2nd Quarter 2006 Form 10-Q

10-Q 1 f10q080306.htm 2ND QUARTER 2006 FORM 10-Q 2nd Quarter 2006 Form 10-Q

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, 2006

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

For the Transition period from ________ to _________

Commission

File Number

Exact name of registrant as specified

in its charter, state of incorporation,

address of principal executive offices,

telephone number

I.R.S.

Employer

Identification

Number

1-16305

PUGET ENERGY, INC.

A Washington Corporation

10885 NE 4^th Street, Suite 1200

Bellevue, Washington 98004-5591

(425) 454-6363

91-1969407

1-4393

PUGET SOUND ENERGY, INC.

A Washington Corporation

10885 NE 4^th Street, Suite 1200

Bellevue, Washington 98004-5591

(425) 454-6363

91-0374630

Indicate by check mark whether the registrants: (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.

Puget Energy, Inc.

Yes

/X/

/ /

Puget Sound Energy, Inc.

Yes

/X/

/ /

Indicate by check mark whether registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Puget Energy, Inc.	Large accelerated filer	/X/	Accelerated filer	/ /	Non-accelerated filer	/ /
Puget Sound Energy, Inc.	Large accelerated filer	/ /	Accelerated filer	/ /	Non-accelerated filer	/X/

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2)

Puget Energy, Inc.

Yes

/ /

/X/

Puget Sound Energy, Inc.

Yes

/ /

/X/

As of July 27, 2006, (i) the number of shares of Puget Energy, Inc. common stock outstanding was 116,241,200 ($.01 par value) and (ii) all of the outstanding shares of Puget Sound Energy, Inc. common stock were held by Puget Energy, Inc.

Table of Contents



Definitions
Filing Format

Forward Looking Statements

Part I.	Financial Information
Item 1.	Financial Statements

	Puget Energy, Inc.
	Consolidated Statements of Income - Three and Six Months Ended June 30, 2006 and 2005
	Consolidated Statements of Comprehensive Income - Three and Six Months Ended June 30, 2006 and 2005
	Consolidated Balance Sheets - June 30, 2006 and December 31, 2005
	Consolidated Statements of Cash Flows - Six Months Ended June 30, 2006 and 2005

	Puget Sound Energy, Inc.
	Consolidated Statements of Income - Three and Six Months Ended June 30, 2006 and 2005
	Consolidated Statements of Comprehensive Income - Three and Six Months Ended June 30, 2006 and 2005
	Consolidated Balance Sheets - June 30, 2006 and December 31, 2005
	Consolidated Statements of Cash Flows - Six Months Ended June 30, 2006 and 2005

	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 1A.	Risk Factors

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

Item 6.	Exhibits

Signatures

Exhibit Index

DEFINITIONS

	AFUDC	Allowance for Funds Used During Construction
	CAISO	California Independent System Operator
	FASB	Financial Accounting Standards Board
	FERC	Federal Energy Regulatory Commission
	FIN	Financial Accounting Standards Board Interpretation
	Foundation	Puget Sound Energy Foundation
	FPA	Federal Power Act
	InfrastruX	InfrastruX Group, Inc.
	kWh	Kilowatt Hour
	LIBOR	London Interbank Offered Rate
	MW	Megawatt (one MW equals one thousand kW)
	MWh	Megawatt Hour (one MWh equals one thousand kWh)
	PCA	Power Cost Adjustment
	PCORC	Power Cost Only Rate Case
	PGA	Purchased Gas Adjustment
	PSE	Puget Sound Energy, Inc.
	Puget Energy	Puget Energy, Inc.
	Tenaska	Tenaska Power Fund, L.P.
	SFAS	Statement of Financial Accounting Standards
	Washington Commission	Washington Utilities and Transportation Commission

FILING FORMAT

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

FORWARD-LOOKING STATEMENTS

Puget Energy and Puget Sound Energy (PSE) are including the following cautionary statements in this Form 10-Q to make applicable and to take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by or on behalf of Puget Energy or PSE. This report includes forward-looking statements, which are statements of expectations, beliefs, plans, objectives, assumptions of future events or performance. Words or phrases such as “anticipates,”“believes,”“estimates,”“expects,”“future,”“intends,”“plans,”“predicts,”“projects,”“will likely result,”“will continue” or similar expressions identify forward-looking statements.

Forward-looking statements involve risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed. Puget Energy’s and PSE’s expectations, beliefs and projections are expressed in good faith and are believed by Puget Energy and PSE, as applicable, to have a reasonable basis, including without limitation management’s examination of historical operating trends, data contained in records and other data available from third parties; but there can be no assurance that Puget Energy’s and PSE’s expectations, beliefs or projections will be achieved or accomplished.

In addition to other factors and matters discussed elsewhere in this report, some important factors that could cause actual results or outcomes for Puget Energy and PSE to differ materially from those discussed in forward-looking statements include:

	·		Governmental policies and regulatory actions, including those of the Federal Energy Regulatory Commission (FERC) and the Washington Utilities and Transportation Commission (Washington Commission), with respect to allowed rates of return, cost recovery, industry and rate structures, transmission and generation business structures within PSE, acquisition and disposal of assets and facilities, operation, maintenance and construction of electric generating facilities, operation of distribution and transmission facilities (gas and electric), licensing of hydroelectric operations and gas storage facilities, recovery of other capital investments, recovery of power and gas costs, recovery of regulatory assets and present or prospective wholesale and retail competition;
	·		Changes in, adoption of and compliance with laws and regulations, including environmental and endangered species laws, regulations, decisions and policies concerning the environment, natural resources, and fish and wildlife (including the Endangered Species Act);
	·		The ability to recover changes in enacted federal state or local tax laws through revenue in a timely manner;
	·		Natural disasters, such as hurricanes, earthquakes, floods, fires and landslides, which can cause temporary supply disruptions and/or price spikes in the cost of fuel and raw materials;
	·		Commodity price risks associated with procuring natural gas and power in wholesale markets that impact customer loads;
	·		Wholesale market disruption, which may result in a deterioration of market liquidity, increase the risk of counterparty default, affect the regulatory and legislative process in unpredictable ways, negatively affect wholesale energy prices and/or impede PSE’s ability to manage its energy portfolio risks and procure energy supply, affect the availability and access to capital and credit markets and/or impact delivery of energy to PSE from its suppliers;
	·		Financial difficulties of other energy companies and related events, which may affect the regulatory and legislative process in unpredictable ways and also adversely affect the availability of and access to capital and credit markets and/or impact delivery of energy to PSE from it suppliers;
	·		The effect of wholesale market structures (including, but not limited to, regional market designs or transmission organizations) or other related federal initiatives;
	·		PSE electric or gas distribution system failure, which may impact PSE’s ability to deliver energy supply to its customers;
	·		Weather, which can have a potentially serious impact on PSE’s revenues and/or impact its ability to procure adequate supplies of gas, fuel or purchased power to serve its customers and on the cost of procuring such supplies;
	·		Variable hydro conditions, which can impact streamflow and PSE’s ability to generate electricity from hydroelectric facilities;
	·		Plant outages, which can have an adverse impact on PSE’s expenses with respect to repair costs, added costs to replace energy or higher costs associated with dispatching a more expensive resource;
	·		The ability of gas or electric plant to operate as intended;
	·		The ability to renew contracts for electric and gas supply and the price of renewal;
	·		Blackouts or large curtailments of transmission systems, whether PSE’s or others’, which can affect PSE’s ability to deliver load to its customers;
	·		The ability to restart generation following a regional transmission disruption;
	·		Failure of the interstate gas pipeline delivering to PSE’s system, which may impact PSE’s ability to adequately deliver gas supply to its customers;
	·		The amount of collection, if any, of PSE’s receivables from the California Independent System Operator (CAISO) and other parties and the amount of refunds found to be due from PSE to the CAISO or other parties;
	·		Industrial, commercial and residential growth and demographic patterns in the service territories of PSE;
	·		General economic conditions in the Pacific Northwest, which might impact customer consumption or affect PSE’s accounts receivable;
	·		The loss of significant customers or changes in the business of significant customers, which may result in changes in demand for PSE’s services;
	·		The impact of acts of terrorism, flu pandemic or similar significant events;
	·		Capital market conditions, including changes in the availability of capital or interest rate fluctuations;
	·		Employee workforce factors, including strikes, work stoppages, availability of qualified employees or the loss of a key executive;
	·		The ability to obtain adequate insurance coverage and the cost of such insurance;
	·		Adequate reserves by Puget Energy for future loss of corporate guarantees related to InfrastruX sale; and
	·		The ability to maintain effective internal controls over financial reporting.

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. You are also advised to consult Item 1A-“Risk Factors” in our most recent annual report on Form 10-K and this quarterly report for updates.

PART I FINANCIAL INFORMATION

Item 1. Financial Statements

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in thousands except per share amounts)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2005			2006			2005
Operating Revenues:
Electric	$	380,980		$	345,420		$	848,403		$	765,511
Gas		192,457			162,567			599,044			483,695
Other		787			2,127			4,510			2,561
Total operating revenues		574,224			510,114			1,451,957			1,251,767
Operating Expenses:
Energy costs:
Purchased electricity		187,945			178,943			440,070			387,122
Electric generation fuel		14,292			12,894			35,876			33,342
Residential exchange		(38,670	)		(37,105	)		(95,303	)		(92,151	)
Purchased gas		118,362			98,142			385,041			299,887
Net unrealized loss (gain) on derivative instruments		(150	)		(591	)		825			(82	)
Utility operations and maintenance		83,598			83,132			170,961			158,654
Other operations and maintenance		689			558			1,544			1,299
Depreciation and amortization		64,545			59,657			128,429			117,734
Conservation amortization		7,462			5,951			15,510			11,113
Taxes other than income taxes		54,178			50,521			133,910			120,221
Income taxes		15,433			6,093			55,778			52,175
Total operating expenses		507,684			458,195			1,272,641			1,089,314
Operating income		66,540			51,919			179,316			162,453
Other income (deductions):
Charitable foundation funding		(15,000	)		--			(15,000	)		--
Other income		5,916			1,890			8,240			3,721
Income taxes		4,532			(292	)		4,547			(959	)
Interest charges:
AFUDC		3,027			2,041			5,049			3,503
Interest expense		(44,417	)		(43,568	)		(87,959	)		(84,611	)
Mandatorily redeemable securities interest expense		(23	)		(23	)		(45	)		(45	)
Income from continuing operations		20,575			11,967			94,148			84,062
Income from discontinued segment (net of tax)		32,954			1,928			51,901			909
Net income before cumulative effect of accounting change		53,529			13,895			146,049			84,971
Cumulative effect of implementation of accounting change (net of tax)		--			--			(89	)		--
Net income	$	53,529		$	13,895		$	146,138		$	84,971
Common shares outstanding weighted average (in thousands)		115,907			100,157			115,817			100,058
Diluted shares outstanding weighted average (in thousands)		116,405			100,690			116,266			100,590
Basic earnings per common share before cumulative effect of accounting change from continuing operations	$	0.18		$	0.12		$	0.81		$	0.84
Basic earnings per common share from discontinued operations		0.28			0.02			0.45			0.01
Cumulative effect from accounting change		--			--			--			--
Basic earnings per common share	$	0.46		$	0.14		$	1.26		$	0.85
Diluted earnings per common share before cumulative effect of accounting change from continuing operations	$	0.18		$	0.12			0.81		$	0.83
Diluted earnings per common share from discontinued operations		0.28			0.02			0.45			0.01
Cumulative effect from accounting change		--			--			--			--
Diluted earnings per common share	$	0.46		$	0.14		$	1.26		$	0.84

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

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in thousands)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2005			2006			2005
Net income	$	53,529		$	13,895		$	146,138		$	84,971
Other comprehensive income, net of tax at 35%:
Foreign currency translation adjustment		(311	)		(15	)		(327	)		(12	)
Minimum pension liability adjustment		145			--			145			--
Net unrealized gains (losses) on derivative instruments during the period		(4,984	)		(8,281	)		(17,914	)		10,589
Reversal of net unrealized gains (losses) on derivative instruments settled during the period		(9,926	)		6,139			(9,885	)		1,110
Settlement of cash flow hedge contracts		13,860			(22,960	)		13,860			(22,960	)
Amortization of cash flow hedge contracts to earnings		190			72			382			72
Deferral of cash flow hedges related to the power cost adjustment mechanism		696			13,539			6,252			7,976
Other comprehensive loss		(330	)		(11,506	)		(7,487	)		(3,225	)
Comprehensive income	$	53,199		$	2,389		$	138,651		$	81,746

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

PUGET ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

(Unaudited)

ASSETS

	June 30, 2006			December 31, 2005
Utility Plant: (at original cost, including construction work in progress of $339,754 and $216,513, respectively)
Electric	$	4,992,980		$	4,802,363
Gas		2,050,426			1,991,456
Common plant		451,220			439,599
Less: Accumulated depreciation and amortization		(2,678,710	)		(2,602,500	)
Net utility plant		4,815,916			4,630,918
Other property and investments		157,545			157,321
Current assets:
Cash		16,402			16,710
Restricted cash		1,049			1,047
Accounts receivable, net of allowance for doubtful accounts		217,789			294,509
Secured pledged accounts receivable		--			41,000
Unbilled revenues		79,501			160,207
Purchased gas adjustment receivable		72,973			67,335
Materials and supplies, at average cost		39,637			36,491
Fuel and gas inventory, at average cost		87,638			91,058
Unrealized gain on derivative instruments		19,880			75,037
Deferred income taxes		309			--
Prepayments and other		9,381			7,596
Current assets of discontinued operations		--			107,434
Total current assets		544,559			898,424
Other long-term assets:
Restricted cash		3,700			--
Regulatory asset for deferred income taxes		121,643			129,693
Regulatory asset for PURPA contract buyout costs		179,555			191,170
Unrealized gain on derivative instruments		16,685			28,464
Power cost adjustment mechanism		6,246			18,380
Other		524,131			388,468
Long-term assets of discontinued operations		--			167,113
Total other long-term assets		851,960			923,288
Total assets	$	6,369,980		$	6,609,951

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, 2006		December 31, 2005
Capitalization:
Common shareholders’ investment:
Common stock $0.01 par value, 250,000,000 shares authorized, 116,233,260 and 115,695,463 shares outstanding, respectively	$	1,162	$	1,157
Additional paid-in capital		1,960,972		1,948,975
Earnings reinvested in the business		157,612		69,407
Accumulated other comprehensive income, net of tax at 35%		21		7,508
Total shareholders’ equity		2,119,767		2,027,047
Redeemable securities and long-term debt:
Preferred stock subject to mandatory redemption		1,889		1,889
Junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities		37,750		237,750
Long-term debt		2,333,360		2,183,360
Total redeemable securities and long-term debt		2,372,999		2,422,999
Total capitalization		4,492,766		4,450,046
Minority interest in discontinued operations		--		6,816
Current liabilities:
Accounts payable		180,279		346,490
Short-term debt		182,597		41,000
Current maturities of long-term debt		135,000		81,000
Accrued expenses:
Taxes		58,722		112,860
Salaries and wages		19,787		15,034
Interest		30,964		31,004
Unrealized loss on derivative instruments		45,404		9,772
Deferred income taxes		--		10,968
Other		34,955		35,694
Current liabilities of discontinued operations		--		55,791
Total current liabilities		687,708		739,613
Long-term liabilities:
Deferred income taxes		723,049		738,809
Unrealized loss on derivative instruments		487		--
Other deferred credits		465,970		513,023
Long-term liabilities of discontinued operations		--		161,644
Total long-term liabilities		1,189,506		1,413,476
Total capitalization and liabilities	$	6,369,980	$	6,609,951

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

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)

(Unaudited)

	Six Months Ended June 30,
	2006			2005
Operating activities:
Net income	$	146,138		$	84,971
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		128,429			117,734
Deferred income taxes and tax credits, net		(25,138	)		(3,301	)
Net unrealized loss (gain) on derivative instruments		825			(82	)
Amortization of gas pipeline capacity assignment		(5,267	)		--
Non-cash return on regulatory assets		4,153			--
Impairment on InfrastruX investment		(7,269	)		5,110
Gain on sale of InfrastruX		(29,764	)		--
Cash collateral (paid) received from energy suppliers		(19,950	)		2,950
Increase (decrease) in residential exchange program		(7,529	)		4,377
Chelan PUD contract initiation prepayment		(89,000	)		--
Other		5,595			20,081
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue		190,636			(1,172	)
Materials and supplies		(2,229	)		(1,580	)
Fuel and gas inventory		3,420			776
Prepayments and other		(4,470	)		(15,795	)
Purchased gas adjustment receivable		(5,638	)		(13,474	)
Accounts payable		(163,262	)		(81,051	)
Taxes payable		(50,081	)		20,779
Tenaska disallowance reserve		--			(3,156	)
Accrued expenses and other		2,392			(552	)
Net cash provided by operating activities		71,991			136,615
Investing activities:
Construction and capital expenditures - excluding equity AFUDC		(310,663	)		(221,369	)
Energy efficiency expenditures		(13,846	)		(15,611	)
Refundable cash received for customer construction projects		7,739			6,137
Restricted cash		(3,703	)		527
Gross proceeds from sale of InfrastruX, net of cash disposed		263,575			--
Other		3,363			18,492
Net cash used by investing activities		(53,535	)		(211,824	)
Financing activities:
Change in short-term debt, net		148,656			163,749
Dividends paid		(51,984	)		(43,910	)
Payments to minority shareholders of InfrastruX		(10,451	)		--
Issuance of common stock		3,411			2,714
Issuance of bonds and notes		250,000			250,000
Redemption of bonds and notes		(183,358	)		(203,456	)
Redemption of trust preferred stock		(200,000	)		(42,500	)
Settlement of cash flow hedge of interest rate derivative		21,323			(35,323	)
Issuance and redemption costs of bonds and other		(2,548	)		(11,500	)
Net cash provided (used) by financing activities		(24,951	)		79,774
Net increase (decrease) in cash		(6,495	)		4,565
Cash at beginning of year		22,897			19,773
Cash at end of period	$	16,402		$	24,338
Supplemental cash flow information:
Cash payments for:
Interest (net of capitalized interest)	$	92,358		$	89,742
Income taxes		77,346			32,682

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in thousands)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2005			2006			2005
Operating revenues:
Electric	$	380,980		$	345,420		$	848,403		$	765,511
Gas		192,457			162,567			599,044			483,695
Other		787			2,127			4,510			2,561
Total operating revenues		574,224			510,114			1,451,957			1,251,767
Operating expenses:
Energy costs:
Purchased electricity		187,945			178,943			440,070			387,122
Electric generation fuel		14,292			12,894			35,876			33,342
Residential exchange		(38,670	)		(37,105	)		(95,303	)		(92,151	)
Purchased gas		118,362			98,142			385,041			299,887
Net unrealized loss (gain) on derivative instruments		(150	)		(591	)		825			(82	)
Utility operations and maintenance		83,598			83,132			170,961			158,654
Other operations and maintenance		242			241			561			500
Depreciation and amortization		64,545			59,657			128,429			117,734
Conservation amortization		7,462			5,951			15,510			11,113
Taxes other than income taxes		54,178			50,521			133,910			120,221
Income taxes		15,633			6,285			56,337			52,830
Total operating expenses		507,437			458,070			1,272,217			1,089,170
Operating income		66,787			52,044			179,740			162,597
Other income (deductions):
Other income		5,560			1,890			7,884			3,721
Income taxes		(713	)		(292	)		(698	)		(959	)
Interest charges:
AFUDC		3,027			2,041			5,049			3,503
Interest expense		(44,538	)		(43,494	)		(88,080	)		(84,469	)
Mandatorily redeemable securities interest expense		(23	)		(23	)		(45	)		(45	)
Net income before cumulative effect of accounting change		30,100			12,166			103,850			84,348
Cumulative effect of implementation of accounting change (net of tax)		--			--			(89	)		--
Net Income	$	30,100		$	12,166		$	103,939		$	84,348

