UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended ~~March 31,~~June 30, 2010

[ ]	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 4th Street, Suite 1200 Bellevue, Washington 98004-5591 (425) 454-6363	91-1969407

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

Indicate by check mark whether the registrants: (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was 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 the registrants have submitted electronically and posted on their corporate websites, if any, every interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Puget Energy, Inc.

Yes

/ /

Puget Sound Energy, Inc.

Yes

/ /

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

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

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

Puget Energy, Inc.

Yes

/ /

/X/

Puget Sound Energy, Inc.

Yes

/ /

/X/

As of February 6, 2009, all of the outstanding shares of voting stock of Puget Energy, Inc. are held by Puget Equico LLC, an indirect wholly owned subsidiary of Puget Holdings LLC. All of the outstanding shares of voting stock of Puget Sound Energy, Inc. are held by Puget Energy, Inc.

Table of Contents


Definitions
~~Definitions~~	Filing Format
~~Filing Format~~
Forward-Looking Statements

Part I.	Financial Statements

	Puget Energy, Inc.
	Consolidated Statements of Income – Three Months Ended ~~March 31,~~June 30, 2010 and 2009
	Consolidated Statements of Income – Six Months Ended June 30, 2010, February 6, 2009 to ~~March 31,~~June 30, 2009 (Successor) and January 1, 2009 to February 5, 2009 (Predecessor)
	Consolidated Statements of Comprehensive Income – Three Months Ended ~~March 31,~~June 30, 2010 and 2009
	Consolidated Statements of Comprehensive Income – Six Months Ended June 30, 2010, February 6, 2009 to ~~March 31,~~June 30, 2009 (Successor) and January 1, 2009 to February 5, 2009 (Predecessor)
	Consolidated Balance Sheets – ~~March 31,~~June 30, 2010 and December 31, 2009
	Consolidated ~~Statement~~Statements of Cash Flows – ~~Three~~Six Months Ended ~~March 31,~~June 30, 2010, February 6, 2009 to ~~March 31,~~June 30, 2009 (Successor) and January 1, 2009 to February 5, 2009 (Predecessor)

	Puget Sound Energy, Inc.
	Consolidated Statements of Income – Three and Six Months Ended ~~March 31,~~June 30, 2010 and 2009
	Consolidated Statements of Comprehensive Income – Three and Six Months Ended ~~March 31,~~June 30, 2010 and 2009
	Consolidated Balance Sheets – ~~March 31,~~June 30, 2010 and December 31, 2009
	Consolidated ~~Statement~~ Statements of Cash Flows – ~~Three~~Six Months Ended ~~March 31,~~June 30, 2010 and 2009

	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 6.~~	~~Exhibits~~

~~Signatures~~

Item 4.	Controls and Procedures

Part II.	Other Information

Item 1.	Legal Proceedings

Item 1A.	Risk Factors

Item 6.	Exhibits

Signatures

Exhibit Index

DEFINITIONS

AFUDC	Allowance for Funds Used During Construction
ASC	Accounting Standards Codification
ASU	Accounting Standards Update
BPA	Bonneville Power Administration
EBITDA	Earnings Before Interest, Tax, Depreciation and Amortization
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	Generally Accepted Accounting Principles
IRP	Integrated Resource Plan
IRS	Internal Revenue Service
ISDA	International Swaps and Derivatives Association
kW	Kilowatt
kWh	Kilowatt Hour
LIBOR	London Interbank Offered Rate
MMBtus	One Million British Thermal Units
MW	Megawatt (one MW equals one thousand kW)
MWh	Megawatt Hour (one MWh equals one thousand kWh)
NAESB	North American Energy Standards Board
NERC	North American Electric Reliability Corporation
Ninth Circuit	United States Court of Appeals for the Ninth Circuit
NPNS	Normal Purchase Normal Sale
OCI	Other Comprehensive Income
PCA	Power Cost Adjustment
PGA	Purchased Gas Adjustment
PSE	Puget Sound Energy, Inc.
Puget Energy	Puget Energy, Inc.
Puget Equico	Puget Equico LLC
Puget Holdings	Puget Holdings LLC
PURPA	Public Utility Regulatory Policies Act
REP	Residential Exchange Program
SERP	Supplemental Executive Retirement Plan
VIE	Variable Interest Entity
Washington Commission	Washington Utilities and Transportation Commission
WECC	Western Electricity Coordinating Council
WSPP	Western System Power Pool

FILING FORMAT

This report on Form 10-Q is a Quarterly Report filed separately by two different registrants, Puget Energy, Inc. (Puget Energy) as a voluntary Securities and Exchange Commission (SEC) filer, and Puget Sound Energy, Inc. (PSE). Any references in this report to the “Company” are to Puget Energy and PSE collectively.

FORWARD-LOOKING STATEMENTS

Puget Energy and PSE include 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 and 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.~~stat ements.

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. However, 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, financings, industry and rate structures, transmission and generation business structures within PSE, acquisition and disposal of assets and facilities, operation, maintenance and construction of electric generating facilities, operation, maintenance and construction of natural gas and electric distribution and transmission facilities, licensing of hydroelectric operations and natural gas storage facilities, recovery of other capital investments, recovery of power and natural gas costs, recovery of regulatory assets and present or prospective wholesale and retail competition;

·	Failure of PSE to comply with FERC or Washington Commission standards and/or rules, which could result in penalties based on the discretion of either commission;

·	Findings of noncompliance with electric reliability standards developed by the North American Electric Reliability Corporation (NERC) or the Western Electricity Coordinating Council (WECC) for users, owners and operators of the power system, which could result in penalties;

Changes in, adoption of and compliance with laws and regulations, including decisions and policies concerning the environment, climate change, greenhouse gas or other emissions or byproducts of electric generation (including coal ash or other substances), natural resources, and fish and wildlife (including the Endangered Species Act) as well as the risk of litigation arising from such matters, whether involving public or private claimants or regulatory investigative or enforcement measures;

·	The ability to recover costs arising from changes in enacted federal, state or local tax laws in a timely manner;

·	Changes in tax law, related regulations or differing interpretation or enforcement of applicable law by the Internal Revenue Service (IRS) or other taxing jurisdiction;

·	Inability to realize deferred tax assets and use production tax credits due to insufficient future taxable income;

·	Accidents or natural disasters, such as hurricanes, windstorms, earthquakes, floods, fires and landslides, which can interrupt service and lead to lost revenues, cause temporary supply disruptions and/or price spikes in the cost of fuel and raw materials and impose extraordinary costs;

·	Commodity price risks associated with procuring natural gas and power in wholesale markets or counterparties extending credit to PSE without collateral posting requirements;

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, adversely affect the availability of and access to capital and credit markets and/or impact delivery of energy to PSE from its 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 natural gas distribution system failure, which may impact PSE’s ability to ~~delivery~~deliver energy supply to its customers;

·	Changes in climate or weather conditions in the Pacific Northwest, which could have effects on customer usage and PSE’s revenues and expenses;

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

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

·	Electric plant generation and transmission system 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 generation resource;

·	The ability of a natural gas or electric plant to operate as intended;

·	The ability to renew contracts for electric and natural 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 power or natural gas to its customers and generating facilities;

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

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

·	Industrial, commercial and residential growth and demographic patterns in the service territories of PSE;

·	General economic conditions in the Pacific Northwest, which may impact customer consumption or affect PSE’s accounts receivable;

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

·	The failure of information systems or the failure to secure information system data, which may impact the operations and cost of PSE’s customer service, generation, distribution and transmission;

·	The impact of acts of God, terrorism, flu pandemic or similar significant events;

·	Capital market conditions, including changes in the availability of capital and 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 insurance coverage and the cost of such insurance;

·	The ability to maintain effective internal controls over financial reporting and operational processes;

Changes in Puget Energy’s or PSE’s credit ratings, which may have an adverse impact on the availability and cost of capital for ~~PSE~~Puget Energy or ~~Puget Energy~~PSE generally, or the failure to comply with the covenants in Puget Energy’s or PSE’s credit facilities, which would limit the Companies’ ability to utilize such facilities for capital; and

·	Deteriorating values of the equity, fixed income and other markets which could significantly impact the value of investments of PSE’s retirement plan, post-retirement medical benefit plan trusts and the funding of obligations thereunder.

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 the Company’s most recent annual report on Form 10-K.

PART I FINANCIAL INFORMATION

Item 1. Financial Statements

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands)

(Unaudited)

	Successor						Predecessor
	Three Months Ended March 31, 2010			February 6, 2009 – March 31, 2009			January 1, 2009 – February 5, 2009			Three Months Ended June 30, 2010			Three Months Ended June 30, 2009
Operating revenues:
Electric	$	554,635		$	386,612		$	213,618		$	463,306		$	456,754
Gas		322,405			316,435			190,001			209,447			226,922
Other		1,166			795			94			534			2,961
Total operating revenues		878,206			703,842			403,713			673,287			686,637
Operating expenses:
Energy costs:
Purchased electricity		254,163			169,416			90,737			174,833			188,773
Electric generation fuel		56,245			36,166			11,961			41,692			17,832
Residential exchange		(22,462	)		(19,862	)		(12,542	)		(16,875	)		(20,929	)
Purchased gas		176,864			199,138			120,925			106,632			132,140
Net unrealized (gain) loss on derivative instruments		60,648			(12,118	)		3,867
Net unrealized gain on derivative instruments											(14,740	)		(38,217	)
Utility operations and maintenance		116,179			77,243			37,650			122,235			122,107
Non-utility expense and other		3,602			2,471			112			4,157			4,318
Merger and related costs		--			2,479			44,324			--			252
Depreciation		70,528			44,222			21,773			74,126			66,115
Amortization		15,468			10,397			4,969			19,187			16,194
Conservation amortization		18,153			13,237			7,592			22,329			13,730
Taxes other than income taxes		83,415			64,407			36,935			67,985			66,697
Total operating expenses		832,803			587,196			368,303			601,561			569,012
Operating income		45,403			116,646			35,410			71,726			117,625
Other income (deductions):
Other income		12,000			6,279			3,653			9,814			12,387
Other expense		(989	)		(7,073	)		(369	)		(2,085	)		(1,691	)
Interest charges:
AFUDC		2,750			1,331			350			3,158			2,218
Interest expense		(82,713	)		(43,151	)		(17,291	)		(77,653	)		(73,379	)
Income from continuing operations before income taxes		(23,549	)		74,032			21,753
Income tax (benefit) expense		(4,358	)		21,972			8,997
Net income (loss)	$	(19,191	)	$	52,060		$	12,756
Income before income taxes											4,960			57,160
Income tax expense											1,297			13,590
Net income										$	3,663		$	43,570

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

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands)

(Unaudited)

				Successor			Predecessor
	Six Months Ended June 30, 2010			February 6, 2009 – June 30, 2009			January 1, 2009 – February 5, 2009
Operating revenues:
Electric	$	1,017,941		$	843,366		$	213,618
Gas		531,852			543,357			190,001
Other		1,700			3,757			94
Total operating revenues		1,551,493			1,390,480			403,713
Operating expenses:
Energy costs:
Purchased electricity		428,996			358,190			90,737
Electric generation fuel		97,937			53,998			11,961
Residential exchange		(39,336	)		(40,792	)		(12,542	)
Purchased gas		283,496			331,278			120,925
Net unrealized (gain) loss on derivative instruments		45,908			(50,334	)		3,867
Utility operations and maintenance		238,414			199,349			37,650
Non-utility expense and other		7,756			6,791			112
Merger and related costs		--			2,731			44,324
Depreciation		144,654			110,337			21,773
Amortization		34,655			26,591			4,969
Conservation amortization		40,482			26,967			7,592
Taxes other than income taxes		151,401			131,104			36,935
Total operating expenses		1,434,363			1,156,210			368,303
Operating income		117,130			234,270			35,410
Other income (deductions):
Other income		21,814			18,666			3,653
Other expense		(3,074	)		(8,765	)		(369	)
Interest charges:
AFUDC		5,908			3,549			350
Interest expense		(160,366	)		(116,529	)		(17,291	)
Income (loss) before income taxes		(18,588	)		131,191			21,753
Income tax expense		(3,060	)		35,561			8,997
Net income (loss)	$	(15,528	)	$	95,630		$	12,756

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

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands)

(Unaudited)

Successor Predecessor

Three Months
Ended
March 31,
2010

February 6,
2009 –
March 31,
2009

January 1,
2009 –
February 5,
2009

Net income (loss) $ (19,191 ) $ 52,060 $ 12,756
Other comprehensive income:
Net unrealized loss on interest rate swaps during the period, net of tax of $(9,394), $(14,438) and $0, respectively (17,446 ) (26,813 ) --
Reclassification of net unrealized loss on interest rate swaps during the period, net of tax of $2,987, $1,720 and $0, respectively 5,547 3,194 --
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $(453), $0 and $170, respectively (841 ) -- 315
Net unrealized loss on energy derivative instruments during the period, net of tax of $0, $(16,060) and $(13,010), respectively -- (29,826 ) (24,162 )
Reclassification of net unrealized loss on energy derivative instruments settled during the period, net of tax of $531, $434 and $2,428, respectively 987 805 4,509
Amortization of financing cash flow hedge contracts to earnings, net of tax of $0, $0 and $15, respectively -- -- 26
Other comprehensive income (loss) (11,753 ) (52,640 ) (19,312 )
Comprehensive income (loss) $ (30,944 ) $ (580 ) $ (6,556 )

	Three Months Ended June 30, 2010			Three Months Ended June 30, 2009
Net income	$	3,663		$	43,570
Other comprehensive income (loss):
Net unrealized gain (loss) on interest rate swaps during the period, net of tax of $(14,071) and $13,626, respectively		(26,131	)		25,305
Reclassification of net unrealized loss on interest rate swaps during the period, net of tax of $2,922 and $2,499, respectively		5,427			4,641
Net unrealized gain from pension and postretirement plans, net of tax of $841 and $0, respectively		839			--
Net unrealized gain on energy derivative instruments during the period, net of tax of $0 and $1,924, respectively		--			3,574
Reclassification of net unrealized loss on energy derivative instruments settled during the period, net of tax of $145 and $692, respectively		268			1,285
Other comprehensive income (loss)		(19,597	)		34,805
Comprehensive income (loss)	$	(15,934	)	$	78,375

	Successor						Predecessor
	Six Months Ended June 30, 2010			February 6, 2009 – June 30, 2009			January 1, 2009 – February 5, 2009
Net income (loss)	$	(15,528	)	$	95,630		$	12,756
Other comprehensive loss:
Net unrealized loss on interest rate swaps during the period, net of tax of $(23,465), $(811) and $0, respectively		(43,577	)		(1,507	)		--
Reclassification of net unrealized loss on interest rate swaps during the period, net of tax of $5,909, $4,219 and $0, respectively		10,974			7,835			--
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $(1), $0 and $170, respectively		(3	)		--			315
Net unrealized loss on energy derivative instruments during the period, net of tax of $0, $(14,135) and $(13,010), respectively		--			(26,253	)		(24,162	)
Reclassification of net unrealized loss on energy derivative instruments settled during the period, net of tax of $676, $1,126 and $2,428, respectively		1,255			2,090			4,509
Amortization of financing cash flow hedge contracts to earnings, net of tax of $0, $0 and $15, respectively		--			--			26
Other comprehensive loss		(31,351	)		(17,835	)		(19,312	)
Comprehensive income (loss)	$	(46,879	)	$	77,795		$	(6,556	)

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

PUGET ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

(Unaudited)

ASSETS

	March 31, 2010			December 31, 2009			June 30, 2010			December 31, 2009
Utility plant (including construction work in progress of $358,322 and $358,732, respectively):
Utility plant (including construction work in progress of $447,428 and $358,732, respectively):
Electric plant	$	4,746,181		$	4,705,900		$	4,927,344		$	4,705,900
Gas plant		2,025,278			1,995,219			2,064,459			1,995,219
Common plant		302,525			284,758			280,829			284,758
Less: Accumulated depreciation and amortization		(283,603	)		(185,474	)		(319,188	)		(185,474	)
Net utility plant		6,790,381			6,800,403			6,953,444			6,800,403
Other property and investments:
Goodwill		1,656,513			1,656,513			1,656,513			1,656,513
Investment in Bonneville Exchange Power contract		25,568			26,450			24,686			26,450
Other property and investments		126,605			127,073			126,921			127,073
Total other property and investments		1,808,686			1,810,036			1,808,120			1,810,036
Current assets:
Cash and cash equivalents		78,507			78,527			132,926			78,527
Restricted cash		17,343			19,844			16,541			19,844
Accounts receivable, net of allowance for doubtful accounts		291,911			320,016			258,431			320,016
Unbilled revenues		138,663			208,948			88,881			208,948
Materials and supplies, at average cost		87,421			75,035			88,537			75,035
Fuel and gas inventory, at average cost		81,749			96,483			95,801			96,483
Unrealized gain on derivative instruments		16,548			14,948			10,748			14,948
Income taxes		112,320			134,617			140,403			134,617
Prepaid expense and other		12,740			13,117			15,017			13,117
Power contract acquisition adjustment gain		173,101			169,171			172,766			169,171
Deferred income taxes		64,505			39,977			59,040			39,977
Total current assets		1,074,808			1,170,683			1,079,091			1,170,683
Other long-term and regulatory assets:
Regulatory assets for deferred income taxes		85,226			89,303			81,372			89,303
Regulatory asset for PURPA buyout costs		68,779			78,162			59,395			78,162
Power cost adjustment mechanism		15,824			8,529			11,044			8,529
Regulatory assets related to power contracts		179,767			210,340			152,875			210,340
Other regulatory assets		812,005			751,999			778,693			751,999
Unrealized gain on derivative instruments		5,074			25,459			1,665			25,459
Power contract acquisition adjustment gain		811,717			865,020			786,583			865,020
Other		91,994			90,206			100,937			90,206
Total other long-term and regulatory assets		2,070,386			2,119,018			1,972,564			2,119,018
Total assets	$	11,744,261		$	11,900,140		$	11,813,219		$	11,900,140

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, 2010			December 31, 2009
Capitalization:
Common shareholder’s equity:
Common stock $0.01 par value, 1,000 shares authorized, 200 shares outstanding	$	--		$	--
Additional paid-in capital		3,308,957			3,308,957
Earnings (deficit) reinvested in the business		(27,580	)		91,024
Accumulated other comprehensive income (loss) – net of tax		(7,864	)		23,487
Total common shareholder’s equity		3,273,513			3,423,468
Long-term debt:
PSE first mortgage bonds and senior notes		2,953,860			2,638,860
PSE junior subordinated notes		250,000			250,000
Puget Energy long-term debt		1,157,884			1,151,838
Total long-term debt		4,361,744			4,040,698
Total capitalization		7,635,257			7,464,166
Current liabilities:
Accounts payable		245,055			321,287
Short-term debt		--			105,000
Current maturities of long-term debt		267,000			232,000
Accrued expenses:
Purchased gas liability		7,380			49,587
Taxes		65,486			77,302
Salaries and wages		25,884			30,654
Interest		50,666			52,540
Unrealized loss on derivative instruments		248,571			168,783
Power contract acquisition adjustment loss		76,860			94,223
Other		123,575			194,786
Total current liabilities		1,110,477			1,326,162
Long-term and regulatory liabilities:
Deferred income taxes		1,168,384			1,147,667
Unrealized loss on derivative instruments		171,033			89,717
Regulatory liabilities		287,258			261,990
Regulatory liabilities related to power contracts		959,349			1,034,192
Power contract acquisition adjustment loss		76,881			117,272
Other deferred credits		404,580			458,974
Total long-term and regulatory liabilities		3,067,485			3,109,812
Commitments and contingencies
Total capitalization and liabilities	$	11,813,219		$	11,900,140

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

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

March 31,
2010

December 31,
2009

Capitalization:
Common shareholder’s equity:
Common stock $0.01 par value, 1,000 shares authorized, 200 shares outstanding $ -- $ --
Additional paid-in capital 3,308,957 3,308,957
Earnings reinvested in the business 17,603 91,024
Accumulated other comprehensive income (loss) – net of tax 11,734 23,487
Total common shareholder’s equity 3,338,294 3,423,468
Long-term debt:
PSE first mortgage bonds and senior notes 2,703,860 2,638,860
PSE junior subordinated notes 250,000 250,000
Puget Energy long-term debt 1,154,270 1,151,838
Total long-term debt 4,108,130 4,040,698
Total capitalization 7,446,424 7,464,166
Current liabilities:
Accounts payable 253,039 321,287
Short-term debt 40,000 105,000
Current maturities of long-term debt 267,000 232,000
Accrued expenses:
Purchased gas liability 7,823 49,587
Taxes 83,243 77,302
Salaries and wages 21,626 30,654
Interest 53,847 52,540
Unrealized loss on derivative instruments 261,561 168,783
Power contract acquisition adjustment loss 84,641 94,223
Other 131,633 194,786
Total current liabilities 1,204,413 1,326,162
Long-term and regulatory liabilities:
Deferred income taxes 1,160,323 1,147,667
Unrealized loss on derivative instruments 142,826 89,717
Regulatory liabilities 280,345 261,990
Regulatory liabilities related to power contracts 984,818 1,034,192
Power contract acquisition adjustment loss 96,137 117,272
Other deferred credits 428,975 458,974
Total long-term and regulatory liabilities 3,093,424 3,109,812
Commitments and contingencies
Total capitalization and liabilities $ 11,744,261 $ 11,900,140

	Successor						Predecessor
	Six Months Ended June 30, 2010			February 6, 2009 – June 30, 2009			January 1, 2009 – February 5, 2009
Operating activities:
Net income (loss)	$	(15,528	)	$	95,630		$	12,756
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation		144,654			110,337			21,773
Amortization		34,655			26,591			4,969
Conservation amortization		40,482			26,967			7,592
Deferred income taxes and tax credits, net		26,467			80,825			(512	)
Amortization of gas pipeline capacity assignment		(4,297	)		(3,861	)		(791	)
Carrying value adjustment related to California wholesale energy sale regulatory asset		17,763			--			--
Non cash return on regulatory assets		(4,758	)		(3,994	)		(800	)
Net unrealized loss (gain) on derivative instruments		45,908			(50,334	)		3,867
Power cost adjustment mechanism		(2,515	)		--			(7	)
Deferred regulatory costs for generation facilities		(8,205	)		(10,682	)		(3,443	)
Renewable energy credit payments received		19,288			--			--
Pension funding		(12,000	)		(6,000	)		--
Change in residential exchange program		2,141			(261	)		1,927
Derivative contracts classified as financing activities due to merger		222,858			258,189			--
Other		8,476			443			5,237
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue		181,652			307,243			(31,332	)
Materials and supplies		(13,503	)		(3,674	)		(3,388	)
Fuel and gas inventory		681			(3,391	)		7,605
Income taxes		(5,786	)		(59,381	)		18,277
Prepayments and other		(2,319	)		6,935			(3,295	)
Purchased gas payable		(42,207	)		52,294			1,711
Accounts payable		(41,413	)		(200,715	)		(40,203	)
Taxes payable		(11,816	)		375			(3,340	)
Accrued expenses and other		1,148			(66,628	)		59,172
Net cash provided by operating activities		581,826			556,908			57,775
Investing activities:
Construction expenditures – excluding equity AFUDC		(426,366	)		(313,983	)		(49,531	)
Energy efficiency expenditures		(49,111	)		(32,630	)		(4,918	)
Treasury grant payment received		28,675			--			--
Restricted cash		3,303			3,138			(10	)
Other		1,331			8,102			959
Net cash used in investing activities		(442,168	)		(335,373	)		(53,500	)
Financing activities:
Change in short-term debt and leases, net		(105,059	)		63,809			(151,800	)
Dividends paid		(103,076	)		(120,848	)		--
Long-term notes and bonds issued		575,000			50,211			250,000
Redemption of preferred stock		--			--			(1,889	)
Redemption of bonds and notes		(225,000	)		(150,000	)		--
Derivative contracts classified as financing activities due to merger		(222,858	)		(258,189	)		--
Issuance cost of bonds and other		(4,266	)		5,008			7,133
Net cash (used in) provided by financing activities		(85,259	)		(410,009	)		103,444
Net increase (decrease) in cash and cash equivalents		54,399			(188,474	)		107,719
Cash and cash equivalents at beginning of year		78,527			231,961			38,526
Cash and cash equivalents at end of year	$	132,926		$	43,487		$	146,245
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	140,472		$	119,392		$	1,239
Cash payments (refunds) for income taxes		(22,513	)		129			--

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,
	2010			2009			2010			2009
Operating revenues:
Electric	$	463,306		$	456,754		$	1,017,941		$	1,056,984
Gas		209,447			226,922			531,852			733,357
Other		534			2,604			1,700			3,493
Total operating revenues		673,287			686,280			1,551,493			1,793,834
Operating expenses:
Energy costs:
Purchased electricity		174,977			188,918			429,284			449,167
Electric generation fuel		41,692			17,832			97,937			65,960
Residential exchange		(16,875	)		(20,929	)		(39,336	)		(53,333	)
Purchased gas		106,632			132,140			283,496			452,203
Net unrealized (gain) loss on derivative instruments		9,126			(9,920	)		122,143			(7,590	)
Utility operations and maintenance		122,235			122,107			238,414			237,000
Non-utility expense and other		3,079			2,088			4,553			3,395
Merger and related costs		--			(3,655	)		--			23,908
Depreciation		74,126			66,191			144,654			132,186
Amortization		19,187			16,194			34,655			31,560
Conservation amortization		22,329			13,730			40,482			34,559
Taxes other than income taxes		67,985			66,697			151,401			168,039
Total operating expenses		624,493			591,393			1,507,683			1,537,054
Operating income		48,794			94,887			43,810			256,780
Other income (deductions):
Other income		9,814			12,387			21,814			22,319
Other expense		(2,085	)		(1,691	)		(3,074	)		(4,134	)
Interest charges:
AFUDC		3,158			2,218			5,908			3,900
Interest expense		(55,081	)		(50,428	)		(116,704	)		(103,004	)
Interest expense on Puget Energy note		(49	)		(68	)		(110	)		(142	)
Income (loss) before income taxes		4,551			57,305			(48,356	)		175,719
Income tax (benefit) expense		4,044			13,528			(10,589	)		46,965
Net income (loss)	$	507		$	43,777		$	(37,767	)	$	128,754

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,
	2010		2009			2010			2009
Net income (loss)	$	507	$	43,777		$	(37,767	)	$	128,754
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $(17), $(741), $1,593 and $(232), respectively		2,369		(1,376	)		2,911			(431	)
Net unrealized gain (loss) on energy derivative instruments during the period, net of tax of $218, $3,202, $244 and $(33,709), respectively		404		5,946			453			(62,603	)
Reclassification of net unrealized loss on energy derivative instruments settled during the period, net of tax of $3,578, $4,418, $13,816 and $11,938, respectively		6,645		8,204			25,658			22,171
Amortization of financing cash flow hedge contracts to earnings, net of tax of $43, $43, $86 and $86, respectively		79		79			159			159
Other comprehensive income (loss)		9,497		12,853			29,181			(40,704	)
Comprehensive income (loss)	$	10,004	$	56,630		$	(8,586	)	$	88,050

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

~~PUGET ENERGY, INC.~~

~~CONSOLIDATED STATEMENTS OF CASH FLOWS~~

~~(Dollars in Thousands)~~

~~(Unaudited)~~

Successor Predecessor

Three Months
Ended
March 31,
2010

February 6,
2009 –
March 31,
2009

January 1,
2009 –
February 5,
2009

Operating activities:
Net income $ (19,191 ) $ 52,060 $ 12,756
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation 70,528 44,222 21,773
Amortization 15,468 10,397 4,969
Conservation amortization 18,153 13,237 7,592
Deferred income taxes and tax credits, net (2,758 ) 26,085 (512 )
Amortization of gas pipeline capacity assignment (2,129 ) (1,517 ) (791 )
Non cash return on regulatory assets (2,396 ) (1,579 ) (800 )
Net unrealized loss (gain) on derivative instruments 60,648 (12,118 ) 3,867
Power cost adjustment mechanism (7,295 ) (13 ) (7 )
Deferred regulatory costs for generation facilities (9,084 ) (2,006 ) (3,443 )
Pension funding (6,500 ) -- --
Change in residential exchange program 1,773 4,403 1,927
Derivative contracts classified as financing activities due to merger 158,770 147,704 --
Other 23,796 31,669 5,237
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue 98,391 74,465 (31,332 )
Materials and supplies (12,386 ) 117 (3,388 )
Fuel and gas inventory 14,733 24,866 7,605
Income taxes 22,297 (19,639 ) 18,277
Prepayments and other 26 (19,319 ) (3,295 )
Purchased gas payable (41,764 ) 19,121 1,711
Accounts payable (33,780 ) (152,305 ) (40,203 )
Taxes payable 5,941 22,795 (3,340 )
Accrued expenses and other (1,548 ) (43,432 ) 59,172
Net cash provided by operating activities 351,693 219,213 57,775
Investing activities:
Construction expenditures – excluding equity AFUDC (184,424 ) (129,777 ) (49,531 )
Energy efficiency expenditures (25,686 ) (11,652 ) (4,918 )
Treasury grant payment received 28,675 -- --
Restricted cash 2,501 2,911 (10 )
Other 2,927 4,001 959
Net cash used in investing activities (176,007 ) (134,517 ) (53,500 )
Financing activities:
Change in short-term debt and leases, net (65,059 ) 113,809 (151,800 )
Dividends paid (54,230 ) (68,594 ) --
Long-term notes and bonds issued 325,000 50,211 250,000
Redemption of preferred stock -- -- (1,889 )
Redemption of bonds and notes (225,000 ) (150,000 ) --
Derivative contracts classified as financing activities due to merger (158,770 ) (147,704 ) --
Issuance costs of bonds and other 2,353 (13,337 ) 7,133
Net cash (used in) provided by financing activities (175,706 ) (215,615 ) 103,444
Net increase (decrease) in cash and cash equivalents (20 ) (130,919 ) 107,719
Cash and cash equivalents at beginning of year 78,527 231,961 38,526
Cash and cash equivalents at end of year $ 78,507 $ 101,042 $ 146,245
Supplemental cash flow information:

