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, 2012

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

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

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

Puget Energy, Inc. Yes /X/ No /  / Puget Sound Energy, Inc. Yes /X/ No /  /

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

Puget Energy, Inc. Yes /X/ No /  / Puget Sound Energy, Inc. Yes /X/ 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.

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

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

Puget Energy, Inc. Yes /  / No /X/ Puget Sound Energy, Inc. Yes /  / No /X/

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

Table of Contents

Definitions		Page
		3
Filing Format		4
Forward-Looking Statements		4
Part I.	Financial Statements
	Puget Energy, Inc.
	Consolidated Statements of Income – Three Months Ended March 31, 2012 and 2011	6
	Consolidated Statements of Comprehensive Income – Three Months Ended March 31, 2012 and 2011	7
	Consolidated Balance Sheets – March 31, 2012 and December 31, 2011	8
	Consolidated Statements of Cash Flows – Three Months Ended March 31, 2012 and 2011	10
	Puget Sound Energy, Inc.
	Consolidated Statements of Income – Three Months Ended March 31, 2012 and 2011	11
	Consolidated Statements of Comprehensive Income – Three Months Ended March 31, 2012 and 2011	12
	Consolidated Balance Sheets – March 31, 2012 and December 31, 2011	13
	Consolidated Statements of Cash Flows – Three Months Ended March 31, 2012 and 2011	15
	Notes
	Combined Notes to Consolidated Financial Statements	16
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Item 3.	Quantitative and Qualitative Disclosure About Market Risk	45
Item 4.	Controls and Procedures	48
Part II.	Other Information	49
Item 1.	Legal Proceedings	49
Item 1A.	Risk Factors	49
Item 6.	Exhibits	49
Signatures		50
Exhibit Index		51

2

DEFINITIONS

AFUDC	Allowance for Funds Used During Construction
ASC	Accounting Standards Codification
BPA	Bonneville Power Administration
EBITDA	Earnings Before Interest, Tax, Depreciation and Amortization
FERC	Federal Energy Regulatory Commission
GAAP	U.S. Generally Accepted Accounting Principles
IRP	Integrated Resource Plan
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
NPNS	Normal Purchase Normal Sale
OCI	Other Comprehensive Income
PCA	Power Cost Adjustment
PGA	Purchased Gas Adjustment
PSE	Puget Sound Energy, Inc.
Puget Energy	Puget Energy, Inc.
Puget Holdings	Puget Holdings LLC
PTC	Production Tax Credit
REC	Renewable Energy Credit
REP	Residential Exchange Program
SERP	Supplemental Executive Retirement Plan
Washington Commission	Washington Utilities and Transportation Commission

3

FILING FORMAT

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

FORWARD-LOOKING STATEMENTS

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

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

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

Ÿ	Governmental policies and regulatory actions, including those of the Federal Energy Regulatory Commission (FERC) and the Washington Utilities and Transportation Commission (Washington Commission), with respect to allowed rates of return, cost recovery, 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, natural gas and electric distribution and transmission facilities, licensing of hydroelectric operations and natural gas storage facilities, recovery of other capital investments, recovery of power and natural gas costs, recovery of regulatory assets, implementation of energy efficiency programs and present or prospective wholesale and retail competition;
Ÿ	Failure of PSE to comply with the FERC or the Washington Commission standards and/or rules, which could result in penalties based on the discretion of either commission;
Ÿ	Findings of noncompliance with electric reliability standards developed by the North American Electric Reliability Corporation (NERC) or the Western Electricity Coordinating Council for users, owners and operators of the power system, which could result in penalties;
Ÿ	Changes in, adoption of and compliance with laws and regulations, including decisions and policies concerning the environment, climate change, greenhouse gas or other emissions or byproducts of electric generation (including coal ash or other substances), natural resources, and fish and wildlife (including the Endangered Species Act) as well as the risk of litigation arising from such matters, whether involving public or private claimants or regulatory investigative or enforcement measures;
Ÿ	The ability to recover costs arising from changes in enacted federal, state or local tax laws in a timely manner;
Ÿ	Changes in tax law, related regulations or differing interpretation or enforcement of applicable law by the Internal Revenue Service (IRS) or other taxing jurisdictions;
Ÿ	Inability to realize deferred tax assets and use production tax credits (PTCs) due to insufficient future taxable income;
Ÿ	Accidents or natural disasters, such as hurricanes, windstorms, earthquakes, floods, fires and landslides, which can interrupt service and lead to lost revenue, cause temporary supply disruptions and/or price spikes in the cost of fuel and raw materials and impose extraordinary costs;
Ÿ	Commodity price risks associated with procuring natural gas and power in wholesale markets or counterparties extending credit to PSE without collateral posting requirements;
Ÿ	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;
Ÿ	Financial difficulties of other energy companies and related events, which may affect the regulatory and legislative process in unpredictable ways, adversely affect the availability of and access to capital and credit markets and/or impact delivery of energy to PSE from its suppliers;
Ÿ	The effect of wholesale market structures (including, but not limited to, regional market designs or transmission organizations) or other related federal initiatives;
Ÿ	PSE electric or natural gas distribution system failure, which may impact PSE’s ability to deliver energy supply to its customers;
Ÿ	Changes in climate or weather conditions in the Pacific Northwest, which could have effects on customer usage and PSE’s revenue and expenses;
Ÿ	Regional or national weather, which can have a potentially serious impact on PSE’s ability to procure adequate supplies of natural gas, fuel or purchased power to serve its customers and on the cost of procuring such supplies;
Ÿ	Variable hydrological conditions, which can impact streamflow and PSE’s ability to generate electricity from hydroelectric facilities;
Ÿ	Electric plant generation and transmission system outages, which can have an adverse impact on PSE’s expenses with respect to repair costs, added costs to replace energy or higher costs associated with dispatching a more expensive generation resource;
Ÿ	The ability of a natural gas or electric plant to operate as intended;
Ÿ	The ability to renew contracts for electric and natural gas supply and the price of renewal;
Ÿ	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;
Ÿ	The ability to restart generation following a regional transmission disruption;
Ÿ	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;
Ÿ	Industrial, commercial and residential growth and demographic patterns in the service territories of PSE;
Ÿ	General economic conditions in the Pacific Northwest, which may impact customer consumption or affect PSE’s accounts receivable;
Ÿ	The loss of significant customers, changes in the business of significant customers or the condemnation of PSE’s facilities, which may result in changes in demand for PSE’s services;
Ÿ	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;
Ÿ	The impact of acts of God, terrorism, flu pandemic or similar significant events;
Ÿ	Capital market conditions, including changes in the availability of capital and interest rate fluctuations;
Ÿ	Employee workforce factors, including strikes, work stoppages, availability of qualified employees or the loss of a key executive;
Ÿ	The ability to obtain insurance coverage and the cost of such insurance;
Ÿ	The ability to maintain effective internal controls over financial reporting and operational processes;
Ÿ	Changes in Puget Energy’s or PSE’s credit ratings, which may have an adverse impact on the availability and cost of capital for Puget Energy or PSE generally, or the failure to comply with the covenants in Puget Energy’s or PSE’s credit facilities, which would limit the Company’s ability to utilize such facilities for capital; and
Ÿ	Deteriorating values of the equity, fixed income and other markets which could significantly impact the value of investments of PSE’s retirement plan, post-retirement medical benefit plan trusts and the funding of obligations thereunder.

Any forward-looking statement speaks only as of the date on which such statement is made and except as required by law, the Company 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 the Company’s most recent Annual Report on Form 10-K.

4

PART I                    FINANCIAL INFORMATION

Item 1.                      Financial Statements

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands)

(Unaudited)

	Three Months Ended March 31,
	2012			2011
Operating revenue:
Electric	$	611,527		$	599,733
Gas	435,966			418,624
Other	1,019			1,236
Total operating revenue	1,048,512			1,019,593
Operating expenses:
Energy costs:
Purchased electricity	199,115			227,896
Electric generation fuel	69,937			45,223
Residential exchange	(23,335		)	(21,682		)
Purchased gas	233,519			236,754
Unrealized (gain) loss on derivative instruments, net	4,726			(33,119		)
Utility operations and maintenance	128,046			117,967
Non-utility expense and other	861			2,922
Depreciation	79,006			74,781
Amortization	13,343			17,973
Conservation amortization	34,402			32,213
Taxes other than income taxes	99,869			100,520
Total operating expenses	839,489			801,448
Operating income	209,023			218,145
Other income (deductions):
Other income	14,937			12,538
Other expense	(3,754		)	(954		)
Non-hedged interest rate derivative expense	527			(48		)
Interest charges:
AFUDC	7,295			4,404
Interest expense	(107,201		)	(81,048		)
Income (loss) before income taxes	120,827			153,037
Income tax (benefit) expense	32,347			45,606
Net income (loss)	$	88,480		$	107,431

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

5

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands)

(Unaudited)

	Three Months Ended March 31,
	2012			2011
Net income (loss)	$	88,480		$	107,431
Other comprehensive income (loss):
Reclassification of net unrealized loss on interest rate swaps during the period, net of tax of $1,350 and $2,279, respectively	2,508			4,233
Net unrealized loss from pension and postretirement plans, net of tax of $(58) and $(142)	(107		)	(262		)
Reclassification of net unrealized (gain) loss on energy derivative instruments, net of tax of $(105) and $101, respectively	(195		)	187
Other comprehensive income (loss)	2,206			4,158
Comprehensive income (loss)	$	90,686		$	111,589

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

6

PUGET ENERGY, INC. CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) ASSETS
	(Unaudited)
	March 31, 2012			December 31, 2011
Utility plant (including construction work in progress of $620,535 and $1,282,463 respectively):
Electric plant	$	6,187,458		$	6,067,672
Gas plant	2,274,653			2,238,741
Common plant	426,757			418,236
Less: Accumulated depreciation and amortization	(745,821		)	(674,782		)
Net utility plant	8,143,047			8,049,867
Other property and investments:
Goodwill	1,656,513			1,656,513
Investment in exchange power contract	18,515			19,396
Other property and investments	122,979			123,352
Total other property and investments	1,798,007			1,799,261
Current assets:
Cash and cash equivalents	70,464			37,235
Restricted cash	4,241			4,183
Accounts receivable, net of allowance for doubtful accounts of $8,760 and $8,495, respectively	325,416			336,530
Unbilled revenue	169,825			191,150
Materials and supplies, at average cost	84,588			76,068
Fuel and gas inventory, at average cost	76,903			100,491
Unrealized gain on derivative instruments	5,424			6,647
Income taxes	9,719			11,553
Prepaid expense and other	16,809			13,969
Power contract acquisition adjustment gain	46,153			65,096
Deferred income taxes	107,083			101,934
Total current assets	916,625			944,856
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes	64,022			62,304
Power cost adjustment mechanism	1,073			6,818
Regulatory assets related to power contracts	41,129			46,202
Other regulatory assets	811,546			766,825
Unrealized gain on derivative instruments	9,049			10,084
Power contract acquisition adjustment gain	499,263			517,740
Other	185,501			180,753
Total other long-term and regulatory assets	1,611,583			1,590,726
Total assets	$	12,469,262		$	12,384,710

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

PUGET ENERGY, INC. CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) CAPITALIZATION AND LIABILITIES
	(Unaudited)
	March 31, 2012			December 31, 2011
Capitalization:
Common shareholder’s equity:
Common stock $0.01 par value, 1,000 shares authorized, 200 shares outstanding	$	—		$	—
Additional paid-in capital	3,308,953			3,308,957
Earnings reinvested in the business	111,358			22,873
Accumulated other comprehensive income (loss), net of tax	(28,701		)	(30,907		)
Total common shareholder’s equity	3,391,610			3,300,923
Long-term debt:
First mortgage bonds and senior notes	3,362,000			3,362,000
Pollution control bonds	161,860			161,860
Junior subordinated notes	250,000			250,000
Long-term debt	1,809,000			1,793,000
Debt discount and other	(273,272		)	(289,493		)
Total long-term debt	5,309,588			5,277,367
Total capitalization	8,701,198			8,578,290
Current liabilities:
Accounts payable	241,700			339,361
Short-term debt	38,000			25,000
Purchased gas adjustment liability	56,150			25,940
Accrued expenses:
Taxes	104,604			90,727
Salaries and wages	26,019			40,892
Interest	70,821			69,329
Unrealized loss on derivative instruments	357,804			327,089
Power contract acquisition adjustment loss	4,201			8,547
Other	74,244			74,409
Total current liabilities	973,543			1,001,294
Long-term and regulatory liabilities:
Deferred income taxes	1,194,374			1,153,755
Unrealized loss on derivative instruments	162,546			196,558
Regulatory liabilities	363,362			346,225
Regulatory liabilities related to power contracts	545,416			582,836
Power contract acquisition adjustment loss	36,928			37,655
Other deferred credits	491,895			488,097
Total long-term and regulatory liabilities	2,794,521			2,805,126
Commitments and contingencies
Total capitalization and liabilities	$	12,469,262		$	12,384,710

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

7

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

	Three Months Ended March 31,
	2012			2011
Operating activities:
Net income (loss)	$	88,480		$	107,431
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation	79,006			74,781
Amortization	13,343			17,973
Conservation amortization	34,402			32,213
Deferred income taxes and tax credits, net	32,564			45,710
Net unrealized (gain) loss on derivative instruments	(5,136		)	(36,845		)
Pension funding	(5,700		)	(5,000		)
Derivative contracts classified as financing activities due to merger	36,621			97,684
AFUDC – Equity	(9,306		)	(3,734		)
Regulatory assets	(48,185		)	7,558
Regulatory liabilities	8,180			(12,900		)
Other long-term assets	(3,625		)	(30,820		)
Other long-term liabilities	28,666			12,670
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	32,439			26,416
Materials and supplies	(8,520		)	(4,483		)
Fuel and gas inventory	23,378			35,575
Income taxes	1,834			63,257
Prepayments and other	(2,840		)	(1,463		)
Purchased gas adjustment	30,210			8,750
Accounts payable	(68,073		)	(29,865		)
Taxes payable	13,877			15,550
Accrued expenses and other	1,989			(14,562		)
Net cash provided by operating activities	273,604			405,896
Investing activities:
Construction expenditures – excluding equity AFUDC	(185,634		)	(317,710		)
Energy efficiency expenditures	(22,657		)	(18,794		)
Restricted cash	(58		)	545
Other	(17,606		)	479
Net cash used in investing activities	(225,955		)	(335,480		)
Financing activities:
Change in short-term debt and leases, net	11,134			(120,400		)
Dividends paid	—			(58,167		)
Long-term notes and bonds issued	864,000			475,000
Redemption of bonds and notes	(848,000		)	(260,000		)
Derivative contracts classified as financing activities due to merger	(36,621		)	(97,684		)
Issuance cost of bonds and other	(4,933		)	(2,123		)
Net cash provided by (used in) financing activities	(14,420		)	(63,374		)
Net increase (decrease) in cash and cash equivalents	33,229			7,042
Cash and cash equivalents at beginning of period	37,235			36,557
Cash and cash equivalents at end of period	$	70,464		$	43,599
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	74,588		$	67,829
Cash payments (refunds) for income taxes	(1,898		)	(63,204		)

