interim and general rate increase	$	(7	.1)	$	2	.3
BPA Residential Exchange Credit		(6	.3)		(16	.7)
Electric sales to other utilities and marketers		40	.2		80	.4
Electric conservation trust credit		(1	.0)		(1	.8)
Electric transportation revenue		(1	.1)		(1	.5)
Electric load and other		7	.4		23	.1

Total electric operating change		32	.1		85	.8

Gas PGA rate and load change		(35	.4)		(176	.0)
Gas general rate increase in base rates		7	.5		20	.7
Gas transportation revenue and other		0	.3		1	.0

Total gas operating change		(27	.6)		(154	.3)

Other operating revenue change		(3	.7)		(3	.7)

Total operating revenue change		0	.8		(72	.2)

Operating expense changes:
Energy costs:
Purchased electricity		63	.7		122	.1
Purchased gas		(31	.1)		(149	.0)
Electric generation fuel		(3	.6)		(53	.7)
Residential exchange power cost credit		(6	.0)		(15	.9)
Unrealized (gain) loss on derivative instruments		0	.2		11	.2
Utility operations and maintenance:
Production operations and maintenance		(2	.9)		(2	.7)
Personal energy management expenses		(1	.5)		(3	.8)
Low income program pass through expenses		1	.8		4	.6
Other utility operations and maintenance		2	.9		6	.3
Other operations and maintenance		(0	.2)		(0	.3)
Depreciation and amortization		0	.6		1	.5
Conservation amortization		2	.7		8	.2
Taxes other than income taxes		(6	.1)		(14	.4)
Income taxes		(9	.1)		5	.1

Total operating expense change		11	.4		(80	.8)

Other income change (net of tax)		(1	.1)		(0	.8)
Interest charges change		(2	.5)		(5	.5)
Cumulative effect of an accounting change (net of tax)			--		(0	.1)

Net income change	$	(9	.2)	$	13	.2

        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 in the first and fourth quarters of the year. Varying wholesale electric prices and the amount of hydroelectric energy supplies available to PSE also make quarter-to-quarter comparisons difficult. The following is additional information pertaining to the changes outlined in the above table.
        Electric margin decreased $25.6 million for the three months ended June 30, 2003 compared to the same period in 2002 primarily as a result of $25.0 million of rate relief in effect only during the interim period of April 1, 2002 through June 30, 2002 and an increase in power costs of $20.8 million which includes the Company’s portion of underrecovered power costs of $7.3 million, and lower margins due to warmer temperatures. These decreases were partially offset by an increase of $17.9 million resulting from the general tariff rate increase effective July 1, 2002. Electric margin increased $22.8 million for the six months ended June 30, 2003 compared to the same period in 2002 primarily due to $27.3 million resulting from the general tariff rate increase effective July 1, 2002 offset by the Company’s portion of underrecovered power costs of $18.9 million. Electric margin is electric sales to retail and transportation customers less pass-through tariff items, revenue sensitive taxes, and the cost of generating and purchasing electric energy sold to customers including transmission costs, to bring electric energy to PSE’s service territory.
        Electric margin for the three and six months ended June 30, 2003 and June 30 2002 is detailed further as follows:

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

	Three Months Ended June 30						Six Months Ended June 30
	2003			2002			2003			2002
Electric retail sales revenue	$	285	.7	$	293	.3	$	633	.4	$	648	.2
Electric transportation revenue		3	.4		4	.5		6	.6		8	.1
Other electric revenue-gas supply resale		2	.2		(0	.6)		7	.3		(18	.5)

Total electric revenue for margin		291	.3		297	.2		647	.3		637	.8
Adjustments for amounts included in revenue:
Pass-through tariff items		(11	.3)		(6	.1)		(24	.3)		(11	.0)
Pass-through revenue-sensitive taxes		(20	.5)		(20	.8)		(45	.4)		(45	.8)
Residential Exchange Credit		37	.0		31	.0		89	.7		73	.7

Net electric revenue for margin		296	.5		301	.3		667	.3		654	.7
Minus Power Costs:
Fuel		(11	.1)		(14	.7)		(26	.2)		(79	.9)
Purchased electricity, net of sales to other		(139	.2)		(114	.8)		(322	.4)		(278	.9)
utilities and marketers

Total electric power costs		(150	.3)		(129	.5)		(348	.6)		(358	.8)

Electric Margin	$	146	.2	$	171	.8	$	318	.7	$	295	.9

Gas margin increased $6.2 million for the three months ended June 30, 2003 compared to the same period in 2002 due primarily to an increase of $7.5 million resulting from the 5.8% general gas tariff rate increase effective September 1, 2002. Gas margin increased $5.5 million for the six months ended June 30, 2003 compared to the same period in 2002 due primarily to an increase of $20.7 million resulting from the 5.8% general gas tariff rate increase effective September 1, 2002 offset by gas therm sales declining 9.9% due to warmer weather. Gas margin is gas sales to retail and transportation customers less pass-through tariff items and revenue sensitive taxes, and the cost of gas purchased, including gas transportation costs to bring gas to PSE’s service territory.

Gas margin for the three and six months ended June 30, 2003 and June 30, 2002 is detailed further as follows:

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

	Three Months Ended June 30						Six Months Ended June 30
	2003			2002			2003			2002
Gas retail revenue	$	110	.7	$	138	.6	$	292	.1	$	447	.4
Gas transportation revenue		3	.4		3	.0		6	.8		5	.9

Total gas revenue for margin		114	.1		141	.6		298	.9		453	.3
Adjustments for amounts included in revenue:
Gas revenue hedge			--			--		0	.2			--
Pass-through tariff items		(0	.8)		(0	.3)		(2	.4)		(0	.6)
Pass-through revenue-sensitive taxes		(9	.7)		(12	.8)		(24	.6)		(37	.1)

Net gas revenue for margin		103	.6		128	.5		272	.1		415	.6
Minus Purchased Gas Costs		(57	.4)		(88	.5)		(144	.3)		(293	.3)