Cash payments for interest (net of capitalized interest) $ 66,345 $ 44,286 $ 1,239
Cash payments (refunds) for income taxes (22,513 ) (271 ) --

~~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
March 31

2010 2009
Operating revenues:
Electric $ 554,635 $ 600,230
Gas 322,405 506,436
Other 1,166 889
Total operating revenues 878,206 1,107,555
Operating expenses:
Energy costs:
Purchased electricity 254,307 260,249
Electric generation fuel 56,245 48,127
Residential exchange (22,462 ) (32,404 )
Purchased gas 176,864 320,063
Net unrealized (gain) loss on derivative instruments 113,017 2,330
Utility operations and maintenance 116,179 114,893
Non-utility expense and other 1,476 1,307
Merger and related costs -- 27,563
Depreciation 70,528 65,995
Amortization 15,468 15,366
Conservation amortization 18,153 20,829
Taxes other than income taxes 83,415 101,343
Total operating expenses 883,190 945,661
Operating income: (4,984 ) 161,894
Other income (deductions):
Other income 12,000 9,932
Other expense (989 ) (2,443 )
Interest charges:
AFUDC 2,750 1,681
Interest expense (61,622 ) (52,576 )
Interest expense on Puget Energy note (62 ) (73 )
Income before income taxes (52,907 ) 118,415
Income tax (benefit) expense (14,633 ) 33,438
Net income (loss) $ (38,274 ) $ 84,977

~~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
March 31

2010 2009
Net income (loss) $ (38,274 ) $ 84,977
Other comprehensive income (loss):
Net unrealized gain from pension and postretirement plans, net of tax of $291 and $509, respectively 539 945
Net unrealized gain (loss) on energy derivative instruments during the period, net of tax of $26 and $(36,911), respectively 49 (68,549 )
Reclassification of net unrealized loss on energy derivative instruments settled during the period, net of tax of $10,238 and $7,521, respectively 19,014 13,967
Amortization of financing cash flow hedge contracts to earnings, net of tax of $43 and $43, respectively 80 80
Other comprehensive income (loss) 19,682 (53,557 )
Comprehensive income (loss) $ (18,592 ) $ 31,420

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

~~PUGET SOUND ENERGY, INC.~~

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

(Unaudited)

ASSETS

	March 31, 2010			December 31, 2009			June 30, 2010			December 31, 2009
Utility plant: (at original cost, including construction work in progress of $358,322 and $358,732, respectively)
Utility plant: (at original cost, including construction work in progress of $447,428 and $358,732, respectively)
Electric plant	$	7,090,363		$	7,046,379		$	7,271,864		$	7,046,379
Gas plant		2,660,819			2,637,003			2,698,647			2,637,003
Common plant		548,694			539,296			411,010			539,296
Less: Accumulated depreciation and amortization		(3,536,523	)		(3,453,165	)		(3,451,244	)		(3,453,165	)
Net utility plant		6,763,353			6,769,513			6,930,277			6,769,513
Other property and investments:
Investment in Bonneville Exchange Power contract		25,568			26,450			24,686			26,450
Other property and investments		115,744			116,267			116,060			116,267
Total other property and investments		141,312			142,717			140,746			142,717
Current assets:
Cash and cash equivalents		78,428			78,407			132,903			78,407
Restricted cash		17,343			19,844			16,541			19,844
Accounts receivable, net of allowance for doubtful accounts		292,019			320,065			258,691			320,065
Unbilled revenues		138,663			208,948			88,881			208,948
Materials and supplies, at average cost		78,348			64,604			79,470			64,604
Fuel and gas inventory, at average cost		78,071			95,813			92,112			95,813
Unrealized gain on derivative instruments		16,548			14,948			10,748			14,948
Income taxes		69,556			99,948			86,434			99,948
Prepaid expenses and other		12,042			12,067			14,386			12,067
Deferred income taxes		72,515			38,781			71,931			38,781
Total current assets		853,533			953,425			852,097			953,425
Other long-term and regulatory assets
Regulatory asset for deferred income taxes		85,226			89,303
Other long-term and regulatory assets:
Regulatory assets for deferred income taxes								81,372			89,303
Regulatory asset for PURPA buyout costs		68,779			78,162			59,395			78,162
Power cost adjustment mechanism		15,824			8,529			11,044			8,529
Other regulatory assets		738,494			665,272			714,079			665,272
Unrealized gain on derivative instruments		1,027			4,605			1,665			4,605
Other		107,040			105,045			115,084			105,045
Total other long-term and regulatory assets		1,016,390			950,916			982,639			950,916
Total assets	$	8,774,588		$	8,816,571		$	8,905,759		$	8,816,571

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

	March 31, 2010			December 31, 2009			June 30, 2010			December 31, 2009
Capitalization:
Common shareholder’s equity:
Common stock ($0.01 par value) – 150,000,000 shares authorized, 85,903,791 shares outstanding	$	859		$	859
Common stock $0.01 par value – 150,000,000 shares authorized, 85,903,791 shares outstanding							$	859		$	859
Additional paid-in capital		2,959,205			2,959,205			2,959,205			2,959,205
Earnings reinvested in the business		219,332			333,128			149,750			333,128
Accumulated other comprehensive income (loss) – net of tax		(190,438	)		(210,120	)
Accumulated other comprehensive loss – net of tax								(180,939	)		(210,120	)
Total common shareholder’s equity		2,988,958			3,083,072			2,928,875			3,083,072
Long-term debt:
First mortgage bonds and senior notes		2,703,860			2,638,860			2,953,860			2,638,860
Junior subordinated notes		250,000			250,000			250,000			250,000
Total long-term debt		2,953,860			2,888,860			3,203,860			2,888,860
Total capitalization		5,942,818			5,971,932			6,132,735			5,971,932
Current liabilities:
Accounts payable		253,039			321,287			245,055			321,287
Short-term debt		40,000			105,000			--			105,000
Short-term note owed to Puget Energy		22,898			22,898			22,898			22,898
Current maturities of long-term debt		267,000			232,000			267,000			232,000
Accrued expenses:
Purchased gas liability		7,823			49,587			7,380			49,587
Taxes		83,243			77,302			65,486			77,302
Salaries and wages		21,626			30,654			25,884			30,654
Interest		50,353			47,154			47,629			47,154
Unrealized loss on derivative instruments		227,769			137,530			221,472			137,530
Other		58,885			104,148			54,559			104,148
Total current liabilities		1,032,636			1,127,560			957,363			1,127,560
Long-term liabilities and regulatory liabilities:
Deferred income taxes		1,016,913			996,576			1,037,065			996,576
Unrealized loss on derivative instruments		142,826			89,717			141,983			89,717
Regulatory liabilities		269,669			250,586			277,070			250,586
Other deferred credits		369,726			380,200			359,543			380,200
Total long-term liabilities and regulatory liabilities		1,799,134			1,717,079			1,815,661			1,717,079
Commitments and contingencies
Total capitalization and liabilities	$	8,774,588		$	8,816,571		$	8,905,759		$	8,816,571

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

	Three Months Ended March 31						Six Months Ended June 30,
	2010			2009			2010			2009
Operating activities:
Net income	$	(38,274	)	$	84,977
Adjustments to reconcile net income to net cash provided by operating activities:
Net income (loss)							$	(37,767	)	$	128,754
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation		70,528			65,995			144,654			132,186
Amortization		15,468			15,366			34,655			31,560
Conservation amortization		18,153			20,829			40,482			34,559
Deferred income taxes and tax credits, net		(21,237	)		26,408			(470	)		68,695
Amortization of gas pipeline capacity assignment		(2,129	)		(2,308	)		(4,297	)		(4,651	)
Carrying value adjustment related to California wholesale energy sale regulatory asset								17,763			--
Non cash return on regulatory assets		(2,396	)		(2,397	)		(4,758	)		(4,793	)
Net unrealized loss (gain) on derivative instruments		113,017			2,330			122,143			(7,590	)
Power cost adjustment mechanism		(7,295	)		(20	)		(2,515	)		--
Deferred regulatory costs for generation facilities		(9,084	)		(5,449	)		(8,205	)		(14,125	)
Renewable energy credit payments received								19,288			--
Pension funding		(6,500	)		--			(12,000	)		(6,000	)
Change in residential exchange program		1,773			6,330			2,141			1,666
Other		20,333			(16,610	)		4,197			(250	)
Counterparty collateral deposit		--			(5,268	)
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue		98,331			46,949			181,441			280,168
Materials and supplies		(13,744	)		(4,693	)		(14,866	)		(8,554	)
Fuel and gas inventory		17,742			46,938			3,702			21,990
Income taxes		30,391			7,046			13,514			(21,670	)
Prepayments and other		26			(9,865	)		(2,319	)		3,543
Purchased gas payable		(41,764	)		20,833			(42,207	)		54,005
Accounts payable		(33,780	)		(101,670	)		(41,413	)		(151,137	)
Taxes payable		5,941			11,530			(11,816	)		(19,192	)
Accrued expenses and other		(1,244	)		6,654			253			(8,147	)
Net cash provided by operating activities		214,256			213,905			401,600			511,017
Investing activities:
Construction expenditures – excluding equity AFUDC		(184,424	)		(179,308	)		(426,366	)		(363,514	)
Energy efficiency expenditures		(25,686	)		(16,570	)		(49,111	)		(37,548	)
Treasury grant payment received		28,675			--			28,675			--
Restricted cash		2,501			2,901			3,303			3,128
Other		2,927			4,960			1,331			9,061
Net cash used in investing activities		(176,007	)		(188,017	)		(442,168	)		(388,873	)
Financing activities:
Change in short-term debt and leases, net		(65,059	)		(10,376	)		(105,059	)		(87,991	)
Dividends paid		(75,522	)		(67,871	)		(145,611	)		(146,422	)
Issuance of bonds and notes		325,000			250,000
Loan from (payment to) Puget Energy		--			(6,610	)
Redemption of trust preferred stock		--			(1,889	)
Long-term notes and bonds issued								575,000			250,000
Loan payment to Puget Energy								--			(3,202	)
Redemption of preferred stock								--			(1,889	)
Redemption of bonds and notes		(225,000	)		(150,000	)		(225,000	)		(150,000	)
Investment from parent		--			29,616			--			25,960
Issuance cost of bonds and other		2,353			(6,199	)		(4,266	)		(3,613	)
Net cash provided by (used in) financing activities		(38,228	)		36,671			95,064			(117,157	)
Net increase (decrease) in cash and cash equivalents		21			62,559
Net increase in cash and cash equivalents								54,496			4,987
Cash and cash equivalents at beginning of year		78,407			38,470			78,407			38,470
Cash and cash equivalents at end of period	$	78,428		$	101,029		$	132,903		$	43,457
Supplemental cash flow information:
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	53,690		$	39,709		$	99,433		$	93,553
Cash payments (refunds) for income taxes		(22,404	)		(271	)		(22,404	)		129

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1)	Summary of Consolidation Policy

Basis of Presentation

Puget Energy, Inc. (Puget Energy) is an energy services holding company that owns Puget Sound Energy, Inc. (PSE). PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering 6,000 square miles, primarily in the Puget Sound region. On February 6, 2009, Puget Holdings LLC (Puget Holdings) acquired Puget Energy. The acquisition of Puget Energy was accounted for in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 805, “Business Combinations” (ASC 805) as of the date of the merger. ASC 805 requires the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the merger date. Puget ~~Energy consolidate d~~Energy’s consolidated financial statements and accompanying footnotes have been segregated to present pre-merger activity as the “Predecessor” Company and post-merger activity as the “Successor” Company.

The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiary, PSE. 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. PSE’s basis of accounting will continue to be on a historical basis and PSE’s financial statements will not include any ASC 805 purchase accounting adjustments.

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 consolidated 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, 2009.

The preparation of financial statements in conformity with Generally Accepted Accounting Principles (GAAP) 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.

PSE collected Washington State excise taxes (which are a component of general retail rates) and municipal taxes ~~of $67.2~~totaling $52.4 million and $119.6 million for the three and six months ended ~~March 31,~~June 30, 2010, respectively, and ~~$85.9~~$53.7 million and $139.6 million for the three and six months ended ~~March 31, 2009.~~June 30, 2009, 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.

Accumulated Other Comprehensive Income (Loss)

The following tables set forth the components of the Company’s accumulated other comprehensive income (loss) at ~~March 31,~~June 30, 2010 and December 31, 2009:

Puget Energy (Dollars in Thousands)	March 31, 2010			December 31, 2009			June 30, 2010			December 31, 2009
Net unrealized loss on energy derivatives during the period	$	(6,091	)	$	(7,078	)	$	(5,823	)	$	(7,078	)
Net unrealized loss on interest rate swaps		(15,792	)		(3,893	)		(36,496	)		(3,893	)
Net unrealized gain and prior service cost on pension plans		33,617			34,458			34,455			34,458
Total Puget Energy, net of tax	$	11,734		$	23,487		$	(7,864	)	$	23,487

Puget Sound Energy (Dollars in Thousands)	June 30, 2010			December 31, 2009
Net unrealized loss on energy derivatives during the period	$	(57,047	)	$	(83,158	)
Settlement of cash flow hedge contract		(7,415	)		(7,574	)
Net unrealized loss and prior service cost on pension plans		(116,477	)		(119,388	)
Total PSE, net of tax	$	(180,939	)	$	(210,120	)

Puget Sound Energy
(Dollars in Thousands)
March 31,
2010

December 31,
2009

Net unrealized loss on energy derivatives during the period $ (64,094 ) $ (83,158 )
Settlement of cash flow hedge contract (7,496 ) (7,574 )
Net unrealized loss and prior service cost on pension plans (118,848 ) (119,388 )
Total PSE, net of tax $ (190,438 ) $ (210,120 )
Accounting Adjustments. During the three months ended June 30, 2010, PSE recorded adjustments to after-tax income of $2.5 million to correct accounting errors which originated in prior periods. These adjustments increased depreciation expense by $2.2 million pre-tax, a net decrease in electric revenue and purchased electricity of $1.8 million pre-tax, and a $1.5 million decrease of income tax expense. Because the amounts were not material to the Company’s financial statements in any prior periods, and the cumulative amount is not material to the estimated results of operations for the year ending December 31, 2010, the Company recorded the cumulative effect of correcting these items during the three months ended June 30, 2010. The adjustments had no impact to cash flows from operations or total cash flows.

(2)	New Accounting Pronouncements

~~Variable Interest Entities.~~ In December 2009, the FASB issued ASU No. 2009-17, Topic 810, “Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities,” which amended the FASB ASC for the issuance of pre-codification FASB Statement No. 167, “Amendments to FASB Interpretation No. 46(R).” This standard replaces the quantitative-based risks and rewards calculation for determining which reporting entity, if any, has a controlling financial interest in a VIE with an approach focused on identifying which reporting entity has the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and: (1) the obligation to absorb lo sses of the entity; or (2) the right to receive benefits from the entity. An approach that is primarily qualitative is expected to be more effective for identifying which reporting entity has a controlling financial interest in a VIE. This standard also requires additional disclosures about a reporting entity’s involvement in VIE relationships, which will enhance the information provided to users of financial statements. The Company adopted the standard in the current period. There was no impact from adoption.

Fair Value Measurements and Disclosures. In January 2010, the FASB issued Accounting Standards Update (ASU) 2010-6, “Improving Disclosures About Fair Value Measurements,” which requires reporting entities to make new disclosures about recurring or nonrecurring fair value measurements including significant transfers into and out of Level 1 and Level 2 fair value measurements and information on purchases, sales, issuances, and settlements on a gross basis in the reconciliation of Level 2 fair value measurements. ASU 2010-6 is effective for annual reporting periods beginning after December 15, 2009, except for Level 3 reconciliation disclosures which are effective for annual periods beginning after December 15, 2010. As ~~these~~thes e new requirements relate solely to disclosures, the adoption of this guidance will not impact the Company’s consolidated financial statements.

Variable Interest Entities. In December 2009, the FASB issued ASU 2009-17, Topic 810, “Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities,” which amended the FASB ASC for the issuance of pre-codification FASB Statement No. 167, “Amendments to FASB Interpretation No. 46(R).” This standard replaces the quantitative-based risks and rewards calculation for determining which reporting entity, if any, has a controlling financial interest in a variable interest entity (VIE) with an approach focused on identifying which reporting entity has the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and: (1) the obligation to absorb losses of the entity; or (2) the right to receive benefits from the entity. An approach that is primarily qualitative is expected to be more effective for identifying which reporting entity has a controlling financial interest in a VIE. This standard also requires additional disclosures about a reporting entity’s involvement in VIE relationships, which will enhance the information provided to users of financial statements. The Company adopted the standard as of January 1, 2010. There was no impact from adoption.

(3)	Accounting for Derivative Instruments and Hedging Activities

The Company manages its interest rate risk through the issuance of mostly fixed-rate debt of various maturities. The Company utilizes ~~bank borrowings,~~internal cash from operations, commercial paper, and line of credit facilities to meet short-term ~~cash requirements. These short-term~~funding needs. 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 February 2009, Puget Energy entered into interest rate swap transactions to hedge the risk associated with the one-month ~~LIBOR~~London Interbank Offered Rate (LIBOR) floating debt rate. As of ~~March 31,~~June 30, 2010, Puget Energy had seven interest rate ~~swap~~sw ap contracts outstanding and PSE did not have any ~~out standing~~outstanding interest rate swap instruments.

As a result of the merger, Puget Energy de-designated its derivative contracts that were designated on PSE’s books as Normal Purchase Normal Sale (NPNS) or cash flow hedges and recorded such contracts at fair value as either assets or liabilities. Certain contracts meeting the criteria defined in ASC 815, “Derivatives and Hedging” (ASC 815) were subsequently re-designated as NPNS or cash flow hedges. Therefore, the amount recorded in accumulated other comprehensive income (OCI) at the time of the merger was reflected as goodwill.

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

On July 1, 2009, Puget Energy and PSE elected to de-designate all energy related derivative contracts ~~that~~which previously had been recorded as cash flow hedges for the purpose of simplifying its financial reporting. The contracts that were de-designated related to physical electric supply contracts and natural gas swap contracts to fix the price of natural gas for electric generation. For these contracts and for contracts initiated after ~~this~~such date, all future mark-to-market adjustments will be recognized through earnings. The amount previously recorded in accumulated OCI is transferred to earnings in the same period or periods during which the hedged transaction affected earnings or sooner if management determines that the forecasted transaction is probable of not occurring. As a result, the Company will likely continue to experience the earnings ~~volatility~~impact of these reversals from OCI in future periods.

ASC 815 requires disclosures about a company’s derivative activities and how the related hedged items affect a company’s financial position, financial performance and cash flows. To meet the objectives, ASC 815 requires qualitative disclosures about the Company’s fair value amounts of gains and losses associated with derivative instruments, as well as disclosures about credit risk related contingent features in derivative agreements.

The following tables present the fair values and locations of Puget Energy’s derivative instruments recorded on the balance sheet at ~~March 31,~~June 30, 2010 and December 31, 2009:

Derivatives Designated as Hedging Instruments	Derivatives Designated as Hedging Instruments								Derivatives Designated as Hedging Instruments
	at March 31, 2010				at December 31, 2009					at June 30, 2010				at December 31, 2009
Puget Energy (Dollars in Thousands)	Asset Derivatives 1		Liability Derivatives 2		Asset Derivatives 1		Liability Derivatives 2			Asset Derivatives 1		Liability Derivatives 2		Asset Derivatives 1		Liability Derivatives 2
Interest rate swaps:
Current	$	--	$	28,344	$	--	$	26,844		$	--	$	27,099	$	--	$	26,844
Long-term		4,047		--		20,854		--			--		29,050		20,854		--
Total derivatives	$	4,047	$	28,344	$	20,854	$	26,844		$	--	$	56,149	$	20,854	$	26,844

Derivatives Not Designated as Hedging Instruments	Derivatives Not Designated as Hedging Instruments								Derivatives Not Designated as Hedging Instruments
	at March 31, 2010				at December 31, 2009					at June 30, 2010				at December 31, 2009
Puget Energy (Dollars in Thousands)	Asset Derivatives 1		Liability Derivatives 2		Asset Derivatives 1		Liability Derivatives 2			Asset Derivatives 1		Liability Derivatives 2		Asset Derivatives 1		Liability Derivatives 2
Electric portfolio:
Current	$	2,789	$	128,121	$	4,137	$	79,732		$	2,851	$	124,658	$	4,137	$	79,732
Long-term		341		104,696		1,003		70,367			1,250		101,964		1,003		70,367
Gas portfolio: 3
Gas portfolio: 3
Current		13,759		105,096		10,811		62,207			7,897		96,814		10,811		62,207
Long-term		686		38,130		3,602		19,350			415		40,019		3,602		19,350
Total derivatives	$	17,575	$	376,043	$	19,553	$	231,656		$	12,413	$	363,455	$	19,553	$	231,656

___________

1	Balance sheet location: Unrealized gain on derivative instruments.
2	Balance sheet location: Unrealized loss on derivative instruments.
3	Puget Energy had a derivative liability and an offsetting regulatory asset of ~~$128.8~~$128.5 million at ~~March 31,~~June 30, 2010 and $67.1 million at December 31, 2009 related to financial contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers. All fair value adjustments on derivatives relating to the natural gas business have been reclassified to a deferred account in accordance with ASC 980, “Regulated Operations,” (ASC 980) due to the ~~PGA~~Purchased Gas Adjustment (PGA) mechanism. All increases and decreases in the cost of natural gas supply are passed on to customers with the PGA ~~mechanism. As~~mechanism and the gains and losses on the hedges ~~are realized~~ in future periods ~~they~~ will be recorded as gas ~~costs under the PGA mechanism.~~costs.

The following table presents the fair values and locations of PSE’s derivative instruments recorded on the balance sheet at ~~March 31,~~June 30, 2010 and December 31, 2009:

Derivatives Not Designated as Hedging Instruments	Derivatives Not Designated as Hedging Instruments								Derivatives Not Designated as Hedging Instruments
	at March 31, 2010				at December 31, 2009					at June 30, 2010				at December 31, 2009
Puget Sound Energy (Dollars in Thousands)	Asset Derivatives 1		Liability Derivatives 2		Asset Derivatives 1		Liability Derivatives 2			Asset Derivatives 1		Liability Derivatives 2		Asset Derivatives 1		Liability Derivatives 2
Electric portfolio:
Current	$	2,789	$	122,673	$	4,137	$	75,323		$	2,851	$	124,658	$	4,137	$	75,323
Long-term		341		104,696		1,003		70,367			1,250		101,964		1,003		70,367
Gas portfolio: 3
Current		13,759		105,096		10,811		62,207			7,897		96,814		10,811		62,207
Long-term		686		38,130		3,602		19,350			415		40,019		3,602		19,350
Total derivatives	$	17,575	$	370,595	$	19,553	$	227,247		$	12,413	$	363,455	$	19,553	$	227,247

___________

1	Balance sheet location: Unrealized gain on derivative instruments.
2	Balance sheet location: Unrealized loss on derivative instruments.
3	PSE had a derivative liability and an offsetting regulatory asset of ~~$128.8~~$128.5 million at ~~March 31,~~June 30, 2010 and $67.1 million at December 31, 2009 related to financial contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers. All fair value adjustments on derivatives relating to the natural gas business have been reclassified to a deferred account in accordance with ASC 980 due to the PGA mechanism. All increases and decreases in the cost of natural gas supply are passed on to customers with the PGA ~~mechanism. As~~mechanism and the gains and losses on the hedges ~~are realized~~ in future periods ~~they~~ will be recorded as gas ~~costs under the PGA mechanism.~~ costs.

For further details regarding the fair value of derivative instruments and their Level categorization please see Note 4 of the notes to the consolidated financial statements.

The following table presents the net unrealized ~~(gains)~~(gain)/~~losses~~loss of Puget Energy’s derivative instruments recorded on the statements of income ~~at March 31,~~for the three months ended June 30, 2010 and 2009:

				Successor			Predecessor
	March 31, 2010			February 6, 2009 – March 31, 2009			January 1, 2009 – February 5, 2009			Three Months Ended June 30, 2010			Three Months Ended June 30, 2009
Puget Energy (Dollars in Thousands)	Net Unrealized (Gain)/Loss			Net Unrealized (Gain)/Loss			Net Unrealized (Gain)/Loss			Net Unrealized (Gain)/Loss			Net Unrealized (Gain)/Loss
Gas / Power NPNS	$	(25,599	)	$	(20,583	)	$	--		$	(7,985	)	$	(15,169	)
Gas for power		48,990			5,986			3,696
Gas for power generation											(71	)		(14,543	)
Power exchange		(927	)		(894	)		(588	)		(530	)		(506	)
Power		38,184			4,518			759			(6,154	)		(20,736	)
Credit reserve		--			(1,145	)		--
Credit reserve 1											--			12,737
Total unrealized (gain)/loss	$	60,648		$	(12,118	)	$	3,867		$	(14,740	)	$	(38,217	)

___________

1	Beginning in the second quarter 2009, the credit reserve was incorporated as a component of the individual derivative value and not recorded separately.

The following table presents the net unrealized ~~(gains)~~(gain)/~~losses~~loss of Puget Energy’s derivative instruments recorded on the statements of income for the six months ended June 30, 2010 and 2009:

				Successor			Predecessor
	Six Months Ended June 30, 2010			February 6, 2009 – June 30, 2009			January 1, 2009 – February 5, 2009
Puget Energy (Dollars in Thousands)	Net Unrealized (Gain)/Loss			Net Unrealized (Gain)/Loss			Net Unrealized (Gain)/Loss
Gas / Power NPNS	$	(33,584	)	$	(35,752	)	$	--
Gas for power generation		48,919			(8,557	)		3,696
Power exchange		(1,457	)		(1,400	)		(588	)
Power		32,030			(16,218	)		759
Credit reserve 1		--			11,593			--
Total unrealized (gain)/loss	$	45,908		$	(50,334	)	$	3,867

___________

1	Beginning in the second quarter 2009, the credit reserve was incorporated as a component of the individual derivative value and not recorded separately.

The following table presents the net unrealized (gain)/loss of PSE’s derivative instruments recorded on the statements of income ~~at March 31,~~for the three months ended June 30, 2010 and 2009:

	March 31, 2010			March 31, 2009			Three Months Ended June 30, 2010			Three Months Ended June 30, 2009
Puget Sound Energy (Dollars in Thousands)	Net Unrealized (Gain)/Loss			Net Unrealized (Gain)/Loss			Net Unrealized (Gain)/Loss			Net Unrealized (Gain)/Loss
Gas for power	$	72,205		$	654
Gas for power generation							$	5,516		$	(8,968	)
Power exchange		(927	)		(1,463	)		(530	)		(512	)
Power		41,739			3,106			4,140			(489	)
Credit reserve		--			33
Credit reserve 1								--			49
Total unrealized (gain)/loss	$	113,017		$	2,330		$	9,126		$	(9,920	)

___________

1	Beginning in the second quarter 2009, the credit reserve was incorporated as a component of the individual derivative value and not recorded separately.

