Unassociated Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2009

[ ]	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

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

Yes

/ /

/X/

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, 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).

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.

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)

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.

Table of Contents


Definitions

Filing Format
Forward Looking Statements

Part I.	Financial Information
Item 1.	Financial Statements

	Puget Energy, Inc.
	Consolidated Statements of Income –Three Months Ended June 30, 2009 (Successor Company) and Three Months Ended June 30, 2008 (Predecessor Company)
	Consolidated Statements of Income – February 6, 2009 - June 30, 2009 (Successor Company), January 1, 2009 - February 5, 2009 and Six Months Ended June 30, 2008 (Predecessor Company)
	Consolidated Statements of Comprehensive Income –Three Months Ended June 30, 2009 (Successor Company) and Three Months Ended June 30, 2008 (Predecessor Company)
	Consolidated Statements of Comprehensive Income – February 6, 2009 - June 30, 2009 (Successor Company), January 1, 2009 - February 5, 2009 and Six Months Ended June 30, 2008 (Predecessor Company)
	Consolidated Balance Sheets – June 30, 2009 (Successor Company) and December 31, 2008 (Predecessor Company)
	Consolidated Statement of Shareholder’s Equity – June 30, 2009 (Successor Company), February 5, 2009 and December 31, 2008 (Predecessor Company)
	Consolidated Statements of Cash Flows – February 6, 2009 - June 30, 2009 (Successor Company), January 1, 2009 - February 5, 2009 and Six Months Ended June 30, 2008 (Predecessor Company)

	Notes
	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

Exhibit Index

DEFINITIONS

AFUDC	Allowance for Funds Used During Construction
BPA	Bonneville Power Administration
EBITDA	Earnings Before Interest, Tax, Depreciation and Amortization
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN	Financial Accounting Standards Board Interpretation
FSP	FASB Staff Position
GAAP	Generally Accepted Accounting Principles
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
Ninth Circuit	United States Court of Appeals for the Ninth Circuit
NPNS	Normal Purchase Normal Sale
OCI	Other Comprehensive Income
PCA	Power Cost Adjustment
PCORC	Power Cost Only Rate Case
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
SFAS	Statement of Financial Accounting Standards
VIE	Variable Interest Entity
Washington Commission	Washington Utilities and Transportation Commission
WSPP	Western Systems Power Pool

FILING FORMAT

This Report on Form 10-Q is a Quarterly Report filed by Puget Energy, Inc. (Puget Energy) as a voluntary Securities and Exchange Commission (SEC) filer. Puget Energy is a voluntary SEC filer as part of the commitments approved by the Washington Utilities and Transportation Commission (Washington Commission) in its merger order.

FORWARD-LOOKING STATEMENTS

Puget Energy is including the following cautionary statements in this Form 10-Q to make applicable and to take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by or on behalf of Puget Energy or its subsidiary, Puget Sound Energy, Inc. (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.

Forward-looking statements involve risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed. Puget Energy’s expectations, beliefs and projections are expressed in good faith and are believed by Puget Energy 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 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 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 Commission, with respect to allowed rates of return, cost recovery, financing, 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, maintenance, construction and operation of natural gas and electric distribution and transmission facilities (natural gas and electric), 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;
·	Failure of PSE to comply with electric reliability standards developed by the North American Electric Reliability Corporation (NERC) for users, owners and operators of the power system, which could result in penalties of up to $1.0 million per day per violation;
·	Changes in, adoption of, and compliance with laws and regulations, including decisions and policies concerning the environment, climate change, emissions, natural resources and fish and wildlife (including the Endangered Species Act);
·	The ability to recover costs arising from changes in enacted federal, state or local tax laws through revenue in a timely manner;
·	Changes in tax law, related regulations, or differing interpretation or enforcement of applicable law by the Internal Revenue Service or other taxing jurisdiction;
·	Accidents or natural disasters, such as hurricanes, windstorms, earthquakes, floods, fires and landslides, which can interrupt service and/or 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;
·	Wholesale market disruption, which may result in a deterioration of market liquidity, increase the risk of counterparty default, affect the regulatory and legislative process in unpredictable ways, negatively affect wholesale energy prices and/or impede PSE’s ability to manage its energy portfolio risks and procure energy supply, affect the availability and access to capital and credit markets and/or impact delivery of energy to PSE from its suppliers;
·	Financial difficulties of other energy companies and related events, which may affect the regulatory and legislative process in unpredictable ways and also adversely affect the availability of and access to capital and credit markets and/or impact delivery of energy to PSE from it suppliers;
·	The effect of wholesale market structures (including, but not limited to, regional market designs or transmission organizations) or other related federal initiatives;

·	PSE electric or natural gas distribution system failure, which may impact PSE’s ability to deliver energy supply to its customers;
·	Changes in weather conditions in the Pacific Northwest, which could have effects on PSE’s customer usage and revenues;
·	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 the cost of procuring such supplies;
·	Variable hydro 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 resource;
·	The ability of 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 electric generation facilities following a regional transmission disruption;
·	The failure of the interstate natural gas pipeline to deliver gas 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 might 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 Puget Energy or PSE; and
·	Deteriorating values of the equity, fixed income and other markets, which could significantly impact the value of investments of PSE’s retirement plan, postretirement 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 undertakes 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 Puget Energy’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 June 30, 2009			Three Months Ended June 30, 2008
Operating revenues:
Electric	$	456,754		$	478,038
Gas		226,922			233,840
Other		2,961			526
Total operating revenues		686,637			712,404
Operating expenses:
Energy costs:
Purchased electricity		188,773			198,886
Electric generation fuel		17,832			32,687
Residential exchange		(20,929	)		(20,298	)
Purchased gas		132,140			137,718
Net unrealized gain on derivative instruments		(38,217	)		(2,364	)
Utility operations and maintenance		122,107			116,449
Non-utility expense and other		4,318			1,597
Merger related costs		252			5,738
Depreciation and amortization		82,309			76,322
Conservation amortization		13,730			15,525
Taxes other than income taxes		66,697			63,674
Total operating expenses		569,012			625,934
Operating income		117,625			86,470
Other income (deductions):
Other income		12,387			8,073
Other expense		(1,691	)		(841	)
Interest charges:
AFUDC		2,218			1,782
Interest expense		(73,379	)		(48,543	)
Income before income taxes		57,160			46,941
Income tax expense		13,590			13,287
Net income	$	43,570		$	33,654

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

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in thousands)

(Unaudited)

	Successor			Predecessor
	February 6, 2009 - June 30, 2009			January 1, 2009 - February 5, 2009			Six Months Ended June 30, 2008
Operating revenues:
Electric	$	843,366		$	213,618		$	1,084,172
Gas		543,357			190,001			677,077
Other		3,757			94			2,088
Total operating revenues		1,390,480			403,713			1,763,337
Operating expenses:
Energy costs:
Purchased electricity		358,190			90,737			471,718
Electric generation fuel		53,998			11,961			79,701
Residential exchange		(40,792	)		(12,542	)		(20,305	)
Purchased gas		331,278			120,925			413,913
Net unrealized (gain) loss on derivative instruments		(50,334	)		3,867			(2,277	)
Utility operations and maintenance		199,349			37,650			228,613
Non-utility expense and other		6,791			112			2,062
Merger related costs		2,731			44,324			7,049
Depreciation and amortization		136,928			26,742			151,688
Conservation amortization		26,967			7,592			28,891
Taxes other than income taxes		131,104			36,935			157,947
Total operating expenses		1,156,210			368,303			1,519,000
Operating income		234,270			35,410			244,337
Other income (deductions):
Other income		18,666			3,653			14,917
Other expense		(8,765	)		(369	)		(1,817	)
Interest charges:
AFUDC		3,549			350			4,211
Interest expense		(116,529	)		(17,291	)		(99,591	)
Income before income taxes		131,191			21,753			162,057
Income tax expense		35,561			8,997			48,590
Net income	$	95,630		$	12,756		$	113,467

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 June 30, 2009		Three Months Ended June 30, 2008
Net income	$	43,570	$	33,654
Other comprehensive income:
Net unrealized gain on interest rate swaps during the period, net of tax of $13,626 and $0, respectively		25,305		--
Reversal of net unrealized loss on interest rate swaps during the period, net of tax of $2,499, and $0, respectively.		4,641		--
Unrealized gain from pension and postretirement plans, net of tax of $0 and $227, respectively		--		422
Net unrealized gain on energy derivative instruments during the period, net of tax of $1,924 and $60,710, respectively		3,574		112,747
Reversal of net unrealized (gain) loss on energy derivative instruments settled during the period, net of tax of $692 and $(1,802), respectively		1,285		(3,347	)
Amortization of financing cash flow hedge contracts to earnings, net of tax of $0 and $43, respectively		--		79
Other comprehensive income		34,805		109,901
Comprehensive income	$	78,375	$	143,555

	Successor			Predecessor
	February 6, 2009 - June 30, 2009			January 1, 2009 - February 5, 2009			Six Months Ended June 30, 2008
Net income	$	95,630		$	12,756		$	113,467
Other comprehensive income:
Net unrealized loss on interest rate swaps during the period, net of tax of $(811), $0, and $0, respectively		(1,507	)		--			--
Reversal of net unrealized loss on interest rate swaps during the period, net of tax of $4,219, $0, and $0, respectively.		7,835			--			--
Unrealized gain from pension and postretirement plans, net of tax of $0, $170 and $322, respectively		--			315			598
Net unrealized gain (loss) on energy derivative instruments during the period, net of tax of $(14,135), $(13,010) and $86,167, respectively		(26,253	)		(24,162	)		160,024
Reversal of net unrealized (gain) loss on energy derivative instruments settled during the period, net of tax of $1,126, $2,428 and $(845), respectively		2,090			4,509			(1,569	)
Amortization of financing cash flow hedge contracts to earnings, net of tax of $0, $15 and $86, respectively		--			26			159
Other comprehensive income (loss)		(17,835	)		(19,312	)		159,212
Comprehensive income (loss)	$	77,795		$	(6,556	)	$	272,679

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

PUGET ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

ASSETS

	Successor			Predecessor
	June 30, 2009 (Unaudited)			December 31, 2008
Utility plant (at original cost, including construction work in progress of $335,620 and $255,214, respectively):
Electric plant	$	4,454,903		$	6,596,359
Gas plant		1,914,119			2,500,236
Common plant		285,210			550,368
Less: Accumulated depreciation and amortization		(134,096	)		(3,358,816	)
Net utility plant		6,520,136			6,288,147
Other property and investments:
Goodwill		1,657,174			--
Investment in Bonneville Exchange Power contract		28,213			29,976
Other property and investments		120,000			118,039
Total other property and investments		1,805,387			148,015
Current assets:
Cash		43,487			38,526
Restricted cash		15,760			18,889
Accounts receivable, net of allowance for doubtful accounts		229,153			203,563
Secured pledged accounts receivable		--			158,000
Unbilled revenues		84,084			248,649
Materials and supplies, at average cost		82,786			62,024
Fuel and gas inventory, at average cost		88,430			120,205
Unrealized gain on derivative instruments		17,868			15,618
Prepaid income tax		60,226			19,121
Prepaid expense and other		10,877			14,964
Power contract fair value gain		145,674			--
Deferred income taxes		73,875			9,439
Total current assets		852,220			908,998
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes		90,562			95,417
Regulatory asset for PURPA buyout costs		94,500			110,838
Power cost adjustment mechanism		2,733			3,126
Other regulatory assets		1,096,820			766,732
Unrealized gain on derivative instruments		47,117			6,712
Power contract fair value gain		959,349			--
Other		87,867			40,421
Total other long-term and regulatory assets		2,378,948			1,023,246
Total assets	$	11,556,691		$	8,368,406

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

PUGET ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

CAPITALIZATION AND LIABILITIES

	Successor			Predecessor
	June 30, 2009 (Unaudited)			December 31, 2008
Capitalization:
Common shareholders’ investment:
Common stock $0.01 par value, 250,000,000 shares authorized, 129,678,489 shares outstanding, respectively	$	--		$	1,297
Common stock $0.01 par value, 1,000 shares authorized, 200 shares outstanding, respectively		--			--
Additional paid-in capital		3,309,618			2,275,225
Earnings reinvested in the business		12,970			259,483
Accumulated other comprehensive loss, net of tax		(17,835	)		(262,804	)
Total shareholders’ equity		3,304,753			2,273,201
Redeemable securities and long-term debt:
Preferred stock subject to mandatory redemption		--			1,889
Junior subordinated notes		250,000			250,000
Long-term debt		3,444,525			2,270,860
Total redeemable securities and long-term debt		3,694,525			2,522,749
Total capitalization		6,999,278			4,795,950
Current liabilities:
Accounts payable		168,157			342,254
Short-term debt		125,000			964,700
Current maturities of long-term debt		233,000			158,000
Accrued expenses:
Purchased gas liability		62,897			8,892
Taxes		65,449			85,068
Salaries and wages		22,045			35,280
Interest		44,833			36,074
Unrealized loss on derivative instruments		380,371			236,866
Power contract fair value loss		110,751			--
Other		155,411			117,222
Total current liabilities		1,367,914			1,984,356
Long-term liabilities and regulatory liabilities:
Deferred income taxes		992,312			749,766
Unrealized loss on derivative instruments		146,629			158,423
Regulatory liabilities		237,624			219,221
Regulatory liabilities related to power contracts		1,105,024			--
Power contracts fair value loss		154,319			--
Other deferred credits		553,591			460,690
Total long-term liabilities and regulatory liabilities		3,189,499			1,588,100
Total capitalization and liabilities	$	11,556,691		$	8,368,406

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

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY

(Dollars in thousands)

(Unaudited)

	Common Stock				Additional						Accumulated Other
	Shares		Amount		Paid-in Capital			Retained Earnings			Comprehensive Loss			Total Amount
Predecessor
Balance at December 31, 2008		129,678,489	$	1,297	$	2,275,225		$	259,483		$	(262,804	)	$	2,273,201
Net income		--		--		--			12,756			--			12,756
Common stock dividend declared		--		--		--			(38,188	)		--			(38,188	)
Common stock expense		--		--		(455	)		--			--			(455	)
Vesting of employee common stock		--		--		1,531			--			--			1,531
Other comprehensive loss		--		--		--			--			(19,312	)		(19,312	)
Balance at February 5, 2009		129,678,489	$	1,297	$	2,276,301		$	234,051		$	(282,116	)	$	2,229,533
Successor
Capitalization at merger		200	$	--	$	3,309,190		$	--		$	--		$	3,309,190
Net income		--		--		--			95,630			--			95,630
Common stock dividend declared		--		--		--			(82,660	)		--			(82,660	)
Employee stock plan tax windfall		--		--		428			--			--			428
Other comprehensive loss		--		--		--			--			(17,835	)		(17,835	)
Balance at June 30, 2009		200	$	--	$	3,309,618		$	12,970		$	(17,835	)	$	3,304,753

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
	February 6, 2009 - June 30, 2009			January 1, 2009 - February 5, 2009			Six Months Ended June 30, 2008
Operating activities:
Net income	$	95,630		$	12,756		$	113,467
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		136,928			26,742			151,688
Conservation amortization		26,967			7,592			28,891
Deferred income taxes and tax credits, net		80,825			(512	)		41,565
Power cost adjustment mechanism		--			--			4,366
Mint Farm deferred costs		(10,682	)		(3,443	)		--
Amortization of gas pipeline capacity assignment		(3,861	)		(791	)		(5,257	)
Non cash return on regulatory assets		(3,994	)		(800	)		(4,972	)
Net unrealized (loss) gain on derivative instruments		(50,334	)		3,867			(2,277	)
Other		443			5,230			(882	)
Pension funding		(6,000	)		--			--
Residential exchange program		(261	)		1,927			32,473
Derivative contracts classified as financing activities due to merger		258,189			--			--
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue		307,243			(31,332	)		199,586
Materials and supplies		(3,674	)		(3,388	)		(642	)
Fuel and gas inventory		(3,391	)		7,605			14,119
Prepaid income taxes		(59,381	)		18,277			44,029
Prepayments and other		6,935			(3,295	)		1,583
Purchased gas receivable/payable		52,294			1,711			(51,100	)
Accounts payable		(200,715	)		(40,203	)		(46,347	)
Taxes payable		375			(3,340	)		(10,762	)
Accrued expenses and other		(66,628	)		59,172			(1,740	)
Net cash provided by operating activities		556,908			57,775			507,788
Investing activities:
Construction and capital expenditures - excluding equity AFUDC		(313,983	)		(49,531	)		(255,776	)
Energy efficiency expenditures		(32,630	)		(4,918	)		(26,963	)
Restricted cash		3,138			(10	)		(8,222	)
Other		8,102			959			2,486
Net cash used by investing activities		(335,373	)		(53,500	)		(288,475	)
Financing activities:
Change in short-term debt and leases, net		63,809			(151,800	)		26,080
Dividends paid		(120,848	)		--			(64,838	)
Long-term debt issued		50,211			250,000			--
Redemption of mandatorily preferred stock		--			(1,889	)		--
Redemption of bonds		(150,000	)		--			(150,000	)
Derivative contracts classified as financing activities due to merger		(258,189	)		--			--
Issuance and redemption costs of bonds and other		5,008			7,133			(2,260	)
Net cash (used) provided by financing activities		(410,009	)		103,444			(191,018	)
Net increase (decrease) in cash		(188,474	)		107,719			28,295
Cash at beginning of year		231,961			38,526			40,797
Cash at end of period	$	43,487		$	146,245		$	69,092
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	119,392		$	1,239		$	101,286
Cash payments (refunds) from income taxes		129			--			(42,392	)

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), a consortium of long-term infrastructure investors, completed its merger with Puget Energy. At the time of the merger, each issued and outstanding share of common stock of Puget Energy, other than any shares owned by the consortium members, were cancelled and converted automatically into the right to receive $30.00 in cash, without interest. Puget Holdings formed Puget Merger Sub as an entity to facilitate the acquisition of Puget Energy. Puget Holdings funded Puget Merger Sub with proceeds used to fund the merger consideration. At the effective time of the merger, Puget Merger Sub merged into Puget Energy. 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. Puget Energy’s basis of accounting incorporates the application of Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 141R, “Business Combinations” (SFAS No. 141R) as of the date of the merger. SFAS No. 141R requires the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the merger date. PSE’s utility plant regulatory assets and liabilities were recorded at Puget Energy at their historical cost basis which is consistent with fair value and PSE’s ratemaking processes and mechanisms. The 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. “Predecessor Company” refers to the operations of Puget Energy and PSE prior to the consummation of the merger. “Successor Company” refers to the operations of Puget Energy and PSE subsequent to the merger.