Gas Margin	$	46	.2	$	40	.0	$	127	.8	$	122	.3

Operating Revenues — Electric
        Electric operating revenues for the three months ended June 30, 2003 were $348.2 million, an increase of $32.1 million compared to the same period in 2002 due primarily to wholesale electric sales to other utilities and marketers which increased $40.2 million due to greater surplus volumes due in part to hedging expected hydro shortfall in energy production and higher prices in the wholesale electricity market. In February 2003, the National Rivers Forecast Center predicted streamflows in the Columbia River Basin would be approximately 76% of normal while actual streamflows were approximately 89% for the six months ended June 30, 2003, resulting in additional hydro production. Wholesale sales volumes increased by 1.0 billion kWh or 129.2% to 1.8 billion kWh as a result of warmer temperatures compared to the same period in 2002 in the Pacific Northwest which provided excess electric energy supplies for sales to the wholesale market as a result of a reduction in retail sales and additional hydro production creating excess energy supply. Temperatures based on heating-degree-days measured at Seattle-Tacoma airport during the three month period ended June 30, 2003 were about normal, while second quarter 2002 temperatures were 12% colder than normal. Retail sales revenue decreased $7.7 million due primarily to $25 million of interim rate relief ended June 30, 2002 offset by the effect of a 4.6% electric general rate increase effective July 1, 2002 that increased electric revenue by approximately $17.9 million in 2003. Retail sales volume increased 1.7% to 4.5 billion kWh from 4.4 billion kWh for the same period in 2002.
        Electric operating revenues for the six months ended June 30, 2003 were $765.2 million, an increase of $85.8 million compared to the same period in 2002 due primarily to wholesale electric sales to other utilities and marketers which increased $80.4 million due to greater surplus volumes due in part to hedging expected hydro shortfall in energy production and higher prices in the wholesale electricity market. Wholesale sales volumes increased by 1.7 billion kWh or 127.6% to 3.1 billion kWh as a result of warmer-than-normal temperatures in the Pacific Northwest which provided excess electric energy supplies for sales to the wholesale market as a result of a reduction in retail sales and additional hydro production creating excess energy supply. Temperatures based on heating-degree-days measured at Seattle-Tacoma airport during the six month period ended June 30, 2003 were 4.7% warmer than normal as compared to heating-degree-days being 9.2% cooler than normal during the six month period ended June 30, 2002. Retail sales revenue decreased $14.8 million due primarily to $25 million of interim rate relief ended June 30, 2002 and warmer temperatures in 2003 offset by the effect of a 4.6% electric general rate increase effective July 1, 2002 that increased electric revenue by approximately $27.3 million in 2003. Retail sales volume decreased 0.8% to 9.8 billion kWh from 9.9 billion kWh for the same period in 2002.
        On June 20, 2002, the Washington Commission approved and adopted the settlement stipulation in the general rate case, putting new rates into effect on July 1, 2002. PSE established a Power Cost Adjustment (PCA) mechanism in the rate case settlement. The PCA mechanism will account for differences in PSE’s modified actual power costs relative to a power cost baseline. The mechanism will account for a sharing of costs and benefits that are graduated over four levels of power cost variances, with an overall cap of $40 million (+/-) over the four year period July 1, 2002 through June 30, 2006 plus 1% of the excess over $40 million. PSE’s share of the cost through June 30, 2003 was $24.1 million, $18.9 million of which was incurred in the first six months of 2003. Utility customers’ share of the costs, which were deferred for later recovery, through June 30, 2003 was $4.1 million, all of which was incurred in the second quarter of 2003. The factors influencing the variability of power costs included in the proposal are primarily weather and market related.
        On June 11, 2001, PSE and BPA entered into an amended settlement agreement regarding the Residential Purchase and Sale Program, under which PSE’s residential and small farm customers would continue to receive benefits of federal power. Completion of this agreement enabled PSE to continue to provide a Residential and Farm Energy Exchange Credit to residential and small farm customers. The amended settlement agreement provides that, for its residential and small farm customers, PSE will receive (a) cash payment benefits during the period July 1, 2001 through September 30, 2006 and (b) benefits in the form of power or cash payments during the period October 1, 2006 through September 30, 2011.
        Under the Residential Purchase and Sale Program, PSE reduces residential and small farm customers revenue on a per kWh basis through the Residential and Farm Energy Exchange Credit. The credit has no impact on PSE’s electric margin or net income as a corresponding reduction is included in purchased electricity expenses. The Residential Purchase and Sale Program provides PSE’s residential and small farm customers benefits of lower-cost federal power.
        On June 17, 2002, PSE entered into an agreement with BPA which amended the payment provisions of the amended settlement agreement to provide for conditional deferral of payment by BPA of certain amounts to be paid under the original agreement. Under the modified agreement, BPA will defer paying a portion of the benefits it would have otherwise paid. The amount of benefits deferred will be $3.5 million each month for the eight-month period beginning February 2003, for a total deferral of $27.7 million. Contemporaneously with entering into this agreement with PSE, BPA is entering into other agreements similar to the agreement with PSE through which other investor-owned utilities and BPA are agreeing to BPA’s deferral of payments in their fiscal year 2003. The total cumulative amount to be deferred under the agreement with PSE and other such agreements equals $55 million, an amount that will help BPA address its current financial difficulties. Absent certain adjustments, BPA will begin paying back the amount deferred with interest over the sixty-month period beginning October 2006. In January 2003, PSE filed revised tariff sheets with the Washington Commission to reflect this modification to the agreement between PSE and the BPA. The Washington Commission accepted the tariff changes and the BPA credit was changed to $0.01740 per kWh, from $0.01817 per kWh, for the period February 15, 2003 through September 30, 2006. On June 30, 2003, BPA adopted its final Record of Decision in the February 2003 rate case, which established a formula for adjusting the rate which will affect the level of residential exchange benefits for PSE’s customers. However, the actual rate level adjustment BPA expects to put into effect October 1, 2003 has not yet been established.
        For the three and six months ended June 30, 2003, the benefits of the Residential and Farm Energy Exchange credited to customers were $38.7 million and $93.8 million, respectively, with a related offset to power costs. PSE received payments from BPA in the amount of $33.5 million and $70.5 million during the three and six months ended June 30, 2003, respectively. The difference between the customers’ credit and the amount received from BPA reduces the previously deferred amount owed to customers. The aggregated deferred amount is recorded on PSE’s balance sheet as restricted cash. Absent certain adjustments, the modified amended settlement agreement will provide for payments from BPA in the amount of $630.6 million for the period January 2003 through September 2006 and for pass-through of the same amount to eligible residential and farm customers.
        There are several actions in the U.S. Ninth Circuit Court of Appeals against BPA, in which the petitioners assert that BPA acted contrary to law or without authority in deciding to enter into, or in entering into or performing, a number of contracts, including the contract between BPA and PSE. BPA rates used in such contract between BPA and PSE for determining the amounts of money to be paid to PSE as residential exchange benefits during the period October 1, 2001 through September 30, 2006 have been confirmed, approved and allowed to go into effect by FERC on an interim basis, subject to refund with interest. It is not clear what impact, if any, review of such rates and the above-described U.S. Ninth Circuit Court of Appeals actions may have on PSE. PSE and other investor owned utilities are presently negotiating a potential settlement of the U.S. Ninth Circuit actions, whereby the litigation would be dismissed and BPA’s discretion over the level of 2007-2011 benefits would be reduced in consideration of a reduction in current period benefits. PSE cannot presently predict the outcome of the settlement negotiations.
        To meet customer demand, PSE dispatches resources in its power supply portfolio such as fossil-fuel generation, owned and contracted hydro capacity and energy, and long-term contracted power. However, depending principally upon availability of hydroelectric energy, plant availability, fuel prices and/or changing load as a result of weather, PSE may sell surplus power or purchase deficit power in the wholesale market. PSE manages its core energy portfolio through short and intermediate-term off-system physical purchases and sales, and through other risk management techniques. A PSE Risk Management Committee oversees energy portfolio exposures.
        During the three and six months ended June 30, 2003, PSE collected in its electric general rate tariff and remitted to a grantor trust $3.8 million and $7.7 million as compared to $2.7 million and $5.8 million for the same periods in 2002 as a result of PSE’s 1995 sale of future electric revenues associated with its investment in conservation assets. The impact of the sale of revenue was offset by reductions in conservation amortization and interest expenses. The principal amount owed by the trust to its bondholders was $11.6 million at June 30, 2003.
        PSE operates within the western wholesale market and has made sales into the California energy market. During the fourth quarter of 2000, PSE made such sales to the California energy market on which the receivable amount is still outstanding. PSE received a payment of approximately $1.3 million on the amount owed in the second quarter of 2003. At June 30, 2003, PSE’s receivable from the California Independent System Operators (CAISO) and other counter-parties, net of reserves, was $24.1 million.