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

8

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands)

(Unaudited)

	Three Months Ended March 31,
	2012			2011
Operating revenue:
Electric	$	611,527		$	599,733
Gas	435,966			418,624
Other	1,019			1,236
Total operating revenue	1,048,512			1,019,593
Operating expenses:
Energy costs:
Purchased electricity	199,115			228,041
Electric generation fuel	69,937			45,223
Residential exchange	(23,335		)	(21,682		)
Purchased gas	233,519			236,754
Unrealized (gain) loss on derivative instruments, net	10,135			(5,984		)
Utility operations and maintenance	128,046			117,967
Non-utility expense and other	3,230			3,351
Depreciation	79,006			74,781
Amortization	13,343			17,973
Conservation amortization	34,402			32,213
Taxes other than income taxes	99,869			100,520
Total operating expenses	847,267			829,157
Operating income (loss)	201,245			190,436
Other income (deductions):
Other income	14,933			12,534
Other expense	(3,754		)	(954		)
Interest charges:
AFUDC	7,295			4,404
Interest expense	(60,737		)	(56,605		)
Interest expense on parent note	(51		)	(65		)
Income (loss) before income taxes	158,931			149,750
Income tax (benefit) expense	46,215			46,311
Net income (loss)	$	112,716		$	103,439

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

9

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands)

(Unaudited)

	Three Months Ended March 31,
	2012		2011
Net income (loss)	$	112,716	$	103,439
Other comprehensive income:
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $1,301 and $753, respectively	2,416		1,398
Reclassification of net unrealized loss on energy derivative instruments during the period, net of tax of $1,035 and $6,779, respectively	1,923		12,590
Amortization of financing cash flow hedge contracts to earnings, net of tax of $43 and $43, respectively	79		80
Other comprehensive income (loss)	4,418		14,068
Comprehensive income (loss)	$	117,134	$	117,507

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

10

PUGET SOUND ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

ASSETS

	(Unaudited)
	March 31, 2012			December 31, 2011
Utility plant (at original cost, including construction work in progress of $620,535 and $1,282,463 respectively):
Electric plant	$	8,507,919		$	8,390,667
Gas plant	2,890,909			2,855,794
Common plant	521,497			518,318
Less:  Accumulated depreciation and amortization	(3,777,278		)	(3,714,912		)
Net utility plant	8,143,047			8,049,867
Other property and investments:
Investment in exchange power contract	18,515			19,396
Other property and investments	113,156			113,528
Total other property and investments	131,671			132,924
Current assets:
Cash and cash equivalents	20,957			31,010
Restricted cash	4,241			4,183
Accounts receivable, net of allowance for doubtful accounts of $8,760 and $8,495, respectively	325,437			336,483
Unbilled revenue	169,825			191,150
Materials and supplies, at average cost	84,588			76,068
Fuel and gas inventory, at average cost	73,696			97,074
Unrealized gain on derivative instruments	5,424			6,647
Income taxes	9,719			11,553
Prepaid expense and other	16,647			13,807
Deferred income taxes	114,517			112,204
Total current assets	825,051			880,179
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes	63,045			61,344
Power cost adjustment mechanism	1,073			6,818
Other regulatory assets	806,377			760,585
Unrealized gain on derivative instruments	9,049			10,084
Other	183,758			183,746
Total other long-term and regulatory assets	1,063,302			1,022,577
Total assets	$	10,163,071		$	10,085,547

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

11

PUGET SOUND ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

CAPITALIZATION AND LIABILITIES

	(Unaudited)
	March 31, 2012			December 31, 2011
Capitalization:
Common shareholder’s equity:
Common stock $0.01 par value – 150,000,000 shares authorized, 85,903,791 shares outstanding	$	859		$	859
Additional paid-in capital	3,246,205			3,246,205
Earnings reinvested in the business	204,984			163,735
Accumulated other comprehensive income (loss), net of tax	(184,161		)	(188,579		)
Total common shareholder’s equity	3,267,887			3,222,220
Long-term debt:
First mortgage bonds and senior notes	3,362,000			3,362,000
Pollution control bonds	161,860			161,860
Junior subordinated notes	250,000			250,000
Debt discount	(15		)	(15		)
Total long-term debt	3,773,845			3,773,845
Total capitalization	7,041,732			6,996,065
Current liabilities:
Accounts payable	241,713			339,568
Short-term debt	38,000			25,000
Short-term note owed to parent	29,998			29,998
Purchased gas adjustment liability	56,150			25,940
Accrued expenses:
Taxes	104,604			90,727
Salaries and wages	26,019			40,892
Interest	56,963			55,843
Unrealized loss on derivative instruments	336,909			301,879
Other	70,549			68,346
Total current liabilities	960,905			978,193
Long-term and regulatory liabilities:
Deferred income taxes	1,168,462			1,115,639
Unrealized loss on derivative instruments	144,752			169,359
Regulatory liabilities	358,488			340,907
Other deferred credits	488,732			485,384
Total long-term and regulatory liabilities	2,160,434			2,111,289
Commitments and contingencies
Total capitalization and liabilities	$	10,163,071		$	10,085,547

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

12

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

	Three Months Ended March 31,
	2012			2011
Operating activities:
Net income (loss)	$	112,716		$	103,439
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation	79,006			74,781
Amortization	13,343			17,973
Conservation amortization	34,402			32,213
Deferred income taxes and tax credits, net	46,430			46,415
Net unrealized (gain) loss on derivative instruments	10,135			(5,984		)
Pension funding	(5,700		)	(5,000		)
AFUDC – Equity	(9,306		)	(3,734		)
Regulatory assets	(48,185		)	7,558
Regulatory liabilities	8,180			(12,900		)
Other long-term assets	(4,359		)	(33,989		)
Other long-term liabilities	15,118			6,176
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	32,371			26,418
Materials and supplies	(8,520		)	(4,483		)
Fuel and gas inventory	23,378			35,575
Income taxes	1,834			49,710
Prepayments and other	(2,840		)	(1,463		)
Purchased gas adjustment	30,210			8,750
Accounts payable	(68,267		)	(29,979		)
Taxes payable	13,877			15,550
Accrued expenses and other	(12,594		)	(17,201		)
Net cash provided by operating activities	261,229			309,825
Investing activities:
Construction expenditures – excluding equity AFUDC	(185,634		)	(317,710		)
Energy efficiency expenditures	(22,657		)	(18,794		)
Restricted cash	(58		)	545
Other	(3,417		)	1,944
Net cash used in investing activities	(211,766		)	(334,015		)
Financing activities:
Change in short-term debt and leases, net	11,134			(120,400		)
Dividends paid	(71,467		)	(74,619		)
Long-term notes and bonds issued	—			300,000
Loan from (payment to) parent	—			7,400
Redemption of bonds and notes	—			(260,000		)
Investment from parent	—			175,000
Issuance cost of bonds and other	817			(1,964		)
Net cash provided by (used in) financing activities	(59,516		)	25,417
Net increase (decrease) in cash and cash equivalents	(10,053		)	1,227
Cash and cash equivalents at beginning of period	31,010			36,320
Cash and cash equivalents at end of period	$	20,957		$	37,547
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	50,232		$	59,799
Cash payments (refunds) for income taxes	(1,898		)	(49,657		)

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

13

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) Summary of Significant Accounting Policies

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.  Following the merger with Puget Holdings LLC (Puget Holdings) on February 6, 2009, Puget Energy is an indirect wholly-owned subsidiary of Puget Holdings.

The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiary, PSE.  PSE’s consolidated financial statements include the accounts of PSE and its subsidiaries.  Puget Energy and PSE are collectively referred to herein as “the Company.”  The consolidated financial statements are presented after elimination of all significant intercompany items and transactions.  PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any purchase accounting adjustments.  Certain prior year amounts have been reclassified to conform to current year presentation.

The consolidated financial statements contained in this Form 10-Q are unaudited.  In the respective opinions of the management of Puget Energy and PSE, all adjustments necessary for a fair statement of the results for the interim periods have been reflected and were of a normal recurring nature.  These consolidated financial statements should be read in conjunction with the audited financial statements (and the Combined Notes thereto) included in the combined Puget Energy and PSE Annual Report on Form 10-K for the year ended December 31, 2011.

The preparation of financial statements in conformity with U.S. 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 revenue and expenses during the reporting period.  Actual results could differ from those estimates.

Revenue Recognition

Operating utility revenue is recognized when the basis of services is rendered, which includes estimated unbilled revenue. In March 2012, PSE changed its estimate of unbilled revenue from a calculation that is based on system load and billing information from its customers to a calculation using meter readings from its automated meter reading (AMR) system. The new estimate calculates unbilled usage at the end of each month as the difference between the customer meter readings on the last day of the month and the last customer meter readings billed. The unbilled usage is then priced at published rates for each schedule to estimate the unbilled revenues by customer.

Sales to other utilities are recognized in accordance with Accounting Standards Codification (ASC) 605, “Revenue Recognition” (ASC 605) and ASC 815, “Derivatives and Hedging” (ASC 815). Non-utility subsidiaries recognize revenue when services are performed or upon the sale of assets. Revenue from retail sales is billed based on tariff rates approved by the Washington Commission. Sales of RECs are deferred as a regulatory liability.

PSE collected Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes totaling $81.0 million and $80.3 million for the three months ended March 31, 2012 and 2011, respectively.  The Company reports such taxes on a gross basis in operating revenue and in taxes other than income taxes in the accompanying consolidated statements of income.

Accumulated Other Comprehensive Income (Loss)

The following tables present the components of the Company’s accumulated other comprehensive income (OCI) at March 31, 2012 and December 31, 2011:

Puget Energy (Dollars in Thousands)	March 31, 2012			December 31, 2011
Net unrealized loss on energy derivative instruments	$	(1,308	)	$	(1,113	)
Net unrealized loss on interest rate swaps	(12,091		)	(14,599		)
Net unrealized loss and prior service cost on pension plans	(15,302		)	(15,195		)
Total Puget Energy, net of tax	$	(28,701	)	$	(30,907	)

14

Puget Sound Energy (Dollars in Thousands)	March 31, 2012			December 31, 2011
Net unrealized loss on energy derivative instruments	$	(11,011	)	$	(12,934	)
Net unrealized loss on treasury interest rate swaps	(6,862		)	(6,941		)
Net unrealized loss and prior service cost on pension plans	(166,288		)	(168,704		)
Total PSE, net of tax	$	(184,161	)	$	(188,579	)

Statements of Cash Flows

The Company has refinancing transactions that do not result in an actual exchange of cash. For these transactions, the Company evaluates if the non-exchange of cash is for convenience purposes and if so, the Company considers the transaction as if it had constructively received and disbursed the cash and presents the transaction as gross on the financing section of the statements of cash flows.

(2) New Accounting Pronouncements

Intangibles - Goodwill and Other

On January 1, 2012, the Company adopted Accounting Standards Update (ASU) 2011-08, Intangibles - Goodwill and Other (Topic 350): Testing Goodwill for Impairment (ASU 2011-08).  ASU 2011-08 allows an entity the option to qualitatively assess whether it must perform the two-step goodwill impairment test in FASB ASC 350-20, Intangibles - Goodwill and Other. An entity has the option to qualitatively assess whether it is more likely than not (more than 50% likelihood) that the fair value of the reporting unit is less than its carrying amount.  If an entity elects to perform the qualitative assessment and determines that it is more likely than not that the reporting unit’s fair value is in excess of its carrying amount, no further evaluation is necessary.  Otherwise, an entity would perform Step 1 of the goodwill impairment test in ASC 350-20.

ASU 2011-08 was effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. ASU 2011-08 did not have a material impact on the financial reporting of the Company.

Comprehensive Income

On January 1, 2012, the Company adopted ASU 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income (ASU 2011-05). ASU 2011-05 allows an entity the option to present the total of comprehensive income, the components of net income, and the components of OCI either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In both choices, an entity is required to present each component of net income along with total net income, each component of OCI along with a total for OCI, and a total amount for comprehensive income. ASU 2011-05 eliminates the option to present the components of OCI as part of the statement of changes in stockholders' equity. The ASU also requires the presentation of reclassification adjustments for items that are reclassified from OCI to net income on the financial statements.  The amendments to the ASC in the ASU do not change the items that must be reported in OCI or when an item of OCI must be reclassified to net income.

ASU 2011-05 should be applied retrospectively, and was effective for fiscal years, and interim periods within those years, beginning after December 15, 2011.  The Company already complies with the presentation requirement, as the Company presents the total of comprehensive income, the components of net income, and the components of OCI in two separate statements.   ASU 2011-05 did not have an impact on the Company’s consolidated financial statements.

Fair Value Measurement

On January 1, 2012, the Company adopted ASU 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in GAAP and International Financial Reporting Standards (IFRS) (ASU 2011-04). ASU 2011-04 represents the converged guidance of the Financial Accounting Standards Board (FASB) and the International Accounting Standards Board on fair value measurement.  Many of the amendments to ASC 820, “Fair Value Measurements and Disclosures” (ASC 820), eliminate unnecessary wording differences between IFRS and GAAP. ASU 2011-04 expands ASC 820’s existing disclosure requirements for fair value measurements categorized in Level 3 by requiring (1) a quantitative disclosure of the unobservable inputs and assumptions used in the measurement, (2) a description of the valuation processes in place, and (3) a narrative description of the sensitivity of the fair value to changes in unobservable inputs and the interrelationships between those inputs.  In addition, ASU 2011-04 requires the Company to indicate the level in the fair value hierarchy of items that are not recorded at fair value but whose fair value must be disclosed.