The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiary, PSE. The consolidated financial statements are presented after elimination of all significant intercompany items and transactions.

The consolidated financial statements contained in this Form 10-Q are unaudited. In the opinions of the management of Puget Energy, 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 Report on Form 10-K for the year ended December 31, 2008.

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 $53.7 million and $139.6 million for the three and six months ended June 30, 2009 and $53.2 million and $129.9 million for the three and six months ended June 30, 2008. Puget Energy’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.

(2)	Business Combinations

On February 6, 2009, Puget Holdings completed its merger with Puget Energy. As a result of the merger, Puget Energy is the direct wholly owned subsidiary of Puget Equico, which is an indirect wholly owned subsidiary of Puget Holdings. After the merger, Puget Energy has 1,000 shares authorized, of which 200 shares have been issued at a par value of $0.01 per share.

At the time of the merger, each issued and outstanding share of common stock of Puget Energy, other than any shares owned by consortium members, were cancelled and converted automatically into the right to receive $30.00 in cash, without interest. The fair value of consideration transferred was $3.9 billion. Puget Holdings funded $3.0 billion, debt of $0.6 billion was issued at Puget Energy and $0.3 billion was the result of the stepped-up basis of the investors’ previously owned shares. In addition, Puget Holdings contributed $85.7 million to Puget Energy.

The table below is the consolidated statement of fair value of assets acquired and accrued liabilities assumed as of February 6, 2009 measured in accordance with SFAS No. 141R. The purchase price allocation is preliminary and there may be revisions to the original allocation.

(Dollars in Thousands)	Amount
Net utility plant	$	6,346,032
Other property and investments		151,913
Goodwill		1,657,174
Current assets		1,185,397
Long-term and regulatory assets		2,497,355
Long-term debt		2,490,544
Current liabilities		2,172,908
Long-term liabilities		3,279,828

The following tables present the fair value adjustments to Puget Energy’s balance sheet and recognition of goodwill in accordance with SFAS No. 141R:

ASSETS

(Dollars in Thousands)	February 6, 2009 (Unaudited)
Utility plant:
Electric plant	$	(2,367,756	)
Gas plant		(666,278	)
Common plant		(302,015	)
Less: Accumulated depreciation and amortization		3,381,095
Net utility plant		45,046
Other property and investments:
Goodwill		1,657,174
Non-utility property		4,250
Total other property and investments		1,661,424
Current assets:
Materials and supplies, at average cost		13,700
Fuel and gas inventory, at average cost		(27,561	)
Unrealized gain on derivative instruments		3,765
Power contract fair value gain		123,975
Deferred income taxes		28,716
Total current assets		142,595
Other long-term and regulatory assets:
Other regulatory assets		145,711
Unrealized gain on derivative instruments		1,359
Regulatory asset related to power contracts		317,800
Power contract fair value gain		1,016,225
Other		(17,072	)
Total other long-term and regulatory assets		1,464,023
Total assets	$	3,313,088

CAPITALIZATION AND LIABILITIES

(Dollars in Thousands)	February 6, 2009 (Unaudited)
Capitalization:
Total shareholders’ equity	$	1,665,056
Redeemable securities and long-term debt:
Long-term debt		(280,315	)
Total redeemable securities and long-term debt		(280,315	)
Total capitalization		1,384,741
Current liabilities:
Unrealized loss on derivative instruments		84,603
Power contract fair value loss		118,167
Other		42,679
Total current liabilities		245,449
Long-term liabilities and regulatory liabilities:
Deferred income taxes		152,974
Unrealized loss on derivative instruments		50,979
Regulatory liabilities		17,417
Regulatory liabilities related to power contracts		1,140,200
Power contract fair value loss		199,633
Other deferred credits		121,695
Total long-term liabilities and regulatory liabilities		1,682,898
Total capitalization and liabilities	$	3,313,088

The carrying values of net utility plant and the majority of regulatory assets and liabilities were determined to be stated at fair value at the acquisition date considering that assets valued are subject to regulation by the Washington Utilities and Transportation Commission (Washington Commission) and the Federal Energy Regulatory Commission (FERC) and a market participant would not be expected to recover any more or less than the carrying value of the assets. SFAS No. 141R requires that the beginning balance of fixed depreciable assets be shown net, with no accumulated amortization recorded, at the date of acquisition, consistent with fresh start accounting.

Other property and investments includes the carrying value of the investments in PSE subsidiaries and other non-utility assets adjusted to fair value based on a combination of the income approach, the market based approach and the cost approach.

The fair values of materials and supplies, which included emission allowances, renewable energy credits and carbon financial instruments were established using a variety of approaches to estimate the market price. The carrying value of fuel inventory was adjusted to its fair value by applying market cost at the date of acquisition.

Energy derivative contracts were reassessed and revalued at the merger date based on forward market prices and forecasted energy requirements.

The fair value assigned to the power contracts was determined using an income approach comparing the contract rate to the market rate over the remaining period of the contracts.

Other regulatory assets includes service contracts which were valued using the income approach comparing the contract rate to the market rate over the remaining period of the contract.

The fair value of leases was determined using the income approach which calculated the favorable/unfavorable leasehold interests as the net present value of the difference between the contract lease rent and market lease rent over the remaining terms of the contracted lease obligation.

The fair value assigned to long-term debt was determined using two different methodologies. For those securities which were actively traded by a third party pricing service, the best indication of fair value was assumed to be the third party’s quoted price. For those securities for which the third party did not provide regular pricing, the fair value of the debt was estimated by forecasting out all coupon and principal payments and discounting them to the present value at an approximated discount rate.

The merger also triggered a new basis of accounting for Puget Energy for the postretirement benefit plans sponsored by PSE under SFAS No. 141R which required remeasuring plan liabilities without the five year smoothing of market-related asset gains and losses.

Puget Energy recognized approximately $1.7 billion in goodwill, which will not be deductible for tax purposes and is reflected on Puget Energy’s consolidated balance sheet as of June 30, 2009. The goodwill represents the potential long-term return of Puget Energy to the investors. Goodwill will be tested at least annually for impairment, with any impairment charged to earnings. Puget Energy will complete its first annual goodwill impairment review in the fourth quarter of 2009. Goodwill will be tested for impairment annually using a two step process in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142). The first step compares the carrying amount of the reporting unit with its fair value, with a carrying value higher than fair value indicating potential impairment. If the first step test fails, the second step is performed. This entails a full valuation of Puget Energy’s assets and liabilities and comparing the valuation to the carrying amount, with the difference indicating the amount of impairment. Goodwill of a reporting unit shall be tested for impairment on an interim basis if an event occurs or circumstances change that would cause the fair value of a reporting unit to fall below its carrying amount.

During the first six months of 2009, Puget Energy incurred pre-tax merger expenses of $47.1 million primarily related to legal fees, transaction advisory services, new credit facility fees, change of control provisions and real estate excise tax. The results of Puget Energy for the first six months of 2009 will not be indicative for periods following the acquisition.

One day prior to the merger, PSE defeased its preferred-stock in the amount of $1.9 million. In conjunction with the merger on February 6, 2009, Puget Energy contributed $805.3 million in capital to PSE, of which $779.3 million was used to pay off short-term debt owed by PSE, including $188.0 million in short-term debt outstanding through the PSE Funding accounts receivable securitization program that was terminated upon closing of the merger. An additional $26.0 million of the capital contribution was used to pay change in control costs associated with the merger.

(3)	Accounting for Derivative Instruments and Hedging Activities

As a result of the merger, Puget Energy reassessed and revalued its derivative contracts that were designated on PSE’s books as Normal Purchase Normal Sale (NPNS) or cash flow hedges and met the criteria defined in SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133). The fair value of the reassessed contracts was recorded as either assets or liabilities with an offset to goodwill. As a result, the amount recorded in accumulated other comprehensive income at the time of the merger was reflected as goodwill.

SFAS No. 133, as amended, requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair value. PSE enters into contracts to manage its energy resource portfolio and interest rate exposure including forward physical and financial contracts, option contracts and swaps. The majority of PSE’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies to contracts with creditworthy counterparties, for which physical delivery is probable and in quantities that will be used in the normal course of business. Power purchases designated as NPNS must meet additional criteria if the transaction is within PSE’s forecasted load requirements and if the counterparty owns or controls energy resources within the western region to allow for physical delivery of the energy. PSE may enter into financial fixed contracts to hedge the variability of certain NPNS contracts. Those contracts that do not meet the NPNS exception or cash flow hedge criteria are marked-to-market to current earnings in the income statement, subject to deferral under SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71), for energy related derivatives due to the Power Cost Adjustment (PCA) mechanism and Purchased Gas Adjustment (PGA) mechanism.

PSE pursues 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 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 effectively, 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.

SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – An Amendment of FASB Statement No. 133” (SFAS No. 161), requires enhanced 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, SFAS No. 161 requires qualitative disclosures about Puget Energy’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. Puget Energy elected to early adopt SFAS No. 161 and began reporting such activities at December 31, 2008.

The following table presents the fair values and locations of derivative instruments recorded on the balance sheet at June 30, 2009 and December 31, 2008:

Derivatives Designated as Hedging Instruments
	Successor at June 30, 2009				Predecessor at December 31, 2008
(Dollars in Millions)	Asset Derivatives 1		Liability Derivatives 2		Asset Derivatives 1		Liability Derivatives 2
Interest rate swaps:
Current	$	--	$	25.8	$	--	$	--
Long-term		35.5		--		--		--
Electric portfolio:
Current		--		99.2		0.1		85.3
Long-term		0.5		60.6		0.4		93.1
Total derivatives	$	36.0	$	185.6	$	0.5	$	178.4

____________

1	Balance sheet location: Unrealized gain on derivative instruments.
2	Balance sheet location: Unrealized loss on derivative instruments.

Derivatives Not Designated as Hedging Instruments
	Successor at June 30, 2009				Predecessor at December 31, 2008
(Dollars in Millions)	Asset Derivatives 1		Liability Derivatives 2		Asset Derivatives 1		Liability Derivatives 2
Electric portfolio:
Current	$	1.0	$	84.3	$	0.3	$	5.3
Long-term		2.7		31.1		0.1		3.0
Gas portfolio:
Current		12.7		122.5		15.2		146.3
Long-term		7.2		31.5		6.2		62.3
Total derivatives	$	23.6	$	269.4	$	21.8	$	216.9

____________

1	Balance sheet location: Unrealized gain on derivative instruments.
2	Balance sheet location: Unrealized loss on derivative instruments.

Puget Energy had a current derivative liability and an offsetting regulatory asset of $134.0 million at June 30, 2009 and $187.2 million at December 31, 2008 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 SFAS No. 71 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.

The following table presents the effect of hedging instruments on OCI and income for the three months ended June 30, 2009:

(Dollars in Millions) Successor Three Months Ended June 30, 2009	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 SFAS No. 133 Cash Flow Hedging Relationships	Effective Portion 1	Effective Portion 2		Ineffective Portion and Amount Excluded from Effectiveness Testing 2, 3
Interest rate contracts:	$ 22.1	Interest expense	$ 7.1		$ --
Commodity contracts: Electric derivatives	(4.6)	Electric generation fuel	0.9	Net unrealized gain on derivative instruments	0.5
Electric derivatives	8.2	Purchased electricity	1.1	Net unrealized gain on derivative instruments	1.5
Total	$ 25.7		$ 9.1		$ 2.0

____________

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.
3	Ineffective portion of long-term power supply contracts that are designated as cash flow hedges.

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

(Dollars in Millions) Successor February 6, 2009 - June 30, 2009	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 SFAS No. 133 Cash Flow Hedging Relationships	Effective Portion 1	Effective Portion 2		Ineffective Portion and Amount Excluded from Effectiveness Testing 2, 3
Interest rate contracts:	$ (1.5)	Interest expense	$ 12.0		$ --
Commodity contracts: Electric derivatives	(19.9)	Electric generation fuel	1.6	Net unrealized gain on derivative instruments	0.3
Electric derivatives	(6.3)	Purchased electricity	1.6	Net unrealized loss on derivative instruments	(2.9)
Total	$ (27.7)		$ 15.2		$ (2.6)

(Dollars in Millions) Predecessor January 1, 2009 - February 5, 2009	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 SFAS No. 133 Cash Flow Hedging Relationships	Effective Portion 1,4	Effective Portion 2		Ineffective Portion and Amount Excluded from Effectiveness Testing 2, 3
Commodity contracts: Electric derivatives	$ (17.5)	Electric generation fuel	$ 5.0	Net unrealized loss on derivative instruments	$ --
Electric derivatives	(2.1)	Purchased electricity	1.9	Net unrealized loss on derivative instruments	(1.0)
Total	$ (19.6)		$ 6.9		$ (1.0)

____________

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.
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.

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. Puget Energy expects that $35.1 million of losses in OCI will be reclassified into earnings within the next 12 months. The maximum length of time over which Puget Energy is hedging its exposure to the variability in future cash flows extends to February 2015 for the physical electric contracts and to January 2012 for electric generation fuel financial contracts. During the current reporting period, Puget Energy reclassified $0.5 million of after-tax losses from OCI into earnings related to transactions that are probable of not occurring.

The following tables present the effect of derivatives not designated as hedging instruments on income during the periods ended for the three months and six months ended June 30, 2009, respectively:

(Dollars in Millions) Successor Three Months Ended June 30, 2009	Location of Gain/(Loss) in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
Commodity contracts: Electric derivatives	Net unrealized gain on derivative instruments	$	24.1
	Electric generation fuel		(5.0	)
	Purchased electricity		(11.4	)
Total		$	7.7

(Dollars in Millions) Six Months Ended June 30, 2009	Location of Gain/(Loss) in Income on Derivatives	Successor February 6, 2009 - June 30, 2009 Amount of Gain/(Loss) Recognized in Income on Derivatives			Predecessor January 1, 2009 - February 5, 2009 Amount of Loss Recognized in Income on Derivatives
Commodity contracts: Electric derivatives	Net unrealized gain/(loss) on derivative instruments	$	20.4		$	(2.9	)
	Electric generation fuel		(11.0	)		(0.9	)
	Purchased electricity		(16.3	)		(0.2	)
Total		$	(6.9	)	$	(4.0	)

Puget Energy had the following outstanding commodity contracts as of June 30, 2009:


Six Months Ended June 30, 2009	Number of Units
Derivatives designated as hedging instruments:
Electric generation fuel	27,645,000 MMBtus
Purchased electricity	4,648,500 MWh
Interest rate swaps	$ 1.483 Billion USD
Derivatives not designated as hedging instruments:
Gas derivatives 1	86,088,661 MMBtus
Electric generation fuel	58,295,000 MMBtus
Purchased electricity	3,202,100 MWh

________________

1	Gas derivatives are deferred in accordance with SFAS No. 71.

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, exposure measurement, exposure monitoring and exposure mitigation.

Where deemed appropriate, PSE may request collateral or other security from its counterparties to mitigate the potential credit default losses. Criterion employed in this decision includes, among other things, the perceived creditworthiness of the counterparty and the expected credit exposure. As of June 30, 2009, PSE held approximately $0.6 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 June 30, 2009, approximately 99.9% of PSE’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 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 agreements (WSPP) - standardized power sales contract in the electric industry; (2) International Swaps and Derivatives Association agreements (ISDA) - standardized financial gas and electric contracts; and (3) North American Energy Standards Board agreements (NAESB) - 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 computes credit reserves at a master agreement level (i.e. WSPP, ISDA or NAESB) by counterparty. PSE considers external credit ratings and market factors, such as credit default swaps and bond spreads, in determination of reserves. PSE recognizes that external ratings may not always reflect how a market participant perceives a counterparty’s risk of default. PSE 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. PSE 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.

PSE applies the counterparty’s default factor to compute credit reserves for counterparties that are in a net asset position. Moreover, PSE applies its own default factor to compute credit reserves for counterparties in a net liability position. Credit reserves are booked as contra accounts to unrealized gain (loss) positions. As of June 30, 2009, PSE 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 PSE’s derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council.

PSE enters into energy contracts with various 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 table below presents the fair value of the overall contractual contingent liability positions for Puget Energy derivative activity at June 30, 2009:

Contingent Feature (Dollars in Millions)	Fair Value 4 Liability			Posted Collateral		Contingent Collateral
Credit rating 1	$	(34.4	)	$	--	$	34.4
Reasonable grounds for adequate assurance 2		(115.6	)		--		--
Forward value of contract 3		(46.1	)		20.0		N/A
Total	$	(196.1	)	$	20.0	$	34.4

_________________

1	PSE is required to maintain an investment grade credit rating from each of the major credit rating agencies.
2	A counterparty with reasonable grounds for insecurity regarding performance of an obligation may request adequate assurance of performance.
3	Collateral requirements may vary, based on changes in forward value of underlying transactions.
4	Represents derivative fair values of contracts with contingent features for counterparties in net derivative liability positions at June 30, 2009. Excludes NPNS, accounts payable and accounts receivable activity.