Operating Revenues — Gas
        Retail gas revenue for the three and six month periods ended June 30, 2003 decreased by $27.9 million and $154.3 million from the same periods in 2002, respectively, which included the effect of a 5.8% gas general rate increase effective September 1, 2002 that increased gas revenue by approximately $7.5 million and $20.7 million for the three and six month periods ended June 30, 2003, respectively. Retail gas sales volumes decreased 7.4% from 158.5 million therms for the three months ended June 30, 2002 to 146.8 million therms for the three months ended June 30, 2003 and decreased 13.0% from 505.5 million therms for the six months ended June 30, 2002 to 440.0 million therms for the six months ended June 30, 2003 due primarily to warmer temperatures in the Pacific Northwest.
        Purchased Gas Adjustment (PGA) rates charged to customers were lower in the three and six month periods ended June 30, 2003 compared to the same periods in 2002 as a result of rate decreases of 7.3% and 12.5% which took effect September 1, 2002 and November 1, 2002, respectively, offset by a rate increase of 20.1% which took effect April 10, 2003. Gas supply costs are passed through to customers in the PGA. The PGA mechanism passes through to customers increases or decreases in the gas supply portion of the natural gas service rates based upon changes in the price of natural gas purchased from producers and wholesale marketers or changes in gas pipeline transportation costs.
        PSE’s gas margin (gas sales to retail and transportation customers less pass-through tariff items and revenue sensitive taxes, and the cost of gas purchased, including gas transportation costs to bring gas to PSE’s service territory) and net income are not affected by changes under the PGA.

Operating Expenses
        Purchased electricity expenses increased $63.7 million and $122.1 million for the three and six month periods ended June 30, 2003 compared to the same periods in 2002. PSE’s hydroelectric production and related power costs in 2003 have been negatively impacted by below normal winter precipitation and snow pack in the Pacific Northwest region associated with an El Nino weather condition. The July 9, 2003 seasonal water supply forecast published by the National Weather Service indicated that the total forecast runoff into the Grand Coulee reservoir for the period January through July 2003 would be 89% of normal. This compares to 108% of normal for the same period in 2002. The National Weather Service forecast runoff into the Grand Coulee reservoir for the later period of April through September 2003 is similar to the January through July 2003 period and is expected to be 88% of normal. Primarily due to adverse hydro conditions in 2003, the Company anticipates reaching the $40 million cumulative cap under the PCA mechanism by the end of 2003. Under the PCA mechanism, further increases in variable power costs through June 30, 2006 would be apportioned 99% to customers and 1% to PSE. PSE’s share of power costs, in excess of those set in rates, through June 30, 2003 was $24.1 million.
        Purchased gas expenses decreased $31.1 million and $149.0 million for the three and six month periods ended June 30, 2003 compared to the same periods in 2002. The decrease was due to lower consumption volumes as a result of warmer than normal temperatures and the impact of decreased gas costs, which are passed through to customers through the PGA mechanism. The PGA allows PSE to recover expected gas costs. PSE defers, as a receivable or liability, any gas costs that exceed or fall short of the amount in PGA rates and accrues interest under the PGA. The PGA balance was a liability at June 30, 2002 of $91.4 million compared to a liability balance at June 30, 2003 of $14.3 million.
        Electric generation fuel expense decreased $3.6 million and $53.7 million for the three and six month periods ended June 30, 2003 compared to the same periods in 2002 due to lower fuel costs for PSE controlled gas-fired generation facilities related to economic dispatch of those facilities.
        Residential exchange credits associated with the Residential Purchase and Sale Agreement with BPA increased $6.0 million and $15.9 million for the three and six month periods ended June 30, 2003 when compared to the same periods in 2002, due to an increase in the Residential and Farm Energy Exchange credit rate in 2002. For further details, see the amended Residential Purchase and Sale Agreement between PSE and BPA discussion in Operating Revenues – Electric.
        Unrealized gains on derivative instruments decreased $0.2 million and $11.2 million for the three and six month periods ended June 30, 2003 compared to the same periods in 2002 due to changes in the market value of derivative instruments. During the three months ended June 30, 2003 and 2002, the Company recorded an increase in earnings for the change in the market value of derivative instruments not meeting cash flow hedge criteria of approximately $44 thousand pre-tax ($29 thousand after-tax) and $0.3 million pre-tax ($0.2 million after-tax), respectively. During the six months ended June 30, 2003 and 2002, the Company recorded an increase in earnings of approximately $0.5 million pre-tax ($0.3 million after-tax) and $11.7 million pre-tax ($7.6 million after-tax), respectively. The $11.7 million pre-tax gain in 2002 represented the reversal of unrealized losses on gas hedge contracts that were de-designated in the fourth quarter of 2001 and the reversal of the mark-to-market unrealized loss on physical electric contracts at December 31, 2001 that were settled in 2002.
         The Company has two contracts outstanding with a counterparty whose senior unsecured debt ratings are below investment grade. The first contract is a fixed for floating price natural gas swap contract for which the Company has collected a collateral deposit in the amount of $30.7 million from the counterparty to guarantee performance. The financial contract will expire in June 2008 and is accounted for as a cash flow hedge under SFAS No. 133. The second is a physical gas supply contract expiring in December 2008, which has been designated as a normal purchase under SFAS No. 133. The counterparty has continuously performed on both contracts since the contracts were entered into in 2000 and the Company believes it is probable that the counterparty will continue to perform. The Company will continue to monitor the performance of the counterparty.
        Production operations and maintenance cost decreased $2.9 million and $2.7 million for the three and six month periods ended June 30, 2003 compared to the same periods in 2002 due primarily to a $4.0 million pre-tax charge in the second quarter of 2002 related to an industrial accident at Colstrip units 1 and 2 (of which PSE is a 50% owner) which did not recur in 2003.
        PSE’s Personal Energy Management^TM energy-efficiency program costs decreased $1.5 million and $3.8 million for the three and six month periods ended June 30, 2003 compared to the same periods in 2002, reflecting a decreased emphasis on the program in light of relatively moderate energy prices and cancellation of the Time of Use program in November 2002.
        A new Low-income Program approved by the Washington Commission in the general rate case settlement began in July 2002 which resulted in increased costs of $1.8 million and $4.6 million for the three and six months ended June 30, 2003 compared to the same periods in 2002. These costs are fully recovered in retail rates beginning at the program’s inception on July 1, 2002 for electric and September 1, 2002 for gas.
        Other utility operations and maintenance costs increased $2.9 million for the three months ended June 30, 2003 compared to the same period in 2002 due primarily to an increase of $1.7 million of energy resources strategic planning and acquisition costs, $1.6 million in administrative and general costs, and $1.1 million of customer accounts and sales expenses, offset by a decrease of $2.5 million related to outsourcing certain operation work which did not recur in 2003. Other utility operations and maintenance costs increased $6.3 million for the six months ended June 30, 2003 compared to the same period in 2002 due primarily to an increase of $2.5 million of electric and gas system operations and maintenance costs, $2.2 million of energy resources strategic planning and acquisition costs, $3.5 million in administrative and general costs, and $2.4 million of customer accounts and sales expenses, offset by a decrease of $4.5 million of severance and benefits costs related to outsourcing certain operation work which did not recur in 2003.
        Depreciation and amortization expense for PSE increased $0.6 million and $1.5 million for the three and six months ended June 30, 2003 compared to the same periods in 2002 due primarily to the effects of new plant placed into service during the past year.
        Conservation amortization expense increased $2.7 million and $8.2 million for the three and six months ended June 30, 2003 compared to the same periods in 2002 due to increased conservation expenditures. These costs are recovered in an electric conservation rider and a gas conservation tracker mechanism with no impact to earnings.
        Taxes other than income taxes decreased $6.1 million and $14.4 million for the three and six months ended June 30, 2003 compared to the same periods in 2002 primarily due to lower municipal and state excise taxes which are revenue based. In addition, PSE reached a settlement with the Oregon State Department of Revenue related to a property tax dispute resulting in a reduction recorded in the second quarter of 2003 of $1.4 million of amounts previously accrued as expense.
        Income taxes decreased $9.1 million for the three months ended June 30, 2003 compared to the same period in 2002 as a result of lower pre-tax operating income and a one-time $6.2 million tax benefit related to a favorable resolution of a federal income tax matter from 1997 to 2002. Income taxes increased $5.1 million for the six months ended June 30, 2003 compared to the same period in 2002 as a result of higher pre-tax operating income, offset by the $6.2 million reduction described above.

