Puget Energy (PSD) 10-Q 2009 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2009

OR

[  ] 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 /  / No /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 /   / No /  /

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 /  / No /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 – February 6, 2009 - March 31, 2009 (Successor Company), January 1, 2009 - February 5, 2009 and Three Months Ended March 31, 2008 (Predecessor Company)
	Consolidated Statements of Comprehensive Income – February 6, 2009 -  March 31, 2009 (Successor Company), January 1, 2009 - February 5, 2009 and Three Months Ended March 31, 2008 (Predecessor Company)
	Consolidated Balance Sheets – March 31, 2009 (Successor Company) and December 31, 2008 (Predecessor Company)
	Consolidated Statement of Shareholder’s Equity – March, 31, 2009 (Successor Company), February 5, 2009 and December 31, 2008 (Predecessor Company)
	Consolidated Statements of Cash Flows – February 6, 2009 -  March 31, 2009 (Successor Company), January 1, 2009 - February 5, 2009 and Three Months Ended March 31, 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
ASC	Average System Cost
BPA	Bonneville Power Administration
CAISO	California Independent System Operator
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
PF	BPA Priority Firm Exchange Rate
PGA	Purchased Gas Adjustment
PSE	Puget Sound Energy, Inc.
Puget Energy	Puget Energy, Inc.
Puget Holdings	Puget Holdings LLC
PURPA	Public Utility Regulatory Policy Act
REP	Residential Exchange Program
RPSA	Residential Purchase and Sale Agreement
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.  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, as applicable, to have a reasonable basis, including without limitation management’s examination of historical operating trends, data contained in records and other data available from third parties.  However, there can be no assurance that Puget Energy’s 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 to comply with FERC or Washington Commission standards and/or rules, which could result in penalties based on the discretion of either commission;

· Failure 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 (IRS) or other taxing jurisdiction;

· 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 customer usage and PSE’s 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 on the cost of procuring such supplies;

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

· Plant outages, which can have an adverse impact on PSE’s expenses with respect to repair costs, added costs to replace energy or higher costs associated with dispatching a more expensive resource;

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

· The ability to renew contracts for electric and natural gas supply and the price of renewal;

· Blackouts or large curtailments of transmission systems, whether PSE’s or others’, which can affect PSE’s ability to deliver power or natural gas to its customers and generating facilities;

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

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

· The amount of collection, if any, of PSE’s receivables from the California Independent System Operator (CAISO) and other parties and the amount of refunds found to be due from PSE to the CAISO or other parties;

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

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

· The loss of significant customers or changes in the business of significant customers 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 PSE’s or Puget Energy’s credit ratings, which may have an adverse impact on the availability and cost of capital for PSE or Puget Energy; and

· Deteriorating values of the equity, fixed income and other markets which could significantly impact the value of investments of PSE’s retirement plan and post-retirement medical 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
	February 6, 2009 - March 31, 2009			January 1, 2009 - February 5, 2009			Three Months Ended  March 31, 2008
Operating revenues:
Electric	$	386,612		$	213,618		$	606,134
Gas		316,435			190,001			443,236
Other		795			94			1,562
Total operating revenues		703,842			403,713			1,050,932
Operating expenses:
Energy costs:
Purchased electricity		169,416			90,737			272,832
Electric generation fuel		36,166			11,961			47,014
Residential exchange		(19,862	)		(12,542	)		(7	)
Purchased gas		199,138			120,925			276,195
Net unrealized (gain) loss on derivative instruments		(12,118	)		3,867			88
Utility operations and maintenance		77,243			37,650			112,163
Non-utility expense and other		2,471			112			462
Merger related costs		2,479			44,324			1,311
Depreciation and amortization		54,619			26,742			75,367
Conservation amortization		13,237			7,592			13,366
Taxes other than income taxes		64,407			36,935			94,273
Total operating expenses		587,196			368,303			893,064
Operating income		116,646			35,410			157,868
Other income (deductions):
Other income		6,279			3,653			6,844
Other expense		(7,073	)		(369	)		(976	)
Interest charges:
AFUDC		1,331			350			2,429
Interest expense		(43,151	)		(17,291	)		(51,048	)
Income before income taxes		74,032			21,753			115,117
Income tax expense		21,972			8,997			35,304
Net income	$	52,060		$	12,756		$	79,813

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
	February 6, 2009 - March 31, 2009			January 1, 2009 - February 5, 2009			Three Months Ended March 31, 2008
Net income	$	52,060		$	12,756		$	79,813
Other comprehensive income:
Interest rate swap, net of tax of $(12,718), $0, and $0, respectively		(23,619	)		--			--
Unrealized gain from pension and postretirement plans, net of tax of $0, $170 and $95, respectively		--			315			176
Net unrealized gains (losses) on energy derivative instruments during the period, net of tax of $(24,999), $(13,010) and $25,457, respectively		(46,426	)		(24,162	)		47,277
Reversal of net unrealized gains  on energy derivative instruments settled during the period, net of tax of $667, $2,428 and $957, respectively		1,239			4,509			1,778
Amortization of financing cash flow hedge contracts to earnings, net of tax of $8,705, $15 and $43, respectively		16,166			27			80
Other comprehensive income (loss)		(52,640	)		(19,311	)		49,311
Comprehensive income (loss)	$	(580	)	$	(6,555	)	$	129,124

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

PUGET ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

ASSETS

	Successor			Predecessor
	March 31, 2009 (Unaudited)			December 31, 2008
Utility plant: (at original cost, including construction work in progress of    $282,785 and $255,214, respectively)
Electric plant	$	4,333,681		$	6,596,359
Gas plant		1,880,112			2,500,236
Common plant		270,148			550,368
Less:  Accumulated depreciation and amortization		(66,405	)		(3,358,816	)
Net utility plant		6,417,536			6,288,147
Other property and investments:
Goodwill		1,652,939			--
Investment in Bonneville Exchange Power contract		29,095			29,976
Other property and investments		122,196			118,039
Total other property and investments		1,804,230			148,015
Current assets:
Cash		101,042			38,526
Restricted cash		15,988			18,889
Accounts receivable, net of allowance for doubtful accounts		395,474			203,563
Secured pledged accounts receivable		--			158,000
Unbilled revenues		171,604			248,649
Materials and supplies, at average cost		78,995			62,024
Fuel and gas inventory, at average cost		60,173			120,205
Unrealized gain on derivative instruments		25,613			15,618
Prepaid income tax		20,483			19,121
Prepaid expense and other		24,285			14,964
Power contract fair value gain		136,821			--
Deferred income taxes		62,240			9,439
Total current assets		1,092,718			908,998
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes		92,202			95,417
Regulatory asset for PURPA buyout costs		102,669			110,838
Power cost adjustment mechanism		3,147			3,126
Other regulatory assets		1,182,304			766,732
Unrealized gain on derivative instruments		11,155			6,712
Power contract fair value gain		989,258			--
Other		50,563			40,421
Total other long-term and regulatory assets		2,431,298			1,023,246
Total assets	$	11,745,782		$	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
	March 31, 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		3,310,950			2,275,225
Earnings reinvested in the business		20,060			259,483
Accumulated other comprehensive income (loss), net of tax		(52,640	)		(262,804	)
Total shareholders’ equity		3,278,370			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		3,442,941			2,270,860
Total redeemable securities and long-term debt		3,692,941			2,522,749
Total capitalization		6,971,311			4,795,950
Current liabilities:
Accounts payable		224,848			342,254
Short-term debt		175,000			964,700
Current maturities of long-term debt		233,000			158,000
Accrued expenses:
Purchased gas liability		29,725			8,892
Taxes		96,172			85,068
Salaries and wages		19,374			35,280
Interest		48,665			36,074
Unrealized loss on derivative instruments		430,547			236,866
Power contract fair value loss		114,424			--
Other		163,403			117,222
Total current liabilities		1,535,158			1,984,356
Long-term liabilities and regulatory liabilities:
Deferred income taxes		906,781			749,766
Unrealized loss on derivative instruments		217,958			158,423
Regulatory liabilities		237,055			219,221
Regulatory liabilities related to power contracts		1,120,126			--
Power contracts fair value loss		181,355			--
Other deferred credits		576,038			460,690
Total long-term liabilities and regulatory liabilities		3,239,313			1,588,100
Total capitalization and liabilities	$	11,745,782		$	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	$	--	$	3,310,522		$	--		$	--		$	3,310,522
Net income		--		--		--			52,060			--			52,060
Common stock dividend declared		--		--		--			(32,000	)		--			(32,000	)
Employee stock plan tax windfall		--		--		428			--			--			428
Other comprehensive loss		--		--		--			--			(52,640	)		(52,640	)
Balance at March 31, 2009		200	$	--	$	3,310,950		$	20,060		$	(52,640	)	$	3,278,370

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 - March 31, 2009			January 1, 2009 - February 5, 2009			Three Months Ended March 31, 2008
Operating activities:
Net income	$	52,060		$	12,756		$	79,813
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		54,619			26,742			75,367
Conservation amortization		13,237			7,592			13,366
Deferred income taxes and tax credits, net		26,085			(512	)		22,283
Mint Farm deferred costs		(2,006	)		(3,443	)		--
Amortization of gas pipeline capacity assignment		(1,517	)		(791	)		(2,614	)
Non cash return on regulatory assets		(1,579	)		(800	)		(3,363	)
Net unrealized (loss) gain on derivative instruments		(12,118	)		3,867			88
Non cash Colstrip settlement		--			--			10,487
Other		37,083			5,071			(2,329	)
Cash collateral paid from energy suppliers		(5,427	)		159			--
Residential exchange program		4,403			1,927			(921	)
Derivative contracts classified as financing activities due to merger		147,704			--			--
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue		74,465			(31,332	)		27,594
Materials and supplies		117			(3,388	)		930
Fuel and gas inventory		24,866			7,605			59,482
Prepaid income taxes		(19,639	)		18,277			43,760
Prepayments and other		(19,319	)		(3,295	)		3,146
Purchased gas receivable/payable		19,121			1,711			(9,436	)
Accounts payable		(152,305	)		(40,203	)		(17,116	)
Taxes payable		22,795			(3,340	)		22,739
Accrued expenses and other		(43,432	)		59,172			11,297
Net cash provided by operating activities		219,213			57,775			334,573
Investing activities:
Construction and capital expenditures - excluding equity AFUDC		(129,777	)		(49,531	)		(126,646	)
Energy efficiency expenditures		(11,652	)		(4,918	)		(14,010	)
Restricted cash		2,911			(10	)		1,150
Other		4,001			959			699
Net cash used by investing activities		(134,517	)		(53,500	)		(138,807	)
Financing activities:
Change in short-term debt and leases, net		113,809			(151,800	)		(158,882	)
Dividends paid		(68,594	)		--			(32,419	)
Long-term bond issued		50,211			250,000			--
Redemption of mandatorily preferred stock		--			(1,889	)		--
Redemption of bonds		(150,000	)		--			--
Derivative contracts classified as financing activities due to merger		(147,704	)		--			--
Issuance and redemption costs of bonds and other		(13,337	)		7,133			3,890
Net cash (used) provided by financing activities		(215,615	)		103,444			(187,411	)
Net increase (decrease) in cash		(130,919	)		107,719			8,355
Cash at beginning of year		231,961			38,526			40,797
Cash at end of period	$	101,042		$	146,245		$	49,152
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	44,286		$	1,239		$	38,642
Cash payments (refunds) from income taxes		(271	)		--			(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, a consortium of long-term infrastructure investors, (Puget Holdings) 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 in respect of which dissenter’s rights were perfected and 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 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 $85.9 million for the three months ended March 31, 2009 and $76.6 million for the three months ended March 31, 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 in respect of which dissenter’s rights were perfected and 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, a debt issuance of $0.6 million was issued at Puget Energy and $0.3 billion was the result of the stepped-up basis of the investors’ 10.5 million previously owned shares.  In addition, Puget Holdings contributed $85.7 million to Puget Energy.