(4)	Fair Value Measurements

SFAS No. 157, “Fair Value Measurements” (SFAS No. 157), establishes 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 SFAS No. 157 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 in the 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 performs an analysis of all instruments subject to SFAS No. 157 and includes in Level 3 all of those 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. Puget Energy’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. The determination of the fair values incorporates various factors that not only include the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), but also the impact of Puget Energy’s nonperformance risk on its liabilities.

As of June 30, 2009, Puget Energy considers 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. Puget Energy 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 table sets forth, by level within the fair value hierarchy, Puget Energy’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2009 and December 31, 2008:

Recurring Fair Value Measures	Successor as of June 30, 2009					Predecessor as of December 31, 2008
(Dollars in Millions)	Level 1	Level 2	Level 3	Other	Total	Level 1	Level 2	Level 3	Total
Assets:
Energy derivative instruments	$ --	$ 20.9	$ 3.4	$ --	$ 24.3	$ --	$ 21.8	$ 0.5	$ 22.3
Money market accounts	19.5	5.7	--	--	25.2	24.7	--	1.4	26.1
Interest rate derivative instruments	--	35.5	--	--	35.5	--	--	--	--
De-designated commodity instruments 1	--	--	--	5.2	5.2	--	--	--	--
Total assets	$ 19.5	$ 62.1	$ 3.4	$ 5.2	$ 90.2	$ 24.7	$ 21.8	$ 1.9	$ 48.4
Liabilities:
Energy derivative instruments	$ --	$ 289.2	$ 140.0	$ --	$ 429.2	$ --	$ 261.2	$ 134.1	$ 395.3
Money market accounts	--	--	--	--	--	--	--	--	--
Interest rate derivative instruments	--	25.8	--	--	25.8	--	--	--	--
De-designated commodity instruments 1	--	--	--	72.0	72.0	--	--	--	--
Total liabilities	$ --	$ 315.0	$ 140.0	$ 72.0	$ 527.0	$ --	$ 261.2	$ 134.1	$ 395.3

_______________

De-designated commodity instruments represent derivative contracts acquired at fair value by Puget Energy at the acquisition date that were subsequently designated as NPNS in accordance with paragraph 10(b) of SFAS No. 133 and are no longer recorded at fair value at the end of the reporting period. The amounts above represent the remaining unamortized value that will be amortized into earnings over the original life of the contracts.

The following tables set forth a reconciliation of changes in the fair value of derivatives classified as Level 3 in the fair value hierarchy:

Level 3 Roll-Forward Net Asset/(Liability) (Dollars in Millions) Three Months Ended June 30,	Successor 2009 1			Predecessor 2008
Balance at beginning of period asset/(liability)	$	(170.4	)	$	17.2
Realized and unrealized energy derivatives
- included in earnings		6.6			3.5
- included in other comprehensive income		10.3			116.3
- included in regulatory assets/liabilities		0.7			3.0
Purchases, issuances, and settlements		7.9			7.7
Energy derivatives transferred in/out of Level 32		8.2			(0.3	)
Balance at end of period asset/(liability)	$	(136.7	)	$	147.4

_______________

1	The ending balance for the Predecessor Company was eliminated as a result of push-down accounting effective February 6, 2009, when the Successor period began, causing a difference between the ending and beginning of period balances for the Predecessor and Successor Companies.
2	The energy derivatives transferred in/out of Level 3 for the Successor Company includes the money market fund balance of $1.4 million. These money market funds became Level 2 during the current period. The transfer in/out balance related to the commodity contracts was $9.6 million for the three months ended roll forward tables.

Level 3 Roll-Forward Net Asset/(Liability) (Dollars in Millions) Six Months Ended June 30,	Successor February 6, 2009 - June 30, 2009 1			Predecessor January 1, 2009 - February 5, 2009 1			Predecessor Six Months Ended June 30, 2008
Balance at beginning of period liability	$	(185.8	)	$	(132.2	)	$	(7.3	)
Realized and unrealized energy derivatives
- included in earnings		(9.8	)		(0.6	)		1.9
- included in other comprehensive income		(17.4	)		(14.8	)		145.0
- included in regulatory assets/liabilities		(2.4	)		(1.4	)		3.0
Purchases, issuances, and settlements		13.7			2.1			5.9
Energy derivatives transferred in/out of Level 32		65.0			8.5			(1.1	)
Balance at end of period asset/(liability)	$	(136.7	)	$	(138.4	)	$	147.4

_______________

1	The ending balance for the Predecessor Company was eliminated as a result of push-down accounting effective February 6, 2009, when the Successor period began, causing a difference between the ending and beginning of period balances for the Predecessor and Successor Companies.
2	The energy derivatives transferred in/out of Level 3 for the Successor Company includes the money market fund balance of $1.4 million. These money market funds became Level 2 during the current period. The transfer in/out balance related to the commodity contracts was $66.4 million for the six months ended roll forward tables for the Successor Company.

During the current reporting period, $9.8 million of unrealized losses were included in earnings of the Successor Company, related to Level 3 contracts still in existence as of June 30, 2009.

Realized gains and losses on energy derivatives for Level 3 recurring items are included in energy costs in Puget Energy’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 derivatives recurring items are included in the net unrealized (gain)/loss on derivative instruments section in Puget Energy’s income statement and as a net unrealized (gain)/loss on derivative instruments in OCI. Puget Energy does not believe that the fair values diverge materially from the amounts Puget Energy currently anticipates realizing on settlement or maturity. The net unrealized loss recognized during the period in earnings, OCI, and regulatory assets and liabilities is primarily due to a significant decrease in market prices.

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 end of the prior reporting period for which the lowest significant input became observable during the current reporting period. The Level 3 opening balance for the Successor Company in the year to date table includes $46.7 million of derivative contracts that were subsequently designated for the NPNS scope exception in accordance with paragraph 10(b) of SFAS No. 133. The value of such contracts was transferred out of Level 3 during the period as the contracts are no longer being recorded at fair value. In addition, $13.3 million of losses were transferred out of Level 3 as the fair value of energy derivative instruments became substantially observable. These transfers were offset by $3.7 million of losses that were classified as Level 2 at the beginning of the period and were transferred into Level 3 as tenor of such derivatives became less observable during the current reporting period.

(5)	Estimated Fair Value of Financial Instruments

The following table presents the carrying amounts and estimated fair values of Puget Energy’s financial instruments at June 30, 2009 and December 31, 2008:

	June 30, 2009				December 31, 2008
(Dollars in Millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Financial assets:
Cash	$	43.5	$	43.5	$	38.5	$	38.5
Restricted cash		15.8		15.8		18.9		18.9
Notes receivable and other		72.8		72.8		71.8		71.8
De-designated commodity instruments 1		5.2		5.2		--		--
Energy derivatives		24.3		24.3		22.3		22.3
Interest rate derivative instruments		35.5		35.5		--		--
Financial liabilities:
Short-term debt	$	125.0	$	125.0	$	964.7	$	964.7
Preferred stock subject to mandatory redemption		--		--		1.9		1.9
Junior subordinated notes		250.0		176.5		250.0		112.5
Current maturities of long-term debt (fixed rate)		233.0		241.0		158.0		158.0
Long-term debt (fixed-rate)		2,295.9		2,303.6		2,270.9		1,951.0
Long-term debt (variable-rate)		1,483.0		1,338.5		--		--
De-designated commodity instruments 1		72.0		72.0		--		--
Energy derivatives		429.2		429.2		395.3		395.3
Interest rate derivative instruments		25.8		25.8		--		--

_______________

The fair value of the senior secured fixed notes and variable rate 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 fair value of the preferred stock subject to mandatory redemption as of December 31, 2008 was estimated based on dealer quotes. 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. PSE values derivative instruments based on daily quoted prices from an independent external pricing service. When external quoted market prices are not available for derivative contracts, PSE uses a valuation model that uses volatility assumptions relating to future energy prices based on specific energy markets and utilizes externally available forward market price curves.

(6)	Financing Arrangements

Puget Energy Credit Facilities

Effective with the close of the merger on February 6, 2009, Puget Energy has a $1.225 billion five-year term loan and a $1.0 billion credit facility for funding utility capital expenditures. Prior to the merger close, Puget Energy had no credit facilities.

Puget Energy’s credit agreements contain usual and customary affirmative and negative covenants that, among other things, place limitations on its, or its operating company’s ability to incur additional indebtedness and liens, issue equity, pay dividends, transact with affiliates and make dispositions and investments. The credit agreements also contain financial covenants, whose measurement periods begin with the third quarter 2009 financial statements, based on the following three ratios: cash flow interest coverage, cash flow debt leverage and debt service coverage.

The two credit facilities mature in February 2014, contain similar terms and conditions and are syndicated among numerous banks 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 plus a spread or at floating rates based on the London Interbank Offered Rate (LIBOR) plus a spread. 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 determined by S&P and Moody’s Investors Services (Moody’s) credit ratings. For Puget Energy’s credit ratings as of the date of this report, the spread over prime rate is 125 basis points, the spread to the LIBOR is 225 basis points and the commitment fee is 84 basis points.

At June 30, 2009, the term loan was fully drawn at $1.225 billion and $258.0 million was outstanding under the $1.0 billion facility, leaving $742.0 million available for use on the facility. Concurrent with the borrowings under these credit agreements, Puget Energy entered into a series of interest rate swaps with a group of banks to fix the interest rates at 4.76% for the term of the credit facilities on the two loans totaling $1.483 billion.

The source of funding to satisfy Puget Energy credit agreement costs is from the payment of dividends to Puget Energy from PSE. See “Dividend Payment Restrictions” discussion in Note 6.

PSE Credit Facilities

As of June 30, 2009 and February 5, 2009, PSE had $147.8 million and $838.6 million in short-term borrowings under its credit facilities, respectively. Effective immediately after the merger on February 6, 2009, PSE has three committed unsecured revolving credit facilities that provide, in the aggregate, $1.150 billion in short-term borrowing capability. Each of the credit facilities are described below.

PSE Credit Agreements at June 30, 2009 (Successor Company)

Effective with the close of the merger, PSE has three committed unsecured revolving credit facilities that provide, in the aggregate, $1.150 billion in short-term borrowing capability. These new 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 similar usual and customary covenants as described in the Puget Energy agreements. PSE’s financial covenants include cash flow interest coverage and cash flow debt leverage ratios whose measurement periods begin with third quarter 2009 financial statements.

These facilities mature in 2014, contain similar terms and conditions and are syndicated among numerous committed banks. The agreements provide PSE with the ability to borrow at either a base rate (based on the Prime Rate) or the Eurodollar rate (based on the LIBOR), plus a spread. PSE must also pay a commitment fee on the unused portion of the facilities. The spread and the commitment fee depend on PSE’s credit ratings as determined by S&P and Moody’s credit ratings. Based on PSE’s credit ratings as of the date of this report, the spread is 85 basis points and the commitment fee is 26 basis points. 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 June 30, 2009, PSE had borrowed $125.0 million on the $400.0 million working capital facility, had a $20.0 million letter of credit outstanding under the $350.0 million facility supporting energy hedging and had no borrowings outstanding under the $400.0 million capital expenditure facility. Outside of the credit agreements, PSE had a $6.6 million letter of credit through a bank in support of a long-term transmission contract.

PSE Credit Agreements at February 5, 2009 (Predecessor Company)

At February 5, 2009, PSE had available unsecured revolving credit agreements in the amounts of $500.0 million for working capital purposes and $350.0 million to support energy hedging activities, each expiring in April 2012. The credit agreements provided credit support for letters of credit and commercial paper. At February 5, 2009, PSE had $249.9 million of loans and outstanding letters of credit drawn on the $500.0 million facility and a $30.0 million letter of credit and no loans drawn under the $350.0 million facility. There was no commercial paper outstanding under either facility.

In August 2008, PSE entered into a nine-month, $375.0 million credit agreement with four banks and as of February 5, 2009, PSE had fully drawn the $375.0 million capacity under the agreement.

At February 5, 2009, PSE had a $200.0 million receivables securitization facility which was set to expire in December 2010. At February 5, 2009, $188.0 million was outstanding under the receivables securitization facility. The facility allowed receivables to be used as collateral to secure short-term loans, not exceeding the lesser of $200.0 million or the borrowing base of eligible receivables, which fluctuate with the seasonality of energy sales to customers.

On February 6, 2009, the credit agreements and securitization facility were repaid, terminated and replaced with the new post-merger facilities described above.

Demand Promissory Note. On June 1, 2006, PSE entered into an uncommitted revolving credit facility with its parent, Puget Energy, pursuant to a Demand Promissory Note (Note) under which PSE may borrow up to $30.0 million from 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. At June 30, 2009, the outstanding balance of the Note was $22.9 million. As of December 31, 2008, the outstanding balance of the Note was $26.1 million. This Note was unaffected by the February 6, 2009 merger.

Bond Issuance. On January 23, 2009, PSE issued $250.0 million of senior notes, secured by first mortgage bonds. The bonds are non-callable, were placed with approximately 35 institutional investors, have a term of seven years and carry a 6.75% interest rate.

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 the Mortgage Indentures. At June 30, 2009, $470.0 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, as approved in the Washington Commission merger order, PSE dividends may not be declared or paid if PSE’s common equity ratio 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 on the date of distribution unless: (a) the ratio of PSE’s Earnings Before Interest, Tax, Depreciation and Amortization (EBITDA) to PSE interest for the most recently ended four fiscal quarter periods prior to such date is equal to or greater than three to one and (b) PSE’s corporate credit/issuer rating is equal to or greater than BBB- with S&P and Baa3 with Moody’s. Puget Energy’s ability to pay dividends to its shareholder is also limited by the merger order, beginning February 6, 2009. 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 most recently ended four fiscal quarter periods prior to such date is equal to or greater than two to one.

Summary of Puget Energy and PSE Credit Facilities

(Dollars in Thousands)	Successor June 30, 2009		Predecessor February 5, 2009
Committed financing arrangements:
PSE line of credit 1, 6	$	--	$	490,000
PSE line of credit 2, 6		--		315,000
PSE line of credit 3, 6		--		375,000
PSE receivables securitization program 4, 6		--		200,000
PSE working capital facility 6, 7		400,000		--
PSE capital expenditures facility 6, 7		400,000		--
PSE hedging facility 6, 7		350,000		--
Puget Energy 5-year term loan 8		1,225,000		--
Puget Energy capital expenditures facility 9		1,000,000		--
Uncommitted financing agreements:
Puget Energy demand promissory note 5		30,000		30,000

_______________

1	Provided liquidity for PSE’s general corporate purposes and support for PSE’s outstanding commercial paper and letters of credit. This $500.0 million facility is reflected as $490.0 million due to Lehman Brothers’ lack of funding its $10.0 million commitment. At February 5, 2009, PSE had $249.9 million of loans and letters of credit outstanding under this facility leaving $240.1 million of available borrowing capacity. This credit facility was repaid and subsequently terminated in connection with the merger.
2	Provided credit support for PSE’s energy and natural gas hedging activities. This $350.0 million facility is reflected as $315.0 million reduced for Lehman Brothers’ lack of funding its $35.0 million commitment. At February 5, 2009, PSE had one outstanding letter of credit under this facility in the amount of $30.0 million. There were no loans outstanding at February 5, 2009. This credit facility was repaid and subsequently terminated in connection with the merger.
3	Provided short-term funding for PSE’s acquisition of the Mint Farm natural gas fired electric generating facility and general corporate liquidity. At February 5, 2009, there were $375.0 million of loans outstanding under this facility. This credit facility was repaid and subsequently terminated in connection with the merger.
4	Provided borrowings secured by accounts receivable and unbilled revenues. At February 5, 2009, PSE Funding had borrowed $188.0 million, leaving $12.0 million available to borrow under the program. This credit facility was repaid and subsequently terminated in connection with the merger.
5	PSE has a revolving credit facility with Puget Energy in the form of a promissory note to borrow up to $30.0 million subject to approval by Puget Energy. At June 30, 2009, there was $22.9 million outstanding. At February 5, 2009, the outstanding balance on the note was $25.7 million. The outstanding balance and related interest are eliminated on Puget Energy’s balance sheet upon consolidation.
6	Effective February 6, 2009, the PSE lines of credit and PSE receivables securitization program were terminated and replaced with three lines of credit with a group of banks.
7	Three new PSE lines of credit consist of $400.0 million to fund operating expenses, $400.0 million to fund capital expenditures and $350.0 million to support energy and natural gas hedging activity. As of June 30, 2009, there was $125.0 million outstanding under the working capital facility, and $20.0 million letter of credit outstanding under the $350.0 hedging facility.
8	Effective February 6, 2009, Puget Energy entered into this credit agreement to assist with funding the merger transaction and repay short-term loans under the previous PSE credit facilities. The full amount of the $1.225 billion loan was hedged to lock in a fixed interest rate of 4.76%.
9	Effective February 6, 2009 Puget Energy entered into this credit facility to provide funding for capital expenditures. At June 30, 2009 a loan in the amount of $258.0 million was outstanding. An interest rate hedge was entered into at time of borrowing to lock in a fixed interest rate of 4.76%.