~~When prices are particularly volatile, as they were in~~

The following table presents the first quarter 2010, the Company expects to experience potentially significant swings in earnings. Not only were prices extremely volatile in the first quarter, they also trended progressively downward. Power prices over the tenornet unrealized (gain)/loss of PSE’s ~~outstanding~~ derivative ~~contracts were down 12.0% since December 2009, whereas gas prices were down over 24.0%. Most~~instruments recorded on the statements of income for the ~~derivative losses were attributed to the decline in gas prices. There were several market drivers contributing to the decline in gas prices. Record warm weather during the winter~~six months ~~in the west, combined with significant discoveries in natural gas supply~~ended June 30, 2010 and new technologies available in shale exploration all contributed to increase supply and drive prices down. Power price declines were mostly attrib uted to the decline in demand over the winter months as regional winter temperatures were unseasonably warm.2009:

	Six Months Ended June 30, 2010			Six Months Ended June 30, 2009
Puget Sound Energy (Dollars in Thousands)	Net Unrealized (Gain)/Loss			Net Unrealized (Gain)/Loss
Gas for power generation	$	77,721		$	(8,314	)
Power exchange		(1,457	)		(1,975	)
Power		45,879			2,617
Credit reserve 1		--			82
Total unrealized (gain)/loss	$	122,143		$	(7,590	)

___________

1	Beginning in the second quarter 2009, the credit reserve was incorporated as a component of the individual derivative value and not recorded separately.

The following tables ~~presents~~present the effect of hedging instruments on Puget Energy’s OCI and statements of income for the three months ended ~~March 31,~~June 30, 2010 and 2009:

Puget Energy Three Month Ended March 31, 2010 (Dollars in Thousands)	Amount of Gain/(Loss) Recognized in OCI on Derivatives 1			Location of Gain/(Loss) Reclassified from Accumulated OCI into Income	Amount of Gain/(Loss) Reclassified from Accumulated OCI into Income		Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
Puget Energy Three Months Ended June 30, 2010 (Dollars in Thousands)										Amount of Gain/(Loss) Recognized in OCI on Derivatives 1			Location of Gain/(Loss) Reclassified from Accumulated OCI into Income	Amount of Gain/(Loss) Reclassified from Accumulated OCI into Income			Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
Derivatives in Cash Flow Hedging Relationships	Effective Portion 2			Effective Portion 3			Ineffective Portion and Amount Excluded from Effectiveness Testing 3			Effective Portion 2			Effective Portion 3				Ineffective Portion and Amount Excluded from Effectiveness Testing 3
Interest rate contracts:	$	(17,446	)	Interest expense	$	8,534		$	--	$	(26,131	)	Interest expense	$	(8,349	)		$	--
Commodity contracts: Electric derivatives		--		Electric generation fuel		122	Net unrealized gain on derivative instruments		--		--		Electric generation fuel		--		Net unrealized gain on derivative instruments		--
Electric derivatives		--		Purchase electricity		1,396	Net unrealized loss on derivative instruments		--		--		Purchased electricity		(413	)	Net unrealized loss on derivative instruments		--
Total	$	(17,446	)		$	10,052		$	--	$	(26,131	)		$	(8,762	)		$	--

___________

1	On July 1, 2009 all electric and gas related cash flow hedge relationships were de-designated. Subsequent measurements of fair value are recorded through earnings, not OCI.
2	Changes in OCI are reported in after tax dollars.
3	A reclassification of a loss in OCI increases accumulated OCI and decreases earnings. Amounts reported are in pre-tax dollars.

Puget Energy Three Months Ended June 30, 2009 (Dollars in Thousands)	Amount of Gain/(Loss) Recognized in OCI on Derivatives			Location of Gain/(Loss) Reclassified from Accumulated OCI into Income	Amount of Gain/(Loss) Reclassified from Accumulated OCI into Income			Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
Derivatives in Cash Flow Hedging Relationships	Effective Portion 1			Effective Portion 2				Ineffective Portion and Amount Excluded from Effectiveness Testing
Interest rate contracts:	$	25,305		Interest expense	$	(7,140	)		$	--
Commodity contracts: Electric derivatives		(4,606	)	Electric generation fuel		(929	)	Net unrealized gain on derivative instruments		410
Electric derivatives		8,180		Purchased electricity		(1,048	)	Net unrealized loss on derivative instruments		1,511
Total	$	28,879			$	(9,117	)		$	1,921

___________

1	Changes in OCI are reported in after tax dollars.
2	A reclassification of a loss in OCI increases accumulated OCI and decreases earnings. Amounts reported are in pre-tax dollars.

The following tables present the effect of hedging instruments on Puget Energy’s OCI and statements of income for the six months ended June 30, 2010 and 2009:

Puget Energy Six Months Ended June 30, 2010 (Dollars in Thousands)	Amount of Gain/(Loss) Recognized in OCI on Derivatives 1			Location of Gain/(Loss) Reclassified from Accumulated OCI into Income	Amount of Gain/(Loss) Reclassified from Accumulated OCI into Income			Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
Derivatives in Cash Flow Hedging Relationships	Effective Portion 2			Effective Portion 3				Ineffective Portion and Amount Excluded from Effectiveness Testing 3
Interest rate contracts:	$	(43,577	)	Interest expense	$	(16,883	)		$	--
Commodity contracts: Electric derivatives		--		Electric generation fuel		(122	)	Net unrealized gain on derivative instruments		--
Electric derivatives		--		Purchased electricity		(1,809	)	Net unrealized loss on derivative instruments		--
Total	$	(43,577	)		$	(18,814	)		$	--

Puget Energy Successor February 6, 2009 - June 30, 2009 (Dollars in Thousands)	Amount of Gain/(Loss) Recognized in OCI on Derivatives			Location of Gain /(loss) Reclassified from Accumulated OCI into Income	Amount of Gain/(Loss) Reclassified from Accumulated OCI into Income			Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
Derivatives in Cash Flow Hedging Relationships	Effective Portion 1			Effective Portion 2				Ineffective Portion and Amount Excluded from Effectiveness Testing
Interest rate contracts:	$	(1,507	)	Interest expense	$	(12,054	)		$	--
Commodity contracts: Electric derivatives		(19,964	)	Electric generation fuel		(1,644	)	Net unrealized loss on derivative instruments		325
Electric derivatives		(6,289	)	Purchased electricity		(1,572	)	Net unrealized loss on derivative instruments		(2,897	)
Total	$	(27,760	)		$	(15,270	)		$	(2,572	)

___________

1	On July 1, 2009 all electric and gas related cash flow hedge relationships were de-designated. Subsequent measurements of fair value are recorded through earnings, not OCI.
2	Changes in OCI are reported in after tax dollars.
3	A reclassification of a loss in OCI increases accumulated OCI and decreases earnings. Amounts reported are in pre-tax dollars.

Successor February 6, 2009 -
March 31, 2009
(Dollars in Thousands)
Amount of
Gain/(Loss)
Recognized
in OCI on
Derivatives

Location of
Gain/(loss)
Reclassified
from
Accumulated
OCI into
Income
Amount of
Gain/(Loss) Reclassified
from
Accumulated
OCI into
Income

Location of
Gain/(Loss)
Recognized
in Income on
Derivatives
Amount of
Gain/(Loss) Recognized
in Income on Derivatives

Derivatives in Cash Flow
Hedging Relationships
Effective Portion 1,4

Effective Portion 2

Ineffective Portion and
Amount Excluded from
Effectiveness Testing 2, 3

Interest rate contracts: $ (23,619 ) Interest expense $ (4,914 ) $ --
Commodity contracts:
Electric derivatives
(15,378 ) Electric generation fuel (715 )
Net unrealized loss
on derivative instruments
(85 )
Electric derivatives (13,669 ) Purchased electricity (524 )
Net unrealized loss
on derivative instruments
(4,408 )
Gas derivatives -- Purchased gas --
Net unrealized loss
on derivative instruments
--
Total $ (52,666 ) $ (6,153 ) $ (4,493 )

Predecessor January 1, 2009 - February 5, 2009 (Dollars in Thousands)	Amount of Gain/(Loss) Recognized in OCI on Derivatives			Location of Gain/(Loss) Reclassified from Accumulated OCI into Income	Amount of Gain/(Loss) Reclassified from Accumulated OCI into Income			Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
Puget Energy Predecessor January 1, 2009 - February 5, 2009 (Dollars in Thousands)												Amount of Gain/(Loss) Recognized in OCI on Derivatives			Location of Gain/(Loss) Reclassified from Accumulated OCI into Income	Amount of Gain/(Loss) Reclassified from Accumulated OCI into Income			Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
Derivatives in Cash Flow Hedging Relationships	Effective Portion 1,4			Effective Portion 2				Ineffective Portion and Amount Excluded from Effectiveness Testing 2, 3				Effective Portion 1,3			Effective Portion 2				Ineffective Portion and Amount Excluded from Effectiveness Testing 2
Interest rate contracts:	$	--		Interest expense	$	(41	)		$	--		$	--		Interest expense	$	(41	)		$	--
Commodity contracts: Electric derivatives		(20,791	)	Electric generation fuel		(5,003	)	Net unrealized loss on derivative instruments		--			(20,791	)	Electric generation fuel		(5,003	)	Net unrealized loss on derivative instruments		--
Electric derivatives		(3,371	)	Purchased electricity		(1,934	)	Net unrealized loss on derivative instruments		(986	)		(3,371	)	Purchased electricity		(1,934	)	Net unrealized loss on derivative instruments		(986	)
Gas derivatives		--		Purchased gas		--		Net unrealized loss on derivative instruments		--			--		Purchased gas		--		Net unrealized loss on derivative instruments		--
Total	$	(24,162	)		$	(6,978	)		$	(986	)	$	(24,162	)		$	(6,978	)		$	(986	)

____________

1	Changes in OCI are reported in after tax dollars.
2	~~Losses~~Amounts are reported in pre-tax dollars.
3	~~Ineffective portion of long-term power supply contracts that are designated as cash flow hedges.~~
4	The balances associated with the components of accumulated other comprehensive income (loss) on Predecessor basis were eliminated as a result of push-down accounting effective February 6, 2009, when the Successor period began.

The following tables ~~presents~~present the effect of hedging instruments on PSE’s OCI and statements of income for the three months ended ~~March 31,~~June 30, 2010 and 2009:

Puget Sound Energy Three Months Ended March 31, 2010 (Dollars in Thousands)	Amount of Gain/(Loss) Recognized in OCI on Derivatives 1		Location of Gain/(Loss) Reclassified from Accumulated OCI into Income	Amount of Gain/(Loss) Reclassified from Accumulated OCI into Income			Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
Puget Sound Energy Three Months Ended June 30, 2010 (Dollars in Thousands)										Amount of Gain/(Loss) Recognized in OCI on Derivatives 1		Location of Gain/(Loss) Reclassified from Accumulated OCI into Income	Amount of Gain/(Loss) Reclassified from Accumulated OCI into Income			Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
Derivatives in Cash Flow Hedging Relationships	Effective Portion 2		Effective Portion 3				Ineffective Portion and Amount Excluded from Effectiveness Testing 3			Effective Portion 2		Effective Portion 3				Ineffective Portion and Amount Excluded from Effectiveness Testing
Interest rate contracts:	$	--	Interest expense	$	(123	)		$	--	$	--	Interest expense	$	(122	)		$	--
Commodity contracts: Electric derivatives		49	Electric generation fuel		23,262		Net unrealized gain on derivative instruments		--		404	Electric generation fuel		(4,964	)	Net unrealized gain on derivative instruments		--
Electric derivatives		--	Purchase electricity		5,990		Net unrealized loss on derivative instruments		--		--	Purchased electricity		(5,259	)	Net unrealized loss on derivative instruments		--
Total	$	49		$	29,129			$	--	$	404		$	(10,345	)		$	--

___________

1	On July 1, 2009 all electric and gas related cash flow hedge relationships were de-designated. Subsequent measurements of fair value are recorded through earnings, not OCI.
2	Changes in OCI are reported in after tax dollars.
3	A reclassification of a loss in OCI increases accumulated OCI and decreases earnings. Amounts reported are in pre-tax dollars.

Puget Sound Energy Three Months Ended June 30, 2009 (Dollars in Thousands)	Amount of Gain/(Loss) Recognized in OCI on Derivatives			Location of Gain/(Loss) Reclassified from Accumulated OCI into Income	Amount of Gain/(Loss) Reclassified from Accumulated OCI into Income			Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
Derivatives in Cash Flow Hedging Relationships	Effective Portion 1			Effective Portion 2				Ineffective Portion and Amount Excluded from Effectiveness Testing
Interest rate contracts:	$	--		Interest expense	$	(122	)		$	--
Commodity contracts: Electric derivatives		(2,242	)	Electric generation fuel		(5,462	)	Net unrealized gain on derivative instruments		--
Electric derivatives		8,188		Purchased electricity		(7,160	)	Net unrealized loss on derivative instruments		489
Total	$	5,946			$	(12,744	)		$	489

___________

1	Changes in OCI are reported in after tax dollars.
2	A reclassification of a loss in OCI increases accumulated OCI and decreases earnings. Amounts reported are in pre-tax dollars.

The following tables present the effect of hedging instruments on PSE’s OCI and statements of income for the six months ended June 30, 2010 and 2009:

Puget Sound Energy Six Months Ended June 30, 2010 (Dollars in Thousands)	Amount of Gain/(Loss) Recognized in OCI on Derivatives 1		Location of Gain/(Loss) Reclassified from Accumulated OCI into Income	Amount of Gain/(Loss) Reclassified from Accumulated OCI into Income			Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
Derivatives in Cash Flow Hedging Relationships	Effective Portion 2		Effective Portion 3				Ineffective Portion and Amount Excluded from Effectiveness Testing 3
Interest rate contracts:	$	--	Interest expense	$	(245	)		$	--
Commodity contracts: Electric derivatives		453	Electric generation fuel		(28,226	)	Net unrealized gain on derivative instruments		--
Electric derivatives		--	Purchased electricity		(11,248	)	Net unrealized loss on derivative instruments		--
Total	$	453		$	(39,719	)		$	--

___________

1	On July 1, 2009 all electric and gas related cash flow hedge relationships were de-designated. Subsequent measurements of fair value are recorded through earnings, not OCI.
2	Changes in OCI are reported in after tax dollars.
3	A reclassification of a loss in OCI increases accumulated OCI and decreases earnings. Amounts reported are in pre-tax dollars.

Puget Sound Energy Six Months Ended June 30, 2009 (Dollars in Thousands)	Amount of Gain/(Loss) Recognized in OCI on Derivatives			Location of Gain/(Loss) Reclassified from Accumulated OCI into Income	Amount of Gain/(Loss) Reclassified from Accumulated OCI into Income			Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
Derivatives in Cash Flow Hedging Relationships	Effective Portion 1			Effective Portion 2				Ineffective Portion and Amount Excluded from Effectiveness Testing
Interest rate contracts:	$	--		Interest expense	$	(245	)		$	--
Commodity contracts: Electric derivatives		(51,301	)	Electric generation fuel		(26,949	)	Net unrealized loss on derivative instruments		--
Electric derivatives		(11,302	)	Purchased electricity		(7,160	)	Net unrealized loss on derivative instruments		(2,749	)
Gas derivatives		--		Purchased gas		--		Net unrealized loss on derivative instruments		--
Total	$	(62,603	)		$	(34,354	)		$	(2,749	)

Puget Sound Energy
Three Months Ended
March 31, 2009
(Dollars in Thousands)

Amount of
Gain/(Loss) Recognized in OCI on Derivatives

Location of
Gain/(Loss)
Reclassified
from
Accumulated
OCI into
Income

Amount of
Gain/(Loss) Reclassified
from Accumulated
OCI into
Income

Location of
Gain/(Loss)
Recognized in
Income on
Derivatives

Amount of
Gain/(Loss) Recognized in Income on Derivatives

Derivatives in Cash Flow
Hedging Relationships

Effective
Portion 1
Effective Portion 2 Ineffective Portion and Amount Excluded from Effectiveness Testing 2, 3
Interest rate contracts: $ -- Interest expense $ (123 ) $ --
Commodity contracts:
Electric derivatives
(48,487 ) Electric generation fuel (21,488 ) Net unrealized loss on derivative instruments --
Electric derivatives (19,490 ) Purchased electricity -- Net unrealized loss on derivative instruments (3,238 )
Gas derivatives -- Purchased gas -- Net unrealized loss on derivative instruments --
Total $ (67,977 ) $ (21,611 ) $ (3,238 )
____________

~~____________~~

1	Changes in OCI are reported in after tax dollars.
2	~~Losses~~Amounts are reported in pre-tax dollars.
3	~~Ineffective portion of long-term power supply contracts that are designated as cash flow hedges.~~

For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. Gains and losses on the derivatives representing hedge ineffectiveness are recognized in current earnings. ~~PSE~~Puget Energy expects that ~~$62.4~~$32.5 million of losses in OCI will be reclassified into earnings within the next twelve months. ~~Puget Energy~~PSE expects that ~~$33.9~~$58.8 million of losses in OCI will be reclassified into earnings within the next twelve months. The maximum length of time over which Puget Energy and PSE are hedging their exposure to the variability in future cash flows extends to February 2015 for purchased ~~electricity~~el ectricity contracts and to January 2013 for ~~electric~~gas for power generation ~~fuel~~ contracts. For Puget Energy interest rate swaps, the maximum length extends to February 2014.

The following ~~table presents~~tables present the effect of Puget Energy’s derivatives not designated as hedging instruments on income during the three and six months ended ~~March 31,~~June 30, 2010 and 2009:

		Three Months Ended March 31, 2010			Successor February 6, 2009 - March 31, 2009			Predecessor January 1, 2009 – February 5, 2009				Three Months Ended June 30, 2010			Three Months Ended June 30, 2009
Puget Energy (Dollars in Thousands)	Location of Gain/(Loss) in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives									Location of Gain/(Loss) in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
Commodity contracts:
Electric derivatives	Net unrealized gain/(loss) on derivative instruments	$	(86,247	)	$	(3,303	)	$	(2,881	)	Net unrealized gain/(loss) on derivative instruments	$	6,754	1	$	21,126	2
	Electric generation fuel		(24,656	)		(6,028	)		(863	)	Electric generation fuel		(8,343	)		(4,976	)
	Purchased electricity		(6,723	)		(4,910	)		(243	)	Purchased electricity		(11,476	)		(11,384	)
Total		$	(117,626	)	$	(14,241	)	$	(3,987	)		$	(13,065	)	$	4,766

___________

1	Differs from the amount stated in the statements of income as it does not include ~~$25.6~~$8.0 million of amortization expense related to contracts that were recorded at fair value at the time of the merger and subsequently designated as NPNS.
2	Differs from the amount stated in the statements of income as it does not include $15.2 million of amortization expense related to contracts that were recorded at fair value at the time of the merger and subsequently designated as NPNS and $1.9 million related to hedge ineffectiveness.

		Six Months Ended June 30, 2010			Successor February 6, 2009 – June 30, 2009			Predecessor January 1, 2009 – February 5, 2009
Puget Energy (Dollars in Thousands)	Location of Gain/(Loss) in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
Commodity contracts:
Electric derivatives	Net unrealized gain/(loss) on derivative instruments	$	(79,493	)1	$	17,823	2	$	(2,881	)3
	Electric generation fuel		(33,000	)		(11,004	)		(863	)
	Purchased electricity		(18,200	)		(16,295	)		(243	)
Total		$	(130,693	)	$	(9,476	)	$	(3,987	)

___________

1	Differs from the amount stated in the statements of income as it does not include $33.6 million of amortization expense related to contracts that were recorded at fair value at the time of the merger and subsequently designated as NPNS.
2	Differs from the amount stated in the statements of income as it does not include $35.1 million of amortization expense related to contracts that were recorded at fair value at the time of the merger and subsequently designated as NPNS and $(2.6) million related to hedge ineffectiveness.
3	Differs from the amount stated in the statements of income as it does not include $(1.0) million related to hedge ineffectiveness.

The following ~~table presents~~tables present the effect of PSE’s derivatives not designated as hedging instruments on income during the three and six months ended ~~March 31,~~June 30, 2010 and 2009:

		Three Months Ended March 31, 2010			Three Months Ended March 31, 2009			Three Months Ended June 30, 2010			Three Months Ended June 30, 2009
Puget Sound Energy (Dollars in Thousands)	Location of Gain/(Loss) in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives					Location of Gain/(Loss) in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
Commodity contracts:
Electric derivatives	Net unrealized gain/(loss) on derivative instruments	$	(113,017	)	$	--	Net unrealized gain/(loss) on derivative instruments	$	(9,126	)	$	9,431	1
	Electric generation fuel		(24,656	)		908	Electric generation fuel		(8,343	)		(4,976	)
	Purchased electricity		(6,723	)		--	Purchased electricity		(11,476	)		(84	)
Total		$	(144,396	)	$	908		$	(28,945	)	$	4,371

___________

1	Differs from the amount stated in the statements of income as it does not include $0.5 million related to hedge ineffectiveness.

		Six Months Ended June 30, 2010			Six Months Ended June 30, 2009
Puget Sound Energy (Dollars in Thousands)	Location of Gain/(Loss) in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
Commodity contracts:
Electric derivatives	Net unrealized gain/(loss) on derivative instruments	$	(122,143	)	$	10,339	1
	Electric generation fuel		(33,000	)		(12,075	)
	Purchased electricity		(18,200	)		(567	)
Total		$	(173,343	)	$	(2,303	)

___________

1	Differs from the amount stated in the statements of income as it does not include $(2.7) million related to hedge ineffectiveness.

The Company had the following outstanding commodity contracts as of ~~March 31,~~June 30, 2010:

Puget Energy at ~~March 31,~~June 30, 2010	Number of Units
Derivatives designated as hedging instruments:
Interest rate swaps	$1.483 billion
Derivatives not designated as hedging instruments:
Gas derivatives1	~~287,325,265~~301,758,242 MMBtus
Electric generation fuel	~~90,425,000~~89,595,000 MMBtus
Purchased electricity	~~6,968,021~~7,847,080 MWh

Puget Sound Energy at ~~March 31,~~June 30, 2010	Number of Units
Derivatives not designated as hedging instruments:
Gas derivatives 1	~~287,325,265~~301,758,242 MMBtus
Electric generation fuel	~~90,425,000~~89,595,000 MMBtus
Purchased electricity2	~~6,742,621~~7,847,080 MWh

__________

1	Gas derivatives are deferred in accordance with ASC 980 due to the PGA mechanism.
2	~~As of March 31, 2010, there were eight forward contracts in Puget Energy’s portfolio that were not in PSE’s portfolio as a result of the revaluation of NPNS contracts at the merger date.~~

The Company is exposed to credit risk primarily through buying and selling electricity and natural 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 credit analysis, exposure measurement, exposure monitoring, and exposure mitigation.

The Company monitors counterparties that ~~are experiencing financial problems,~~ have significant swings in credit default swap rates, have credit rating changes by external rating agencies, or have changes in ~~ownership.~~ownership or are experiencing financial problems. Where deemed appropriate, the Company may request collateral or other security from its counterparties to mitigate potential credit default losses. Criteria employed in this decision include, among other things, the perceived creditworthiness of the counterparty and the expected credit exposure.

In response to the Deepwater Horizon disaster that occurred in the Gulf of Mexico in April 2010, PSE examined and continues to carefully monitor its derivative exposure to BP Energy and Anadarko Petroleum, both of whom were downgraded by credit agencies during the second quarter. As of June 30, 2010, PSE was in a net derivative liability position of $5.3 million with BP Energy and in a net derivative asset position of $0.1 million with Anadarko. All transactions related to these two counterparties are PSE energy supply purchase contracts and are marked-to-market on a daily basis.

It is possible that volatility in energy commodity prices could cause the Company to have material 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 ~~March 31,~~June 30, 2010, approximately 99.9% of the Company’s energy portfolio exposure, excluding NPNS transactions, is with counterparties that are rated at least investment grade by the major rating agencies and 0.1% are either rated below investment grade or not rated by rating agencies. The Company assesses credit risk internally for counterparties that are not rated.

The Company generally enters into the following master agreements: (1) Western Systems Power Pool (WSPP) agreements – standardized power sales contract in the electric industry; (2) International Swaps and Derivatives Association (ISDA) agreements ~~(ISDA)~~ – standardized financial gas and electric contracts; and (3) North American Energy Standards Board (NAESB) agreements ~~(NAESB)~~ – standardized physical gas contracts. The Company believes that ~~entering into~~ such agreements ~~reduces~~reduce credit risk exposure because such agreements provide for the netting and offset of monthly payments and, in the event of counterparty default, termination payments.

The Company computes credit reserves at a master agreement level (i.e., WSPP, ISDA, or NAESB) by counterparty. The Company considers external credit ratings and market factors, such as credit default swaps and bond spreads, in determination of reserves. The Company recognizes that external ratings may not always reflect how a market participant perceives a counterparty’s risk of default. The Company uses both default factors published by Standard & Poor’s (S&P) and factors derived through analysis of market risk, which reflect the application of an industry standard recovery rate. The Company selects a default factor by counterparty at an aggregate master agreement level based on a weighted average default tenor for that counterparty’s deals. ; The default tenor is used by weighting fair values and contract tenors for all deals for each counterparty and coming up with an average value. The default factor used is dependent upon whether the counterparty is in a net asset or a net liability position after applying the master agreement levels.

The Company applies the counterparty’s default factor to compute credit reserves for counterparties that are in a net asset position. Moreover, the Company applies its own default factor to compute credit reserves for counterparties that are in a net asset position. Credit reserves are booked as ~~contract~~contra accounts to unrealized gain (loss) positions. As of ~~March 31,~~June 30, 2010, the Company was in a net liability position with the majority of counterparties, so the default factors of counterparties did not have a significant impact on reserves for the year. The majority of the Company’s derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating ~~Council.~~Council (WECC). Despite its net liability position, PSE was n ot required to post any additional collateral with any of its counterparties. Additionally, PSE did not trigger any collateral requirements with any of its counterparties nor were any of PSE’s counterparties required to post additional collateral resulting from credit rating downgrades.

~~The~~As of June 30, 2010, the Company ~~enters into~~did not have any outstanding energy supply contracts with ~~various~~counterparties that contained credit risk related contingent features, which could result in a counterparty requesting immediate payment or demanding immediate and ongoing full overnight collateralization on derivative instruments in a net liability position.

The tables below present the fair value of the overall contractual contingent liability positions for the Company’s derivative activity at ~~March 31,~~June 30, 2010:

Puget Energy Contingent Feature (Dollars in Thousands)	Fair Value 1 Liability			Posted Collateral		Contingent Collateral		Fair Value 1 Liability			Posted Collateral		Contingent Collateral
Credit rating 2	$	(41,975	)	$	--	$	41,975	$	(34,103	)	$	--	$	34,103
Reasonable grounds for adequate assurance		(71,908	)		--		--
Requested credit for adequate assurance									(74,070	)		--		--
Forward value of contract 3		(21,262	)		--		--		(20,149	)		--		--
Total	$	(135,145	)	$	--	$	41,975	$	(128,322	)	$	--	$	34,103

Puget Sound Energy Contingent Feature (Dollars in Thousands)	Fair Value 1 Liability			Posted Collateral		Contingent Collateral		Fair Value 1 Liability			Posted Collateral		Contingent Collateral
Credit rating 2	$	(36,527	)	$	--	$	36,527	$	(34,103	)	$	--	$	34,103
Reasonable grounds for adequate assurance		(71,908	)		--		--
Requested credit for adequate assurance									(74,070	)		--		--
Forward value of contract 3		(21,262	)		--		--		(20,149	)				--
Total	$	(129,697	)	$	--	$	36,527	$	(128,322	)	$	--	$	34,103

__________

1	Represents derivative fair values of contracts with contingent features for counterparties in net derivative liability positions at ~~March 31,~~June 30, 2010. Excludes NPNS, accounts payable and accounts receivable liability.
2	PSE is required to maintain an investment grade credit rating from each of the major credit rating agencies.
3	Collateral requirements may vary, based on changes in forward value of underlying transactions.

(4)	Fair Value Measurements

ASC 820, “Fair Value Measurements and Disclosures” (ASC 820), established a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy defined by ASC 820 are as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and listed equities. Equity securities that are also classified as cash equivalents are considered Level 1 if there are unadjusted quoted prices in active markets for identical assets or liabilities.

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are ~~executed~~execut ed in the ~~marketpla ce.~~marketplace. Instruments in this category include non-exchange-traded derivatives such as over-the-counter forwards and options.

Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. At each balance sheet date, Puget Energy and PSE perform an analysis of all instruments subject to ASC 820 and include in Level 3 all of those instruments whose fair value is based on significant unobservable inputs.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. If a fair value measurement relies on inputs from different levels of the hierarchy, the entire measurement must be placed based on the lowest level input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. On a daily basis, the Company obtains quoted forward prices for the electric and natural gas market from an independent external pricing service. These forward price quotes are then used in addition to other various inputs to determine the reported fair values. Some of the inputs include the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), assumptions for time value, and also the impact of the Company’s nonperformance risk of its liabilities.