Other amendments to ASC 820 include clarifying the highest and best use and valuation premise for nonfinancial assets, net risk position fair value measurement option for financial assets and liabilities with offsetting positions in market risks or counterparty credit risk, premiums and discounts in fair value measurement, and fair value of an instrument classified in a reporting entity’s shareholders’ equity.

ASU 2011-04 was effective for interim and annual periods beginning after December 15, 2011.  Adoption of ASU 2011-04 did not have a significant impact on the Company’s consolidated financial statements.

15

(3) Accounting for Derivative Instruments and Hedging Activities

PSE employs various portfolio optimization strategies, but is not in the business of assuming risk for the purpose of realizing speculative trading revenue. The nature of serving regulated electric customers with its 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 costs and margins 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 natural gas portfolios.

At the February 2009 merger date, Puget Energy de-designated its derivative contracts that were designated on PSE's books as NPNS or cash flow hedges and recorded such contracts at fair value as either assets or liabilities. Certain contracts meeting the criteria defined in ASC 815 were subsequently re-designated as NPNS or cash flow hedges.

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

The Company manages its interest rate risk through the issuance of mostly fixed-rate debt with varied maturities. The Company utilizes internal cash from operations, commercial paper, and credit facilities to meet short-term funding needs. Short-term obligations are commonly refinanced with fixed-rate bonds or notes when needed and when interest rates are considered favorable. The Company may enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts. As of March 31, 2012 Puget Energy had three interest rate swap contracts outstanding and PSE did not have any outstanding interest rate swap instruments.

In February 2009, Puget Energy entered into a cash flow hedge using interest rate swaps to hedge the risk associated with one-month LIBOR floating rate debt. Subsequently, in order to satisfy a commitment the Company made to the Washington Commission and to mitigate refinancing risk, the Company refinanced a portion of the underlying debt hedged by the interest rate swaps in 2010 and again during 2011. As a result of refinancing, the Company de-designated the cash flow hedge accounting relationship between the debt and interest rate swaps in 2010. On February 10, 2012, the Company terminated its previous term loan and capital expenditure credit facility (which originally acted as a portion of the underlying variable rate debt in the cash flow hedge) in favor of a new five year $1.0 billion revolving senior secured credit facility and used this new senior secured credit facility to pay off the remaining balance on the original term loan and capital expenditure credit facility. At March 31, 2012, the balance on the new senior secured credit facility was $859.0 million. In order to better align its existing swap notional with the new credit facility, the Company settled an additional $277.4 million of the interest rate swaps on February 15, 2012, thereby reducing the swap notional to $1.0 billion. The transaction did not impact the consolidated statements of income as the fair value losses for those swaps had already been recorded through earnings. Since replacing the previous term loan and capital expenditure credit facility with the new senior secured credit facility effectively replaced debt with like debt, the original hedged forecasted interest payments are still probable of occurring and there is no anticipated reclassification of existing amounts deferred in accumulated OCI to earnings as a result of this transaction. Therefore at March 31, 2012 the outstanding notional balance of the interest rate swaps was $1.0 billion, exceeding the balance of $859.0 million in variable rate debt of which the swaps are hedging. During the period in which the Company's interest rate swaps are in excess of the Company's variable rate debt, the Company will be subject to additional interest rate risk.

16

The following tables present the fair value and locations of the Company's derivative instruments recorded on the balance sheets at March 31, 2012 and December 31, 2011:

Derivatives Not Designated as Hedging Instruments
Puget Energy	March 31, 2012				December 31, 2011
(Dollars in Thousands)	Assets 1		Liabilities 2		Assets 1		Liabilities 2
Interest rate swaps:
Current	$	—	$	20,895	$	—	$	25,210
Long-term	—		17,794		—		27,199
Electric portfolio:
Current	3,597		193,421		5,212		173,582
Long-term	5,051		76,018		5,508		90,752
Natural gas portfolio: 3
Current	1,827		143,488		1,435		128,297
Long-term	3,998		68,734		4,576		78,607
Total derivatives	$	14,473	$	520,350	$	16,731	$	523,647

Derivatives Not Designated as Hedging Instruments
Puget Sound Energy	March 31, 2012				December 31, 2011
(Dollars in Thousands)	Assets 1		Liabilities 2		Assets 1		Liabilities 2
Electric portfolio:
Current	$	3,597	$	193,421	$	5,212	$	173,582
Long-term	5,051		76,018		5,508		90,752
Natural gas portfolio: 3
Current	1,827		143,488		1,435		128,297
Long-term	3,998		68,734		4,576		78,607
Total derivatives	$	14,473	$	481,661	$	16,731	$	471,238

___________

¹  Balance sheet location: Unrealized gain on derivative instruments.

²  Balance sheet location: Unrealized loss on derivative instruments.

³  PSE had a derivative liability and an offsetting regulatory asset of $206.4 million at March 31, 2012 and $200.9 million at December 31, 2011 related to financial contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers. All fair value adjustments on derivatives relating to the natural gas business have been reclassified to a deferred account in accordance with ASC 980 due to the PGA mechanism. All increases and decreases in the cost of natural gas supply are passed on to customers with the PGA mechanism and the gains and losses on the hedges in future periods will be recorded as gas costs.

For further details regarding the fair value of derivative instruments, see Note 4.

The following tables present the net unrealized (gain) loss of the Company's derivative instruments recorded on the statements of income for the three months ended March 31, 2012 and 2011:

Puget Energy	Three Months Ended March 31,
(Dollars in Thousands)	2012			2011
Natural gas / Power NPNS 1	$	(2,151	)	$	(8,050	)
Natural gas for power generation	(51		)	(41,523		)
Power	6,928			16,454
Total net unrealized (gain) loss on derivative instruments	$	4,726		$	(33,119	)
Interest expense – interest rate swaps	$	1,740		$	(1,926	)
Other deductions – interest rate swaps	$	(14,323	)	$	(1,800	)

___________

¹  Amount represents amortization expense related to contracts that were recorded at fair value as of the date of the merger.

17

Puget Sound Energy	Three Months Ended March 31,
(Dollars in Thousands)	2012			2011
Natural gas for power generation	$	(49	)	$	(24,678	)
Power	10,184			18,694
Total net unrealized (gain) loss on derivative instruments	$	10,135		$	(5,984	)

The following tables present the effect of hedging instruments on Puget Energy's OCI and statements of income, related to derivatives that were in a previous cash flow hedge relationship, for the three months ended March 31, 2012, and 2011:

Puget Energy (Dollars in Thousands)
Three Months Ended March 31
Derivatives in Cash Flow Hedging Relationships	Gain (Loss) Recognized  in OCI on Derivatives (Effective Portion 1)				Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion 2)
	2012		2011		Location	2012			2011
Interest rate contracts:	$	—	$	—	Interest expense	$	(3,859	)	$	(6,512	)
Commodity contracts: Electric derivatives	—		—		Electric generation fuel	100			(30		)
					Purchased electricity	200			(258		)
Total	$	—	$	—		$	(3,559	)	$	(6,800	)

___________

¹   Changes in OCI are reported in after-tax dollars.

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

The following table presents the effect of hedging instruments on PSE's OCI and statements of income for the three months ended March 31, 2012, and 2011:

Puget Sound Energy (Dollars in Thousands)
Three Months Ended March 31
Derivatives in Cash Flow Hedging Relationships	Gain (Loss) Recognized  in OCI on Derivatives  (Effective Portion 1)				Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion 2)
	2012		2011		Location	2012			2011
Interest rate contracts:	$	—	$	—	Interest expense	$	(122	)	$	(123	)
Commodity contracts: Electric derivatives	—		—		Electric generation fuel	97			(16,873		)
					Purchased electricity	(3,055		)	(2,496		)
Total	$	—	$	—		$	(3,080	)	$	(19,492	)

___________

¹  Changes in OCI are reported in after-tax dollars.

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

For derivative instruments that met cash flow hedge criteria, the effective portion of the gain or loss on the derivative was reported as a component of OCI, then reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. Puget Energy expects that $12.8 million of losses in OCI will be reclassified into earnings within the next twelve months. PSE expects that $12.7 million of losses in OCI will be reclassified into earnings within the next twelve months. The maximum length of time over which the Company is hedging its exposure to the variability in future cash flows extends to March 2015 for purchased electricity contracts, October 2018 for gas for power generation contracts and February 2014 for interest rate swaps.

18

The following tables present the effect of Puget Energy's derivatives not designated as hedging instruments on income during the three months ended March 31, 2012, and 2011:

Puget Energy		Three Months Ended March 31,
(Dollars in Thousands)	Location	2012			2011
Interest rate contracts:	Other deductions	$	527		$	(48	)
	Interest expense	(6,641		)	(4,577		)
Commodity contracts:
Electric derivatives	Unrealized gain (loss) on derivative instruments, net 1	$	(6,876	)	$	25,069
	Electric generation fuel	(22,993		)	(40,814		)
	Purchased electricity	(45,413		)	(14,672		)
Total gain (loss) recognized in     income on derivatives		$	(81,396	)	$	(35,042	)

___________

¹  Differs from the amounts stated in the statements of income as it does not include amortization expense related to contracts that were recorded at fair value at the time of the February 2009 merger and subsequently designated as NPNS of $2.2 million and $8.1 million for the three months ended March 31, 2012 and 2011 respectively.

Puget Sound Energy		Three Months Ended March 31,
(Dollars in Thousands)	Location	2012			2011
Commodity contracts:
Electric derivatives	Unrealized gain (loss) on derivative instruments, net	$	(10,135	)	$	5,984
	Electric generation fuel	(22,993		)	(40,814		)
	Purchased electricity	(45,413		)	(14,672		)
Total gain (loss) recognized in income on derivatives		$	(78,541	)	$	(49,502	)

The Company had the following outstanding interest rate and commodity contracts as of March 31, 2012:

Derivatives not designated as hedging instruments:	Number of Units
Puget Energy:
Interest rate swaps	$1.0 billion
Puget Energy and Puget Sound Energy:
Natural gas derivatives 1	490,052,220 MMBtus
Electric generation fuel	133,830,360  MMBtus
Purchased electricity	12,251,900      MWhs

__________

¹  Unrealized gains (losses) on naturalgas derivatives are offset by a regulatory asset or liability in accordance with ASC 980 due to the PGA mechanism.

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

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

It is possible that volatility in energy commodity prices could cause the Company to have material credit risk exposure with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company

19

could suffer a material financial loss. However, as of March 31, 2012, approximately 99.9% of the Company's energy portfolio exposure, excluding NPNS transactions, is with counterparties that are rated at least investment grade by the major rating agencies and 0.1% are either rated below investment grade or not rated by rating agencies. The Company assesses credit risk internally for counterparties that are not rated.

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

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

The Company applies the counterparty's default factor to compute credit reserves for counterparties that are in a net asset position. Moreover, the Company applies its own default factor to compute credit reserves for counterparties that are in a net liability position. Credit reserves are booked as contra accounts to unrealized gain (loss) positions. As of March 31, 2012, the Company was in a net liability position with the majority of counterparties, so the default factors of counterparties did not have a significant impact on reserves for the quarter. The majority of the Company's derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council. Despite its net liability position, PSE was not required to post any additional collateral with any of its counterparties. Additionally, PSE did not trigger any collateral requirements with any of its counterparties nor were any of PSE's counterparties required to post additional collateral resulting from credit rating downgrades.

As of March 31, 2012, the Company did not have any outstanding energy supply contracts with counterparties that contained credit risk related contingent features, which could result in a counterparty requesting immediate payment or demanding immediate and ongoing full overnight collateralization on derivative instruments in a net liability position.

The table below presents the fair value of the overall contractual contingent liability positions for the Company's derivative activity at March 31, 2012:

Puget Energy and Puget Sound Energy Contingent Feature (Dollars in Thousands)	Fair Value 1 Liability			Posted Collateral		Contingent Collateral
Credit rating 2	$	(52,462	)	$	—	$	52,462
Requested credit for adequate assurance	(90,291		)	—		—
Forward value of contract 3	(17,322		)	—		—
Total	$	(160,075	)	$	—	$	52,462

__________

¹  Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions at March 31, 2012. Excludes NPNS, accounts payable and accounts receivable.

²  Failure by PSE to maintain an investment grade credit rating from each of the major credit rating’s agencies provides counterparties a contractual right to demand collateral.

³  Collateral requirements may vary, based on changes in the forward value of underlying transactions relative to contractually defined collateral thresholds.

(4) Fair Value Measurements

GAAP established a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy categorizes the inputs into three levels with the highest priority given to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority given to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:

Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. 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.

20

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 reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. 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 have little or no observability as of the reporting date. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. If a fair value measurement relies on inputs from different levels of the hierarchy, the entire measurement must be placed based on the lowest level input that is significant to the fair value measurement. The Company primarily determines fair value measurements classified as Level 2 or Level 3 using a combination of the income and market valuation approaches and inputs as determined by the manager of derivatives accounting who reports to the assistant controller. On a daily basis, the Company obtains quoted forward prices for the electric and natural gas market from an independent external pricing service. These forward price quotes are used in addition to other various inputs to determine the reported fair value. Some of the inputs, which are not significant, include the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), assumptions for time value, and also the impact of the Company's nonperformance risk of its liabilities. For its interest rate swaps, the Company obtains monthly mark to market values from an independent external pricing service for LIBOR forward rates, which is a significant input. Some of the inputs of the interest rate swap valuations, which are not significant, include the credit standing of the counterparties, assumptions for time value and the impact of the Company's nonperformance risk of its liabilities. Cash equivalents and restricted cash classified as Level 2 fair value instruments consist of special money market funds and premium checking accounts. The Company valued Level 2 cash equivalents and restricted cash using the market approach based on the fair value of underlying investments at reporting date.

As of March 31, 2012, the Company considered the markets for its electric and natural gas commodity contracts and interest rate swaps as Level 2 derivative instruments, since such contracts are commonly traded as over-the-counter forwards with indirectly observable price quotes. However, certain energy derivative instruments are classified as Level 3 in the fair value hierarchy since Level 3 inputs are significant to the fair value measurement. Management's assessment was based on the trading activity volume in real-time and forward electric and natural gas markets. Each quarter, the Company confirms the validity of pricing service quoted prices (e.g., Level 2 in the fair value hierarchy) used to value commodity contracts with the actual prices of commodity contracts entered into during the most recent quarter.