Interest Charges
Interest charges decreased $2.5 million for the three months ended and $5.5 million for the six months ended June 30, 2003 compared to the same periods in 2002. Interest on long-term debt decreased $4.1 million for the three months ended and $6.2 million for the six months ended June 30, 2003, compared to the same periods in 2002. This is primarily a result of the maturity of $107 million of Medium Term Notes with interest rates ranging from 7.07% to 7.91% during the third and fourth quarter of 2002 and the redemption of $19.7 million of 8.231% Capital Trust I Preferred Securities in February 2003, and $60 million in Medium Term Notes with interest rates ranging from 8.2% to 8.59% in May 2003.

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

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

	Three Month Period			Six Month Period
Operating revenue change:
Other operating revenue	$	16	.2	$	26	.1

Operating expense changes:
Other operations and maintenance		15	.2		31	.4
Depreciation and amortization		1	.3		2	.4
Taxes other than income taxes		(0	.7)		0	.1
Income taxes		0	.3		(3	.5)

Total operating expense change		16	.1		30	.4
Other Income (net of tax) change		0	.0		(0	.1)
Interest charges change		(0	.2)		0	.1
Minority interest change		0	.1		(0	.4)

Net income change	$	0	.2	$	(4	.1)

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

        InfrastruX revenue increased $16.2 million and $26.1 million for the three and six month periods ended June 30, 2003 compared to the same periods in 2002 due primarily to acquisitions of several companies during 2002 and 2003, which contributed an increase of $11.8 million and $24.8 million, respectively. Existing company revenues increased for the six month period ended June 30, 2003, but were adversely impacted by severe winter weather and snow accumulation in the Northeast and Midwest and by extremely wet winter conditions in the South, resulting in a significant slowdown in utility construction work. InfrastruX operations are seasonal, with its highest revenues typically in the second and third quarters of the year.
        InfrastruX operation and maintenance expenses increased $15.2 million and $31.4 million for the three and six month periods ended June 30, 2003 compared to the same periods in 2002 due to the additional costs related to acquired companies and weather-related problems in the first half of 2003 that impacted efficiency and productivity.
        Depreciation and amortization expense increased by $1.3 million and $2.4 million for the three and six month periods ended June 30, 2003 compared to the same periods in 2002 due to acquisitions during 2002 and additional assets placed in service to support growth.
        Income taxes increased $0.3 million the three month period ended June 30, 2003 compared to the same period in 2002 due primarily to operating income contributed from acquired companies. Income taxes decreased $3.5 million for the six month period ended June 30, 2003 compared to the same period in 2002 due primarily to the tax benefit associated with the first quarter 2003 net loss.

Capital Expenditures, Capital Resources and Liquidity

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

Puget Energy	Payments Due Per Period
Contractual Obligations (Dollars in millions)	Total			2003			2004-2005			2006-2007			2008 and Thereafter
Long-term debt (1)	$	2,276	.8	$	45	.9	$	306	.2	$	211	.3	$	1,713	.4
Short-term debt		53	.4		53	.4			--			--			--
Trust preferred securities (2)		280	.3			--			--			--		280	.3
Mandatorily redeemable preferred stock (3)		36	.3		34	.4			--			--		1	.9
Preferred dividends (4)		1	.1		1	.1			--			--			--
Service contract obligations		180	.5		9	.7		40	.7		43	.4		86	.7
Capital lease obligations		25	.8		3	.7		13	.5		7	.5		1	.1
Non-cancelable operating leases		70	.6		9	.4		30	.3		20	.5		10	.4
Fredonia combustion turbines lease (5)		71	.9		2	.3		8	.9		8	.6		52	.1
Energy purchase obligations		4,780	.5		479	.7		1,300	.1		931	.0		2,069	.7
Financial hedge obligations		(24	.4)		(8	.5)		(10	.1)		(4	.8)		(1	.0)

Total contractual cash obligations	$	7,752	.8	$	631	.1	$	1,689	.6	$	1,217	.5	$	4,214	.6

	Amount of Commitment Expiration Per Period
Commercial Commitments (Dollars in millions)	Total			2003			2004-2005			2006-2007			2008 and Thereafter
Guarantees (6)	$	135	.0	$		--	$	135	.0	$		--	$	--
Liquidity facilities - available (7)		290	.9		209	.5		81	.4			--		--
Lines of credit - available (8)		29	.6		2	.9		16	.7		10	.0		--
Energy operations letter of credit (9)		0	.5			--		0	.5			--		--

Total commercial commitments	$	456	.0	$	212	.4	$	233	.6	$	10	.0	$	--

(1)	The 2003 long-term debt includes $3 million in first mortgage bonds that had a maturity date in 2023, which were called for redemption by PSE in April 2003. The redemption date is scheduled for August 2003.

(2)

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) 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. During the first quarter of 2003, PSE repurchased $19.7 million of the Trust Securities.

(3)	On July 14, 2003, PSE called outstanding shares of the mandatorily redeemable 7.75% Series Cumulative Preferred Stock, which will be redeemed on August 15, 2003. The redemption price will be $102.07 per share plus accrued dividends.