As of ~~March 31,~~June 30, 2010, the Company considered the markets for its electric and natural gas Level 2 derivative instruments to be actively traded. Management’s assessment is based on the trading activity volume in real-time and forward electric and natural gas markets. The Company regularly confirms the validity of pricing service quoted prices (e.g., Level 2 in the fair value hierarchy) used to value commodity contracts to the actual prices of commodity contracts entered into during the most recent quarter.

The following tables set forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis and the reconciliation of the changes in the fair value of derivatives classified as Level 3 in the fair value hierarchy as of ~~March 31,~~June 30, 2010 and December 31, 2009:

Puget Energy Recurring Fair Value Measures	at Fair Value as of March 31, 2010								at Fair Value as of December 31, 2009								at Fair Value as of June 30, 2010								at Fair Value as of December 31, 2009
(Dollars in Thousands)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	--	$	156	$	2,974	$	3,130	$	--	$	2,469	$	2,671	$	5,140	$	--	$	928	$	3,173	$	4,101	$	--	$	2,469	$	2,671	$	5,140
Gas derivative instruments		--		13,470		975		14,445		--		14,298		115		14,413		--		7,339		973		8,312		--		14,298		115		14,413
Cash equivalents		49,380		5,467		--		54,847		38,835		5,465		--		44,300		93,422		5,375		--		98,797		38,835		5,465		--		44,300
Restricted cash		713		--		--		713		3,305		--		--		3,305		1,312		--		--		1,312		3,305		--		--		3,305
Interest rate derivative instruments		--		4,047		--		4,047		--		20,854		--		20,854		--		--		--		--		--		20,854		--		20,854
Total assets	$	50,093	$	23,140	$	3,949	$	77,182	$	42,140	$	43,086	$	2,786	$	88,012	$	94,734	$	13,642	$	4,146	$	112,522	$	42,140	$	43,086	$	2,786	$	88,012
Liabilities:
Electric derivative instruments	$	--	$	105,198	$	127,619	$	232,817	$	--	$	51,099	$	99,000	$	150,099	$	--	$	93,294	$	133,328	$	226,622	$	--	$	51,099	$	99,000	$	150,099
Gas derivative instruments		--		138,061		5,165		143,226		--		77,438		4,119		81,557		--		130,894		5,939		136,833		--		77,438		4,119		81,557
Interest rate derivative instruments		--		28,344		--		28,344		--		26,844		--		26,844		--		56,149		--		56,149		--		26,844		--		26,844
Total liabilities	$	--	$	271,603	$	132,784	$	404,387	$	--	$	155,381	$	103,119	$	258,500	$	--	$	280,337	$	139,267	$	419,604	$	--	$	155,381	$	103,119	$	258,500

Puget Energy Level 3 Roll-Forward Net (Liability) (Dollars in Thousands) Three Months Ended June 30,	2010			2009
Balance at beginning of period	$	(128,835	)	$	(170,431	)
Changes during period:
Realized and unrealized energy derivatives
- included in earnings		(10,017	)		6,633
- included in other comprehensive income		--			10,273
- included in regulatory assets / liabilities		(644	)		740
Purchases, issuances and settlements		5,512			7,927
Transferred into Level 3		(536	)		--
Transferred out of Level 3		(601	)		8,181
Balance at end of period	$	(135,121	)	$	(136,677	)

				Successor			Predecessor
Puget Energy Level 3 Roll-Forward Net (Liability) (Dollars in Thousands)	Six Months Ended June 30, 2010			For the Period Ended February 6, 2009 – June 30, 2009 1			For the Period Ended January 1, 2009 – February 5, 2009
Balance at beginning of period	$	(100,333	)	$	(185,813	)	$	(132,256	)
Changes during period:
Realized and unrealized energy derivatives
- included in earnings		(79,616	)		(9,746	)		(627	)
- included in other comprehensive income		--			(17,429	)		(14,821	)
- included in regulatory assets / liabilities		(839	)		(2,442	)		(1,410	)
Purchases, issuances and settlements		13,340			13,716			2,154
Transferred into Level 3		(536	)		(8,611	)		--
Transferred out of Level 3		32,863			73,648			8,560
Balance at end of period	$	(135,121	)	$	(136,677	)	$	(138,400	)

Successor Predecessor
Puget Energy
Level 3 Roll-Forward Net (Liability)
(Dollars in Thousands)
Three Months
Ended
March 31,
2010

For the Period Ended
February 6,
2009 –
March 31,
2009 1

For the Period Ended
January 1,
2009 –
February 5,
2009

Balance at beginning of period $ (100,333 ) $ (185,813 ) $ (132,256 )
Changes during period:
Realized and unrealized energy derivatives
- included in earnings (69,598 ) (16,379 ) (627 )
- included in other comprehensive income -- (27,702 ) (14,821 )
- included in regulatory assets / liabilities (196 ) (3,182 ) (1,410 )
Purchases, issuances and settlements 7,828 5,788 2,154
Transferred into Level 3 -- (8,610 ) --
Transferred out of Level 3 33,464 65,467 8,560
Balance at end of period $ (128,835 ) $ (170,431 ) $ (138,400 )

___________

1	The beginning balance for the Successor period was adjusted to reflect the impact of certain fair value adjustments from the merger transaction.

Puget Sound Energy Recurring Fair Value Measures	at Fair Value as of March 31, 2010								at Fair Value as of December 31, 2009								at Fair Value as of June 30, 2010								at Fair Value as of December 31, 2009
(Dollars in Thousands)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	--	$	156	$	2,974	$	3,130	$	--	$	2,469	$	2,671	$	5,140	$	--	$	928	$	3,173	$	4,101	$	--	$	2,469	$	2,671	$	5,140
Gas derivative instruments		--		13,470		975		14,445		--		14,298		115		14,413		--		7,339		973		8,312		--		14,298		115		14,413
Cash equivalents		49,380		5,467		--		54,847		38,835		5,465		--		44,300		93,422		5,375		--		98,797		38,835		5,465		--		44,300
Restricted cash		713		--		--		713		3,305		--		--		3,305		1,312		--		--		1,312		3,305		--		--		3,305
Total assets	$	50,093	$	19,093	$	3,949	$	73,135	$	42,140	$	22,232	$	2,786	$	67,158	$	94,734	$	13,642	$	4,146	$	112,522	$	42,140	$	22,232	$	2,786	$	67,158
Liabilities:
Electric derivative instruments	$	--	$	99,749	$	127,620	$	227,369	$	--	$	46,690	$	99,000	$	145,690	$	--	$	93,294	$	133,328	$	226,622	$	--	$	46,690	$	99,000	$	145,690
Gas derivative instruments		--		138,062		5,164		143,226		--		77,438		4,119		81,557		--		130,894		5,939		136,833		--		77,438		4,119		81,557
Total liabilities	$	--	$	237,811	$	132,784	$	370,595	$	--	$	124,128	$	103,119	$	227,247	$	--	$	224,188	$	139,267	$	363,455	$	--	$	124,128	$	103,119	$	227,247

Puget Sound Energy Level 3 Roll-Forward Net (Liability) (Dollars in Thousands) Three Months Ended June 30,	2010			2009
Balance at beginning of period	$	(128,835	)	$	(176,222	)
Changes during period:
Realized and unrealized energy derivatives
- included in earnings		(10,017	)		6,633
- included in other comprehensive income		--			15,095
- included in regulatory assets / liabilities		(644	)		1,513
Purchases, issuances and settlements		5,512			8,004
Transferred into Level 3		(536	)		(3,710	)
Transferred out of Level 3		(601	)		12,010
Balance at end of period	$	(135,121	)	$	(136,677	)

Puget Sound Energy Level 3 Roll-Forward Net (Liability) (Dollars in Thousands) Three Months Ended March 31	2010			2009
Puget Sound Energy Level 3 Roll-Forward Net (Liability) (Dollars in Thousands) Six Months Ended June 30,							2010			2009
Balance at beginning of period	$	(100,333	)	$	(132,256	)	$	(100,333	)	$	(132,256	)
Changes during period:
Realized and unrealized energy derivatives
- included in earnings		(69,598	)		(2,350	)		(79,616	)		4,283
- included in other comprehensive income		--			(53,142	)		--			(38,047	)
- included in regulatory assets / liabilities		(196	)		(7,434	)		(839	)		(5,921	)
Purchases, issuances and settlements		7,828			8,144			13,340			16,148
Transferred into Level 3		--			(3,068	)		(536	)		(6,778	)
Transferred out of Level 3		33,464			13,884			32,863			25,894
Balance at end of period	$	(128,835	)	$	(176,222	)	$	(135,121	)	$	(136,677	)

Realized gains and losses on energy derivatives for Level 3 recurring items are included in energy costs in the Company’s income statement under purchased electricity, electric generation fuel or purchased natural gas when settled.

Unrealized gains and losses for Level 3 inputs on energy derivative recurring items are included in the net unrealized (gain)/loss on derivative instruments section in the Company’s income statement and as a net unrealized (gain)/loss on derivative instruments in OCI. The Company does not believe that the fair values diverge materially from the amounts the Company currently anticipates realizing on settlement or maturity.

Certain energy derivative instruments are classified as Level 3 in the fair value hierarchy because Level 3 inputs are significant to their fair value measurement. Energy derivatives transferred out of Level 3 represent existing assets or liabilities that were classified as Level 3 at the start of the reporting period for which the lowest significant input became observable during the current reporting period and ~~was~~were transferred into Level 2. ~~Puget Energy’s~~Conversely, energy derivatives transferred ~~out of~~into Level 3 ~~and into~~from Level 2 ~~totaled $33.5 million and $65.4 million for~~represent scenarios in which the ~~three months ended March 31, 2010 and 2009, respectively. PSE’s energy derivatives transferred out of Level 3 and into Level 2 totaled $33.5 million and $10.8 million for~~lowest significant input became unobservable during the ~~three months ended March 31, 2010 and 2009, respectiv ely.~~current reporting period. The Company had no transfers between Level 2 and Level 1 during the three and six months ended ~~March 31,~~June 30, 2010 or 2009.

(5)	Estimated Fair Value of Financial Instruments

Puget Energy

The following table presents the carrying amounts and estimated fair values of Puget Energy’s financial instruments at ~~March 31,~~June 30, 2010 and December 31, 2009:

	March 31, 2010				December 31, 2009				June 30, 2010				December 31, 2009
(Dollars in Thousands)	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Financial assets:
Cash and cash equivalents	$	78,507	$	78,507	$	78,527	$	78,527	$	132,926	$	132,926	$	78,527	$	78,527
Restricted cash		17,343		17,343		19,844		19,844		16,541		16,541		19,844		19,844
Notes receivable and other		74,072		74,072		74,063		74,063		74,161		74,161		74,063		74,063
Electric derivatives		3,130		3,130		5,140		5,140		4,101		4,101		5,140		5,140
Gas derivatives		14,445		14,445		14,413		14,413		8,312		8,312		14,413		14,413
Interest rate derivatives		4,047		4,047		20,854		20,854		--		--		20,854		20,854
Financial liabilities:
Short-term debt	$	40,000	$	40,000	$	105,000	$	105,000	$	--	$	--	$	105,000	$	105,000
Junior subordinated notes		250,000		226,155		250,000		232,684		250,000		223,515		250,000		232,684
Current maturities of long-term debt (fixed-rate)		267,000		282,154		232,000		234,632		267,000		277,462		232,000		234,632
Long-term debt (fixed-rate)		2,703,860		2,873,956		2,638,860		2,815,048		2,953,860		3,268,917		2,638,860		2,815,048
Long-term debt (variable-rate)		1,483,000		1,493,797		1,483,000		1,478,632		1,483,000		1,457,859		1,483,000		1,478,632
Electric derivatives		232,817		232,817		150,099		150,099		226,622		226,622		150,099		150,099
Gas derivatives		143,226		143,226		81,557		81,557		136,833		136,833		81,557		81,557
Interest rate derivatives		28,344		28,344		26,844		26,844		56,149		56,149		26,844		26,844

Puget Sound Energy

The following table presents the carrying amounts and estimated fair values of PSE’s financial instruments at ~~March 31,~~June 30, 2010 and December 31, 2009:

	March 31, 2010				December 31, 2009				June 30, 2010				December 31, 2009
(Dollars in Thousands)	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Financial assets:
Cash and cash equivalents	$	78,428	$	78,428	$	78,407	$	78,407	$	132,903	$	132,903	$	78,407	$	78,407
Restricted cash		17,343		17,343		19,844		19,844		16,541		16,541		19,844		19,844
Notes receivable and other		74,072		74,072		74,063		74,063		74,161		74,161		74,063		74,063
Electric derivatives		3,130		3,130		5,140		5,140		4,101		4,101		5,140		5,140
Gas derivatives		14,445		14,445		14,413		14,413		8,312		8,312		14,413		14,413
Financial liabilities:
Short-term debt	$	40,000	$	40,000	$	105,000	$	105,000	$	--	$	--	$	105,000	$	105,000
Short-term debt owed by PSE to Puget Energy 1		22,898		22,898		22,898		22,898		22,898		22,898		22,898		22,898
Junior subordinated notes		250,000		226,155		250,000		232,684		250,000		223,515		250,000		232,684
Current maturities of long-term debt (fixed-rate)		267,000		282,154		232,000		234,632		267,000		277,462		232,000		234,632
Non-current maturities of long-term debt (fixed-rate)		2,703,860		2,873,956		2,638,860		2,815,048		2,953,860		3,268,917		2,638,860		2,815,048
Electric derivatives		227,369		227,369		145,690		145,690		226,622		226,622		145,690		145,690
Gas derivatives		143,226		143,226		81,557		81,557		136,833		136,833		81,557		81,557

___________

1	Short-term debt owed by PSE to Puget Energy is eliminated upon consolidation of Puget Energy.

The fair value of the ~~senior secured~~long-term notes was estimated using U.S. Treasury yields and related current market credit spreads, interpolating to the maturity date of each issue. ~~The fair value of the junior subordinated notes was priced on a yield to call basis using a market price from an independent financial institution.~~

The carrying values of short-term debt and notes receivable are considered to be a reasonable estimate of fair value. The carrying amount of cash, which includes temporary investments with original maturities of three months or less, is also considered to be a reasonable estimate of fair value.

(6)	~~Financing Arrangements~~

~~Financing Program~~

The Company’s external financing requirements principally reflect the cash needs of its construction program, its schedule of maturing debt and certain operational needs. PSE anticipates refinancing maturing debt when due with its liquidity facilities and/or the issuance of new long-term debt. Access to funds depends upon factors such as Puget Energy’s and PSE’s credit ratings, prevailing interest rates and investor receptivity to investing in the utility industry and PSE.

~~Liquidity Facilities and Commercial Paper~~

Proceeds from PSE’s short-term borrowings and sales of commercial paper are used to provide working capital and the interim funding of utility construction programs. Puget Energy and PSE continue to have reasonable access to the capital and credit markets.

~~Puget Sound Energy Credit Facilities~~

PSE maintains three committed unsecured revolving credit facilities that provide, in the aggregate, $1.150 billion in short-term borrowing capability which mature concurrently in February 2014. Such facilities include a $400.0 million credit agreement for working capital needs, a $400.0 million credit facility for funding capital expenditures and a $350.0 million facility to support energy hedging activities.

PSE’s credit agreements contain usual and customary affirmative and negative covenants that, among other things, place limitations on its ability to incur additional indebtedness and liens, issue equity, pay dividends, transact with affiliates and make asset dispositions and investments. PSE’s credit agreements also contain financial covenants which include: a cash flow interest coverage ratio and to the extent below investment grade, a cash flow to net debt outstanding ratio (each as specified in the facilities). PSE certifies its compliance with such covenants to participating lenders each quarter. As of March 31, 2010, PSE was in compliance with all applicable covenants.

These credit facilities contain similar terms and conditions, and are syndicated among numerous committed lenders and financial institutions. The agreements provide PSE with the ability to borrow at different interest rate options and include variable fee levels. The bank credit agreements allow PSE to borrow at the bank’s prime rate or to make floating rate advances at the London Interbank Offered Rate (LIBOR) plus a spread that is based upon PSE’s credit rating. The $400.0 million working capital facility and $350.0 million credit agreement to support energy hedging allow for issuing standby letters of credit up to the entire amount of the credit agreements. The $400.0 million working capital facility also serves as a backstop for PSE’s commercial paper program.

As of March 31, 2010, PSE had $40.0 million drawn and outstanding under the $400.0 million working capital facility, no debt outstanding under the $350.0 million facility and no amounts drawn and outstanding (under letters of credit) under the $400.0 million capital expenditure facility.

~~Demand Promissory Note.~~ On June 1, 2006, PSE entered into a revolving credit facility with its parent, Puget Energy, in the form of a credit agreement and a Demand Promissory Note (Note). Under the terms of such agreement and Note, PSE may borrow up to $30.0 million from Puget Energy subject to approval by Puget Energy. 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 or (b) PSE’s senior unsecured revolving credit facility. Absent such borrowings, interest is charged at the one-month LIBOR plus 0.25%. At March 31, 2010, the out standing balance of the Note was $22.9 million. The outstanding balance and the related interest under the Note are eliminated by Puget Energy upon consolidation of PSE’s financial statements.

~~Puget Energy Credit Facilities~~

Puget Energy has entered into a $1.225 billion five-year term loan and a $1.0 billion credit facility for funding capital expenditures. Such loan and facility mature in February 2014. These credit agreements contain usual and customary affirmative and negative covenants which are similar to PSE’s credit facilities. Puget Energy’s credit agreements contain financial covenants based on the following three ratios: cash flow interest coverage, cash flow to net debt outstanding and debt service coverage (cash available for debt service to borrower interest), each as specified in the facilities. Puget Energy certifies its compliance with such covenants each quarter. As of March 31, 2010, Puget Energy was in compliance with all applicable covenants.

These facilities contain similar terms and conditions and are syndicated among numerous committed lenders and financial institutions. The agreements provide Puget Energy with the ability to borrow at different interest rate options and include variable fee levels. Borrowings may be at the bank’s prime rate or at floating rates based on LIBOR plus a spread that is based upon Puget Energy’s credit rating. Puget Energy must also pay a commitment fee on the unused portion of the $1.0 billion facility. The spreads and the commitment fee depend on Puget Energy’s credit ratings. As of the date of this report, the spread over prime rate is 1.25%, the spread to the LIBOR is 2.25% and the commitment fee is 0.84%. As of March 31, 2010, the term loan was fully dra wn and $258.0 million was outstanding under the $1.0 billion facility.

~~Long-Term Funding and Restrictive Covenants~~

~~Bond Issuances.~~ On March 8, 2010, PSE issued $325.0 million of senior notes, secured by first mortgage bonds. The notes have a term of 30 years and an interest rate of 5.795%. Net proceeds from such bond offering were used to replenish funds utilized to redeem a $225.0 million bond which matured on February 22, 2010 and carried a 7.96% interest rate. Net proceeds were also used to pay down debt under PSE’s capital expenditure credit facility.

On September 11, 2009, PSE issued $350.0 million of senior notes, secured by first mortgage bonds. The bonds have a term of 30 years and carry a 5.757% interest rate. Net proceeds from such offering were used to repay short-term debt incurred primarily for early retirement of maturing long-term debt and to fund in part the utility’s capital expenditures.

~~Dividend Payment Restrictions.~~ The payment of dividends by PSE to Puget Energy is restricted by provisions of certain covenants applicable to long-term debt contained in PSE’s electric and natural gas mortgage indentures. At March 31, 2010, approximately $428.5 million of unrestricted retained earnings was available for the payment of dividends under the most restrictive mortgage indenture covenant.

In addition, beginning February 6, 2009, pursuant to the terms of the Washington Utilities and Transportation Commission (Washington Commission) merger order, dividends may not be declared or paid if PSE’s common equity ratio, calculated on a regulatory basis, is 44.0% or below except to the extent a lower equity ratio is ordered by the Washington Commission. In addition, pursuant to the merger order, PSE may not declare or make any distribution unless on the date of distribution PSE’s corporate credit/issuer rating is investment grade, or if its credit rating is below investment grade, PSE’s ratio of Earnings Before Interest, Tax, Depreciation and Amortization (EBITDA) to interest for the most recently ended four fiscal quarter periods prior to such date is equal to or greater than three to one.

PSE’s ability to pay dividends is also limited by the terms of its credit facilities. Under the credit facilities, PSE is not permitted to pay dividends during any Event of Default (as defined in the facilities), such as failure to comply with certain financial covenants.

Puget Energy’s ability to pay dividends to its shareholder is also limited by the merger order issued by the Washington Commission as well as by the terms of its credit facilities. Pursuant to the merger order, Puget Energy may not declare or make a distribution unless on such date Puget Energy’s ratio of consolidated EBITDA to consolidated interest expense for the four most recently ended fiscal quarters prior to such date is equal to or greater than two to one. In accordance with terms of the Puget Energy credit facilities, Puget Energy is limited to paying a dividend within an eight-day period that begins seven days following the delivery of quarterly or annual financial statements to the Facility Agent. Puget Energy is not permitted to pay dividends during any Event of Default (as defin ed in the facilities), such as failure to comply with certain financial covenants. In addition, in order to declare or pay unrestricted dividends, Puget Energy’s interest coverage ratio may not be less than 1.5 to one and its cash flow to net debt outstanding ratio may not be less than 8.25% for the 12 months ending each quarter-end. Puget Energy is also subject to other restrictions, such as a “lock up” provision that, in certain circumstances such as failure to meet certain cash flow tests, may further restrict Puget Energy’s ability to pay dividends.

~~At March 31, 2010, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.~~

~~(7)~~

Retirement Benefits

PSE has a defined benefit pension plan, covering substantially all PSE employees. Pension benefits earned are a function of age, salary and years of service. The Company also maintains a non-qualified supplemental executive retirement plan (SERP) for certain of its senior management employees. In addition to providing pension benefits, the Company provides certain health care and life insurance benefits for retired employees. These benefits are provided principally through an insurance company. The insurance premiums are based on the benefits provided during the year, and are paid primarily by retirees.

The February 6, 2009 merger of Puget Energy with Puget Holdings triggered a new basis of accounting for PSE’s retirement benefit plans in the Puget Energy consolidated financial statements. Such purchase accounting adjustments associated with the remeasurement of retirement plans are recorded at Puget Energy.

Puget Energy

The following tables summarize Puget Energy’s net periodic benefit cost for the three months ended ~~March 31:~~June 30:

Qualified Pension Benefits				Successor			Predecessor
(Dollars in Thousands)	Three Months Ended March 31, 2010			February 6, 2009 – March 31, 2009			January 1, 2009 – February 5, 2009
Three Months Ended June 30, (Dollars in Thousands)										2010			2009
Components of net periodic benefit cost:
Service cost	$	4,037		$	2,267		$	1,090		$	4,037		$	3,401
Interest cost		7,032			4,711			2,302			7,032			7,067
Expected return on plan assets		(8,206	)		(5,015	)		(3,585	)		(8,207	)		(7,523	)
Amortization of prior service cost		--			--			95
Amortization of net loss (gain)		--			--			269
Net periodic benefit cost (income)	$	2,863		$	1,963		$	171
Net periodic benefit cost										$	2,862		$	2,945

SERP Pension Benefits			Successor		Predecessor
(Dollars in Thousands)	Three Months Ended March 31, 2010		February 6, 2009 – March 31, 2009		January 1, 2009 – February 5, 2009
Three Months Ended June 30, (Dollars in Thousands)							2010			2009
Components of net periodic benefit cost:
Service cost	$	256	$	173	$	89	$	267		$	259
Interest cost		541		396		193		555			594
Amortization of prior service cost		--		--		51
Amortization of net loss (gain)		--		--		74
Net periodic benefit cost (income)	$	797	$	569	$	407
Amortization of net gain								(1	)		--
Net periodic benefit cost							$	821		$	853

Other Benefits
Three Months Ended June 30, (Dollars in Thousands)	2010			2009
Components of net periodic benefit cost:
Service cost	$	12		$	31
Interest cost		208			244
Expected return on plan assets		(130	)		(103	)
Amortization of net gain		(31	)		--
Net periodic benefit cost	$	59		$	172

The following tables summarize Puget Energy’s net periodic benefit cost for the six months ended June 30:

Qualified Pension Benefits				Successor			Predecessor
(Dollars in Thousands)	Six Months Ended June 30, 2010			February 6, 2009 – June 30, 2009 1			January 1, 2009 – February 5, 2009
Components of net periodic benefit cost:
Service cost	$	8,074		$	5,668		$	1,090
Interest cost		14,064			11,778			2,302
Expected return on plan assets		(16,413	)		(12,538	)		(3,585	)
Amortization of prior service cost		--			--			95
Amortization of net loss		--			--			269
Net periodic benefit cost	$	5,725		$	4,908		$	171

SERP Pension Benefits				Successor		Predecessor
(Dollars in Thousands)	Six Months Ended June 30, 2010			February 6, 2009 – June 30, 2009 1		January 1, 2009 – February 5, 2009
Components of net periodic benefit cost:
Service cost	$	523		$	432	$	89
Interest cost		1,096			990		193
Amortization of prior service cost		--			--		51
Amortization of net loss (gain)		(1	)		--		74
Net periodic benefit cost	$	1,618		$	1,422	$	407

Other Benefits				Successor			Predecessor
(Dollars in Thousands)	Six Months Ended June 30, 2010			February 6, 2009 – June 30, 2009 1			January 1, 2009 – February 5, 2009
Components of net periodic benefit cost:
Service cost	$	42		$	52		$	11
Interest cost		426			406			88
Expected return on plan assets		(254	)		(172	)		(37	)
Amortization of prior service cost		--			--			7
Amortization of net gain		(33	)		--			(15	)
Amortization of transition obligation		--			--			4
Net periodic benefit cost	$	181		$	286		$	58

___________

1	The disclosed information is based on an initial January 31, 2009 measurement date, and as a result, the expense numbers are shown pro-rated for the second quarter 2009.

The following table summarizes Puget Energy’s change in benefit obligation for the periods ended June 30, 2010 and December 31, 2009:

	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	June 30, 2010			December 31, 2009			June 30, 2010			December 31, 2009			June 30, 2010			December 31, 2009
Change in benefit obligation:
Benefit obligation at beginning of period	$	504,786		$	453,731		$	39,152		$	38,750		$	15,953		$	15,807
Service cost		8,075			12,469			512			951			53			114
Interest cost		14,064			25,912			1,083			2,178			440			894
Actuarial loss		--			33,458			--			1,433			86			770
Benefits paid		(15,600	)		(20,784	)		(865	)		(4,160	)		(942	)		(2,050	)
Medicare part D subsidy received		--			--			--			--			400			418
Benefit obligation at end of period	$	511,325		$	504,786		$	39,882		$	39,152		$	15,990		$	15,953

The fair value of plan assets declined from $485.7 million at December 31, 2009 to $462.0 million at June 30, 2010.

Other Benefits Successor Predecessor
(Dollars in Thousands)
Three Months
Ended
March 31,
2010

February 6,
2009 –
March 31,
2009

January 1,
2009 –
February 5,
2009

Components of net periodic benefit cost:
Service cost $ 30 $ 21 $ 11
Interest cost 218 162 88
Expected return on plan assets (124 ) (69 ) (37 )
Amortization of prior service cost -- -- 7
Amortization of net loss (gain) (2 ) -- (15 )
Amortization of transition obligation -- -- 4
Net periodic benefit cost (income) $ 122 $ 114 $ 58

Puget Sound Energy

The following table summarizes PSE’s net periodic benefit cost for the three months ended ~~March 31:~~June 30:

	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits						Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
(Dollars in Thousands)	2010			2009			2010		2009		2010			2009			2010			2009			2010		2009		2010			2009
Components of net periodic benefit cost:
Service cost	$	4,037		$	3,271		$	256	$	267	$	30		$	32		$	4,037		$	3,800		$	267	$	267	$	12		$	30
Interest cost		7,032			6,905			541		579		218			266			7,032			6,962			555		579		208			214
Expected return on plan assets		(10,994	)		(10,755	)		--		--		(124	)		(111	)		(10,994	)		(10,972	)		--		--		(130	)		(116	)
Amortization of prior service cost		185			283			141		154		33			21			185			284			175		154		(1	)		21
Amortization of net loss (gain)		1,706			808			192		221		(119	)		(46	)		1,706			1,043			154		221		(120	)		(184	)
Amortization of transition obligation		--			--			--		--		12			13			--			--			--		--		12			12
Net periodic benefit cost (income)	$	1,966		$	512		$	1,130	$	1,221	$	50		$	175		$	1,966		$	1,117		$	1,151	$	1,221	$	(19	)	$	(23	)

The following table summarizes PSE’s net periodic benefit cost for the six months ended June 30:

	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
(Dollars in Thousands)	2010			2009			2010		2009		2010			2009
Components of net periodic benefit cost:
Service cost	$	8,074		$	7,071		$	523	$	534	$	42		$	62
Interest cost		14,064			13,867			1,096		1,157		426			480
Expected return on plan assets		(21,988	)		(21,727	)		--		--		(254	)		(227	)
Amortization of prior service cost		370			567			316		308		32			41
Amortization of net loss (gain)		3,412			1,851			346		443		(239	)		(230	)
Amortization of transition obligation		--			--			--		--		24			25
Net periodic benefit cost	$	3,932		$	1,629		$	2,281	$	2,442	$	31		$	151

The following table summarizes PSE’s change in benefit obligation for the periods ended June 30, 2010 and December 31, 2009:

	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	June 30, 2010			December 31, 2009			June 30, 2010			December 31, 2009			June 30, 2010			December 31, 2009
Change in benefit obligation:
Benefit obligation at beginning of period	$	504,786		$	460,586		$	39,152		$	39,348		$	15,953		$	18,088
Service cost		8,075			14,141			512			1,068			53			125
Interest cost		14,064			27,734			1,083			2,315			440			960
Amendment		--			--			--			--			--			--
Actuarial loss (gain)		--			25,094			--			707			86			(1,296	)
Benefits paid		(15,600	)		(22,769	)		(865	)		(4,286	)		(942	)		(2,342	)
Medicare part D subsidiary received		--			--			--			--			400			418
Benefit obligation at end of period	$	511,325		$	504,786		$	39,882		$	39,152		$	15,990		$	15,953

The fair value of plan assets declined from $485.7 million at December 31, 2009 to $462.0 million at June 30, 2010.