21

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following tables present the Company's financial assets and liabilities by level, within the fair value hierarchy, that were accounted for at fair value on a recurring basis and the reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy as of March 31, 2012 and December 31, 2011:

Puget Energy	Fair Value Measurement								Fair Value Measurement
	At March 31, 2012								At December 31, 2011
(Dollars in Thousands)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	—	$	703	$	7,945	$	8,648	$	—	$	2,340	$	8,380	$	10,720
Natural gas derivative instruments	—		269		5,556		5,825		—		—		6,011		6,011
Cash equivalents	8,013		1,749		—		9,762		14,809		1,958		—		16,767
Restricted cash	1,967		630		—		2,597		2,043		735		—		2,778
Total assets	$	9,980	$	3,351	$	13,501	$	26,832	$	16,852	$	5,033	$	14,391	$	36,276
Liabilities:
Electric derivative instruments	$	—	$	154,130	$	115,309	$	269,439	$	—	$	165,643	$	98,691	$	264,334
Natural gas derivative instruments	—		203,499		8,723		212,222		—		195,852		11,052		206,904
Interest rate derivative instruments	—		38,689		—		38,689		—		52,409		—		52,409
Total liabilities	$	—	$	396,318	$	124,032	$	520,350	$	—	$	413,904	$	109,743	$	523,647

Puget Sound Energy	Fair Value Measurement at March 31, 2012								Fair Value Measurement at December 31, 2011
(Dollars in Thousands)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	—	$	703	$	7,945	$	8,648	$	—	$	2,340	$	8,380	$	10,720
Natural gas derivative instruments	—		269		5,556		5,825		—		—		6,011		6,011
Cash equivalents	6,900		1,749		—		8,649		9,200		1,958		—		11,158
Restricted cash	1,967		630		—		2,597		2,043		735		—		2,778
Total assets	$	8,867	$	3,351	$	13,501	$	25,719	$	11,243	$	5,033	$	14,391	$	30,667
Liabilities:
Electric derivative instruments	$	—	$	154,130	$	115,309	$	269,439	$	—	$	165,643	$	98,691	$	264,334
Natural gas derivative instruments	—		203,499		8,723		212,222		—		195,852		11,052		206,904
Total liabilities	$	—	$	357,629	$	124,032	$	481,661	$	—	$	361,495	$	109,743	$	471,238

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Puget Energy and Puget Sound Energy Level 3 Roll-Forward Net (Liability)	Three Months Ended March 31,
(Dollars in Thousands)	2012				2011
Balance at beginning of period	$	(95,352	)		$	(91,295	)
Changes during period:
Realized and unrealized energy derivatives
Included in earnings	(21,947		)	1	(15,707		)	2
Included in regulatory assets / liabilities	(1,283		)		1,119
Settlements 3	20,824				10,440
Transferred into Level 3	(16,874		)		—
Transferred out of Level 3	4,101				3,900
Balance at end of period	$	(110,531	)		$	(91,543	)

__________

¹  Includes unrealized gains (losses) on derivatives still held in position as of the reporting date for electric and natural gas derivatives of $(19.3) million and $2.7 million, respectively, for the three months ended March 31, 2012.

²  Includes unrealized gains (losses) on derivatives still held in position as of the reporting date for electric and natural gas derivatives of $(14.4) million and $1.1 million, respectively, for the three months ended March 31, 2011.

³  The Company had no purchases or issuances during the reported periods.

Realized gains and losses on energy derivatives for Level 3 recurring items are included in energy costs in the Company's consolidated statements of income under purchased electricity, electric generation fuel or purchased natural gas when settled. Unrealized gains and losses on energy derivatives for Level 3 recurring items are included in net unrealized (gain) loss on derivative instruments in the Company's consolidated statements of income.

In order to determine what assets and liabilities are classified as Level 3, the Company receives market data from its independent external pricing service defining the tenor of observable market quotes. To the extent any of the Company's commodity contracts extend beyond what is considered observable as defined by its independent pricing service, the contracts are classified as Level 3. The actual tenor of what the independent pricing service defines as observable is subject to change depending on market conditions. Therefore, as the market changes, the same contract may be designated Level 3 one month and Level 2 the next, and vice versa. These changes of fair value classification in Level 3 contracts are reported in the Level 3 Roll-forward table above as Transfers In/Out of Level 3 at the end of the quarter. The Company does periodically transact at locations, or market price points, that are illiquid and/or for which no prices are available from the independent pricing service. In such circumstances the Company uses a more liquid price point and performs a 15-month regression against the illiquid locations to serve as a proxy for market prices. Such transactions are classified as Level 3. The Company does not use internally developed models to make adjustments to significant unobservable pricing inputs. The only significant unobservable input into the fair value measurement of the Company's Level 3 assets and liabilities is the forward price for electric and natural gas contracts. Below are the forward price ranges during the period ended March 31, 2012.

	Valuation Technique	Low	High	Average
Electricity	Discounted cash flow	$13.75 per MWh	$75.75 per MWh	$44.67 per MWh
Natural gas	Discounted cash flow	$1.76 per MMBtu	$6.14 per MMBtu	$4.73 per MMBtu

Consequently significant increases or decreases in the forward prices of electricity or natural gas could result in a significantly higher or lower fair value for Level 3 assets and liabilities. At March 31, 2012, a hypothetical 10% increase or decrease in market prices of natural gas and electricity would change the fair value of the Company's derivative portfolio, classified as Level 3 within the fair value hierarchy, by $15.4 million.

The Company did not have any transfers between Level 2 and Level 1 during the three months ended March 31, 2012 or 2011.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

At the time of merger, Puget Energy recorded the fair value of its intangible assets in accordance with ASC 360, “Property, Plant, and Equipment,” (ASC 360). The fair value assigned to the power contracts was determined using an income approach comparing the contract rate to the market rate for power over the remaining period of the contracts incorporating nonperformance risk. Management also incorporated certain assumptions related to quantities and market presentation that it believes market participants would make in the valuation. The fair value of the power contracts is amortized as the contracts settle. ASC 360 requires long-lived assets to be tested for impairment on an on-going basis, whenever events or circumstances would more likely

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than not reduce the fair value of the long-lived assets below its carrying value. One such triggering event is a significant decrease in market price.

Puget Energy completed a valuation and impairment test as of March 31, 2012 for long-term power purchase contracts. The valuation indicated impairment to one of the purchased power contracts. As of March 31, 2012, the carrying value for the intangible asset contract was $113.3 million and its fair value on a discounted basis was determined to be $96.7 million thereby requiring a $16.6 million write-off of the intangible asset with a corresponding reduction in the regulatory liability.

The valuation was measured using the income approach. Significant inputs included forward electricity prices and power contract pricing which provided future net cash flow estimates which are classified as Level 3 within the fair value hierarchy. An insignificant input is the discount rate reflective of PSE's cost of capital used in the valuation. Below are the quarterly significant unobservable inputs during the period ended March 31, 2012.

(Dollars in Thousands)	Valuation Technique	Low	High	Average
Electricity	Discounted cash flow	$10.36 per MWh	$49.78 per MWh	$34.98 per MWh
Power contract costs	Discounted cash flow	$3,185	$5,030	$4,663
Net cash flows	Discounted cash flow	$(808)	$6,773	$3,985

(5) Estimated Fair Value of Financial Instruments

The following tables present the fair value hierarchy, carrying amounts and estimated fair value of the Company’s financial instruments at March 31, 2012 and December 31, 2011:

		March 31, 2012					December 31, 2011
Puget Energy (Dollars in Thousands)	Fair Value Hierarchy	Carrying Amount			Fair Value		Carrying Amount		Fair Value
Assets:
Cash	1	$	60,702	60,702,000	$	60,702	$	20,468	$	20,468
Cash equivalents	*1	9,762		9,762,000	9,762		16,767		16,767
Restricted cash	1	3,611		3,611,000	3,611		3,448		3,448
Restricted cash	*1	630		630,000	630		735		735
Notes receivable and other	2	72,744			72,744		73,031		73,031
Electric derivatives	*2	8,648			8,648		10,720		10,720
Natural gas derivatives	*2	5,825			5,825		6,011		6,011
Liabilities:
Short-term debt	2	$	38,000		$	38,000	$	25,000	$	25,000
Junior subordinated notes	2	250,000			248,624		250,000		248,583
Long-term debt (fixed-rate), net of discount	2	4,200,588			5,425,996		4,197,511		5,503,571
Long-term debt (variable-rate), net of discount	2	859,000			859,000		829,856		856,978
Electric derivatives	*2	269,439			269,439		264,334		264,334
Natural gas derivatives	*2	212,222			212,222		206,904		206,904
Interest rate derivatives	*2	38,689			38,689		52,409		52,409

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			March 31, 2012				December 31, 2011
Puget Sound Energy (Dollars in Thousands)	Fair Value Hierarchy		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Assets:
Cash	1		$	12,308	$	12,308	$	19,852	$	19,852
Cash equivalents	*1	8,649	8,649		8,649		11,158		11,158
Restricted cash	1	3,611	3,611		3,611		3,448		3,448
Restricted cash	*1	630	630		630		735		735
Notes receivable and other	2		72,744		72,744		73,031		73,031
Electric derivatives	*2		8,648		8,648		10,720		10,720
Natural gas derivatives	*2		5,825		5,825		6,011		6,011
Liabilities:
Short-term debt	2		$	38,000	$	38,000	$	25,000	$	25,000
Short-term debt owed by PSE to Puget Energy3	2		29,998		29,998		29,998		29,998
Junior subordinated notes	2		250,000		248,624		250,000		248,583
Long-term debt (fixed-rate)	2		3,523,845		4,397,854		3,523,845		4,499,295
Electric derivatives	*2		269,439		269,439		264,334		264,334
Natural gas derivatives	*2		212,222		212,222		206,904		206,904

___________

¹  For cash equivalents and restricted cash fair value hierarchies see Note 4, Fair Value Measurements.

²  For derivative fair value hierarchies see Note 4, Fair Value Measurements.

³  Short-term debt owed by PSE to Puget Energy is eliminated upon consolidation of Puget Energy.

The carrying amount of cash, which includes temporary investments with original maturities of three months or less, is also considered to be a reasonable estimate of market fair value. The carrying values of short-term debt and notes receivable are considered to be a reasonable estimate of fair value.  The fair value of the junior subordinated and long-term notes were estimated using the discounted cash flow method with U.S. Treasury yields and Company credit spreads as inputs, interpolating to the maturity date of each issue.  

(6) Retirement Benefits

PSE has a defined benefit pension plan covering substantially all PSE employees.  Pension benefits earned are a function of age, salary, years of service and, in the case of employees in the cash balance formula plan, the applicable annual interest crediting rates.  PSE also maintains a non-qualified Supplemental Executive Retirement Plan (SERP) for its key senior management employees.  In addition to providing pension benefits, PSE provides group health care and life insurance benefits for certain retired employees.  These benefits are provided principally through an insurance company.  The insurance premiums, paid primarily by retirees, are based on the benefits provided during the year.

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

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The following tables summarize the Company’s net periodic benefit cost for the three months ended March 31, 2012 and 2011:

Puget Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
	Three Months Ended March 31,						Three Months Ended March 31,				Three Months Ended March 31,
(Dollars in Thousands)	2012			2011			2012		2011		2012			2011
Components of net periodic benefit cost:
Service cost	$	4,235		$	4,059		$	268	$	310	$	38		$	31
Interest cost	6,442			6,630			538		548		187			204
Expected return on plan assets	(9,001		)	(8,860		)	—		—		(108		)	(125		)
Amortization of prior service cost	(495		)	(495		)	—		—		—			—
Amortization of net loss (gain)	149			—			176		90		9			1
Net periodic benefit cost	$	1,330		$	1,334		$	982	$	948	$	126		$	111

Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
	Three Months Ended March 31,						Three Months Ended March 31,				Three Months Ended March 31,
(Dollars in Thousands)	2012			2011			2012		2011		2012			2011
Components of net periodic benefit cost:
Service cost	$	4,235		$	4,059		$	268	$	310	$	38		$	31
Interest cost	6,442			6,630			538		548		188			204
Expected return on plan assets	(10,333		)	(11,056		)	—		—		(109		)	(125		)
Amortization of prior service cost	(393		)	(393		)	73		141		9			16
Amortization of net loss (gain)	3,717			2,694			358		298		(60		)	(109		)
Amortization of transition obligation	—			—			—		—		12			13
Net periodic benefit cost	$	3,668		$	1,934		$	1,237	$	1,297	$	78		$	30

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The following table summarizes the Company’s change in benefit obligation for the periods ended March 31, 2012 and December 31, 2011:

Puget Energy and Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
	Three Months Ended			Year Ended			Three Months Ended			Year Ended			Three Months Ended			Year Ended
(Dollars in Thousands)	March 31, 2012			December 31, 2011			March 31, 2012			December 31, 2011			March 31, 2012			December 31, 2011
Change in benefit obligation:
Benefit obligation at beginning of period	$	565,997		$	532,615		$	48,370		$	44,322		$	16,436		$	16,579
Service cost	4,234			15,822			269			1,241			38			113
Interest cost	6,442			26,263			538			2,192			188			807
Actuarial loss	—			18,485			—			4,467			—			384
Benefits paid	(11,775		)	(27,188		)	(3,824		)	(2,687		)	(440		)	(1,855		)
Medicare part D subsidiary received	—			—			—			—			—			408
Curtailment loss/(gain)1	$	—		—			$	—		(1,165		)	$	—		—
Benefit obligation at end of period	$	564,898		$	565,997		$	45,353		$	48,370		$	16,222		$	16,436

__________

¹  A curtailment gain was recognized in OCI due to the plan amendment that ceased SERP benefits for non-officers still in the plan as of December 31, 2011.

The fair value of the Company’s pension plan assets was $516.1 million and $479.8 million at March 31, 2012 and December 31, 2011, respectively.

The aggregate expected contributions by the Company to fund the retirement plan, SERP and the other postretirement plans for the year ending December 31, 2012 are expected to be at least $22.8 million, $6.1 million and $0.9 million, respectively. During the three months ended March 31, 2012, the Company contributed $5.7 million, $3.8 million and $0.4 million to fund the qualified retirement plan, SERP and the other postretirement plan, respectively.  