Below is the consolidated statement of fair value of assets and liabilities assumed as of February 6, 2009 measured in accordance with SFAS No. 141R:

(Dollars in Thousands)		Amount
Net utility plant	$		6,346,032
Other property and investments			151,913
Goodwill			1,652,939
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		1,652,939
Non-utility property		4,250
Total other property and investments		1,657,189
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	$	3,308,853

CAPITALIZATION AND LIABILITIES

(Dollars in Thousands)	February 6, 2009 (Unaudited)
Capitalization:
Total shareholders’ equity	$	1,660,821
Redeemable securities and long-term debt:
Long-term debt		(280,315	)
Total redeemable securities and long-term debt		(280,315	)
Total capitalization		1,380,506
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	$	3,308,853

The carrying values of net utility plant and 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 at the date of acquisition, with no accumulated amortization recorded, 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 date of acquisition.

Energy derivative contract valuations were performed using the discounted cash flow method.

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 the postretirement benefit plans 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 March 31, 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.”  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 it 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 quarter 2009, Puget Energy incurred pre-tax merger expenses of $50.5 million.  Many of these costs were paid as of the merger date and were primarily for 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 quarter 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 $808.9 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 $29.6 million of the capital contribution was used to pay for change in control costs associated with the merger.

(3)   Accounting for Derivative Instruments and Hedging Activities

        SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (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.  Puget Energy revalued all contracts that met the definition of a derivative as a result of purchase accounting effective at the merger date of February 6, 2009.  After revaluation, several energy and natural gas derivative contracts meeting the normal purchase normal sale (NPNS) scope criteria in paragraph 10(b) of SFAS No. 133, were designated as such.  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 in paragraph 10(b)(4) of SFAS No. 133, including whether the counterparty owns or controls energy resources within the western region to allow for physical delivery of the energy and the transaction is within PSE’s forecasted load requirements.  Subsequent to the date of the merger, Puget Energy designated several financial fixed contracts as cash flow hedges that were entered into to hedge the variability of certain NPNS contracts.  In addition, certain fixed price power purchase agreements that do not meet the NPNS criteria were also designated as cash flow hedges. The effectiveness assessment of derivative instruments designated as cash flow hedges subsequent to the application of push-down accounting was performed at the merger date and at March 31, 2009.  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. During the current reporting period, Puget Energy also designated several fixed-for-float interest rate swaps as cash flow hedges of the interest rate risk associated with its variable rate debt.

       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 Financial Accounting Standards Board (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 March 31, 2009 and December 31, 2008:

	Derivatives Designated as Hedging Instruments
	Successor at March 31, 2009						Predecessor at December 31,2008
	Asset Derivatives			Liability Derivatives			Asset Derivatives			Liability Derivatives
(Dollars in Millions)	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet  Location	Fair Value
Interest rate swaps: Current	Unrealized gain on derivative instruments	$	--	Unrealized loss on derivative instruments	$	26.5	Unrealized gain on derivative instruments	$	--	Unrealized loss on derivative instruments	$	--
Long-term	Unrealized gain on derivative instruments		--	Unrealized loss on derivative instruments		9.8	Unrealized gain on derivative instruments		--	Unrealized loss on derivative instruments		--
Commodity contracts: Electric portfolio: Current	Unrealized gain on derivative instruments	$	--	Unrealized loss on derivative instruments	$	104.5	Unrealized gain on derivative instruments	$	0.1	Unrealized loss on derivative instruments	$	85.3
Long-term	Unrealized gain on derivative instruments		0.1	Unrealized loss on derivative instruments		80.5	Unrealized gain on derivative instruments		0.4	Unrealized loss on derivative instruments		93.1
Gas portfolio: Current	Unrealized gain on derivative instruments		--	Unrealized loss on derivative instruments		--	Unrealized gain on derivative instruments		--	Unrealized loss on derivative instruments		--
Long-term	Unrealized gain on derivative instruments		--	Unrealized loss on derivative instruments		--	Unrealized gain on derivative instruments		--	Unrealized loss on derivative instruments		--
Total derivatives designated as hedging instruments		$	0.1		$	221.3		$	0.5		$	178.4

	Derivatives Not Designated as Hedging Instruments
	Successor at March 31, 2009						Predecessor at December 31,2008
	Asset Derivatives			Liability Derivatives			Asset Derivatives			Liability Derivatives
(Dollars in Millions)	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity contracts: Electric portfolio: Current	Unrealized gain on derivative instruments	$	1.2	Unrealized loss on derivative instruments	$	79.3	Unrealized gain on derivative instruments	$	0.3	Unrealized loss on derivative instruments	$	5.3
Long-term	Unrealized gain on derivative instruments		0.8	Unrealized loss on derivative instruments		43.2	Unrealized gain on derivative instruments		0.1	Unrealized loss on derivative instruments		3.0
Gas portfolio: Current	Unrealized gain on derivative instruments		20.3	Unrealized loss on derivative instruments		166.8	Unrealized gain on derivative instruments		15.2	Unrealized loss on derivative instruments		146.3
Long-term	Unrealized gain on derivative instruments		9.0	Unrealized loss on derivative instruments		52.7	Unrealized gain on derivative instruments		6.2	Unrealized loss on derivative instruments		62.3
Total derivatives not designated as hedging instruments		$	31.3		$	342.0		$	21.8		$	216.9

	De-Designated Commodity Contracts 1
	Successor at March 31, 2009						Predecessor at December 31,2008
	Asset Derivatives			Liability Derivatives			Asset Derivatives			Liability Derivatives
(Dollars in Millions)	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity contracts: Current	Unrealized gain on derivative instruments	$	4.1	Unrealized loss on derivative instruments	$	53.4	Unrealized gain on derivative instruments	$	--	Unrealized loss on derivative instruments	$	--
Long-term	Unrealized gain on derivative instruments		1.3	Unrealized loss on derivative instruments		31.8	Unrealized gain on derivative instruments		--	Unrealized loss on derivative instruments		--
De-designated commodity contracts1		$	5.4		$	85.2		$	--		$	--
Combined total		$	36.8		$	648.5		$	22.3		$	395.3

______________

1 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 table presents the effect of energy related derivatives on the PGA mechanism on the balance sheet at March 31, 2009 and December 31, 2008:

	Successor at March 31, 2009						Predecessor at December 31,2008
	Asset Derivatives			Liability Derivatives			Asset Derivatives			Liability Derivatives
(Dollars in Millions)	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity contracts: Gas derivatives: Current	Other regulatory assets	$	190.2	Regulatory liabilities	$	--	Other regulatory assets	$	187.2	Regulatory liabilities	$	--
Total		$	190.2		$	--		$	187.2		$	--

At March 31, 2009, Puget Energy had total of $190.2 million of unrealized losses deferred in Other Regulatory Assets 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 during the respective periods ended:

Successor February 6, 2009 - March 31, 2009 (Dollars in Millions)	Amount of Loss Recognized in OCI on Derivatives			Location of Loss Reclassified from Accumulated OCI into Income	Amount of Loss Reclassified from Accumulated OCI into Income		Location of Loss Recognized in Income on Derivatives	Amount of 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
Interest rate contracts:	$	(23.6	)	Interest expense	$	4.9		$	--
Commodity contracts: Electric derivatives		(15.3	)	Electric generation fuel		0.7	Net unrealized loss on derivative instruments		(0.1	)
Electric derivatives		(13.7	)	Purchased electricity		0.5	Net unrealized loss on derivative instruments		(4.4	)
Gas derivatives		--		Purchased gas		--	Net unrealized loss on derivative instruments		--
Total	$	(52.6	)		$	6.1		$	(4.5	)

Predecessor January 1, 2009 - February 5, 2009 (Dollars in Millions)	Amount of Loss Recognized in OCI on Derivatives			Location of Loss Reclassified from Accumulated OCI into Income	Amount of Loss Reclassified from Accumulated OCI into Income		Location of Loss Recognized in Income on Derivatives	Amount of 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
Interest rate contracts:	$	--		Interest expense	$	--		$	--
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	)
Gas derivatives		--		Purchased gas		--	Net unrealized loss on derivative instruments		--
Total	$	(19.6	)		$	6.9		$	(1.0	)

____________

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

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.  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 OCI are recognized as energy costs and are included as part of the PCA mechanism.

Puget Energy expects that $32.0 million of after-tax losses in OCI will be reclassified into earnings within the next 12 months related to both commodity and interest rate contracts designated as cash flow hedges.  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 physical electric contracts, to January 2012 for electric generation fuel financial contracts and to February 2014 for interest rate swap contracts. During the current reporting period, the Predecessor Company reclassified $0.5 million of after-tax losses from OCI into earnings related to transactions that are probable of not occurring.