(4)	On April 4, 2003, the Board of Directors of PSE declared a dividend payable on July 1, 2003 for preferred stock outstanding on June 13, 2003.

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

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

(7)

At June 30, 2003, PSE had available a $250 million unsecured 364-day credit agreement and $81.4 million in a receivable securization facility which provides credit support for outstanding commercial paper totaling $40 million and an outstanding letter of credit totaling $0.5 million, thereby effectively reducing the available borrowing capacity under this liquidity facility to $290.9 million. At June 30, 2003, the Company had available $81.4 million of receivables for sale under its three year $150.0 million receivables securitization facility. See “Accounts Receivable Securitization Program” under “Off-Balance Sheet Arrangements” below.

(8)

Puget Energy has a $15 million line of credit with a bank. Currently, $5 million is outstanding, reducing the available borrowing capacity under this line of credit to $10 million. InfrastruX has $179.1 million in lines of credit with various banks, including the $150 million line of credit guaranteed by Puget Energy, which fund capital requirements of InfrastruX and its subsidiaries. InfrastruX and its subsidiaries had outstanding loans of $155.4 million and letters of credit of $4.1 million, effectively reducing the available borrowing capacity under these lines of credit to $19.6 million.

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

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

Puget Sound Energy	Payments Due Per Period
Contractual Obligations (Dollars in millions)	Total			2003			2004-2005			2006-2007			2008 and Thereafter
Long-term debt (1)	$	2,133	.9	$	45	.0	$	169	.5	$	206	.0	$	1,713	.4
Short-term debt		33	.0		33	.0			--			--			--
Trust preferred securities (2)		280	.3			--			--			--		280	.3
Mandatorily redeemable preferred stock (3)		36	.3		34	.4			--			--		1	.9
Preferred dividends (4)		1	.1		1	.1			--			--			--
Service contract obligations		180	.5		9	.7		40	.7		43	.4		86	.7
Non-cancelable operating leases		51	.8		5	.5		19	.2		17	.7		9	.4
Fredonia combustion turbines lease (5)		71	.9		2	.3		8	.9		8	.6		52	.1
Energy purchase obligations		4,780	.5		479	.7		1,300	.1		931	.0		2,069	.7
Financial hedge obligations		(24	.4)		(8	.5)		(10	.1)		(4	.8)		(1	.0)

Total contractual cash obligations	$	7,544	.9	$	602	.2	$	1,528	.3	$	1,201	.9	$	4,212	.5

	Amount of Commitment Expiration Per Period
Commercial Commitments (Dollars in millions)	Total			2003			2004-2005			2006-2007		2008 and Thereafter

Liquidity facilities - available (6)	$	290	.9	$	209	.5	$	81	.4	$	--	$	--
Energy operations letter of credit (7)		0	.5			--		0	.5		--		--

Total commercial commitments	$	291	.4	$	209	.5	$	81	.9	$	--	$	--

(1) See note (1) above.
(2) See note (2) above.
(3) See note (3) above.
(4) See note (4) above.
(5) See note (5) above.
(6) See note (7) above.
(7) See note (9) above.

Off-Balance Sheet Arrangements
Conservation Trust. In 1995, PSE sold a stream of future electric revenues associated with $202.3 million of its investment in conservation assets in its electric general rate tariff to a grantor trust in order to obtain financing at rates superior to those otherwise available. As a result of this sale, PSE collects these revenues from its electric customers and remits them to the trust. During the three months ended June 30, 2003, PSE collected and remitted to the grantor trust $3.8 million as compared to $2.7 million for the same period in 2002. The impact of the sale of revenue was offset by reductions in conservation amortization and interest expenses. The principal amount owed by the trust to its bondholders was $11.6 million at June 30, 2003. Under Financial Accounting Standards Board Interpretation Number 46, “Consolidation of Variable Interest Entities,” PSE will begin consolidating the Conservation Trust in July 2003.

Accounts Receivable Securitization Program. In order to provide a source of liquidity for PSE at attractive cost of capital rates, in December 2002, PSE entered into a Receivables Sales Agreement with Rainier Receivables, Inc., a wholly owned subsidiary of PSE, pursuant to which PSE sold all of its utility customers accounts receivable and unbilled utility revenues to Rainier Receivables. Concurrently with entering into the Receivables Sales Agreement, Rainier Receivables entered into a Receivables Purchase Agreement with PSE and several financial institutions. The Receivables Purchase Agreement allows Rainier Receivables to sell the receivables purchased from PSE to the financial institutions. The amount of receivables sold by Rainier Receivables is not permitted to exceed $150 million at any time.
The receivables securitization facility is the functional equivalent of a secured revolving line of credit. In the event Rainier Receivables elects to sell receivables under the Receivables Purchase Agreement, Rainier Receivables is required to pay the purchasers of the receivables fees that are analogous to interest on a revolving line of credit. As receivables are collected by PSE as agent for the receivables purchasers, the outstanding amount of receivables purchased by the purchasers declines until Rainier Receivables elects to sell additional receivables to the purchasers.
The receivables securitization facility has a three year term, but is terminable by PSE and Rainier Receivables upon notice to the receivables purchasers. At June 30, 2003 there were no amounts outstanding under the accounts receivable securitization facility and the maximum receivables available for sale was $81.4 million.

Fredonia 3 and 4 Operating Lease. PSE leases two combustion turbines for its Fredonia 3 and 4 electric generation facility pursuant to a master lease that was amended for this purpose in April 2001. The lease has a term expiring in 2011, but can be canceled by PSE after three years. Payments under the lease vary with changes in the London inter-bank offered rate (LIBOR). At June 30, 2003, PSE’s outstanding balance under the lease was $60.2 million. The expected residual value under the lease is the lesser of $37.4 million or 60% of the cost of the equipment. In the event the equipment is sold to a third party upon termination of the lease and the aggregate sales proceeds are less than the unamortized value of the equipment, PSE would be required to pay the lessor contingent rent in an amount equal to the deficiency up to a maximum of 87% of the unamortized value of the equipment.

Utility Construction Program. Current utility construction expenditures for generation, transmission and distribution are designed to meet continuing customer growth and to improve efficiencies of PSE’s energy delivery systems. Construction expenditures, excluding equity Allowance for Funds Used During Construction (AFUDC), were $134.6 million for the six months ended June 30, 2003. PSE expects construction expenditures will be approximately $272 million, $325 million and $280 million in 2003, 2004 and 2005, respectively. In addition, PSE anticipates spending up to $250 million for new generating resources in 2004, subject to regulatory approval of the resources and related new revenue requirements. The purchase of any generating resource would be funded through the issuance of long-term debt and equity. PSE may arrange short-term bridge financing for the resources pending the sale of equity and long-term debt. Construction expenditure estimates are subject to periodic review and adjustment in light of changing economic, regulatory, environmental and conservation factors.