(7) Regulation and Rates

On January 6, 2012, PSE filed an electric transmission rate case with FERC as well as an increase in ancillary service charges. PSE requested a rate increase of $3.8 million with an effective date of April 1, 2012. On March 30, 2012, FERC issued an order setting for hearing PSE's formula transmission rate filing. PSE's proposed reclassification of facilities and formula rate for network and point-to-point service on the Washington Area Facilities have been suspended for five months until September 1, 2012. PSE's proposed formula rate decrease for service on the Colstrip and Southern Intertie lines have been accepted and placed into effect April 1, 2012 subject to refund if rates should be lower. The initial settlement conference is scheduled for May 2012.     

On February 29, 2012, PSE filed to increase the amount of the credit being passed back to customers in Schedule 95a, the Federal Incentive Tracker, by $2.4 million. PSE's proposed rate change seeks to include interest on the unamortized balance of United States Treasury Department grants (Treasury Grant) received on February 23, 2010, under Section 1603 of the American Recovery and Reinvestment Act of 2009. Inclusion of interest in rates became possible with the passage of the newly enacted National Defense Authorization Act for Fiscal Year 2012 (NDAA) which eliminated the requirement for utilities to normalize the Section 1603 Treasury Grant. PSE applied the interest beginning January 1, 2012. Washington Commission Staff seeks to include interest calculated from the date the Treasury Grant was received, February 2010. At the March 29, 2012 open meeting, the Washington Commission requested legal briefing of the issues. The Washington Commission recessed the matter until its May 24, 2012 open meeting.     

On May 7, 2012, the Washington Commission issued its order in PSE's consolidated electric and natural gas general rate case filed in June 2011, approving a general rate increase for electric customers of $63.3 million or 3.2% annually, and an increase in natural gas rates of $13.4 million or 1.3% annually. The rate increases for electric and natural gas customers will be effective May 14, 2012. In its order, the Washington Commission approved a weighted cost of capital of 7.8% and a capital structure that included 48.0% common equity with a return on equity of 9.80%.

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(8) Litigation

Residential Exchange. The Northwest Power Act, through the Residential Exchange Program (REP), provides access to the benefits of low-cost federal hydroelectric power to residential and small farm customers of regional utilities, including PSE. The program is administered by the Bonneville Power Administration (the BPA). Pursuant to agreements (including settlement agreements) between the BPA and PSE, the BPA has provided payments of REP benefits to PSE, which PSE has passed through to its residential and small farm customers in the form of electricity bill credits.

In 2007, the U.S. Court of Appeals for the Ninth Circuit ruled that REP agreements of the BPA with PSE and a number of other investor-owned utilities were inconsistent with the Northwest Power Act. Since that time, those investor-owned utilities, including PSE, the BPA and other parties have been involved in ongoing litigation at the Ninth Circuit relating to the amount of REP benefits paid to utilities, including PSE, for the period fiscal year 2002 through fiscal year 2011 and the amount of REP benefits to be paid going forward.

In July 2011, the BPA, PSE and a number of other parties entered into a settlement agreement that by its terms if upheld in their entirety would resolve the disputes between BPA and PSE regarding REP benefits paid for the period fiscal year 2002-fiscal year 2011. In October 2011, certain other parties challenged BPA decisions with regard to its entering into this most recent settlement agreement. Pending disposition of this challenge, the other pending Ninth Circuit litigation regarding REP benefits for the period fiscal year 2002 through fiscal year 2011 has been stayed by the Ninth Circuit.

Due to the pending and ongoing proceedings, PSE is unable to reasonably estimate any amounts of REP payments - either to be recovered by the BPA or to be paid for any future periods to PSE - and is unable to determine the impact, if any, these proceedings and litigation may have on PSE. However, the Company believes it is unlikely that any unfavorable outcome would have a material adverse effect on PSE because REP benefits received by PSE are passed through to PSE's residential and small farm customers.

Pacific Northwest Refund Proceeding. In October 2000, PSE filed a complaint with the FERC (Docket No. EL01-10) against “all jurisdictional sellers” in the Pacific Northwest seeking prospective price caps consistent with any result the FERC ordered for the California markets. The FERC issued an order including price caps in July 2001, and PSE moved to dismiss the proceeding. In response to PSE's motion, various entities intervened and sought to convert PSE's complaint into one seeking retroactive refunds in the Pacific Northwest. The FERC rejected that effort, after holding what the FERC referred to as a “preliminary evidentiary hearing” before an administrative law judge. On October 3, 2011, after appellate reviews, the FERC issued an Order on Remand and set the matter for hearing before an administrative law judge, but first requiring the parties to engage in settlement talks that began in the fall of 2011 and are ongoing. As such, the hearing date itself is not known. PSE has not taken any reserve on this matter as it believes it has no exposure, and intends to vigorously defend its position but is unable to predict the outcome of this matter.

Other Proceedings. The Company is also involved in litigation relating to claims arising out of its operations in the normal course of business. The Company has recorded reserves of $3.5 million and $2.8 million relating to these claims as of March 31, 2012 and 2011, respectively.

(9) Other

Allowance for Funds Used During Construction (AFUDC).  AFUDC represents the cost of both debt and equity funds used to finance utility plant additions during the construction period.  The amount of AFUDC recorded in each accounting period varies depending principally upon the level of construction work in progress and the AFUDC rate used.  AFUDC is capitalized as a part of the cost of utility plant and is credited to interest expense and as a non-cash item to other income.  Cash inflow related to AFUDC does not occur until these charges are reflected in rates.

The AFUDC rates authorized by the Washington Commission for natural gas and electric utility plant additions is 8.1% which was effective April 8, 2010.    

The Washington Commission authorized the Company to calculate AFUDC using its allowed rate of return.  To the extent amounts calculated using this rate exceed the AFUDC calculated rate using the FERC formula, PSE capitalizes the excess as a deferred asset, crediting other income.  The deferred asset is amortized over the average useful life of PSE’s non-project electric utility plant, which is approximately 30 years.

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The following table presents the Company’s AFUDC amounts:

	Three Months Ended March 31,
(Dollars in Thousands)	2012		2011
Equity AFUDC	$	9,306	$	3,734
Washington Commission AFUDC	141		3,905
Total in other income	9,447		7,639
Debt AFUDC	7,295		4,404
Total AFUDC	$	16,742	$	12,043

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

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

Overview

Puget Energy is an energy services holding company and all of its operations are conducted through its subsidiary PSE, a regulated electric and natural gas utility company. PSE is the largest electric and natural gas utility in the state of Washington, primarily engaged in the business of electric transmission, distribution and generation and natural gas distribution. Puget Energy's business strategy is to generate stable cash flows by offering reliable electric and natural gas service in a cost-effective manner through PSE. On February 6, 2009, Puget Holdings completed its merger with Puget Energy. Puget Holdings is a consortium of long-term infrastructure investors including Macquarie Infrastructure Partners I, Macquarie Infrastructure Partners II, Macquarie Capital Group Limited, Macquarie-FSS Infrastructure Trust, the Canada Pension Plan Investment Board (CPPIB), the British Columbia Investment Management Corporation, and the Alberta Investment Management Corporation. As a result of the merger, all of Puget Energy's common stock is indirectly owned by Puget Holdings. Puget Energy accounted for the merger as a business combination and all its assets and liabilities were recorded at fair value as of the merger date. PSE's basis of accounting continues to be on a historical basis and PSE's financial statements do not include any purchase accounting adjustments. Puget Energy and PSE are collectively referred to herein as “the Company.”

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

For the three months ended March 31, 2012 as compared to the same periods in 2011, PSE's net income was affected by the following three factors: (1) an increase in natural gas retail sales (2) lower power costs as a result of it being more economical to generate energy from PSE's combustion turbine facilities than to purchase wholesale energy; and (3) increase in utility operations

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and maintenance primarily due to an increase in storm related expenses.

For the three months ended March 31, 2012 as compared to the same period in 2011, Puget Energy's net income was affected by PSE as noted above and the following factors: (1) increase in interest expense on Puget Energy debt due to write-off of unamortized debt costs, mark-to-market on interest rate swap contracts and higher interest costs; and (2) lower gain on energy derivative instruments due to purchase accounting.

Further detail on each of these primary drivers, as well as other factors affecting performance, is set forth in this “Overview” section, as well as in other sections of the Management's Discussion & Analysis.

Factors and Trends Affecting PSE's Performance. PSE's regulatory requirements and operational needs require the investment of substantial capital in 2012 and future years. Because PSE intends to seek recovery of such investments through the regulatory process, its financial results depend heavily upon favorable outcomes from that process. Further, PSE's financial performance is heavily influenced by general economic conditions in its service territory, which affect customer growth and use-per-customer and thus utility sales, as well as by its customers' conservation investments, which also tend to reduce energy sales. The principal business, economic and other factors that affect PSE's operations and financial performance include:

Ÿ	The rates PSE is allowed to charge for its services;
Ÿ	PSE’s ability to recover fixed costs that are included in rates which are based on volume;
Ÿ	Weather conditions, including snow-pack affecting hydrological conditions;
Ÿ	Demand for electricity and natural gas among customers in PSE’s service territory;
Ÿ	Regulatory decisions allowing PSE to recover costs, including purchased power and fuel costs, on a timely basis;
Ÿ	PSE’s ability to supply electricity and natural gas, either through company-owned generation, purchase power contracts or by procuring natural gas or electricity in wholesale markets;
Ÿ	Availability and access to capital and the cost of capital;
Ÿ	Regulatory compliance costs, including those related to new and developing federal regulations of electric system reliability, state regulations of natural gas pipelines and federal, state and local environmental laws and regulations;
Ÿ	The impact of energy efficiency programs on sales and margins;
Ÿ	Wholesale commodity prices of electricity and natural gas;
Ÿ	Increasing depreciation and related property taxes; and
Ÿ	Federal, state, and local taxes.

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

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Electric Rates

PSE has a Power Cost Adjustment (PCA) mechanism that provides for the recovery of power costs from customers or refunding of power cost savings to customers in the event those costs vary from the “power cost baseline” level of power costs. The “power cost baseline” levels are set, in part, based on normalized assumptions about weather and hydroelectric conditions. Excess power costs or power cost savings are apportioned between PSE and its customers pursuant to the graduated scale set forth in the PCA mechanism.

The graduated scale is as follows:

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

PSE had a favorable PCA imbalance for the three months ended March 31, 2012, which was $31.6 million below the “power cost baseline” level, $5.8 million of which was apportioned to customers. This compares to a favorable imbalance of $6.4 million for the three months ended March 31, 2011, $1.0 million of which was apportioned to customers.    

On January 6, 2012, PSE filed an electric transmission rate case with FERC as well as an increase in ancillary service charges. PSE requested a rate increase of $3.8 million with an effective date of April 1, 2012. On March 30, 2012, FERC issued an order setting for hearing PSE's formula transmission rate filing. PSE's proposed reclassification of facilities and formula rate for network and point-to-point service on the Washington Area Facilities have been suspended for five months until September 1, 2012. PSE's proposed formula rate decrease for service on the Colstrip and Southern Intertie lines have been accepted and placed into effect April 1, 2012 subject to refund if rates should be lower. The initial settlement conference is scheduled for May 2012.

On February 29, 2012, PSE filed to increase the amount of the credit being passed back to customers in Schedule 95a, the Federal Incentive Tracker, by $2.4 million. PSE's proposed rate change seeks to include interest on the unamortized balance of United States Treasury Department grants (Treasury Grant) received on February 23, 2010, under Section 1603 of the American Recovery and Reinvestment Act of 2009. Inclusion of interest in rates became possible with the passage of the newly enacted National Defense Authorization Act for Fiscal Year 2012 (NDAA) which eliminated the requirement for utilities to normalize the Section 1603 Treasury Grant. PSE applied the interest beginning January 1, 2012. Washington Commission Staff seeks to include interest calculated from the date the Treasury Grant was received, February 2010. At the March 29, 2012 open meeting, the Washington Commission requested legal briefing of the issues. The Washington Commission recessed the matter until its May 24, 2012 open meeting.

On May 7, 2012, the Washington Commission issued its order in PSE's electric general rate case filed in June 2011, approving a general rate increase for electric customers of $63.3 million or 3.2% annually. The rate increases for electric customers will be effective May 14, 2012. In its order, the Washington Commission approved a weighted cost of capital of 7.8% and a capital structure that included 48.0% common equity with a return on equity of 9.8%.

Natural Gas Rates

PSE has a PGA mechanism in retail natural gas rates to recover variations in natural gas supply and transportation costs. Variations in natural gas rates are passed through to customers; therefore, PSE's net income is not affected by such variations. Changes in the PGA rates affect PSE's revenue, but do not impact net income as the changes to revenue are offset by increased or decreased purchased gas and gas transportation costs. The following table sets forth natural gas rate adjustments approved by the Washington Commission and the corresponding impact to PSE's annual revenue based on the effective dates:

Type of Rate Adjustment	Effective Date	Average Percentage Increase (Decrease) in Rates		Annual Increase (Decrease) in Revenue (Dollars in Millions)
Purchased Gas Adjustment	November 1, 2011	(4.3	)%	$	(43.5	)
Natural Gas General Tariff Adjustment	April 1, 2011	1.8		19.0

On May 7, 2012, the Washington Commission issued its order in PSE's natural gas general rate case filed in June 2011, approving a general rate increase for natural gas customers of $13.4 million or 1.3% annually. The rate increases for natural gas customers will be effective May 14, 2012. In its order, the Washington Commission approved a weighted cost of capital of 7.8% and a capital structure that included 48.0% common equity with a return on equity of 9.8%.

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Weather Conditions. Weather conditions in PSE's service territory have a significant impact on customer energy usage, affecting PSE's revenue and energy supply expenses. PSE's operating revenue and associated energy supply expenses are not generated evenly throughout the year. While both PSE's electric and natural gas sales are generally greatest during winter months, variations in energy usage by customers occur from season to season and month to month within a season, primarily as a result of weather conditions. PSE normally experiences its highest retail energy sales, and subsequently higher power costs, during the winter heating season in the first and fourth quarters of the year and its lowest sales in the third quarter of the year. Varying wholesale electric prices and the amount of hydroelectric energy supplies available to PSE also make quarter-to-quarter comparisons difficult. PSE reported slightly higher customer usage in the three months ended March 31, 2012 primarily due to Pacific Northwest temperatures being cooler in January and March.