The Company expects contributions to fund the qualified pension plan and to meet SERP and the other postretirement ~~plans~~plan obligations for the year ending December 31, 2010 to be $12.0 million, $3.0 million and $0.5 million, respectively. During the three months ended ~~March 31,~~June 30, 2010, ~~contributions by~~ the Company contributed $5.5 million to fund the qualified retirement plan and $0.4 million to meet the SERP plan requirements. During the six months ended June 30, 2010, the Company contributed $12.0 million to fund the qualified retirement plan and ~~the other postretirement plans were $6.5 million, $0.4~~$0.9 million and $0.3 million to meet the SERP and other postretirement obligations, respectively.

As a result of the Patient Protection and Affordable Care Act of 2010, PSE recorded a tax expense of $0.8 million during the six months ended June 30, 2010, related to a Medicare D subsidy that PSE receives. These subsidies have been non-taxable in the past and ~~are now~~will be subject to federal income taxes after 2012 as a result of ~~the legislation after 2012.~~such legislation.

~~(8)~~(7)

Regulation and Rates

Effective July 1, 2010, the Washington Utilities and Transportation Commission (Washington Commission) approved a change in PSE’s Wind Power Production Credit (PTC) tariff. PSE has not been able to utilize PTC’s since 2007 due to insufficient taxable income. PSE set the PTC tariff to zero which resulted in an increase in electric rates of 1.65%.

On May 20, 2010, the Washington Commission issued an order to PSE determining the use of proceeds and the related accounting in connection with PSE sale of renewable energy credits and carbon financial instruments to third parties. In its order, the Washington Commission approved the Company’s request to defer, as a regulatory liability, proceeds obtained as a result of sales of renewable energy credits and carbon financial instruments. The Washington Commission’s order authorized $3.3 million of renewable energy credit sales proceeds recorded as a regulatory liability by PSE to be used as a partial offset to PSE’s California wholesale energy sales regulatory asset and $4.6 million to fund PSE’s low income customer conservation programs, with remaining accumulated regulatory credits to date a s well as future proceeds to be amortized over a ten year period for ratemaking and accounting. Several parties to the proceeding, including PSE, have subsequently filed requests with the Washington Commission seeking reconsideration and clarification of the decision. In PSE’s request for reconsideration filed with the Washington Commission on May 28, 2010, the Company seeks correction in the manner in which the regulatory credits are treated for ratemaking and adjustment of the California wholesale energy sales regulatory offset amount to $6.5 million from $3.3 million. Other parties have requested reconsideration of the allocation of proceeds to PSE’s low income customer programs. The Washington Commission has set the matter for hearing in August 2010 with an order to be issued by August 31, 2010.

As a result of the Washington Commission’s order of May 20, 2010, PSE adjusted the carrying value of its California wholesale energy sales regulatory asset in the second quarter of 2010 by $17.8 million (from $21.1 million to $3.3 million), with the $3.3 million then offset against the Company’s renewable energy credits regulatory liability as provided in the order. The Company’s California wholesale energy sales regulatory asset represented unpaid bills for power sold into the markets maintained by the California Independent System Operator during the California Energy Crisis, the claims of which were settled along with all counterclaims against PSE in a settlement agreement approved by the Federal Energy Regulatory Commission (FERC) on July 1, 2009. PSE’s settlement with the California parties was expressly conditioned upon two other actions: (1) the California Energy Commission approval as qualifying facilities under California renewable energy rules of PSE’s Wild Horse and Hopkins Ridge wind farms; and (2) the approval by the California Public Utilities Commission of a renewable power agreement between PSE and Southern California Edison (SCE), under which PSE is selling qualifying renewable power to SCE in 2009 and 2010. PSE entered into the SCE contract in January 2009 and all required approvals for that contract were obtained by June 18, 2009. PSE similarly has sold renewable energy credits to Pacific Gas and Electric (PG&E) which were also approved by the California Public Utilities Commission. In its petition for an order authorizing the use of renewable energy credits and carbon financial instruments t o the Washington Commission, PSE sought approval for the use of $21.1 million of such proceeds as an offset against its California wholesale energy sales regulatory asset.

On April 2, 2010, the Washington Commission issued its order in PSE’s consolidated electric and natural gas general rate case filed in May 2009, supplemented by an order of clarification on April 8, 2010 approving a general rate increase for electric customers of 3.7% annually or $74.1 million. The electric general rate order also created a tariff rider intended to allow PSE to collect in electric rates $52.3 million related to the recovery of certain deferred production related costs that were part of the general ~~rates and~~rates. These costs will be fully amortized at the end of 2011. The natural gas rate increase approved was 0.8% or $10.1 million on an annual basis. The rate increase for electric and natural gas customers was effective April 8, 2010. In its order , the Washington Commission approved a weighted cost of capital of 8.1% and a capital structure that included 46.0% common equity with an after-tax return on equity of 10.1%.

The Company adopted the Simplified Service Cost Method (SSCM) in 2001 and claimed tax benefits of $71.4 million before the Internal Revenue Service (IRS) disallowed the deductions in an audit. This tax benefit had been included in rates. Customer rates were corrected to reflect the IRS denial of the adjustment and the Washington Commission had deferred the recoverability of any interest payment payable to the IRS until it was assessed. As part of the general rate order, the Washington Commission disallowed recovery of a regulatory asset related to the recovery of interest paid to the IRS associated with the loss of the ~~Simplified Service Cost Method (SSCM)~~SSCM deduction. The Company adopted SSCM in 2001 and claimed tax benefits of $71.4 million before the IRS disallowed the deductions in an audit. The Company formally appealed the audit resulting in a determination that allowed the Company to reinstate 85% of the audit adjustment. However, the IRS changed the regulations which required the Company to change from the use of SSCM to the use of a less advantageous method. As a result, PSE recorded a $6.9 million interest expense adjustment in the first quarter of 2010 reflecting the write-off of the regulatory asset.

~~(9)~~(8)

Litigation

Residential Exchange. PSE is a party to certain agreements with the Bonneville Power Administration (BPA) that provide payments under its ~~residential exchange program~~Residential Exchange Program (REP) to PSE, which PSE passes through to its residential and small farm electric customers. PSE has agreements with BPA for REP payments to 2012 and for the period 2012 to 2028. PSE and other parties have sought United States Court of Appeals for the Ninth Circuit (Ninth Circuit) review regarding BPA’s agreements for REP payments during these periods. The amounts of REP payments under these agreements and the ~~met hods~~methods utilized in setting them are subject to ~~Federal Energy Regulatory Commission (FERC)~~FERC review or judicial review, or both, and are subject to adjustment, which may affect the amount of REP payments made or to be made by BPA to PSE. It is not clear what impact, if any, these reviews or other REP-related litigation may ultimately have on PSE.

~~California Regulatory Asset.~~ PSE has held as a regulatory asset a receivable relating to unpaid bills for power sold into the markets maintained by the California Independent System Operator (CAISO). At March 31, 2010, the net receivable for such sales was $21.2 million. The collectability is subject to the outcome of the Washington Commission ruling on an accounting petition related to Renewable Energy Credits (RECs) sold to utilities in California. On October 7, 2009, PSE filed an amended accounting petition requesting that the Washington Commission authorize PSE to defer the net revenues from the sale of RECs and carbon financial instruments (collectively, REC Proceeds) and use the revenues to : (1 ) provide funding for low income energy efficiency and renewable energy services; (2) credit a portion of the REC Proceeds to the California Receivable; and (3) provide a credit to customers by offsetting the REC Proceeds against a regulatory asset. A hearing was held in March 2010 for the accounting petition. A Washington Commission order is anticipated in the second quarter of 2010.

Equilon Litigation. On April 21, 2010, Equilon Enterprises (dba Shell Oil Products), the owner of an oil refinery in Skagit County, Washington, filed suit against PSE in USthe United States District Court for the Western District of Washington in Seattle. The complaint alleges that PSE violated contractual, legal or regulatory standards in connection with a power outage that occurred on April 23, 2009, and seeks compensation for Equilon’s losses, claimed to exceed $7.0 million. ~~Western Electricity Coordinating Council (WECC)~~WECC and North American Electric Reliability Corporation (NERC) previously investigated this event, and concluded that PSE did not violate any mandatory reliability standards. PSE intends to vigorously defend this ~~litigatio n~~litigation but cannot ~~predict~~pred ict the ultimate outcome.

Colstrip Matters. In May 2003, approximately 50 plaintiffs initiated an action against the owners of Colstrip, including PSE, alleging that: (1) seepage from two different wastewater pond areas caused groundwater contamination and threatened to contaminate domestic water wells and the Colstrip water supply pond; and (2) seepage from the Colstrip water supply pond caused structural damage to buildings and toxic mold. The defendants reached agreement on a global settlement with all plaintiffs on April 29, 2008 and PSE paid its share of the settlement in July 2008.

On March 29, 2007, a second complaint related to pond seepage was filed on behalf of two ranch owners alleging damage due to the Colstrip Units 3 & 4 effluent holding pond. A mediation between plaintiffs and PPL took place on July 14, 2010 and parties are working toward a final settlement.

The federal Clean Air Mercury Rule, enacted by the Environmental Protection Agency (EPA) in May 2005, was vacated by the D.C. Circuit Court in February 2008. Final resolution of this matter is still pending. However the Montana Board of Environmental Review approved a Montana mercury control rule to limit mercury emissions from coal-fired plants on October 16, 2006 (with a limit of 0.9 lbs/Trillion British thermal units (TBtu) for plants burning coal like that used at Colstrip) which remains in effect. In 2008, the Colstrip owners, based on testing performed in 2006, 2007 and 2008, ordered mercury control equipment intended to achieve the new limit. The equipment has been fully installed and is in regular operation. The Colstrip mercury control equipment is operating at a level that meets the current Montana limit, which is based on a rolling 12 month average so compliance cannot be fully confirmed until January 1, 2011. Optimization of the feed rates of calcium bromide and activated carbon is underway. Depending on actual long-term performance, an evaluation will be conducted to determine whether additional controls, if any, are necessary.

On June 15, 2005, EPA issued the Clean Air Visibility rule to address regional haze or regionally-impaired visibility caused by multiple sources over a wide area. The rule defines Best Available Retrofit Technology (BART) requirements for electric generating units, including presumptive limits for sulfur dioxide, particulate matter and nitrogen oxide controls for larger units. In February 2007, Colstrip was notified by EPA that Colstrip Units 1 & 2 were determined to be subject to EPA’s BART requirements. PSE submitted a BART engineering analysis for Colstrip Units 1 & 2 in August 2007 and responded to an EPA request for additional analyses with an addendum in June 2008. PSE cannot yet determine the outcome.

On June 21, 2010, EPA issued a Proposed Rulemaking for the “Identification and Listing of Special Wastes: Disposal of Coal Combustion Residuals from Electric Utilities” which proposes different regulatory mechanisms by which to regulate coal combustion residuals, generally referred to as “coal ash,” and requests information from industry on these respective proposals. PSE has joined other Colstrip owners in requesting an extension to the 120 day comment period, and the owners are currently evaluating the potential impact of these regulations on operations at Colstrip. PSE’s potential increased cost of operating Colstrip is unknown at this time and dependent on the outcome of this rulemaking.

~~(10)~~(9)

Variable Interest Entities

In accordance with ASC 810, “Consolidation” (ASC 810), a business entity that has a controlling financial interest in a ~~variable interest entity (VIE)~~VIE should consolidate the VIE in its financial statements. A primary beneficiary of a VIE is the variable interest holder that has both the power to direct matters that significantly impact the activities of the VIE and has the obligation to absorb losses or the right to receive benefits. The Company enters into a variety of contracts for energy with other counterparties and evaluates all contracts to determine if they are variable interests. The Company’s variable interests primarily arise through power purchase agreements where it is required to buy all or a majority of generation from a plant at rates set forth in the agreement.

The Company evaluated its power purchase agreements and determined it was not the primary beneficiary of any VIEs. The Company had previously ~~reported~~disclosed two potentially significant variable interests in prior ~~periods,~~periods; both entities are qualifying facilities contracts that expire at the end of 2011. The Company has requested information to the relevant entities; however, they have refused to provide the necessary information to the Company, as they are not required to do so under their contracts. However, due to the short duration of the remaining life of the contracts, if the variable interests were determined to be VIEs, the Company has concluded it is not the primary beneficiary of these entities based on available ~~information. The Company~~information and it has no exposure to losses on these ~~contracts and the purchase power expense for~~contracts. 0; For the three months ended ~~Mar ch 31,~~June 30, 2010 and 2009, the ~~Company paid~~Company’s purchased power expense for these entities ~~$47.5~~was $39.6 million and ~~$47.4~~$31.7 million, respectively. For the six months ended June 30, 2010 and 2009, the Company’s purchased power expense for these entities was $87.2 million and $79.1 million, respectively.

~~(11)~~(10)

Other

Snoqualmie Falls Project.Under the Snoqualmie Falls hydroelectric facility’s federal operating license granted by FERC in 2004 and finalized in 2009, PSE is performing a major, three and a half year redevelopment project to upgrade aging energy infrastructure, enhance park and recreation amenities, and preserve cultural and historical artifacts. This project will enable Snoqualmie Falls to continue to produce clean, renewable energy for decades to come.

The substantial upgrades and enhancements to its power-generating infrastructure will include new generators, water-intake structures, penstocks and flow-control systems at Plant 1 and Plant 2. The upgrades will boost the project’s authorized output (currently 44 ~~MW)~~megawatt (MW)) to 54 MW. Plant 1 isand Plant 2 are now offline and isare expected to ~~return to service in March 2013. Plant 2 is expected to go offline in June 2010 and~~ return to service in March 2013. PSE has engaged a general contractor to perform this work on its behalf, pursuant to a guaranteed maximum price construction contract.

IBEW Union Contract. The International Brotherhood of Electrical Workers (IBEW) Local 77 union contract, which had been extended following the expiration of its March 31, 2010 term, expired on ~~March 31,~~May 18, 2010. PSE and the IBEW ~~continue to negotiate~~Local 77 have reached a tentative agreement on a new contract and ~~both parties are working under an extension~~the results of the ~~existing contract.~~IBEW vote will be known on August 31, 2010.

Bond Issuances. On June 29, 2010, PSE issued $250.0 million of senior notes, secured by first mortgage bonds. The notes have a term of 30 years and an interest rate of 5.764%. Net proceeds from the offering will be used to repay $7.0 million of medium-term notes with a 7.12% interest rate that mature on September 13, 2010 and to repay short-term debt outstanding under the $400.0 million capital expenditure credit facility.

On March 8, 2010, PSE issued $325.0 million of senior notes, secured by first mortgage bonds. The notes have a term of 30 years and an interest rate of 5.795%. Net proceeds from the offering were used to replenish funds utilized to repay $225.0 million of senior medium-term notes which matured on February 22, 2010 and carried a 7.96% interest rate. Remaining net proceeds were used to pay down debt under PSE’s capital expenditure credit facility.

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

The following discussion and analysis should be read in conjunction with the financial statements and related notes thereto included elsewhere in this report on Form 10-Q. The discussion contains forward-looking statements that involve risks and uncertainties, such as Puget Energy, Inc.’s (Puget Energy) and Puget Sound Energy, Inc.’s (PSE) objectives, expectations and intentions. Words or phrases such as “anticipates,” “believes,” “estimates,” “expects,” “plans,” “predicts,” ~~"projects,"~~“projects,” “will likely result,” “will continue” and similar expressions are intended to identify certain of these forward-looking statements. However, these words are not ~~the~~t he exclusive means of ~~identifyi ng~~identifying such statements. In addition, any statements that refer to expectations, projections or other characterizations of future events or circumstances are forward-looking statements. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this report. Puget Energy’s and PSE’s actual results could differ materially from results that may be anticipated by such forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed in the section entitled “Forward-Looking Statements” and “Risk Factors” included elsewhere in this report. Except as required by law, neither Puget Energy nor PSE undertakes an obligation to revise any forward-looking statements in order to reflect events or circumstances that may subsequently arise. Readers are urged to ~~carefully~~carefu lly review and consider the ~~var ious~~various disclosures made in this report and in Puget Energy’s and PSE’s other reports filed with the United States Securities and Exchange Commission that attempt to advise interested parties of the risks and factors that may affect Puget Energy’s and PSE’s business, prospects and results of operations.

Overview

Puget Energy is an energy services holding company and all of its operations are conducted through its subsidiary PSE, a regulated electric and natural gas utility company. PSE is the largest electric and natural gas utility in the state of Washington, primarily engaged in the business of electric transmission, distribution, generation and natural gas distribution. Puget Energy’s business strategy is to generate stable cash flows by offering reliable electric and natural gas service in a cost-effective manner through PSE. On February 6, 2009, Puget Holdings LLC (Puget Holdings) completed its merger with Puget Energy. Puget Holdings is a consortium of long-term infrastructure investors including Macquarie Infrastructure Partners I, Macquarie Infrastructure Partners II , Macquarie Capital Group Limited, Macquarie-FSS Infrastructure Trust, the Canada Pension Plan Investment Board, the British Columbia Investment Management Corporation, and the Alberta Investment Management ~~Corporation (collectively, the Consortium).~~Corporation. As a result of the merger, Puget Energy is a direct wholly owned subsidiary of Puget Equico LLC (Puget Equico), which is an indirect wholly owned subsidiary of Puget Holdings. In connection with the merger transaction, Puget Energy applied Accounting Standards Codification (ASC) No. 805, “Business Combinations” (ASC 805). PSE’s basis of accounting will continue to be on a historical basis and PSE’s financial statements will include no purchase accounting adjustments.

PSE generates revenues and cash flow primarily from the sale of electric and natural gas services to residential and commercial customers within a service territory covering approximately 6,000 square miles, principally in the Puget Sound region of the state of Washington. To meet customer growth, replacement of expiring power contracts and to meet Washington state’s renewable energy portfolio standards, PSE is increasing its energy efficiency programs to reduce the need for additional energy generation, and pursuing additional renewable energy production resources (primarily wind) and base load natural gas-fired generation to meet its needs. The Company’s external financing requirements principally reflect the cash needs of its construction program, its schedule of maturing debt ~~and~~an d certain ~~operation al~~operational needs. PSE requires access to bank and capital markets to meet its financing needs.

On May 20, 2010, the Washington Utilities and Transportation Commission (Washington Commission) issued an order to PSE determining the use of proceeds and the related accounting in connection with PSE sale of renewable energy credits and carbon financial instruments to third parties. In its order, the Washington Commission approved the Company’s request to defer, as a regulatory liability, proceeds obtained as a result of sales of renewable energy credits and carbon financial instruments. The Washington Commission’s order authorized $3.3 million of renewable energy credit sales proceeds recorded as a regulatory liability by PSE to be used as a partial offset to PSE’s California wholesale energy sales regulatory asset and $4.6 million to fund PSE’s low income customer conservation programs, wi th remaining accumulated regulatory credits to date as well as future proceeds to be amortized over a ten year period for ratemaking and accounting. Several parties to the proceeding, including PSE, have subsequently filed requests with the Washington Commission seeking reconsideration and clarification of the decision. In PSE’s request for reconsideration filed with the Washington Commission on May 28, 2010, the Company seeks correction in the manner in which the regulatory credits are treated for ratemaking and adjustment of the California wholesale energy sales regulatory offset amount to $6.5 million from $3.3 million. Other parties have requested reconsideration of the allocation of proceeds to PSE’s low income customer programs. The Washington Commission has set the matter for hearing in August 2010 with an order to be issued by August 31, 2010.

As a result of the Washington Commission’s order of May 20, 2010, PSE adjusted the carrying value of its California wholesale energy sales regulatory asset in the second quarter of 2010 by $17.8 million (from $21.1 million to $3.3 million), with the $3.3 million then offset against the Company’s renewable energy credits regulatory liability as provided in the order. The Company’s California wholesale energy sales regulatory asset represented unpaid bills for power sold into the markets maintained by the California Independent System Operator during the California Energy Crisis, the claims of which were settled along with all counter claims against PSE in a settlement agreement approved by the Federal Energy Regulatory Commission (FERC) on July 1, 2009. PSE’s settlement with the California parties was expressly conditioned upon two other actions: (1) the California Energy Commission approval as qualifying facilities under California renewable energy rules of PSE’s Wild Horse and Hopkins Ridge wind farms; and (2) the approval by the California Public Utilities Commission of a renewable power agreement between PSE and Southern California Edison (SCE), under which PSE is selling qualifying renewable power to SCE in 2009 and 2010. PSE entered into the SCE contract in January 2009 and all required approvals for that contract were obtained by June 18, 2009. PSE similarly has sold renewable energy credits to Pacific Gas and Electric (PG&E) which were also approved by the California Public Utilities Commission. In its petition for an order authorizing the use of renewable energy credits and carbon financial instruments to the Wash ington Commission, PSE sought $21.1 million of such proceeds be used as an offset against its California Wholesale Energy Sales regulatory asset.

In addition, energy derivatives had a ~~significant~~ negative impact on ~~the financial statements which caused a~~ net ~~loss~~income for the three months ended ~~March 31,~~June 30, 2010 due to continued declines in forward energy prices and a significant negative impact for the six months ended June 30, 2010. ~~Since~~As of July 1, 2009, PSE no longer ~~designates~~designated energy derivatives as cash flow hedges, ~~as of July 1, 2009,~~resulting in all of the mark-to-market changes ~~are~~being recorded in the income statement. The forward prices of electricity and natural gas over the tenor of PSE’s outstanding derivative contracts declined ~~12.0%~~13.1% and ~~24.0%~~15.3%, respectively, from December 31, 2009 which caused additional losses on energy derivative contracts for the six months ended June 30, 2010.

PSE’s electric retail kilowatt sales for the three months ended ~~March 31, 2010.~~

~~The number of~~June 30, 2010 decreased 1.3% and gas therm sales increased 10.1%, as compared to the same period in 2009. PSE’s ~~electric and~~ natural gas ~~customers continued~~sales in the three months ended June 30, 2010 were favorably impacted by colder temperatures as such sales are largely heating related but continue to ~~increase in~~be negatively impacted by use-per-customer volume declines when adjusted for temperature differences among comparison periods. For the six months ended June 30, 2010, ~~but at a significantly slower rate. Electric~~electric retail kilowatt sales and gas therm sales ~~for the three months ended March 31, 2010 declined 9.6%~~decreased 6.0% and ~~21.8%~~11.7%, respectively, as compared to the same period in 2009. The increase in electric operating revenues for the three months ended June 30, 2010, was due to the general rate case increase effec tive April 8, 2010. The increase was partially offset by the decrease in kilowatt sale volumes. The decline in ~~sales volumes in~~electric operating revenue for the six months ended 2010 is due primarily to warmer temperatures in the first quarter of 2010 and, to a lesser extent, the impact of PSE’s residential and commercial customer conservation programs, as well as continued effects of weak economic conditions in the Pacific Northwest. The average temperature in PSE’s service territory during the first ~~three months~~quarter of 2010, the quarter PSE normally experiences its highest sales volumes, was 46.8 degrees, or 6.2 degrees warmer than the same period in 2009, which was 40.6 degrees. Normal temperatures for the same period is ~~43. 5~~43.5 degrees. The Pacific Northwest also experienced below normal hydroelectric and wind conditions for the six months ended June 30, 2010 that adversely impacted PSE’s power costs in ~~the first quarter of~~ 2010. In total, for the three months ended Ju ne 30, 2010 hydroelectric and wind generation decreased by ~~310,776~~289,205 megawatt hours (MWhs) or ~~19.3%.~~13.2% while hydroelectric and wind generation decreased by 599,980 MWhs or 15.8% for the six months ended June 30, 2010.

Factors and Trends Affecting PSE’s Performance. PSE’s regulatory requirements and operational needs require the investment of substantial capital over the next several years. Because PSE intends to seek recovery of such investments through the regulatory process, ~~it is substantially dependent~~its financial results depend heavily upon positive outcomes from that process. Further, PSE’s financial performance is heavily influenced by general economic conditions in its service territory, which affect customer growth and use per customer and thus utility sales, as well as by the effects of its customers’ conservation investments, which also tend to reduce energy sales. The principal business, economic and ~~ot her~~other factors that ~~affect~~affe ct PSE’s operations and financial performance include:

·	The rates PSE is allowed to charge for its services;

·	Weather conditions;

·	Demand for electricity and natural gas among customers in PSE’s service territory;

·	Regulatory decisions allowing PSE to recover costs, including purchased power and fuel costs, on a timely basis;

·	PSE’s ability to supply electricity and natural gas, either through company-owned generation, purchase power contracts or by procuring natural gas or electricity in wholesale markets;

·	Availability and access to capital and the cost of capital;

·	Regulatory compliance costs, including those related to new and developing federal regulations of electric system reliability, state regulations of natural gas pipelines and federal and state environmental standards; and

·	The impact of energy efficiency programs on sales and margins.

Regulation of PSE Rates and Recovery of PSE Costs. The rates that PSE is allowed to charge for its services is ~~the single most~~an important item influencing its financial condition, results of operations and liquidity. PSE is highly regulated and the rates that it charges its retail customers are determined by the Washington ~~Utilities and Transportation Commission (Washington Commission).~~Commission. The Washington Commission determines these rates based, to a large extent, on historic test year costs plus weather normalized assumptions about hydro conditions and power costs in the relevant rate year. Incremental customer growth and sales are typically insufficient to provide for year-to-year cost growth, thus rate increases are required. If, in a particular rate year, PSE’s costs are higher than what is allowed to be recovered in rates, revenues may not be sufficient to permit PSE to earn its allowed return. In addition, the Washington Commission determines whether expenses and investments are reasonable and prudent in providing electric and natural gas service. If the Washington Commission determines that part of PSE’s costs do not meet the standard applied, those costs may be disallowed partially or entirely and not recovered in rates.

Electric Rates

On April 2, 2010, the Washington Commission issued its order in PSE’s consolidated electric rate case filed in May 2009, supplemented by an order of clarification on April 8, 2010 approving a general rate increase for electric customers of 3.7% annually or $74.1 million. The electric general rate order also created a tariff rider of $52.3 million related to the recovery of certain deferred production related costs that were part of general ~~rates and~~rates. These costs will be fully amortized at the end of 2011. The rate increase for electric customers was effective April 8, 2010. In its order, the Washington Commission approved a weighted cost of capital of 8.1% and a capital structure that included 46.0% common equity with a return on equity of 10.1%.

Currently, PSE has a Power Cost Adjustment (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. Excess power costs or power cost savings are apportioned between PSE and its customers pursuant to the graduated scale set forth in the PCA mechanism. As a result, if power costs are significantly higher than the baseline rate, PSE’s expenses could significantly increase.

The graduated scale is as follows:

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

The following table sets forth electric rate changes that were approved by the Washington Commission and the corresponding impact on PSE’s annual revenues based on the effective dates:

Type of Rate Adjustment	Effective Date	Average Percentage Increase (Decrease) in Rates			Annual Increase (Decrease) in Revenues (Dollars in Millions)			Effective Date	Average Percentage Increase (Decrease) in Rates	Annual Increase (Decrease) in Revenues (Dollars in Millions)
Electric General Rate Case	April 8, 2010		3.7	%	$	74.1		April 8, 2010	3.7%	$ 74.1

Gas Rates

On April 2, 2010, the Washington Commission issued its order in PSE’s natural gas general rate case filed in May 2009, approving a general rate increase ~~for natural gas customers to increase rates by~~of $10.1 million or 0.8% ~~annually or $10.1 million.~~annually. The rate increase for natural gas customers was effective April 8, 2010. In its order, the Washington Commission approved a weighted cost of capital of 8.1% and a capital structure that included 46.0% common equity with a return on equity of 10.1%.