(7)	Income Taxes

The details of income taxes on continuing operations for the three months ended June 30, 2009 as compared to the same period in 2008 are as follows:

	Successor			Predecessor
(Dollars in Thousands)	Three Months Ended June 30, 2009			Three Months Ended June 30, 2008
Charged to operating expense:
Current:
Federal	$	(42,534	)	$	(4,274	)
State		(343	)		96
Deferred - federal		56,466			17,465
Total income taxes	$	13,589		$	13,287

The details of income taxes on continuing operations for the six months ended June 30, 2009 as compared to the same period in 2008 are as follows:

	Successor			Predecessor			Predecessor
(Dollars in Thousands)	February 6, 2009 - June 30, 2009			January 1, 2009 - February 5, 2009			Six Months Ended June 30, 2008
Charged to operating expense:
Current:
Federal	$	(39,258	)	$	10,185		$	9,064
State		(737	)		87			(53	)
Deferred - federal		75,556			(1,275	)		39,579
Total income taxes	$	35,561		$	8,997		$	48,590

The following reconciliations compare pre-tax book income at the federal statutory rate of 35.0% to the actual income tax expense in the Consolidated Statements of Income for the three months and six months ended June 30, 2009, respectively, as compared to the same period in 2008:

	Successor			Predecessor
(Dollars in Thousands)	Three Months Ended June 30, 2009			Three Months Ended June 30, 2008
Income taxes at the statutory rate	$	20,007		$	16,426
Increase (decrease):
Utility plant differences		1,701			959
AFUDC excluded from taxable income		(1,984	)		(1,777	)
Capitalized interest		424			550
Regulatory		614			532
Production tax credit		(6,285	)		(5,681	)
Transaction costs		126			--
Other, net		(1,014	)		2,278
Total income taxes	$	13,589		$	13,287
Effective tax rate		23.8	%		28.3	%

	Successor			Predecessor			Predecessor
(Dollars in Thousands)	February 6, 2009 - June 30, 2009			January 1, 2009 - February 5, 2009			Six Months Ended June 30, 2008
Income taxes at the statutory rate	$	45,918		$	7,613		$	56,719
Increase (decrease):
Utility plant differences		3,472			1,472			3,878
AFUDC excluded from taxable income		(4,179	)		(1,771	)		(3,349	)
Capitalized interest		2,181			914			3,001
Regulatory		2,335			1,429			2,151
Production tax credit		(12,707	)		(5,870	)		(15,918	)
Transaction costs		202			5,544			--
Other, net		(1,661	)		(334	)		2,108
Total income taxes	$	35,561		$	8,997		$	48,590
Effective tax rate		27.1	%		41.4	%		30.0	%

Puget Energy’s deferred tax liability at June 30, 2009 and December 31, 2008 is composed of amounts related to the following types of temporary differences:

	Successor			Predecessor
(Dollars in Thousands)	June 30, 2009			December 31, 2008
Utility plant and equipment	$	917,073		$	746,486
Regulatory asset for income taxes		90,562			95,417
Storm damage		39,639			42,037
Pensions and other compensation		15,894			(62,837	)
Other deferred tax liabilities		202,080			47,963
Subtotal deferred tax liabilities		1,265,248			869,066
Fair value of derivative instruments		(162,683	)		(69,259	)
Other deferred tax assets		(184,128	)		(59,480	)
Subtotal deferred tax assets		(346,811	)		(128,739	)
Total	$	918,437		$	740,327

The above amounts have been classified in the Consolidated Balance Sheets at June 30, 2009 and December 31, 2008 as follows:

	Successor			Predecessor
(Dollars in Thousands)	June 30, 2009			December 31, 2008
Current deferred taxes	$	(73,875	)	$	(9,439	)
Non-current deferred taxes		992,312			749,766
Total	$	918,437		$	740,327

Puget Energy calculates its deferred tax assets and liabilities under FASB Statement No. 109, “Accounting for Income Taxes” (SFAS No. 109). SFAS No. 109 requires recording deferred tax balances, at the currently enacted tax rate, on assets and liabilities that are reported differently for income tax purposes than for financial reporting purposes. For ratemaking purposes, deferred taxes are not provided for certain temporary differences. PSE has established a regulatory asset for income taxes recoverable through future rates related to those temporary differences for which no deferred taxes have been provided, based on prior and expected future ratemaking treatment.

Puget Energy accounts for uncertain tax positions under Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109” (FIN 48), which clarifies the accounting for uncertainty in income taxes recognized in the financial statements in accordance with SFAS No. 109. FIN 48 requires the use of a two-step approach for recognizing and measuring tax positions taken or expected to be taken in a tax return. First, a tax position should only be recognized when it is more likely than not, based on technical merits, that the position will be sustained upon examination by the taxing authority. Second, a tax position that meets the recognition threshold should be measured at the largest amount that has a greater than 50% likelihood of being sustained.

At June 30, 2009 and December 31, 2008, Puget Energy had no material unrecognized tax benefits. As a result, no interest or penalties were accrued for unrecognized tax benefits during the year.

For FIN 48 purposes, Puget Energy has open tax years from 2006 through 2009. Puget Energy classifies interest as interest expense and penalties as other expense in the financial statements.

(8)	Retirement Benefits

PSE has a defined benefit pension plan covering substantially all PSE employees; years of pension benefits earned are a function of age, salary and service. PSE also maintains a non-qualified supplemental retirement plan for officers and certain director-level employees.

The February 6, 2009 merger of Puget Energy with Puget Holdings triggered a new basis of accounting for PSE’s retirement benefit plans. PSE did not record the remeasurement of retirement plans as all the purchase accounting adjustments are recorded at Puget Energy. The following tables summarize Puget Energy’s net periodic benefit cost for the three months ended June 30, 2009 as compared to the same period in 2008:

Qualified Pension Benefits
(Dollars in Thousands)	Successor Three Months Ended June 30, 2009			Predecessor Three Months Ended June 30, 2008
Components of net periodic benefit cost:
Service cost	$	3,401		$	3,321
Interest cost		7,067			6,805
Expected return on plan assets		(7,523	)		(10,327	)
Amortization of net loss		--			472
Amortization of prior service cost		--			162
Net periodic benefit cost	$	2, 945		$	433

SERP Pension Benefits
(Dollars in Thousands)	Successor Three Months Ended June 30, 2009		Predecessor Three Months Ended June 30, 2008
Components of net periodic benefit cost:
Service cost	$	259	$	234
Interest cost		594		553
Amortization of net loss		--		183
Amortization of prior service cost		--		154
Net periodic benefit cost	$	853	$	1,124

Other Benefits
(Dollars in Thousands)	Successor Three Months Ended June 30, 2009			Predecessor Three Months Ended June 30, 2008
Components of net periodic benefit cost:
Service cost	$	31		$	43
Interest cost		244			283
Expected return on plan assets		(103	)		(197	)
Amortization of net gain		--			(199	)
Amortization of prior service cost		--			21
Amortization of transition obligation		--			13
Net periodic benefit cost (income)	$	172		$	(36	)

The following tables summarize Puget Energy’s net periodic benefit cost for the six months ended June 30, 2009 as compared to the same period in 2008:

Qualified Pension Benefits
(Dollars in Thousands)	Successor February 6, 2009 - June 30, 20091			Predecessor January 1, 2009 - February 5, 2009			Predecessor Six Months Ended June 30, 2008
Components of net periodic benefit cost:
Service cost	$	5,668		$	1,090		$	6,375
Interest cost		11,778			2,302			13,304
Expected return on plan assets		(12,538	)		(3,585	)		(20,782	)
Amortization of net loss		--			269			472
Amortization of prior service cost		--			95			323
Net periodic benefit cost (income)	$	4,908		$	171		$	(308	)

SERP Pension Benefits
(Dollars in Thousands)	Successor February 6, 2009 - June 30, 20091		Predecessor January 1, 2009 - February 5, 2009		Predecessor Six Months Ended June 30, 2008
Components of net periodic benefit cost:
Service cost	$	432	$	89	$	468
Interest cost		990		193		1,105
Amortization of net loss		--		74		366
Amortization of prior service cost		--		51		308
Net periodic benefit cost	$	1,422	$	407	$	2,247

_________________

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.

Other Benefits
(Dollars in Thousands)	Successor February 6, 2009 - June 30, 20091			Predecessor January 1, 2009 - February 5, 2009			Predecessor Six Months Ended June 30, 2008
Components of net periodic benefit cost:
Service cost	$	52		$	11		$	87
Interest cost		406			88			566
Expected return on plan assets		(172	)		(37	)		(394	)
Amortization of net gain		--			(15	)		(398	)
Amortization of prior service cost		--			7			42
Amortization of transition obligation		--			4			25
Net periodic benefit cost (income)	$	286		$	58		$	(72	)

__________________

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.

PSE expects to make contributions totaling $18.0 million to the qualified pension plan for the year ending December 31, 2009. During the three months ended June 30, 2009, PSE contributed $6.0 million to the qualified pension plan. PSE previously disclosed in its financial statements for the year ended December 31, 2008 that it expected contributions by PSE to fund the Supplemental Executive Retirement Plan (SERP) and the other postretirement plans for the year ending December 31, 2009 to be $4.0 million and $0.1 million, respectively. During the six months ended June 30, 2009, PSE contributed $3.5 million to the SERP plan.

During the three and six months ended June 30, 2009, payments of benefits related to PSE’s non-qualified pension plans were $1.9 million and $3.5 million, respectively. During the three and six months ended June 30, 2009, actual contributions for the other postretirement medical benefit plan were $0.4 million and $0.6 million, respectively.

(9)	Regulation and Rates

On May 8, 2009, PSE filed a general rate case requesting recovery of increased electric and natural gas revenue requirements. PSE is requesting an electric general rate increase of approximately $148.1 million or 7.4% annually, and an increase in natural gas rates of $27.2 million or 2.2% annually. This rate request includes an equity component of 48.0% and a requested return on equity of 10.8%. A final order from the Washington Commission is expected by April 2010.

On May 28, 2009, the Washington Commission approved a PGA rate decrease of $21.2 million or 1.7% annually effective June 1, 2009. PGA rate changes do not impact net income.

On April 17, 2009, the Washington Commission issued an order approving and adopting a settlement agreement that authorized PSE to defer certain ownership and operating costs related to its purchase of the Mint Farm Generation Station (Mint Farm) that will be incurred prior to PSE recovering such costs in electric customer rates. Under Washington State law, a jurisdictional electric utility may defer the costs associated with purchasing and operating a natural gas plant that complies with the greenhouse gases (GHG) emissions performance standard until the plant is included in rates or for two years from the date of purchase, whichever occurs sooner. As of June 30, 2009, PSE had established a regulatory asset of $16.4 million per the Washington Commission order. The prudence of the Mint Farm acquisition, recovery of costs of Mint Farm and compliance with the GHG emissions performance standard will be addressed in PSE’s general rate proceeding.

On October 8, 2008, the Washington Commission issued its order in PSE’s consolidated electric and natural gas general rate case filed in December 2007, approving a general rate increase for electric customers of $130.2 million or 7.1% annually, and an increase in natural gas rates of $49.2 million or 4.3% annually. The rate increases for electric and natural gas customers were effective November 1, 2008. In its order, the Washington Commission approved a weighted cost of capital of 8.25% and a capital structure that included 46.0% common equity with a return on equity of 10.15%. The Washington Commission issued a separate order on January 15, 2009, that authorized the continuation of the Power Cost Only Rate Case (PCORC) with certain modifications to which the Washington Commission staff and PSE agreed. The five procedural modifications to the PCORC include extending the expected procedural schedule from five to six months, limiting the power cost updates to one per PCORC unless an additional update is allowed by the Washington Commission as part of the compliance filing, prohibiting the overlap of PCORC and general rate cases (except for requests for interim rate relief), shortening data request time from ten to five business days and requiring PSE to provide its future energy resource model projections at the outset of a case.

On September 25, 2008, the Washington Commission approved PSE’s requested revisions to its PGA tariff schedules resulting in an increase of $108.8 million or 11.1% on an annual basis in gas sales revenues effective October 1, 2008. The rate increase was the result of higher costs of natural gas in the forward market and a reduction of the credit for the accumulated PGA payable balance. The PGA rate change impacted PSE’s revenue but will not impact its net income as the increased revenue will be offset by increased purchased gas costs.

(10)	Litigation

Residential Exchange. Like other investor-owned utilities in the region, PSE has been a party to certain agreements with the Bonneville Power Administration (BPA) that provide payments to PSE which PSE passes through to its residential and small farm electric customers. Several actions in the United States Court of Appeals for the Ninth Circuit (Ninth Circuit) against BPA assert that BPA acted contrary to law in connection with this Residential Exchange Program (REP), including with respect to benefits received or to be received by PSE from BPA and the Ninth Circuit has directed BPA to revisit certain REP calculations relating to payments made in the 2001 to 2006 period. PSE and BPA, separately, also have agreed to certain go-forward REP payment amounts through 2011 and have sought Ninth Circuit review of the agreements related thereto. The amounts of such payments and the methods utilized in setting them are subject to FERC review or judicial review, or both, and are subject to adjustment, which may affect the amount of REP benefits paid or to be paid by BPA to PSE. Although it is not clear what impact, if any, these reviews or other REP-related litigation may ultimately have on PSE, any changes to the REP payments pass through to customers with no impact to PSE’s net income.

PSE Settlement of California Matters. On May 8, 2009, PSE and certain California parties filed a proposed settlement with FERC, seeking FERC’s approval to resolve all the matters and disputes pending between PSE and California parties relating to the western energy crisis. On July 1, 2009, FERC approved that settlement.

Under the settlement, PSE releases all claims to amounts held in, or presumed payable into, certain escrow accounts. In particular, the California Power Exchange and Pacific Gas & Electric (PG&E) will deliver $59.9 million, plus up to $36.8 million in interest, from escrows they maintain to the California parties. The release of those funds fully satisfies all claims by the California parties against PSE and the California parties assume the risk of any shortfalls or adjustments that occur in those accounts.

The settlement resolves all claims by the California parties against PSE in all proceedings and resolves all claims by PSE against California energy purchasers in all proceedings; except that PSE retains any claims or defenses that pertain to the Pacific Northwest Refund Proceedings at FERC.

In addition to the FERC approval obtained 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 (CPUC) of a renewable power agreement between PSE and Southern California Edison (SCE), under which PSE will sell 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.

Use of the proceeds from the renewable power transaction, for ratemaking and accounting purposes, will be determined by the Washington Commission. PSE anticipates that it will receive full recovery of the net California receivable through this proceeding.

The settlement means that PSE’s exposure to western energy crisis claims is now limited to the Pacific Northwest Refund Proceeding, described previously and updated below.

Pacific Northwest Refund Proceeding. In October 2000, PSE filed a complaint at FERC (Docket No. EL01-10) against “all jurisdictional sellers” in the Pacific Northwest seeking prospective price caps consistent with any result FERC ordered for the California markets. In April 2009, the Ninth Circuit rejected the requests for rehearing filed in this matter and remanded the proceeding to FERC. FERC is now considering what response to take to the Court remand order. PSE intends to vigorously defend its position but is unable to predict the outcome of this matter.

(11)	Related Party Transactions

On June 1, 2006, PSE entered into a revolving credit facility with its parent, Puget Energy, in the form of a Demand Promissory Note (Note). Through the Note, PSE may borrow up to $30.0 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 lower of the weighted-average interest rate of: (a) PSE’s outstanding commercial paper interest rate or (b) PSE’s senior unsecured revolving credit facility. At June 30, 2009 and December 31, 2008, the outstanding balance of the Note was $22.9 million and $26.1 million, respectively, and the interest rate was 1.2% and 1.7%, respectively. This Note was unaffected by the February 6, 2009 merger.

Effective with the close of the merger on February 6, 2009, Puget Energy has a $1.225 billion five-year term loan and a $1.0 billion credit facility for funding capital expenditures. These facilities mature in 2014, contain similar terms and conditions and are syndicated among numerous committed banks. One of these banks is Macquarie Bank Limited, which has a commitment of $25.2 million to the term loan and a $20.6 million commitment to the capital expenditure credit facility. As of June 30, 2009, the term loan was fully drawn at $1.225 billion and $258.0 million was outstanding under the $1.0 billion credit facility. On February 6, 2009, Puget Energy entered into several interest rate swap instruments to hedge volatility associated with these two loans. Two of the swap instruments were entered into with Macquarie Bank Limited with a total notional amount of $444.9 million.

(12)

Other

In January 2003, FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46), as further revised in December 2003 with FIN 46R, which clarifies the application of Accounting Research Bulletin No. 51, “Consolidated Financial Statements,” to certain entities in which equity investors do not have a controlling interest or sufficient equity at risk for the entity to finance its activities without additional financial support.

A variable interest entity (VIE) is an entity in which the equity of the investors as a group do not have: (1) the characteristics of a controlling financial interest; (2) sufficient equity at risk for the entity to finance its activities without additional subordinated financial support; or (3) symmetry between voting rights and economic interests and where substantially all of the entity’s activities either involve or are conducted on behalf of an investor with disproportionally few voting rights. Variable interests in a VIE are contractual, ownership or other pecuniary interests in an entity that change with changes in the fair value of the entity’s net assets exclusive of variable interest.

FIN 46R requires that if a business entity has a controlling financial interest in a VIE, the financial statements must be included in the consolidated financial statements of the business entity. The adoption of FIN 46 for all interests in VIEs created after January 31, 2003 was effective immediately. For VIEs created before February 1, 2003, it was effective July 1, 2003. The adoption of FIN 46R was effective March 31, 2004 for PSE.

In December 2008, FASB issued FIN 46R-8, “Disclosures by Public Entities (Enterprises) about Transfers of Financial Assets and Interests in Variable Interest Entities” (FIN 46R-8), which requires new expanded disclosures for VIEs in the quarterly financial statements for periods ending after December 15, 2008. The disclosures required by FIN 46R-8 are intended to provide users of the financial statements with greater transparency about a transferor’s continuing involvement with transferred financial assets and an enterprise’s involvement with VIEs.

A primary beneficiary of a VIE is the variable interest holder (e.g. a contractual counterparty or capital provider), who is deemed to have the controlling financial interest(s) and is considered to be exposed to the majority of the risks and rewards associated with the VIE and therefore must consolidate it. PSE enters into a variety of contracts for energy with other counterparties and evaluates all contracts for variable interests. PSE’s variable interests primarily arise through power purchase agreements where PSE obtains control other than through voting rights and is required to buy all or a majority of generation from a plant at rates set forth in a power purchase agreement, subject to displacement. If a counterparty does not deliver energy to PSE, PSE may have to replace the energy at prices which could be higher or lower than agreed to prices. Therefore, PSE may be exposed to risk associated with replacement costs of a contract.