Customer Demand. PSE expects the number of natural gas customers to grow at rates slightly above electric customers. PSE also expects energy usage by both residential electric and natural gas customers to continue a long-term trend of slow decline due to continued energy efficiency improvements and the effect of higher retail rates.

Access to Debt Capital. PSE relies on access to bank borrowings and short-term money markets as sources of liquidity and longer-term debt markets to fund its utility construction program, to meet maturing debt obligations and other capital expenditure requirements not satisfied by cash flow from its operations or equity investment from its parent, Puget Energy. Neither Puget Energy nor PSE have any debt outstanding whose maturity would accelerate upon a credit rating downgrade. However, a ratings downgrade could adversely affect the Company's 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 fees increase as their respective credit ratings decline. If PSE is unable to access debt capital on reasonable terms, its ability to pursue improvements or acquisitions, including generating capacity, which may be relied on for future growth and to otherwise implement its strategy, could be adversely affected. PSE monitors the credit environment and expects to continue to be able to access the capital markets to meet its short-term and long-term borrowing needs. PSE's credit facilities expire in 2014 and Puget Energy's senior secured credit facility expires in 2017. (See discussion on credit facilities in “Financing Program” section.)

Regulatory Compliance Costs and Expenditures. PSE's operations are subject to extensive federal, state and local laws and regulations. Such regulations cover electric system reliability, gas pipeline system safety and energy market transparency, among other areas. Environmental laws and regulations related to air and water quality, including climate change and endangered species protection, waste handling and disposal (including generation byproducts such as coal ash), remediation of contamination and siting new facilities also impact the Company's operations. PSE must spend significant amounts to fulfill requirements set by regulatory agencies, many of which have greatly expanded mandates, and on measures including, but not limited to, resource planning, remediation, monitoring, pollution control equipment and emissions-related abatement and fees in order to comply with these regulatory requirements.

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

Other Challenges and Strategies

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

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

Operational Risks Associated With Generating Facilities. PSE owns and operates coal, natural gas-fired, hydroelectric, wind-powered, solar and oil-fired generating facilities. Operation of electric generating facilities involves risks that can adversely affect energy output and efficiency levels, including facility shutdowns due to equipment and process failures or fuel supply interruptions. PSE does not have business interruption insurance coverage to cover replacement power costs.

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

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

Results of Operations

Puget Sound Energy

The following discussion should be read in conjunction with the unaudited consolidated financial statements and the related notes included elsewhere in this document. The following discussion provides the significant items that impacted PSE's results of operations for the three months ended March 31, 2012 and 2011. Set forth below is the consolidated financial results of PSE for the three months ended March 31, 2012 and 2011:

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	Three Months Ended March 31,
Puget Sound Energy (Dollars in Thousands)	2012			2011			Favorable/ (Unfavorable)
Operating revenue:
Electric
Residential sales	$	362,479		$	369,316		(1.9	)%
Commercial sales	230,193			230,484			(0.1	)%
Industrial sales	27,952			27,494			1.7	%
Other retail sales, including unbilled revenue	(15,130		)	(22,813		)	33.7	%
Total retail sales	605,494			604,481			0.2	%
Transportation sales	2,472			2,541			(2.7	)%
Sales to other utilities and marketers	7,046			8,948			(21.3	)%
Other	(3,485		)	(16,237		)	78.5	%
Total electric operating revenue	611,527			599,733			2.0	%
Gas
Residential sales	296,795			281,615			5.4	%
Commercial sales	120,880			118,569			1.9	%
Industrial sales	10,886			11,075			(1.7	)%
Total retail sales	428,561			411,259			4.2	%
Transportation sales	3,921			3,726			5.2	%
Other	3,484			3,639			(4.3	)%
Total gas operating revenue	435,966			418,624			4.1	%
Non-utility operating revenue	1,019			1,236			(17.6	)%
Total operating revenue	1,048,512			1,019,593			2.8	%
Operating expenses:
Energy costs:
Purchased electricity	199,115			228,041			12.7	%
Electric generation fuel	69,937			45,223			(54.6	)%
Residential exchange	(23,335		)	(21,682		)	7.6	%
Purchased gas	233,519			236,754			1.4	%
Net unrealized (gain) loss on derivative instruments	10,135			(5,984		)	*
Utility operations and maintenance	128,046			117,967			(8.5	)%
Non-utility expense and other	3,230			3,351			3.6	%
Depreciation	79,006			74,781			(5.6	)%
Amortization	13,343			17,973			25.8	%
Conservation amortization	34,402			32,213			(6.8	)%
Taxes other than income taxes	99,869			100,520			0.6	%
Total operating expenses	847,267			829,157			(2.2	)%
Operating income (loss)	201,245			190,436			5.7	%
Other income	14,933			12,534			19.1	%
Other expense	(3,754		)	(954		)	*
Interest expense	(53,493		)	(52,266		)	(2.3	)%
Income (loss) before income taxes	158,931			149,750			6.1	%
Income tax (benefit) expense	46,215			46,311			0.2	%
Net income (loss)	$	112,716		$	103,439		9.0	%

__________

^*Not meaningful

NON-GAAP FINANCIAL MEASURES - Electric and Gas Margins

The following discussion includes financial information prepared in accordance with U.S. Generally Accepted Accounting Principles (GAAP), as well as two other financial measures, electric margin and gas margin, that are considered “non-GAAP

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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 an 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. PSE'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

Electric Margin

The following table displays the details of PSE's electric margin changes for the three months ended March 31, 2012 as compared to the same period in 2011. Electric margin represents 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.

	Three Months Ended March 31,
Electric Margin (Dollars in Thousands)	2012			2011			Percent Change
Electric operating revenue1	$	611,527		$	599,733		2.0	%
Add (less): Other electric operating revenue	3,484			16,238			(78.5	)
Less: Other electric operating revenue-gas supply resale	(3,198		)	(32,669		)	(90.2	)
Add (less): Other electric operating revenue-RECs & PTCs	(10,345		)	6,612			*
Total electric revenue for margin	601,468			589,914			2.0
Adjustments for amounts included in revenue:
Pass-through tariff items	(29,377		)	(29,612		)	(0.8	)
Pass-through revenue-sensitive taxes	(45,705		)	(45,446		)	0.6
Net electric revenue for margin	526,386			514,856			2.2
Minus power costs:
Purchased electricity1	(199,115		)	(228,041		)	(12.7	)
Electric generation fuel1	(69,937		)	(45,223		)	54.6
Residential exchange1	23,335			21,682			7.6
Total electric power costs	(245,717		)	(251,582		)	(2.3	)
Electric margin2	$	280,669		$	263,274		6.6	%

______________

¹  As reported on PSE’s Consolidated Statement of Income.

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 $17.4 million for the three months ended March 31, 2012, as compared to the same period in 2011. Following is a discussion of significant items that impact electric operating revenue and electric energy costs which are included in electric margin:

Electric Operating Revenue

Electric operatingrevenues increased $11.8 million, or 2.0%, to $611.5 million from $599.7 million for the three months ended March 31, 2012, as compared to the same period in 2011. The increase in operating revenues of $11.8 million was primarily due to higher electric retail sales of $1.0 million, higher miscellaneous operating revenues of $12.8 million and partially offset by lower sales to other utilities and marketers of $1.9 million. These items are discussed in detail below.

Electric retail sales increased $1.0 million, or 0.2%, to $605.5 million from $604.5 million for the months ended March 31, 2012, as compared to the same period in 2011. The increase in electric retail sales was due to a $1.9 million increase in retail electricity usage of 19,130 MWhs, or 0.3%, primarily due to cooler temperatures in PSE's service territory during January and March as compared to the same period in the prior year. Offsetting the increase was a decrease in retail sales of $12.9 million due to the termination of a regulatory asset tracker mechanism on December 31, 2011. Pass-though tariff items that have no impact on earnings but contributed to an increase in retail sales included a $1.1 million increase related to the reduction of the federal

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incentive tariff credit, a $1.7 million decrease in the residential exchange rate credit, and various other pass-through items. The suspension of REC credits in 2011 contributed $16.7 million in electric retail sales for the three months ended March 31, 2012. The REC credit to customers is offset in other electric operating revenue with no impact to earnings. PSE's customers received credits effective November 1, 2010 through April 30, 2011.

Sales to other utilities and marketers decreased $1.9 million for the three months ended March 31, 2012, as compared to the same period in 2011. This decrease was primarily due to a decline in market electricity prices which decreased revenue $2.1 million and was partially offset by $0.2 million due to a reduction in sales volumes of 8,380 MWhs, or 2.7%.

Other electric operating revenue increased $12.8 million for the three months ended March 31, 2012, as compared to the same period in 2011. For the three months ended March 31, 2012 the increase was primarily due to a reductions to revenue offsets due to non-core gas sales of $29.5 million and $21.1 million related to PTCs deferrals, partially offset by a decrease in REC revenue of $38.0 million, PTCs are deferred until PSE utilizes the tax credit on its tax return. As discussed above, REC revenue is an offset of the REC credit provided to PSE's customers in electric retail sales with no impact to earnings.

Electric Energy Costs

Purchased electricity expense decreased $28.9 million, or 12.7%, for the three months ended March 31, 2012, as compared to the same period in 2011. The decrease in purchased electricity expense for the three months ended March 31, 2012 was primarily the result of a decrease of $47.9 million related to the expiration of long-term firm contracts. Offsetting this decrease was a $9.6 million increase related to PSE's power purchase contracts and $4.9 million wholesale market offset cost related to Lower Snake River which is being deferred and included in purchased power. Also offsetting the decrease is a $5.8 million increase due to sharing of overrecovery of power costs with customers in accordance with the PCA mechanism customer sharing for the three months ended March 31, 2012, which reduced the customer PCA deferral as compared to an overrecovery of power costs of $1.0 million in the same period in 2011.

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

Electric generation fuel expense increased $24.7 million, or 54.6%, for the three months ended March 31, 2012, as compared to the same period in 2011. The increase was primarily due to lower hydroelectric generation of 453,845 MWhs, or 22.3%, which resulted in increased electricity generation from PSE's combustion turbine facilities that contributed $25.7 million in expense. Generation fuel costs were also higher, due to increased generation from PSE's combustion turbine facilities.

Residential exchange credits increased $1.7 million, or 7.6%, for the three months ended March 31, 2012, as compared to the same period in 2011 as a result of higher electric residential and farm customer sales volumes associated with the BPA Residential Exchange Program (REP). The REP credit is a pass-through tariff item with a corresponding credit in electric operating revenue, with no impact on net income.

Natural Gas Margin

The following table displays the details of PSE's natural gas margin for the three months ended March 31, 2012 as compared to the same period in 2011. 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.

	Three Months Ended March 31,
Natural Gas Margin (Dollars in Thousands)	2012			2011			Percent Change
Gas operating revenue1	$	435,966		$	418,624		4.1	%
Less: Other gas operating revenue	(3,485		)	(3,639		)	(4.2	)
Total gas revenue for margin	432,481			414,985			4.2
Adjustments for amounts included in revenue:
Pass-through tariff items	(11,493		)	(9,047		)	27.0
Pass-through revenue-sensitive taxes	(35,325		)	(34,851		)	1.4
Net gas revenue for margin	385,663			371,087			3.9
Minus purchased gas costs1	(233,519		)	(236,754		)	(1.4	)
Natural gas margin2	$	152,144		$	134,333		13.3	%

¹  As reported on PSE's Consolidated Statement of Income.

²  Gas margin does not include any allocation for amortization/depreciation expense or electric generation operations and maintenance expense.

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Natural gas margin increased $17.8 million for the three months ended March 31, 2012, as compared to the same period in 2011. Following is a discussion of significant items of gas operating revenue and gas energy costs which are included in gas margin:

Gas Operating Revenue

Gas operating revenues increased $17.3 million, or 4.1%, to $436.0 million from $418.6 million for the three months ended March 31, 2012, as compared to the same period in 2011. The increase in gas operating revenues of $17.3 million was due primarily to higher natural gas retail sales of $17.3 million which is discussed below.

Natural gas retail sales increased $17.3 million, or 4.2%, to $428.6 million from $411.3 million for the three months ended March 31, 2012, as compared to the same period in 2011. The increase in natural gas retail sales for the three months ended March 31, 2012, as compared to the same period in 2011 was primarily due to an increase in therm sales of $10.1 million, or 2.8% due to colder temperatures in January and March that resulted in an $11.6 million increase. Additionally, a change in accounting estimate related to PSE's unbilled revenue calculation resulted in a current period increase of $15.2 million (See Note 1 for additional information on the change in accounting estimate of unbilled revenue). Also, the 4.1% natural gas general rate tariff effective April 1, 2011 contributed $8.3 million. Offsetting the increase in natural gas retail sales was a 4.3% PGA rate decrease effective November 1, 2011 which reduced revenues by $18.7 million. 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 net income is not affected by changes under the PGA mechanism.

Gas Energy Costs

Purchased gasexpenses decreased $3.2 million, or 1.4%, for the three months ended March 31, 2012, as compared to the same period in 2011. The decrease was primarily due to lower natural gas costs reflected in PGA rates effective November 1, 2011. This decrease was partially offset by an increase in customer volume of 6.7% for the three months ended March 31, 2012, as compared to the same period in 2011. The 6.7% increase was due in part to a change in accounting estimate related to PSE's unbilled gas revenue calculation and colder temperatures in January and March. The PGA mechanism provides the rates used to determine natural gas costs based on customer usage. The rate decrease was the result of decreasing costs of wholesale natural gas. The PGA mechanism allows PSE to recover expected natural gas supply and transportation costs and defer, as a receivable or liability, any natural gas supply and transportation costs that exceed or fall short of this expected natural gas cost amount in PGA mechanism rates, including accrued interest. 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 underrecovery of market natural gas cost through rates. A payable balance reflects overrecovery of market natural gas cost through rates. The PGA mechanism payable balance at March 31, 2012 was $56.2 million, which will be passed through to customers through a future PGA rate filing.

Other Operating Expenses

Net unrealized loss on derivative instrumentsdecreased $16.1 million to a loss of $10.1 million during the three months ended March 31, 2012 from a gain of $6.0 million during the same period in 2011. The losses were primarily due to the market movement of commodity prices. Forward prices of electricity and natural gas declined by 11.6% and 8.8%, respectively, for the three months ended March 31, 2012. The losses were partially offset by contracts that were recorded in previous periods as losses, which were reversed at settlement, leading to gains.