On May 28, 2009, the Washington Commission approved a Purchased Gas Adjustment (PGA) rate decrease of $21.2 million or 1.8% annually, effective June 1, 2009. On September 24, 2009, the Washington Commission approved a PGA rate decrease of $198.1 million or 17.1% annually, effective October 1, 2009. PSE has a PGA mechanism in retail natural gas rates to recover variations in natural gas supply and transportation costs. Variations in natural gas rates are passed through to customers; therefore, PSE’s net income is not affected by such variations.

The following table sets forth gas rate changes that were approved by the Washington Commission and the corresponding impact to PSE’s annual revenues based on the effective dates:

Type of Rate Adjustment	Effective Date	Average Percentage Increase (Decrease) in Rates			Annual Increase (Decrease) in Revenues (Dollars in Millions)			Effective Date	Average Percentage Increase (Decrease) in Rates	Annual Increase (Decrease) in Revenues (Dollars in Millions)
Gas General Rate Case	April 8, 2010		0.8	%	$	10.1		April 8, 2010	0.8%	$ 10.1
Purchased Gas Adjustment	October 1, 2009		(17.1	)		(198.1	)	October 1, 2009	(17.1)	(198.1)
Purchased Gas Adjustment	June 1, 2009		(1.8	)		(21.2	)	June 1, 2009 - May 31, 2010	(1.8)	(21.2)

Weather Conditions. Weather conditions in PSE’s service territory have a significant impact on customer energy usage, affecting PSE’s revenues and energy supply expenses. PSE’s operating revenues and associated energy supply expenses are not generated evenly throughout the year. While both PSE’s electric and natural gas sales are generally greatest during winter months, variations in energy usage by customers 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 and, subsequently, higher power costs during the winter heating season in the first and ~~fou rth~~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. PSE reported ~~lower~~higher customer usage in the ~~first quarter of~~three months ended June 30, 2010 primarily due to Pacific Northwest temperatures averaging 3 degrees colder than the same period in 2009 tempered by lower customer usage when weather adjusted, reflecting a weak Pacific Northwest economy and PSE’s conservation programs. PSE reported lower customer usage for the six months ended June 30, 2010 primarily due to warmer temperatures in the Pacific Northwest during the first quarter of 2010 than the same period in 2009. The average temperature during the first quarter of 2010 was 46.8 degrees, or 6.2 degrees warmer than the same period in ~~2009.~~2009, while the average temperature for the second quarter of 2010 was 3 degrees colder than the same period in 2009.

Customer Demand. ~~Although, in the long term~~ PSE expects the number of natural gas customers to grow at rates slightly above electric ~~customers, both~~customers. Both residential electric and natural gas customers are expected to continue a long-term trend of slow decline of energy usage based on continued energy efficiency improvements and the effect of higher retail rates. The effects of the current recession on Washington’s economy have ~~accelerated~~exacerbated a decline in customer usage in the ~~first~~second quarter of 2010.

Access to Debt Capital. PSE relies on access to bank borrowings and short-term money markets as sources of liquidity and longer-term debt markets to fund its utility construction program, to meet maturing debt ~~maturing~~ obligations and other capital expenditure requirements not satisfied by cash flow from its ~~capital~~ operations or equity investment from its parent, Puget Energy. Neither Puget Energy nor PSE have any debt outstanding whose maturity would accelerate upon a credit rating downgrade. However, 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 Puget Energy’s and ~~P SE’s~~PSE’s credit facilities, both ofo f which expire in 2014, the borrowing costs and commitment fees increase as their respective credit ratings decline. If PSE is unable to access debt capital on reasonable terms, its ability to pursue improvements or acquisitions, including generating capacity, which may be relied on for future growth and to otherwise implement its strategy, could be adversely affected. PSE monitors the credit environment and expects to continue to be able to access the capital markets to meet its short-term and long-term borrowing needs.

Regulatory Compliance Costs and Expenditures. PSE’s operations are subject to extensive federal, state and local laws and regulations. Such regulations cover electric system reliability, gas pipeline system safety and energy market transparency, among other areas. Environmental regulations of air and water quality, ~~hazardous waste~~generation by-products disposal and endangered species protection also impact the Company’s operations, as would possible climate change legislation or the regulation of generation by-products, such as coal ash. PSE must spend significant sums on measures including resource planning, remediation, monitoring, pollution control equipment and emissions-related abatement and fees in order to comply with these regulatory requirements.

Compliance with these or other future regulations, such as those pertaining to climate change and ~~hazardous waste~~generation by-products could require significant capital expenditures by PSE and may adversely affect PSE’s financial position, results of operations, cash flows and liquidity.

Other Challenges and Strategies

Energy Supply. As noted in PSE’s Integrated Resource Plan (IRP) filed with the Washington Commission, PSE projects that future energy needs will exceed current resources from long-term power purchase agreements and Company-controlled power resources. The IRP identifies reductions in contractual supplies of energy and capacity available under certain long-term power purchase agreements, requiring replacement of supplies to meet projected demands. Therefore, PSE’s IRP sets forth a multi-part strategy of implementing energy efficiency programs and pursuing additional renewable resources (primarily wind) and the additional base load natural gas-fired generation to meet the growing needs of its customers. If ~~PSE~~PS E cannot acquire needed energy supply resources at a reasonable cost, it may be required to purchase additional power in the open market at a cost that could, in the absence of regulatory relief, significantly increase its expenses and reduce earnings and cash flows.

Infrastructure Investment. PSE is investing in its utility infrastructure and customer service functions in order to meet regulatory requirements, serve customers energy needs and replace aging infrastructure. These investments and operating requirements give rise to significant growth in depreciation expense and operating expense, which are not recovered through the ratemaking process in a timely manner. This “regulatory lag” is expected to continue for the foreseeable future.

Operational Risks Associated With Generating Facilities. PSE owns and operates coal, natural gas-fired, hydroelectric, wind-powered and oil-fired generating facilities. Operation of electric generating facilities involves risks that can adversely affect energy output and efficiency levels, including facility shutdowns due to equipment and process failures or fuel supply interruptions. For example, Colstrip Unit 4 was out of service from March 2009 to the end of October 2009 due to significant repair work to the unit which was discovered during its routine overhaul. As a result of this outage, PSE incurred higher power costs of approximately $16.9 million from July through October 2009. PSE does not have business interruption insurance coverage to cover replacement power costs.

Energy Efficiency Related Lost Sales Margin. PSE’s sales, margins, earnings and cash flow are adversely affected by its energy efficiency programs, many of which are mandated by law. The Company is evaluating strategies and other means to reduce or eliminate these adverse financial effects.

Markets For Intangible Power Attributes. The Company is actively engaged in monitoring the development of the commercial markets for such intangible power attributes as Renewable Energy Credits ~~(RECs)~~ and Carbon Financial Instruments. The Company supports the development of regional and national markets for such products that are free, open, transparent and liquid.

Results of Operations

The following discussion should be read in conjunction with the consolidated financial statements and the related notes included elsewhere in this document. Set forth below isare the consolidated financial results of PSE for the three and six months ended ~~March 31,~~June 30, 2010 and 2009:

Puget Sound Energy (Dollars in Thousands) Three Month Ended March 31	2010			2009			Percent Change
Puget Sound Energy (Dollars in Thousands) Three Months Ended June 30										Three Months Ended June 30, 2010			Three Months Ended June 30, 2009			Percent Change			Six Months Ended June 30, 2010			Six Months Ended June 30, 2009			Percent Change
Operating revenues:
Electric
Residential sales	$	322,242		$	358,784			(10.2	)%	$	252,564		$	240,409			5.1	%	$	574,806		$	599,193			(4.1	)%
Commercial sales		216,202			231,562			(6.6	)		198,750			197,981			0.4			414,952			429,543			(3.4	)
Industrial sales		25,443			26,551			(4.2	)		24,594			23,897			2.9			50,037			50,449			(0.8	)
Other retail sales, including unbilled revenues		(29,047	)		(29,388	)		(1.2	)		(17,507	)		(25,707	)		(31.9	)		(46,554	)		(55,095	)		(15.5	)
Total retail sales		534,840			587,509			(9.0	)		458,401			436,580			5.0			993,241			1,024,090			(3.0	)
Transportation sales		3,127			2,503			24.9			2,755			2,340			17.7			5,883			4,843			21.5
Sales to other utilities and marketers		17,208			9,351			84.0			(3,293	)		10,888			(130.2	)		13,915			20,239			(31.2	)
Other		(540	)		867			(162.3	)		5,443			6,946			(21.6	)		4,902			7,812			(37.3	)
Total electric operating revenues		554,635			600,230			(7.6	)		463,306			456,754			1.4			1,017,941			1,056,984			(3.7	)
Gas
Residential sales		214,165			344,218			(37.8	)		130,787			142,122			(8.0	)		344,952			486,341			(29.1	)
Commercial sales		91,590			139,431			(34.3	)		64,019			68,143			(6.1	)		155,609			207,574			(25.0	)
Industrial sales		9,219			14,740			(37.5	)		7,232			8,279			(12.6	)		16,452			23,018			(28.5	)
Total retail sales		314,974			498,389			(36.8	)		202,038			218,544			(7.6	)		517,013			716,933			(27.9	)
Transportation sales		3,375			3,109			8.6			3,667			3,140			16.8			7,042			6,250			12.7
Other		4,056			4,938			(17.9	)		3,742			5,238			(28.6	)		7,797			10,174			(23.4	)
Total gas operating revenues		322,405			506,436			(36.3	)		209,447			226,922			(7.7	)		531,852			733,357			(27.5	)
Non-utility operating revenues		1,166			889			31.2			534			2,604			(79.5	)		1,700			3,493			(51.3	)
Total operating revenues		878,206			1,107,555			(20.7	)		673,287			686,280			(1.9	)		1,551,493			1,793,834			(13.5	)
Operating expenses:
Energy costs:
Purchased electricity		254,307			260,249			2.3			174,977			188,918			7.4			429,284			449,167			4.4
Electric generation fuel		56,245			48,127			(16.9	)		41,692			17,832			(133.8	)		97,937			65,960			(48.5	)
Residential exchange		(22,462	)		(32,404	)		30.7			(16,875	)		(20,929	)		19.4			(39,336	)		(53,333	)		26.2
Purchased gas		176,864			320,063			44.7			106,632			132,140			19.3			283,496			452,203			37.3
Net unrealized (gain) loss on derivative instruments		113,017			2,330			*			9,126			(9,920	)		192.0			122,143			(7,590	)		*
Utility operations and maintenance		116,179			114,893			(1.1	)		122,235			122,107			(0.1	)		238,414			237,000			(0.6	)
Non-utility expense and other		1,476			1,307			(12.9	)		3,079			2,088			(47.5	)		4,553			3,395			(34.1	)
Merger and related costs		--			27,563			100.0			--			(3,655	)		*			--			23,908			*
Depreciation		70,528			65,995			(6.9	)		74,126			66,191			(12.0	)		144,654			132,186			(9.4	)
Amortization		15,468			15,366			*			19,187			16,194			(18.5	)		34,655			31,560			(9.8	)
Conservation amortization		18,153			20,829			12.8			22,329			13,730			(62.6	)		40,482			34,559			(17.1	)
Taxes other than income taxes		83,415			101,343			17.7			67,985			66,697			(1.9	)		151,401			168,039			9.9
Total operating expenses		883,190			945,661			6.6			624,493			591,393			(5.6	)		1,507,683			1,537,054			1.9
Operating income		(4,984	)		161,894			(103.1	)		48,794			94,887			(48.6	)		43,810			256,780			(82.9	)
Other income		12,000			9,932			20.8			9,814			12,387			(20.8	)		21,814			22,319			(2.3	)
Other expense		(989	)		(2,443	)		59.5			(2,085	)		(1,691	)		23.3			(3,074	)		(4,134	)		(25.6	)
Interest expense		(58,934	)		(50,968	)		15.6			(51,972	)		(48,278	)		7.7			(110,906	)		(99,246	)		11.7
Income before income taxes		(52,907	)		118,415			(144.7	)
Income tax expense		(14,633	)		33,438			143.8
Net income	$	(38,274	)	$	84,977			(145.0	)%
Income (loss) before income taxes											4,551			57,305			(92.1	)		(48,356	)		175,719			(127.5	)
Income tax (benefit) expense											4,044			13,528			70.1			(10,589	)		46,965			122.5
Net income (loss)										$	507		$	43,777			(98.8	)%	$	(37,767	)	$	128,754			(129.3	)%

__________

*	Not meaningful

Puget Sound Energy

Summary Results of Operations

PSE’s net ~~loss~~income for the three months ended ~~March 31,~~June 30, 2010 was ~~$38.3~~$0.5 million onwith operating revenues ~~from continuing operations~~ of ~~$878.2~~$673.3 million as compared to net income of ~~$85.0~~$43.8 million on operating revenues ~~from continuing operations~~ of ~~$1.1 billion~~$686.3 million for the same period in 2009. Operating revenues for the three months ended June 30, 2010 include ~~decreases~~an increase in electric operating revenues of $6.6 million despite a $17.8 million carrying value adjustment related to the California wholesale energy sales regulatory asset recorded as a reduction in sales to other utilities and marketers and a decrease in gas operating revenues of ~~$45.6 million and $184.0 million, respectively.~~ $17.5 million.

The following are significant factors impacting PSE’s net ~~income:~~

income for the three months ended June 30, 2010:

Increase in purchased electricity and electric generation fuel of ~~$2.2~~$9.9 million despite a ~~9.6%~~1.3% reduction in electric customer retail sales volumes due primarily to the use of higher cost resources. The increase in power costs is due to lower hydroelectric generation offset by wind generation which caused an increase of $9.2 million. Additionally, PSE increased the generation from combustion turbines and coal fired plants which increased production costs.

·	Increase in net unrealized loss on derivative instruments of $19.0 million primarily due to falling forward market prices of electricity and natural gas on de-designation of cash flow hedges related to PSE’s energy contracts. PSE discontinued cash flow hedge accounting July 1, 2009.

·	Increase in interest expense of $3.7 million primarily due to increase in long-term debt outstanding issued to fund PSE’s capital expenditures.

PSE’s net loss for the six months ended June 30, 2010 was $37.8 million on operating revenues of $1.6 billion as compared to the net income of $128.8 million on operating revenues of $1.8 billion for the same period in 2009. Operating revenues include a decrease in electric operating revenues of $39.0 million with a $17.8 million carrying value adjustment related to the California wholesale energy sales regulatory asset and a decrease in gas operating revenues of $201.5 million, respectively.

The following are significant factors impacting PSE’s net loss for the six months ended June 30, 2010:

Increase in purchased electricity and electric generation fuel of $12.1 million despite a 6.0% reduction in electric customer retail sales volumes due primarily to warmer temperatures in the Pacific Northwest. The increase in power costs is due to lower hydroelectric and wind generation for which replacement power costs caused an increase of ~~$13.3~~$22.5 million. Additionally, PSE increased the generation from combustion turbines and coal fired plants which ~~resulted in~~ increased ~~natural gas fuel~~production costs.

·	Increase in residential exchange credits for power costs of $9.9 million from the Bonneville Power Administration (BPA), which was a pass-through to PSE customers, reflected as a reduction in PSE electric operating revenues.

·	Increase in net unrealized loss on derivative instruments of ~~$110.7~~$129.7 million primarily due to falling forward market prices of electricity and natural gas on de-designation cash flow hedges related to PSE’s energy contracts. PSE discontinued cash flow hedge accounting July 1, 2009.

·	Increase in depreciation expense of $12.5 million primarily due to additional capital expenditures that were placed in service.

Increase in interest expense of ~~$8.0~~$11.7 million primarily due to a $6.9 million write off of a regulatory asset for deferred interest paid to the ~~IRS~~Internal Revenue Service (IRS) related to the Simplified Service Cost Method deduction in prior years which was disallowed for the rate of recovery in the general rate case order of April 2, 2010.

The above increases were partially offset by a decrease from one time merger costs of $23.9 million related to the merger of Puget Energy with Puget Holdings. These costs were primarily related to PSE employee compensation triggered by Puget Energy’s change of control, credit agreement related expenses and the impact of increases in the deferred compensation related liability.

The above changes were partially offset by a decrease from one time merger costs of $27.6 million related to the merger of Puget Energy with Puget Holdings. These costs were primarily related to PSE employee compensation triggered by Puget Energy’s change of control, credit agreement related expenses and the impact of increases in the deferred compensation related liability.

Puget Sound Energy

The following discussion provides the significant items that impact PSE’s results of operations for the three and six months ended ~~March 31,~~June 30, 2010 and 2009.

Regulated Utility Operating Revenues

Electric Operating Revenues. Electric retail sales ~~decreased $52.7~~increased $21.8 million, or ~~9.0%~~5.0%, to ~~$534.8~~$458.4 million from ~~$587.5~~$436.6 million for the three months ended ~~March 31,~~June 30, 2010 as compared to the same period in 2009. The ~~decrease in retail electricity usage of 602,275 MWhs or 9.6% related to lower customer usage, resulting in a decrease of approximately $56.6 million to electric operating revenue. The decrease~~increase was primarily due to warmer than average temperatures in the current year as compared to the same period in 2009, to a lesser extent PSE’s residential and commercial customer conservation programs and the cont inued effects of a weak Pacific Northwest economy. Average temperatures of 46.8 degrees inan electric rate increase effective April 8, 2010 were 6.2 degrees warmer than the same period in 2009. The increase in warmer temperatures translates to a 25.6% decrease in heating degree days (difference in average daily temperature compared to 65 degrees) from the prior year.which contributed $14.1 million. Also contributing to the ~~decrease~~increase is ~~a $3.6~~an $7.6 million ~~decrease~~increase related to conservation rider ~~revenues. This~~revenues and a decrease ~~was partially offset by the~~in benefits of the Residential and Farm Energy Exchange Benefit credited to customers which increased electric operating revenues by ~~$10.4~~$4.2 million. The credit also ~~reduced~~increased power costs by a corresponding amount ~~with~~wit h no impact on earnings. These increases were partially offset by a decrease in retail electricity usage of 64,575 MWhs, or 1.3%, related to lower customer usage, resulting in a decrease of approximately $6.3 million to electric operating revenue. The decrease was also due to PSE’s residential and commercial customer conservation programs and the continued effects of a weak Pacific Northwest economy and, to a lesser extent, the energy conservation program. The decrease in usage related to the continued effects of a weaker economy were somewhat offset by average temperatures which averaged 3 degrees cooler than normal for the three months ended June 30, 2010.

Sales to other utilities and marketers ~~increased $7.9~~decreased $14.2 million, ~~or 84.0%,~~ to ~~$17.2~~$(3.3) million from ~~$9.4 million. The sales volume increased by 176,658 MWh or 69.3%, which increased revenues by $7.1~~$10.9 million for the three months ended ~~March 31, 2010 as compared~~June 30, 2010. The decrease consisted of an increase in actual sales to other utilities of $3.6 million which was offset by a carrying value adjustment of $17.8 million related to PSE’s California wholesale energy sales regulatory asset. The increase in actual sales to other utilities prior to the ~~same period in 2009. The increase~~carrying value adjustment was primarily due to favorable wholesale market conditions that made it cost effective for PSE to generate energy at its company-owned combustion turbine facilities and to sell ~~into~~it in the wholesale market. ~~Prices~~

Electric retail sales decreased $30.8 million, or 3.0%, to $993.2 million from $1.0 billion for the six months ended June 30, 2010 as compared to the same period in 2009. The decrease in retail electricity usage of 666,851 MWhs or 6.0% is related to lower customer usage, resulting in a decrease of approximately $63.4 million in electric operating revenue. The decrease was primarily due to warmer than average temperatures in the first quarter of 2010 as compared to the same period in 2009 and, to a lesser extent, PSE’s residential and commercial customer conservation programs and the continued effects of a weak Pacific Northwest economy. During the first quarter of 2010, the average temperature was 46.8 degrees, or 6.2 degrees warmer than the same period in 2009, while the secon d quarter of 2010 the average temperature was 3 degrees colder than the same period in 2009. The warmer temperatures translates to an 11.8% decrease in heating degree days (difference in average daily temperature compared to 65 degrees) from the prior year. This decrease was partially offset by a $4.0 million increase related to conservation rider revenues. The decrease is also offset by the benefits of the Residential and Farm Energy Exchange Benefit credited to customers which increased electric operating revenues by $14.6 million. The credit also reduced power costs by a corresponding amount with no impact on earnings. Also offsetting the decrease was an electric rate increase effective April 8, 2010 which contributed $14.1 million.

Sales to other utilities and marketers decreased $6.3 million, or 31.2%, to $13.9 million from $20.2 million for the six months ended June 30, 2010 as compared to the same period in 2009. The decrease consisted of an increase in actual sales to other utilities of $11.5 million which was offset by carrying value adjustment of $17.8 million related to PSE’s California wholesale energy sales regulatory asset. The increase in actual sales to other utilities prior to the carrying value adjustment was primarily due to favorable wholesale market conditions that made it cost effective for PSE to generate energy at its company-owned combustion turbine facilities and to sell it in the wholesale ~~market increased from the prior year which resulted in an increase of $0.8 million.~~market.

Gas Operating Revenues.Gas retail sales decreased ~~$184.4~~$16.5 million, or ~~36.8%~~7.6%, to ~~$315.0~~$202.0 million from ~~$498.4~~$218.5 million for the three months ended ~~March 31,~~June 30, 2010 as compared to the same period in 2009. The decrease was primarily due to a ~~94.6 million or 21.8% decrease in gas therm sales which decreased revenue by $120.0 million and a $69.3~~$37.8 million decrease in gas operating revenues as a result of PGA rate decreases on June 1, 2009 and October 1, 2009 which reduced rates by 18.9%. This decrease was partially offset by a 20.5 million, or 10.1%, increase in gas therm sales which increased revenue by $25.9 million as compared to the same period in 2009. The PGA mechanism passes through to customer increases or decreases in the natural gas supply portion of the natural gas service rates based upon changes in the price of natur al gas purchased from producers and wholesale marketers or changes in natural gas pipeline transportation costs. PSE’s net income is not affected by changes under the PGA mechanism. The increase in usage was due to average temperatures which were 3 degrees cooler than normal for the three months ended June 30, 2010 tempered by a weather adjusted reduction in use-per-customer.

Gas retail sales decreased $199.9 million, or 27.9%, to $517.0 million from $716.9 million for the six months ended June 30, 2010 as compared to the same period in 2009. The decrease was primarily due to a 74.1 million, or 11.7%, decrease in gas therm sales which decreased revenue by $90.8 million and a $107.1 million decrease in gas operating revenues as a result of PGA rate decreases on June 1, 2009 and October 1, 2009. The PGA mechanism passes through to customer increases or decreases in the natural gas supply portion of the natural gas service rates based upon changes in the price of natural gas purchased ~~fr om~~from producers and wholesale marketers or changes in natural gas pipeline transportation costs. PSE’s net income is not affected by changes under the PGA mechanism. The decrease was due primarily to warmer than average temperatures in the Pacific Northwest for the current year as compared to colder than normal temperatures in 2009 and, to a lesser extent, the impact of PSE’s residential and commercial customer conservation programs and the continued effects of a weak Pacific Northwest economy.

Operating Expenses

Purchased electricityexpenses decreased ~~$5.9~~$13.9 million, or ~~2.3%~~7.4%, ~~to $254.3~~and $19.9 million, ~~from $260.3 million~~or 4.4%, for the three and six months ended ~~March 31,~~June 30, 2010, respectively, as compared to the same period in 2009. ~~This~~The decrease for the three months ended June 30, 2010 is primarily the result of PSE generating electricity from its natural gas-fired combustion turbine facilities due to higher wholesale prices as compared to the price of PSE electric generation and lower customer usage related to a weak economy in the Pacific Northwest. Offsetting the decreases were higher costs of $11.0 million associated with lower hydroelectric generation of 352,320 MWhs or 18.4% due to lower prec ipitation as compared to the same period in 2009. The decrease for the six months ended June 30, 2010 is primarily the result of lower customer usage related to warmer than normal temperatures ~~and~~in the first quarter of 2010, a weak economy in the Pacific ~~Northwest. In addition,~~Northwest and higher ~~wholesale market conditions allowed PSE to generate~~generation of electricity from ~~its~~PSE’s natural gas-fired combustion turbine ~~facilities.~~facilities due to higher wholesale prices as compared to the price of PSE’s electric generation. PSE purchases less power when the cost of natural gas is lower than the cost of wholesale electricity due to gas-fired generating facilities. ~~Off setting~~Offsetting the decreases are ~~additional~~higher costs of $22.5 million related to lower hydroelectric and wind generation. Hydroelectric and wind generation for the six months ended June 30, 2010 was lower as compared to the same period in ~~the first quarter of 2010~~2009 by ~~310,776~~599,980 MWhs or ~~19.3%~~15.8% as a result of less precipitation and wind.

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 purchase or sell power in the wholesale market. PSE manages its regulated power portfolio through short-term and intermediate-term off-system physical purchases and sales, as well as through other risk management techniques.

Electric generation fuelexpense increased ~~$8.1~~$23.9 million, or ~~16.9%~~133.8%, ~~to $56.3~~and $32.0 million, ~~from $48.1 million~~or 48.5%, for the three and six months ended ~~March 31,~~June 30, 2010, respectively, as compared to the same period in 2009. ~~This~~The increase for the three months ended June 30, 2010 was primarily due to ~~a $7.4~~an $18.5 million increase in costs related to higher volumes of electricity generation from natural gas fuel burned at PSE’s combustion turbine facilities and a $5.3 million increase related to higher generation of electricity at Colstrip due to the Unit 4 extended outage in 2009. The increase for the six months ended June 30, 2010 was primarily due to a $25.9 million increase in costs related to hi gher volumes of electricity generation from natural gas fuel costs at PSE’s combustion turbine ~~facilities. The~~facilities and a $6.0 million increase related to increased ~~cost is a result of higher~~ generation ~~from~~at Colstrip in 2010 and the Colstrip Unit 4 extended outage in 2009. Increased electric generation fuel expense at company-owned natural ~~gas-fired combustion turbines as a~~gas facilities was primarily the result of lower hydroelectric generation at facilities located on the Columbia River where PSE obtains energy produced under take-or-pay purchased electricity contracts. Also contributing to the increased costs is the increase at Colstrip due to the Unit 4 outage which was taken offline in March 2009 to conduct maintenance and ~~wind generation.~~repair. Unit 4 returned to service in November 2009.

Residential exchange credits decreased ~~$9.9~~$4.1 million ~~or 30.7%, to $(22.5) million from $(32.4)~~and $14.0 million for the three and six months ended ~~March 31,~~June 30, 2010, respectively, as compared to the same period in 2009. Associated with the ~~BPA~~Bonneville Power Administration (BPA) Residential Exchange Program (REP), the ~~increase was a~~decreases were the result of ~~an agreement with BPA to continue to pass on REP benefits to PSE’s customers.~~lower electric residential and farm customer sales volumes. REP credit is a pass-through tariff item with a corresponding credit in electric operating revenue; thus, it has no impact on net income.

Purchased gasexpenses decreased ~~$143.2~~$25.5 million, or ~~44.7%~~19.3%, ~~to $176.9~~and $168.7, million ~~from $320.1 million~~or 37.3%, for the three and six months ended ~~March 31,~~June 30, 2010, respectively, as compared to the same period in 2009. The decrease for the three months ended June 30, 2010 was primarily due to a ~~21.8%~~decrease in gas costs reflected in PGA rates. The decrease related to the reduction in PGA rates was partially offset by a 10.1% usage increase related to 3 degrees cooler than average temperatures. The decrease for the six months ended June 30, 2010 was primarily due to a 11.7% decrease in customer usage and gas costs reflected in PGA rates. The decrease in customer usage was mainly due to warmer than average temperatures in the ~~current year~~first quarter of 2010 as compared to the same period in 2009 and, to a lesser extent, the impact of PSE’s residential and commercial customer conservation programs and the continued effects of a weak Pacific Northwest economy. ~~& #160;~~The PGA mechanism provides the rates used to determine gas costs based on customer usage. The rate decrease was the result of declining costs of wholesale natural gas. The PGA mechanism allows PSE to recover expected natural gas supply and transportation costs and defer, as a receivable or liability, any natural gas supply and transportation costs that exceed or fall short of this expected gas cost amount in PGA mechanism rates, including accrued interest. The PGA mechanism payable balance at ~~March 31,~~June 30, 2010 was ~~$7.8~~$7.4 million as compared to $49.6 million at December 31, 2009. PSE is authorized by the Washington Commission to accrue carrying costs on PGA receivable and payable balances. A receivable balance in the PGA mechanism reflects an under recovery of market natural gas cost through rates. A payable balance reflects over recovery of market natural gas cost through rates.