The following table presents the effect of derivatives not designated as hedging instruments on income during the respective periods ended:

(Dollars in Millions)	Location of Gain/(Loss) in Income on Derivatives	Successor February 6, 2009 - March 31, 2009 Amount of Gain/(Loss) Recognized in Income on Derivatives			Predecessor January 1, 2009 - February 5, 2009 Amount of Gain/(Loss) Recognized in Income on Derivatives
Interest rate contracts:		$	--		$	--
Commodity contracts: Electric derivatives	Net unrealized gain on derivative instruments		(3.3	)		(2.9	)
	Electric generation fuel		(6.0	)		(0.9	)
	Purchased electricity		(4.9	)		(0.2	)
Gas derivatives	Net unrealized gain on derivative instruments		--			--
Total		$	(14.2	)	$	(4.0	)

____________

1 The net unrealized gain (loss) on derivative instruments line item on the statement of performance also includes amortization of $19.9 million of unrealized losses related to de-designated commodity instruments that were deemed to be derivatives and recorded at fair value by the Successor Company at the acquisition date and subsequently designated as NPNS in accordance with paragraph 10(b) of SFAS No. 133. These contracts are no longer recorded at fair value and are being amortized over the remaining life of the contract.

Puget Energy had the following outstanding commodity and interest rate contracts that were entered into as of March 31, 2009:

As of March 31, 2009	Number of Units
Derivatives designated as hedging instruments:
Electric generation fuel	30,330,000	MMBtus
Purchased electricity	4,812,300	MWh
Interest rate swaps	$ 1.483 billion	USD
Derivatives not designated as hedging instruments:
Gas derivatives 1	86,021,684	MMBtus
Electric generation fuel	36,558,960	MMBtus
Purchased electricity	3,778,700	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 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.  Criteria employed in this decision include, among other things, the perceived creditworthiness of the counterparty and the expected credit exposure.  PSE monitors counterparties’ credit standing, including those 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.

It is possible that volatility in energy commodity prices could cause PSE to have material credit risk exposures with one or more counterparties.  If such counterparties fail to perform their obligations under one or more agreements, PSE could suffer a material financial loss.  However, as of March 31, 2009, approximately 90.0% of the counterparties with derivative transactions outstanding in PSE’s energy portfolio are rated at least investment grade by the major rating agencies and 10.0% 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 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 determining the appropriate reserves.  PSE recognizes that external ratings may not always reflect how a market participant perceives 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 determining 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 March 31, 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 Electric Coordinating Council (WECC). 

PSE enters into energy contracts with various credit-risk-related contingent features, which could result in a counterparty requesting immediate payment or demand 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’s derivative activity at March 31, 2009:

Contingent Feature (Dollars in Millions) At March 31, 2009	Fair Value 4  Liability			Posted Collateral		Contingent Collateral
Credit rating 1	$	(44.6	)	$	--	$	44.6
Reasonable grounds for adequate assurance 2		(138.7	)		--		--
Forward value of contract 3		(58.3	)		35.0		--
Total	$	(241.6	)	$	35.0	$	44.6

_________________

1	PSE is required to maintain an investment grade credit rating from each of the major credit rating agencies.
2	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 March 31, 2009.  Excludes NPNS derivative contracts, 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 into the same level 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 March 31, 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:

Recurring Fair Value Measures	Successor as of March 31, 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	$       --	$    30.5	$      0.9	$        --	$     31.4	$       --	$    21.8	$       0.5	$    22.3
Money market accounts	63.9	--	1.4	--	65.3	24.7	--	1.4	26.1
De-designated commodity instruments 1	--	--	--	5.4	5.4	--	--	--	--
Total assets	$   63.9	$    30.5	$      2.3	$     5.4	$   102.1	$   24.7	$    21.8	$       1.9	$    48.4
Liabilities:
Energy derivative instruments	$       --	$  354.3	$  172.7	$        --	$   527.0	$       --	$  261.2	$   134.1	$  395.3
Interest rate derivative instruments	--	(36.3)	--	--	36.3	--	--	--	--
De-designated commodity instruments 1	--	--	--	85.2	85.2	--	--	--	--
Total liabilities	$       --	$  390.6	$  172.7	$   85.2	$   648.5	$       --	$  261.2	$   134.1	$  395.3

_______________

1 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 table sets 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)	Successor February 6, 2009 - March 31, 2009 1			Predecessor January 1, 2009 - February 5, 2009 1			Predecessor January 1, 2008 - March 31, 2008
Balance at beginning of period asset / (liability)	$	(185.8	)	$	(132.2	)	$	(7.3	)
Realized and unrealized energy derivatives
- included in earnings		(16.4	)		(0.6	)		(0.1	)
- included in other comprehensive income		(27.7	)		(14.8	)		28.7
- included in regulatory assets/liabilities		(3.2	)		(1.4	)		0.3
Purchases, issuances, and settlements		5.8			2.1			(1.9	)
Energy derivatives transferred in/out of Level 3		56.9			8.5			(1.1	)
Balance at end of period asset /(liability)	$	(170.4	)	$	(138.4	)	$	18.6

_______________

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.

During the current reporting period, $13.3 million and $0.6 million of unrealized losses were included in earnings of the Successor and Predecessor Companies, respectively, related to Level 3 contracts still in existence as of March 31, 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 net unrealized (gain) loss on derivative instruments in other comprehensive income.  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, other comprehensive income, 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 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 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, $18.8 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 $8.6 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)   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 short-term 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 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).  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 March 31, 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

As of March 31, 2009 and February 5, 2009, PSE had $175.0 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 March 31, 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 for the Puget Energy agreements.  PSE’s financial covenants include the following two ratios:  cash flow interest coverage and cash flow debt leverage.

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. 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 March 31, 2009, PSE had borrowed $175.0 million on the $400.0 million working capital facility, had a $35.0 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 drawn loans 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.  $188.0 million was outstanding under the receivables securitization facility at February 5, 2009.  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 and terminated and were 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 March 31, 2009, the outstanding balance of the Note was $19.4 million.  As of December 31, 2008, the outstanding balance of the Note was $26.1 million.  This Note is unaffected by the February 6, 2009 merger.

Bond Issuance.  On January 23, 2009, PSE issued $250.0 million of 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.  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’s 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 March 31, 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 March 31, 2009, there was $19.4 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 March 31, 2009, there was $175.0 million outstanding under the working capital facility, and $35.0 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 is 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 March 31, 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%.

(6)   Income Taxes

The details of income taxes on continuing operations are as follows:

	Successor			Predecessor			Predecessor
(Dollars In Thousands)	February 6, 2009 - March 31, 2009			January 1, 2009 - February 5, 2009			Quarter Ended March 31, 2008
Charged to operating expense:
Current:
Federal	$	3,276		$	10,185		$	13,338
State		(394	)		87			(149	)
Deferred - federal		19,090			(1,275	)		22,115
Total income taxes	$	21,972		$	8,997		$	35,304

The following reconciliation compares pre-tax book income at the federal statutory rate of 35.0% to the actual income tax expense in the Consolidated Statements of Income:

	Successor			Predecessor			Predecessor
(Dollars In Thousands)	February 6, 2009 - March 31, 2009			January 1, 2009 - February 5, 2009			Quarter Ended March 31, 2008
Income taxes at the statutory rate	$	25,911		$	7,613		$	40,293
Increase (decrease):
Utility plant differences		1,771			1,472			2,919
AFUDC excluded from taxable income		(2,195	)		(1,771	)		(1,572	)
Capitalized interest		1,757			914			2,451
Regulatory		1,721			1,429			1,619
Production tax credit		(6,422	)		(5,870	)		(10,237	)
Transaction costs		76			5,544			--
Other - net		(647	)		(334	)		(169	)
Total income taxes	$	21,972		$	8,997		$	35,304
Effective tax rate		29.7	%		41.4	%		30.7	%

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

	Successor			Predecessor
(Dollars In Thousands)	March 31, 2009			December 31, 2008
Utility plant and equipment	$	785,177		$	746,486
Regulatory asset for income taxes		92,202			95,417
Storm damage		40,944			42,037
Pensions and other compensation		15,584			(62,837	)
Other deferred tax liabilities		219,434			47,963
Subtotal deferred tax liabilities		1,153,341			869,066
Fair value of derivative instruments		(216,742	)		(69,259	)
Other deferred tax assets		(92,058	)		(59,480	)
Subtotal deferred tax assets		(308,800	)		(128,739	)
Total	$	844,541		$	740,327

The above amounts have been classified in the Consolidated Balance Sheets as follows:

	Successor			Predecessor
(Dollars In Thousands)	March 31, 2009			December 31, 2008
Current deferred taxes	$	(62,240	)	$	(9,439	)
Non-current deferred taxes		906,781			749,766
Total	$	844,541		$	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 position 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 March 31, 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.

(7)   Retirement Benefits

PSE has a defined benefit pension plan covering substantially all of its employees, with a cash balance feature for all but International Brotherhood of Electrical Workers employees.  Benefits 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 Puget Energy under SFAS No. 141R which required remeasuring plan liabilities without the five year smoothing of market-related asset gains and losses.  As a result, Puget Energy’s results for these plans are different than PSE’s.

The following tables summarize the net periodic benefit cost, change in benefit obligation and the change in plan assets for the three months ended March 31:

Qualified Pension Benefits
(Dollars in Thousands)	Successor February 6, 2009 - March 31, 2009 1			Predecessor January 1, 2009 - February 5, 2009			Predecessor Quarter Ended March 31, 2008
Components of net periodic benefit cost:
Service cost	$	2,267		$	1,090		$	3,054
Interest cost		4,711			2,302			6,498
Expected return on plan assets		(5,015	)		(3,585	)		(10,455	)
Amortization of prior service cost		--			95			161
Amortization of net loss (gain)		--			269			--
Net periodic benefit cost (income)	$	1,963		$	171		$	(742	)

SERP Pension Benefits
(Dollars in Thousands)	Successor February 6, 2009 - March 31, 2009 1		Predecessor January 1, 2009 - February 5, 2009		Predecessor Quarter Ended March 31, 2008
Components of net periodic benefit cost:
Service cost	$	173	$	89	$	234
Interest cost		396		193		553
Amortization of prior service cost		--		51		154
Amortization of net loss (gain)		--		74		183
Net periodic benefit cost (income)	$	569	$	407	$	1,124

Other Benefits
(Dollars in Thousands)	Successor February 6, 2009 - March 31, 2009 1			Predecessor January 1, 2009 - February 5, 2009			Predecessor Quarter  Ended March 31, 2008
Components of net periodic benefit cost:
Service cost	$	21		$	11		$	43
Interest cost		162			88			283
Expected return on plan assets		(69	)		(37	)		(197	)
Amortization of prior service cost		--			7			21
Amortization of net loss (gain)		--			(15	)		(199	)
Amortization of transition obligation		--			4			13
Net periodic benefit cost (income)	$	114		$	58		$	(36	)