PSE evaluates variable interest relationships based on significance. If PSE did not participate significantly in the design or redesign of an entity and the variable interest is not considered significant to PSE’s financial statements, the variable interest is not considered significant. Purchase power contracts with governmental organizations do not require disclosure. When PSE determines a significant variable interest may exist with another party, PSE requests information to determine if it is required to be consolidated.

Due to the merger and adoption of SFAS No. 141R, Puget Energy has re-evaluated PSE’s power purchase agreements under Emerging Issues Task Force (EITF) Issue No. 01-8, “Determining Whether an Arrangement Contains a Lease,” (EITF No. 01-8) and FIN 46R. Puget Energy has determined that one power purchase agreement, which was signed prior to FIN 46R, may be considered to be a significant VIE. PSE is required to buy all the generation from the cogeneration plant, subject to displacement by PSE, at rates set forth in the relevant power purchase agreements. As a result, PSE submitted requests for information to that party; however, the party has refused to submit to PSE the necessary information for PSE to determine whether they meet the requirements of a VIE that requires consolidation. PSE will continue to submit requests for information to the counterparty annually to determine if FIN 46R is applicable. PSE’s purchased electricity expense for the three months ended June 30, 2009 and 2008 for this entity was $11.5 million and $9.6 million, respectively. The contract expires in December 2011.

EITF No. 01-8 is to be applied to: (a) arrangements agreed to or committed to, if earlier, after the beginning of an entity’s next reporting period beginning after May 28, 2003; (b) arrangements modified after the beginning of an entity’s next reporting period beginning after May 28, 2003; and (c) arrangements acquired in business. As part of the merger, one power purchase agreement which is reported as a potential VIE for PSE, has been re-evaluated by Puget Energy and is classified as a capital lease. The inception of the contract was prior to EITF No. 01-8 and FIN 46R.

The following table presents PSE’s VIE relationships, irrespective of significance, related to power purchase agreements as of June 30, 2009:

(Dollars in Millions)	Variable Interests in Power Purchase Agreements as of June 30, 2009
Nature of Variable Interest	Longest Contract Tenor	Number of Counterparties		Aggregate Carrying Value Liability 2			Level of Activity - 2009 YTD Expenses 2
Electric-combustion turbine co-generation plant 1	2011		1	$	(3.3	)	$	29.1
Electric-hydro	2037		7		(1.7	)		6.4
Other	2011		2		--			0.2
Total			10	$	(5.0	)	$	35.7

_____________

1	Variable interests may be significant.
2	Carrying values are classified on the balance sheet in accounts payable and expenses are classified on the income statement in purchased electricity.

Snoqualmie Falls Project

PSE received a new 40-year operating license for its Snoqualmie Falls hydroelectric project from FERC in 2004. The license contained an array of FERC-approved plans to upgrade the facility. Due to changed circumstances, on December 6, 2007, PSE filed an application for a non-capacity amendment to the license to account for technology improvements and hydrologic and other changes. On June 1, 2009, FERC issued an order amending the license that incorporates the changes requested by PSE. This order is final and no party sought rehearing or review.

(13)	New Accounting Pronouncements

In June 2009, FASB issued, Accounting Standards Update No. 2009-01, Topic 105, “Generally Accepted Accounting Principles amendments based on the Statement of Financial Standards No. 168 – The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles” and SFAS No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles, a replacement of FASB Statement No. 162” (SFAS No. 168). The Accounting Standards Update and SFAS No. 168 make the FASB Codification the authoritative source of GAAP. The FASB Codification is effective for interim and annual reporting periods ending after September 15, 2009, which will be September 30, 2009 for Puget Energy. Puget Energy will update GAAP referencing for the third quarter 2009 Form 10-Q. The FASB Codification is not expected to have a material impact on the financial reporting of Puget Energy.

In June 2009, FASB issued SFAS No. 167, “Amendments to FASB Interpretation No. 46 (R)” (SFAS No. 167). This Statement replaces a quantitative approach with a qualitative approach to determine whether PSE’s variable interest or interests give it a controlling financial interest in a VIE. In addition, the Statement requires enhanced disclosures which will provide users of the financial statements with more transparent information about an enterprises involvement in a VIE. SFAS No. 167 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 Puget Energy. Puget Energy is assessing the impact of SFAS No. 167.

In May 2009, FASB issued SFAS No. 165, “Subsequent Events” (SFAS No. 165). The standard does not require significant changes regarding recognition or disclosure of subsequent events but does require disclosure of the date through which subsequent events have been evaluated for disclosure and recognition. The standard is effective for financial statements issued after June 15, 2009 which was the quarter ended June 30, 2009. The implementation of this standard did not have a significant impact on the financial statements of Puget Energy. Puget Energy has performed an evaluation of subsequent events through August 13, 2009, which is the date the financial statements were issued.

On April 9, 2009, FASB issued Staff Position (FSP) No. 107-1, “Interim Disclosures about Fair Value of Financial Instruments” (FSP No. 107-1). FSP No. 107-1 amends SFAS No. 107, “Disclosures about Fair Value of Financial Instruments,” to require disclosures about fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. FSP No. 107-1 also amends APB Opinion No. 28, “Interim Financial Reporting,” to require those disclosures in summarized financial information at interim reporting periods. FSP No. 107-1 was effective for Puget Energy as of June 30, 2009.

On April 9, 2009, FASB issued FSP 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (FSP No. 157-4). FSP No. 157-4 became effective for Puget Energy as of June 30, 2009. FSP No. 157-4 provides additional guidance for estimating fair value in accordance with SFAS No. 157, when the volume and level of activity for the asset or liability have significantly decreased. FSP No. 157-4 also includes guidance on identifying circumstances that indicate a transaction is not orderly. As of June 30, 2009, Puget Energy has determined that FSP No. 157-4 has no impact to its consolidated financial position or results of operations.

On January 1, 2009, Puget Energy adopted SFAS No. 141(R), “Business Combinations.” SFAS No. 141(R) replaces FASB Statement No. 141, “Business Combinations,” and addresses the accounting for all transactions or other events in which an entity obtains control of one or more businesses. The objective of SFAS No. 141(R) is to improve the relevance, representational faithfulness and comparability of the information that a reporting entity provides in its financial reports about a business combination and its effects. To accomplish that, SFAS No. 141(R) establishes principles and requirements for how the acquirer: (1) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree, (2) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase and (3) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination.

On December 30, 2008, FASB issued FSP No. 132(R) -1, “Employers’ Disclosures about Postretirement Benefit Plan Assets” (FSP No. 132(R)-1). FSP No. 132(R)-1 directs companies to provide additional disclosures about plan assets of a defined benefit pension or other postretirement plan. The objectives of the disclosures are to disclose the following: (1) how investment allocation decisions are made, including the factors that are pertinent to an understanding of investment policies and strategies, (2) major categories of plan assets, (3) inputs and valuation techniques used to measure the fair value of plan assets, (4) effect of fair value measurements using significant unobservable inputs (Level 3) on changes in plan assets for the period and (5) significant concentrations of risk within plan assets. FSP No. 132(R)-1 is effective for the fiscal year December 15, 2009, which will be effective for Puget Energy for the fiscal year end December 31, 2009. Puget Energy is currently assessing the impact of FSP No. 132(R)-1.

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

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

Overview

Puget Energy, Inc. (Puget Energy) is an energy services holding company and all of its operations are conducted through its subsidiary Puget Sound Energy, Inc. (PSE), a regulated electric and natural gas utility company. Puget Energy is dependent upon the results of PSE since PSE is its most significant asset. Puget Energy’s business strategy is to generate stable earnings and cash flow by offering reliable electric and natural gas service in a cost effective manner through PSE.

Puget Energy Merger

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 led by Macquarie Infrastructure Partners I, Macquarie Capital Group Limited, Canada Pension Plan Investment Board and British Columbia Investment Management Corporation, and also includes Alberta Investment Management Corporation, Macquarie-FSS Infrastructure Trust and Macquarie Infrastructure Partners II (collectively, the Consortium). At the time of the merger, each issued and outstanding share of common stock of Puget Energy, other than any shares owned by the Consortium, were cancelled and converted automatically into the right to receive $30.00 in cash, without interest. 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. On January 16, 2009, Standard & Poor’s Rating Services (S&P) raised its corporate credit rating on PSE while it lowered its corporate credit rating for Puget Energy. At the same time it removed both companies from its watch list for negative implications citing a stable outlook. The rating actions reflected the completion of the acquisition of Puget Energy and PSE by Puget Holdings, which occurred on February 6, 2009. On February 2, 2009, Moody’s Investors Service (Moody’s) downgraded the Issuer Rating of Puget Energy to Ba2 from Ba1 and affirmed the long-term ratings of PSE. The ratings outlook for both companies is stable. Puget Energy’s equity ratio increased from 38.4% at December 31, 2008 to 44.9% at June 30, 2009.

Puget Sound Energy

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. PSE generates revenues primarily from the sale of electric and natural gas services to residential and commercial customers within Washington State. PSE’s operating revenues and associated expenses are not generated evenly throughout the year. Variations in energy usage by consumers occur from season to season and from month to month within a season, primarily as a result of weather conditions. PSE normally experiences its highest retail energy sales and subsequently higher power costs during the winter heating season in the first and fourth quarters of the year and its lowest sales in the third quarter of the year. Varying wholesale electric prices and the amount of hydroelectric energy supplies available to PSE also make quarter to quarter comparisons difficult. For 2009, PSE is experiencing lower customer usage due to warmer temperatures in 2009 as compared to 2008 and the effects of the recession on Washington State’s economy.

Colstrip Unit 4 has been out of service since March 2009 due to significant repair work required to the unit which was discovered during its routine overhaul. It is estimated that the unit will be out of service until November 2009 and that PSE will incur higher power costs of approximately $16.0 million from July through October 2009. PSE has a 25.0% ownership interest in the 370 megawatt (MW) electric generating facility. The Colstrip owners are assessing the need to inspect and/or repair Colstrip Unit 3 based on the causes of the Colstrip Unit 4 repairs. No decision by the Colstrip owners has been made at this time.

Non-GAAP Financial Measures – Energy Margins

The following discussion includes financial information prepared in accordance with Generally Accepted Accounting Principles (GAAP), as well as two other financial measures, electric margin and gas margin, that are considered “non-GAAP financial measures.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that exclude (or include) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. The presentation of electric margin and gas margin is intended to supplement investors’ understanding of PSE’s operating performance. Electric margin and gas margin are used by PSE to determine whether PSE is collecting the appropriate amount of energy costs from its customers to allow recovery of operating costs. Puget Energy’s electric margin and gas margin measures may not be comparable to other companies’ electric margin and gas margin measures. Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.

Results of Operations

Puget Energy

All the operations of Puget Energy are conducted through its subsidiary PSE. “Predecessor Company” refers to the operations of Puget Energy and PSE prior to the consummation of the merger. “Successor Company” refers to the operations of Puget Energy and PSE subsequent to the merger. The merger was accounted for in accordance with the Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 141R, “Business Combinations” (SFAS No. 141R). The purchase price was allocated to the related assets and liabilities based on their respective estimated fair values on the merger date with the remaining consideration recorded as goodwill. The fair values of assets are being amortized over their estimated useful lives in a manner that best reflects the economic benefits derived from such assets. Goodwill is not amortized, but is subject to impairment testing on an annual basis. Such adjustments to fair value and the allocation of purchase price between identifiable intangibles and goodwill will have an impact on Puget Energy’s expenses and profitability.

Puget Energy’s net income for the three and six months ended June 30 is as follows:

(Dollars in Millions)	Successor Three Months Ended June 30, 2009			Predecessor Three Months Ended June 30, 2008			Successor February 6, 2009 - June 30, 2009			Predecessor January 1, 2009 - February 5, 2009			Combined 2009			Predecessor Six Months Ended June 30, 2008
PSE	$	43.8		$	39.1		$	97.1		$	31.7		$	128.8		$	120.0
Puget Energy (parent)		(0.2	)		(5.4	)		(1.5	)		(18.9	)		(20.4	)		(6.5	)
Net income	$	43.6		$	33.7		$	95.6		$	12.8		$	108.4		$	113.5

Puget Energy’s net income for the three months ended June 30, 2009 was $43.6 million on operating revenues of $686.6 million as compared to net income of $33.7 million on operating revenues of $712.4 million for the same period in 2008, which included PSE net income of $43.8 million and operating revenues of $686.3 million. Net income was positively impacted by a $5.0 million pre-tax increase in PSE’s electric margin and partially offset by a $2.3 million pre-tax decrease in PSE’s gas margin. Electric and natural gas margins were favorably impacted by general tariff rate increases of 7.1% and 4.3%, respectively, that were approved by the Washington Utilities and Transportation Commission (Washington Commission) and were effective November 1, 2008. Electric and natural gas margins were impacted by lower customer usage which declined 4.8% and 16.0%, respectively primarily due to warmer average temperatures in the Pacific Northwest during the second quarter of 2009 compared to the same period in 2008. Electric margin was also impacted due to the extended Colstrip outage which resulted in the purchase of electricity priced approximately $2.0 million higher than Colstrip production cost. PSE owns a 25% interest in Colstrip Unit 4 with its share of the output being 185 MWs. Net income was negatively impacted by an increase in utility operations and maintenance expenses of $5.6 million, a $3.0 million increase in taxes other than income taxes and an increase in depreciation and amortization of $6.0 million. These decreases to electric margin were partially offset by an increase in unrealized gains related to derivatives of $35.8 million primarily driven by warmer temperatures in the Pacific Northwest during the second quarter of 2009 as compared to the same period of 2008. Also adversely impacting 2009 revenue is the impact of a weaker economy.

PSE’s basis of accounting will continue to be on a historical basis and PSE’s financial statements will not include any SFAS No. 141R purchase accounting adjustments. Puget Energy’s net income was also impacted by purchase accounting related to valuations of PSE’s assets and liabilities and additional interest expense at Puget Energy as a result the issuance of debt at the time of the merger. Puget Energy’s net income was positively impacted by unrealized gains on derivative instruments related to settlements of contracts and mark-to-market accounting of derivative contracts which increased net income by an additional $28.3 million pre-tax due to purchase accounting and changes in the forward market prices on natural gas and electricity. These contracts were reassessed and valued at Puget Energy due to purchase accounting. Net income was impacted by increases in interest expense of $22.9 million related to the issuance of debt at the time of the merger. There was a $1.8 million increase due to pension and postretirement plan costs associated with the remeasurement of PSE’s retirement plans at the time of the merger and various other costs of $3.6 million.

Net income for the six months ended June 30, 2009 was $108.4 million on operating revenues of $1.8 billion as compared to net income of $113.5 million on operating revenues of $1.8 billion for the same period in 2008, which included PSE net income of $128.8 million and operating revenues of $1.8 billion. Net income for the six months ended June 30, 2009 as compared to the same period in 2008 was positively impacted by a $31.1 million pre-tax increase in electric margin and a $9.9 million pre-tax increase in gas margin. Electric and natural gas margins were favorably impacted by general tariff rate increases of 7.1% and 4.3%, respectively, that were approved by the Washington Commission and were effective November 1, 2008. Electric and natural gas margins were impacted by lower customer usage which declined 2.4% and 6.7%, respectively. Electric margin was also impacted due to the extended Colstrip outage which resulted in purchasing higher priced electricity than the Colstrip production cost.

Net income was negatively impacted by one-time merger costs of $40.0 million, of which $23.9 million was from PSE relating to the merger of Puget Energy with Puget Holdings. These costs were primarily related to PSE employee compensation triggered by the Puget Energy’s change of control, credit agreement related expenses and the income statement impact of deferred compensation related liability increases triggered by the merger. Net income was also negatively impacted due to an increase in depreciation and amortization of $11.9 million and an increase of $8.4 million in utility operations and maintenance. These increases were partially offset by a $44.2 million increase in unrecognized gain on derivatives. Puget Energy net income was also impacted by purchase accounting and interest expenses at Puget Energy. Puget Energy net income was positively impacted by an increase in unrealized gains on derivative instruments related to settlement and mark-to-market accounting of derivative contracts which increased net income by an additional $38.8 million pre-tax due to purchase accounting and changes in the forward market prices on natural gas and electricity. Net income was impacted by increases in interest expense of $30.8 million related to the issuance of debt at the time of the merger, a $5.0 million charitable contribution to the PSE Foundation, and a $3.2 million increase due to pension and postretirement plan costs.

The following tables set forth changes between Puget Energy and PSE income statements as a result of purchase accounting adjustments, merger related costs and Puget Energy operating expenses. Significant changes related to Puget Energy will be discussed below while PSE changes will be discussed under “Puget Energy Results from the Operations of Puget Sound Energy”.