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in thousands)

(Unaudited)

	Three Months ended June 30,						Six Months Ended June 30,
	2006			2005			2006			2005
Net income	$	30,100		$	12,166		$	103,939		$	84,348
Other comprehensive income, net of tax at 35%:
Minimum pension liability adjustment		145			--			145			--
Net unrealized gains (losses) on derivative instruments during the period		(4,984	)		(8,281	)		(17,914	)		10,589
Reversal of net unrealized gains (losses) on derivative instruments settled during the period		(9,926	)		6,139			(9,885	)		1,110
Settlement of cash flow hedge contracts		13,860			(22,960	)		13,860			(22,960	)
Amortization of cash flow hedge contracts to earnings		190			72			382			72
Deferral of cash flow hedges related to the power cost adjustment mechanism		696			13,539			6,252			7,976
Other comprehensive loss		(19	)		(11,491	)		(7,160	)		(3,213	)
Comprehensive income	$	30,081		$	675		$	96,779		$	81,135

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, 2006			December 31, 2005
Utility plant: (at original cost, including construction work in progress of $339,754 and $216,513, respectively)
Electric	$	4,992,980		$	4,802,363
Gas		2,050,426			1,991,456
Common plant		451,220			439,599
Less: Accumulated depreciation and amortization		(2,678,710	)		(2,602,500	)
Net utility plant		4,815,916			4,630,918
Other property and investments		157,545			157,321
Current assets:
Cash		16,351			16,709
Restricted cash		1,049			1,047
Accounts receivable, net of allowance for doubtful accounts		214,883			299,938
Secured pledged accounts receivable		--			41,000
Unbilled revenues		79,501			160,207
Purchased gas adjustment receivable		72,973			67,335
Materials and supplies, at average cost		39,637			36,491
Fuel and gas inventory, at average cost		87,638			91,058
Unrealized gain on derivative instruments		19,880			75,037
Deferred income taxes		309			--
Prepayments and other		8,808			7,023
Total current assets		541,029			795,845
Other long-term assets:
Regulatory asset for deferred income taxes		121,643			129,693
Regulatory asset for PURPA contract buyout costs		179,555			191,170
Unrealized gain on derivative instruments		16,685			28,464
Power cost adjustment mechanism		6,246			18,380
Other		523,794			388,009
Total other long-term assets		847,923			755,716
Total assets	$	6,362,413		$	6,339,800

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, 2006		December 31, 2005
Capitalization:
Common shareholder’s investment:
Common stock ($10 stated value) - 150,000,000 shares authorized, 85,903,791 shares outstanding	$	859,038	$	859,038
Additional paid-in capital		989,825		924,154
Earnings reinvested in the business		242,776		196,248
Accumulated other comprehensive income, net of tax at 35%		21		7,181
Total shareholder’s equity		2,091,660		1,986,621
Redeemable securities and long-term debt:
Preferred stock subject to mandatory redemption		1,889		1,889
Junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities		37,750		237,750
Long-term debt		2,333,360		2,183,360
Total redeemable securities and long-term debt		2,372,999		2,422,999
Total capitalization		4,464,659		4,409,620
Current liabilities:
Accounts payable		180,604		346,490
Short-term debt		209,099		41,000
Current maturities of long-term debt		135,000		81,000
Accrued expenses:
Taxes		58,686		111,900
Salaries and wages		18,749		15,034
Interest		31,086		31,004
Unrealized loss on derivative instruments		45,404		9,772
Deferred income taxes		--		10,968
Other		34,613		30,932
Total current liabilities		713,241		678,100
Long-term liabilities:
Deferred income taxes		726,894		739,162
Unrealized loss on derivative instruments		487		--
Other deferred credits		457,132		512,918
Total long-term liabilities		1,184,513		1,252,080
Total capitalization and liabilities	$	6,362,413	$	6,339,800

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)

(Unaudited)

	Six Months Ended June 30,
	2006			2005
Operating activities:
Net income	$	103,939		$	84,348
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		128,429			117,734
Deferred income taxes and tax credits, net		(11,562	)		(2,877	)
Net unrealized loss (gain) on derivative instruments		825			(82	)
Amortization of gas pipeline capacity assignment		(5,267	)		--
Non-cash return on regulatory assets		4,153			--
Cash collateral (paid) received from energy suppliers		(19,950	)		2,950
Increase (decrease) in residential exchange program		(7,529	)		4,377
Chelan PUD contract initiation prepayment		(89,000	)		--
Other		20,245			13,951
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue		206,759			1,721
Materials and supplies		(3,146	)		(1,579	)
Fuel and gas inventory		3,420			776
Prepayments and other		(1,785	)		(11,177	)
Purchased gas adjustment receivable		(5,638	)		(13,474	)
Accounts payable		(165,884	)		(79,941	)
Taxes payable		(53,214	)		17,269
Tenaska disallowance reserve		--			(3,156	)
Accrued expenses and other		7,479			(4,811	)
Net cash provided by operating activities		112,274			126,029
Investing activities:
Construction expenditures - excluding equity AFUDC		(306,387	)		(212,054	)
Energy efficiency expenditures		(13,846	)		(15,611	)
Restricted cash		(3	)		527
Refundable cash received for customer construction projects		7,739			6,137
Other		3,466			18,507
Net cash used by investing activities		(309,031	)		(202,494	)
Financing activities:
Change in short-term debt, net		168,099			159,623
Dividends paid		(57,411	)		(45,039	)
Investment from Puget Energy		62,986			2,425
Issuance of bonds and notes		250,000			250,000
Redemption of bonds and notes		(46,000	)		(200,000	)
Redemption of trust preferred stock		(200,000	)		(42,500	)
Settlement of cash flow hedge interest rate derivative		21,323			(35,323	)
Issuance and redemption cost of bonds and other		(2,598	)		(9,060	)
Net cash provided by financing activities		196,399			80,126
Net increase (decrease) in cash		(358	)		3,661
Cash at beginning of year		16,709			12,955
Cash at end of period	$	16,351		$	16,616
Supplemental cash flow information:
Cash payments for:
Interest (net of capitalized interest)	$	88,958		$	85,581
Income taxes		77,346			32,682

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 a holding company that owns Puget Sound Energy (PSE) and until May 7, 2006, InfrastruX. PSE is a public utility incorporated in the State of Washington that furnishes electric and gas services in a territory covering 6,000 square miles, primarily in the Puget Sound region.

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 owned a 90.9% interest in InfrastruX until it was sold on May 7, 2006. The results of PSE and InfrastruX are presented on a consolidated basis. The financial position and results of operations for InfrastruX are presented as discontinued operations. InfrastruX is a non-regulated utility construction service company incorporated in the State of Washington, which provides construction services to the electric and gas utility industries primarily in the Midwest, Texas, south-central and eastern United States regions. PSE’s consolidated financial statements include the accounts of PSE and its subsidiaries. Puget Energy and PSE are collectively referred to herein as “the Company.” The consolidated financial statements are presented after elimination of all significant intercompany items and transactions. Certain amounts previously reported have been reclassified to conform with current year presentations with no effect on total equity or net income.

The consolidated financial statements contained in this Form 10-Q are unaudited. In the respective opinions of the management of Puget Energy and PSE, all adjustments necessary for a fair statement 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, 2005. With the treatment of InfrastruX as discontinued operations, Puget Energy has one reportable segment.

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

(2)

Discontinued Operations and Corporate Guarantees (Puget Energy Only)

On May 7, 2006, Puget Energy sold InfrastruX to an affiliate of Tenaska Power Fund, L.P. (Tenaska) for $275 million before taking into account cash on hand at May 7, 2006 of $11.4 million for a net sale price of $263.6 million. After repayment of debt, adjustments for working capital, transaction costs and distributions to minority interests, Puget Energy received after-tax cash proceeds of approximately $95.9 million for its 90.9% interest in InfrastruX in the second quarter 2006. The sale resulted in an after-tax gain of $29.8 million for the three months ended June 30, 2006. Puget Energy accounted for InfrastruX as a discontinued operation under SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” in 2005 and 2006.

Under the terms of the sale agreement, Puget Energy is obligated for certain representations and warranties made by InfrastruX concerning its business. Puget Energy obtained a representation and warranty insurance policy and deposited $3.7 million into an escrow account to serve as retention under the policy. As of June 30, 2006, long-term restricted cash in the amount of $3.7 million is included in the accompanying balance sheets; that amount represents management’s estimate of the aggregate fair value of the amount potentially payable under those representations and warranties and is Puget Energy’s maximum exposure. The obligation expires May 7, 2008. Should Tenaska make any claims against Puget Energy, payment for the claims will be made from the escrow account, and total payments are limited to $3.7 million. Puget Energy also agreed to indemnify Tenaska for certain potential future losses related to one of InfrastruX’s subsidiary companies. Under the indemnity agreement, Puget Energy is liable for certain costs with the maximum amount of loss not to exceed $15.0 million. As of June 30, 2006, a liability in the amount of $5.0 million is included in the accompanying balance sheets; that amount represents Puget Energy’s estimate of the fair value of the amount potentially payable using a probability-weighted approach to a range of future cash flows. The obligation expires May 7, 2011. Tenaska and Puget Energy have also negotiated the terms of an environmental guaranty as part of the sale agreement. Under the terms of the agreement, Tenaska will be responsible for the first $0.1 million of environmental claims, Tenaska and Puget Energy will share the next $6.4 million equally and Puget Energy will be responsible for the next $3.5 million. Based on a review of a third-party environmental report, Puget Energy believes it will not have a future loss in connection with the environmental guarantee.

For the three and six months ended June 30, 2006, Puget Energy reported InfrastruX related income from discontinued operations (net of taxes and minority interest), including gain on sale, of $33.0 million and $51.9 million, respectively, compared to $1.9 million and $0.9 million (net of taxes and minority interest) for the three and six months ended June 30, 2005. Puget Energy’s income from discontinued operations for the six months ended June 30, 2006 includes $7.3 million related to the reversal of a carrying value adjustment recorded in 2005.

	Three Months Ended June 30,						Six Months Ended June 30,
(Dollars in thousands)	2006			2005			2006			2005
Revenues	$	46,504		$	97,307		$	138,573		$	174,998
Operating expenses (including interest expense)		(40,735	)		(85,544	)		(128,634	)		(163,260	)
Pre-tax income		5,769			11,763			9,939			11,738
Income tax expense		(2,260	)		(4,028	)		(3,516	)		(3,903	)
Puget Energy carrying value adjustment of InfrastruX		--			(5,110	)		7,269			(5,110	)
Puget Energy cost of sale related to InfrastruX, net of tax		--			--			(937	)		(1,116	)
Puget Energy deferred tax basis adjustment of InfrastruX		--			--			9,966			--
Gain on sale, net of tax		29,764			--			29,764			--
Minority interest in income of discontinued operations		(319	)		(697	)		(584	)		(700	)
Income from discontinued operations	$	32,954		$	1,928		$	51,901		$	909

In accordance with SFAS No. 144, InfrastruX discontinued depreciation and amortization of its assets effective February 8, 2005. This discontinuation of depreciation and amortization resulted in $1.9 million ($1.3 million after-tax) and $4.7 million ($2.9 million after-tax) lower depreciation and amortization expense than otherwise would have been recorded as continuing operations for the three months ended June 30, 2006 and 2005, respectively. Depreciation and amortization was $6.7 million ($4.3 million after-tax) and $7.3 million ($4.5 million after-tax) lower than otherwise would have been recorded as continuing operations for the six months ended June 30, 2006 and 2005, respectively.

Puget Energy’s balance sheet at June 30, 2006 does not include InfrastruX assets and liabilities as a result of the disposition in May 2006. InfrastruX’s summarized assets and liabilities, including intercompany balances eliminated in consolidation, at December 31, 2005 were:


(Dollars in thousands)	December 31, 2005
Assets:
Cash	$	6,187
Accounts receivable		78,842
Other current assets		22,405
Total current assets		107,434
Goodwill		43,886
Intangibles		14,443
Non-utility property and other		108,784
Total long-term assets		167,113
Total assets	$	274,547

Liabilities:
Accounts payable	$	9,178
Short-term debt		3,809
Current maturities of long-term debt		6,477
Other current liabilities		36,327
Total current liabilities		55,791
Deferred income taxes		24,645
Long-term debt		120,013
Other deferred credits		16,986
Total long-term liabilities		161,644
Total liabilities	$	217,435

(3)

Earnings per Common Share (Puget Energy Only)

Puget Energy’s basic earnings per common share have been computed based on weighted average common shares outstanding of 115,907,000 and 115,817,000 for the three and six months ended June 30, 2006, respectively, and 100,157,000 and 100,058,000 for the three and six months ended June 30, 2005, respectively.

Puget Energy’s diluted earnings per common share have been computed based on weighted average common shares outstanding of 116,405,000 and 116,266,000 for the three and six months ended June 30, 2006, respectively, and 100,690,000 and 100,590,000 for the three and six months ended June 30, 2005, respectively. These shares include the dilutive effect of securities related to employee and director equity plans.

(4)

Accounting for Derivative Instruments and Hedging Activities

SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138 and SFAS No. 149, requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair value. The Company enters into both physical and financial contracts to manage its energy resource portfolio and interest rate exposure including forward physical and financial contracts, option contracts and swaps. The majority of these contracts qualify for the normal purchase normal sale (NPNS) exception to derivative accounting rules if they meet certain criteria. NPNS applies if the counterparty is creditworthy and has energy resources within the western region to allow for physical delivery of the energy, and if the transaction is within PSE’s forecasted load requirements. Those contracts that do not meet NPNS exception or cash flow hedge criteria are marked-to-market to current earnings in the income statement, subject to deferral under SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” for energy related derivatives due to the Power Cost Adjustment (PCA) mechanism and Purchased Gas Adjustment (PGA) Mechanism.

The nature of serving regulated electric customers with its wholesale portfolio of owned and contracted electric generation resources exposes the Company and its customers to some volumetric and commodity price risks within the sharing mechanism of the PCA. The Company’s energy risk portfolio management function monitors and manages these risks using analytical models and tools. The Company is not engaged in the business of assuming risk for the purpose of realizing speculative trading revenues. Therefore, wholesale market transactions are focused on balancing the Company’s energy portfolio, reducing costs and risks where feasible, and reducing volatility in wholesale costs and margin in the portfolio. In order to manage risks effectively, the Company enters into physical and financial transactions which are appropriate for the service territory of the Company and are relevant to its regulated electric and gas portfolios.

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

At June 30, 2006, the Company was subject to a range of netting provisions, including both stand alone agreements and the provisions associated with the Western Systems Power Pool agreement, of which many energy suppliers in the western United States are a part.

During the three months ended June 30, 2006, the Company recorded an increase in earnings for the change in the market value of derivative instruments not meeting NPNS nor cash flow hedge criteria of approximately $0.2 million compared to an increase in earnings of approximately $0.6 million for the three months ended June 30, 2005. At June 30, 2006, the Company had a net unrealized gain recorded in other comprehensive income of $15.4 million after-tax related to energy and financial contracts which meet the criteria for designation as cash flow hedges under SFAS No. 133. At June 30, 2006, PSE had a net short-term liability of $0.8 million related to non-cash flow hedges; as well as a net short-term asset of $7.5 million and a net long-term asset of $16.2 million related to energy contracts designated as cash flow hedges that represent forward financial purchases of gas supply for electric generation from PSE-owned electric plants in future periods. If it is determined that it is uneconomical to run the plants in the future period, the hedging relationship is ended and the cash flow hedge is de-designated and any unrealized gains and losses are recorded in the income statement. Gains and losses when these de-designated cash flow hedges are settled are recognized in energy costs and are included as part of the PCA mechanism.

During the six months ended June 30, 2006, the Company recorded a decrease in earnings for the change in the market value of derivative instruments not meeting cash flow hedge criteria of approximately $0.8 million compared to an increase in earnings of approximately $0.1 million for the six months ended June 30, 2005.

At June 30, 2006, the Company also has a net short-term liability of approximately $32.3 million related to the cash flow hedge of gas contracts to serve natural gas customers. All mark-to-market adjustments relating to the natural gas business have been reclassified to a deferred account in accordance with SFAS No. 71 due to the PGA mechanism. The PGA mechanism passes increases and decreases in the cost of natural gas supply to customers. As the gains and losses on the cash flow hedges are realized in future periods, they will be recorded as gas costs under the PGA mechanism.

In the second quarter 2006, the Company settled its two forward starting interest rate swap contracts originating in May 2005. The purpose of the forward starting swap contracts was to hedge interest rate volatility for a debt offering of $200 million that was completed on June 30, 2006. Since interest rates increased related to the hedged debt from the date of issuance of the forward starting swap contracts, PSE received $21.3 million from the counterparties when the contracts were settled. The forward starting swap contracts were designated and documented under SFAS No. 133 criteria as cash flow hedges, with all changes in market value for each reporting period presented net of tax in other comprehensive income. In the second quarter 2006, the settlement of these instruments resulted in a gain of $13.9 million after-tax, which was recorded in other comprehensive income. In accordance with SFAS No. 133, the gain will be amortized out of other comprehensive income to current earnings as a decrease to interest expense over the life of the new debt issued at an annual amount of approximately $0.7 million pre-tax. The ending balance in other comprehensive income related to the forward starting swaps and previously settled treasury lock contracts at June 30, 2006 was a loss of $8.3 million after-tax and accumulated amortization.

(5)

Stock Compensation

Prior to 2006, the Company had various stock-based compensation plans which were accounted for according to Accounting Principles Board (APB) No. 25, “Accounting for Stock Issued to Employees,” and related interpretations as allowed by SFAS No. 123, “Accounting for Stock-Based Compensation.” In 2003, the Company adopted the fair value based accounting of SFAS No. 123 using the prospective method under the guidance of SFAS No. 148, “Accounting for Stock-Based Compensation - Transition and Disclosure.” The Company applied SFAS No. 123 accounting to stock compensation awards granted subsequent to January 1, 2003, while grants prior to 2003 continued to be accounted for using the intrinsic value method of APB No. 25. Effective January 1, 2006, the Company adopted the fair value recognition provisions of SFAS No. 123R, “Share-Based Payment,” using the modified-prospective transition method. Under that transition method, compensation cost recognized in 2006 includes: (a) compensation cost for all share-based payments granted prior to, but not yet vested as of January 1, 2006, based on the grant date fair value estimated in accordance with the original provisions of SFAS No. 123, and (b) compensation cost for all share-based payments granted subsequent to January 1, 2006, based on the grant-date fair value estimated in accordance with the provisions of SFAS No. 123R. Results for prior periods have not been restated, as provided for under the modified-prospective method.

The adoption of SFAS No. 123R resulted in a cumulative benefit from an accounting change of $0.1 million, net of tax, for the quarter ended March 31, 2006. The cumulative effect adjustment is the result of the inclusion of estimated forfeitures occurring before award vesting dates in the computation of compensation expense for unvested awards.

As a result of adopting SFAS No. 123R on January 1, 2006, the Company’s income before income taxes and net income from continuing operations for the six months ended June 30, 2006, is $0.1 million and $0.1 million higher, respectively, than if it had continued to account for share-based compensation under SFAS No. 123 due to the inclusion of estimated forfeitures in compensation cost. There is no difference between basic and diluted earnings per share for income from continuing operations for the three and six months ended June 30, 2006 under SFAS No. 123R as compared to earlier methods.