Qualified Pension Benefits
(Dollars in Thousands)	Successor February 6, 2009 - March 31, 2009 1			Predecessor January 1, 2009 - February 5, 2009			Predecessor Quarter Ended March 31, 2008
Change in benefit obligation:
Benefit obligation at beginning of period	$	453,732		$	460,586		$	426,253
Service cost		2,267			1,090			3,054
Interest cost		4,711			2,302			6,498
Benefits paid		(6,283	)		(2,517	)		(6,825	)
Benefit obligation at end of period	$	454,427		$	461,461		$	428,980

Qualified Pension Benefits
(Dollars in Thousands)	Successor February 6, 2009 - March 31, 2009 1			Predecessor January 1, 2009 - February 5, 2009			Predecessor Quarter Ended March 31, 2008
Change in plan assets:
Fair value of plan assets at beginning of period	$	373,767		$	392,900		$	558,529
Expected return on plan assets		5,015			3,585			10,455
Benefits paid		(6,283	)		(2,517	)		(6,825	)
Fair value of plan assets at end of period		372,499			393,968			562,159
Funded status at end of period	$	(81,928	)	$	(67,493	)	$	133,179

SERP Pension Benefits
(Dollars in Thousands)	Successor February 6, 2009 - March 31, 2009 1			Predecessor January 1, 2009 - February 5, 2009			Predecessor Quarter Ended March 31, 2008
Change in benefit obligation:
Benefit obligation at beginning of period	$	38,750		$	39,348		$	37,111
Service cost		173			89			234
Interest cost		396			193			553
Benefits paid		(1,470	)		(532	)		(379	)
Benefit obligation at end of period	$	37,849		$	39,098		$	37,519

SERP Pension Benefits
(Dollars in Thousands)	Successor February 6, 2009 - March 31, 2009 1			Predecessor January 1, 2009 - February 5, 2009			Predecessor Quarter Ended March 31, 2008
Change in plan assets:
Fair value of plan assets at beginning of period	$	--		$	--		$	--
Expected return on plan assets		--			--			--
Employer contribution		1,470			532			379
Benefits paid		(1,470	)		(532	)		(379	)
Fair value of plan assets at and of period		--			--			--
Funded status at end of period	$	(37,849	)	$	(39,098	)	$	(37,519	)

Other Benefits
(Dollars in Thousands)	Successor February 6, 2009 - March 31, 2009 1			Predecessor January 1, 2009 - February 5, 2009			Predecessor Quarter Ended March 31, 2008
Change in benefit obligation:
Benefit obligation at beginning of period	$	15,807		$	18,089		$	18,864
Service cost		21			11			43
Interest cost		163			89			283
Benefits paid		(357	)		(147	)		(431	)
Medicare Part D subsidy received		418			139			--
Benefit obligation at end of period	$	16,052		$	18,181		$	18,759

Other Benefits
(Dollars in Thousands)	Successor February 6, 2009 - March 31, 2009 1			Predecessor January 1, 2009 - February 5, 2009			Predecessor Quarter Ended March 31, 2008
Change in plan assets:
Fair value of plan assets at beginning of period	$	7,829		$	8,435		$	14,700
Expected return on plan assets		69			37			197
Employer contribution		239			82			11
Benefits paid		(357	)		(147	)		(431	)
Fair value of plan assets at and of period		7,780			8,407			14,477
Funded status at end of period	$	(8,272	)	$	(9,774	)	$	(4,282	)

__________________

1 The disclosed information is based on an initial February 5, 2009 measurement date and as a result the expense numbers are shown pro-rated for the first quarter 2009.

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.  The full amount of the pension funding for 2009 is for PSE’s non-qualified supplemental retirement plan.

During the three months ended March 31, 2009, payments of benefits related to PSE’s non-qualified pension plans were $0.4 million.  Based on this activity, PSE anticipates paying additional benefits of $3.6 million for PSE’s non-qualified pension plan during 2009.  During the three months ended March 31, 2009, actual other post-retirement medical benefit plan contributions were $0.2 million.  PSE expects to make additional contributions of approximately $18.0 million during the remaining periods of 2009.

(8)   Regulation and Rates

The merger order issued by the Washington Commission was subject to a Settlement Stipulation which included 78 conditions.  The conditions provided for, among other matters, minimum equity to capitalization ratio, dividend restrictions, financial reporting and rate credits of $10.0 million per year for ten years.  PSE does not expect these conditions to impact PSE’s ability to pay expenses, dividends or redeem debt.

On May 8, 2009, PSE filed a general rate case requesting recovery of increased electric and natural gas revenue requirements of approximately $148.1 million or 7.4% annually, and $27.2 million or 2.2% annually, respectively.  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 8, 2009, PSE filed an adjustment to its PGA with an effective date of June 1, 2009 to credit $21.2 million over four months to customers.  This decrease in rates reflects natural gas prices that are lower than what are currently reflected in gas rates.  On May 20, 2009, after discussions with Washington Commission Staff, PSE adjusted the filing to pass the credit back to customers over twelve months.  The Washington Commission approved the credit May 28, 2009 with an effective date of June 1, 2009.

On April 17, 2009, the Washington Commission issued a final 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 company 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 is sooner.  As of March 31, 2009, PSE had established a regulatory asset of $7.7 million.  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 4.6% 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.

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 natural 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 will increase PSE’s revenue but will not impact PSE’s net income as the increased revenue will be offset by increased purchased gas costs.

(9)   Litigation

Residential Exchange.  Petitioners in several actions in the U. S. Court of Appeals for the Ninth Circuit (Ninth Circuit) against the Bonneville Power Administration (BPA) asserted that BPA acted contrary to law in entering into,  performing or implementing a number of agreements, including the amended settlement agreement (and the May 2004 agreement) between BPA and PSE regarding the Residential Exchange Program (REP).  Petitioners in several actions in the Ninth Circuit against BPA also asserted that BPA acted contrary to law in adopting or implementing the rates upon which the benefits received or to be received from BPA during the October 1, 2001 through September 30, 2006 period were based.  A number of parties claimed that BPA rates proposed or adopted in the BPA rate proceeding to develop BPA rates to be used in the agreements for determining the amounts of money to be paid to PSE by BPA during the period October 1, 2006 through September 30, 2009 are contrary to law and that BPA acted contrary to law or without authority in deciding to enter into, in entering into,  in performing or in implementing such agreements.

On May 3, 2007, the Ninth Circuit issued an opinion in Portland Gen. Elec. v. BPA, CaseNo. 01-70003, in which proceeding the actions of BPA in entering into settlement agreements regarding the REP with PSE and with other investor-owned utilities were challenged.  In this opinion, the Ninth Circuit granted petitions for review and held the settlement agreements entered into between BPA and the investor-owned utilities being challenged in that proceeding to be inconsistent with statute.  On May 3, 2007, the Ninth Circuit also issued an opinion in Golden Northwest Aluminum v. BPA, CaseNo. 03-73426, in which proceeding the petitioners sought review of BPA’s 2002-2006 power rates.  In this opinion, the Ninth Circuit granted petitions for review and held that BPA unlawfully shifted onto its preference customers the costs of its settlements with the investor-owned utilities.  On October 5, 2007, petitions for rehearing of these two opinions were denied.  On February 1, 2008, PSE and other utilities filed in the Supreme Court of the United States a petition for a writ of certiorari to review the decisions of the Ninth Circuit, which petition was denied in June 2008.

In May 2007, following the Ninth Circuit’s issuance of these two opinions, BPA suspended payments to PSE under the amended settlement agreement (and the May 2004 agreement).  On October 11, 2007, the Ninth Circuit remanded the May 2004 agreement to BPA in light of the Portland Gen. Elec. v. BPA opinion and dismissed the remaining three pending cases regarding settlement agreements.

In March 2008, BPA and PSE signed an agreement pursuant to which BPA made a payment to PSE related to the REP benefits for the fiscal year ended September 30, 2008, which payment is subject to true-up depending upon the amount of any REP benefits ultimately determined to be payable to PSE.  In March and April 2008, Clatskanie People’s Utility District filed petitions in the Ninth Circuit for review of BPA actions in connection with offering or entering into such agreement with PSE and similar agreements with other investor-owned utilities.  Clatskanie People’s Utility District asserts that BPA’s actions in entering into and executing the 2008 REP agreements were contrary to law or without authority and that such agreements are null and void and result in overpayments of REP benefits to PSE and other regional investor-owned utilities.

In September 2008, BPA issued its record of decision in its reopened WP-07 rate proceeding to respond to the various Ninth Circuit opinions.  In thisrecord of decision, BPA adjusted its fiscal year 2009 rates, determined the amounts of REP benefits it considered to have been improperly paid after fiscal year 2001 to PSE and the other regional investor-owned utilities, and determined that such amounts are to be recovered through reductions in REP benefit payments to be made over a number of years.  The amount determined by BPAto be recovered through reductions commencing October 2007 in REP payments for PSE’s residential and small farm customers was approximately $207.2 million plus interest on unrecovered amounts.  However, these BPA determinations are subject to subsequent administrative and judicial review, which may alter or reverse such determinations.PSE and others, including a number of preference agency and investor-owned utility customers of BPA, in December 2008 filed petitions for review in the Ninth Circuit of various of these BPA determinations.  PSE is reviewing its options in determining if it will contest the amounts withheld as improper payments made since 2001.

In September 2008, BPA and PSE signed a short-termResidential Purchase and Sale Agreement (RPSA) under which BPA is to pay REP benefits to PSE for fiscal years ending September 30, 2009–2011.In December 2008, BPA and PSE signed another long-term RPSA under which BPA is to pay REP benefits to PSE for the period October 2011 through September 2028.  PSE and other customers of BPA in December 2008 filed petitions for review in the Ninth Circuit of the short-term and long-term RPSAs signed by PSE (and similar RPSAs signed by other investor-owned utility customers of BPA) and BPA’s record of decision regarding such RPSAs.  Generally, REP benefit payments under a RPSA are based on the amount, if any, by which a utility’s average system cost (ASC) exceeds BPA’s Priority Firm (PF) Exchange rate for such utility.  The ASC for a utility is determined using an ASC methodology adopted by BPA.  The ASC methodology adopted by BPA and the ASC determinations, REP overpayment determinations, and the PF Exchange rate determinations by BPA are all subject to Federal Energy Regulatory Commission (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.  As discussed above, BPA has determined to reduce such payments based on its determination of REP benefit overpayments after fiscal year 2001.