(Dollars in Millions)	Successor									Predecessor
Three Months Ended June 30,	2009									2008
	PSE			Puget Energy (Parent)			Total Puget Energy			Puget Energy			Change
Other operating revenue	$	2.6		$	0.4		$	3.0		$	0.5		$	2.5
Purchased electricity		188.9			(0.1	)		188.8			198.9			(10.1	)
Unrealized gain on derivative instruments		(9.9	)		(28.3	)		(38.2	)		(2.4	)		(35.8	)
Non-utility expense and other		2.1			2.2			4.3			1.6			2.7
Merger related costs		(3.7	)		4.0			0.3			5.7			(5.4	)
Depreciation and amortization		82.4			(0.1	)		82.3			76.3			6.0
Interest expense		48.3			22.9			71.2			46.8			24.4
Income tax expense		13.5			0.1			13.6			13.3			0.3

	Successor									Predecessor					Predecessor
(Dollars in Millions)	February 6, 2009 - June 30, 2009									January 1, 2009 - February 5, 2009		Combined			Six Months Ended June 30, 2008
	PSE			Puget Energy (Parent)			Total Puget Energy			Puget Energy		Total Puget Energy			Puget Energy			Change
Other operating revenue	$	3.4		$	0.4		$	3.8		$	0.1	$	3.9		$	2.1		$	1.8
Purchased electricity		358.5			(0.3	)		358.2			90.7		448.9			471.7			(22.8	)
Unrealized (gain)loss on derivative instruments		(11.5	)		(38.8	)		(50.3	)		3.9		(46.4	)		(2.3	)		(44.1	)
Non-utility expense and other		3.3			3.5			6.8			0.1		6.9			2.1			4.8
Merger related costs		--			2.7			2.7			44.3		47.0			7.0			40.0
Depreciation and amortization		137.0			(0.1	)		136.9			26.7		163.6			151.7			11.9
Other expense		3.8			5.0			8.8			0.4		9.2			1.8			7.4
Interest expense		82.3			30.7			113.0			16.9		129.9			95.4			34.5
Income tax expense		36.4			(0.8	)		35.6			9.0		44.6			48.6			(4.0	)

Unrealized gain on derivative instruments at Puget Energy was higher than the unrealized gain at PSE by $28.3 million and $38.8 million for the three and six months ended June 30, 2009, respectively, due to the reassessment of derivatives due to purchase accounting under SFAS No. 141R. Puget Energy revalued the contracts at the date of the merger and determined that certain Normal Purchase Normal Sale (NPNS) contracts would be marked-to-market on Puget Energy financial statements while they remain NPNS contracts on PSE financial statements. In addition, at the time of the merger, cash flow hedge contracts had recorded an unrealized loss in accumulated OCI which was moved to goodwill in accordance with SFAS No. 141R. As these contract settle, the losses reflected at the time of the merger are reversed through earnings at Puget Energy while it is reversed through OCI at PSE.

Non-utility expense and other at Puget Energy was higher than PSE by $2.2 million and $3.5 million for the three and six months ended June 30, 2009, respectively, primarily related to a remeasurement of PSE’s pension and post retirement plans due to the merger under SFAS No. 141R, which contributed $1.8 million and $3.2 million for the three and six months ended June 30, 2009.

Other expense increased $5.0 million at Puget Energy due to a charitable contribution to PSE Foundation for the six months ended June 30, 2009.

Interest expense at Puget Energy increased $22.9 million and $30.7 million for the three and six months ended June 30, 2009 due to the term loan and credit facility entered into by the Consortium as part of the purchase of Puget Energy.

Income tax expense decreased $4.0 million for the six months ended June 30, 2009 as compared to the same period in 2008. The difference is due primarily to a lower effective tax rate as a result of an increased amount of production tax credits and projected lower annualized income for 2009 which reduced taxes by $2.0 million. The remaining $2.0 million decrease is related to tax deductible interest.

Puget Energy Results from the Operations of Puget Sound Energy

All the operations of Puget Energy are conducted through its subsidiary PSE. “Predecessor Company” refers to the operations of PSE prior to the consummation of the merger. “Successor Company” refers to the operations of PSE subsequent to the merger.

PSE’s operating revenues and expenses are not generated evenly throughout the year. 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 fourth quarters of the year and its lowest sales in the third quarter of the year. Power cost recovery is seasonal, with underrecovery normally in the first and fourth quarters when electric sales volumes and power costs are higher and over recovery in the second and third quarters. Varying wholesale electric prices and the amount of hydroelectric energy supplies available to PSE also make quarter to quarter comparisons difficult.

Energy Margins

The following table displays the details of PSE’s electric margin changes for the three months ended June 30, 2009 as compared to the same period in 2008. Electric margin is electric sales to retail and transportation customers less pass-through tariff items, revenue-sensitive taxes, and the cost of generating and purchasing electric energy sold to customers, including transmission costs to bring electric energy to PSE’s service territory.

	Electric Margin
(Dollars in Millions) Three Months Ended June 30,	Successor 2009			Predecessor 2008			Change			Percent Change
Electric operating revenue 1	$	456.8		$	478.0		$	(21.2	)	(4.4	) %
Less: Other electric operating revenue		(6.9	)		(20.3	)		13.4		66.0
Add: Other electric operating revenue-gas supply resale		(5.0	)		8.3			(13.3	)	*
Total electric revenue for margin		444.9			466.0			(21.1	)	(4.5	)
Adjustments for amounts included in revenue:
Pass-through tariff items		(14.9	)		(16.2	)		1.3		8.0
Pass-through revenue-sensitive taxes		(33.6	)		(32.9	)		(0.7	)	(2.1	)
Net electric revenue for margin		396.4			416.9			(20.5	)	(4.9	)
Minus power costs:
Purchased electricity 1		(188.9	)		(198.9	)		10.0		5.0
Electric generation fuel 1		(17.8	)		(32.7	)		14.9		45.6
Residential exchange 1		20.9			20.3			0.6		3.0
Total electric power costs		(185.8	)		(211.3	)		25.5		12.1
Electric margin 2	$	210.6		$	205.6		$	5.0		2.4	%

____________________________

1	As reported on PSE’s Consolidated Statements of Income in PSE’s Report on Form 10-Q for the period ended June 30, 2009.
2	Electric margin does not include any allocation for amortization/depreciation expense or electric generation operation and maintenance expense.
*	Percent change not applicable or meaningful.

Electric margin increased $5.0 million for the three months ended June 30, 2009 as compared to the same period in 2008. Electric margin increased $16.8 million due to a general rate case increase of 7.1% effective November 1, 2008. This increase was partially offset by a $10.2 million decrease in margin due to a 4.8% decrease in retail kilowatt hour (kWh) sales as a result of decreased customer usage and a $1.6 million decrease in other items due primarily to an increase in purchase power costs related to the aforementioned outage at a Colstrip generating unit which is undergoing major repair and lower hydroelectric generation as compared to 2008.

The following table displays the details of PSE’s electric margin changes for the six months ended June 30, 2009 as compared to the same period in 2008. Electric margin is electric sales to retail and transportation customers less pass-through tariff items, revenue-sensitive taxes, and the cost of generating and purchasing electric energy sold to customers, including transmission costs to bring electric energy to PSE’s service territory.

	Electric Margin
(Dollars in Millions) Six Months Ended June 30,	Successor February 6, 2009 - June 30, 2009			Predecessor January 1, 2009 - February 5, 2009			Combined 2009			Predecessor 2008			Change			Percent Change
Electric operating revenue 1	$	843.4		$	213.6		$	1,057.0		$	1,084.2		$	(27.2	)	(2.5	) %
Less: Other electric operating revenue		(9.6	)		1.8			(7.8	)		(32.5	)		24.7		76.0
Add: Other electric operating revenue-gas supply resale		(9.2	)		(4.6	)		(13.8	)		11.0			(24.8	)	*
Total electric revenue for margin		824.6			210.8			1,035.4			1,062.7			(27.3	)	(2.6	)
Adjustments for amounts included in revenue:
Pass-through tariff items		(28.7	)		(7.9	)		(36.6	)		(29.1	)		(7.5	)	(25.8	)
Pass-through revenue-sensitive taxes		(62.0	)		(15.9	)		(77.9	)		(74.6	)		(3.3	)	(4.4	)
Net electric revenue for margin		733.9			187.0			920.9			959.0			(38.1	)	(4.0	)
Minus power costs:
Purchased electricity 1		(358.5	)		(90.7	)		(449.2	)		(471.7	)		22.5		4.8
Electric generation fuel 1		(54.0	)		(12.0	)		(66.0	)		(79.7	)		13.7		17.2
Residential exchange 1		40.8			12.5			53.3			20.3			33.0		*
Total electric power costs		(371.7	)		(90.2	)		(461.9	)		(531.1	)		69.2		13.0
Electric margin 2	$	362.2		$	96.8		$	459.0		$	427.9		$	31.1		7.3	%

_____________________

1	As reported on PSE’s Consolidated Statements of Income in PSE’s Report on Form 10-Q for the period ended June 30, 2009.
2	Electric margin does not include any allocation for amortization/depreciation expense or electric generation operation and maintenance expense.
*	Percent change not applicable or meaningful.

Electric margin increased $31.1 million for the six months ended June 30, 2009 as compared to the same period in 2008. The increase in electric margin was primarily due to a general tariff rate increase of 7.1% or $40.0 million. This increase was partially offset by a decrease in margin due to a 2.4% decrease in retail kWh sales and increased costs due to the Colstrip outage and a 7.3% decline in hydroelectric generation for the six months ended June 30, 2009 as compared to the same period in 2008.

The following table displays the details of PSE’s gas margin changes for the three months ended June 30, 2009 as compared to the same period in 2008. Gas margin is natural gas sales to retail and transportation customers less pass-through tariff items and revenue-sensitive taxes, and the cost of natural gas purchased, including transportation costs to bring natural gas to PSE’s service territory.

	Gas Margin
(Dollars in Millions) Three Months Ended June 30,	Successor 2009			Predecessor 2008			Change			Percent Change
Gas operating revenue 1	$	226.9		$	233.8		$	(6.9	)	(3.0	) %
Less: Other gas operating revenue		(5.2	)		(4.2	)		(1.0	)	23.8
Total gas revenue for margin		221.7			229.6			(7.9	)	(3.4	)
Adjustments for amounts included in revenue:
Pass-through tariff items		(2.5	)		(2.3	)		(0.2	)	(8.7	)
Pass-through revenue-sensitive taxes		(20.1	)		(20.3	)		0.2		1.0
Net gas revenue for margin		199.1			207.0			(7.9	)	(3.8	)
Minus purchased gas costs 1		(132.1	)		(137.7	)		5.6		(4.1	)
Gas margin 2	$	67.0		$	69.3		$	(2.3	)	(3.3	) %

____________________

1	As reported on PSE’s Consolidated Statement of Income in PSE’s Report on Form 10-Q for the period ended June 30, 2009.
2	Gas margin does not include any allocation for amortization/depreciation expense or electric generation operations and maintenance expense.

Gas margin decreased $2.3 million for the three months ended June 30, 2009 compared to the same period in 2008. There was a 16.0% decrease in gas therm sales related to warmer temperatures in 2009 as compared to the same period in 2008 which contributed to a $12.5 million decrease to margin. This decrease was partially offset by a general rate case increase of 4.3% effective November 1, 2008 which contributed to a $7.2 million increase in margin as well as customer mix and other pricing variances contributed to a $3.0 million increase.

The following table displays the details PSE’s of gas margin changes for the six months ended June 30, 2009 as compared to the same period in 2008. Gas margin is natural gas sales to retail and transportation customers less pass-through tariff items and revenue-sensitive taxes, and the cost of natural gas purchased, including transportation costs to bring natural gas to PSE’s service territory.

	Gas Margin
(Dollars in Millions) Six Months Ended June 30,	Successor February 6, 2009 - June 30, 2009			Predecessor January 1, 2009 - February 5, 2009			Combined 2009			Predecessor 2008			Change			Percent Change
Gas operating revenue 1	$	543.4		$	190.0		$	733.4		$	677.1		$	56.3		8.3	%
Less: Other gas operating revenue		(8.6	)		(1.6	)		(10.2	)		(8.9	)		(1.3	)	(14.6	)
Total gas revenue for margin		534.8			188.4			723.2			668.2			55.0		8.2
Adjustments for amounts included in revenue:
Pass-through tariff items		(5.4	)		(1.8	)		(7.2	)		(6.7	)		(0.5	)	(7.5	)
Pass-through revenue-sensitive taxes		(46.3	)		(15.4	)		(61.7	)		(55.4	)		(6.3	)	(11.4	)
Net gas revenue for margin		483.1			171.2			654.3			606.1			48.2		8.0
Minus purchased gas costs 1		(331.3	)		(120.9	)		(452.2	)		(413.9	)		(38.3	)	(9.3	)
Gas margin 2	$	151.8		$	50.3		$	202.1		$	192.2		$	9.9		5.2	%

____________________

1	As reported on PSE’s Consolidated Statement of Income in PSE’s Report on Form 10-Q for the period ended June 30, 2009.
2	Gas margin does not include any allocation for amortization/depreciation expense or electric generation operations and maintenance expense.

Gas margin increased $9.9 million for the six months ended June 30, 2009 as compared to the same period in 2008 primarily due to a $27.7 million increase in margin primarily due to the general tariff rate increase of 4.3% effective November 1, 2008. This increase was partially offset by a $12.8 million decrease in margin due to a 6.7% decrease in gas therm volume due to warmer weather in 2009 as compared to 2008 and a $5.0 million decrease due to customer mix and other pricing variances.

Electric Operating Revenues

The table below sets forth changes in electric operating revenues for PSE for the three months ended June 30, 2009 as compared to the same period in 2008.

(Dollars in Millions) Three Months Ended June 30,	Successor 2009			Predecessor 2008			Change			Percent Change
Electric operating revenues:
Residential sales	$	240.4		$	237.1		$	3.3		1.4	%
Commercial sales		198.0			189.4			8.6		4.5
Industrial sales		23.9			26.1			(2.2	)	(8.4	)
Other retail sales, including unbilled revenue		(25.7	)		(20.7	)		(5.0	)	24.2
Total retail sales		436.6			431.9			4.7		1.1
Transportation sales		2.3			1.4			0.9		64.3
Sales to other utilities and marketers		10.9			24.4			(13.5	)	(55.3	)
Other		7.0			20.3			(13.3	)	(65.5	)
Total electric operating revenues	$	456.8		$	478.0		$	(21.2	)	(4.4	)%

Electric retail sales increased $4.7 million for the three months ended June 30, 2009 as compared to the same period in 2008. The increase was due in part to the electric general rate increase of November 1, 2008 partially offset by a merger rate credit effective February 13, 2009, which combined, contributed to an increase in electric retail sales of $29.5 million for 2009 as compared to 2008. This increase was partially offset by a $2.2 million decrease in the conservation rider charged to customers for PSE’s energy efficiency programs, which has no impact on net income as the amount is offset in conservation amortization. Also partially offsetting these increases was a decrease in retail electricity usage of 243,899 megawatt hours (MWhs) or 4.8% related to decreased customer usage for 2009 as compared to the same period in 2008, which resulted in a decrease of approximately $22.2 million to electric operating revenue. The benefits of the Residential and Farm Energy Exchange Benefit credited to customers reduced electric operating revenues by $0.7 million. This credit also reduced power costs and revenue sensitive taxes by a corresponding amount with no impact on earnings.

Sales to other utilities and marketers decreased $13.5 million for the three months ended June 30, 2009 as compared to the same period in 2008 primarily due to a decrease in wholesale electric energy prices and a 7.5% decline in kWh volumes.

Other electric operating revenues decreased $13.3 million for the three months ended June 30, 2009 as compared to the same period in 2008 primarily due to a decrease of $13.7 million in non-core gas sales and related losses from hedging contracts entered into to manage electric generation fuel costs.

The table below sets forth changes in electric operating revenues for PSE for the six months ended June 30, 2009 as compared to the same period in 2008.

(Dollars in Millions) Six Months Ended June 30,	Successor February 6, 2009 - June 30, 2009			Predecessor January 1, 2009 - February 5, 2009			Combined 2009			Predecessor 2008			Change			Percent Change
Electric operating revenues:
Residential sales	$	466.7		$	132.5		$	599.2		$	583.7		$	15.5		2.7	%
Commercial sales		349.9			79.6			429.5			401.5			28.0		7.0
Industrial sales		41.7			8.8			50.5			53.5			(3.0	)	(5.6	)
Other retail sales, including unbilled revenue		(46.6	)		(8.5	)		(55.1	)		(32.3	)		(22.8	)	(70.6	)
Total retail sales		811.7			212.4			1,024.1			1,006.4			17.7		1.8
Transportation sales		4.3			0.5			4.8			2.9			1.9		65.5
Sales to other utilities and marketers		17.9			2.4			20.3			42.4			(22.1	)	(52.1	)
Other		9.5			(1.7	)		7.8			32.5			(24.7	)	(76.0	)
Total electric operating revenues	$	843.4		$	213.6		$	1,057.0		$	1,084.2		$	(27.2	)	(2.5	)%

Electric retail sales increased $17.7 million for the six months ended June 30, 2009 as compared to the same period in 2008. The increase was due in part to the electric general rate increase of November 1, 2008 partially offset by a merger rate credit effective February 13, 2009, which combined, contributed to an increase in electric retail sales of $70.6 million for 2009 as compared to 2008. Also positively impacting retail sales is $5.3 million related to an increase in the conservation rider charged to customers due to an increase in PSE’s energy efficiency programs, which has no impact on net income as the amount is offset in conservation amortization. This increase was partially offset by the benefits of the Residential and Farm Energy Exchange Benefit credited to customers which reduced electric operating revenues by $34.6 million. This credit also reduced power costs and revenue sensitive taxes by a corresponding amount with no impact on earnings. Also partially offsetting these increases was a decrease in retail electricity usage of 274,245 MWhs or 2.4% related to decreased customer usage for 2009 as compared to the same period in 2008, which resulted in a decrease of approximately $25.2 million to electric operating revenue.

Sales to other utilities and marketers decreased $22.1 million for the six months ended June 30, 2009 as compared to the same period in 2008 primarily due to a decrease in wholesale electric energy prices and a 4.2% decline in kWh volumes.

Other electric operating revenues decreased $24.7 million for the six months ended June 30, 2009 as compared to the same period in 2008 primarily due to $24.9 million decrease in non-core gas sales and related losses from hedging contracts entered into to manage electric generation fuel costs.

The following electric rate changes were approved by the Washington Commission in 2008 and 2009:

Type of Rate Adjustment	Effective Date	Average Percentage Increase (Decrease) in Rates	Annual Increase (Decrease) in Revenues (Dollars in Millions)
Electric General Rate Case	November 1, 2008	7.1 %	$ 130.2
Merger Rate Credit	February 13, 2009	(0.4)	(6.7)

Gas Operating Revenues

The table below sets forth changes in gas operating revenues for PSE for the three months ended June 30, 2009 as compared to the same period in 2008.