Utility operations and maintenanceexpense increased $10.1 million, or 8.5%, for the three months ended March 31, 2012, as compared to the same period in 2011. The increase was driven by increases of $3.1 million increase in electric production, $1.3 million in administration and general expenses and $5.7 million in electric transmission and distribution expenses due primarily to the January storm. Additionally, PSE deferred as a regulatory asset for future recovery approximately $57.1 million in transmission and distribution expenses related to the January 2012 winter storm.

Depreciation expense increased $4.2 million, or 5.6%, for the three months ended March 31, 2012, as compared to the same period in 2011. The increase was primarily due to additional capital expenditures placed into service, net of retirements.

Amortization expense decreased $4.6 million, or 25.8%, for the three months ended March 31, 2012, as compared to the same period in 2011. The decrease is primarily due to the deferral of amortization related to the Lower Snake River project of $3.9 million. Additionally, a decrease of $1.0 million is related to the Goldendale deferred costs being fully amortized in 2011.

Conservation amortization increased $2.2 million, or 6.8%, for the three months ended March 31, 2012, as compared to the same period in 2011. The increase was due to a higher authorized recovery of electric and natural gas conservation expenditures. Conservation amortization is a pass-through tariff item with no impact on earnings.

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Other Income and Interest Expense and Income Tax Expense

Other Income increased$2.4 million, or 19.1%, for the three months ended March 31, 2012, as compared to the same periods in 2011. The increase was primarily due to the carrying costs associated with the Lower Snake River accruing interest income of $3.7 million as authorized by the Washington Commission. Also contributing to the increase is an $1.8 million increase in AFUDC equity income. Partially offsetting these increases is a $2.1 million decrease in regulatory interest and a $0.6 million decrease related to PTC's.

Other Expense increased$2.8 million for the three months ended March 31, 2012, as compared to the same period in 2011. The increase was primarily due to a $2.4 million increase related to customer credits resulting from the outages due to the January 2012 winter storm.

Puget Energy

Summary Results of Operations

All the operations of Puget Energy are conducted through its subsidiary PSE. Puget Energy's net income (loss) for the three months ended March 31, 2012 and 2011were as follows:

	Three Months Ended March 31,
Benefit/(Expense) (Dollars in Thousands)	2012			2011			Percent Change
PSE net income (loss)	$	112,716		$	103,439		9.0	%
Purchased electricity	—			145			*
Net unrealized gain on energy derivative instruments	5,409			27,135			(80.1	)
Non-utility expense and other	2,370			429			*
Other income	3			4			(25.0	)
Non-hedged interest rate derivative expense	527			(48		)	*
Interest expense 1	(46,413		)	(24,378		)	(90.4	)
Income tax benefit (expense)	13,868			705			*
Puget Energy net income (loss)	$	88,480		$	107,431		(17.6	)%

__________

^* Not meaningful

¹  Puget Energy’s interest expense includes elimination adjustments of intercompany interest on short-term debt.

Puget Energy's net income for the three months ended March 31, 2012 was $88.5 million with operating revenue of $1.0 billion as compared to net income of $107.4 million with operating revenue of $1.0 billion for the same period in 2011. The following are significant factors that impacted Puget Energy's net income which are not included in PSE's discussion:

Net unrealized gain on derivative instruments decreased $21.7 million for the three months ended March 31, 2012, as compared to the same period in 2011 due to the effects of purchase accounting on derivative contracts in OCI of $15.8 million and the fair value amortization of NPNS derivative contracts of $5.9 million.

Interest expense increased $22.0 million for the three months ended March 31, 2012, as compared to the same period in 2011.  The increase is primarily due to a $13.2 million write-off of the unamortized issuance costs associated with the five-year term loan and capital expenditure credit facility which were terminated on February 10, 2012. Also contributing to the increase was $6.4 million related to mark-to-market on interest rate swap contracts and $2.9 million of interest expense related to higher fixed rate debt issuances and additional debt balances.

Income tax benefit increased $13.2 million for the three months ended March 31, 2012, as compared to the same period in 2011 due primarily to higher pre-tax loss.

Capital Requirements

Contractual Obligations and Commercial Commitments

The only changes to the contractual obligations and consolidated commercial commitments set forth in Part II, Item 7 in Puget Energy's and PSE's combined annual report on Form 10-K for the year ended December 31, 2011 are as follows: (1) Puget Energy's borrowing of $859.0 million on February 10, 2012 under a new $1.0 billion, five-year revolving senior secured credit facility and the concurrent paydown of debt outstanding under Puget Energy's prior term loan and capital expenditure credit facility which were terminated. This increased contractual obligations by $16.0 million, net of redemptions and decreased available commitments

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of $314.0 million due to the change in debt structure from $298.0 million drawn under the term loan and $545.0 million drawn under the prior $1.0 billion term loan capital expenditure credit facility to a total $859.0 million drawn under the new $1.0 billion senior secured credit facility.

Utility Construction Program

PSE’s construction programs for generating facilities, the electric transmission system and the natural gas and electric distribution systems are designed to meet regulatory requirements and customer growth and to support reliable energy delivery.  Construction expenditures, excluding equity AFUDC, were $185.6 million for the three months ended March 31, 2012.  Presently planned utility construction expenditures, excluding AFUDC, for 2012, 2013 and 2014 are as follows:

Capital Expenditure Projections (Dollars in Thousands)	2012		2013		2014
Total energy delivery, technology and facilities expenditures	$	698,458	$	632,400	$	591,206

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

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

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

Baker Project.  Under the terms of the FERC issued 50-year operating license for the Baker power generating facility, PSE has completed several capital projects and is currently undertaking several more, each of which implements various license provisions and upgrades for the 80-year old facility. One of these upgrades includes the addition of 30 MW of generating capacity, which is expected to be in service by the end of 2013.

Lower Snake River.  The Lower Snake River wind project is PSE’s newest renewable energy development project. The project was designed to be built in five phases. PSE began construction on Phase 1 in 2010. On February 29, 2012, the 343 MW Phase 1 Lower Snake River Wind Facility began commercial operations and was placed in-service. The new facility’s 149 wind turbines are located in Garfield County in southeast Washington.

Capital Resources

Cash From Operations

Puget Sound Energy

Cash generated from operations for the three months ended March 31, 2012 decreased by $48.6 million to $261.2 million from $309.8 million generated during the same period in 2011.  The decrease in cash flow was primarily the result of the following:

• In 2012, there was approximately $64.8 million of cash outflow for costs incurred related to the January winter storm of which $57.1 million was deferred for future recovery.

• Tax refunds received decreased by $47.9 million in 2012.

• Increase in payments of $38.3 million related to energy and operational costs.

The decrease in cash generated from operating activities in 2012 described above was partially offset by the following cash increases:

• Payments made in 2011 relating to transmission prepayments for the Lower Snake River project and the purchase of combustion turbine inventory that did not occur in 2012, which caused an increase in cash flow of approximately $27.1 million.

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• PSE's PGA tariff rates over collected natural gas costs in 2012 due to lower natural gas costs. As a result of the over collection, PSE had a net increase in cash flow of approximately $21.4 million. The over collection will reduce customers PGA tariff rates in the future.

• In 2011, PSE provided customers $10.1 million of REC proceeds while in 2012, PSE sold and deferred REC proceeds of $9.1 million which provided an increase in cash flow of $19.2 million.

In addition, non cash items increased approximately $17.9 million related to items such as depreciation, amortization, deferred income taxes and credits, and fair value adjustment related to derivative instruments.

Puget Energy

Cash generated from operations for the three months ended March 31, 2012 was $273.6 million, a decrease of $132.3 million from the $405.9 million generated during the three months ended March 31, 2011.  The decrease included $48.6 million from the cash provided by the operating activities of PSE as previously discussed.  The other factors contributing to the decrease included the following:

• As a result of the merger, $36.6 million in derivative settlement payments were reclassified to financing activities during the three months ended March 31, 2012 as compared to $97.7 million during the same period in 2011, resulting in a decrease in operating cash flows of $61.1 million.  This decrease was due to a decline in the number of contracts settled during 2012 as compared to the prior period.  These contracts represent proceeds received from derivative instruments that included financing elements at the merger date.

• Tax refund received by Puget Energy of $13.5 million in 2011 as compared to no refund received in 2012.

Financing Program

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

Credit Facilities and Commercial Paper

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

Puget Sound Energy Credit Facilities

PSE maintains three committed unsecured revolving credit facilities that provide, in the aggregate, $1.15 billion in short-term borrowing capability and which mature concurrently in February 2014. These facilities include a $400.0 million credit agreement for working capital needs, a $400.0 million credit facility for funding capital expenditures and a $350.0 million facility to support energy hedging activities.

PSE's credit agreements contain usual and customary affirmative and negative covenants that, among other things, place limitations on PSE's ability to incur additional indebtedness and liens, issue equity, pay dividends, transact with affiliates and make asset dispositions and investments. The credit agreements also contain financial covenants which include a cash flow interest coverage ratio and, in addition, if PSE has a below investment grade credit rating, a cash flow to net debt outstanding ratio (each as specified in the facilities). PSE certifies its compliance with such covenants to participating banks each quarter. As of March 31, 2012, PSE was in compliance with all applicable covenants.

These credit facilities contain similar terms and conditions and are syndicated among numerous committed lenders. The agreements provide PSE with the ability to borrow at different interest rate options and include variable fee levels. The credit agreements allow PSE to borrow at the bank's prime rate or to make floating rate advances at the LIBOR plus a spread that is based upon PSE's credit rating. The working capital facility, as amended, includes a swing line feature allowing same day availability on borrowings up to $50.0 million. The $400.0 million working capital facility and $350.0 million credit agreement to support energy hedging allow for issuing standby letters of credit. PSE must also pay a commitment fee on the unused portion of the credit facilities. The spreads and the commitment fee depend on PSE's credit ratings. As of the date of this report, the spread to the LIBOR is 0.85% and the commitment fee is 0.26%. The $400.0 million working capital facility also serves as a backstop for PSE's commercial paper program.

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As of March 31, 2012, $38.0 million was drawn and outstanding under PSE's $400.0 million working capital facility. A $12.5 million letter of credit supporting contracts was outstanding under the facility and there were no amounts outstanding under the commercial paper program. The $400.0 million capital expenditure facility had no amounts drawn and outstanding. No amounts were drawn or outstanding (including letters of credit) under PSE's $350.0 million facility supporting energy hedging. Outside of the credit agreements, PSE had a $5.3 million letter of credit in support of a long-term transmission contract.

Demand Promissory Note. On June 1, 2006, PSE entered into a revolving credit facility with Puget Energy, in the form of a credit agreement and a Demand Promissory Note (Note) pursuant to which PSE may borrow up to $30.0 million from Puget Energy subject to approval by Puget Energy. Under the terms of the Note, PSE pays interest on the outstanding borrowings based on the lower of the weighted-average interest rates of PSE's outstanding commercial paper interest rate or PSE's senior unsecured revolving credit facility. Absent such borrowings, interest is charged at one-month LIBOR plus 0.25%. At March 31, 2012, the outstanding balance of the Note was $30.0 million. The outstanding balance and the related interest under the Note are eliminated by Puget Energy upon consolidation of PSE's financial statements.

Puget Energy Credit Facilities

At the time of the merger in February 2009, Puget Energy entered into a $1.225 billion five-year term loan and a $1.0 billion capital expenditure credit facility for funding capital expenditures. On February 10, 2012, Puget Energy entered into a $1.0 billion five-year revolving senior secured credit facility. As a revolving facility, amounts borrowed may be repaid without a reduction in the size of the facility. Initial borrowings under this facility were used to repay debt outstanding under the existing term loan and capital expenditure credit facility and those agreements were terminated. As of March 31, 2012, $859.0 million was outstanding under the new $1.0 billion five year senior secured credit facility.

The new senior secured credit facility contains usual and customary affirmative and negative covenants. The agreement also contains two financial covenants based on the following ratios: Group Funds From Operations (FFO) Coverage Ratio and Maximum Leverage Ratio, as defined in the agreement governing the senior secured credit facility. As of March 31, 2012, Puget Energy was in compliance with all applicable covenants.

The senior secured credit facility provides Puget Energy the ability to borrow at different interest rate options and includes variable fee levels. Interest rates may be based on the prime rate or LIBOR, plus a spread based on Puget Energy's credit ratings. Puget Energy must pay a commitment fee on the unused portion of the facility. As of March 31, 2012, the spread over LIBOR was 2.0% and the commitment fee was 0.375%.

Dividend Payment Restrictions

The payment of dividends by PSE to Puget Energy is restricted by provisions of certain covenants applicable to long-term debt contained in PSE's electric and natural gas mortgage indentures. At March 31, 2012, approximately $496.4 million of unrestricted retained earnings was available for the payment of dividends under the most restrictive mortgage indenture covenant.

Beginning February 6, 2009, pursuant to the terms of the Washington Commission merger order, PSE may not declare or pay dividends if PSE's common equity ratio, calculated on a regulatory basis, is 44.0% or below except to the extent a lower equity ratio is ordered by the Washington Commission. Also, pursuant to the merger order, PSE may not declare or make any distribution unless on the date of distribution PSE's corporate credit/issuer rating is investment grade, or, if its credit ratings are below investment grade, PSE's ratio of EBITDA to interest expense for the most recently ended four fiscal quarter periods prior to such date is equal to or greater than 3 to one. The common equity ratio, calculated on a regulatory basis, was 48.5% at March 31, 2012 and the EBITDA to interest expense was 4.4 to one for the 12 months then ended.

PSE's ability to pay dividends is also limited by the terms of its credit facilities, pursuant to which PSE is not permitted to pay dividends during any Event of Default, or if the payment of dividends would result in an Event of Default (as defined in the facilities), such as failure to comply with certain financial covenants.

Puget Energy's ability to pay dividends is also limited by the merger order issued by the Washington Commission. Pursuant to the merger order, Puget Energy may not declare or make a distribution unless on such date Puget Energy's ratio of consolidated EBITDA to consolidated interest expense for the four most recently ended fiscal quarters prior to such date is equal to or greater than 2 to one. At March 31, 2012, the EBITDA to interest expense was 2.5 to one for the 12 months then ended.