It is not clear what impact, if any, such development or review of such BPA rates, review of such ASC, ASC methodology, and BPA determination of REP overpayments, review of such agreements, and the above described Ninth Circuit litigation may ultimately have on PSE.  Any changes to the REP payments passes through to customers with no impact to PSE’s net income.

Proceedings Related to the Western Power Market. Puget Energy’s and PSE’s Annual Report on Form 10-K for the year ended December 31, 2008 includes a summary relating to the western power market proceedings.  PSE is vigorously defending each of these cases.  Litigation is subject to numerous uncertainties and PSE is unable to predict the ultimate outcome of these matters.  Accordingly, there can be no guarantee that these proceedings, either individually or in the aggregate, will not materially and/or adversely affect PSE’s financial condition, results of operations or liquidity.

CPUC v. FERC. On August 2, 2006, the Ninth Circuit decided that FERC erred in excluding potential relief for tariff violations for periods that pre-dated October 2, 2000 and additionally ruled that FERC should consider remedies for transactions previously considered outside the scope of the proceedings.  The August 2, 2006 decision may adversely impact PSE’s ability to recover the full amount of its California Independent System Operator (CAISO) receivable.  The decision may also expose PSE to claims or liabilities for transactions outside the previously defined “refund period.”  At this time the ultimate financial outcome for PSE is unclear.  Rehearing by the Ninth Circuit was denied on April 6, 2009.  Parties have been engaged in court-sponsored settlement discussions, and those discussions may result in some settlements.

On May 8, 2009, PSE and the California Parties filed a proposed settlement at FERC that would resolve all issues arising from the 2000-2001 western energy crisis between PSE and California.  The settlement is contingent upon FERC and CPUC approvals and upon regulatory approvals of a renewable power transaction between PSE and Southern California Edison.  PSE anticipates receiving those approvals by mid-summer.  Until regulatory treatment of the settlement is established, the net financial impact of the settlement is uncertain.

(10)   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 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 March 31, 2009 and December 31, 2008, the outstanding balance of the Note was $19.4 million and $26.1 million, respectively, and the interest rate was 1.4% and 1.7%, respectively.  This Note is unaffected by the February 6, 2009 merger.

PSE has a general liability claim from AEGIS Insurance Services Inc. (AEGIS) for $3.3 million as of March 31, 2009 which was recovered by PSE in April 2009.  A PSE management employee serves on one of AEGIS’ risk management advisory committees for which no compensation is received.

PSE has property insurance with various companies and approximately 35.0% of the property insurance coverage is with American International Group, Inc (AIG).  On October 23, 2008, AIG named the wife of PSE’s President and Chief Executive as its Vice Chairman and Chief Restructuring Officer.

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 March 31, 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.

(11)   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 in the quarterly financial statements for periods ending after December 15, 2008 for VIEs.  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) 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, the 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 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 period of January 1, 2009 through February 5, 2009 for this entity was $6.2 million and $11.4 million for the period of February 6, 2009 through March 31, 2009.  Purchased electricity expense for the period ended March 31, 2008 for this entity was $17.9 million.  The contract expires in December 2011.

EITF No. 01-8 is to be applied to: (a) arrangement 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 March 31, 2009:

(Dollars in Millions)	Variable Interests in Power Purchase Agreements as of March 31, 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	$	(5.7	)	$	17.5
Electric-hydro	2037		7		(0.4	)		1.6
Other	2011		2		--			0.1
Total			10	$	(6.1	)	$	19.2

_____________

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.

(12)   New Accounting Pronouncements

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 April 9, 2009, FASB issued Staff Position (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.”  This FSP 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. This FSP also includes guidance on identifying circumstances that indicate a transaction is not orderly.  The FSP will be effective for Puget Energy as of June 30, 2009.  Puget Energy is currently assessing the impact of the FSP on its disclosures.

On April 9, 2009, FASB issued FSP 107-1, “Interim Disclosures about Fair Value of Financial Instruments.”  This FSP 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.  This FSP also amends APB Opinion No. 28, “Interim Financial Reporting,” to require those disclosures in summarized financial information at interim reporting periods.  The FSP will be effective for Puget Energy as of June 30, 2009.

On May 28, 2009, FASB issued SFAS No. 165, “Subsequent Events.”  The objective of this statement is to establish general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued.  SFAS No. 165 is not expected to have a material impact on the financial reporting of Puget Energy.

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.  The Company’s actual results could differ materially from those anticipated in these forward-looking statements for many reasons, including the factors described below and under the caption “Forward-Looking Statements” at the beginning of this report.  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.  PSE is the largest electric and natural gas utility in the state of Washington, primarily engaged in the business of electric transmission, distribution, generation and natural gas distribution.  Puget Energy’s business strategy is to generate stable 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, the 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 in respect of which dissenter’s rights were perfected and 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 44.4% at March 31, 2009.

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 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.

Net income for the three months ended March 31, 2009 was $64.8 million on operating revenues of $1.1 billion as compared to net income of $79.8 million on operating revenues of $1.1 billion for the same period in 2008.  Net income for the three months ended March 31, 2009 as compared to the same period in 2008 was positively impacted by a $26.3 million pre-tax increase in electric margin and a $12.1 million pre-tax increase in natural gas margin.  Electric and natural gas margins were favorably impacted by general tariff rate increases of 7.1% and 4.6%, respectively, approved by the Washington Utilities and Transportation Commission (Washington Commission) and were effective November 1, 2008.  The favorable impact of lower natural gas prices and wholesale power costs was offset by below normal hydroelectric energy production during the first quarter of 2009.  Net income was negatively impacted by merger costs of $46.8 million related to the merger of Puget Energy with Puget Holdings.  The merger costs primarily related to PSE employee compensation triggered by Puget Energy’s change of control compensation expense, credit agreement related expenses and the transaction advisory services and legal fees.  Net income was negatively impacted by an increase in interest expense of approximately $10.1 million which is due primarily to an increase in new debt of $1.5 billion issued at the time of the merger.  Also negatively impacting net income was an increase in depreciation and amortization of $6.0 million and a $5.0 million contribution to the Puget Sound Energy Foundation.  A $8.3 million unrealized gain on derivative instruments related to the revaluation of derivatives in accordance with SFAS No. 141R positively impacted net income for the quarter ended March 31, 2009.

Puget Sound Energy

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 under recovery 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 electric margin changes for the three months ended March 31, 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 March 31,	Successor February 6, 2009 - March 31, 2009			Predecessor January 1, 2009 - February 5, 2009			Combined 2009			Predecessor 2008			Change			Percent Change
Electric operating revenue1	$	386.6		$	213.6		$	600.2		$	606.1		$	(5.9	)		(1.0	) %
Less: Other electric operating revenue		(2.6	)		1.8			(0.8	)		(12.2	)		11.4			93.4
Add: Other electric operating revenue-gas supply resale		(4.3	)		(4.6	)		(8.9	)		2.6			(11.5	)		*
Total electric revenue for margin		379.7			210.8			590.5			596.5			(6.0	)		(1.0	)
Adjustments for amounts included in revenue:
Pass-through tariff items		(13.8	)		(7.9	)		(21.7	)		(12.9	)		(8.8	)		(68.2	)
Pass-through revenue-sensitive taxes		(28.5	)		(15.9	)		(44.4	)		(41.6	)		(2.8	)		(6.7	)
Net electric revenue for margin		337.4			187.0			524.4			542.0			(17.6	)		(3.2	)
Minus power costs:
Purchased electricity1		(169.5	)		(90.7	)		(260.2	)		(272.8	)		12.6			4.6
Electric generation fuel1		(36.1	)		(12.0	)		(48.1	)		(47.0	)		(1.1	)		(2.3	)
Residential exchange1		19.9			12.5			32.4			--			32.4			*
Total electric power costs		(185.7	)		(90.2	)		(275.9	)		(319.8	)		43.9			13.7
Electric margin2	$	151.7		$	96.8		$	248.5		$	222.2		$	26.3			11.8	%

__________________

1	As reported on Puget Energy’s Consolidated Statement of Income for Successor and Predecessor.
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 $26.3 million for the three months ended March 31, 2009 as compared to the same period in 2008.  The increase in electric margin was primarily due to a general rate case increase of 7.1% effective November 1, 2008 and favorable impact of lower natural gas and wholesale power prices offset by below normal hydroelectric energy production during the first quarter 2009 which increased margin by $28.3 million.  With lower natural gas prices, PSE increased its generation from its gas-fired generating facilities.  This increase was partially offset by a 0.5% decrease in retail kilowatt hour (kWh) sales and other items which decreased margin by $1.9 million.

The following table displays the details of gas margin changes for the three months ended March 31, 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 March 31,	Successor February 6, 2009 - March 31, 2009			Predecessor January 1, 2009 -  February 5, 2009			Combined 2009			Predecessor 2008			Change			Percent Change
Gas operating revenue1	$	316.4		$	190.0		$	506.4		$	443.2		$	63.2			14.3	%
Less: Other gas operating revenue		(3.3	)		(1.6	)		(4.9	)		(4.6	)		(0.3	)		(6.5	)
Total gas revenue for margin		313.1			188.4			501.5			438.6			62.9			14.3
Adjustments for amounts included in revenue:
Pass-through tariff items		(2.9	)		(1.8	)		(4.7	)		(4.4	)		(0.3	)		(6.8	)
Pass-through revenue-sensitive taxes		(26.2	)		(15.4	)		(41.6	)		(35.0	)		(6.6	)		(18.9	)
Net gas revenue for margin		284.0			171.2			455.2			399.2			56.0			14.0
Minus purchased gas costs1		(199.2	)		(120.9	)		(320.1	)		(276.2	)		(43.9	)		(15.9	)
Gas margin2	$	84.8		$	50.3		$	135.1		$	123.0		$	12.1			9.8	%

____________________
1	As reported on Puget Energy’s Consolidated Statement of Income for Successor and Predecessor.
2	Gas margin does not include any allocation for amortization/depreciation expense or electric generation operations and maintenance expense.

Gas margin increased $12.1 million for the three months ended March 31, 2009 as compared to the same period in 2008 primarily due to the general rate case increase of 4.6% effective November 1, 2008 which increased margin by $20.4 million.  This increase was partially offset by a decrease in margin of $6.4 million due to customer mix and other pricing variances and a decrease of $1.9 million due to a 1.6% decrease in gas therm volume.

Electric Operating Revenues

The table below sets forth changes in electric operating revenues for PSE for the three months ended March 31, 2009 as compared to the same period in 2008.