(Dollars in Millions) Three Months Ended June 30,	Successor 2009		Predecessor 2008		Change			Percent Change
Gas operating revenues:
Residential sales	$	142.1	$	144.3	$	(2.2	)	(1.5	)%
Commercial sales		68.1		72.1		(4.0	)	(5.5	)
Industrial sales		8.3		9.7		(1.4	)	(14.4	)
Total retail sales		218.5		226.1		(7.6	)	(3.4	)
Transportation sales		3.1		3.4		(0.3	)	(8.8	)
Other		5.3		4.3		1.0		23.3
Total gas operating revenues	$	226.9	$	233.8	$	(6.9	)	(3.0	)%

Gas retail sales decreased $7.6 million for the three months ended June 30, 2009 as compared to the same period in 2008 primarily due to a 35.4 million decrease in gas therm sales related to warmer temperatures for the three months ended June 30, 2009 as compared to the same period in 2008, which decreased revenue by $50.4 million. Partially offsetting the decrease is a $43.0 million increase in gas operating revenues as a result of a 11.1% Purchased Gas Adjustment (PGA) mechanism rate increase for retail customers effective October 1, 2008, a general rate increase effective November 1, 2008 and a 1.7% PGA mechanism rate decrease effective June 1, 2009. The PGA mechanism passes through to customers 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 from producers and wholesale marketers or changes in natural gas pipeline transportation costs. PSE’s gas margin and net income are not affected by changes under the PGA mechanism.

The table below sets forth changes in gas operating revenues for PSE for the six months ended June 30, 2009 as compared to the same period in 2008.

(Dollars in Millions) Six Months Ended June 30,	Successor February 6, 2009 - June 30, 2009		Predecessor January 1, 2009 - February 5, 2009		Combined 2009		Predecessor 2008		Change			Percent Change
Gas operating revenues:
Residential sales	$	355.5	$	130.8	$	486.3	$	438.5	$	47.8		10.9	%
Commercial sales		155.7		51.9		207.6		200.0		7.6		3.8
Industrial sales		18.1		4.9		23.0		22.5		0.5		2.2
Total retail sales		529.3		187.6		716.9		661.0		55.9		8.5
Transportation sales		5.5		0.8		6.3		7.2		(0.9	)	(12.5	)
Other		8.6		1.6		10.2		8.9		1.3		14.6
Total gas operating revenues	$	543.4	$	190.0	$	733.4	$	677.1	$	56.3		8.3	%

Gas retail sales increased $55.9 million for the six months ended June 30, 2009 as compared to the same period in 2008 due to a $105.1 million increase in gas operating revenues as a result of a 11.1% PGA mechanism rate increase for retail customers effective October 1, 2008, a general rate increase effective November 1, 2008 and a 1.7% PGA mechanism rate decrease effective June 1, 2009. The PGA mechanism passes through to customers 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 from producers and wholesale marketers or changes in natural gas pipeline transportation costs. PSE’s gas margin and net income are not affected by changes under the PGA mechanism. Partially offsetting the increase is a 36.4 million decrease in gas therm sales which decreased revenue by $49.9 million.

The following natural gas rate adjustments were approved by the Washington Commission in 2008 and 2009:

Type of Rate Adjustment	Effective Date	Average Percentage Increase (Decrease) in Rates	Annual Increase (Decrease) in Revenues (Dollars in Millions)
Purchased Gas Adjustment	October 1, 2008	11.1 %	$ 108.8
General Rate Case	November 1, 2008	4.3	49.2
Merger Rate Credit	February 13, 2009	(0.4)	(3.6)
Purchased Gas Adjustment	June 1, 2009	(1.7)	(21.2)

Non-Utility Operating Revenues

The table below sets forth changes in non-utility operating revenues for PSE for the three and six months ended June 30, 2009, respectively, as compared to the same period in 2008.

(Dollars in Millions) Three Months Ended June 30,	2009		2008		Change		Percent Change
Non-utility operating revenue	$ 2.6		$ 0.5		$ 2.1		*

_______________

*	Percent change not applicable or meaningful.

(Dollars in Millions) Six Months Ended June 30,	2009		2008		Change		Percent Change
Non-utility operating revenue	$ 3.5		$ 2.1		$ 1.4		66.7	%

Non-utility operating revenues increased $2.1 million and $1.4 million for the three and six months ended June 30, 2009, respectively, as compared to the same period in 2008 due to higher property sales during 2009 as compared to the same period in 2008 by PSE’s real estate subsidiary.

Operating Expenses

The table below sets forth significant changes in operating expenses for PSE and its subsidiaries for the three months ended June 30, 2009 as compared to the same period in 2008.

(Dollars in Millions) Three Months Ended June 30,	Successor 2009			Predecessor 2008			Change			Percent Change
Purchased electricity	$	188.9		$	198.9		$	(10.0	)	(5.0	)%
Electric generation fuel		17.8			32.7			(14.9	)	(45.6	)
Purchased gas		132.1			137.7			(5.6	)	(4.1	)
Unrealized (gain) loss on derivatives		(9.9	)		(2.4	)		(7.5	)	*
Utility operations and maintenance		122.1			116.5			5.6		4.8
Non-utility expense and other		4.3			1.6			2.7		*
Depreciation and amortization		82.4			76.3			6.1		8.0
Taxes other than income taxes		66.7			63.7			3.0		4.7

___________________

*	Percent change not applicable or meaningful.

The table below sets forth significant changes in operating expenses for PSE and its subsidiaries for the six months ended June 30, 2009 as compared to the same period in 2008.

(Dollars in Millions) Six Months Ended June 30,	Successor February 6, 2009 - June 30, 2009			Predecessor January 1, 2009 - February 5, 2009			Combined 2009			Predecessor 2008			Change			Percent Change
Purchased electricity	$	358.5		$	90.7		$	449.2		$	471.7		$	(22.5	)	(4.8	)%
Electric generation fuel		54.0			12.0			66.0			79.7			(13.7	)	(17.2	)
Residential exchange		(40.8	)		(12.5	)		(53.3	)		(20.3	)		(33.0	)	*
Purchased gas		331.3			120.9			452.2			413.9			38.3		9.3
Unrealized (gain) loss on derivatives		(11.4	)		3.8			(7.6	)		(2.3	)		(5.3	)	*
Utility operations and maintenance		199.3			37.7			237.0			228.6			8.4		3.7
Non-utility expense and other		6.8			0.1			6.9			2.1			4.8		*
Merger and related costs		(3.7	)		27.6			23.9			--			23.9		*
Depreciation and amortization		137.0			26.7			163.7			151.7			12.0		7.9
Conservation amortization		27.0			7.6			34.6			28.9			5.7		19.7
Taxes other than income taxes		131.1			36.9			168.0			158.0			10.0		6.3

___________________

*	Percent change not applicable or meaningful.

Purchased electricity expenses decreased $10.0 million and $22.5 million for the three and six months ended June 30, 2009 as compared to the same period in 2008. The decrease for the three months ended June 30, 2009 was primarily the result of lower wholesale market prices and a decrease of 1.1% in energy purchased reflecting lower customer energy demands. The decrease for the six months ended June 30, 2009 was also the result of lower wholesale market prices and a 3.4% decrease in the volume of energy purchased.

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

Electric generation fuel expense decreased $14.9 million and $13.7 million for the three and six months ended June 30, 2009, respectively, as compared to the same period in 2008. The decrease for the three months ended June 30, 2009 was due in part to decreased generation from Goldendale and Frederickson combustion turbines which contributed $6.1 million and $4.0 million, respectively. There was a decrease in fuel expense of $4.0 million primarily due to the outage of Colstrip Unit 4 during the second quarter. The unit was taken offline in March 2009 to conduct maintenance and repair and is expected to return to service in November 2009. The decrease for the six months ended June 30, 2009 was primarily due to lower cost of natural gas in 2009 as compared to 2008.

Residential exchange credits associated with the Bonneville Power Administration (BPA) Residential Exchange Program (REP) increased $33.0 million for the six months ended June 30, 2009 as a result of an agreement with BPA to continue to pass on REP benefits to PSE’s customers. REP does not have an impact on net income.

Purchased gas expenses decreased $5.6 million and increased $38.3 million for the three and six months ended June 30, 2009, respectively, as compared to the same period in 2008 primarily due to an increase of 11.1% in PGA rates effective October 1, 2008 offset by a 1.7% PGA rate decrease effective June 1, 2009 which provides the rates used to determine gas costs based on customer usage. The rate increase was the result of declining costs of natural gas wholesale costs and a reduction of the credit for accumulated PGA payable balance. 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 June 30, 2009 was $62.9 million as compared to $8.9 million at December 31, 2008. 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.

Unrealized gain on derivative instruments increased $7.5 million and $5.3 million for the three and six months ended June 30, 2009, respectively, as compared to the same period in 2008. For the three months ended June 30, 2009, the increase was primarily related to a reversal of unrealized losses on gas for power financial contracts. The reversal of losses was primarily related to increases in the forward market price of natural gas from March 31, 2009. The increase for the six months ended June 30, 2009 was primarily due to increasing forward market prices of natural gas on gas for power financial contracts, which resulted in the reversal of losses previously recorded.

Utility operations and maintenance expense increased $5.6 million and $8.4 million for the three and six months ended June 30, 2009, respectively, as compared to the same period in 2008. The increase for the three months ended June 30, 2009 was primarily due to an increase in customer service costs of $3.5 million, including increases in bad debt expense, electric generation operations and maintenance costs and gas operations and distribution expenses. These increases were partially offset by a $1.5 million decrease in electric transmission and distribution costs. The increase for the six months ended June 30, 2009 was driven by a $5.7 million increase in customer service expenses, which included increases in bad debt expense, salaries and benefits rent expense, and electric plant maintenance and a $2.4 million increase in gas operations costs offset by a $5.2 million decrease in production costs related to a reduction in operations at Colstrip and maintenance costs.

Non-utility operations and maintenance expense increased $2.7 million and $4.8 million for the three and six months ended June 30, 2009, respectively, as compared to the same period in 2008. The increase for the three and six months ended June 30, 2009 was primarily due to charges related to PSE’s pension plans.

Merger and related costs associated with the merger with Puget Holdings incurred for the six months ended June 30, 2009 were $23.9 million. The costs include compensation costs as a result of the change in control, write-off of deferred debt costs associated with the termination of the pre-merger credit facilities, expenses associated with new credit facilities and the impact of deferred compensation liabilities as a result of the merger. Pursuant to the Washington Commission merger order commitments, PSE will not seek recovery of these costs.

Depreciation and amortization expense increased $6.1 million and $12.0 million for the three and six months ended June 30, 2009, respectively, as compared to the same period in 2008. Excluding the regulatory credit for the deferral of Mint Farm Generation Station (Mint Farm) fixed costs of $3.2 million and $7.0 million, depreciation and amortization expense increased $9.3 million and $19.0 million, respectively, for the three and six months ended June 30, 2009 as compared to the same period in 2008. This increase is due to additional depreciable property placed into service and an increase in storm amortization costs as approved in PSE’s general rate case effective November 1, 2008.

Conservation amortization increased $5.7 million for the six months ended June 30, 2009 as compared to the same period in 2008 due to lower recovery of conservation expenditures. Conservation amortization is a pass-through tariff item with no impact on earnings.

Taxes other than income taxes increased $3.0 million and $10.0 million for the three and six months ended June 30, 2009, respectively, as compared to the same period in 2008 due to revenue sensitive taxes.

Other Income, Other Expenses, Interest Expense and Income Tax Expense. The table below sets forth significant changes for PSE for the three months ended June 30, 2009 as compared to the same period in 2008.

(Dollars in Millions) Three Months Ended June 30,		Successor 2009				Predecessor 2008				Change				Percent Change
Other income and expense (net)		$	10.7			$	7.2			$	3.5				48.6	%

The table below sets forth significant changes for PSE for the six months ended June 30, 2009 as compared to the same period in 2008.

(Dollars in Millions) Six Months Ended June 30,	Successor February 6, 2009 - June 30, 2009		Predecessor January 1, 2009 - February 5, 2009		Combined 2009		Predecessor 2008		Change		Percent Change
Other income and expense (net)	$	14.9	$	3.3	$	18.2	$	13.1	$	5.1		38.9	%
Interest expense		82.3		16.9		99.2		95.8		3.4		3.5

Other income and expense increased $3.5 million and $5.1 million for the three and six months ended June 30, 2009, respectively, as compared to the same period in 2008. The increase was primarily due to an increase in regulatory interest income from Mint Farm of $4.5 million offset by penalties of $0.4 million in 2009 and a benefit in a penalty true-up in 2008 of $0.8 million. The increase of $5.1 million for six months ended June 30, 2009 as compared to the same period in 2008 is primarily due to an increase in regulatory interest income from Mint Farm.

Interest expense increased $3.4 million for the six months ended June 30, 2009 as compared to the same period in 2008. The increase was primarily due to higher long-term debt rates and increased debt issuance amortization costs on the post–merger credit facilities.

Capital Requirements

Contractual Obligations and Commercial Commitments

There have been no material changes from the contractual obligations and consolidated commercial commitments set forth in Part II, Item 7 in Puget Energy’s Form 10-Q for the period ended March 31, 2009. The information provided in the contractual obligations table is incorporated herein by reference to the material under “Capital 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.

Off-Balance Sheet Arrangements

Fredonia 3 and 4 Operating Lease. PSE leases two gas-fired turbines for its Fredonia 3 and 4 generating facility pursuant to a master operating lease that was amended for this purpose in April 2001. On November 14, 2008, GE Capital Commercial Inc. notified PSE of its intentions to cancel the lease effective January 14, 2009. PSE has up to one year to complete the termination of the lease. PSE expects to purchase the gas-fired turbines by January 2010. Payments under the lease vary with changes in the London Interbank Offered Rate (LIBOR). At June 30, 2009, PSE’s outstanding balance under the lease was $44.0 million. The expected residual value under the lease is the lesser of $42.3 million or 60.0% of the cost of the equipment.

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 continuing customer growth and to support reliable energy delivery. The cash flow construction expenditures, excluding equity Allowance for Funds Used During Construction (AFUDC) and customer refundable contributions, was $358.6 million for the six months ended June 30, 2009. The anticipated utility construction expenditures, excluding AFUDC, for 2009, 2010 and 2011 are:

Capital Expenditure Estimates (Dollars in Millions)	2009		2010		2011
Energy delivery, technology and facilities	$	687	$	840	$	786
New supply resources		234		621		346
Total expenditures	$	921	$	1,461	$	1,132

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

Capital Resources

Cash From Operations

Cash generated from operations for the six months ended June 30, 2009 was $614.7 million, an increase of $106.9 million from the $507.8 million generated during the six months ended June 30, 2008. The increase was primarily the result of $258.2 million in derivative settlement payments reclassified to financing activities because certain derivative contracts had value at the time of the merger in accordance with SFAS No. 149 “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” Also contributing to the increase in operating cash flow was the overrecovery of natural gas costs through the PGA mechanism during the first six months of 2009 of $54.0 million compared to an underrecovery of $51.1 million during the same period in 2008 which increased operating activities by $105.1 million. In addition, Puget Energy collected $76.3 million more in accounts receivable in 2009 as compared to 2008 and recognized $38.7 million greater net deferred income taxes and tax credits during the six months ended June 30, 2009 as compared to the same period in 2008.

The increase in cash generated from operating activities for the first six months of 2009 as compared to 2008 was partially offset by an increase of $194.6 million in natural gas payments and payment of gas financial hedge contracts, power cost and other payable balances as compared to the same period in 2008. Further, Puget Energy received a refund of $42.4 million in income taxes during the first six months of 2008 compared to a net refund of $0.1 million in 2009 which resulted in a decrease of $42.3 million. Also, there was a net unrealized gain on derivative instruments of $46.5 million during the first six months of 2009, compared to a net unrealized gain of $2.3 million during the same period in 2008, which decreased operating activities by $44.2 million and there was an increase in residential exchange program net payments made of $30.8 million over the same period in 2008. Puget Energy also increased prepaid income taxes for the first six months of 2009 by $85.1 million compared to the same period in 2008.

Financing Program

Financing utility construction requirements and operational needs are dependent upon the amount of cash available and the cost and availability of external funds from the capital markets. PSE anticipates refinancing the redemption of bonds with its liquidity facilities and/or the issuance of new bonds. Access to funds depends upon factors such as general economic conditions, regulatory climate and policies, Puget Energy’s and PSE’s credit ratings and investor receptivity to investing in the utility industry and PSE.

Liquidity Facilities and Commercial Paper

PSE’s short-term borrowings and sales of commercial paper are used to provide working capital and funding of utility construction programs. Puget Energy and PSE have not been significantly impacted by the recent disruption in the credit environment.

Puget Energy Credit Facilities

Puget Energy’s credit agreements contain usual and customary affirmative and negative covenants that, among other things, place limitations on its, or its operating companies’ ability to incur additional indebtedness and liens, issue equity, pay dividends, transact with affiliates and make dispositions and investments. The credit agreements also contain financial covenants, whose measurement periods begin with third quarter 2009 financial statements, based on the following three ratios: cash flow interest coverage, cash flow debt leverage and debt service coverage.

The two credit facilities mature in February 2014, contain similar terms and conditions and are syndicated among numerous banks 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 plus a spread or at floating rates based on the LIBOR plus a spread. 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 determined by S&P and Moody’s. At Puget Energy’s credit ratings as of the date of this report, the spread over prime rate is 125 basis points, the spread to the LIBOR is 225 basis points and the commitment fee is 84 basis points.