Had Puget Energy applied the fair value method of accounting specified by SFAS No. 123 for all grants at their grant date rather than prospectively implementing SFAS No. 123, net income and earnings per share would have been as follows:

(Dollars in thousands, except per share amounts)	Three Months Ended June 30, 2005			Six Months Ended June 30, 2005
Net income, as reported	$	13,895		$	84,971
Add: Total stock-based employee compensation expense included in net income, net of tax		1,069			1,805
Less: Total stock-based employee compensation expense per the fair value method of SFAS No. 123, net of tax		(989	)		(1,899	)
Pro forma net income	$	13,975		$	84,877

Earnings per share:
Basic per common share as reported	$	0.14		$	0.85
Diluted per common share as reported		0.14			0.84
Basic per common share pro forma	$	0.14		$	0.85
Diluted per common share pro forma		0.14			0.84

The Company’s Long-Term Incentive Plan (LTI Plan), established in 1995 after approval by shareholders, encompasses many of the awards granted to employees. The plan was amended and restated in 2005, and approved by shareholders. The LTI Plan applies to officers and key employees of the Company and awards granted under this plan include stock awards, performance awards or other stock-based awards as defined by the plan. Any shares awarded are either purchased on the open market or are a new issuance. The 2006 cycle included a grant of restricted stock, which was added to reduce the volatility of the plan. Beginning with the 2004 share grants, plan participants meeting the Company’s stock ownership guidelines can elect to be paid up to 50% of the share award in cash. The maximum number of shares that may be purchased or issued as new shares for the LTI Plan is 4,200,000.

Performance Share Grants

The Company generally awards performance share grants annually under the LTI Plan. These are granted to key employees and vest at the end of three years for grants made in 2004, 2005 and 2006. Grants made prior to 2004 vest in four years. The number of shares awarded and expense recorded depends on Puget Energy’s performance as compared to other companies and service quality indices for customer service. Compensation expense related to performance share grants was $(0.6) million and $(1.4) million for the three months ended June 30, 2006 and 2005, respectively, and $1.3 million and $2.0 million for the six months ended June 30, 2006 and 2005, respectively. The weighted average fair value per share of the performance awards granted for the 2006, 2005, 2004 and 2003 cycles was $21.40, $21.19, $19.70, and $16.93, respectively. There were a total of 151,815 performance awards granted for the 2006 cycle of which the company estimates a forfeiture rate of 10.1%, or 15,333 awards based on historical forfeitures. There were a total of 251,680 performance awards granted for the 2005 cycle of which the Company estimated a forfeiture rate of 11.8%, or 29,698, awards based on historical forfeitures. As of June 30, 2006, there were four active grant cycles for a total of 859,063 grants outstanding. As of December 31, 2005, there were four active grant cycles for a total of 907,983 share grants outstanding. As of June 30, 2006, there was $4.3 million of total unrecognized compensation cost, net of forfeitures, related to nonvested performance share grants. That cost is expected to be recognized over a weighted-average period of two years. During the three and six months ended June 30, 2006, 4,880 and 47,772 performance shares, respectively, were forfeited. No performance shares vested during the three or six months ended June 30, 2006 and 2005. The fair value of the 2006 performance share grants takes into consideration the historical performance of the performance share grants and prospective analysis using the Capital Asset Pricing Model and expected EPS growth rates. Shares granted prior to 2006 were valued using the Black-Scholes option pricing model.

Measurement of Performance Share Grants

The portion of the performance share grants that can be paid in cash is classified and accounted for as a liability under SFAS No. 123R. As a result, the expense recognized over the performance period for a portion of the performance share grants will equal the fair value (i.e. cash value) of the award as of the last day of the performance period times the number of awards that are earned. Furthermore, SFAS No. 123R requires that the quarterly expense recognized during the performance period is based on the fair value of the performance share grants as of the end of the most recent quarter. Prior to the end of the performance period, compensation costs for the liability portion of performance share grants are based on the awards’ most recent quarterly fair values and the number of months of service rendered during the performance period. The fair value of the performance share grants is based on the closing price of the Company’s common stock on the date of measurement.

Stock Options

In 2002, Puget Energy’s Board of Directors granted 40,000 stock options under the LTI Plan and an additional 260,000 options outside of the LTI Plan (for a total of 300,000 non-qualified stock options) to the Chairman, President and Chief Executive Officer. These options can be exercised at the grant date market price of $22.51 per share and vest annually over four and five years although the options would become fully vested upon a change of control of the Company or an employment termination without cause. The options expire 10 years from the grant date and have a remaining contractual term of approximately 6 years. All 300,000 options remained outstanding at June 30, 2006, with 270,000 options exercisable. There is no aggregate intrinsic value of options vested (or expected to vest) or options currently exercisable at June 30, 2006. At June 30, 2005, 202,500 options were exercisable. The fair value of the options at the grant date was $3.33 per share. Compensation expense related to stock options was immaterial to the financial statements for the three and six months ended June 30, 2006. As of June 30, 2006, there was an immaterial amount of total unrecognized compensation cost related to nonvested stock options which will be recognized in 2006. The total fair value of stock options vested during the six months ended June 30, 2006 and 2005, was $0.2 million and $0.2 million, respectively. The fair value of the stock option award was estimated on the date of grant using the Black-Scholes option valuation model.

Restricted Stock

In 2006, 2005, 2004 and 2003, the Company granted 107,181 shares, 50,000 shares, 40,000 shares and 11,000 shares, respectively, of restricted stock under the LTI Plan to be purchased on the open market or as a new issuance. During the six months ended June 30, 2006, 107,181 shares of restricted stock were granted as part of the 2006 LTIP cycle. The shares vest 15% on January 1, 2007, 25% vest on January 1, 2008, and the remaining 60% vest on January 1, 2009 based upon a performance and service condition. Under the 2005 grant, 40,000 shares vest in one installment on the date of the 2008 Annual Shareholders’ Meeting based upon performance criteria and the remaining 10,000 shares vest equally over three years. The 2004 grant vests 8,000 shares in three years and the remaining 32,000 shares in four years. For the 2003 grant, 1,000 vested in 2003 with the remaining shares vesting evenly over the following five years. At June 30, 2006, there were 212,598 total shares of nonvested restricted stock and the weighted average grant date fair value of these shares was $22.02. Compensation expense related to the restricted shares, including the restricted shares granted as part of the 2006 LTIP cycle, was $0.5 million and $0.2 million for the three months ended June 30, 2006 and 2005, respectively, and $1.0 million and $0.3 million for the six months ended June 30, 2006 and 2005, respectively. Dividends are paid on all outstanding shares of restricted stock and are accounted for as a Puget Energy common stock dividend, not as compensation expense. The weighted average grant date fair value for all outstanding shares of restricted stock granted in 2006 and 2005 was $21.32 and $21.86, respectively. As of June 30, 2006, there was $2.8 million of total unrecognized compensation cost related to nonvested restricted stock. That cost is expected to be recognized over a weighted-average period of 2.1 years. No restricted stock vested and 583 shares were forfeited during the three and six months ended June 30, 2006. No restricted stock vested or was forfeited during the three and six months ended June 30, 2005. The fair value of the restricted stock is based on the closing price of the Company’s common stock on the date of grant.

Restricted Stock Units

In 2004, the Company granted 10,000 restricted stock units outside of the LTI Plan but subject to the terms and conditions of the plan. The units vest 2,000 shares in three years and the remaining 8,000 shares in four years. At June 30, 2006, there were 3,573 total shares of nonvested restricted stock units and the weighted average fair value of these units was $21.48. There were no restricted stock units granted or forfeited during the three and six months ended June 30, 2006 and 2005. There were 643 restricted stock units accrued during the three months ended June 30, 2006 and 1,285 restricted stock units accrued during the six months ended June 30, 2006. The restricted stock units will be settled in cash when they become vested at the end of each cycle. Dividends are paid on the outstanding stock units and are accounted for as compensation expense. Compensation expense related to the restricted stock units agreement was immaterial for the three and six months ended June 30, 2006 and 2005. The weighted average grant date fair value for the restricted stock units was $23.55. As of June 30, 2006, there was $0.1 million of total unrecognized compensation cost related to nonvested restricted stock units. That cost is expected to be recognized over a weighted-average period of 1.8 years. The fair value of the restricted stock units is based on the closing price of the Company’s common stock at each reporting period.

Retirement Equivalent Stock

The Company has a retirement equivalent stock agreement under which in lieu of participating in the Company’s executive supplemental retirement plan, the Chairman, President and Chief Executive Officer is granted performance-based stock equivalents in January of each year, which are deferred under the Company’s deferred compensation plan. In 2006, 2005, 2004 and 2003, the Company awarded 8,218, 6,063, 6,469 and 4,319, shares, respectively, which vest over a period from January 1, 2002 to May 2008 at 15% per year for the first six years and the remaining 10% in the seventh year. At June 30, 2006 there were 6,744 total shares of nonvested retirement equivalent stock units and the weighted average grant date fair value of these units was $22.71. During the six months ended June 30, 2006, 8,218 retirement equivalent stock units were granted. Dividends are paid on the stock equivalents accumulated in the deferred compensation account in the form of Puget Energy common stock, which is added to the deferred compensation account. Compensation expense related to the retirement equivalent stock agreement was immaterial to the financial statements. The weighted average grant date fair value for the retirement equivalent stock was $20.42, $24.70, $23.77 and $22.05 for 2006, 2005, 2004 and 2003, respectively. As of June 30, 2006, there was an immaterial amount of unrecognized compensation cost related to nonvested retirement equivalent stock units. That cost is expected to be recognized over a weighted-average period of 1.9 years. There were 778 retirement equivalent stock units that vested during the three months ended June 30, 2006 and 6,487 retirement equivalent stock units that vested during the six months ended June 30, 2006. No retirement equivalent stock units were forfeited during the quarter ended June 30, 2006. The fair value of the restricted stock is based on the closing price of the Company’s common stock on the date of grant.

Employee Stock Purchase Plan

The Company has a shareholder-approved Employee Stock Purchase Plan (ESPP) open to all employees. Offerings occur at six-month intervals at the end of which the participating employees receive shares for 85% of the lower of the stock’s fair market price at the beginning or the end of the six-month period. A maximum of 500,000 shares may be sold to employees under the plan through May 2007. At June 30, 2006, 117,393 shares could still be sold to employees under the plan. Under the SFAS No. 123 accounting that the Company adopted in 2003 and under SFAS No. 123R, ESPP is considered to be compensation expense and the amount is immaterial to the financial statements. New shares issued for the Employee Stock Purchase Plan were 31,421 and 23,048 for the six months ended June 30, 2006 and 2005, respectively. Dividends are not paid on ESPP shares until they are purchased by employees and thus are accounted for as dividends, not compensation expense.

Non-Employee Director Stock Plan

The Company has a director stock plan approved by shareholders in 1997 and effective beginning in 1998, for all non-employee directors of Puget Energy and PSE. The plan was amended and restated in 2005 and approved by shareholders in 2005. Under the plan, which has a term through December 31, 2015, non-employee directors receive a portion of their quarterly retainer fees in Puget Energy stock except that 100% of quarterly retainers are paid in Puget Energy stock until the director holds a number of shares equal in value to two years of their retainer fees. Directors may optionally receive their entire retainer in Puget Energy stock. The compensation expense related to the director stock plan was $0.1 million and $0.1 million for the three months ended June 30, 2006 and 2005, respectively, and $0.2 million and $0.2 million for the six months ended June 30, 2006, respectively. The Company issues new shares or purchases stock for this plan on the open market up to a maximum of 350,000 shares. As of June 30, 2006, 32,086 shares had been issued or purchased for the director stock plan and 83,361 deferred, for a total of 115,447 shares. As of June 30, 2005, the number of shares that had been purchased for the director stock plan was 21,033 and 70,425 deferred, for a total of 91,458 shares.

Option Model Assumptions

The Company used the Black-Scholes option pricing model to determine the fair value of certain stock-based awards to employees. The following assumptions were used for awards outstanding in 2006 and 2005.

Stock issuance cycle	2006			2005			2004			2003			2002
Stock options
Risk-free interest rate		*			*			*			*			4.32	%
Expected lives - years		*			*			*			*			5.0
Expected stock volatility		*			*			*			*			22.82	%
Dividend yield		*			*			*			*			5.00	%
Performance awards
Risk-free interest rate		**			2.50	%		2.59	%		2.35	%		*
Expected lives - years		3.0			3.0			3.0			4.0			*
Expected stock volatility		**			15.10	%		22.24	%		23.85	%		*
Dividend yield		*			4.18	%		4.45	%		4.86	%		*
Employee Stock Purchase Plan
Risk-free interest rate		4.07	%		2.68	%		1.28	%		1.07	%		*
Expected lives - years		0.5			0.5			0.5			0.5			*
Expected stock volatility		13.03	%		13.98	%		9.89	%		19.47	%		*
Dividend yield		4.77	%		4.17	%		4.42	%		4.39	%		*

*		Not applicable
**		Fair value is determined by end of period market value.

The expected lives of the securities represents the estimated period of time until exercise and is based on the vesting period of the award and the historical exercise experience of similar awards. All participants were assumed to have similar exercise behavior. Expected volatility is based on historical volatility over the approximate expected term of the option.

(6)

Retirement Benefits

The following summarizes the net periodic benefit cost for the three months ended June 30:

	Pension Benefits						Other Benefits
(Dollars in thousands)	2006			2005			2006			2005
Service cost	$	3,061		$	2,761		$	85		$	69
Interest cost		6,163			5,979			358			279
Expected return on plan assets		(9,434	)		(9,451	)		(182	)		(220	)
Amortization of prior service cost		586			717			134			117
Recognized net actuarial (gain) loss		1,246			910			(127	)		(295	)
Amortization of transition (asset) obligation		--			(41	)		105			104
Net periodic benefit cost	$	1,622		$	875		$	373		$	54

The following summarizes the net periodic benefit cost for the six months ended June 30:

	Pension Benefits						Other Benefits
(Dollars in thousands)	2006			2005			2006			2005
Service cost	$	6,122		$	5,775		$	171		$	152
Interest cost		12,329			11,928			716			698
Expected return on plan assets		(18,869	)		(18,964	)		(363	)		(439	)
Amortization of prior service cost		1,171			1,433			267			233
Recognized net actuarial (gain) loss		2,499			1,677			(254	)		(320	)
Amortization of transition (asset) obligation		--			(82	)		209			209
Net periodic benefit cost	$	3,252		$	1,767		$	746		$	533

The Company previously disclosed in its financial statements for the year ended December 31, 2005 that it expected contributions by the Company to fund the pension and other benefits plans for the year ended December 31, 2006 to be $2.1 million and $1.0 million, respectively. During the three and six months ended June 30, 2006, the actual cash contributions to the pension plans were $1.6 million and $2.1 million, respectively. Based on this activity, the Company anticipates contributing an additional $1.0 million to the Company’s pension plan in 2006. The full amount of the pension plan funding for 2006 is for the Company’s non-qualified supplemental retirement plan.

During the three and six months ended June 30, 2006, actual other post-retirement medical benefit plan contributions were $0.2 million and $0.6 million, respectively, and the Company expects to make additional contributions of $0.1 million for a total of $0.7 in 2006.

On March 31, 2006, Financial Accounting Standards Board (FASB) issued a Proposed Statement of Financial Accounting Standard, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.” The proposed statement would require the Company to report the overfunded or underfunded status of defined benefit postretirement plans in the Company’s consolidated balance sheet. An overfunded status would result in the recognition of an asset and an underfunded status would result in the recognition of a liability. This amount is to be measured as the difference between the fair value of plan assets and the projected benefit obligation. At December 31, 2005, the combined fair value of plan assets and projected benefit obligation for the Company’s defined benefit pension and the retiree medical and life plans were $481 million and $439 million, respectively. Any adjustment required to recognize an asset or liability upon adoption of the standard, as currently proposed, would result in a charge or benefit to Accumulated Other Comprehensive Income. The Company is currently evaluating what impact the application of the proposed standard will have on its operations. FASB indicated that it expects to issue a final statement by September 2006 and that the statement would be effective for fiscal years ending after December 15, 2006, which will be the year ended December 31, 2006, for the Company. On July 12, 2006, FASB affirmed the effective date of the proposed standard for fiscal years ending after December 15, 2006.

(7)

Regulatory and Other

On June 28, 2006, the Washington Commission approved a 5.9%, or $45.3 million, power cost only rate case (PCORC) increase in electric rates for the period July 1, 2006 through December 31, 2006. The increase allows PSE to recover higher projected costs of power caused primarily by higher market prices for natural gas used as fuel for electric generators. The rate increase will not appreciatively impact PSE’s income. The annualized basis of the PCORC rate increase when applied to the general rate case test year is $96.1 million. Primarily as a result of this order, PSE reduced its pending electric general tariff increase from $140.9 million to $42.9 million, or 2.5%, on an annualized basis. Additionally, PSE has requested approval of a new tariff in its original general rate case filing to recover increases in electric transmission and distribution depreciation costs incurred between general rate cases of $7.9 million. The resolution of the general rate is expected by the end of 2006.

On July 10, 2006, PSE reduced its gas general rate increase request filed on February 15, 2006 from $40.4 million to $39.2 million, or 4.2%, on an annual basis with the Washington Commission. PSE also has requested approval of a new depreciation tracker in its original gas general rate case filing to recover increase in gas distribution depreciation costs incurred between general rate cases of $10.9 million. In addition, a gas decoupling mechanism was requested and does not have an impact on the current rate increase; however, it is designed to stabilize revenue changes due to load variations between regulatory filings. The resolution of the general rate case is expected by the end of 2006.

PSE leases the Whitehorn power generating facility under a noncancelable operating lease expiring in February 2009 and received notice of alleged default for the non-performance of certain covenants from the lessor. PSE immediately investigated the matter and provided notice that it disputed the allegations. The facility consists of two dual-fuel combustion turbine engines with 147 MW net capacity, which are operated for peak load conditions, emergencies, and to maintain reliability of service during periods of adverse water or weather conditions. The notice of default included the threat of eviction and recovery of all damages should PSE fail to cure the alleged default and assign governmental permits and licenses associated with the facility to the lessor. PSE subsequently agreed to reimburse the lessor for its legal costs and expenses incurred in connection with the default and the lessor has four times agreed to suspend the notice of default for a one-month period to allow the parties to further investigate the matter and negotiate possible solutions. The current suspension period runs through August 31, 2006. PSE is seeking resolution of the matter, which may include the modification of the lease or the purchase of the project. If PSE cannot negotiate reasonable terms to settle the dispute, the amount of the ultimate impact upon the Company, if any, cannot be predicted at this time.

On June 30, 2006, PSE redeemed for $200 million all of its outstanding shares of the 8.40% Capital Trust Preferred Securities (classified as Junior Subordinated Debentures of the Corporation Payable to a Subsidiary Trust Holding Mandatorily Redeemable Preferred Securities on the balance sheet) at $25 par value per share plus accrued interest to the redemption date.

On June 30, 2006, PSE completed the issuance of $250 million of senior secured notes at a rate of 6.724%, which are due on June 15, 2036. The net proceeds from the issuance of the senior notes of approximately $247.8 million were used to redeem $200 million of 8.40% Capital Trust Preferred Securities, which were redeemed at par on June 30, 2006, and to repay a portion of PSE’s short-term debt. The short-term debt was incurred to repay $46 million of 8.06% senior notes that matured June 19, 2006. The yield to maturity of the $250 million senior secured notes was 6.17% after the settlement of two forward starting swap interest rate contracts.