(Dollars in Millions) Three Months Ended March 31,	Successor February 6, 2009 - March 31, 2009			Predecessor January 1, 2009 - February 5, 2009			Combined 2009			Predecessor 2008			Change			Percent Change
Electric operating revenues:
Residential sales	$	226.3		$	132.5		$	358.8		$	346.6		$	12.2			3.5	%
Commercial sales		152.0			79.6			231.6			212.0			19.6			9.2
Industrial sales		17.7			8.8			26.5			27.5			(1.0	)		(3.6	)
Other retail sales, including unbilled revenue		(20.9	)		(8.5	)		(29.4	)		(11.6	)		(17.8	)		*
Total retail sales		375.1			212.4			587.5			574.5			13.0			2.3
Transportation sales		2.0			0.5			2.5			1.5			1.0			66.7
Sales to other utilities and marketers		6.9			2.4			9.3			18.0			(8.7	)		(48.3	)
Other		2.6			(1.7	)		0.9			12.1			(11.2	)		(92.6	)
Total electric operating revenues	$	386.6		$	213.6		$	600.2		$	606.1		$	(5.9	)		(1.0	)%

____________________

* Percent change not applicable or meaningful.

Electric retail sales increased $13.0 million for the three months ended March 31, 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, which was partially offset by a merger rate credit effective February 13, 2009, which on a combined basis, contributed to an increase in electric retail sales of $41.4 million for 2009 as compared to 2008.  Electric retail sales also increased by $7.5 million as a result of an increase in the conservation rider charged to customers due to an increase in PSE’s energy efficiency programs, which have no impact on net income as the amount is offset in conservation amortization.  These increases were partially offset by a decrease in retail electricity usage of 30,346 megawatt hours (MWh) or 0.5% for 2009 as compared to the same period in 2008, which resulted in a decrease of approximately $2.9 million to electric operating revenue.  The benefits of the Residential and Farm Energy Exchange Benefit (REP) credited to customers reduced electric operating revenues by $33.9 million in 2009.  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 $8.7 million for the three months ended March 31, 2009 as compared to the same period in 2008 primarily due to a decrease in wholesale electric energy prices which decreased revenue by of $9.1 million.  This decrease was partially offset by an increase in other items.

Other electric operating revenues decreased $11.2 million for the three months ended March 31, 2009 as compared to the same period in 2007 primarily due to a decrease of $11.5 million in noncore gas sales and related losses from hedging contracts entered into to manage those noncore gas sales.

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 March 31, 2009 as compared to the same period in 2008.

(Dollars in Millions) Three Months Ended March 31,	Successor February 6, 2009 - March 31, 2009		Predecessor January 1, 2009 - February 5, 2009		Combined 2009		Predecessor 2008		Change			Percent Change
Gas operating revenues:
Residential sales	$	213.4	$	130.8	$	344.2	$	294.2	$	50.0			17.0	%
Commercial sales		87.5		51.9		139.4		127.8		11.6			9.1
Industrial sales		9.9		4.9		14.8		12.8		2.0			15.6
Total retail sales		310.8		187.6		498.4		434.8		63.6			14.6
Transportation sales		2.3		0.8		3.1		3.8		(0.7	)		(18.4	)
Other		3.3		1.6		4.9		4.6		0.3			6.5
Total gas operating revenues	$	316.4	$	190.0	$	506.4	$	443.2	$	63.2			14.3	%

Gas retail sales increased $63.6 million for the three months ended March 31, 2009 as compared to the same period in 2008 due to a $64.8 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 and a general rate increase effective November 1, 2008.  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 was a $1.0 million decrease in gas therm sales which decreased margin $1.3 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)

Operating Expenses

The table below sets forth significant changes in operating expenses for PSE and its subsidiaries for the three months ended March 31, 2009 as compared to the same period in 2008.

(Dollars in Millions) Three Months Ended March 31,	Successor February 6, 2009 - March 31, 2009			Predecessor January 1, 2009 - February 5, 2009			Combined 2009			Predecessor 2008		Change			Percent Change
Purchased electricity	$	169.5		$	90.7		$	260.2		$	272.8	$	(12.6	)		(4.6	)%
Residential exchange		(19.9	)		(12.5	)		(32.4	)		--		(32.4	)		*
Purchased gas		199.1			120.9			320.1			276.2		43.9			15.9
Unrealized (gain) loss on derivatives		(12.1	)		3.8			(8.3	)		0.1		(8.4	)		*
Utility operations and maintenance		77.2			37.7			114.9			112.2		2.7			2.4
Non-utility expense and other		2.5			0.1			2.6			0.5		2.1			*
Merger and related costs		2.5			44.3			46.8			1.3		45.5			*
Depreciation and amortization		54.7			26.7			81.4			75.4		6.0			8.0
Conservation amortization		13.2			7.6			20.8			13.4		7.4			55.2
Taxes other than income taxes		64.4			36.9			101.3			94.3		7.0			7.4

___________________

* Percent change not applicable or meaningful.

Purchased electricity expenses decreased $12.6 million for the three months ended March 31, 2009 as compared to the same period in 2008.  The decrease is related to lower wholesale power prices and increased generation at PSE’s gas-fired generating facilities due to lower cost of natural gas in the three months ended March 31, 2009 as compared to the same period in 2008, which resulted in a decrease of $13.1 million.  PSE utilizes less purchased power when the cost of natural gas is lower than the cost of wholesale purchased power due to its recent acquisitions of the Goldendale and Mint Farm gas-fired generating facilities, which have low heat rates. This decrease was partially offset by an increase of $0.6 million in transmission and other expenses.

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

Residential exchange credits associated with the Bonneville Power Administration (BPA) REP increased to $32.4 million for the three months ended March 31, 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 increased $43.9 million for the three months ended March 31, 2009 as compared to the same period in 2008 primarily due to an increase of 11.1% in PGA rates which provides the rates used to determine gas costs based on customer usage.  The rate increase was the result of higher costs of natural gas in the forward market 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 to defer, as a receivable or liability, any natural gas supply and transportation costs that exceed or fall short of this expected gas cost amount in PGA mechanism rates, including accrued interest.  The PGA mechanism payable balance at March 31, 2009 was $29.7 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 $8.4 million for the three months ended March 31, 2009 as compared to the same period in 2008 primarily due to SFAS No. 141R which required Puget Energy to account for the cash flow hedge contracts at fair value.  A loss of $136.9 million pre-tax was recorded as part of purchase accounting.  The fair value of these contracts at time of the merger will be recorded through the income statement upon settlement.  As a result, $23.1 million of unrealized losses reversed and settled during the quarter and $1.0 million in other items provided a positive impact to earnings.  These earnings were offset by $11.4 million of unrealized losses due to decreased market prices related to electric derivative contracts and $4.3 million of unrealized losses associated with the ineffective portion of cash flow hedges for certain power purchase agreements which had a negative impact on earnings.

Utility operations and maintenance expense increased $2.7 million for the three months ended March 31, 2009 as compared to the same period in 2008.  The increase for the three months ended March 31, 2009 was primarily due to an increase in administrative and general expenses of $3.1 million which included increases in salary and employee benefits expense, an increase in rent expense and an increase in property insurance costs, customer service costs of $3.0 million, electric transmission and distribution costs of $1.9 million and a $1.6 million increase in gas operations and distribution expenses.  These increases were partially offset by a $7.8 million decrease in production operations and maintenance costs related to settlement of a lawsuit at the Colstrip generating facilities.

Non utility expense and other expense increased $2.1 million for the three months ended March 31, 2009 as compared to the same period in 2008.   The increase was primarily the result of a $1.3 million charge related to the postretirement and pension plan expenses as a result of a purchase accounting fair value adjustment which cause the plan to be revaluated at the date of the merger.  Also contributing to the increase is a $0.6 million charge related to officer/director performance based post-merger retention agreements coupled with a reversal of an overaccrual in the long-term incentive stock plan during the same period in the prior year.

Merger and related costs increased $45.5 million for the three months ended March 31, 2009 as compared to the same period in 2008.  Merger related 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.  Also contributing to the increase in merger expenses were transaction advisory costs and legal fees.  Pursuant to the Washington Commission merger order commitments, PSE will not seek recovery of these costs.

Depreciation and amortization expense increased $6.0 million for the three months ended March 31, 2009 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 $3.8 million, depreciation and amortization expense increased $9.8 million for the three months ended March 31, 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 $7.4 million for the three months ended March 31, 2009 as compared to the same period in 2008 due to higher authorized recovery of electric conservation expenditures.  Conservation amortization is a pass-through tariff item with no impact on earnings.

Taxes other than income taxes increased $7.0 million for the three months ended March 31, 2009 as compared to the same period in 2008.  Revenue sensitive taxes increased $9.3 million due to an increase in revenue offset by a decrease of $2.7 million in property taxes from a true-up of accrued property taxes recorded for 2008.

Other Income, Other Expenses, Interest Expense and Income Tax Expense.  The table below sets forth significant changes for Puget Energy from 2008 to 2009.

(Dollars in Millions) Three Months Ended March 31,	Successor February 6, 2009 -  March 31, 2009			Predecessor January 1, 2009 -  February 5,  2009			Combined 2009			Predecessor 2008			Change			Percent Change
Other income and expense	$	(0.8	)	$	3.3		$	2.5		$	5.9		$	(3.4	)		(57.6	)%
Interest expense		(41.8	)		(16.9	)		(58.7	)		(48.6	)		(10.1	)		(20.8	)
Income tax expense		22.0			9.0			31.0			35.3			(4.3	)		(12.2	)

Other income and expense decreased $3.4 million for 2009 as compared to the same period in 2008.  The decrease was primarily due to a donation of $5.0 million to the PSE foundation.   This decrease was partially offset by an increase of $1.7 million related to an increase in regulatory interest income from Mint Farm.

Interest expense increased $10.1 million for 2009 as compared to the same period in 2008.  The increased interest expense is primarily the result of increased short-term debt outstanding in January before proceeds from the merger paid down the debt in February after the merger closed and an increase in new debt of $1.5 billion which was issued at the time of the merger.  This increase was offset by $3.3 million of debt discount amortization.

Income tax expensedecreased $4.3 millionin 2009 as compared to the same period in 2008 primarily due to declining income which lowered tax expense by $6.7 million.  Non deductible transaction costs increased tax expense by $5.6 million which were partially offset by a beneficial change in production tax credits of $2.1 million between 2009 and 2008.