Other Additions. Other property, plant and equipment additions were $6.8 million for the six months ended June 30, 2003. Puget Energy expects InfrastruX’s capital additions to be $16.6 million in 2003. Construction expenditure estimates are subject to periodic review and adjustment in light of changing economic, regulatory, environmental, and conservation factors.

Refinancings. PSE refinanced $138.5 million of its outstanding 5.875% to 7.25% series of Pollution Control Bonds on March 11, 2003. The remaining $23.4 million of outstanding 5.875% series Pollution Control bonds was refinanced on April 1, 2003. These outstanding Pollution Control Bonds were refinanced with the proceeds from the issuance of two new series of Pollution Control Bonds: (1) $138.5 million 5.00% series and (2) $23.4 million 5.10% series. Each of these new series of Pollution Control Bonds matures on March 1, 2031.

Capital Resources
Cash From Operations. Cash generated from operations for the six month period ended June 30, 2003 was $154.5 million. During the period, $44.9 million in cash was used for AFUDC and payment of dividends. Consequently, cash available for utility construction expenditures and other capital expenditures was $109.6 million or 73.3% of the $149.5 million in construction expenditures (net of AFUDC) and other capital expenditure requirements for the period. For the same period in 2002, cash generated from operations was $436.0 million, $57.0 million of which was used for AFUDC and payment of dividends. Therefore, cash available for utility construction expenditures and other capital expenditures for the six month period ended June 30, 2002 was $379.0 million. The reduction in cash generated from operations from 2002 is primarily due to refunds reducing the PGA balance. In the six months ended June 30, 2002, PSE received $128.6 million in excess of actual gas costs from customers through the PGA mechanism compared to refunds to customers through the PGA mechanism of $69.5 million for the six months ended June 30, 2003. In addition, cash outflows increased $7.9 million in 2003 due to injection of gas into storage facilities as compared to cash inflows of $29.0 million in 2002 due to withdrawals of gas from storage facilities for a total decrease in cash flow of $36.9 million. Cash from accounts receivables and unbilled revenues decreased by $17.3 million due primarily to 9.2% colder than normal temperatures in the six months ended June 30, 2002 compared to near normal temperatures in 2003.
Puget Energy and PSE expect to continue financing the utility construction program and other capital expenditure requirements with internally generated funds and externally financed capital.

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

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

•

approximately $774.2 million of first mortgage bonds, as PSE has approximately $1.3 billion of electric and gas bondable property available for use, subject to the interest coverage ratio limitation of 2.0 times net earnings available for interest. PSE’s interest coverage ratio at June 30, 2003 was 2.7 times net earnings available for interest which would allow issuance of approximately $855.4 million of additional first mortgage bonds, at an assumed interest rate of approximately 6% on a ten-year first mortgage bond;

•	approximately $342.2 million of additional preferred stock at an assumed dividend rate of 7.75%; and

•	approximately $272.9 million of unsecured long-term debt.

Credit Ratings. Neither Puget Energy nor PSE has any rating downgrade triggers that would accelerate the maturity dates of outstanding debt. However, a downgrade in the credit ratings could adversely affect the Companies’ ability to renew existing, or obtain access to new credit facilities and could increase the cost of such facilities. For example, under PSE’s revolving credit facility, the spreads over the index and commitment fee increase as PSE’s secured long-term debt ratings decline. A downgrade in commercial paper ratings could preclude PSE’s ability to issue commercial paper under its current programs. The marketability of PSE commercial paper is currently limited by the A-3/P-2 ratings by Standard & Poor’s and Moody’s Investors Service. A further downgrade in commercial paper ratings could preclude entirely PSE’s ability to issue commercial paper. In addition, downgrades in any or a combination of PSE’s debt ratings may allow counterparties on a contract by contract basis in the wholesale electric, wholesale gas and financial derivative markets to require PSE to post a letter of credit or other collateral, make cash prepayments, obtain a guarantee agreement or provide other mutually agreeable security.
The ratings of Puget Energy and PSE as of August 7, 2003 were:

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

No ratings provided. S&P and Moody’s have placed an indicative rating of BB+ and Baa3, respectively, on senior unsecured debt were the Company to issue any pursuant to the $500 million shelf registration filed in February 2002. To date, the Company has not issued any senior unsecured debt.

No ratings provided.

Moody’s Investors Service has stated that its negative outlook is based upon uncertainty about the outcome of investigations by FERC of the Western power markets.

Shelf Registrations. In February 2002, Puget Energy and PSE filed a shelf registration statement with the Securities and Exchange Commission for the offering, on a delayed or continuous basis, of up to $500 million of:

•	common stock of Puget Energy,

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

•	unsecured debentures of PSE, and

•	trust preferred securities of Puget Sound Energy Capital Trust III.

On November 5, 2002, Puget Energy sold 5.75 million shares of common stock in a public offering. The net proceeds of approximately $114.6 million were invested in PSE to reduce its debt. On June 4, 2003, PSE issued $150 million of 3.363% Senior Notes, which have a maturity date of June 1, 2008. Proceeds were used to retire long term debt. Approximately $230 million of securities remain available for issuance under the shelf registration as of June 30, 2003.

         Liquidity Facilities and Commercial Paper. PSE’s short-term borrowings and sales of commercial paper are used to provide working capital and funding of utility construction programs.
        On December 23, 2002, PSE entered into a $250 million unsecured 364-day credit agreement with various banks and a $150 million 3-year receivables securitization program. At June 30, 2003, PSE had available $250 million in the unsecured credit agreement and $81.4 million in the receivable securitization facility, which provide credit support for outstanding commercial paper of $40 million and outstanding letters of credit of $0.5 million, effectively reducing the available borrowing capacity under the liquidity facilities to $290.9 million.
        In June 2001, InfrastruX signed a three-year credit agreement with several banks to provide up to $150 million in financing. Puget Energy is the guarantor of the line of credit. In addition, InfrastruX’s subsidiaries have an additional $29.1 million in lines of credit with various banks. Borrowings available for InfrastruX are used to fund acquisitions and working capital requirements of InfrastruX and its subsidiaries. At June 30, 2003, InfrastruX and its subsidiaries had outstanding loans of $155.4 million and letters of credit of $4.1 million, effectively reducing the available borrowing capacity under these lines of credit to $19.6 million.
        On May 27, 2003, Puget Energy entered into a $15 million, three-year credit agreement with a bank. Under the terms of the agreement, Puget Energy will pay a floating interest rate on borrowings based on the London inter-bank offered rate (LIBOR). The interest rate is set for one, two, or three month periods at the option of Puget Energy with interest due at the end of each period. Puget Energy will also pay a commitment fee on any unused portion of the credit facility.
        On May 30, 2003, Puget Energy borrowed $5 million under the credit agreement. The proceeds of the loan were invested in InfrastruX, which used the proceeds to acquire a construction services company in New Mexico.