PSE has contracted to purchase a portion of the output from the Rocky Reach and Rock Island hydroelectric generating facilities located on the mid-Columbia River owned by Chelan County PUD (Chelan). On February 3, 2006, PSE and Chelan entered into a new Power Sales Agreement and a related Transmission Agreement for 25% of the output of the Rocky Reach and Rock Island facilities in exchange for PSE paying 25% of the operating costs of the facilities. PSE’s share of the output represents approximately 487 MW of capacity and 243 average MW of energy. The agreements terminate in 2031 and provide that PSE will begin to receive power upon expiration of PSE’s existing long-term contracts with Chelan for the Rocky Reach and Rock Island output (expiring in 2011 and 2012, respectively). FERC granted approval of the agreement on March 28, 2006, and PSE made a non-refundable capacity reservation payment of $89 million on April 26, 2006 to Chelan under the terms of the agreement. PSE believes that the new agreements with Chelan will lower its overall power costs during the 20-year contract period compared to other available alternatives, secure critical operational flexibility, reduce PSE’s projected long-term energy and capacity deficit and continue PSE’s long-term relationship with the public utility district. PSE filed for an accounting order from the Washington Commission in April 2006 for approval to recognize such payments as a regulatory asset with accrual of carrying costs at the Company’s net of tax rate of return. On April 26, 2006, the Washington Commission approved the accounting petition to defer the capacity reserve payment plus carrying costs on a temporary basis until resolution of PSE’s electric general rate case later this year.

At June 30, 2006, PSE had a net receivable totaling $21.2 million in connection with wholesale sales in 2000 to the California Independent System Operator (CAISO) and counterparties where payment to PSE was conditioned on the counterparties being paid by the California Power Exchange. In August 2005, PSE submitted a Fuel Cost Adjustment Claim for $3.4 million related to sales in 2000 to the CAISO, pursuant to FERC’s California refund proceeding.

Based upon FERC orders, PSE has determined a range related to its CAISO receivable to be between $21.2 million (PSE’s net receivable balance) and $29.3 million, including interest, on its past due receivables as of June 30, 2006.

In January 2003, FASB issued Interpretation No. 46R, “Consolidation of Variable Interest Entities” (FIN 46R). FIN 46R requires that if a business entity has a controlling financial interest in a variable interest entity, the financial statements of the variable interest entity must be included in the consolidated financial statements of the business entity. The Company has evaluated its purchase power agreements and determined that three counterparties may be considered variable interest entities. Consistent with FIN 46R, PSE submitted requests for information to those parties; however, the parties have refused to submit to PSE the necessary information for PSE to determine whether they meet the requirements of a variable interest entity. PSE also determined that it does not have a contractual right to such information. PSE will continue to submit requests for information to the counterparties in accordance with FIN 46R.

For the three purchase power agreements that may be considered variable interest entities under FIN 46R, PSE is required to buy all the generation from these plants, subject to displacement by PSE, at rates set forth in the purchase power agreements. If at any time the counterparties cannot deliver energy to PSE, PSE would have to buy energy in the wholesale market at prices which could be higher or lower than the purchase power agreement prices. PSE’s purchased electricity expense for the three months ended June 30, 2006 and 2005 for these three entities was $37.1 million and $41.6 million, respectively. PSE’s purchased electricity expense for the six months ended June 30, 2006 and 2005 for these three entities was $95.9 million and $113.5 million, respectively.

(8)

Litigation

There are several actions in the U.S. Ninth Circuit Court of Appeals against Bonneville Power Administration (BPA), in which the petitioners assert or may assert that BPA acted contrary to law or without authority in deciding to enter into, or in entering into or performing or implementing, a number of agreements, including the amended settlement agreement (and the May 2004 agreement) between BPA and PSE regarding the BPA Residential Purchase and Sale Program. BPA rates used in such agreements between BPA and PSE for determining the amounts of money to be paid to PSE by BPA under such agreements during the period October 1, 2001 through September 30, 2006 have been confirmed, approved and allowed to go into effect by FERC. There are also several actions in the U.S. Ninth Circuit Court of Appeals against BPA, in which petitioners assert that BPA acted contrary to law in adopting or implementing the rates or rate adjustment clause upon which the benefits received or to be received from BPA during the October 1, 2001 through September 30, 2006 period are based. The parties to these various actions presented oral arguments to the U.S. Ninth Circuit Court of Appeals in November 2005. A decision from the Court is anticipated in 2006. A number of parties have claimed that the BPA rates proposed or adopted in the BPA rate proceeding to develop BPA rates to be used in the agreements for determining the amounts of money to be paid to PSE by BPA during the period October 1, 2006 through September 30, 2009 are contrary to law and that BPA acted contrary to law or without authority in deciding to enter into, or in entering into or performing or implementing such agreements. It is not clear what impact, if any, development or review of such rates, review of such agreements, and the above described U.S. Ninth Circuit Court of Appeals actions may have on PSE.

(9)

Related Party Transaction

During the three-month period ended June 30, 2006, Puget Energy established the Puget Sound Energy Foundation (Foundation) with a $15.0 million contribution to the Foundation from a portion of the proceeds from the sale of InfrastruX. The contribution was recorded as other income (deduction) expense. The Foundation was established by Puget Energy as a not-for-profit organization whose results are not consolidated by Puget Energy.

On June 1, 2006, PSE entered into a revolving credit facility with its parent, Puget Energy, in the form of a Demand Promissory Note (Note). Through the Note, PSE may borrow up to $30 million from Puget Energy, subject to approval. Under the terms of the Note, PSE pays interest on the outstanding borrowings based on the lowest of the weighted average interest rate of (a) PSE’s outstanding commercial paper interest rate; (b) PSE’s senior unsecured revolving credit facility; or (c) PSE Funding receivable securitization facility interest rate which is the LIBOR rate plus a marginal rate. At June 30, 2006, the outstanding balance of Note was $26.5 million.

(10)

New Accounting Pronouncements

At its June 15, 2006 meeting, the Financial Accounting Standards Board’s (FASB) Emerging Issues Task Force (EITF) approved the issuance of EITF Issue No. 06-3 “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation).” EITF No. 06-3 will require disclosure whether or not the taxes collected from customers and remitted to government authorities are reported on a gross (included in revenues and costs) or a net (excluded from revenues) basis. In addition, for any such taxes that are reported on a gross basis, a company should disclose the amounts of those taxes in interim and annual financial statements for each period for which an income statement is presented if those amounts are significant. The EITF concluded that these requirements should be applied to financial reports for interim and annual periods beginning after December 15, 2006, which will be the quarter ended March 31, 2007, for the Company. PSE collected Washington State excise taxes (which are a component of general retail rates) and municipal taxes of $40.6 million and $105.2 million for the three and six months ended June 30, 2006, respectively, and $37.3 million and $90.9 million for the three and six months ended June 30, 2005, respectively. The Company’s policy is to report such taxes on a gross basis in operating revenues and taxes other than income taxes in the accompanying consolidated statements of income.

In July 2006, FASB issued Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109”, which clarifies the accounting for uncertainty in income taxes recognized in the financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” FIN 48 provides guidance on recognition threshold and measurement attributed to a tax position taken or expected to be taken in a tax return. The tax positions should only be recognized when it is more likely than not, based on technical merits, that the position will be sustained upon examination by the taxing authority. FIN 48 is effective for fiscal years beginning after December 15, 2006, which will be the quarter ended March 31, 2007. The Company is currently evaluating the provisions of FIN 48 to determine the potential impact, if any, the adoption will have on the Company’s financial statements.

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 “anticipates,” “believes,” “estimates,” “expects,” “future,” “intends,” “plans,” “projects,” “predicts,” “will likely result,” and “will continue” and similar expressions are used to identify forward-looking statements. However, these words are not the exclusive means of identifying such statements. In addition, any statements that refer to expectations, projections or other characterizations of future events or circumstances are forward-looking statements. The Company’s actual results could differ materially from those anticipated in these forward-looking statements for many reasons, including the factors described below and under the caption “Forward-Looking Statements” at the beginning of this report. You should not place undue reliance on these forward-looking statements, which apply only as of the date of this Form 10-Q.

Overview

Puget Energy is an energy services holding company and all of its operations are conducted through its subsidiary Puget Sound Energy (PSE), a regulated electric and gas utility company, and until May 7, 2006, InfrastruX. Puget Energy owned a 90.9% interest in InfrastruX, a utility construction and services company, until it was sold to an affiliate of Tenaska Power Fund, L.P. on May 7, 2006 for $275 million before taking into account cash on hand at may 7, 2006 of $11.4 million for a net sale price of $263.6 million. After repayment of debt, adjustments for working capital, transaction costs and distributions to minority interests, Puget Energy received $95.9 million for its 90.9% interest in InfrastruX in the second quarter 2006. The sale resulted in an after-tax gain of $29.8 million for the three months ended June 30, 2006. Puget Energy accounted for InfrastruX as a discontinued operation under SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” in 2005 and 2006. See section titled “InfrastruX” for further discussion. The $95.9 million net proceeds Puget Energy received from the sale of InfrastruX was used to support PSE through an equity contribution of $60.0 million and a loan of $26.5 million. In addition, Puget Energy established a charitable foundation, Puget Sound Energy Foundation, with a contribution of $15.0 million from the net proceeds from the sale of InfrastruX along with investment income of $0.4 million on the cash proceeds and a federal income tax benefit of $5.3 million from funding the Puget Sound Energy Foundation.

Puget Sound Energy

PSE generates revenues from the sale of electric and gas services, mainly to residential and commercial customers within Washington State. A majority of PSE’s revenues are generated in the first and fourth quarters during the winter heating season in Washington State.

As a regulated utility company, PSE is subject to Federal Energy Regulatory Commission (FERC) and Washington Utilities and Transportation Commission (Washington Commission) regulation which may impact a large array of business activities, including limitation of future rate increases; directed accounting requirements that may negatively impact earnings; licensing of PSE-owned generation facilities; and other FERC and Washington Commission directives that may impact PSE’s long-term goals. In addition, PSE is subject to risks inherent to the utility industry as a whole, including weather changes affecting purchases and sales of energy; outages at owned and non-owned generation plants where energy is obtained; storms or other events which can damage gas and electric distribution and transmission lines; and wholesale market stability over time.

PSE’s main operational objective is to provide reliable, safe and cost-effective energy to its customers. To help accomplish this objective, PSE intends to be more self-sufficient in energy generation resources. Owning more generation resources will reduce the Company’s reliance on the wholesale energy market. PSE is continually exploring new electric-power resource generation and long-term purchase power agreements to meet this goal. The completion of the Hopkins Ridge wind project in the fourth quarter 2005 and progress on construction of the Wild Horse wind project are two steps in reaching this goal. The Hopkins Ridge wind project provides approximately 150 MW of capacity or 52 average MW. The Company expects to complete construction of the Wild Horse wind project by the end of 2006. The Wild Horse wind project is designed to provide approximately 230 MW of capacity or 73 average MW. Together these electric generation resources will serve the needs of approximately 123,000 of PSE’s electric customers.

The Hopkins Ridge wind project and the Wild Horse wind project were included as part of PSE’s energy resource portfolio in its long-term electric Least Cost Plan that was filed May 2, 2005 with the Washington Commission. The plan supports a strategy of diverse resource acquisitions including resources fueled by natural gas and coal, renewable resources and shared resources. The Least Cost Plan was followed by issuing an all-source request for proposal (RFP) on November 1, 2005. Proposals were received January 13, 2006 and are currently under evaluation and assessment.

Results of Operations

Puget Energy

All the operations of Puget Energy are conducted through PSE and until May 7, 2006, InfrastruX. Net income for the three months ended June 30, 2006 was $53.5 million on operating revenues from continuing operations of $574.2 million compared to net income of $13.9 million on operating revenues from continuing operations of $510.1 million for the same period in 2005. The net income for both periods includes the results of discontinued operations for InfrastruX.

Basic and diluted earnings per share for the three months ended June 30, 2006 were $0.46 compared to basic and diluted earnings per share for the three months ended June 30, 2005 of $0.14. Included in the basic and diluted earnings per share for the three months ended June 30, 2006 and 2005 was earnings per share related to discontinued operations of InfrastruX of $0.28 and $0.02, respectively.

Net income for the three months ended June 30, 2006 was positively impacted by income from discontinued operations from InfrastruX of $33.0 million (after-tax) compared to $1.9 million (after-tax) for the three months ended June 30, 2005. The income from discontinued operations for the three months ended June 30, 2006 includes a gain on disposal of $29.8 million (after-tax) resulting from the sale of InfrastruX. Net income for the three months ended June 30, 2006 was also positively impacted by increased electric margins of $25.8 million compared to the same period in 2005 primarily from overrecovery of excess power cost under the Power Cost Adjustment (PCA) mechanism and increased sales volumes. In addition, gas margin increased $7.2 million as compared to 2005, largely due to a $5.0 million true-up of previously reported gas costs in 2005. Increased electric and natural gas sales volumes favorably impacted energy margins for the three and six months ended June 30, 2006. The increase was partially offset by a charitable contribution of $15.0 million ($9.75 million after-tax) to the Puget Sound Energy Foundation (Foundation) formed on May 12, 2006. The terms of the contribution require the Foundation to establish an endowment and permit contributions to qualified nonprofit organizations. The increase was also partially offset by higher depreciation expense, which negatively impacted net income. Income from continuing operations was $30.4 million and $103.9 million, for the three and six months ended June 30, 2006, respectively, excluding the impact of the charitable contribution to the Foundation. Management of the Company believes it is useful to present income from continuing operations and diluted earnings excluding the impact of the charitable contribution because it represents a more accurate measure of our operating performance and facilitates period-to-period comparisons. Diluted earnings per share from continuing operations was $0.26 and $0.89 for the three and six months ended June 30, 2006, respectively, excluding the impact of the charitable contribution to the Foundation. A reconciliation to amounts under generally accepted accounting principles is as follows:

(Dollars in millions, except per share amounts)	Three Months Ended June 30, 2006		Six Months Ended June 30, 2006
Income from continuing operations, as reported	$	20.6	$	94.1
Add: Impact of charitable contribution to Foundation, net of tax		9.8		9.8
Income from continuing operations, excluding charitable contribution	$	30.4	$	103.9

Earnings per share:
Basic and diluted earnings per share before cumulative effect of accounting change from continuing operations, as reported	$	0.18	$	0.81
Add: Impact of charitable contribution to Foundation		0.08		0.08
Basic and diluted earnings per share before cumulative effect of accounting change from continuing operations, excluding charitable contribution	$	0.26	$	0.89

For the six months ended June 30, 2006, Puget Energy’s net income was $146.1 million on operating revenues from continuing operations of $1.5 billion compared to net income of $85.0 million on operating revenues from continuing operations of $1.3 billion for the same period in 2005. Basic and diluted earnings per share for the six months ended June 30, 2006 were $1.26 compared to basic and diluted earnings per share of $0.85 and $0.84, respectively, for the same period in 2005. Included in the basic and diluted earnings per share for the six months ended June 30, 2006 and 2005 was $0.45 and $0.01, respectively, earnings per share related to discontinued operations of InfrastruX.

Net income for the six months ended June 30, 2006 was positively impacted by income from discontinued operations of InfrastruX of $51.9 million (after-tax) compared to $0.9 million (after-tax) for the six months ended June 30, 2005. The income from discontinued operations for the six months ended June 30, 2006 includes a gain on disposal of $29.8 million (after-tax) resulting from the sale of InfrastruX. The reversal of an InfrastruX carrying value charge recognized in 2005 of $7.3 million contributed to the gain on disposal. Natural gas and electric margins increased by $20.0 million and $30.1 million, respectively, for the six months ended June 30, 2006 compared to the same period in 2005, which positively impacted net income. The increase in natural gas margins resulted from increased natural gas general rates, increased sales volumes and the true-up of previously reported gas costs in 2005. The increase in electric margins was the result of favorable hydro conditions, increased sales volumes and an increase in electric tariff rates. The increase was partially offset by a charitable contribution of $15.0 million ($9.75 million after-tax), higher storm damage repair costs of $7.2 million due to severe wind storms in the first quarter 2006, an increase in non-storm related operations and maintenance expense and depreciation expense which negatively impacted net income.

Puget Sound Energy

PSE’s operating revenues and associated expenses are not generated evenly during the year. Variations in energy usage by consumers occur from season to season and from month to month within a season, primarily as a result of weather conditions. PSE normally experiences its highest retail energy sales during the heating season in the first and fourth quarters of the year, and its lowest sales in the third quarter of the year. Varying wholesale electric prices and the amount of hydroelectric energy supplies available to PSE also make quarter-to-quarter comparisons difficult.

Energy Margins

PSE uses the following margin information in reviewing its operations to determine whether PSE is collecting the appropriate amount of energy costs from its customers to allow recovery of its operating costs.

The following table displays the details of electric margin changes for the three months ended June 30, 2006 compared to the same period in 2005. Electric margin is electric sales to retail and transportation customers less pass-through tariff items and revenue-sensitive taxes, and the cost of generating and purchasing electric energy sold to customers, including transmission costs to bring electric energy to PSE’s service territory.

	Electric Margin
(Dollars in Millions) Three Months Ended June 30,	2006			2005			Change			Percent Change
Electric retail sales revenue	$	345.2		$	316.5		$	28.7			9.1	%
Electric transportation revenue		2.7			2.4			0.3			12.5	%
Other electric revenue-gas supply resale		6.1			1.0			5.1			*
Total electric revenue for margin¹		354.0			319.9			34.1			10.7	%
Adjustments for amounts included in revenue:
Pass-through production tax credits (PTCs)		3.1			--			3.1			*
Pass-through tariff items		(8.4	)		(7.2	)		(1.2	)		(16.7	)%
Pass-through revenue-sensitive taxes		(24.8	)		(23.6	)		(1.2	)		(5.1	)%
Residential exchange credit		38.7			37.1			1.6			4.3	%
Net electric revenue for margin		362.6			326.2			36.4			11.2	%
Minus power costs:
Electric generation fuel		(14.3	)		(12.9	)		(1.4	)		(10.9	)%
Purchased electricity, net of sales to other utilities and marketers²		(151.3	)		(152.4	)		1.1			0.7	%
Total electric power costs³		(165.6	)		(165.3	)		(0.3	)		(0.2	)%
Electric margin before PCA		197.0			160.9			36.1			22.4	%
Power cost deferred under the PCA mechanism		(19.9	)		(9.6	)		(10.3	)		*
Electric margin⁴	$	177.1		$	151.3		$	25.8			17.1	%

_________________________________

*		Percent change not applicable or unmeaningful.
¹		For the three months ended June 30, 2006, total electric revenue for margin was $354.0 million, which does not include $16.8 million in sales to other utilities and marketers and $10.2 million in other miscellaneous electric revenue included in electric operating revenues of $381.0 million. For the three months ended June 30, 2005, total electric revenue for margin was $319.9 million, which does not include $16.9 million in sales to other utilities and marketers and $8.6 million in other miscellaneous electric revenues included in electric operating revenues of $345.4 million.
²		For the three months ended June 30, 2006, purchased electricity, net of sales to other utilities and marketers, was $151.3 million, excluding sales to other utilities and marketers of $16.8 million and including power cost deferral under the PCA mechanism of $19.9 million, purchased electricity was $188.0 million. For the three months ended June 30, 2005, purchased electricity, net of sales to other utilities and marketers, was $152.4 million, excluding sales to other utilities and marketers of $16.9 million and including power cost deferral under the PCA mechanism of $9.6 million, purchased electricity was $178.9 million.
³		For the three months ended June 30, 2006, total electric power costs were $165.6 million, which includes electric generation fuel and purchased electricity, net of sales to other utilities and marketers (see note 2 above), but does not include the residential exchange credit of $(38.7) million and unrealized net gain on derivative instruments of $(0.2) million. These amounts, excluding sales of electricity to other utilities and marketers, provide electric energy costs of $163.4 million. For the three months ended June 30, 2005, total electric power costs were $165.3 million, which includes electric generation fuel and purchased electricity, net of sales to other utilities and marketers (see note 2 above), but does not include the residential exchange credit of $(37.1) million and unrealized net gain on derivative instruments of $(0.6) million. These amounts, excluding sales of electricity to other utilities and marketers, provide electric energy costs of $154.1 million.
⁴		Electric margin does not include any allocation for amortization/depreciation expense or electric generation operations and maintenance expense.