Capital Requirements

Contractual Obligations and Commercial Commitments

Puget Energy.  The following are Puget Energy’s aggregate contractual obligations and commercial commitments as of March 31, 2009:

			Payments Due Per Period
Contractual Obligations (Dollars in Millions)	Total		2009			2010- 2011		2012- 2013	2014 & Thereafter
Long-term debt including interest	$	8,086.6	$	210.6	$	952.8	$	449.1	$	6,474.1
Short-term debt including interest		194.5		194.5		--		--		--
Service contract obligations		398.3		51.9		129.2		82.3		134.9
Non-cancelable operating leases		193.6		47.4		28.9		27.7		89.6
Fredonia gas-fired generating facility lease 1		46.3		46.3		--		--		--
Energy purchase obligations		4,796.2		645.5		1,635.2		772.0		1,743.5
Contract initiation payment/collateral requirement		18.5		--		18.5		--		--
Financial hedge obligations		112.6		59.7		52.9		--		--
Purchase obligations		130.1		73.1		6.6		6.8		43.6
Pension and other benefits funding and payments		155.0		21.5		46.0		43.8		43.7
Total contractual cash obligations	$	14,131.7	$	1,350.5	$	2,870.1	$	1,381.7	$	8,529.4

______________

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

The following are Puget Energy’s aggregate consolidated commercial commitments as of March 31, 2009:

Puget Energy			Amount of Commitment Expiration Per Period
Commercial Commitments (Dollars in Millions)	Total		2009			2010- 2011		2012- 2013	2014 & Thereafter
Puget Energy capital expenditure facility 1	$	742.0	$	--	$	--	$	--	$	742.0
PSE working capital facility 1		225.0		--		--		--		225.0
PSE capital expenditure facility 1		400.0		--		--		--		400.0
PSE energy hedging facility 1		315.0		--		--		--		315.0
PSE energy operations letter of credit		6.6		6.6		--		--		--
PSE energy hedging letter of credit		35.0		35.0		--		--		--
Total commercial commitments	$	1,723.6	$	41.6	$	--	$	--	$	1,682.0

_____________

1 See the discussion below on credit facilities.

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 intends to purchase the gas-fired turbines by January 2010.  Payments under the lease vary with changes in the London Interbank Offered Rate (LIBOR).  At March 31, 2009, PSE’s outstanding balance under the lease was $44.7 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 $177.7 million for the three months ended March 31, 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 cash from operations, short-term debt, long-term debt and equity.  Construction expenditure estimates, including any new generation resources, are subject to periodic review and adjustment in light of changing economic, regulatory, environmental and efficiency factors.

Capital Resources

Cash From Operations

Cash generated from operations for 2009 was $277.0 million, a decrease of $57.6 million from the $334.6 million generated during the first quarter of 2008.  The decrease was primarily the result of an increase of $175.4 million paid related to operating and merger expenses.  Also contributing to the decrease was an income tax refund of $42.3 million in 2008 compared to a refund of $0.3 million in 2009.  Fuel and gas inventory costs increased $27.0 million as compared to the same period in 2008 due to higher natural gas storage volumes and costs in 2009.  

The decrease in cash generated from operating activities for 2009 as compared to 2008 was partially offset by $147.7 million of derivatives cash outflow that was reclassified as a financing activity as a result of the merger.  The derivative activity relates to settlement of energy derivative contracts that accounting rules refer to as a financing activity.  The decrease in cash generated from operating activities for the first quarter 2009 as compared to 2008 was also partially offset by overrecovery of natural gas costs through the PGA mechanism during the first quarter 2009 of $20.8 million compared to an underrecovery of $9.4 million during the same period in 2008 which increased operating activities by $30.2 million.

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.

On January 23, 2009, PSE issued $250.0 million of first mortgage bonds.  The bonds were placed with approximately 35 institutional investors, have a term of seven years and carry a 6.75% interest rate.

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

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 short-term 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 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.  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 March 31, 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

As of March 31, 2009 and February 5, 2009, PSE had $175.0 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 March 31, 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 for the Puget Energy agreements.  PSE’s financial covenants include the following two ratios:  cash flow interest coverage and cash flow debt leverage.

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. 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 March 31, 2009, PSE had borrowed $175.0 million on the $400.0 million working capital facility, had a $35.0 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 drawn loans 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.  $188.0 million was outstanding under the receivables securitization facility at February 5, 2009.  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 and terminated and were 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 March 31, 2009, the outstanding balance of the Note was $19.4 million.  This Note is unaffected by the February 6, 2009 merger.

Bond Issuance.  On January 23, 2009, PSE issued $250.0 million of 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.  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’s 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 by 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 March 31, 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 March 31, 2009;

·   approximately $560.0 million of additional first mortgage bonds under PSE’s natural gas mortgage indenture based on approximately $930.0 million 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 March 31, 2009.

At March 31, 2009, PSE had approximately $5.1 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.

The ratings of Puget Energy and PSE, as of May 5, 2009, were as follows:

	Ratings
	S&P1	Moody’s2
Puget Sound Energy, Inc.
Corporate credit/issuer rating	BBB	Baa3
Senior secured debt	A-	Baa2
Junior subordinated notes	BB+	Ba1
Preferred stock	BB+	Ba2
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.

Other

Regulation and Rates

The merger order issued by the Washington Commission was subject to a Settlement Stipulation which included 78 conditions.  The conditions provided for, among other matters, minimum equity to capitalization ratio, dividend restrictions, financial reporting and rate credits of $10.0 million per year for ten years.  PSE does not expect these conditions to impact PSE’s ability to pay expenses, dividends or redeem debt.

On May 8, 2009, PSE filed a general rate case requesting recovery of increased electric and natural gas revenue requirements of approximately $148.1 million or 7.4% annually, and $27.2 million or 2.2% annually, respectively.  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 8, 2009, PSE filed an adjustment to its PGA with an effective date of June 1, 2009 to credit $21.2 million over four months to customers.  This decrease in rates reflects natural gas prices that are lower than what are currently reflected in gas rates.  On May 20, 2009, after discussions with Washington Commission Staff, PSE adjusted the filing to pass the credit back to customers over twelve months.  The Washington Commission approved the credit May 28, 2009 with an effective date of June 1, 2009.

On April 17, 2009, the Washington Commission issued a final 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 company 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 March 31, 2009, PSE had established a regulatory asset of $7.7 million.  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 4.6% 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.

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 will increase PSE’s revenue but will not impact PSE’s net income as the increased revenue will be offset by increased purchased gas costs.

Proceedings Relating to the Western Power Market

Puget Energy’s and PSE’s Annual Report on Form 10-K for the year ended December 31, 2008 includes a summary relating to the western power market proceedings.  PSE is vigorously defending each of these cases.  Litigation is subject to numerous uncertainties and PSE is unable to predict the ultimate outcome of these matters.  Accordingly, there can be no guarantee that these proceedings, either individually or in the aggregate, will not materially and/or adversely affect PSE’s financial condition, results of operations or liquidity.

CPUC v. FERC.  On August 2, 2006, the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit) decided that Federal Energy Regulatory Commission (FERC) erred in excluding potential relief for tariff violations for periods that pre-dated October 2, 2000 and additionally ruled that FERC should consider remedies for transactions previously considered outside the scope of the proceedings.  The August 2, 2006 decision may adversely impact PSE’s ability to recover the full amount of its California Independent System Operator (CAISO) receivable.  The decision may also expose PSE to claims or liabilities for transactions outside the previously defined “refund period.”  At this time, the ultimate financial outcome for PSE is unclear.  Rehearing by the Ninth Circuit was denied on April 6, 2009.  Parties have been engaged in court-sponsored settlement discussions, and those discussions may result in some settlements.

On May 8, 2009, PSE and the California Parties filed a proposed settlement at FERC that would resolve all issues arising from the 2000-2001 western energy crisis between PSE and California.  The settlement is contingent upon FERC and CPUC approvals and upon regulatory approvals of a renewable power transaction between PSE and Southern California Edison.  PSE anticipates receiving those approvals by mid-summer.  Until regulatory treatment of the settlement is established, the net financial impact of the settlement is uncertain.

Proceedings Relating to the Bonneville Power Administration

Petitioners in several actions in the Ninth Circuit against BPA asserted that BPA acted contrary to law in entering into or performing or implementing a number of agreements, including the amended settlement agreement (and the May 2004 agreement) between BPA and PSE regarding the REP.  Petitioners in several actions in the Ninth Circuit against BPA also asserted that BPA acted contrary to law in adopting or implementing the rates upon which the benefits received or to be received from BPA during the October 1, 2001 through September 30, 2006 period were based.  A number of parties claimed that the BPA rates proposed or adopted in the BPA rate proceeding to develop BPA rates to be used in the agreements for determining the amounts of money to be paid to PSE by BPA during the period October 1, 2006 through September 30, 2009 are contrary to law and that BPA acted contrary to law or without authority in deciding to enter into, in entering into, in performing or in implementing such agreements.

On May 3, 2007, the Ninth Circuit issued an opinion in Portland Gen. Elec. v. BPA, CaseNo. 01-70003, in which proceeding the actions of BPA in entering into settlement agreements regarding the REP with PSE and with other investor-owned utilities were challenged.  In this opinion, the Ninth Circuit granted petitions for review and held the settlement agreements entered into between BPA and the investor-owned utilities being challenged in that proceeding to be inconsistent with statute.  On May 3, 2007, the Ninth Circuit also issued an opinion in Golden Northwest Aluminum v. BPA, CaseNo. 03-73426, in which proceeding the petitioners sought review of BPA’s 2002-2006 power rates.  In this opinion, the Ninth Circuit granted petitions for review and held that BPA unlawfully shifted onto its preference customers the costs of its settlements with the investor-owned utilities.  On October 5, 2007, petitions for rehearing of these two opinions were denied.  On February 1, 2008, PSE and other utilities filed in the Supreme Court of the United States a petition for a writ of certiorari to review the decisions of the Ninth Circuit, which petition was denied in June 2008.

In May 2007, following the Ninth Circuit’s issuance of these two opinions, BPA suspended payments to PSE under the amended settlement agreement (and the May 2004 agreement).  On October 11, 2007, the Ninth Circuit remanded the May 2004 agreement to BPA in light of the Portland Gen. Elec. v. BPA opinion and dismissed the remaining three pending cases regarding settlement agreements.

In March 2008, BPA and PSE signed an agreement pursuant to which BPA made a payment to PSE related to the REP benefits for the fiscal year ended September 30, 2008, which payment is subject to true-up depending upon the amount of any REP benefits ultimately determined to be payable to PSE.  In March and April 2008, Clatskanie People’s Utility District filed petitions in the Ninth Circuit for review of BPA actions in connection with offering or entering into such agreement with PSE and similar agreements with other investor-owned utilities.  Clatskanie People’s Utility District asserts that BPA’s actions in entering into and in executing the 2008 REP agreements were contrary to law or without authority and that such agreements are null and void and result in overpayments of REP benefits to PSE and other regional investor-owned utilities.