Stock Purchase and Dividend Reinvestment Plan. Puget Energy has a stock purchase and dividend reinvestment plan pursuant to which shareholders and other interested investors may invest cash and cash dividends in shares of Puget Energy’s common stock. Since new shares of common stock may be purchased directly from Puget Energy, funds received may be used for general corporate purposes. Puget Energy issued common stock from the Stock Purchase and Dividend Reinvestment Plan of $3.9 million (176,806 shares) and $7.6 million (369,571 shares) for the three and six months ended June 30, 2003 compared to $3.3 million (165,996 shares) and $9.8 million (470,110 shares) for the same period in 2002. The decrease in the shares issued under the Stock Purchase and Dividend Reinvestment Plan from the six month period ended June 30, 2002 compared to the six month period ended June 30, 2003 was largely attributable to the reduction of the common stock dividend on May 15, 2002 to a quarterly dividend of $0.25 per share.

Common Stock Offering Programs. To provide additional financing options, Puget Energy entered into agreements on July 10, 2003 with two financial institutions under which Puget Energy may offer and sell shares of its common stock from time to time through these institutions as sales agents, or as principals. Sales of the common stock, if any, may be made by means of negotiated transactions or in transactions that may be deemed to be “at-the-market” offerings as defined in Rule 415 promulgated under the Securities Act of 1933, including in ordinary brokers’ transactions on the New York Stock Exchange at market prices. No shares have been issued under the agreements as of the filing date of this report.

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

California Independent System Operator (CAISO) Receivable. In 2001, PG&E and Southern California Edison defaulted on payment obligations owed to various energy suppliers, including the CAISO. The CAISO in turn defaulted on its payment obligations to various energy suppliers, including obligations to PSE relating to sales made by PSE into the California energy market during the fourth quarter of 2000 through the CAISO. After deducting a bad debt reserve and a transaction fee reserve totaling $41.5 million, PSE has a net receivable from the CAISO at June 30, 2003 of $24.1 million. PSE received $1.3 million in the second quarter of 2003 relating to CAISO transactions. As previously described, the March 26, 2003, FERC Order on Proposed Findings on Refund Liability in Docket EL00-95 was silent as to the stipulation regarding two PSE “non-spot-market” transactions. The total gross revenue associated with the transactions is approximately $26 million. On April 25, 2003, PSE requested clarification and/or rehearing to confirm those transactions are not subject to refund. No party has resisted PSE’s request. Based upon the order, PSE has estimated a range related to the net CAISO receivable to be between $24.1 million and $25.6 million, including interest on past due amounts.

California Refund Proceeding. On July 25, 2001, FERC ordered an evidentiary hearing (Docket No. EL00-95) to determine the amount of refunds due to California energy buyers, including the CAISO, for purchases made in the spot markets operated by the CAISO during the period October 2, 2000 through June 20, 2001.
On March 26, 2003, FERC issued an Order on Proposed Findings on Refund Liability in Docket EL00-95 that substantially adopted the recommendations made by the Administrative Law Judge on December 12, 2002, except that the Order also substantially adopts the FERC Staff gas price recommendation from the Staff’s August 2002 report. Rehearing of that Order is pending. The March 26 Order also permitted generators that wished to recover fuel costs above the amount set using the “Staff methodology” to submit their actual cost data by May 12, 2003. On May 12, 2003, PSE filed documents to support recovery of its actual fuel costs above the amount set using the “Staff methodology.” On May 21, 2003, the California parties filed a motion to reject all fuel cost adjustment filings, including the filing made by PSE.

Pacific Northwest Refund Proceeding. On June 25, 2003, FERC issued an order terminating the Pacific Northwest refund proceeding, Docket EL01-10, largely on procedural, jurisdictional and equitable grounds. Various parties filed rehearing requests on July 25, 2003. Based upon public statements by some of the refund claimants, it is likely they will ultimately appeal that order.

Orders to Show Cause. On June 25, 2003, FERC issued two show cause orders pertaining to its Western market investigations that commenced individual proceedings against many sellers. One show cause proceeding seeks to investigate approximately 26 entities that allegedly had potential “partnerships” with Enron. PSE is not named in that show cause order, though the order states additional parties may be added. The second show cause proceeding seeks to investigate approximately 55 entities that allegedly had engaged in potential “gaming” practices in the CAISO and California PX markets. PSE is one of the entities named in the “gaming” show cause order. On July 16, 2003, CAISO provided data to FERC in connection with the gaming show cause order that indicates that, under the standards adopted by FERC in the June 25 orders, CAISO’s previously reported claims against PSE as to “ricochet” transactions completely disappear. PSE believes the remaining claims (“paper trading” and “cut schedules”) pose minimum exposure for PSE. PSE is to respond to the CAISO filing on or before September 2, 2003. The two show cause orders also expressly encourage the parties to settle the cases with FERC staff. PSE expects to explore that opportunity. PSE does not believe that the orders to show cause raise new issues or concerns or will have a material adverse impact on the financial condition, results of operation or liquidity of the Company.

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

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

Washington and Oregon Class Action Cases Regarding Market Manipulation. In December 2002, PSE was named as one of more than 30 defendants in two class actions, one filed in the federal district court in Seattle and the other in Multnomah County Circuit Court in Oregon. The complaints alleged that they were brought on behalf of all retail customers in Washington and Oregon, respectively, and seek relief against the defendants (each of which is a seller of electric energy at wholesale in certain markets) for “unfair or deceptive acts”, “fraud by concealment”, negligence and for an accounting. No specific amount of damages was pled in the complaints. In May 2003, the plaintiffs in both cases filed motions for voluntary dismissal, which were granted later that same month by both courts. Although the motions expressly reserved the right to refile the complaints, no new case by those plaintiffs or law firms has named PSE.

                                                                          Other
        On March 31, 2003, PSE released for public comment its least-cost plan for meeting customers’ energy needs through a diversified mix of energy supplies. The plan was open for 30 days of public comment before review by the Washington Commission. After incorporating the comments from the Washington Commission staff, key stakeholder groups, and the public, PSE’s plan was filed with the Washington Commission on April 30, 2003 and will be revised in August 2003 to incorporate forthcoming energy-efficiency data. PSE is actively reviewing new generating resources alternatives.
        On July 31, 2002, FERC issued its Notice of Proposed Rulemaking on Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design (SMD NOPR). The SMD NOPR would have major implications for the delivery of electric energy throughout the U.S if enacted in its proposed form. Major elements of FERC’s proposal include: (a) the use of Network Access Service to replace the existing network and point-to-point services. All customers, including load-serving entities on behalf of bundled retail load, would be required to take network service under a new pro forma tariff; (b) Vertically integrated utilities would be required to retain Independent Transmission Providers to administer the new tariff and functionally operate transmission systems; (c) The formation of Regional State Advisory Committees and other regional entities to coordinate the planning, certification and siting of new transmission facilities in cooperation with states. State regulators and industry representatives have pointed out that the western North American electricity market has unique characteristics that may not readily lend itself to the Standard Market Design proposed by FERC. FERC has expressed its willingness to offer regional flexibility in its order on RTO West, Docket Nos. RT01-35-005 and RT01-35-007, issued September 18, 2002. In April 2003, FERC issued a white paper responding to concerns of state regulators regarding the impact of the SMD proposal on the western market. PSE cannot predict the outcome of the SMD NOPR or whether the ultimate resolution will have a material impact on the financial condition, results of operations or liquidity of the Company.