As of June 30, 2009, the term loan was fully drawn at $1.225 billion and $258.0 million was outstanding under the $1.0 billion facility, leaving $742.0 million available for use on the facility. Concurrent with the borrowings under these credit agreements, Puget Energy entered into a series of interest rate swaps with a group of banks to fix the interest rates at 4.76% for the term of the credit facilities on these two loans totaling $1.483 billion.

PSE Credit Facilities

PSE Credit Agreements at June 30, 2009 (Successor Company)

These facilities mature in 2014, contain similar terms and conditions and are syndicated among numerous committed banks. The agreements provide PSE with the ability to borrow at either a base rate (which is based on the Prime Rate) or the Eurodollar rate (which is based on the LIBOR), plus a spread. PSE must also pay a commitment fee on the unused portion of the facilities. The spread and the commitment fee depend on PSE’s credit ratings as determined by S&P and Moody’s credit ratings. For PSE’s credit ratings as of the date of this report, the spread is 85 basis points and the commitment fee is 26 basis points. 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.

PSE Credit Agreements at February 5, 2009 (Predecessor Company)

In August 2008, PSE entered into a nine-month, $375.0 million credit agreement with four banks and as of February 5, 2009, PSE had fully drawn the $375.0 million capacity under the agreement.

On February 6, 2009, the credit agreements and securitization facility were repaid, terminated and were replaced with the new post-merger facilities described above.

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 the Mortgage Indentures. In addition, beginning February 6, 2009, as approved in the Washington Commission merger order, PSE dividends may not be declared or paid if PSE’s common equity ratio 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 on the date of distribution unless: (a) the ratio of PSE’s Earnings Before Interest, Tax, Depreciation and Amortization (EBITDA) to PSE interest for the most recently ended four fiscal quarter periods prior to such date is equal to or greater than three to one; and (b) PSE’s corporate credit/issuer rating is equal to or greater than BBB- with S&P and Baa3 with Moody’s. Puget Energy’s ability to pay dividends to its shareholder is also limited by the merger order, beginning February 6, 2009. 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 most recently ended four fiscal quarter periods prior to such date is equal to or greater than two to one.

Long-term Funding and 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 on PSE limits it to $500.0 million of long-term debt 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 provision whereby additional capital 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 issues long-term debt secured under electric and natural gas mortgage indentures. Under the most restrictive tests, at June 30, 2009, PSE could issue:

approximately $1.0 billion of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately $1.7 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 June 30, 2009; and

approximately $652 million of additional first mortgage bonds under PSE’s natural gas mortgage indenture based on approximately $1.09 billion of gas bondable property available for issuance, subject to interest coverage ratio limitations of 1.75 times and 2.0 times net earnings available for interest (as defined in the natural gas utility mortgage), which PSE exceeded at June 30, 2009.

At June 30, 2009, PSE had approximately $3.7 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 has any debt outstanding that would accelerate debt maturity upon a credit rating downgrade. A ratings downgrade could adversely affect the ability to renew existing, or obtain access to new credit facilities and could increase the cost of such facilities. For example, under 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 may 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 while it lowered its corporate credit rating for Puget Energy. At the same time it removed both companies from its watch list for negative implications citing a stable outlook. The rating actions reflected the anticipated completion of the acquisition of Puget Energy and PSE by Puget Holdings, which occurred on February 6, 2009.

On February 2, 2009, Moody’s downgraded the Issuer Rating of Puget Energy to Ba2 from Ba1 and affirmed the long-term ratings of PSE. The ratings outlook for both companies is stable.

On August 3, 2009, Moody’s upgraded the Senior Secured Debt rating of PSE to Baa1 from Baa2.

The ratings of Puget Energy and PSE, as of August 13, 2009, were as follows:

	Ratings
	S&P 1	Moody’s 2
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

_______________

1	On January 16, 2009, S&P upgraded PSE’s corporate and other credit ratings, while downgrading Puget Energy’s corporate credit rating. It also removed all the ratings from negative watch, citing a stable outlook.
2	On February 2, 2009, Moody’s affirmed the long-term ratings of PSE, while downgrading PSE short-term rating for commercial paper to P-3 and the Issuer Rating of Puget Energy to Ba2. On August 3, 2009 Moody’s upgraded PSE’s senior secured debt rating to Baa1.

Other

Regulation and Rates

On May 28, 2009, the Washington Commission approved a PGA rate decrease of $21.2 million or 1.7% annually effective June 1, 2009. PGA rate changes do not impact net income.

On April 17, 2009, the Washington Commission issued an order approving and adopting a settlement agreement that authorized PSE to defer certain ownership and operating costs related to its purchase of the Mint Farm that will be incurred prior to PSE recovering such costs in electric customer rates. Under Washington state law, a jurisdictional electric utility may defer the costs associated with purchasing and operating a gas plant that complies with the greenhouse gases (GHG) emissions performance standard until the plant is included in rates or for two years from the date of purchase, whichever is sooner. As of June 30, 2009, PSE had established a regulatory asset of $16.4 million per the Washington Commission order. The prudence of the Mint Farm acquisition, recovery of costs of Mint Farm and compliance with the GHG emissions performance standard will be addressed in PSE’s general rate proceeding.

On October 8, 2008, the Washington Commission issued its order in PSE’s consolidated electric and natural gas general rate case filed in December 2007, approving a general rate increase for electric customers of $130.2 million or 7.1% annually, and an increase in natural gas rates of $49.2 million or 4.3% annually. The rate increases for electric and natural gas customers were effective November 1, 2008. In its order, the Washington Commission approved a weighted cost of capital of 8.25% and a capital structure that included 46.0% common equity with a return on equity of 10.15%. The Washington Commission issued a separate order on January 15, 2009, that authorized the continuation of the Power Cost Only Rate Case (PCORC) with certain modifications to which the Washington Commission staff and PSE had agreed. The five procedural modifications to the PCORC include extending the expected procedural schedule from five to six months, limiting the power cost updates to one per PCORC unless an additional update is allowed by the Washington Commission as part of the compliance filing, prohibiting the overlap of PCORC and general rate cases (except for requests for interim rate relief), shortening data request time from ten to five business days and requiring PSE to provide its future energy resource model projections at the outset of a case.

Snoqualmie Falls Project

PSE received a new 40-year operating license for its Snoqualmie Falls hydroelectric project from the Federal Energy Regulatory Commission (FERC) in 2004. The license contained an array of FERC-approved plans to upgrade the facility. Due to changed circumstances, on December 6, 2007, PSE filed an application for a non-capacity amendment to the license to account for technology improvements and hydrologic and other changes. On June 1, 2009, FERC issued an order amending the license that incorporates the changes requested by PSE. This order is final and no party sought rehearing or review.

Proceedings Relating to the Western Power Market

The following discussion summarizes the status as of the date of this report of ongoing proceedings relating to the western power markets to which PSE is a party. PSE is vigorously defending the remaining claims. Litigation is subject to numerous uncertainties and PSE is unable to predict the ultimate outcome of these matters. Accordingly, there can be no guarantee that these proceedings will not materially and adversely affect PSE’s financial condition, results of operations or liquidity.

Under the settlement, PSE releases all claims to amounts held in, or presumed payable into, certain escrow accounts. In particular, the California Power Exchange and Pacific Gas & Electric (PG&E) will deliver $59.9 million, plus up to $36.8 million in interest, from escrows they maintain to the California parties. The release of those funds fully satisfies all claims by the California parties against PSE, and the California parties assume the risk of any shortfalls or adjustments that occur in those accounts.

The settlement resolves all claims by the California parties against PSE in all proceedings and resolves all claims by PSE against California energy purchasers in all proceedings, except that PSE retains any claims or defenses that pertain to the Pacific Northwest Refund Proceedings at FERC.

In addition to the FERC approval obtained on July 1, 2009, PSE’s settlement with the California parties was expressly conditioned upon two other actions: (1) the California Energy Commission’s 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 Utility Commission (CPUC) of a renewable power agreement between PSE and Southern California Edison (SCE), under which PSE will sell 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.

The settlement means that PSE’s exposure to western energy crisis claims is now limited to the Pacific Northwest Refund Proceeding, described previously and updated below.

Pacific Northwest Refund Proceeding. In October 2000, PSE filed a complaint at FERC (Docket No. EL01-10) against “all jurisdictional sellers” in the Pacific Northwest seeking prospective price caps consistent with any result FERC ordered for the California markets. In April, 2009, the Ninth Circuit rejected the requests for rehearing filed in this matter and remanded the proceeding to FERC. FERC is now considering what response to take to the Court remand order. PSE intends to vigorously defend its position but is unable to predict the outcome of this matter.

Proceedings Relating to the Bonneville Power Administration

Like other investor-owned utilities in the region, PSE has been a party to certain agreements with the BPA that provide payments to PSE which PSE passes through to its residential and small farm electric customers. Several actions in the Ninth Circuit against BPA assert that BPA acted contrary to law in connection with this REP, including with respect to benefits received or to be received by PSE from BPA and the Ninth Circuit has directed BPA to revisit certain REP calculations relating to payments made in the 2001 to 2006 period. PSE and BPA, separately, also have agreed to certain go-forward REP payment amounts through 2011 and have sought Ninth Circuit review of the agreements related thereto. The amounts of such payments and the methods utilized in setting them are subject to FERC review or judicial review, or both, and are subject to adjustment, which may affect the amount of REP benefits paid or to be paid by BPA to PSE. Although it is not clear what impact, if any, these reviews or other REP-related litigation may ultimately have on PSE, any changes to the REP payments pass through to customers with no impact to PSE’s net income.

New Accounting Pronouncements

In June 2009, FASB issued SFAS No. 167, “Amendments to FASB Interpretation No. 46 (R)” (SFAS No. 167). This Statement replaces a quantitative approach with a qualitative approach to determine whether the company’s variable interest or interests give it a controlling financial interest in a variable interest entity (VIE). In addition, the Statement requires enhanced disclosures which will provide users of the financial statements with more transparent information about an enterprises involvement in a VIE. SFAS No. 167 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 Puget Energy. Puget Energy is assessing the impact of SFAS No. 167.

On April 9, 2009, FASB issued FSP 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (FSP No. 157-4). FSP No. 157-4 became effective for PSE as of June 30, 2009. FSP No. 157-4 provides additional guidance for estimating fair value in accordance with SFAS No. 157, when the volume and level of activity for the asset or liability have significantly decreased. FSP No. 157-4 also includes guidance on identifying circumstances that indicate a transaction is not orderly. As of June 30, 2009, Puget Energy has determined that FSP No. 157-4 has no impact to its consolidated financial position or results of operations.

On December 30, 2008, FASB issued FSP No. 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets” (FSP No. 132(R)-1). FSP No. 132(R)-1 directs companies to provide additional disclosures about plan assets of a defined benefit pension or other postretirement plan. The objectives of the disclosures are to disclose the following: (1) how investment allocation decisions are made, including the factors that are pertinent to an understanding of investment policies and strategies, (2) major categories of plan assets, (3) inputs and valuation techniques used to measure the fair value of plan assets, (4) effect of fair value measurements using significant unobservable inputs (Level 3) on changes in plan assets for the period and (5) significant concentrations of risk within plan assets. FSP No. 132(R)-1 is effective for the fiscal year December 15, 2009, which will be effective for Puget Energy for the fiscal year end December 31, 2009. Puget Energy is currently assessing the impact of FSP No. 132(R)-1.

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 commodity price exposure and risks associated with volumetric variability in the gas and electric portfolios and the 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.

SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – An Amendment of FASB Statement No. 133” (SFAS No. 161) 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 the SFAS No. 161 disclosures, summary metrics that may be included in this MD&A discussion may be further expanded upon in the footnotes preceding the MD&A.

The following table presents a summary of the fair value of both electric and natural gas (used in both electric generation and in core gas sales) derivative instruments that do not meet the NPNS exception at June 30, 2009 and December 31, 2008, including contracts designated as cash flow hedges:

Derivative Portfolio (Dollars in Millions)	Successor June 30, 2009		Predecessor December 31, 2008
Current asset	$	13.7	$	15.6
Long-term asset		45.9		6.7
Total assets	$	59.6	$	22.3

Current liability	$	331.8	$	236.9
Long-term liability		123.2		158.4
Total liabilities	$	455.0	$	395.3

If it is determined that it is uneconomical to operate PSE’s controlled electric generating facilities in the future period, the fuel supply cash flow hedge relationship is terminated and the hedge is de-designated which results in recognition of future changes in value in the income statements. As these contracts are settled, amounts previously deferred in other comprehensive income (OCI) are recognized as energy costs and are included as part of the Power Cost Adjustment (PCA) mechanism. 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, “Accounting for Derivative Instruments and Hedging Activities.”

At June 30, 2009, PSE had total assets of $20.0 million and total liabilities of $154.0 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 SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71), 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% decrease in market prices of natural gas and electricity would decrease the fair value of derivative contracts by $102.2 million, with a corresponding after-tax decrease in other comprehensive income and earnings of $21.7 million and $1.4 million respectively related to derivatives designated as hedges, and would decrease the fair value of those contracts marked-to-market in earnings by $15.2 million after-tax related to derivatives not designated as hedges. A discussion of the Level 3 valuation is included in Note 4, “Fair Value Measurements.”

Contingent Features and Counterparty Credit Risk

Where deemed appropriate, PSE may request collateral or other security from its counterparties to mitigate the potential credit default losses. Criterion employed in this decision include, among other things, the perceived creditworthiness of the counterparty and the expected credit exposure. As of June 30, 2009, PSE held approximately $0.6 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 June 30, 2009, approximately 96.7% of PSE’s energy portfolio exposure, including NPNS transactions, is with counterparties that are rated at least investment grade by the major rating agencies and 3.3% 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 agreements (WSPP) - standardized power sales contracts in the electric industry; (2) International Swaps and Derivatives Association agreements (ISDA) - standardized financial gas and electric contracts; and (3) North American Energy Standards Board agreements (NAESB) - 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). SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133) 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 balance sheet, with the corresponding amount recorded in the income statement.

Cash flow hedge derivative treatment is also impacted by a counterparty’s deterioration of credit under SFAS No. 133 guidelines. If a forecasted transaction associated with a cash flow hedge is no longer probable of occurring, based on deterioration of credit, PSE would discontinue hedge accounting, record in earnings subsequent changes in the derivative’s fair value and freeze amounts previously accounted for in Accumulated OCI. If the transaction is remote of occurring, any amounts previously accounted for in Accumulated OCI would be reclassified into earnings.

Should a counterparty file for bankruptcy, which could 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 termination receivable or payables, based on the terms of existing master arrangements.

PSE computes credit reserves at a master agreement level (i.e. WSPP, ISDA or NAESB) by counterparty. PSE considers external credit ratings and market factors, such as credit default swaps and bond spreads in determination of reserves. PSE recognizes that external ratings may not always reflect how a market participant perceives a counterparty’s risk of default. PSE 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 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.

PSE applies the counterparty’s default factor to compute credit reserves for counterparties that are in a net asset position. Moreover, PSE 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 June 30, 2009, PSE was in a net liability position with all but one counterparty; as a result, the default factors of counterparties did not have a significant impact on reserves for the year.

Interest Rate Risk

Puget Energy believes its interest rate risk primarily relates to the use of short-term debt instruments, variable-rate notes and leases and anticipated long-term debt financing needed to fund capital requirements. Puget Energy manages its interest rate risk through the issuance of mostly fixed-rate debt of various maturities. Puget Energy utilizes bank borrowings, commercial paper, line of credit facilities and, prior to the merger, accounts receivable securitization to meet short-term cash requirements. These short-term obligations are commonly refinanced with fixed-rate bonds or notes when needed and when interest rates are considered favorable. Puget Energy may enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts. Puget Energy had seven interest rate swap contracts outstanding as of June 30, 2009.

In February 2009, Puget Energy entered into certain interest rate swap transactions to hedge the risk associated with one-month LIBOR floating rate debt. As of December 31, 2008 the fair value of such instruments were zero as they had not yet been executed, and as of June 30, 2009, the fair value of interest rate swaps designated as cash flow hedges was $9.7 million. 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 gain of $6.3 million after tax related to the interest rate swaps designated as cash flow hedges during the current reporting period at the Successor Company. This compares to a loss of $7.9 million in OCI after tax as of December 31, 2008 at the Predecessor Company related to previously settled treasury locks.

A hypothetical 10.0% increase in three-month LIBOR would increase the fair value of interest rate swaps by $17.4 million, with a corresponding after-tax increase in unrealized gains recorded in OCI by $11.3 million. A hypothetical 10.0% decrease in interest rates would decrease the fair value of interest rate swaps by $21.1 million, with a corresponding after-tax increase in unrealized losses recorded in OCI by $13.7 million.

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 June 30, 2009, 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 quarter ended June 30, 2009 that have materially affected, or are reasonably likely to materially affect, Puget Energy’s internal control over financial reporting.

PART II OTHER INFORMATION

Item 1. Legal Proceedings

See the section titled “Proceedings Relating to the Western Power Market” under “Other” of Management’s Discussion and Analysis of Financial Conditions and Results of Operations of this Report on Form 10-Q. Contingencies arising out of the normal course of PSE’s business exist at June 30, 2009. 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 II, Item 1A in Puget Energy’s Form 10-Q for the period ended March 31, 2009.

Item 6. Exhibits

See Exhibit Index for list of exhibits.

SIGNATURES

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

	PUGET ENERGY, INC.

	/s/ James W. Eldredge
	James W. Eldredge
	Vice President, Controller and Chief Accounting Officer

Date: August 13, 2009
	Chief accounting officer and officer duly authorized to sign this report on behalf of the registrant

EXHIBIT INDEX

The following exhibits are filed herewith:

12.1	Statement setting forth computation of ratios of earnings to fixed charges: Years Ended December 31, 2004 through 2008, January 1, 2009 - February 5, 2009 (Predecessor Company) and February 6, 2009 - June 30, 2009 (Successor Company) for Puget 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.
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.