In September 2008, BPA issued its record of decision in its reopened WP-07 rate proceeding to respond to the various Ninth Circuit opinions.  In thisrecord of decision, BPA adjusted its fiscal year 2009 rates, determined the amounts of REP benefits it considered to have been improperly paid after fiscal year 2001 to PSE and the other regional investor-owned utilities, and determined that such amounts are to be recovered through reductions in REP benefit payments to be made over a number of years.  The amount determined by BPAto be recovered through reductions commencing October 2007 in REP payments for PSE’s residential and small farm customers was approximately $207.2 million plus interest on unrecovered amounts.  However, these BPA determinations are subject to subsequent administrative and judicial review, which may alter or reverse such determinations.PSE and others, including a number of preference agency and investor-owned utility customers of BPA, in December 2008 filed petitions for review in the Ninth Circuit of various of these BPA determinations.  PSE is reviewing its options in determining if it will contest the amounts withheld as improper payments made since 2001.

In September 2008, BPA and PSE signed a short-termRPSA under which BPA is to pay REP benefits to PSE for fiscal years ending September 30, 2009–2011.In December 2008, BPA and PSE signed another long-term RPSA under which BPA is to pay REP benefits to PSE for the period October 2011 through September 2028.  PSE and other customers of BPA in December 2008 filed petitions for review in the Ninth Circuit of the short-term and long-term RPSAs signed by PSE (and similar RPSAs signed by other investor-owned utility customers of BPA) and BPA’s record of decision regarding such RPSAs.  Generally, REP benefit payments under a RPSA are based on the amount, if any, by which a utility's average system cost (ASC) exceeds BPA’s Priority Firm (PF) Exchange rate for such utility.  The ASC for a utility is determined using an ASC methodology adopted by BPA.  The ASC methodology adopted by BPA and the ASC determinations, REP overpayment determinations, and the PF Exchange rate determinations by BPA are all 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.  As discussed above, BPA has determined to reduce such payments based on its determination of REP benefit overpayments after fiscal year 2001.

It is not clear what impact, if any, such development or review of such BPA rates, review of such ASC, ASC methodology, and BPA determination of REP overpayments, review of such agreements, and the above described Ninth Circuit litigation may ultimately have on PSE.

Critical Accounting Policies And Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the reported amounts of assets and liabilities in the financial statements.  The following accounting policy, in addition to the critical accounting policies described in Puget Energy’s 2008 Form 10-K, represent those that management believes are particularly important to the financial statements and that require the use of estimates, assumptions, and judgment to describe matters that are inherently uncertain.

Business Combinations.  On February 6, 2009, Puget Holdings completed its merger with Puget Energy.  The transaction was accounted for in accordance with SFAS No. 141R, which requires the use of the acquisition method to account for business combinations.  The objective of this method is to establish a new accounting basis for the acquiree, Puget Energy.  Puget Energy’s assets and liabilities were remeasured and recorded at fair value as of the acquisition date.

New Accounting Pronouncements

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 April 9, 2009, Financial Accounting Standards Board (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.”  This FSP 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. This FSP also includes guidance on identifying circumstances that indicate a transaction is not orderly.  The FSP will be effective for Puget Energy as of June 30, 2009.  Puget Energy is currently assessing the impact of the FSP on its disclosures.

        On April 9, 2009, FASB issued FSP 107-1, “Interim Disclosures about Fair Value of Financial Instruments.”  This FSP 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. This FSP also amends APB Opinion No. 28, “Interim Financial Reporting,” to require those disclosures in summarized financial information at interim reporting periods.  The FSP will be effective for Puget Energy as of June 30, 2009.

On May 28, 2009, FASB issued SFAS No. 165, “Subsequent Events.”  The objective of this statement is to establish general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued.  SFAS No. 165 is not expected to have a material impact on the financial reporting of Puget Energy.

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 Puget Energy 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.

The following table presents the fair value of both electric and natural gas (electric generation fuel) derivative instruments entered into the “Electric” portfolio that do not meet the Normal Purchase Normal Sale (NPNS) exception at March 31, 2009 and December 31, 2008, including contracts designated as cash flow hedges:

Electric Portfolio (Dollars in Millions)	Successor March 31, 2009		Predecessor December 31, 2008
Current asset	$	1.2	$	0.4
Long-term asset		0.9		0.5
Total assets	$	2.1	$	0.9
Current liability	$	183.8	$	90.6
Long-term liability		123.7		96.1
Total liabilities	$	307.5	$	186.7

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.

The following table presents the earnings impact of changes in the market value of derivative instruments not meeting NPNS or cash flow hedges that are considered to be effective, but does include the earnings impact due to cash flow hedge ineffectiveness during the respective periods ended:

(Dollars in Millions)	Successor February 6,   2009 - March 31, 2009	Predecessor January 1, 2009 - February 5, 2009	Predecessor March 31, 2008
Decrease in earnings	$  (7.8)	$  (3.9)	$  (0.1)

The amount of unrealized loss, net of tax, related to PSE’s energy-related cash flow hedges under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133), deferred in accumulated OCI consisted of the following at March 31, 2009 and December 31, 2008:

(Dollars in Millions, net of tax)	Successor March 31, 2009	Predecessor March 31, 2008
Other comprehensive income – unrealized loss	$ (29.0)	$ (111.7)

The following table presents the fair value of  natural gas derivative instruments entered into the “Gas” portfolio that do not meet the NPNS exception at March 31, 2009 and December 31, 2008:

Gas Portfolio (Dollars in Millions)	Successor March 31, 2009		Predecessor December 31, 2008
Current asset	$	20.3	$	15.2
Long-term asset		9.0		6.2
Total assets	$	29.3	$	21.4
Current liability	$	166.8	$	146.3
Long-term liability		52.7		62.3
Total liabilities	$	219.5	$	208.6

At March 31, 2009, Puget Energy had total assets of $29.3 million and total liabilities of $219.5 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 $97.0 million, with a corresponding after-tax decrease in other comprehensive income and earnings of $21.1 million and $1.5 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.”

The following table presents the remaining unamortized inception fair values as of March 31, 2009 for De-Designated Commodity Instruments which represent derivative contracts acquired at fair value by the Successor Company at the acquisition date.  These commodity contracts were subsequently designated as NPNS in accordance with paragraph 10(b) of SFAS No. 133 and are no longer fair valued as of March 31, 2009.  The amounts below represent the remaining unamortized values at March 31, 2009 and December 31, 2008 that will be amortized into earnings over the original life of the contracts:

De-Designated Commodity Instruments (Dollars in Millions)	Successor March 31, 2009		Predecessor December 31, 2008
Current asset	$	4.1	$	--
Long-term asset		1.3		--
Total assets	$	5.4	$	--
Current liability	$	53.4	$	--
Long-term liability		31.8		--
Total liabilities	$	85.2	$	--

The de-designated commodity contracts are no longer considered to be derivative instruments due to the NPNS scope exception applied immediately following the acquisition date but will have an impact to net unrealized gains /(losses) due the subsequent amortization of the February 6, 2009 inception valuations which were frozen at that time.  The table below represents the earnings impact for the amortization of the unrealized gains/(losses) for contracts that were valued at February 6, 2009 (date of acquisition) during the respective periods ended:

Amortization of De-Designated Commodity Instruments (Dollars in Millions)	Successor February 6, 2009 - March 31, 2009	Predecessor January 1, 2009 - February 5, 2009
Increase (decrease) in earnings	$ 19.9	$  --

Contingent Features and Counterparty Credit Risk

PSE is exposed to credit risk primarily through buying and selling electricity and natural gas to serve customers.  Credit risk is the potential loss resulting from a counterparty’s non-performance under an agreement.  PSE manages credit risk with policies and procedures for, among other things, counterparty analysis, exposure measurement and 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 March 31, 2009, PSE held approximately $1.1 million worth of standby letters of credit in support of various electricity and renewable energy credit transactions.

It is possible that volatility in energy commodity prices could cause PSE to have material credit risk exposures with one or more counterparties.  If such counterparties fail to perform their obligations under one or more agreements, PSE could suffer a material financial loss.  However, as of March 31, 2009, approximately 99.6% of the counterparties with transaction amounts outstanding in PSE’s energy portfolio, including NPNS transactions, are rated at least investment grade by the major rating agencies and 0.4% 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.

Puget Energy 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 Puget Energy'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 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, Puget Energy 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, Puget Energy 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 March 31, 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.

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 March 31, 2009.

The following table presents the fair value of interest rate swaps designated as cash flow hedges at March 31, 2009 and December 31, 2008:

Interest Rate Swaps (Dollars in Millions)	Successor March 31, 2009		Predecessor December 31, 2008
Current liability	$	26.5	$	--
Long-term liability		9.8		--
Total liabilities	$	36.3	$	--

The fair value of interest rate swaps as of March 31, 2009 takes into account Puget Energy's non-performance risk estimated using Puget Energy's incremental borrowing rate on unsecured debt over the risk-free rate. The ending balance in OCI includes a net loss of $23.6 millionafter 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 100 basis point increase in interest rates would increase the fair value of interest rate swaps by $64.2 million, with a corresponding after-tax increase in unrealized gains recorded in OCI by $41.7 million.A hypothetical 100 basis point decrease in interest rates would decrease the fair value of interest rate swaps by $65.1 million, with a corresponding after-tax increase in unrealized losses recorded in OCI by $42.3 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 March 31, 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 March 31, 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 March 31, 2009.  Litigation is subject to numerous uncertainties and PSE is unable to predict the ultimate outcome of these matters.

Item 1A.           Risk Factors

As a holding company, Puget Energy depends on PSE’s ability to pay dividends. 

As a holding company with no significant operations of its own, the primary source of funds for the repayment of debt and other expenses, as well as payment of dividends to its shareholder, is cash dividends PSE pays to Puget Energy.  PSE is a separate and distinct legal entity and has no obligation to pay any amounts to Puget Energy, whether by dividends, loans or other payments.  The ability of PSE to pay dividends or make distributions to Puget Energy, and accordingly, Puget Energy’s ability to pay dividends or repay debt or other expenses, will depend on its earnings, capital requirements and general financial condition.  If Puget Energy does not receive adequate distributions from PSE, it may not be able to meet its obligations or pay dividends.

       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’s 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.

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:  June 11, 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 - March 31, 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.