Electric margin increased $25.8 million for the three months ended June 30, 2006 compared to the same period in 2005, primarily due to favorable hydro conditions resulting in lower power costs than the amount reflected in PSE’s rates, increase in retail customer usage and varied usage among customer classes as compared to 2005. Lower power costs under the PCA mechanism contributed $11.3 million to margin for the three months ended June 30, 2006 as compared to 2005. Retail customer kWh sales (residential, commercial and industrial customers) increased 3.4% for the three months ended June 30, 2006 compared to 2005, which contributed $5.9 million to electric margin, and changes in customer class usage increased margin by $8.9 million compared to the same period in 2005.

The following table displays the details of electric margin changes for the six months ended June 30, 2006 compared to the same period in 2005.

	Electric Margin
(Dollars in Millions) Six Months Ended June 30,	2006			2005			Change			Percent Change
Electric retail sales revenue	$	780.4		$	703.6		$	76.8			10.9	%
Electric transportation revenue		5.4			5.1			0.3			5.9	%
Other electric revenue-gas supply resale		11.9			5.1			6.8			*
Total electric revenue for margin¹		797.7			713.8			83.9			11.8	%
Adjustments for amounts included in revenue:
Pass-through production tax credits (PTCs)		7.0			--			7.0			*
Pass-through tariff items		(17.0	)		(13.7	)		(3.3	)		(24.1	)%
Pass-through revenue-sensitive taxes		(56.7	)		(52.2	)		(4.5	)		(8.6	)%
Residential exchange credit		95.3			92.2			3.1			3.4	%
Net electric revenue for margin		826.3			740.1			86.2			11.6	%
Minus power costs:
Electric generation fuel		(35.9	)		(33.4	)		(2.5	)		(7.5	)%
Purchased electricity, net of sales to other utilities and marketers²		(394.8	)		(362.2	)		(32.6	)		(9.0	)%
Total electric power costs³		(430.7	)		(395.6	)		(35.1	)		(8.9	)%
Electric margin before PCA		395.6			344.5			51.1			14.8	%
Tenaska disallowance reserve		--			5.3			(5.3	)		*
Power cost deferred under the PCA mechanism		(12.7	)		3.0			(15.7	)		*
Electric margin⁴	$	382.9		$	352.8		$	30.1			8.5	%

_________________________________

*	Percent change not applicable or unmeaningful.
¹	For the six months ended June 30, 2006, total electric revenue for margin was $797.7 million, which does not include $32.6 million in sales to other utilities and marketers and $18.1 million in other miscellaneous electric revenue included in electric operating revenues of $848.4 million. For the six months ended June 30, 2005, total electric revenue for margin was $713.8 million, which does not include $33.2 million in sales to other utilities and marketers and $18.6 million in other miscellaneous electric revenues included in electric operating revenues of $765.5 million.
²	For the six months ended June 30, 2006, purchased electricity, net of sales to other utilities and marketers, was $394.8 million. Excluding sales to other utilities and marketers of $32.6 million and including power cost deferral under the PCA mechanism of $12.7 million, purchased electricity was $440.1 million. For the six months ended June 30, 2005, purchased electricity, net of sales to other utilities and marketers, was $362.2 million, excluding sales to other utilities and marketers of $33.2 million and including the Tenaska disallowance reserve turnaround of $(5.3) million and power cost deferral under the PCA mechanism of $(3.0) million, purchased electricity was $387.1 million.
³	For the six months ended June 30, 2006, total electric power costs were $430.7 million, which includes electric generation fuel and purchased electricity, net of sales to other utilities and marketers (see note 2 above), but does not include the residential exchange credit of $(95.3) million and unrealized net loss on derivative instruments of $0.8 million. These amounts, excluding sales of electricity to other utilities and marketers, provide electric energy costs of $381.5 million. For the six months ended June 30, 2005, total electric power costs were $395.6 million, which includes electric generation fuel and purchased electricity, net of sales to other utilities and marketers (see note 2 above), but does not include the residential exchange credit of $(92.2) million and unrealized net gain on derivative instruments of $(0.1) million. These amounts, excluding sales of electricity to other utilities and marketers, provide electric energy costs of $328.2 million.
⁴	Electric margin does not include any allocation for amortization/depreciation expense or electric generation operations and maintenance expense.

Electric margin increased $30.1 million for the six months ended June 30, 2006 compared to the same period in 2005 primarily due to favorable hydro conditions resulting in lower power costs than the amount in PSE’s rates which increased margin $11.0 million, a change in customer class usage, which increased margin by $8.3 million and an increase in retail customer usage, which contributed $13.4 million to margin. Retail customer kWh sales (residential, commercial and industrial customers) increased 3.9% for the six months ended June 30, 2006 compared to 2005. In addition, electric margin increased as a result of the effects of the power cost only rate case (PCORC) effective November 1, 2005, which increased margin by $8.2 million. These increases were partially offset by the non-recurring benefit of a February 23, 2005 Washington Commission order allowing recovery of power costs that lowered electric margin by $6.0 million and a reduction in the rate of return due to the general rate case which decreased margin by $7.1 million for the six months ended June 30, 2006.

The following table displays the details of gas margin changes for the three months ended June 30, 2006 compared to the same period in 2005. 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
(Dollars in Millions) Three Months Ended June 30,	2006			2005			Change			Percent Change
Gas retail revenue	$	185.1		$	155.2		$	29.9			19.3	%
Gas transportation revenue		3.1			3.2			(0.1	)		(3.1	)%
Total gas revenue for margin¹		188.2			158.4			29.8			18.8	%
Adjustments for amounts included in revenue:
Pass-through tariff items		(1.2	)		(1.0	)		(0.2	)		(20.0	)%
Pass-through revenue-sensitive taxes		(15.8	)		(13.7	)		(2.1	)		(15.3	)%
Net gas revenue for margin		171.2			143.7			27.5			19.1	%
Minus purchased gas costs		(118.4	)		(98.1	)		(20.3	)		(20.7	)%
Gas margin²	$	52.8		$	45.6		$	7.2			15.8	%

_________________________________

¹		For the three months ended June 30, 2006, total gas revenue for margin was $188.2 million, which does not include $4.3 million related to other gas operating revenues that is included in gas operating revenues of $192.5 million. For the three months ended June 30, 2005, total gas revenue for margin was $158.4 million, which does not include $4.2 million related to other gas operating revenues that is included in gas operating revenues of $162.6 million.
²		Gas margin does not include any allocation for amortization/depreciation expense or electric generation operations and maintenance expense.

Gas margin increased $7.2 million for the three months ended June 30, 2006 compared to the same period in 2005 primarily due to a one-time true-up of previously reported gas costs under the Purchased Gas Adjustment (PGA) mechanism during the three months ended June 30, 2005 which increased margin $5.0 million. In addition, retail customer therm sales increased 5.1% for the three months ended June 30, 2006, compared to the same period in 2005, which provided $2.6 million to margin. Gas margin decreased $0.4 million for the three months ended June 30, 2006 compared to the same period in 2005 as a result of changes in customer class usage.

The following table displays the details of gas margin changes for the six months ended June 30, 2006 compared to the same period in 2005.

	Gas Margin
(Dollars in Millions) Six Months Ended June 30,	2006			2005			Change			Percent Change
Gas retail revenue	$	583.7		$	468.0		$	115.7			24.7	%
Gas transportation revenue		6.7			6.6			0.1			1.5	%
Total gas revenue for margin¹		590.4			474.6			115.8			24.4	%
Adjustments for amounts included in revenue:
Pass-through tariff items		(3.8	)		(2.9	)		(0.9	)		(31.0	)%
Pass-through revenue-sensitive taxes		(48.5	)		(38.7	)		(9.8	)		(25.3	)%
Net gas revenue for margin		538.1			433.0			105.1			24.3	%
Minus purchased gas costs		(385.0	)		(299.9	)		(85.1	)		(28.4	)%
Gas margin²	$	153.1		$	133.1		$	20.0			15.0	%

_________________________________

¹		For the six months ended June 30, 2006, total gas revenue for margin was $590.4 million, which does not include $8.6 million related to other gas operating revenues that is included in gas operating revenues of $599.0 million. For the six months ended June 30, 2005, total gas revenue for margin was $474.6 million, which does not include $9.1 million related to other gas operating revenues that is included in gas operating revenues of $483.7 million.
²		Gas margin does not include any allocation for amortization/depreciation expense or electric generation operations and maintenance expense.

Gas margin increased $20.0 million for the six months ended June 30, 2006 compared to the same period in 2005. Gas margin increased $7.0 million as a result of the gas general tariff rate case and the effect of the one-time true-up of previously reported gas costs as noted above increased margin by $4.5 million. In addition, retail customer therm sales increased 7.3% for the six months ended June 30, 2006 compared to the same period in 2005, which provided $10.1 million to gas margin, and changes in customer class usage reduced margin by $1.6 million.

Electric Operating Revenues

The table below sets forth changes in electric operating revenues for PSE for the three months ended June 30, 2006 compared to the same period in 2005.

(Dollars in Millions) Three Months Ended June 30,	2006			2005			Change			Percent Change
Electric operating revenues:
Residential sales	$	167.1		$	152.9		$	14.2			9.3	%
Commercial sales		159.5			150.0			9.5			6.3	%
Industrial sales		24.2			23.2			1.0			4.3	%
Other retail sales, including unbilled revenue		(5.6	)		(9.6	)		4.0			41.7	%
Total retail sales		345.2			316.5			28.7			9.1	%
Transportation sales		2.7			2.4			0.3			12.5	%
Sales to other utilities and marketers		16.8			16.9			(0.1	)		(0.6	)%
Other		16.3			9.6			6.7			69.8	%
Total electric operating revenues	$	381.0		$	345.4		$	35.6			10.3	%

Electric retail sales increased $28.7 million for the three months ended June 30, 2006 compared to the same period in 2005 due primarily to rate increases related to the PCORC and increased retail customer usage. The PCORC rate case provided $16.6 million to electric operating revenues for the three months ended June 30, 2006 compared to the same period in 2005. Retail electricity usage increased 155,538 MWh or 3.4% for the three months ended June 30, 2006 compared to the same period in 2005, which resulted in an approximate $10.9 million increase in electric operating revenue. During the three month period ended June 30, 2006, the benefits of the Residential and Farm Energy Exchange Benefit credited to customers reduced electric operating revenues by $40.5 million compared to $38.8 million for the same period in 2005. This credit also reduced power costs by a corresponding amount with no impact on earnings.

During the three month period ended June 30, 2006, the benefits of production tax credits (PTCs) (federal income tax credits received for wind generation) were passed through to electric customers by crediting customers’ bills, which reduced electric operating revenues by $3.1 million. The PTCs also reduced income taxes. The PTCs began November 2005 when the Hopkins Ridge wind generation facility was placed in service.

Other electric revenues increased $6.7 million for the three months ended June 30, 2006 compared to the same period in 2005, primarily from the increase in the sale of non-core gas purchased for intended electric generation of $5.1 million. Non-core gas sales are included in the PCA mechanism calculation as a reduction in determining net power costs. Miscellaneous customer revenue and transmission revenue increased other electric revenues by $1.6 million compared to the same period in 2005.

The table below sets forth changes in electric operating revenues for PSE for the six months ended June 30, 2006 compared to the same period in 2005.

(Dollars in Millions) Six Months Ended June 30,	2006			2005			Change			Percent Change
Electric operating revenues:
Residential sales	$	409.1		$	364.8		$	44.3			12.1	%
Commercial sales		342.2			307.9			34.3			11.1	%
Industrial sales		50.5			45.2			5.3			11.7	%
Other retail sales, including unbilled revenue		(21.4	)		(14.4	)		(7.0	)		(48.6	)%
Total retail sales		780.4			703.5			76.9			10.9	%
Transportation sales		5.4			5.1			0.3			5.9	%
Sales to other utilities and marketers		32.6			33.2			(0.6	)		(1.8	)%
Other		30.0			23.7			6.3			26.6	%
Total electric operating revenues	$	848.4		$	765.5		$	82.9			10.8	%

Electric retail sales increased $76.9 million for the six months ended June 30, 2006 compared to the same period in 2005 due primarily to rate increases related to the PCORC and the electric general rate case, and increased retail customer usage. The PCORC and electric general rate case provided a combined additional $30.6 million to electric operating revenues for the six months ended June 30, 2006 compared to the same period in 2005. Retail electricity usage increased 402,173 MWh or 3.9% for the six months ended June 30, 2006 compared to the same period in 2005. The increase in electricity usage was mainly the result of a 1.3% higher average number of customers served in the six month period ended June 30, 2006 compared to the same period in 2005.

During the six month period ended June 30, 2006, the benefits of the Residential and Farm Energy Exchange Benefit credited to customers reduced electric operating revenues by $99.8 million compared to $96.4 million for the same period in 2005. This credit also reduced power costs by a corresponding amount with no impact on earnings.

Other electric revenues increased $6.3 million for the six month period ended June 30, 2006 compared to the same period in 2005, primarily from the sale of excess non-core gas. Non-core gas sales are included in the PCA mechanism calculation as a reduction in determining net power costs.

The following electric rate changes were approved by the Washington Commission in 2006 and 2005:

Type of Rate Adjustment	Effective Date	Average Percentage Increase in Rates		Annual Increase in Revenues (Dollars in Millions)
Electric General Rate Case	March 4, 2005	4.1	%	$ 57.7
Power Cost Only Rate Case	November 1, 2005	3.7	%	55.6
Power Cost Only Rate Case	July 1, 2006	5.9	%	45.3

Gas Operating Revenues

The table below sets forth changes in gas operating revenues for PSE for the three months ended June 30, 2006 compared to the same period in 2005.

(Dollars in Millions) Three Months Ended June 30,	2006		2005		Change			Percent Change
Gas operating revenues:
Residential sales	$	110.1	$	94.8	$	15.3			16.1	%
Commercial sales		62.4		50.4		12.0			23.8	%
Industrial sales		12.6		10.0		2.6			26.0	%
Total retail sales		185.1		155.2		29.9			19.3	%
Transportation sales		3.1		3.2		(0.1	)		(3.1	)%
Other		4.3		4.2		0.1			2.4	%
Total gas operating revenues	$	192.5	$	162.6	$	29.9			18.4	%

Gas retail sales increased $29.9 million for the three months ended June 30, 2006 compared to the same period in 2005 due to higher PGA mechanism rates in 2006 and higher customer gas usage. The Washington Commission approved a PGA mechanism rate increase effective October 1, 2005 that increased rates 14.7% annually. The PGA mechanism passes through to customers increases or decreases in the gas supply portion of the natural gas service rates based upon changes in the price of natural gas purchased from producers and wholesale marketers or changes in gas pipeline transportation costs. PSE’s gas margin and net income are not affected by changes under the PGA mechanism. For the three months ended June 30, 2006, the effects of the PGA mechanism rate increases provided an increase of $21.2 million in gas operating revenues. An increase of 3.0% in the average number of customers increased customer usage by 7.6 million therms or approximately $8.3 million in gas operating revenues.

The table below sets forth changes in gas operating revenues for PSE for the six months ended June 30, 2006 compared to the same period in 2005.

(Dollars in Millions) Six Months Ended June 30,	2006		2005		Change			Percent Change
Gas operating revenues:
Residential sales	$	375.1	$	303.4	$	71.7			23.6	%
Commercial sales		179.2		141.6		37.6			26.6	%
Industrial sales		29.4		23.0		6.4			27.8	%
Total retail sales		583.7		468.0		115.7			24.7	%
Transportation sales		6.7		6.6		0.1			1.5	%
Other		8.6		9.1		(0.5	)		(5.5	)%
Total gas operating revenues	$	599.0	$	483.7	$	115.3			23.8	%

Gas retail sales increased $115.7 million for the six months ended June 30, 2006 compared to the same period in 2005 due to higher PGA mechanism rates in 2006, approval of a 3.5% general gas rate increase in the gas general rate case and higher retail customer gas usage. The Washington Commission approved a PGA mechanism rate increase effective October 1, 2005 that provided $69.1 million in gas revenues for the six months ended June 30, 2006 compared to the same period in 2005. In addition, the gas general rate case increase provided an additional $7.0 million in gas operating revenues for the six months ended June 30, 2006 compared to the same period in 2005. The remaining increase in gas retail revenues was primarily due to a higher average number of customers, which increased 3.0%, and higher gas sales of 40.3 million therms or $34.7 million for the six months ended June 30, 2006 compared to the same period in 2005.

The following gas rate adjustments were approved by the Washington Commission in 2006 and 2005:

Type of Rate Adjustment	Effective Date	Average Percentage Increase in Rates		Annual Increase in Revenues (Dollars in Millions)
Gas General Rate Case	March 4, 2005	3.5	%	$ 26.3
Purchased Gas Adjustment	October 1, 2005	14.7	%	121.6

Operating Expenses

The table below sets forth significant changes in operating expenses for PSE and its subsidiaries for the three months ended June 30, 2006 compared to the same period in 2005.

(Dollars in Millions) Three Months Ended June 30,	2006			2005			Change		Percent Change
Purchased electricity	$	187.9		$	178.9		$	9.0		5.0	%
Electric generation fuel		14.3			12.9			1.4		10.9	%
Residential exchange credit		(38.7	)		(37.1	)		1.6		4.3	%
Purchased gas		118.4			98.1			20.3		20.7	%
Depreciation and amortization		64.5			59.7			4.8		8.0	%
Conservation amortization		7.5			6.0			1.5		25.0	%
Taxes other than income taxes		54.2			50.5			3.7		7.3	%
Income taxes		15.6			6.3			9.3		*

___________________

Percent change not applicable or meaningful

The table below sets forth significant changes in operating expenses for PSE and its subsidiaries for the six months ended June 30, 2006 compared to the same period in 2005.

(Dollars in Millions) Six Months Ended June 30,	2006			2005			Change		Percent Change
Purchased electricity	$	440.1		$	387.1		$	53.0		13.7	%
Electric generation fuel		35.9			33.3			2.6		7.8	%
Residential exchange credit		(95.3	)		(92.2	)		3.1		3.4	%
Purchased gas		385.0			299.9			85.1		28.4	%
Utility operations and maintenance		171.0			158.7			12.3		7.8	%
Depreciation and amortization		128.4			117.7			10.7		9.1	%
Conservation amortization		15.5			11.1			4.4		39.6	%
Taxes other than income taxes		133.9			120.2			13.7		11.4	%
Income taxes		56.3			52.8			3.5		6.6	%

Purchased electricity expenses increased $9.0 million and $53.0 million for the three and six months ended June 30, 2006, respectively, compared to the same periods in 2005. The increase for the three months ended June 30, 2006 was primarily the result of the reversal of previously deferred excess power costs of $10.2 million offset by lower wholesale market prices. Total purchased power for the three months ended June 30, 2006 increased 743,352 MWh or 19.6% compared to the same period in 2005. The increase for the six months ended June 30, 2006 was primarily the result of the reversal of deferred excess power costs and from higher customer kWh sales. Total purchased power for the six months ended June 30, 2006 increased 838,534 MWh or 9.9% compared to the same period in 2005. Increases in the purchases offset by slightly lower wholesale prices of power contributed $27.3 million to the increase for the six months ended June 30, 2006. The increase also reflected the reversal of previously deferred excess power costs of $12.7 million. Also contributing to the increase was a February 23, 2005 Washington Commission order concerning PSE’s compliance filing related to the PCA 2 period of July 1, 2003 through June 30, 2004. In its order, the Washington Commission determined that PSE was allowed to reflect additional power costs totaling $6.0 million during the PCA 2 period of July 1, 2003 through December 31, 2003 during the three months ended March 31, 2005. These costs were deferred under the PCA mechanism, which resulted in a reduction in purchased electricity expense for the three months ended March 31, 2005. Increase in transmission and other expenses contributed $4.8 million.