Net unrealized loss on derivative instrumentsincreased ~~$110.7~~$19.0 million ~~to a loss of $113.0~~and $129.7 million for the three and six months ended ~~March 31,~~June 30, 2010, respectively, as compared to ~~a loss of $2.3 million during~~ the same period in 2009. The loss was mainly due to mark-to-market accounting for PSE’s energy derivative contracts which are no longer cash flow hedges. On July 1, 2009, PSE elected to de-designate its energy derivative contracts previously designated as cash flow hedges. The contracts that were de-designated were physical electric supply contracts and natural gas financial swap contracts which were used to fix the price of natural ~~gas~~ga s for electric generation. For these contracts, all future mark-to-market accounting impacts will be recognized through earnings. The amount in accumulated other comprehensive income (OCI) is transferred to earnings when the contracts settle or sooner, if management determines that the forecasted transaction is probable of not occurring. As a result, PSE will likely continue to experience the earnings ~~volatility~~impact of these reversals from OCI in future periods. ~~The~~For the three months ended June 30, 2010, the forward prices of hedge transactions declined by 2.0% related to electricity prices and 3.2% for gas prices as compared to the prior year. For the three months ended June 30, 2009, the forward price of electricity increased 5.0% and 3.9% for gas power hedge contracts as compared to March 2009 forward prices. For the six months ended June 30, 2010, the mark-to-market accounting was also impacted by declining forward energy prices over the tenor of ~~PSE’s~~P SE’s derivative contracts outstanding which decreased by ~~12.0%~~13.1% related to electricity prices and ~~24.0%~~15.3% for gas prices as compared to the prior year. ~~The~~For the six months ended June 30, 2009, the forward price ~~changes resulted in an additional $39.1 million for purchased~~of electricity ~~hedges~~increased 5.2% and ~~$71.6 million~~5.0% for gas ~~for~~ power hedge ~~contracts.~~contracts as compared to December 2008 forward prices.

Merger and related costs associated with the merger with Puget Holdings ~~recorded~~incurred for the three and six months ended June 30, 2009 was $(3.7) million and $23.9 million, respectively. For the three months ended June 30, 2009, the decrease relates to a revision to compensation costs as a result of the change in ~~the first quarter of 2009 were $27.6 million.~~control. These costs were due to one-time PSE employee compensation costs, expenses related to the termination of credit ~~agreement related expenses,~~agreements, legal fees and deferred compensation liability increases triggered by the merger. Pursuant to the Washington Commission merger order commitments, PSE did not seek recovery of these costs in retail rates.

Depreciation expense increased ~~$4.6~~$7.9 million ~~or 6.9%, to $86.0 million from $81.4~~and $12.5 million for the three and six months ended ~~March 31,~~June 30, 2010, respectively, as compared to the same ~~period~~periods in 2009. This increase was primarily due to additional capital expenditures that were placed into service.

Amortization expense increased ~~$0.1~~$3.0 million ~~which included a benefit related~~and $3.1 million for the three and six months ended June 30, 2010, respectively, due to the ~~deferral~~inclusion of Mint Farm and Wild Horse expansion ~~fixed~~operating and ownership costs in general rates effective April 8, 2010. PSE ceased deferral of ~~$1.2 million. Excluding the benefit of the regulatory deferral, amortization expense would have increased $1.3 million.~~these costs effective April 8, 2010.

Conservation amortization ~~decreased $2.7~~increased $8.6 million ~~or 12.8% to $18.2 million from $20.8~~and $5.9 million for the three and six months ended ~~March 31,~~June 30, 2010, respectively, as compared to the same ~~period~~periods in 2009. The ~~decrease~~increase was due to a lower authorized recovery of electric and natural gas conservation expenditures. Conservation amortization is a pass-through tariff item with no impact on earnings.

Taxes other than income taxes decreased ~~$17.9 million, or 17.7%, to $83.4 million from $101.3~~$16.6 million for the ~~three~~six months ended ~~March 31,~~June 30, 2010, as compared to the same period in 2009. The decrease was primarily due to a decrease in revenue sensitive ~~taxes.~~taxes due to lower retail sales.

Other Income and Interest Expense and Income Tax Expense

~~Interest expense~~Other Income ~~increased $8.0 million, or 15.6%, to $58.9 million from $50.9~~decreased $2.6 million for the three months ended ~~March 31,~~June 30, 2010, as compared to the same period in 2009. The decrease is primarily due to the carrying costs associated with the Mint Farm regulatory asset being included in general rates effective April 8, 2010. Prior to April 8, 2010, the Mint Farm regulatory asset was accruing interest income as authorized by the Washington Commission.

Interest expense increased $3.7 million and $11.7 million for the three and six months ended June 30, 2010, respectively, as compared to the same periods in 2009. The increase during the three months ended June 30, 2010 is primarily due to increased expense on long-term bonds. For the six months ended June 30, 2010, the increase was primarily due to a $6.9 million write off of a regulatory asset of deferred interest paid to the ~~Internal Revenue Service~~IRS related to the Simplified Service Cost Method deduction from prior years which was disallowed in the general rate case order of April 2, 2010. Also impacting the increase is higher long-term debt outstanding.

Income tax expense decreased ~~$48.1~~$9.5 million ~~or 143.8% to a benefit of $(14.6) million from $33.4~~and $57.6 million for the three and six months ended ~~March 31,~~June 30, 2010, respectively, as compared to the same ~~period~~periods in 2009. The decrease is primarily related to lower pre-tax income.

Puget Energy

Summary Results of Operations

All the operations of Puget Energy are conducted through its subsidiary PSE. “Predecessor” refers to the operations of Puget Energy and PSE prior to the consummation of the merger on February 6, 2009. “Successor” refers to the operations of Puget Energy and PSE subsequent to the merger.

Puget Energy’s net income for the three months ended ~~March 31~~June 30 was as follows:

(Dollars in Thousands)				Successor			Predecessor
Benefit/(Expense)	Three Months Ended March 31, 2010			February 6, 2009 – March 31, 2009			January 1, 2009 – February 5, 2009			2009 Combined			Percent Change
Benefit/(Expense) (Dollars in Thousands)																Three Months Ended June 30, 2010			Three Months Ended June 30, 2009			Percent Change
PSE reported net income	$	(38,274	)	$	53,366		$	31,611		$	84,977			145.0	%	$	507		$	43,777			(98.8	)%
Other operating revenue		--			--			--			--			--			--			358			*
Purchased electricity		145			95			--			95			52.6			144			144			0.0
Net unrealized gain on derivative instruments		52,369			10,581			--			10,581			*			23,866			28,297			(15.7	)
Non-utility expense and other		(2,126	)		(1,272	)		(4	)		(1,276	)		66.6			(1,078	)		(2,229	)		51.6
Merger and related costs		--			1,177			(20,416	)		(19,239	)		100.0			--			(3,907	)		*
Depreciation and amortization		--			--			--			--			--			--			76			*
Charitable contribution expense		--			(5,000	)		--			(5,000	)		100.0
Interest expense 1		(21,029	)		(7,816	)		25			(7,791	)		*			(22,523	)		(22,883	)		1.6
Income tax expense		(10,276	)		929			1,540			2,469			*
Income tax benefit (expense)																	2,747			(63	)		*
Puget Energy net income	$	(19,191	)	$	52,060		$	12,756		$	64,816			(129.6	)%	$	3,663		$	43,570			(91.6	)%

__________

*	Not meaningful
1	Puget Energy’s interest expense includes elimination adjustments of intercompany interest on short-term debt.

Puget Energy’s net ~~loss~~income (loss) for the six months ended June 30 was as follows:

				Successor			Predecessor
Benefit/(Expense) (Dollars in Thousands)	Six Months Ended June 30, 2010			February 6, 2009 – June 30, 2009			January 1, 2009 – February 5, 2009			2009 Combined			Percent Change
PSE reported net income (loss)	$	(37,767	)	$	97,143		$	31,611		$	128,754			(129.3	)%
Other operating revenue		--			358			--			358			*
Purchased electricity		288			241			--			241			19.5
Net unrealized gain on derivative instruments		76,235			38,878			--			38,878			96.1
Non-utility expense and other		(3,203	)		(3,502	)		(4	)		(3,506	)		8.6
Merger and related costs		--			(2,731	)		(20,416	)		(23,147	)		*
Depreciation and amortization		--			76			--			76			*
Charitable contribution expense		--			(5,000	)		--			(5,000	)		*
Interest expense 1		(43,552	)		(30,699	)		25			(30,674	)		(42.0	)
Income tax benefit (expense)		(7,529	)		866			1,540			2,406			*
Puget Energy net income (loss)	$	(15,528	)	$	95,630		$	12,756		$	108,386			(114.3	)%

__________

*	Not meaningful
1	Puget Energy’s interest expense includes elimination adjustments of intercompany interest on short-term debt.

Puget Energy’s net income for the three months ended ~~March 31,~~June 30, 2010 was ~~$19.2~~$3.7 million on operating revenues of ~~$878.2~~$673.3 million as compared to net income of ~~$64.8~~$43.6 million on operating revenues of ~~$1.1~~$686.6 million for the same period in 2009. Puget Energy’s net loss for the six months ended June 30, 2010 was $15.5 million on operating revenues of $1.6 billion as compared to net income of $108.4 million on operating revenues of $1.8 billion for the same period in 2009. The following are significant factors impacting Puget Energy’s net ~~income:~~

income (loss):

Puget Energy’s net income for the three months ended June 30, 2010 was ~~positively~~negatively impacted by ~~$41.8~~$4.4 million ~~representing a~~ change in net unrealized gain on derivative instruments as a result of the required recognition of all contracts at fair value as part of purchase accounting, including derivative contracts previously designated as Normal Purchase Normal Sale (NPNS). Certain of these contracts were subsequently redesignated as NPNS. The unrealized gain represents amortization of the fair values recorded.

~~These increases were partially offset by one-time merger costs of $19.2 million recorded~~Puget Energy’s net loss for the six months ended June 30, 2010 as compared to net income for the same period in 2009 ~~related~~was positively impacted by a $37.4 million change in net unrealized gain on derivative instruments as a result of the required recognition of all contracts at fair value as part of purchase accounting, including derivative contracts previously designated as NPNS. Certain of these contracts were subsequently redesignated as NPNS. The unrealized gain represents amortization of the fair values recorded. Puget Energy’s net income for the same period was negatively impacted by $12.9 million of interest expense due to the ~~merger of~~long-term debt at Puget Energy, ~~with Puget Holdings. These costs were primarily related to real estate excise tax, legal fees, transaction advisory services~~ and ~~stock options.~~

·	~~Net income was impacted by an increase in interest expense~~business combination fair value of ~~$13.2 million primarily related to the issuance of~~PSE’s debt, ~~at the time of the merger.~~and PSE’s deferred debt costs.

2010 compared to 2009

Operating Expenses

Net unrealized gain on derivative instruments decreased $4.4 million for the three months ended June 30, 2010 as compared to the same period in 2009, and increased ~~$41.8 million~~by $37.4 for the first six months of ended June 30, 2010 as compared to the same period in 2009 due to ~~valuation of derivative contracts as a result~~the fair value amortization of the ~~merger.~~derivative contracts.

Merger and related costs decreased ~~$19.2~~$23.1 million for the ~~three~~six months ended ~~March 31,~~June 30, 2010 as compared to the same period in 2009, due to one-time merger cost of compensation triggered by Puget Energy’s change of control, excise taxes associated with the transaction and financial advisor fees.

Other Income and Expense, Interest Expense and Income Tax Expense

Charitable contribution expense decreased $5.0 million at Puget Energy for the ~~three~~six months ended ~~March 31,~~June 30, 2010 as compared to the same period in 2009, due to a charitable contribution to the PSE Foundation in 2009.

Interest expense at Puget Energy increased ~~$13.2~~$12.9 million for the ~~three~~six months ended March 31, 2010 as compared to the same period in 2009, primarily due to the term loan and credit facility fees related to the credit facilities entered into in connection with the merger on February 6, 2009. Offsetting this increase were the business combination fair value amortization of PSE’s fair value debt, PSE’s deferred debt costs and PSE’s Treasury Lock derivative.

~~Income tax expense~~ ~~at Puget Energy decreased $12.8 million for the three months ended March 31,~~June 30, 2010 as compared to the same period in 2009 due to ~~a decrease in pre-tax income combined with a decrease~~the difference in the ~~effective~~length of time the term loan and capital expenditures loan were outstanding and the business combination fair value adjustment amortization. During the six months ended June 30, 2010, there were six months of interest on the term and capital expenditure loans and six months of business combination fair value adjustments amortization related to PSE’s long-term debt and deferred debt costs, as compared to five months for the same period in 2009. The interest expense for the term and capital expenditure loans contributed $8.3 million and the business combination fair value am ortization contributed $4.6 million.

Income tax ~~rate.~~expense at Puget Energy decreased $2.8 million for the three months ended June 30, 2010 and increased $9.9 million for the six months ended June 30, 2010, as compared to the same periods in 2009. The decrease for the three months ended June 30, 2010 is primarily related to lower pre-tax income. The increase for the six months ended June 30, 2010 is due to higher pretax income from derivative instruments.

Capital Requirements

Contractual Obligations and Commercial Commitments

With the exception of the $250.0 million senior notes issued on June 29, 2010 and the $325.0 million senior notes issued on March 8, 2010, which increased contractual obligations by $1.3 billion net of redemptions (including accrued interest through the life of the issuance), there have been no other changes from the contractual obligations and consolidated commercial commitments set forth in Part II, Item 7 in Puget Energy’s and PSE’s combined annual report on Form 10-K for the year ended December 31, 2009. The information provided in the contractual obligations and commercial commitments table ~~is incorporated herein by reference to the material~~ under “Capital ~~Requirements – Contractual Obligations and Commercial Commitments”~~Requirements” in Item 7 “Management’s Discussion and Analysis of Financial Conditions and Results of Operations” in the combined Puget Energy and PSE annual report on Form 10-K for the year ended December 31, ~~2009.~~2009 is incorporated herein by reference.

Utility Construction Program

PSE’s construction programs for generating facilities, the electric transmission system and the natural gas and electric distribution systems are designed to meet regulatory requirements and customer growth and to support reliable energy delivery. The cash flow from construction expenditures, excluding equity Allowance for Funds Used During Construction (AFUDC), was ~~$184.4~~$426.4 million for the ~~three~~six months ended ~~March 31,~~June 30, 2010. As a result of a general slowing in the economy and changes to the Company’s proposed resources PSE’s projected construction expenditures have been reduced. Presently planned utility construction expenditures, excluding AFUDC, for 2010, 2011 and 2012 are:

Capital Expenditure Projections (Dollars in Millions)	2010		2011		2012		2010		2011		2012
Energy delivery, technology and facilities	$	657	$	596	$	591	$	547	$	595	$	591
New resources		369		524		513		324		409		149
Total expenditures	$	1,026	$	1,120	$	1,104	$	871	$	1,004	$	740

The program is subject to change to respond to general business, economic and regulatory conditions. Utility construction expenditures and any new generation resource expenditures may be funded with a combination of sources that may include cash from operations, short-term debt, long-term debt and/or equity. PSE’s planned capital expenditures result in a level of spending that will likely exceed its cash flow from operations. As a result, execution of PSE’s strategy is dependent in part on continued access to the capital markets.

Capital Resources

Cash From Operations

Puget Sound Energy

Cash generated from operations for the ~~three~~six months ended ~~March 31,~~June 30, 2010 was ~~$214.3~~$401.6 million, ~~an increase~~a decrease of ~~$0.4~~$109.4 million from the ~~$213.9~~$511.0 million generated during the first ~~quarter~~six months of 2009. The ~~increase~~decrease was primarily the result of the following factors:

Accounts receivable and unbilled revenue decreased ~~$98.3~~$181.4 million during the first ~~three~~six months of 2010 compared to a decrease of ~~$46.9~~$280.2 million during the same period in 2009 ~~due to a reduction in sales and lower natural gas PGA rates~~ causing an operating cash flow ~~increase~~decrease of ~~$51.4~~$98.8 million.

·	PGA mechanism provided $42.2 million to customers during the six months ended June 30, 2010 compared to an overrecovery from customers of $54.0 million during the same period in 2009, which resulted in a decrease in cash flows from operating activities of $96.2 million.

·	PSE’s deferred taxes decreased $0.5 million in 2010 as compared to tax savings in 2009 of $68.7 million due to bonus depreciation and repair allowance deductions.

The decrease in cash generated from operating activities in 2010 was partially offset by the following:

Net payments of ~~$33.8~~$41.4 million on accounts payable during the ~~first three~~six months ofended June 30, 2010 compared to net payments of ~~$101.7~~$151.1 million during the same period in 2009 due to the timing of invoice payments, as well as variances in energy payables due to weather fluctuations, which resulted in an increase in operating cash flows of ~~$67.9~~$109.7 million.

·	A decrease in prepaid income taxes of ~~$30.4~~$13.5 million during the ~~first three~~six months ofended June 30, 2010 compared to ~~a decrease~~an increase of ~~$7.0~~$21.7 million during the same period in 2009, causing an increase in cash from operations of ~~$23.4~~$35.2 million.

~~The increase in cash generated from operating activities in 2010 was partially offset by the following:~~

Fuel and gas inventory decreased $17.7 million during the first three months of 2010 compared to a decrease of $46.9 million during the same period in 2009, which resulted in a decrease in cash from operations of $29.2 million. The decrease is due to lower customer usage in 2010 which caused a delay in recovery of the winter inventory levels.

·	PSE’s deferred taxes decreased $21.2 million in 2010 due to energy derivatives that are non-cash items as compared to tax savings in 2009 of $26.4 million due to bonus depreciation and repair allowance deductions.

PGA mechanism provided $41.8 million payment to customers related to overcollection of prior year plan related rates during the first three months of 2010 compared to an overrecovery from customers of $20.8 million during the same period in 2009, which decreased cash flow from operating activities by $62.6 million.

Puget Energy

Cash generated from operations for the ~~three~~six months ended ~~March 31,~~June 30, 2010 was ~~$351.7~~$581.8 million, ~~an increase~~a decrease of ~~$74.7~~$32.9 million from the ~~$277.0~~$614.7 million ~~generation~~generated during the first ~~quarter~~six months of 2009. The ~~increase~~decrease included ~~$0.4~~$109.4 million from the cash provided by the operating activities of PSE, discussed above. In addition, the ~~increase~~decrease was ~~primarily~~ the result of the following:

As a result of the merger, ~~$158.8~~$222.9 million in derivative settlement payments were reclassified to financing activities during the ~~first three~~six months ofended June 30, 2010 compared to ~~$147.7~~$258.2 million during the same period in 2009, resulting in ~~an increase~~a decrease in operating cash flows of ~~$11.1~~$35.3 million. These contracts represent proceeds received from derivative instruments that included financing elements at the merger date.

The decrease in cash generated from operating activities in 2010 was partially offset by the following:

·	Puget Energy ~~recognized $19.3~~made $89.8 million greater net ~~deferred income taxes and tax credits~~payments on accounts payable during the six months ended June 30, 2010 as compared to ~~2009 than PSE over~~ the same ~~period.~~period in 2009.

Financing Program

The Company’s external financing requirements principally reflect the cash needs of its construction program, its schedule of maturing debt and certain operational needs. PSE anticipates refinancing the redemption of bonds with its ~~liquidity~~credit facilities and/or the issuance of new long-term debt. Access to funds depends upon factors such as Puget Energy’s and PSE’s credit ratings, prevailing interest rates and investor receptivity to investing in the utility industry and PSE.

~~Liquidity~~Credit Facilities and Commercial Paper

Puget Sound Energy Credit Facilities

PSE maintains three committed unsecured revolving credit facilities that provide, in the aggregate, $1.150 billion in short-term borrowing capability and which mature concurrently in February 2014. Such facilities include a $400.0 million credit agreement for working capital needs, a $400.0 million credit facility for funding capital expenditures and a $350.0 million facility to support energy hedging activities.

PSE’s credit agreements contain usual and customary affirmative and negative covenants that, among other things, place limitations on its ability to incur additional indebtedness and liens, issue equity, pay dividends, transact with affiliates and make asset dispositions and investments. The credit agreements also contain financial covenants which include: a cash flow interest coverage ratio and to the extent below investment grade, a cash flow to net debt outstanding ratio (each as specified in the facilities). PSE certifies its compliance with such covenants to participating banks each quarter. As of ~~March 31,~~June 30, 2010, PSE was in compliance with all applicable covenants.

These credit facilities contain similar terms and conditions and are syndicated among numerous committed ~~lenders and financial institutions.~~lenders. The agreements provide PSE with the ability to borrow at different interest rate options and include variable fee levels. The ~~bank~~ credit agreements allow PSE to borrow at the bank’s prime rate or to make floating rate advances at the London Interbank Offered Rate (LIBOR) plus a spread that is based upon PSE’s credit rating. The $400.0 million working capital facility and $350.0 million credit agreement to support energy hedging allow for issuing standby letters of ~~credit up to the entire amount of the credit agreements.~~credit. The $400.0 million working capital facility also serves as a backstop for PSE’s commercial paper program.

In May 2010, PSE’s credit facilities were amended, in part, to include a swing line feature allowing same day availability on such borrowings up to $50.0 million. This feature does not increase the total lending commitments.

As of ~~March 31,~~June 30, 2010, PSE had ~~$40.0 million drawn and~~no debt outstanding under the $400.0 million working capital facility, no debt outstanding under the ~~$350.0~~$400.0 million capital expenditure facility and no ~~amounts~~amount drawn and outstanding ~~(under~~(including letters of credit) under the ~~$400.0~~$350.0 million ~~capital expenditure facility.~~facility supporting energy hedging. Outside of the credit agreements, PSE had a $6.2 million letter of credit in support of a long-term transmission contract. Effective July 1, 2010, the amount of this letter of credit decreased to $5.7 million.

Demand Promissory Note. On June 1, 2006, PSE entered into a revolving credit facility with its parent, Puget Energy, in the form of a credit agreement and a Demand Promissory Note (Note). Under the terms of such agreement and Note, PSE may borrow up to $30.0 million from Puget Energy subject to approval by Puget Energy. 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 or (b) PSE’s senior unsecured revolving credit facility. Absent such borrowings, interest is charged at one-month LIBOR plus 0.25%. At ~~March 31,~~June 30, 2010, the ~~outstan ding~~outstanding balance of the Note was $22.9 million. The outstanding balance and the related interest under the Note are eliminated by Puget Energy upon consolidation of PSE’s financial statements.

Puget Energy Credit Facilities

Puget Energy has entered into a $1.225 billion five-year term loan and a $1.0 billion credit facility for funding capital expenditures. Such loan and facility mature in February 2014. These credit agreements contain usual and customary affirmative and negative covenants which are similar to PSE’s credit facilities. Puget Energy’s credit agreements contain financial covenants based on the following three ratios: cash flow interest coverage, cash flow to net debt outstanding and debt service coverage (cash available for debt service to borrower interest), each as specified in the facilities. Puget Energy certifies its compliance with such covenants each quarter. As of ~~March 31,~~June 30, 2010, Puget Energy was in compliance with all applicable ~~covenants.~~covenant s.

In May 2010, Puget Energy’s credit facilities were amended, in part, to include a provision for the sharing of collateral with future note holders when notes are issued to repay and reduce the size of the bank facilities.

These facilities contain similar terms and conditions, and are syndicated among numerous committed ~~lenders and financial institutions.~~lenders. The agreements provide Puget Energy with the ability to borrow at different interest rate options and include variable fee levels. Borrowings may be at the bank’s prime rate or at floating rates based on LIBOR plus a spread that is based upon Puget Energy’s credit rating. Puget Energy must also pay a commitment fee on the unused portion of the $1.0 billion facility. The spreads and the commitment fee depend on Puget Energy’s credit ratings. As of the date of this report, the spread over prime rate is 1.25%, the spread to the LIBOR is 2.25% and the commitment fee is 0.84%. As of ~~March 31,~~June 30, 2010, the term loan was fully ~~dr awn~~drawn and ~~$258.0~~$ 258.0 million was outstanding under the $1.0 billion facility.

~~Long-Term Funding and Restrictive Covenants~~

Dividend Payment Restrictions. The payment of dividends by PSE to Puget Energy is restricted by provisions of certain covenants applicable to long-term debt contained in PSE’s electric and natural gas mortgage indentures. At ~~March 31,~~June 30, 2010, approximately ~~$428.5~~$364.8 million of unrestricted retained earnings ~~was~~were available for the payment of dividends under the most restrictive mortgage indenture covenant.

In addition, beginning February 6, 2009, pursuant to the terms of the Washington Commission merger order, dividends may not be declared or paid if PSE’s common equity ratio, calculated on a regulatory basis, is 44.0% or below except to the extent a lower equity ratio is ordered by the Washington Commission. Also, pursuant to the merger order, PSE may not declare or make any distribution unless on the date of distribution PSE’s corporate credit/issuer rating is investment grade, or, if its credit rating is below investment grade, PSE’s ratio of Earnings Before Interest, Tax, Depreciation and Amortization (EBITDA) to interest for the most recently ended four fiscal quarter periods prior to such date is equal to or greater than three to one.

Puget Energy’s ability to pay dividends to its shareholder is also limited by the merger order issued by the Washington Commission as well as by the terms of its credit facilities. Pursuant to the merger order, Puget Energy may not declare or make a distribution unless on such date Puget Energy’s ratio of consolidated EBITDA to consolidated interest expense for the four most recently ended fiscal quarters prior to such date is equal to or greater than two to one. In accordance with terms of the Puget Energy credit facilities, Puget Energy is limited to paying a dividend within an eight-day period that begins seven days following the delivery of quarterly or annual financial statements to the Facility Agent. Puget Energy is not permitted to pay dividends during any Event ofo f Default (as ~~defin ed~~defined in the facilities), such as failure to comply with certain financial covenants. In addition, in order to declare or pay unrestricted dividends, Puget Energy’s interest coverage ratio may not be less than 1.5 to one and its cash flow to net debt outstanding ratio may not be less than 8.25% for the 12 months ending each quarter-end. Puget Energy is also subject to other restrictions, such as a “lock up” provision that, in certain circumstances, such as failure to meet certain cash flow tests, may further restrict Puget Energy’s ability to pay dividends.

At ~~March 31,~~June 30, 2010, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.

Debt Restrictive Covenants. The type and amount of future long-term financing for Puget Energy and PSE are limited by provisions in their credit agreements and restated articles of incorporation as well as PSE’s mortgage indentures. Under its credit agreements, Puget Energy is generally limited to permitted refinancings and borrowings under its credit facilities and by restrictions placed upon its subsidiaries. One such restriction limits PSE’s long-term debt issuances to not exceed $500.0 million per year, plus any amount needed to refinance maturing bonds. Unused amounts under this limitation may be carried forward into future years. Puget Energy’s facilities contain a ~~pr ovision~~provision whereby additional ~~capital~~c apital expenditure loans up to $750.0 million may, under certain conditions, be made available after the $1.0 billion capital expenditure commitment has been fully borrowed.

~~PSE~~PSE’s ability to issue additional secured debt may be limited by certain restrictions contained in its ~~credit facilities, its~~ electric and natural gas mortgage ~~indentures and certain loan agreements.~~indentures. Under the most restrictive tests, at ~~March 31,~~June 30, 2010, PSE could issue:

approximately ~~$1.2~~$1.4 billion of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately ~~$2.1~~$2.3 billion of electric bondable property available for issuance, subject to an interest coverage ratio limitation of 2.0 times net earnings available for interest (as defined in the electric utility mortgage), which PSE exceeded at ~~March 31,~~June 30, 2010; and

·��

~~approximately $315.0 million of~~no additional first mortgage bonds under PSE’s natural gas mortgage ~~indenture based on~~indenture. Although PSE had approximately ~~$525.0~~$390.0 million of gas bondable property available for issuance, the Company is subject to a combined gas and electric interest coverage ~~ratio limitations~~test of 1.75 times net earnings available for interest and a gas interest coverage test of 2.0 times net earnings available for interest (as defined in the natural gas utility mortgage)~~, which~~. At June 30, 2010, PSE exceeded ~~at March 31, 2010.~~the gas 2.0 times net earnings test, but did not meet the combined 1.75 times test primarily as a result of lower energy sales and higher net power costs due to warmer than normal temperatures and lower than normal hydroelectric and wind generation. The company expects to meet this test by December 2010 as it collects additional revenues from the April 8, 20 10 rate increase for electric and natural gas customers.

At ~~March 31,~~June 30, 2010, PSE had approximately $5.5 billion in electric and natural gas ratebase to support the interest coverage ratio limitation test for net earnings available for interest.