Item 3. Quantitative and Qualitative Disclosure About Market Risk

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

Portfolio Management. The nature of serving regulated electric customers with its wholesale portfolio of owned and contracted resources does expose the Company to some volumetric and commodity price risks within the sharing mechanism of the PCA. The Company’s energy risk management function monitors and manages these risks using analytical models and tools. The Company manages its energy supply portfolio to achieve three primary objectives:
       (i)      Ensure that physical energy supplies are available to serve retail customer requirements;
       (ii)     Manage portfolio risks to limit undesired impacts on the Company’s financial results and to stabilize                  earnings; and
       (iii)    Optimize the value of the Company’s energy supply assets.
        The portfolio is subject to major sources of variability (e.g., hydro generation, outage risk, regional economic factors, temperature-sensitive retail sales, and market prices for gas and power supplies). At certain times, these sources of variability can mitigate portfolio imbalances; at other times they can exacerbate portfolio imbalances.
        The Company’s energy risk management staff develops hedging strategies for the Company’s energy supply portfolio. The first priority is to protect against unwanted risk exposure. The second priority is to optimize excess capacity or flexibility within the wholesale portfolio. Most hedges can be implemented in ways that retain the Company’s ability to use its energy supply optimization opportunities. Still other hedges are structured similarly to insurance instruments, where PSE pays an insurance premium to protect against certain extreme conditions.
        Portfolio exposure is managed in accordance with Company polices and procedures. The Risk Management Committee, which is composed of Company officers, provides policy level and strategic direction for management of the energy portfolio. The Audit Committee of the Company’s Board of Directors has oversight of the Risk Management Committee.
        The prices of energy commodities are subject to fluctuations due to unpredictable factors including weather, generation outages and other factors which impact supply and demand. The volumetric and commodity price risk is a consequence of purchasing energy at fixed and variable prices and providing deliveries at different tariff and variable prices. Costs associated with ownership and operation of production facilities are another component of this risk. The Company may use forward delivery agreements, swaps and option contracts for the purpose of hedging commodity price risk. Without jeopardizing the security of supply within its portfolio, the Company will also engage in optimizing the portfolio. Optimization may take the form of utilizing excess capacity, shaping flexible resources to capture their highest value, utilizing transmission capacity or capitalizing on market price movement. As a result, portions of the Company’s energy portfolio are monetized through use of forward price instruments.
        The regulatory mechanisms of the PGA and the PCA mitigate the impact of commodity price volatility upon the Company. The PGA mechanism passes through to customers increases and decreases in the cost of natural gas supply. The PCA mechanism provides for a sharing of costs and benefits that are graduated over four levels of power cost variances with an overall cap of $40 million (+/-) plus 1% of the excess over the $40 million cap over the four year period ending June 30, 2006.
        Transactions that qualify as hedge transactions under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, are recorded on the balance sheet at fair value. Changes in fair value of the Company’s derivatives are recorded each period in current earnings or other comprehensive income. Short-term derivative contracts for the purchase and sale of electricity are valued based upon daily quoted prices from an independent energy brokerage service. Values for short-term and medium-term natural gas swap contracts are derived from a combination of quotes from several independent energy brokers and are updated daily. Long-term gas swap contracts 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 June 30, 2003, the Company had an after-tax net asset of approximately $15.9 million of energy contracts designated as qualifying cash flow hedges and a corresponding unrealized gain amount in other comprehensive income. The Company also had energy contracts that were marked-to-market through current earnings for the second quarter of 2003 of $0.4 million after-tax. A hypothetical 10% increase in the market prices of natural gas and electricity would increase the fair value of qualifying cash flow hedges by approximately $7.1 million after-tax and would increase current earnings for those contracts marked-to-market in earnings by an immaterial amount.

Interest Rate Risk. The Company believes its interest rate risk primarily relates to the use of short-term debt instruments, variable rate leases and long-term debt financing needed to fund capital requirements. The Company manages its interest rate risk through the issuance of mostly fixed-rate debt of various maturities. The Company does utilize bank borrowings, commercial paper and line of credit facilities to meet short-term cash requirements. These short-term obligations are commonly refinanced with fixed-rate bonds or notes when needed and when interest rates are considered favorable. The Company may enter into swap instruments to manage the interest rate risk associated with these debts and did not have any swap instruments outstanding as of June 30, 2003.

Item 4. Controls and Procedures

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

Changes in internal controls over financial reporting. There have been no significant changes in Puget Energy’s or PSE’s internal control over financial reporting during the quarter covered by this report that have materially affected, or are reasonably likely to materially affect, Puget Energy’s or Puget Sound Energy’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 June 30, 2003. The ultimate resolution of these issues in part or in the aggregate is not expected to have a material adverse impact on the financial condition, results of operations or liquidity of the Company.

Item 4. Submission of Matters to a Vote of Security Holders

Puget Energy’s annual meeting of shareholders was held on May 13, 2003. At the annual meeting, the shareholders elected three directors to hold office until the annual meeting of shareholders in 2006 or until their successors are elected and qualified. The vote was as follows:

	Number of Shares
	For	Withheld
TERM EXPIRING 2006
Douglas P. Beighle	77,926,652	2,276,315
Craig W. Cole	78,640,366	1,562,601
Tomio Moriguchi	77,983,759	2,219,208

There were no broker non-votes.

The terms of the following directors continued after the annual meeting:

        Charles W. Bingham
        Phyllis J. Campbell
        Robert Dryden
        Kenneth P. Mortimer
        Sally G. Narodick
        Stephen P. Reynolds

Item 6.

Exhibits and Reports on Form 8-K

(a)

See Exhibit Index for list of exhibits.

(b)

Reports on Form 8-K

Filed by Puget Energy & Puget Sound Energy:

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

Filed by Puget Sound Energy:

Form 8-K dated June 6, 2003, Item 5 — Other Events, related to filing Form S-3 for the issuance of $150,000,000 Senior Notes.

SIGNATURES

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

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

Date: August 8, 2003	Chief accounting officer and officer duly authorized to sign this report on behalf of each registrant

EXHIBIT INDEX

The following exhibits are filed herewith:

4.1

Pledge Agreement dated March 11, 2003 between Puget Sound Energy and Wells Fargo Bank Northwest, National Association, as Trustee (incorporated herein by reference to Exhibit 4.24 to the Company’s Post-Effective Amendment No. 1 to Registration Statement on Form S-3 dated July 11, 2003, Commission File No. 333-82940-02)

4.2

Loan Agreement dated as of March 1, 2003, between the City of Forsyth, Rosebud County, Montana and Puget Sound Energy (incorporated herein by reference to Exhibit 4.25 to the Company’s Post-Effective Amendment No.1 to Registration Statement on Form S-3, dated July 11, 2003, Commission file No. 333-82490-02).

12.1

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

12.2

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

31.1

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

31.2

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

31.3

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

31.4

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

32.1

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

32.2

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

UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549

FORM 10-Q

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Results of Operations

Capital Expenditures, Capital Resources and Liquidity

PART II OTHER INFORMATION

SIGNATURES

EXHIBIT INDEX

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549