PSE’s hydroelectric production and related power costs in 2005 were negatively impacted by below-normal precipitation and reduced snow pack in the Pacific Northwest region. PSE cannot determine if lower than normal runoff will continue in future years nor what impact lower runoff may have on the amount of electricity that will need to be purchased. The July 10, 2006 Columbia Basin Runoff Forecast published by the National Weather Service Northwest River Forecast Center indicated that the total forecasted runoff above Grand Coulee Reservoir for the period January through July 2006 would be 106% of normal, which compares to 86% of normal observed runoff for the same period in 2005.

To meet customer demand, PSE economically dispatches resources in its power supply portfolio such as fossil-fuel generation, owned and contracted hydroelectric capacity and energy, and long-term contracted power. However, depending principally upon availability of hydroelectric energy, plant availability, fuel prices and/or changing load as a result of weather, PSE may sell surplus power or purchase deficit power in the wholesale market. PSE manages its regulated power portfolio through short-term and intermediate-term off-system physical purchases and sales and through other risk management techniques.

Electric generation fuel expense increased $1.4 million and $2.6 million for the three and six months ended June 30, 2006, respectively, compared to the same periods in 2005. The increase for the three months ended June 30, 2006 is primarily related to an increase in the cost of gas of PSE-controlled combustion turbine generating facilities. The increase for the six months ended June 30, 2006 was primarily the result of an increase in the cost of coal at Colstrip generating facilities of $2.3 million compared to the same period in 2005.

Residential exchange credits associated with the Residential Purchase and Sale Agreement with BPA increased $1.6 million and $3.1 million for the three and six months ended June 30, 2006, respectively, compared to the same periods in 2005, as a result of increased residential and small farm customer electric load. The residential exchange credit is a pass-through tariff item with a corresponding credit in electric operating revenue; thus, it has no impact on electric margin or net income.

Purchased gas expenses increased $20.3 million and $85.1 million for the three and six months ended June 30, 2006, respectively, compared to the same periods in 2005 primarily due to an increase in PGA rates as approved by the Washington Commission and higher customer therm sales. The PGA mechanism allows PSE to recover expected gas costs, and defer, as a receivable or liability, any gas costs that exceed or fall short of this expected gas cost amount in PGA mechanism rates, including accrued interest. The PGA mechanism receivable balance at June 30, 2006 and December 31, 2005 was $73.0 million and $67.3 million, respectively. PSE is authorized by the Washington Commission to accrue carrying costs on PGA receivable balances. A receivable balance in the PGA mechanism reflects a current underrecovery of market gas cost through rates.

Utility operations and maintenance expense increased $12.3 million for the six months ended June 30, 2006, compared to the same period in 2005. The increase for the six months ended June 30, 2006 was primarily due to higher electric distribution system restoration costs as a result of a series of strong winter storms with high winds in Western Washington during the first quarter of 2006. Storm damage related costs increased $7.2 million compared to the same period in 2005. In addition, maintenance of electric and gas distribution system increased $2.9 million, and customer service and call center costs increased $2.9 million for the six months ended June 30, 2006 compared to the same period in 2005. PSE anticipates operation and maintenance expense to increase in future years as investments in new generating resources and energy delivery infrastructure are completed. The timing and amounts of increases will vary depending on when new generating resources come into service.

Depreciation and amortization expense increased $4.8 million and $10.7 million for the three and six months ended June 30, 2006, respectively, compared to the same periods in 2005 due to additional utility plant placed in service. Included in the increase for the three and six months ended June 30, 2006 is a $2.2 million and $4.1 million increase, respectively, related to PSE’s Hopkins Ridge wind project that became operational on November 26, 2005. PSE anticipates depreciation expense will increase in future years as investments in new generating resources and energy delivery infrastructure are completed.

Conservation amortization increased $1.5 million and $4.4 million for the three and six months ended June 30, 2006, respectively, compared to the same periods in 2005 due to higher authorized recovery of electric conservation expenditures. Conservation amortization is a pass-through tariff item with no impact on earnings.

Taxes other than income taxes increased $3.7 million and $13.7 million for the three and six months ended June 30, 2006, respectively, compared to the same periods in 2005 due primarily to increases in revenue-based Washington State excise tax and municipal tax due to increased operating revenues. Revenue sensitive Washington State excise and municipal taxes have no impact on earnings.

Income taxes increased $9.3 million and $3.5 million for the three and six months ended June 30, 2006, respectively, compared to the same periods in 2005. The increase was the result of higher taxable income offset by a lower effective tax rate as compared to the same periods in 2005 due to higher production tax credits of $3.8 million and $0.8 million for the three and six months ended June 30, 2006, respectively, as compared to the same periods in 2005.

Other Income (Deductions) And Interest Charges

The table below sets forth significant changes in other income for PSE and its subsidiaries for the three months ended June 30, 2006 compared to the same period in 2005.

(Dollars in Millions) Three Months Ended June 30,		2006			2005			Change			Percent Change
Other income		$	5.6		$	1.9		$	3.7			*

___________________

Percent change not applicable or meaningful

Other income increased $3.7 million for the three months ended June 30, 2006 compared to the same period in 2005 primarily due to increases in the equity portion of allowance for funds used during construction, a decrease in long-term incentive plan costs and an increase in the return on regulatory assets.

The table below sets forth significant changes in other income and interest charges for PSE and its subsidiaries for the six months ended June 30, 2006 compared to the same period in 2005.

(Dollars in Millions) Six Months Ended June 30,	2006		2005		Change		Percent Change
Other income	$	7.9	$	3.7	$	4.2		*
Interest charges		83.1		81.0		2.1		2.6	%

___________________

Percent change not applicable or meaningful

Other income increased $4.2 million for the six months ended June 30, 2006 compared to the same period in 2005 primarily due to increases in the equity portion of allowance for funds used during construction, a decrease in long-term incentive plan costs and an increase in the return on regulatory assets.

Interest charges increased $2.1 million for the six months ended June 30, 2006 compared to the same period in 2005. The increase is due primarily to higher average interest rates and higher amounts of borrowings outstanding during the six months ended June 30, 2006 compared to the same period in 2005.

InfrastruX

On May 7, 2006, Puget Energy sold InfrastruX to an affiliate of Tenaska Power Fund, L.P. (Tenaska) for $275 million before taking into account cash on hand at May 7, 2006 of $11.4 million for a net sale price of $263.6 million. After repayment of debt, adjustments for working capital, transaction costs and distributions to minority interests, Puget Energy received after-tax cash proceeds of approximately $95.9 million for its 90.9% interest in InfrastruX in the second quarter 2006. The sale resulted in an after-tax gain of $29.8 million for the three months ended June 30, 2006. The repayment of InfrastruX’s debt by Puget Energy released Puget Energy’s corporate guarantee relating to the debt. Puget Energy accounted for InfrastruX as a discontinued operation under SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” in 2005 and 2006.

Under the terms of the sale agreement, Puget Energy is obligated for certain representations and warranties made by InfrastruX concerning its business. Puget Energy obtained a representation and warranty insurance policy and deposited $3.7 million into an escrow account to serve as retention under the policy. As of June 30, 2006, long-term restricted cash in the amount of $3.7 million is included in the accompanying balance sheets; that amount represents management’s estimate of the aggregate fair value of the amount potentially payable under those representations and warranties and is Puget Energy’s maximum exposure. The obligation expires May 7, 2008. Should Tenaska make any claims against Puget Energy, payment for the claims will be made from the escrow account, and total payments are limited to $3.7 million. Puget Energy also agreed to indemnify the purchaser for certain potential future losses related to one of InfrastruX’s subsidiary companies. Under the indemnity agreement, Puget Energy is liable for certain costs with the maximum amount of loss not to exceed $15.0 million. As of June 30, 2006, a liability in the amount of $5.0 million is included in the accompanying balance sheets; that amount represents Puget Energy’s estimate of the fair value of the amount potentially payable using a probability-weighted approach to a range of future cash flows. The obligation expires May 7, 2011. Tenaska and Puget Energy have also negotiated the terms of an environmental guaranty as part of the sale agreement. Under the terms of the agreement, Tenaska will be responsible for the first $0.1 million of environmental claims, Tenaska and Puget Energy will share the next $6.4 million equally and Puget Energy will be responsible for the next $3.5 million. Based on a review of a third-party environmental report, Puget Energy believes it will not have a future loss in connection with the environmental guarantee.

For the three and six months ended June 30, 2006, Puget Energy reported InfrastruX related income from discontinued operations (net of taxes and minority interest), including gain on sale, of $33.0 million and $51.9 million, respectively, compared to $1.9 million and $0.9 million (net of taxes and minority interest) for the three and six months ended June 30, 2005, respectively. Puget Energy’s income from discontinued operations for the six months ended June 30, 2006 includes $7.3 million related to the reversal of a carrying value adjustment recorded in 2005.

InfrastruX's operating revenue for the three and six months ended June 30, 2006 was $46.5 million and $138.6 million, respectively, compared to $97.3 million and $175.0 million, respectively, for the same periods in 2005. Pre-tax income for the three and six months ended June 30, 2006 was $5.8 million and $9.9 million, respectively, compared to $11.8 million and $11.7 million, respectively for the same periods in 2005.

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, 2006:

Puget Energy				Payments Due Per Period
Contractual Obligations (Dollars in Millions)	Total			2006		2007- 2008		2009- 2010		2011 & Thereafter
Long-term debt including interest		$	4,692.5	$	116.2	$	601.2	$	640.4	$	3,334.7
Short-term debt including interest			182.6		182.6		--		--		--
Junior subordinated debentures payable to a subsidiary trust including interest¹			102.8		1.6		6.2		6.2		88.8
Mandatorily redeemable preferred stock			1.9		--		--		--		1.9
Service contract obligations			152.4		12.6		55.5		54.4		29.9
Non-cancelable operating leases			95.2		6.7		29.1		21.8		37.6
Fredonia combustion turbines lease ²			58.6		2.2		8.5		8.2		39.7
Energy purchase obligations			6,235.5		525.6		1,932.9		1,283.5		2,493.5
Contract initiation payment/collateral requirement			18.5		--		--		--		18.5
Financial hedge obligations			24.2		0.6		23.6		--		--
Purchase obligations			179.9		179.9		--		--		--
Non-qualified pension and other benefits funding			50.0		2.7		11.1		10.2		26.0
Total contractual cash obligations		$	11,794.1	$	1,030.7	$	2,668.1	$	2,024.7	$	6,070.6

Puget Energy

Amount of Commitment

Expiration Per Period

Commercial Commitments

(Dollars in Millions)

Total

2006

2007-

2008

2009-

2010

2011 & Thereafter

Indemnity agreements ³	$	8.7	$	--	$	3.7	$	--	$	5.0
Credit agreement - available ⁴		316.9		--		--		--		316.9
Unsecured credit agreement		20.0		--		--		--		20.0
Receivable securitization facility ⁵		177.4		--		--		177.4		--
Energy operations letter of credit		0.5		0.5		--		--		--
Total commercial commitments	$	523.5	$	0.5	$	3.7	$	177.4	$	341.9

_______________________

¹	In 2001, PSE formed Puget Sound Energy Capital Trust II for the sole purpose of issuing and selling preferred securities (Trust Securities) to investors and issuing common securities to PSE. The proceeds from the sale of Trust Securities were used by the Trust to purchase Junior Subordinated Debentures (Debentures) from PSE. The Debentures are the sole assets of the Trusts and PSE owns all common securities of the Trusts.
²	See “Fredonia 3 and 4 Operating Lease” under “Off-Balance Sheet Arrangements” below.
³	Under the InfrastruX sale agreement, Puget Energy is obligated for certain representations and warranties concerning InfrastruX’s business and anti-trust inquiries. The fair value of the business warranty is $3.7 million at June 30, 2006 and the obligation expires on May 7, 2008. Puget Energy also agreed to indemnify the buyer relating to an anti-trust inquiry of an InfrastruX subsidiary that had a fair value of $5.0 million at June 30, 2006. See “InfrastruX” above for further discussion.
⁴	At June 30, 2006, PSE had available a $500 million unsecured credit agreement expiring in April 2011. The credit agreement provides credit support for letters of credit and commercial paper. At June 30, 2006, PSE had $0.5 million for an outstanding letter of credit and $182.6 million commercial paper outstanding, effectively reducing the available borrowing capacity to $316.9 million.
⁵	At June 30, 2006, PSE had available a $200 million receivables securitization facility that expires in December 2010. There were no amounts outstanding under the receivables securitization facility at June 30, 2006. The facility allows receivables to be used as collateral to secure short-term loans, not exceeding the lesser of $200 million or the borrowing base of eligible receivables, which fluctuate with the seasonality of energy sales to customers. The borrowing base of eligible receivables at June 30, 2006 was $177.4 million. See “Receivables Securitization Facility" below for further discussion.

Puget Sound Energy. The following are PSE’s aggregate contractual obligations and commercial commitments as of June 30, 2006:

Puget Sound Energy

Payments Due Per Period

Contractual Obligations

(Dollars in Millions)

Total

2006

2007-

2008

2009-

2010

2011 & Thereafter

Long-term debt including interest	$	4,692.5	$	116.2	$	601.2	$	640.4	$	3,334.7
Short-term debt including interest¹		209.2		209.2		--		--		--
Junior subordinated debentures payable to a subsidiary trust including interest²		102.8		1.6		6.2		6.2		88.8
Mandatorily redeemable preferred stock		1.9		--		--		--		1.9
Service contract obligations		152.4		12.6		55.5		54.4		29.9
Non-cancelable operating leases		95.2		6.7		29.1		21.8		37.6
Fredonia combustion turbines lease ³		58.6		2.2		8.5		8.2		39.7
Energy purchase obligations		6,235.5		525.6		1,932.9		1,283.5		2,493.5
Contract initiation payment/collateral requirement		18.5		--		--		--		18.5
Financial hedge obligations		24.2		0.6		23.6		--		--
Purchase obligations		179.9		179.9		--		--		--
Non-qualified pension and other benefits funding		50.0		2.7		11.1		10.2		26.0
Total contractual cash obligations	$	11,820.7	$	1,057.3	$	2,668.1	$	2,024.7	$	6,070.6

Puget Sound Energy

Amount of Commitment

Expiration Per Period

Commercial Commitments

(Dollars in Millions)

Total

2006

2007-

2008

2009-

2010

2011 & Thereafter

Credit agreement - available ⁴	$	316.9	$	--	$	--	$	--	$	316.9
Unsecured credit agreement		20.0		--		--		--		20.0
Receivable securitization facility ⁵		177.4		--		--		177.4		--
Energy operations letter of credit		0.5		0.5		--		--		--
Total commercial commitments	$	514.8	$	0.5	$	--	$	177.4	$	336.9

_______________________

¹	Short-term borrowing include $26.5 million outstanding debt under a Demand Promissory Note owed to Puget Energy. The outstanding balance under the Demand Promissory Note is eliminated by Puget Energy upon consolidation of PSE’s financial statements.
²	See note 1 under Puget Energy above.
³	See note 2 under Puget Energy above.
⁴	See note 4 under Puget Energy above.
⁵	See note 5 under Puget Energy above.

Off-Balance Sheet Arrangements

Fredonia 3 and 4 Operating Lease. PSE leases two combustion turbines for its Fredonia 3 and 4 electric generating facility pursuant to a master operating lease that was amended for this lease in April 2001. The lease has a term expiring in 2011, but can be canceled by PSE at any time. Payments under the lease vary with changes in the London Interbank Offered Rate (LIBOR). At June 30, 2006, PSE’s outstanding balance under the lease was $52.6 million. The expected residual value under the lease is the lesser of $37.4 million or 60% of the cost of the equipment. In the event the equipment is sold to a third party upon termination of the lease and the aggregate sales proceeds are less than the unamortized value of the equipment, PSE would be required to pay the lessor contingent rent in an amount equal to the deficiency up to a maximum of 87% of the unamortized value of the equipment.

Utility Construction Program

Utility construction expenditures for generation, transmission and distribution are designed to meet continuing customer growth and to improve efficiencies of PSE’s energy delivery systems. Construction expenditures, excluding equity Allowance for Funds Used during Construction (AFUDC) and customer refundable contributions, were $306.4 million for the six months ended June 30, 2006. Utility construction expenditures, excluding AFUDC and excluding new generation resources other than the Wild Horse project (which will be determined as the Company proceeds through the least cost planning process) are anticipated to be the following in 2006 and 2007:

Capital Expenditure Projections (Dollars in Millions)	2006		2007
Energy delivery, technology and facilities	$	444	$	500
Wild Horse wind project		317		--
Total capital expenditures		761		500
Chelan contract payment¹		89		--
Total expenditures	$	850	$	500

_______________________

¹	The Chelan contract payment represents a capacity reservation charge in conjunction with a new contract for hydroelectric power beginning 2011. PSE obtained an accounting order from the Washington Commission that treated the payment made on April 26, 2006 as a regulatory asset.

The proposed utility construction expenditures and any new generation resource expenditures that may be incurred are anticipated to be funded with a combination of cash from operations, short-term debt, long-term debt and equity. Construction expenditure estimates, including any new generation resources, are subject to periodic review and adjustment in light of changing economic, regulatory, environmental and efficiency factors.

Capital Resources

Cash From Operations

Cash generated from operations for the six months ended June 30, 2006 was $72.0 million. During that period, $5.0 million was used for AFUDC, which reduced interest expense and $52.0 million for payment of dividends. Consequently, cash flows available for utility construction expenditures and other capital expenditures were $15.0 million or 4.8% of the $311.8 million in construction expenditures (net of AFUDC and customer refundable contributions) and other capital expenditure requirements for the six months ended June 30, 2006. For the six months ended June 30, 2005, cash generated from operations was $136.6 million, $3.5 million was used for AFUDC, which reduced interest expense, and $43.9 million for payment of dividends. Therefore, cash flows available for utility construction expenditures and other capital expenditures were $89.2 million, or 39.2% of the $227.4 million in construction expenditures (net of AFUDC and customer refundable contributions) and other capital expenditure requirements for the six months ended June 30, 2005. The following table provides a summary of cash available and construction expenditures:

(Dollars in millions) (Unaudited) Six Months Ended June 30,	2006			2005
Cash from operations	$	72.0		$	136.6
Less: Dividends paid		(52.0	)		(43.9	)
AFUDC		(5.0	)		(3.5	)
Cash available for construction expenditures	$	15.0		$	89.2

Construction and energy efficiency expenditures	$	324.5		$	237.0
Less: AFUDC		(5.0	)		(3.5	)
Cash received from refundable customer contributions		(7.7	)		(6.1	)
Net construction and energy efficiency expenditures	$	311.8		$	227.4

The overall cash generated from operating activities for the six month period ended June 30, 2006 decreased $63.7 million compared to the same period in 2005. This decrease in cash from operations is primarily attributable to a non-refundable capacity reservation prepayment of $89.0 million in April 2006 for the Chelan PUD power sales agreement. This agreement will begin providing power to PSE at the end of 2011. In addition, cash from operations decreased $44.7 million due to an increase in the amount of taxes paid in 2006 as compared to 2005. Cash from operations was also negatively impacted by a $20.0 million refund of collateral deposits related to energy counterparties compared to $3.0 million receipt in 2005; a $15.0 million payment to fund Puget Sound Energy charitable foundation; and an increase of $82.2 million in payments made for accounts payable related to energy purchases. Offsetting the decrease in cash from operations is an increase in accounts receivable of $191.8 million. The increase in accounts receivable is primarily attributable to Rainier Receivables accounts receivable securitization sale of $150 million in December 2004 that was not collected from customers in the first quarter 2005. This compares to no activity under the Rainier Receivables accounts receivable securitization at December 31, 2005 due to termination of the Rainier Receivable accounts receivable securitization program in December 2005. As a result, cash from operations increased due to collection of accounts receivable in 2006. Collections of accounts receivable will increase in the second and third quarters of the year due to the highest accounts receivable balances in thre first and fourth quarters of the year.