~~Credit Ratings~~

Neither Puget Energy nor PSE have 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 Puget Energy’s and PSE’s credit facilities, the borrowing costs and commitment fee increase as their respective credit 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-2/P-3 ratings by S&P and Moody’s, respectively. In addition, downgrades in any or a combination of PSE’s debt ratings ma y prompt counterparties on a contract by contract basis in the wholesale electric, wholesale natural gas and financial derivative markets to require PSE to post a letter of credit or other collateral, make cash prepayments, obtain a guarantee or provide other mutually agreeable security.

On January 16, 2009, S&P raised its corporate credit rating on PSE to BBB from BBB- while lowering its corporate credit rating on Puget Energy to BB+ from BBB-. The rating actions reflected the anticipated completion of the acquisition of Puget Energy and PSE by Puget Holdings, which occurred on February 6, 2009. In taking this action, S&P noted that the acquisition was expected to increase total net debt by $850.0 million on a consolidated basis while reducing debt at PSE. At the same time, S&P removed both companies’ ratings from credit watch with negative implications and revised its ratings outlook to stable.

On February 2, 2009, Moody’s downgraded the issuer rating of Puget Energy from Ba2 to Ba1 and affirmed the long-term ratings of PSE. The ratings downgrade at Puget Energy reflected Moody’s concern about the increase in financial risk resulting from the additional debt being introduced from the acquisition by Puget Holdings. The ratings outlook for both companies is stable.

~~On August 3, 2009, Moody’s upgraded the senior secured debt ratings of PSE to Baa1 from Baa2.~~

~~On February 1, 2010, Moody’s reaffirmed the issuer rating on PSE at Baa3 and the issuer rating on Puget Energy at Ba2.~~

~~On February 18, 2010, S&P reaffirmed the corporate credit rating on PSE at BBB and the corporate credit rating on Puget Energy at BB+.~~

~~The ratings of Puget Energy and PSE, as of May 3, 2010 were as follows:~~

	~~Ratings~~
	~~S&P~~	~~Moody’s~~
~~Puget Sound Energy, Inc.~~
~~Corporate credit/issuer rating~~	~~BBB~~	~~Baa3~~
~~Senior secured debt~~	A-	~~Baa1~~
~~Junior subordinated notes~~	~~BB+~~	~~Ba1~~
~~Commercial paper~~	~~A-2~~	~~P-3~~
~~Bank facilities~~	~~BBB~~	~~Baa3~~
~~Ratings outlook~~	~~Stable~~	~~Stable~~
~~Puget Energy, Inc.~~
~~Corporate credit/issuer rating~~	~~BB+~~	~~Ba2~~
~~Bank facilities~~	~~BB+~~	~~Ba2~~
~~Ratings outlook~~	~~Stable~~	~~Stable~~

Shelf Registrations and Long-Term Debt Activity

~~In connection with the closing of the merger, all shelf registration statements of Puget Energy were terminated. On March 13, 2009,~~ PSE filed ~~with the SEC~~ a ~~new~~ shelf registration statement to provide for the offering of an aggregate amount of $800.0 million senior notes of PSE, secured by first mortgage bonds and unsecured debentures of PSE. This shelf registration statement, which did not specify the amount of securities that PSE may offer, was amended on January 26, 2010 and will remain valid until March 13, 2012. Under the shelf registration, as amended, PSE may offer senior notes secured by first mortgage bonds in an aggregate amount of up to $800.0 million. The Company ~~also~~ remains subject to the restrictions of PSE’s indentures on the amount of first mortgage bonds that PSE may issue.

On June 29, 2010, PSE issued $250.0 million of senior notes, secured by first mortgage bonds. The notes have a term of 30 years and an interest rate of 5.764%. Net proceeds from the note offering will be used to repay $7.0 million of medium-term notes with a 7.12% interest rate that mature on September 13, 2010 and to repay short-term debt outstanding under the $400.0 million capital expenditure credit facility.

On March 8, 2010, PSE issued $325.0 million of senior notes, secured by first mortgage bonds. The notes have a term of 30 years and an interest rate of 5.795%. Net proceeds from ~~such bond~~the offering were used to replenish funds utilized to ~~redeem a~~repay $225.0 million ~~bond~~of senior medium-term notes which matured on February 22, 2010 and carried a 7.96% interest rate. ~~Net~~Remaining net proceeds were ~~also~~ used to pay down debt under PSE’s capital expenditure credit facility.

On September 11, 2009, PSE completed a $350.0 million issuance of senior secured notes. The notes have a term of 30 years and an interest rate of 5.795%. Net proceeds from the issue were used to repay short-term debt which had been incurred primarily for earlier retirement of maturing long-term debt and to fund in part the utility’s capital expenditures.

Other

Proceedings Relating to the Bonneville Power Administration

PSE has been a party to certain agreements with BPA that provide payments under its REP to PSE, which PSE passes through to its residential and small farm electric customers. PSE has agreements with BPA for REP payments to 2012 and for the period 2012 to 2028. PSE and other parties have sought United States Court of Appeals for the Ninth Circuit (Ninth Circuit) review regarding BPA’s agreements for REP payments during these periods. The amounts of REP payments under these agreements and the methods utilized in setting them are subject to ~~Federal Energy Regulatory Commission (FERC)~~FERC review or judicial review, or both, and are subject to adjustment, which may affect the amount of REP payments made or to be made by BPA to PSE. It is not clear what impact, if any, these reviews or other REP-related litigation may ultimately have on PSE.

~~California Regulatory Asset.~~ PSE has held as a regulatory asset a receivable relating to unpaid bills for power sold into the markets maintained by the CAISO. At March 31, 2010, the net receivable for such sales was $21.2 million. The collectability is subject to the outcome of the Washington Commission ruling on an accounting petition related to Renewable Energy Credits (RECs) sold to utilities in California. On October 7, 2009, PSE filed an amended accounting petition requesting that the Washington Commission authorize PSE to defer the net revenues from the sale of RECs and carbon financial instruments (collectively, REC Proceeds) and use the revenues to: (1) provide funding for low income energy eff iciency and renewable energy services; (2) credit a portion of the REC Proceeds to the California Receivable; and (3) provide a credit to customers by offsetting the REC Proceeds against a regulatory asset. A hearing was held in March 2010 for the accounting petition. A Washington Commission order is anticipated in the second quarter of 2010.

Equilon Litigation. On April 21, 2010, Equilon Enterprises (dba Shell Oil Products), the owner of an oil refinery in Skagit County, Washington, filed suit against PSE in USthe United States District Court for the Western District of Washington in Seattle. The complaint alleges that PSE violated contractual, legal or regulatory standards in connection with a power outage that occurred on April 23, 2009, and seeks compensation for Equilon’s losses, claimed to exceed $7.0 million. ~~WECC~~Western Electricity Coordinating Council (WECC) and ~~NERC~~North American Electric Reliability Corporation (NERC) previously investigated this event, and concluded that PSE did not violate any mandatory reliability standards. PSE intends to ~~vigorously~~vigoro usly defend this litigation but cannot predict the ultimate outcome.

Regulations and Rates

Effective July 1, 2010, the Washington Commission approved a change in PSE’s Wind Power Production Credit (PTC) tariff. PSE has not been able to utilize PTC’s since 2007 due to insufficient taxable income. PSE set the PTC tariff to zero which resulted in an increase in electric rates of 1.65%.

On April 2, 2010, the Washington Commission issued its order in PSE’s consolidated electric and natural gas general rate case filed in May 2009, supplemented by an order of clarification on April 8, 2010 approving a general rate increase for electric customers of 3.7% annually or $74.1 million. The electric general rate order also created a tariff rider intended to allow PSE to collect in electric rates $52.3 million related to the recovery of certain deferred costs that were part of the general rates and will be fully amortized at the end of 2011. The natural gas rate increase approved was 0.8% or $10.1 million on an annual basis. The rate increase for electric and natural gas customers was effective April 8, 2010. In its order, the Washington Commission ~~approved~~approv ed a weighted cost of capital of 8.1% and a capital structure that included 46.0% common equity with an after-tax return on equity of 10.1%.

Colstrip Matters

In May 2003, approximately 50 plaintiffs initiated an action against the owners of Colstrip, including PSE, alleging that: (1) seepage from two different wastewater pond areas caused groundwater contamination and threatened to contaminate domestic water wells and the Colstrip water supply pond; and (2) seepage from the Colstrip water supply pond caused structural damage to buildings and toxic mold. The defendants reached agreement on a global settlement with all plaintiffs on April 29, 2008 and PSE paid its share of the settlement in July 2008.

New Accounting Pronouncements

Fair Value Measurements and Disclosures. In January 2010, the FASB issued ASU 2010-6, “Improving Disclosures About Fair Value Measurements,” which requires reporting entities to make new disclosures about recurring or nonrecurring fair value measurements including significant transfers into and out of Level 1 and Level 2 fair value measurements and information on purchases, sales, issuances and settlements on a gross basis in the reconciliation of Level 2 fair value measurements. ASU 2010-6 is effective for annual reporting periods beginning after December 15, 2009, except for Level 3 reconciliation disclosures which are effective for annual periods beginning after December 15, 2010. As these new requirements relate solely to d isclosures, the adoption of this guidance will not impact the Company’s consolidated financial statements.

Variable Interest Entities. In December 2009, the ~~FASB~~Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2009-17, Topic 810, “Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities,” which amended the FASB ASC for the issuance of pre-codification FASB Statement No. 167, “Amendments to FASB Interpretation No. 46(R).” This standard replaces the quantitative-based risks and rewards calculation for determining which reporting entity, if any, has a controlling financial interest in a variable interest entity (VIE) with an approach focused on identifying which reporting entity has the power to direct the activities of a VIE that most significantly impact the ~~entity’s~~enti ty’s economic performance and: (1) the obligation to absorb losses of the entity; or (2) the right to receive benefits from the entity. An approach that is primarily qualitative is expected to be more effective for identifying which reporting entity has a controlling financial interest in a VIE. This standard also requires additional disclosures about a reporting entity’s involvement in VIE relationships, which will enhance the information provided to users of financial statements. The Company adopted the standard is effective for the first annual reporting period beginning after November 15, 2009 and for interim periods within that first annual reporting period, which will be the period ending March 31, 2010 for the Company.as of January 1, 2010. There was no impact from adoption.

~~Fair Value Measurements and Disclosures.~~ In January 2010, the FASB issued ASU 2010-6, “Improving Disclosures About Fair Value Measurements,” (ASU 2010-6) which requires reporting entities to make new disclosures about recurring or nonrecurring fair value measurements including significant transfers into and out of Level 1 and Level 2 fair value measurements and information on purchases, sales, issuances and settlements on a gross basis in the reconciliation of Level 2 fair value measurements. ASU 2010-6 is effective for annual reporting periods beginning after December 15, 2009, except for Level 3 reconciliation disclosures which are effective for annual periods beginning after December 15, 2010. As these new requirements relate solely to disclosures, the adoption of this guidance will not impact the Company’s consolidated financial statements.

Item 3. Quantitative and Qualitative Disclosure about Market Risk

Energy Portfolio Management

PSE maintains energy risk policies and procedures to manage commodity and volatility risks and the related effects on credit, tax accounting, financing and liquidity. PSE’s Energy Management Committee establishes PSE’s risk management policies and procedures and monitors compliance. The Energy Management Committee is comprised of certain PSE officers and is overseen by the PSE Board of Directors.

PSE is focused on the commodity price exposure and risks associated with volumetric variability in the natural gas and electric portfolios and related effects noted above. It is not engaged in the business of assuming risk for the purpose of speculative trading. PSE hedges open gas and electric positions to reduce both the portfolio risk and the volatility risk in prices. The exposure position is determined by using a probabilistic risk system that models 250 simulations of how PSE’s gas and power portfolios will perform under various weather, hydro and unit performance conditions. The objectives of the hedging strategy are to:

·	Ensure physical energy supplies are available to reliably and cost-effectively serve retail load;

·	Manage the energy portfolio prudently to serve retail load at overall least cost and limit undesired impacts on PSE’s customers and shareholders;

·	Reduce power costs by extracting the value of PSE’s assets; and

·	Meet the credit, liquidity, financing, tax and accounting requirements of PSE.

ASC 815, “Derivatives and Hedging” (ASC 815) requires a significant amount of disclosure regarding PSE’s derivative activities and the nature of such derivatives impact on PSE’s financial position, financial performance and cash flows. Such detail should serve as an accompaniment to Management’s Discussion and Analysis (MD&A), which is located under Item 2 of this report. Further, and as a result of ASC 815 disclosures, summary metrics that may be included in this MD&A discussion may be further expanded upon in the footnotes preceding the MD&A.

PSE employs various portfolio optimization strategies but is not in the business of assuming risk for the purpose of realizing speculative trading revenues. PSE’s portfolio of owned and contracted electric generation resources exposes PSE and its retail electric customers to volumetric and commodity price risks within the sharing mechanism of the PCA. PSE’s natural gas retail customers are served by natural gas purchase contracts which expose PSE’s customers to commodity price risks through the PGA mechanism. All purchased natural gas costs are recovered through customer rates with no direct impact on PSE. Therefore, wholesale market transactions are focused on balancing PSE’s energy portfolio, reducing costs and risks where feasible and reducing ~~volatility. 0;~~vo latility. PSE’s energy risk portfolio management function monitors and manages these risks. In order to manage risks effectively, PSE enters into forward physical electricity and gas purchase and sale agreements, and floating for fixed swap contracts that are related to its regulated electric and gas portfolios. The forward physical electricity contracts are both fixed and variable (at index) while the physical natural gas contracts are variable with investment grade counterparties that do not require collateral calls on the contracts. To fix the price of natural gas, PSE may enter into natural gas floating for fixed swap (financial) contracts with various counterparties.

On July 1, 2009, Puget Energy and PSE elected to ~~de-designate~~revalue all energy related derivative contracts that previously had been recorded as cash flow hedges for the purpose of simplifying its financial reporting. The contracts that were de-designated related to physical electric supply contracts and natural gas swap contracts to fix the price of natural gas for electric generation. For these contracts initiated after this date, all future mark-to-market ~~accounting~~adjustments will be recognized through earnings. The amount previously recorded in accumulated OCI is transferred to earnings in the same period or periods during which the hedged transaction affected earnings or sooner if management determines that the forecasted transaction is probable of not occurring. As a result, the Company will likely continue to experience the earnings ~~volatility~~impact of these reversals from OCI in future periods.

The following tables present the Company’s energy derivatives instruments that do not meet the NPNS exception at ~~March 31,~~June 30, 2010 and December 31, 2009:

	Energy Derivatives								Energy Derivatives
Puget Sound Energy Derivative Portfolio (Dollars in thousands)	March 31, 2010				December 31, 2009
Puget Energy Derivative Portfolio (Dollars in thousands)									June 30, 2010				December 31, 2009
	Assets		Liabilities		Assets		Liabilities		Assets		Liabilities		Assets		Liabilities
Electric portfolio
Current	$	2,789	$	122,673	$	4,137	$	75,323	$	2,851	$	124,658	$	4,137	$	79,732
Long-term		341		104,696		1,003		70,367		1,250		101,964		1,003		70,367
Total electric derivatives	$	3,130	$	227,369	$	5,140	$	145,690	$	4,101	$	226,622	$	5,140	$	150,099
Gas portfolio
Current	$	13,759	$	105,096	$	10,811	$	62,207	$	7,897	$	96,814	$	10,811	$	62,207
Long-term		686		38,130		3,602		19,350		415		40,019		3,602		19,350
Total gas derivatives	$	14,445	$	143,226	$	14,413	$	81,557	$	8,312	$	136,833	$	14,413	$	81,557
Total derivatives	$	17,575	$	370,595	$	19,553	$	227,247	$	12,413	$	363,455	$	19,553	$	231,656

Energy Derivatives
Puget Energy
Derivative Portfolio
(Dollars in thousands)
March 31, 2010 December 31, 2009
Assets Liabilities Assets Liabilities
Electric portfolio
Current $ 2,789 $ 128,121 $ 4,137 $ 79,732
Long-term 341 104,696 1,003 70,367
Total electric derivatives $ 3,130 $ 232,817 $ 5,140 $ 150,099
Gas portfolio
Current $ 13,759 $ 105,096 $ 10,811 $ 62,207
Long-term 686 38,130 3,602 19,350
Total gas derivatives $ 14,445 $ 143,226 $ 14,413 $ 81,557
Total derivatives $ 17,575 $ 376,043 $ 19,553 $ 231,656

	Energy Derivatives
Puget Sound Energy Derivative Portfolio (Dollars in thousands)	June 30, 2010				December 31, 2009
	Assets		Liabilities		Assets		Liabilities
Electric portfolio
Current	$	2,851	$	124,658	$	4,137	$	75,323
Long-term		1,250		101,964		1,003		70,367
Total electric derivatives	$	4,101	$	226,622	$	5,140	$	145,690
Gas portfolio
Current	$	7,897	$	96,814	$	10,811	$	62,207
Long-term		415		40,019		3,602		19,350
Total gas derivatives	$	8,312	$	136,833	$	14,413	$	81,557
Total derivatives	$	12,413	$	363,455	$	19,553	$	227,247

For further details regarding both the fair value of derivative instruments and the impacts such instruments have on current period earnings and OCI (for cash flow hedges), please see Note 3 and Note 4 of the notes to the consolidated financial statements.

At ~~March 31,~~June 30, 2010, the Company had total assets of ~~$14.4~~$8.3 million and total liabilities of ~~$143.2~~$136.8 million related to financial contracts used to economically hedge the cost of physical natural gas purchased to serve natural gas customers. All fair value adjustments on derivatives relating to the natural gas business have been reclassified to a deferred account in accordance with ASC 980 due to the PGA mechanism. All increases and decreases in the cost of natural gas supply are passed on to customers with the PGA mechanism. As the gains and losses on the hedges are realized in future periods, they will be recorded as gas costs under the PGA mechanism.

A hypothetical 10.0% increase or decrease in market prices of natural gas and electricity would change the fair value of ~~Puget Energy and PSE~~the Company derivative contracts by ~~$102.7~~$115.5 million ~~and $102.8 million, respectively,~~ and would impact the fair value of those contracts marked-to-market in earnings by ~~$37.7~~$75.0 million ~~and $37.8 million, respectively,~~ after-tax related to derivatives not designated as hedges.

Contingent Features and Counterparty Credit Risk

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

Where deemed appropriate, PSE may request collateral or other security from its counterparties to mitigate the potential credit default losses. Criteria employed in this decision include, among other things, the perceived creditworthiness of the counterparty and the expected credit exposure. As of ~~March 31,~~June 30, 2010, PSE held approximately ~~$2.6~~$1.1 million worth of standby letters of credit in support of various electricity and renewable energy credit transactions.

It is possible that volatility in energy commodity prices could cause PSE to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, PSE could suffer a material financial loss. However, as of ~~March 31,~~June 30, 2010, approximately ~~92.4%~~91.6% of PSE’s energy and gas portfolio exposure, including NPNS transactions, is with counterparties that are rated at least investment grade by the major rating agencies, and ~~7.6%~~8.4% of PSE’s portfolio are either rated below investment grade or are not rated by rating agencies. PSE assesses credit risk internally for counterparties that are not rated.

PSE has entered into commodity master arrangements with its counterparties to mitigate credit exposure to those counterparties. PSE generally enters into the following master arrangements: (1) Western Systems Power Pool (WSPP) agreements – standardized power sales contracts in the electric industry; (2) International Swaps and Derivatives Association (ISDA) agreements ~~(ISDA)~~ – standardized financial gas and electric contracts; and (3) North American Energy Standards Board ~~agreements~~ (NAESB) –agreements– standardized physical gas contracts. PSE believes that entering into such agreements reduces the risk of default by allowing a counterparty the ability to make only one net payment.

PSE monitors counterparties that are experiencing financial problems, have significant swings in credit default swap rates, have credit rating changes by external rating agencies or have changes in ownership. Counterparty credit risk impacts PSE’s decisions on derivative accounting treatment. A counterparty may have a deterioration of credit below investment grade, potentially indicating that it is no longer probable that it will fulfill its obligations under a contract (e.g., make a physical delivery upon the contract’s maturity). ASC 815 specifies the requirements for derivative contracts to qualify for the NPNS scope exception. When performance is no longer probable, based on the deterioration of counterparty’s credit, PSE records the fair value of the contract on the ~~ba lance~~balance sheet with the corresponding amount recorded in the statements of income.

The locked accumulated OCI of the cash flow hedge is impacted by a counterparty’s deterioration of credit under ASC 815 guidelines. If a forecasted transaction associated with cash flow hedge is no longer probable of occurring, based on deterioration of credit, PSE will record in earnings the locked accumulated OCI. Should a counterparty file for bankruptcy, which would be considered a default under master arrangements, PSE may terminate related contracts. Derivative accounting entries previously recorded would be reversed in the financial statements. PSE would compute any terminations receivable or payable, based on the terms of existing master agreements.

~~PSE~~The Company computes credit reserves at a master agreement level (i.e., WSPP, ISDA or NAESB) by counterparty. ~~PSE~~The Company considers external credit ratings and market factors, such as credit default swaps and bond spreads, in determination of reserves. ~~PSE~~The Company recognizes that external ratings may not always reflect how a market participant perceives a counterparty’s risk of default. ~~PSE~~The Company uses both default factors published by S&P and factors derived through analysis of market risk, which reflect the application of an industry standard recovery rate. ~~PSE~~The Company selects a default factor by counterparty at an aggregate master agreement level based on a weighted average default tenor for that counterparty’s deals. The default tenor is ~~used~~use d by weighting fair values and contract tenors for all ~~deal s~~deals for each counterparty and coming up with an average value. The default factor used is dependent upon whether the counterparty is in a net asset or a net liability position after applying the master agreement levels.

~~PSE~~The Company applies the counterparty’s default factor to compute credit reserves for counterparties that are in a net asset position. Moreover, ~~PSE~~the Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate. The fair value of derivatives includes the impact of taking into account credit and non-performance reserves. As of ~~March 31,~~June 30, 2010, ~~PSE~~the Company was in a net liability position with the majority of its ~~counterparties; as a result,~~counterparties so the default factors of counterparties did not have a significant impact on reserves for the year. Despite its net liability position, PSE was not required to post any additional collateral with any of its counterparties. Additionally, PSE did not trigger any colla teral requirements with any of its counterparties, nor were any of PSE’s counterparties required to post additional collateral resulting from credit rating downgrades.

Interest Rate Risk

The Company believes its interest rate risk primarily relates to the use of short-term debt instruments and leases and anticipated 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,~~internal cash from operations, commercial paper and line of credit facilities to meet short-term ~~cash requirements. These short-term~~funding needs. 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. As of ~~March 31,~~June 30, 2010, Puget Energy had seven ~~interest~~intere st rate swap contracts outstanding, ~~whereas~~and PSE did not have any outstanding interest rate swap instruments.

In February 2009, Puget Energy entered into interest rate swap transactions to hedge the risk associated with one-month LIBOR floating rate debt. As of ~~March 31,~~June 30, 2010, the fair value of the interest rate swaps designated as cash flow hedges was a ~~$24.3~~$56.1 million pre-tax loss. This fair value considers the risk of Puget Energy’s non-performance by using Puget Energy’s incremental borrowing rate on unsecured debt over the risk-free rate in the valuation estimate. The ending balance in OCI includes a loss of ~~$15.8~~$36.5 million after tax related to the interest rate swaps designated as cash flow hedges during the current reporting period.

A hypothetical 10% increase in interest rates would increase the fair value of interest rate swaps by ~~$13.5~~$7.2 million, with a corresponding after-tax increase in unrealized loss recorded in accumulated OCI of ~~$8.8~~$4.6 million. A hypothetical 10% decrease in interest rates would decrease the fair value of interest rate swaps by ~~$35.2~~$7.3 million loss, with a corresponding tax decrease in unrealized losses recorded in accumulated OCI of ~~$22.9~~$4.7 million.

The following table presents Puget Energy’s interest rate derivative instruments designated as cash flow hedges at ~~March 31,~~June 30, 2010 and December 31, 2009:

Puget Energy Derivative Portfolio (Dollars in Thousands)	March 31, 2010				December 31, 2009				June 30, 2010				December 31, 2009
Interest Rate Swaps	Assets		Liabilities		Assets		Liabilities		Assets		Liabilities		Assets		Liabilities
Current	$	--	$	28,344	$	--	$	26,844	$	--	$	27,099	$	--	$	26,844
Long-term		4,047		--		20,854		--		--		29,050		20,854		--
Total	$	4,047	$	28,344	$	20,854	$	26,844	$	--	$	56,149	$	20,854	$	26,844

From time to time PSE may enter into treasury locks or forward starting swap contracts to hedge interest rate exposure related to an anticipated debt issuance. The ending balance in OCI related to the forward starting swaps and previously settled treasury lock contracts at ~~March 31,~~June 30, 2010 is a net loss of ~~$2.5~~$7.4 million after tax and accumulated amortization. This compares to a loss of $7.6 million in OCI after tax as of December 31, 2009. All financial hedge contracts of this type are reviewed by an officer, presented to the Asset Management Committee or the Board of Directors, as applicable, and are approved prior to execution. PSE had no treasury locks or forward starting swap contracts outstanding at ~~March 31,~~June 30, 2010.

Item 4. Controls and Procedures

Puget Energy

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of Puget Energy’s management, including the ~~President and~~ Chief Executive Officer and the Executive Vice President and Chief Financial Officer, Puget Energy has evaluated the effectiveness of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of ~~March 31,~~June 30, 2010, the end of the period covered by this report. Based upon that evaluation, the ~~President and~~ Chief Executive Officer and the Executive Vice President 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 three months ended ~~March 31,~~June 30, 2010 that have materially affected or are reasonably likely to materially affect, Puget Energy’s internal control over financial reporting.

Puget Sound Energy

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of PSE’s management, including the ~~President and~~ Chief Executive Officer and the Executive Vice President and Chief Financial Officer, PSE has evaluated the effectiveness of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of ~~March 31,~~June 30, 2010, the end of the period covered by this report. Based upon that evaluation, the ~~President and~~ Chief Executive Officer and the Executive Vice President 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 three months ended ~~March 31,~~June 30, 2010 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 Litigation footnote of this Quarterly Report on Form 10-Q. Contingencies arising out of the normal course of PSE’s business exist at ~~March 31,~~June 30, 2010. Litigation is subject to numerous uncertainties and PSE is unable to predict the ultimate outcome of these matters.

Item 1A. Risk Factors

There have been no material changes from the risk factors set forth in Part I, Item 1A in Puget Energy’s and PSE’s Form 10-K for the year ended December 31, 2009.

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, Controller and Chief Accounting Officer
Date: ~~May 4,~~August 12, 2010
	Chief Accounting Officer and Officer duly authorized to sign this report on behalf of each registrant

EXHIBIT INDEX

The following exhibits are filed herewith:

10.1	Amendment dated May 10, 2010 to Credit Agreement (dated February 6, 2009) among Puget Sound Energy, Inc. as Borrower, Barclays Bank PLC, as Facility Agent, and the lenders party thereto.
10.2	First Amendment dated May 10, 2010 to Credit Agreement (dated May 16, 2008) among Puget Energy, Inc., as Borrower, Barclays Bank PLC, as Facility Agent, and Collateral Agent, and the lenders party thereto.
12.1	Statement setting forth computation of ratios of earnings to fixed charges (2005 through 2008, January 1, 2009 – February 5, 2009 (Predecessor) and February 6, 2009 – December 31, 2009 and 12 months ended ~~March 31,~~June 30, 2010 (Successor)) for Puget Energy.
12.2	Statement setting forth computation of ratios of earnings to fixed charges (2005 through 2009 and 12 months ended ~~March 31,~~June 30, 2010) for Puget Sound Energy.
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.

Puget Sound Energy Three Months Ended March 31, 2009 (Dollars in Thousands)		Amount of Gain/(Loss) Recognized in OCI on Derivatives		Location of Gain/(Loss) Reclassified from Accumulated OCI into Income		Amount of Gain/(Loss) Reclassified from Accumulated OCI into Income		Location of Gain/(Loss) Recognized in Income on Derivatives		Amount of Gain/(Loss) Recognized in Income on Derivatives
Derivatives in Cash Flow Hedging Relationships		Effective Portion 1		Effective Portion 2				Ineffective Portion and Amount Excluded from Effectiveness Testing 2, 3
Interest rate contracts:	$	--		Interest expense	$	(123	)		$	--
Commodity contracts: Electric derivatives		(48,487	)	Electric generation fuel		(21,488	)	Net unrealized loss on derivative instruments		--
Electric derivatives		(19,490	)	Purchased electricity		--		Net unrealized loss on derivative instruments		(3,238	)
Gas derivatives		--		Purchased gas		--		Net unrealized loss on derivative instruments		--
Total	$	(67,977	)		$	(21,611	)		$	(3,238	)