Financing Program

Financing utility construction requirements and operational needs are dependent upon the cost and availability of external funds through capital markets and from financial institutions. Access to funds is dependent upon factors such as general economic conditions, regulatory authorizations and policies, and Puget Energy’s and PSE’s credit ratings.

Restrictive Covenants

In determining the type and amount of future financing, PSE may be limited by restrictions contained in its electric and gas mortgage indentures, articles of incorporation and certain loan agreements. Under the most restrictive tests, at June 30, 2006, PSE could issue:

approximately $321 million of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately $535 million of electric bondable property available for issuance, subject to an interest coverage ratio limitation of 2.0 times net earnings available for interest, which PSE exceeded at June 30, 2006;

approximately $250 million of additional first mortgage bonds under PSE’s gas mortgage indenture based on approximately $417 million of gas bondable property available for issuance, subject to an interest coverage ratio limitation of 1.75 times net earnings available for interest, which PSE exceeded at June 30, 2006;

·	approximately $772 million of additional preferred stock at an assumed dividend rate of 7.0%; and

·	approximately $647 million of unsecured long-term debt.

At June 30, 2006, PSE had approximately $3.8 billion in electric and gas ratebase to support the interest coverage ratio limitation test for net earnings available for interest.

Credit Ratings

Neither Puget Energy nor PSE has any debt outstanding that would accelerate debt maturity upon a credit rating downgrade. A ratings downgrade could adversely affect the 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 borrowing costs and commitment fee increase as PSE’s secured long-term debt ratings decline. A downgrade in commercial paper ratings could preclude PSE’s ability to issue commercial paper under its current programs. The marketability of PSE commercial paper is currently limited by the A-3/P-2 ratings by Standard & Poor’s and Moody’s Investors Service. In addition, downgrades in any or a combination of PSE’s debt ratings may prompt counterparties on a contract by contract basis in the wholesale electric, wholesale gas and financial derivative markets to require PSE to post a letter of credit or other collateral, make cash prepayments, obtain a guarantee agreement or provide other mutually agreeable security.

The ratings of Puget Energy and PSE, as of July 27, 2006, were as follows:

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

_______________________

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

Shelf Registrations, Long-Term Debt and Common Stock Activity

On March 16, 2006, Puget Energy and PSE filed a shelf registration statement with the Securities and Exchange Commission for the offering of:

·	common stock of Puget Energy;

·	senior notes of PSE, secured by first mortgage bonds;

·	preferred stock of PSE; and

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

The registration statement is valid for three years and does not specify the amount of securities that the Company may offer. The Company is subject to restrictions under PSE’s indentures and restated articles of incorporation on the amount of first mortgage bonds, unsecured debt and preferred stock that the Company may issue.

On June 30, 2006, PSE completed the issuance of $250 million of senior secured note at a rate of 6.724% which are due on June 15, 2036. The net proceeds from the issuance of the senior notes of approximately $247.8 million were used to redeem $200 million of 8.40% Capital Trust Preferred Securities, which were redeemed at par on June 30, 2006, and to repay a portion of PSE’s short-term debt. The short-term debt was incurred to repay $46 million of 8.06% senior notes that matured June 19, 2006. The yield to maturity of the $250 million senior secured notes was 6.17% after the settlement of two interest rate forward starting swap contracts.

Based on PSE's goal to become a more vertically integrated utility, it is expected that further issuances of debt will be utilized within one to two years to fund acquisitions of new generating resources. The structure, timing and amount of such financings are dependent on market conditions, projects available to be developed and financing needed at the time of any such acquisitions.

Forward Starting Interest Rate Swap Settlement

In the second quarter 2006, the Company settled its two forward starting interest rate swap contracts originating in May 2005. The purpose of the forward starting swap contracts was to hedge interest rate volatility for a debt offering of $200 million that was completed on June 30, 2006. Since interest rates increased related to the hedged debt from the date of issuance of the forward starting swap contracts, PSE received $21.3 million from the counterparties when the contracts were settled. The forward starting swap contracts were designated and documented under SFAS No. 133 criteria as cash flow hedges, with all changes in market value for each reporting period presented net of tax in other comprehensive income. In the second quarter 2006, the settlement gain on these instruments amounted to $13.9 million after-tax, and was recorded as a gain in other comprehensive income. In accordance with SFAS No. 133, the gain will be amortized out of other comprehensive income to current earnings as a decrease to interest expense over the life of the new debt issued at an annual rate of approximately $0.7 million before tax.

Liquidity Facilities and Commercial Paper

PSE’s short-term borrowings and sales of commercial paper are used to provide working capital and funding of utility construction programs.

PSE Credit Facilities

The Company has two committed credit facilities that provide, in aggregate, $700 million in short-term borrowing capability. These include a $500 million credit agreement and a $200 million accounts receivable securitization facility. In addition, PSE has an uncommitted $20 million unsecured credit agreement with a bank with no expiration date. The unsecured credit agreement can be terminated by either party upon written notice. PSE pays a varying interest rate on outstanding borrowings based on terms entered into at the time of the borrowings. There were no amounts outstanding under the unsecured credit agreement at June 30, 2006.

Demand Promissory Note. On June 1, 2006, PSE entered into a revolving credit facility with its parent, Puget Energy, in the form of a Demand Promissory Note (Note). Through the Note, PSE may borrow up to $30 million from Puget Energy, subject to approval. Under the terms of the Note, PSE pays interest on the outstanding borrowings based on the lowest of the weighted average interest rate of (a) PSE’s outstanding commercial paper interest rate; (b) PSE’s senior unsecured revolving credit facility; or (c) PSE Funding receivable securitization facility interest rate which is LIBOR rate plus a marginal rate. At June 30, 2006, the outstanding balance of Note was $26.5 million.

Credit Agreement. In March 2005, PSE entered into a five-year, $500 million unsecured credit agreement with a group of banks. In April 2006, PSE amended this credit agreement to extend the expiration date from April 2010 to April 2011. The agreement is primarily used to provide credit support for commercial paper and letters of credit. Under the terms of the credit agreement, PSE pays a floating interest rate on outstanding borrowings based either on the agent bank’s prime rate or on LIBOR plus a marginal rate based on PSE’s long-term credit rating at the time of borrowing. PSE pays a commitment fee on any unused portion of the credit agreement also based on long-term credit ratings of PSE. At June 30, 2006, there was $0.5 million outstanding under a letter of credit and $182.6 million commercial paper outstanding, effectively reducing the available borrowing capacity under the credit facility to $316.9 million.

Receivables Securitization Facility. PSE entered into a five-year Receivable Sales Agreement with PSE Funding, Inc. (PSE Funding), a wholly owned subsidiary, on December 20, 2005. Pursuant to the Receivables Sales Agreement, PSE sells all of its utility customer accounts receivable and unbilled utility revenues to PSE Funding. In addition, PSE Funding entered into a Loan and Servicing Agreement with PSE and two banks. The Loan and Servicing Agreement allows PSE Funding to use the receivables as collateral to secure short-term loans, not exceeding the lesser of $200 million or the borrowing base of eligible receivables which fluctuate with the seasonality of energy sales to customers. All loans from this facility will be reported as short-term debt in the financial statements.

The PSE Funding facility expires in December 2010, and is terminable by PSE and PSE Funding upon notice to the banks. During the six months ended June 30, 2006, PSE Funding borrowed a cumulative amount of $97.0 million secured by accounts receivable. There were no loans secured by accounts receivable pledged as collateral at June 30, 2006. The borrowing base of eligible receivables at June 30, 2006 was $177.4 million.

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 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 under the Stock Purchase and Dividend Reinvestment Plan of $3.4 million (164,784 shares) and $6.9 million (331,635 shares) for the three and six months ended June 30, 2006, respectively, compared to $3.7 million (168,213 shares) and $7.3 million (320,020 shares) for the three and six months ended June 30, 2005, respectively.

Common Stock Offering Programs

To provide additional financing options, Puget Energy entered into agreements in July 2003 with two financial institutions under which Puget Energy may offer and sell shares of its common stock from time to time through these institutions as sales agents, or as principals. Sales of the common stock, if any, may be made by means of negotiated transactions or in transactions that may be deemed to be “at-the-market” offerings as defined in Rule 415 promulgated under the Securities Act of 1933, including in ordinary brokers’ transactions on the New York Stock Exchange at market prices.

Other

FERC Hydroelectric Projects And Licenses

Baker River project. The Baker River project consists of the Lower Baker Development (constructed in 1925) and the Upper Baker Development (constructed in 1959). The Baker River project’s current license expires on April 30, 2007, and PSE submitted an application for a new license to FERC on April 30, 2004. On November 30, 2004, PSE and 23 parties comprised of federal, state and local governmental organizations, Native American Indian tribes, environmental and other non-governmental entities filed a proposed comprehensive settlement agreement on all issues relating to the relicensing of the Baker River project. The proposed settlement includes a set of proposed license articles and, if approved by FERC without material modification, would allow for a new license of 45 years or more. The proposed settlement would require an investment of approximately $360 million over the next 30 years (capital expenditures and operations and maintenance cost) in order to implement the conditions of the new license. The proposed settlement is subject to contingencies that have yet to be resolved and is subject to additional regulatory approvals yet to be attained from various agencies. On April 7, 2006, FERC issued a Draft Environmental Impact Statement discussing the proposed settlement. A Final Environmental Impact Statement is due in the third quarter of 2006. However, FERC has not yet ruled on the proposed settlement and its ultimate outcome remains uncertain.

White River project. The White River project was built in 1911 and was operated as a hydropower facility until January 15, 2004. PSE submitted a license application to FERC in 1983, and in December 1997, FERC issued a proposed license for the project. PSE appealed the 1997 license because it contained terms and conditions that would render ongoing operations of the project uneconomic relative to alternative resources. In November 2003, PSE determined that it could no longer continue to operate the project economically due to additional conditions primarily related to two listings under the Endangered Species Act. On December 23, 2003, PSE notified FERC that it rejected the 1997 license for the White River project and on January 15, 2004, generation of electricity ceased at the White River project. PSE is actively seeking to sell the project to one or more entities interested in maintaining the reservoir for commercial purposes. On February 16, 2006, PSE entered into a Letter of Intent with the Cascade Land Conservancy to facilitate efforts to sell certain former project properties to one or more third parties that may have an interest in acquiring these properties for potential open space, habitat and recreational interests.

In the PCORC Order issued on April 7, 2004, the Washington Commission approved PSE’s recovery on the unamortized White River plant investment. At June 30, 2006, the White River project net book value totaled $67.2 million, which included $44.2 million of net utility plant, $15.9 million of capitalized FERC licensing costs, $4.6 million of costs related to construction work in progress and $1.7 million related to dam operations and safety On February 18, 2005, the Washington Commission approved the recovery of the White River net utility plant costs but did not allow current recovery of FERC licensing costs and other related costs until all costs associated with selling the White River plant and any sales proceeds are known.

In January 2001, certain environmental groups gave notice of their intent to sue for alleged violations of the Endangered Species Act, but no such lawsuit has been filed. In May 2004, the Puyallup Indian Tribe gave PSE notice of intent to sue for an alleged violation of water quality laws associated with the release of water from the White River project reservoir. No such lawsuit has been filed and PSE is in discussion with the Puyallup Indian Tribe regarding their concerns. Additionally, PSE sought further direction from the Washington State Department of Ecology (Ecology) as to whether any additional actions are necessary to maintain compliance with applicable water quality laws, and Ecology has not recommended any such further actions.

Homeowners and others interested in preserving the project reservoir (Lake Tapps) have expressed concern over the possible loss of the reservoir and there has been a solicitation of interest in a potential lawsuit against PSE to preserve the reservoir, but no such lawsuit has been filed to date.

In September 2005, the Company renewed its contract with the United States Army Corps of Engineers (COE) to maintain operation of the White River diversion dam to support the COE’s ongoing operation of its Mud Mountain Dam fish passage facilities. The agreement provides for reimbursement of a portion of PSE’s operating costs and directs PSE to operate the diversion dam in accordance with measures determined by federal agencies to be necessary to protect listed species and habitat. This contract expires in September 2010, unless terminated prior to that date.

In June 2003, Ecology approved an application for new municipal water rights related to the White River project reservoir. This approval was sought in connection with PSE’s ongoing efforts to sell the White River project to be used for commercial purposes. An appeal of Ecology’s decision approving the new municipal water rights was subsequently filed with the Washington State Pollution Control Hearings Board. In July 2004, this decision was remanded back to Ecology for further analysis of non-hydropower operations. The Company has been advised by Ecology that Ecology anticipates issuing a revised decision in 2006; however, no firm date has been set for any such revised decision. Any proceeds from the sale of the White River water rights will reduce the balance of the deferred regulatory asset. Neither the outcome of this matter nor any potential associated costs can be predicted at this time.

Snoqualmie Falls project. The Snoqualmie Falls project, built in 1898, had its original license issued May 13, 1975, which was made effective retroactive to March 1, 1956, and expired on December 31, 1993. PSE filed its application to relicense the project on November 25, 1991, and operated the project pursuant to annual licenses issued by FERC after the original license expired. On June 29, 2004, FERC granted PSE a new 40-year operating license for the Snoqualmie Falls project. PSE estimates that the investment required to implement the conditions of the new license agreement will cost approximately $44 million. These conditions include modified operating procedures and various project upgrades that include better protection of fish, development of riparian habitat to promote fish propagation, increased minimum flows in the Snoqualmie River during low-water periods and the development of recreational amenities near the down-river power house. On July 29, 2004, the Snoqualmie Tribe and certain other parties filed a request for rehearing of the new license and a request to stay the FERC license. On March 1, 2005, FERC issued an Order on Rehearing and Dismissing Stay Request. The order requires additional flows at Snoqualmie Falls during certain times of the year. PSE requested rehearing of the order on the grounds that the order interferes with the Washington State Department of Ecology’s authority to regulate water quality and that FERC arbitrarily and capriciously rebalance the public interest without support of substantive evidence in the record. The Snoqualmie Tribe appealed FERC’s operating license decision to the United States Court of Appeals for the Ninth Circuit and PSE intervened in that proceeding. PSE’s request for rehearing was denied on June 1, 2005 and on July 8, 2005, PSE asked for further review by the Ninth Circuit. The two petitions have been consolidated and briefing is anticipated to be completed in the third quarter of 2006.

Electron project. The Electron project was built in 1904. The project’s capacity is currently 22 MW. In 1977, the project was determined to be a “pre-1935” project under the Federal Power Act (FPA) and therefore not subject to FERC jurisdiction. In this status, the project can continue to operate without a FERC license absent “post-1935” construction of a nature sufficient to invoke FERC’s jurisdiction. PSE does not anticipate undertaking any betterments or improvements to the project that would entail “post-1935” construction.

The project also operates in compliance with the terms and conditions of a “Resource Enhancement Agreement” with the Puyallup Indian Tribe. This agreement resolved the Tribe’s long-standing claims for resource and other damages allegedly associated with the construction and operation of the project. The agreement also provides that in 2018 PSE must decide to either retire the project by 2026 or, in lieu of retirement, undertake significant upgrades that would likely invoke FERC jurisdiction. The outcome of these deliberations is not expected to have a material impact upon the financial condition, results of operations or liquidity of the Company. In July of 2005, the National Marine Fisheries Service and the U.S. Fish and Wildlife Service advised the Company of concerns with potential effects of project facilities and operations on listed species (salmon and bull trout). In response, the Company has initiated efforts to secure additional authorizations from the Services with respect to project facilities and operations. These efforts are ongoing.

Electric Regulation and Rates

Power Cost Only Rate Case and Electric General Rate Case. On June 28, 2006, the Washington Commission approved a 5.9%, or $45.3 million, power cost only rate case (PCORC) increase in electric rates for the period July 1, 2006 through December 31, 2006. The increase allows PSE to recover higher projected costs of power caused by higher market prices for natural gas used as fuel for electric generators. The rate increase granted will not appreciatively impact PSE’s income. The annualized basis of the PCORC rate increase when applied to the general rate case test year is $96.1 million. Primarily as a result of this order, PSE reduced its pending electric general tariff increase on July 10, 2006 from $140.9 million to $42.9 million, or 2.5%, on an annualized basis. Additionally, PSE has requested approval of a new tariff in its original general rate case filing to recover increases in electric transmission and distribution depreciation costs incurred between general rate cases of $7.9 million. The resolution of the general rate case is expected by the end of 2006.

PCA Mechanism. On June 20, 2002, the Washington Commission approved a PCA mechanism that triggers if PSE’s costs to provide customers’ electricity falls outside certain bands from a normalized level of power costs established in an electric rate case. During the four-year period ended June 30, 2006, PSE’s cumulative maximum pre-tax earnings exposure due to power cost variations was limited to $40 million plus 1% of the excess. All significant variable power supply cost drivers are included in the PCA mechanism (hydroelectric generation variability, market price variability for purchased power and surplus power sales, natural gas and coal fuel price variability, generation unit forced outage risk and transmission cost variability.

Beginning July 1, 2006, the most significant risks are hydroelectric generation variability and wholesale market prices of natural gas and power. On a July through December 2006 basis, the current PCA mechanism apportions increases or decreases in power costs, on a graduated scale, between PSE and its customers in the following manner:

Prior to July 2006 Annual Power Cost Variability		July-December 2006 Power Cost Variability¹		Customers’ Share	Company’s Share²
	+/- $20 million		+/- $10 million	0%	100%
	+/- $20 - $40 million		+/- $10 - $20 million	50%	50%
	+/- $40 - $120 million		+/- $20 - $60 million	90%	10%
	+/- $120 million		+/- $60 million	95%	5%

__________________________

¹	In October 2005, the Washington Commission in its Power Cost Only Rate Case order made a provision to reduce the power cost variability amounts to half the annual power cost variability for the period July 1, 2006 through December 31, 2006.
²	Over the four-year period July 1, 2002 through June 30, 2006, the Company’s share of pre-tax power cost variations is capped at a cumulative $40 million plus 1% of the excess. Power cost variation after June 30, 2006 will be apportioned on an annual basis, on the graduated scale without a cumulative cap.

PSE proposed the following change to the annual PCA sharing bands effective January 1, 2007 in its general rate case filing on February 15, 2006:

Power Cost Variability		Customers’ Share	Company’s Share
	+/- $0 - $25 million	50%	50%
	+/- $25 - $120 million	90%	10%
	+/- $120 million	95%	5%

Gas Regulation and Rates

Gas General Rate Case. On July 10, 2006, PSE reduced its gas general rate increase request filed on February 15, 2006 from $40.4 million to $39.2 million, or 4.2%, on an annual basis with the Washington Commission. PSE also has requested approval of a new depreciation tracker in its original gas general rate case filing to recover increase in gas distribution depreciation costs incurred between general rate cases of $10.9 million. In addition, a gas decoupling mechanism was requested and does not have an impact on the current rate increase; however, it is designed to stabilize revenue changes due to load variations between regulatory filings. The resolution of the general rate case is expected by the end of 2006.

Other

Whitehorn Power Generating Facility Lease. PSE leases the Whitehorn power generating facility under a noncancelable operating lease expiring in February 2009 and received notice of alleged default for the non-performance of certain covenants from the lessor. PSE immediately investigated the matter and provided notice it disputed the allegations. The facility consists of two dual-fuel combustion turbine engines with 147 MW net capacity, which are operated for peak load conditions, emergencies, and to maintain reliability of service during periods of adverse water or weather conditions. The notice of default included the threat of eviction and recovery of all damages should PSE fail to cure the alleged default and assign governmental permits and licenses associated with the facility to the lessor. PSE subsequently agreed to reimburse the lessor for its legal costs and expenses incurred in connection with the default and the lessor has four times agreed to suspend the notice of default for a one-month period to allow the parties to further investigate the matter and negotiate possible solutions. The current suspension period runs through August 31, 2006. PSE is seeking resolution of the matter, which may include the modification of the lease or the purchase of the project. If PSE cannot negotiate reasonable terms to settle the dispute, the amount of the ultimate impact upon the Company, if any, cannot be predicted at this time.

Proceedings Relating to the Western Power Market

Puget Energy’s and PSE’s Annual Report on Form 10-K for the year ended December 31, 2005 and Quarterly Report on Form 10-Q for the quarter ended March 31, 2006 include a summary and subsequent developments relating to the western power market proceedings described below. The following discussion provides a summary of material developments in these proceedings that occurred during and subsequent to the period covered by this report. PSE intends to vigorously defend against each of these cases and does not expect the ultimate resolution of these proceedings in the aggregate to have a material adverse impact on the financial condition, results of operations or liquidity of the Company. However, there can be no assurances in that regard because litigation is subject to numerous uncertainties and PSE is unable to predict the ultimate outcome of these matters. Accordingly, there can be no guarantee that these proceedings, either individually or in the aggregate, will not materially and adversely affect PSE’s financial condition, results of operations or liquidity.

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

California Refund Proceeding. On July 25, 2001, FERC ordered an evidentiary hearing (Docket No. EL00-95) to determine the amount of refunds due to California energy buyers for purchases made in the spot markets operated by the CAISO and the California PX during the period October 2, 2000 through June 20, 2001 (refund period). The CAISO continues its efforts to prepare revised settlement statements based on newly recalculated costs and charges for spot market sales to California during the refund period. If the refunds required by the formula would cause a seller to recover less than its actual costs for the refund period, FERC has held that the seller would be allowed to document these costs and limit its refund liability commensurately. In August 2005, PSE submitted its audited Fuel Cost Allowance Claim with the CAISO. That claim is currently pending. In September 2005, PSE submitted an additional cost filing claim pursuant to FERC’s August 2005 order, demonstrating an overall revenue shortfall for sales into the California spot markets during the refund period after the mitigated market clearing price methodology was applied to its transactions. In January 2006, FERC issued its order on cost filings accepting PSE’s cost filing claim subject to certain modifications and the utilization of final CAISO data. PSE does not agree with all of FERC’s rulings and sought rehearing of some of FERC’s determinations. Once the CAISO receives updated cost offset filings from sellers, including PSE, it will continue efforts to prepare revised settlement statements for spot market sales to California during the refund period. Thus, PSE’s ability to recover all or a part of its costs remains uncertain at this time. Global settlements have been announced and/or approved, including settlements between the California Parties and Williams, Duke, El Paso, Mirant, Dynegy, Enron, Reliant, Public Service Company of Colorado and Idacorp. These settlements, supported by a statement from FERC Chairman Joseph Kelliher, may suggest that the process momentum toward settlement in the California Refund Proceedings is increasing.

Many of the numerous orders that FERC issued in Docket No. EL00-95 are on appeal before the United States Court of Appeals for the Ninth Circuit. Some of those issues have been consolidated as a result of a case management conference conducted on September 21, 2004. The Ninth Circuit ordered on October 22, 2004 that briefing proceed in two rounds. The first round was limited to three issues: (1) which parties are subject to FERC’s refund jurisdiction in light of the exemption for government-owned utilities in section 201(f) of the FPA; (2) the temporal scope of refunds under section 206 of the FPA; and (3) which categories of transactions are subject to refunds.

On September 6, 2005, the court ruled that, as to the first issue, FERC does not have refund authority over wholesale electric sales made by governmental utilities. On August 2, 2006, the court decided the remaining issues of the first round, ruling that FERC erred in excluding potential relief for tariff violations for periods that pre-dated October 2, 2000, and ruling that FERC should consider remedies for certain CAISO and California PX transactions outside the 24-hour period previously used to define the scope of the proceedings.

The August 2, 2006 decision may adversely impact PSE’s ability to recover the full amount of its CAISO Receivable described below, and the decision may expose PSE to claims or liabilities for transactions outside the previously defined “refund period,” but at this time the ultimate financial outcome for PSE is unclear. It is likely that some parties will seek rehearing of the court’s decision and/or that settlement talks will ensue. If the proceedings are not resolved through such a process, the matters would be remanded to FERC for further proceedings. PSE is studying the court’s decision, but is unable to predict either the outcome of the proceedings or the ultimate financial effect on PSE at this time.

CAISO Receivable. At June 30, 2006, PSE had a net receivable totaling $21.2 million in connection with wholesale sales in 2000 to the California Independent System Operator (CAISO) and counterparties where payment to PSE was conditioned on the counterparties being paid by the California Power Exchange. In August 2005, PSE submitted a Fuel Cost Adjustment Claim for $3.4 million related to sales in 2000 to the CAISO, pursuant to FERC’s California refund proceeding.

Pursuant to an order issued by FERC in August 2005, PSE also submitted a Portfolio Cost Claim in September 2005 for $9.3 million to the CAISO. On January 26, 2006, FERC issued its order on Cost Filings accepting PSE’s cost filing subject to certain modifications, which appear to have the effect of reducing PSE’s Portfolio Claim substantially. PSE filed a revised Portfolio Claim in the amount of $2.3 million on March 3, 2006. PSE does not agree with all of FERC’s rulings and sought rehearing. As a result of the Ninth Circuit decision of August 2, 2006 discussed above, PSE cannot assess the ultimate resolution of its California Receivable. However, the Company does not believe the claim will be reduced below the $21.2 million receivable. PSE does not agree with all of FERC’s rulings and sought rehearing. PSE’s ability to recover all or a portion of these claims is uncertain at the present time.

PSE has determined a range related to its CAISO receivable to be between $21.2 million (PSE’s net receivable balance) and $29.3 million, including interest, on its past due receivables as of June 30, 2006. At this time there is no reasonable basis to adjust PSE’s net receivable balance of $21.2 million because the procedural outcome of a rehearing or remand to FERC is uncertain, and any financial impact cannot be quantified.

Critical Accounting Policies And Estimates

Effective January 1, 2006, the Company adopted the fair value recognition provisions of SFAS No. 123R, “Share-Based Payment,” using the modified-prospective transition method. Results for prior periods have not been restated, as provided for under the modified-prospective method. Prior to 2006, stock-based compensation plans were accounted for according to Accounting Principles Board (APB) No. 25, “Accounting for Stock Issued to Employees,” and related interpretations as allowed by SFAS No. 123, “Accounting for Stock-Based Compensation.” In 2003, the Company adopted the fair value based accounting of SFAS No. 123 using the prospective method under the guidance of SFAS No. 148, “Accounting for Stock-Based Compensation - Transition and Disclosure.” The Company applied SFAS No. 123 accounting to stock compensation awards granted subsequent to January 1, 2003, while grants prior to 2003 continued to be accounted for using the intrinsic value method of APB No. 25.

The adoption of SFAS 123R resulted in a cumulative benefit from an accounting change of $0.1 million, net of tax, for the quarter ended March 31, 2006. The cumulative effect adjustment is primarily the result of the inclusion of estimated forfeitures occurring before award vesting dates in the computation of compensation expense for unvested awards. As a result of adopting SFAS No. 123R on January 1, 2006, the Company’s income before income taxes and net income from continuing operations for the six months ended June 30, 2006, is $0.1 million and $0.1 million higher, respectively, than if it had continued to account for share-based compensation under SFAS No. 123 due to the inclusion of estimated forfeitures in compensation cost. There is no difference between basic and diluted earnings per share for income from continuing operations for the three and six months ended June 30, 2006, under SFAS No. 123R as compared to earlier methods.

The fair value of the stock-based grants is based on the closing price of the Company’s common stock on the date of measurement and historical performance of the certain share grants and prospective analysis using the Capital Asset Pricing Model and expected EPS growth rates. Based on this analysis, the Company’s total shareholder returns would need to significantly increase as compared to other companies to have a material impact on the Company’s financial statements. Shares granted prior to 2006 were valued using the Black-Scholes option pricing model.

Item 3. Quantitative and Qualitative Disclosure About Market Risk

Energy Portfolio Management

The regulatory mechanisms of the PGA and the PCA mitigate the impact of commodity price volatility on the Company. The PGA mechanism passes through increases and decreases in the cost of natural gas supply to customers. The PCA mechanism provided 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. For the period July 1, 2006 through December 31, 2006, the sharing bands will be half of the annual bands without a cap for excess power costs, and beginning January 1, 2007, the PCA mechanism will provide sharing of costs and benefits that are graduated over four levels for each calendar year without a maximum cap for excess power costs.

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

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

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

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

·	maximize the value of the Company’s energy supply assets.

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

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

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

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

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

The Company has entered into master netting agreements with counterparties when available to mitigate credit exposure to those counterparties. The Company believes that entering into such agreements reduces risk of settlement default for the ability to make only one net payment. In addition, the Company believes risk is mitigated with an improved position in potential counterparty bankruptcy situations due to a consistent netting approach.

At June 30, 2006, the Company was subject to a range of netting provisions, including both stand alone agreements and the provisions associated with the Western Systems Power Pool agreement of which many energy suppliers in the western United States are a part.

Transactions that qualify as hedge transactions under SFAS No. 133 are recorded on the balance sheet at fair value. Changes in fair value of the Company’s derivatives are recorded each period in current earnings or other comprehensive income. Short-term derivative contracts for the purchase and sale of electricity are valued based on daily quoted prices from an independent energy brokerage service. Valuations for short-term and medium-term natural gas financial derivatives are derived from a combination of quotes from several independent energy brokers and are updated daily. Long-term gas financial derivatives are valued based on published pricing from a combination of independent brokerage services and are updated monthly. Option contracts are valued using market quotes and a Monte Carlo simulation process employing stochastic differential equations using market volatilities and prices as inputs to create various commodity forward curves. These simulated forward curves are then used to value various option contracts across a spectrum of commodities.

At June 30, 2006, the Company had a net asset of approximately $23.7 million of energy contracts designated as qualifying cash flow hedges and a corresponding unrealized gain of $15.4 million after-tax recorded in other comprehensive income. These cash flow hedges represent forward financial purchases of gas intended to run PSE-owned electric plants in future periods. If it is determined that it is uneconomical to run the plants in the future period, the hedging relationship is ended and the cash flow hedge is de-designated and any unrealized gains and losses are recorded in the income statement. Gains and losses when these de-designated cash flow hedges are settled are recognized in energy costs and are included as part of the PCA mechanism. Amounts settling after June 30, 2006 have not been deferred as the $40 million cap under the PCA mechanism has expired and the sharing band under the PCA mechanism reset. The Company also had energy contracts that were marked-to-market at a gain of $0.2 million and a loss of $0.8 million through current earnings for the three and six months ended June 30, 2006, respectively. These mark-to-market adjustments were the result of excluding certain contracts from the normal purchase normal sale exception under SFAS No. 133 and de-designated cash flow hedges where the hedging relationship was ended. At June 30, 2006, the Company also has a net liability of approximately $32.3 million related to the fair value of gas contracts to serve gas customers. All mark-to-market adjustments relating to the natural gas business have been reclassified to a deferred account in accordance with SFAS No. 71 due to the PGA mechanism. The PGA mechanism passes on to customers increases and decreases in the cost of natural gas supply. As the gains and losses on the cash flow hedges are realized in future periods, they will be recorded as gas costs under the PGA mechanism. A hypothetical 10% decrease in the market prices of natural gas and electricity would decrease the fair value of qualifying cash flow hedges and comprehensive income by approximately $5.9 million after-tax and would decrease current earnings for those contracts marked-to-market in earnings by $0.2 million pre-tax. All items affecting comprehensive income are presented after-tax as items recorded in comprehensive income are net of tax.

Credit Risk

The Company is exposed to credit risk primarily through buying and selling electricity and gas to serve its customers. Credit risk is the potential loss resulting from a counterparty’s non-performance under an agreement. The Company manages credit risk with policies and procedures for, among other things, counterparty analysis, exposure measurement, exposure monitoring and exposure mitigation.

It is possible that extreme volatility in energy commodity prices could cause the Company to have sub-optimal credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. However, as of June 30, 2006, approximately 95% of the Company’s energy portfolio was rated investment grade or higher by Standard & Poor's Ratings Services and/or Moody's Investor Services, Inc.

Interest Rate Risk

The Company believes its interest rate risk primarily relates to the use of short-term debt instruments, variable-rate notes and leases and long-term debt financing needed to fund capital requirements. The Company manages its interest rate risk through the issuance of mostly fixed-rate debt of various maturities. The Company utilizes bank borrowings, commercial paper, line of credit facilities and accounts receivable securitization to meet short-term cash requirements. These short-term obligations are commonly refinanced with fixed-rate bonds or notes when needed and when interest rates are considered favorable. The Company may enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts.

In the second quarter 2006, the Company settled its two forward starting interest rate swap contracts originating in May 2005. The purpose of the forward starting swap contracts was to hedge interest rate volatility for a debt offering of $200 million that was completed on June 30, 2006. Since interest rates increased related to the hedged debt from the date of issuance of the forward starting swap contracts, PSE received $21.3 million from the counterparties when the contracts were settled. The forward starting swap contracts were designated and documented under SFAS No. 133 criteria as cash flow hedges, with all changes in market value for each reporting period being presented net of tax in other comprehensive income. In the second quarter 2006, the settlement gain on these instruments amounted to $13.9 million, after-tax, and was recorded as a gain in other comprehensive income. In accordance with SFAS No. 133, the gain will be amortized out of other comprehensive income to current earnings as a decrease to interest expense over the life of the new debt issued at an annual rate of approximately $0.7 million before tax. The ending balance in other comprehensive income related to the forward starting swaps and previously settled treasury lock contracts at June 30, 2006 was a net loss of $8.3 million after-tax and accumulated amortization. All financial hedge contracts of this type are reviewed by senior management and presented to the Securities Pricing Committee of the Board of Directors, and are approved prior to execution.

Item 4. Controls and Procedures

Puget Energy

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of Puget Energy’s management, including the Chairman, President and Chief Executive Officer and the Senior Vice President Finance and Chief Financial Officer, Puget Energy has evaluated the effectiveness of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of June 30, 2006, the end of the period covered by this report. Based upon that evaluation, the Chairman, President and Chief Executive Officer and the Senior Vice President Finance and Chief Financial Officer of Puget Energy concluded that these disclosure controls and procedures are effective.

Changes in Internal Control Over Financial Reporting

There have been no changes in Puget Energy’s internal control over financial reporting during the quarter ended June 30, 2006 that have materially affected, or are reasonably likely to materially affect, Puget Energy’s internal control over financial reporting.

Puget Sound Energy

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of PSE’s management, including the Chairman, President and Chief Executive Officer and the Senior Vice President Finance and Chief Financial Officer, PSE has evaluated the effectiveness of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of June 30, 2006, the end of the period covered by this report. Based upon that evaluation, the Chairman, President and Chief Executive Officer and the Senior Vice President Finance and Chief Financial Officer of PSE concluded that these disclosure controls and procedures are effective.

Changes in Internal Control Over Financial Reporting

There have been no changes in PSE’s internal control over financial reporting during the quarter ended June 30, 2006, that have materially affected, or are reasonably likely to materially affect, PSE’s internal control over financial reporting.

PART II OTHER INFORMATION

Item 1. Legal Proceedings

See the section titled “Proceedings Relating to the Western Power Market” under Item 2 “Management’s Discussion and Analysis of Financial Conditions and Results of Operations” of this Quarterly Report on Form 10-Q.

Contingencies arising out of the normal course of the Company’s business exist at June 30, 2006. 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 1A. Risk Factors

Risk factors previously disclosed by Puget Energy and Puget Sound Energy under “Risks Relating to Disposition of Discontinued Operations” in their Form 10-K, Item 1A for the period ending December 31, 2005, are no longer relevant after May 7, 2006 as InfrastruX was sold on that date. In addition, the following risk factor is an update to the previously disclosed risk factors by Puget Energy and PSE in the Form 10-K, Item 1A.

The mechanism by which variations in PSE’s power costs are apportioned between it and its customers will change in 2006, at which time PSE could experience a significant increase in expenses.

PSE has a PCA mechanism that provides for recovery of power costs from customers or refunding of power cost savings to customers, as those costs vary from the “power cost baseline” level of power costs which are set in part based on normalized assumptions about weather and hydro conditions. PSE’s exposure due to power cost variations over the four-year period ending June 30, 2006 was limited to $40 million plus 1% of the excess costs. The $40 million cap expired June 30, 2006, after which excess power costs or power cost savings will be apportioned between PSE and its customers pursuant to the graduated scale set forth in the PCA mechanism without operation of any cap. Although PSE received approval to reset its power cost baseline rates effective July 1, 2006, it is possible that PSE could experience higher expenses associated with excess power costs under the apportionment arrangement. PSE was also required by the settlement terms of its 2005 power cost only rate case to make a general rate case filing in February 2006 to again reset the power cost baseline rate effective January 1, 2007, and PSE has complied with that requirement. PSE’s pending general rate case filing, has requested modifications to the PCA mechanism but the outcome of that case cannot be known at this time and PSE may continue to experience substantial exposure to excess power costs beyond January 1, 2007.

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

Puget Energy’s annual meeting of shareholders was held on May 9, 2006. At the annual meeting, the shareholders elected three directors to hold office until the annual meeting of shareholders in 2009. The vote was as follows:

	Number of Shares
	For	Withheld
TERM EXPIRING 2009
Craig W. Cole	97,934,526	1,324,773
Tomio Moriguchi	97,936,836	1,322,463
Herbert B. Simon	97,943,607	1,315,692

There were no broker non-votes.

In addition, shareholders ratified the appointment of PricewaterhouseCoopers LLP. The vote was as follows:

	Number of Shares
	For	Against	Abstain
Ratify PricewaterhouseCoopers LLP	97,706,262	1,081,293	471,738

Item 6. Exhibits

See Exhibit Index for list of exhibits.

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
	Vice President, Corporate Secretary and Chief Accounting Officer

Date: August 3, 2006
	Chief accounting officer and officer duly authorized to sign this report on behalf of each registrant

EXHIBIT INDEX

The following exhibits are filed herewith:

12.1	Statement setting forth computation of ratios of earnings to fixed charges (2001 through 2005 and 12 months ended June 30, 2006) for Puget Energy.
12.2	Statement setting forth computation of ratios of earnings to fixed charges (2001 through 2005 and 12 months ended June 30, 2006) 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.