Debt Restrictive Covenants

The type and amount of future long-term financings for PSE are limited by provisions in PSE's credit agreements and mortgage indentures. Under its credit agreements, PSE's long-term debt issuances can not exceed $500.0 million per year, plus any amount needed to refinance maturing bonds. Unused amounts under this limitation may be carried forward into future years.

PSE's ability to issue additional secured debt may also be limited by certain restrictions contained in its electric and natural gas mortgage indentures. Under the most restrictive tests, at March 31, 2012, PSE could issue:

• Approximately $1.3 billion of additional first mortgage bonds under PSE's electric mortgage indenture based on approximately $2.1 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, 2012; and

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• Approximately $230.0 million of additional first mortgage bonds under PSE's natural gas mortgage indenture based on approximately $383.3 million of gas bondable property available for issuance, subject to a combined gas and electric interest coverage test of 1.75 times net earnings available for interest and a gas interest coverage test of 2.0 times net earnings available for interest (as defined in the natural gas utility mortgage), both of which PSE exceeded at March 31, 2012.

At March 31, 2012, PSE had approximately $5.9 billion in electric and natural gas ratebase to support the interest coverage ratio limitation test for net earnings available for interest.

Shelf Registrations and Long-Term Debt Activity

Puget Sound Energy. PSE has in effect a shelf registration statement under which it may issue, from time to time, senior notes secured by first mortgage bonds. The Company remains subject to the restrictions of PSE's indentures and credit agreements on the amount of first mortgage bonds that PSE may issue.

Other

Residential Exchange

The Northwest Power Act, through the Residential Exchange Program (REP), provides access to the benefits of low-cost federal hydroelectric power to residential and small farm customers of regional utilities, including PSE. The program is administered by the Bonneville Power Administration (the BPA). Pursuant to agreements (including settlement agreements) between the BPA and PSE, the BPA has provided payments of REP benefits to PSE, which PSE has passed through to its residential and small farm customers in the form of electricity bill credits.

In 2007, the U.S. Court of Appeals for the Ninth Circuit ruled that REP agreements of the BPA with PSE and a number of other investor-owned utilities were inconsistent with the Northwest Power Act. Since that time, those investor-owned utilities, including PSE, the BPA and other parties have been involved in ongoing litigation at the Ninth Circuit relating to the amount of REP benefits paid to utilities, including PSE, for the period fiscal year 2002 through fiscal year 2011 and the amount of REP benefits to be paid going forward.

In July 2011, the BPA, PSE and a number of other parties entered into a settlement agreement that by its terms if upheld in their entirety would resolve the disputes between BPA and PSE regarding REP benefits paid for the period fiscal year 2002-fiscal year 2011. In October 2011, certain other parties challenged BPA decisions with regard to its entering into this most recent settlement agreement. Pending disposition of this challenge, the other pending Ninth Circuit litigation regarding REP benefits for the period fiscal year 2002 through fiscal year 2011 has been stayed by the Ninth Circuit.

Due to the pending and ongoing proceedings, PSE is unable to reasonably estimate any amounts of REP payments - either to be recovered by the BPA or to be paid for any future periods to PSE - and is unable to determine the impact, if any, these proceedings and litigation may have on PSE. However, the Company believes it is unlikely that any unfavorable outcome would have a material adverse effect on PSE because REP benefits received by PSE are passed through to PSE's residential and small farm customers

Pacific Northwest Refund Proceeding

In October 2000, PSE filed a complaint with the FERC (Docket No. EL01-10) against “all jurisdictional sellers” in the Pacific Northwest seeking prospective price caps consistent with any result the FERC ordered for the California markets. The FERC issued an order including price caps in July 2001, and PSE moved to dismiss the proceeding. In response to PSE's motion, various entities intervened and sought to convert PSE's complaint into one seeking retroactive refunds in the Pacific Northwest. The FERC rejected that effort, after holding what the FERC referred to as a “preliminary evidentiary hearing” before an administrative law judge. On October 3, 2011, after appellate reviews, the FERC issued an Order on Remand and set the matter for hearing before an administrative law judge, but first requiring the parties to engage in settlement talks that began in the fall of 2011 and are ongoing. As such, the hearing date itself is not known. PSE has not taken any reserve on this matter as it believes it has no exposure, and intends to vigorously defend its position but is unable to predict the outcome of this matter.

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Item 3.                      Quantitative and Qualitative Disclosure about Market Risk

Energy Portfolio Management

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

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

Ÿ	Ensure physical energy supplies are available to reliably and cost-effectively serve retail load;
Ÿ	Manage the energy portfolio prudently to serve retail load at overall least cost and limit undesired impacts on PSE’s customers and shareholders;
Ÿ	Reduce power costs by extracting the value of PSE’s assets; and
Ÿ	Meet the credit, liquidity, financing, tax and accounting requirements of PSE.

Accounting Standards Codification (ASC) 815, “Derivatives and Hedging” (ASC 815), requires a significant amount of disclosure regarding PSE’s derivative activities and the nature of such derivatives impact on PSE’s financial position, financial performance and cash flows.  Such detail should serve as an accompaniment to Management’s Discussion and Analysis included in Item 2 of this report.

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

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

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The following table presents the Company's energy derivative instruments that do not meet the Normal Purchase Normal Sale (NPNS) exception at March 31, 2012 and December 31, 2011:

Puget Energy and Puget Sound Energy	Energy Derivatives
Derivative Portfolio (Dollars in thousands)	March 31, 2012				December 31, 2011
	Assets		Liabilities		Assets		Liabilities
Electric portfolio:
Current	$	3,597	$	193,421	$	5,212	$	173,582
Long-term	5,051		76,018		5,508		90,752
Total electric derivatives	$	8,648	$	269,439	$	10,720	$	264,334
Natural gas portfolio:
Current	$	1,827	$	143,488	$	1,435	$	128,297
Long-term	3,998		68,734		4,576		78,607
Total natural gas derivatives	$	5,825	$	212,222	$	6,011	$	206,904
Total derivatives	$	14,473	$	481,661	$	16,731	$	471,238

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

At March 31, 2012, the Company had total assets of $5.8 million and total liabilities of $212.2 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 of derivatives relating to the natural gas business have been reclassified to a deferred account in accordance with ASC 980 due to the PGA mechanism. All increases and decreases in the cost of natural gas supply are passed on to customers with the PGA mechanism. As the gains and losses on the hedges are realized in future periods, they will be recorded as natural gas costs under the PGA mechanism.

A hypothetical 10.0% increase or decrease in market prices of natural gas and electricity would change the fair value of the Company derivative contracts by $38.6 million and would impact the fair value of those contracts marked-to-market in earnings by $25.1 million after-tax related to derivatives not designated as hedges

Contingent Features and Counterparty Credit Risk

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

Where deemed appropriate, and when allowed under the terms of the agreements, PSE may request collateral or other security from its counterparties to mitigate the potential credit default losses. Criteria employed in this decision include, among other things, the perceived creditworthiness of the counterparty and the expected credit exposure. As of March 31, 2012, PSE held approximately $11.1 million worth of standby letters of credit in support of various electricity and REC 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. As of March 31, 2012, approximately 96.2% of PSE's energy and natural gas portfolio exposure, including NPNS transactions, is with counterparties that are rated at least investment grade by the major rating agencies, while 3.8% 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) WSPP, Inc. (WSPP) agreements - standardized power sales contracts in the electric industry; (2) International Swaps and Derivatives Association (ISDA) agreements - standardized financial gas and electric contracts; and (3) North American Energy Standards Board (NAESB) agreements- standardized physical gas contracts. PSE believes that entering into such agreements reduces the risk of default by allowing a counterparty the ability to make only one net payment.

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

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Accumulated OCI of the cash flow hedge is also impacted by a counterparty's deterioration of credit under ASC 815 guidelines. If a forecasted transaction associated with cash flow hedge is not probable of occurring, PSE will reclassify the amounts deferred in accumulated OCI into earnings.

Should a counterparty file for bankruptcy, which would be considered a default under master arrangements, PSE may terminate related contracts. Derivative accounting entries previously recorded would be reversed in the financial statements. PSE would compute any terminations receivable or payable, based on the terms of existing master agreements.

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

The Company applies the counterparty's default factor to compute credit reserves for counterparties that are in a net asset position. The Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate. The fair value of derivatives includes the impact of taking into account credit and non-performance reserves. As of March 31, 2012, the Company was in a net liability position with the majority of its counterparties, therefore the default factors of counterparties did not have a significant impact on reserves for the year. Despite its net liability position, PSE was not required to post any additional collateral with any of its counterparties. Additionally, PSE did not trigger collateral requirements with any of its counterparties, nor were any of PSE's counterparties required to post additional collateral resulting from credit rating downgrades.

Interest Rate Risk

The Company believes its interest rate risk primarily relates to the use of short-term debt instruments, variable rate leases and anticipated long-term debt financing needed to fund capital requirements. The Company manages its interest rate risk through the issuance of mostly fixed-rate debt with varied maturities. The Company utilizes internal cash from operations, commercial paper and credit facilities to meet short-term funding needs. Short-term obligations are commonly refinanced with fixed-rate bonds or notes when needed and when interest rates are considered favorable. The Company may also enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with its debt. As of March 31, 2012, Puget Energy had three interest rate swap contracts outstanding and PSE did not have any outstanding interest rate swap instruments.

In February 2009, Puget Energy entered into a cash flow hedge using interest rate swap to hedge the risk associated with one-month LIBOR floating rate debt. Subsequently, in order to satisfy a commitment the Company made to the Washington Commission and to mitigate refinancing risk, the Company refinanced a portion of the underlying debt hedged by the interest rate swaps in 2010 and again during 2011. As a result of the refinance, the Company de-designated the cash flow hedging relationship between the debt and interest rate swaps in 2010. On February 10, 2012, the Company terminated its previous capital expenditure credit facility (which originally acted as a portion of the underlying variable rate debt in the cash flow hedge) in favor of a new five year $1.0 billion revolving senior secured credit facility and used this new senior secured credit facility to pay off the remaining balance on the original term loan and capital expenditure credit facility. At March 31, 2012, the balance on the new senior secured credit facility was $859.0 million. In order to better align its existing swap notional with the new credit facility, the Company settled an additional $277.4 million of the interest rate swaps on February 15, 2012, thereby reducing the swap notional to $1.0 billion. The transaction did not impact the consolidated statements of income as the fair value losses for those swaps had already been recorded through earnings. Since replacing the previous capital expenditure credit facility with the new senior secured credit facility effectively replaced debt with like debt, the original hedged forecasted interest payments are still probable of occurring and there is no anticipated reclassification of existing amounts deferred in accumulated OCI to earnings as a result of this transaction. Therefore at March 31, 2012 the outstanding notional balance of the interest rate swaps was $1.0 billion, exceeding the balance of $859.0 million in variable rate debt of which the swaps are hedging. During the period in which the Company's interest rate swaps are in excess of the Company's variable rate debt, the Company will be subject to additional interest rate risk.

At March 31, 2012, the fair value of the interest rate swaps was a $38.7 million pre-tax loss. This fair value considers the risk of Puget Energy's non-performance by using Puget Energy's incremental borrowing rate on unsecured debt over the risk-free rate in the valuation estimate. The ending balance in OCI includes a loss of $18.6 million pre-tax and $12.1 million after tax, related to the interest rate swaps previously designated as a cash flow hedge. The OCI balance relates to the loss that was recorded when the cash flow hedge was de-designated in December 2010. Going forward, all changes in market value will be recorded in earnings instead of OCI.

A hypothetical 10% increase or decrease in interest rates would change the fair value of Puget Energy interest rate swaps by $0.6 million or $0.4 million after tax, recorded in accumulated OCI.

As a result of the cash flow hedge de-designation related to its interest rate swaps, the Company is exposed to additional interest rate risk on the portion of swaps that remain non-hedged. A hypothetical 10% change in the one-month LIBOR would

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change the fair value of these specific non-hedged swaps by $0.5 million. This hypothetical change in fair value would directly impact earnings.

The following table presents Puget Energy's interest rate swaps at March 31, 2012 and December 31, 2011:

Puget Energy Derivative Portfolio (Dollars in Thousands)	March 31, 2012		December 31,  2011
	Liabilities		Liabilities
Interest rate swaps:
Current	$	20,895	$	25,210
Long-term	17,794		27,199
Total	$	38,689	$	52,409

From time to time PSE may enter into treasury locks or forward starting swap contracts to hedge interest rate exposure related to an anticipated debt issuance. The ending balance in OCI related to the forward starting swaps and previously settled treasury lock contracts at March 31, 2012 was a net loss of $6.9 million after tax and accumulated amortization. This compares to an after-tax loss of $6.9 million in OCI as of December 31, 2011. All financial hedge contracts of this type are reviewed by an officer, presented to the Board of Directors or a committee of the Board, as applicable, and are approved prior to execution. PSE had no treasury locks or forward starting swap contracts outstanding at March 31, 2012.

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 Senior 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, 2012, the end of the period covered by this report.  Based upon that evaluation, the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer of Puget Energy concluded that these disclosure controls and procedures are effective.

Changes in Internal Control Over Financial Reporting

There have been no changes in Puget Energy’s internal control over financial reporting during the three months ended March 31, 2012 that have materially affected, or are reasonably likely to materially affect, Puget Energy’s internal control over financial reporting.

Puget Sound Energy

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of PSE’s management, including the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, PSE has evaluated the effectiveness of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of March 31, 2012, the end of the period covered by this report.  Based upon that evaluation, the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer of PSE concluded that these disclosure controls and procedures are effective.

Changes in Internal Control Over Financial Reporting

There have been no changes in PSE’s internal control over financial reporting during the three months ended March 31, 2012 that have materially affected, or are reasonably likely to materially affect, PSE’s internal control over financial reporting.

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Part II                    Other Information

Item 1.                      Legal Proceedings

For details on legal proceedings, see the Litigation footnote in the notes to the consolidated financial statements of this Quarterly Report on Form 10-Q.  Contingencies arising out of the normal course of PSE’s business existed as of March 31, 2012.  Litigation is subject to numerous uncertainties and PSE is unable to predict the ultimate outcome of these matters.

Item 1A.                  Risk Factors

There have been no material changes from the risk factors set forth in Part I, Item 1A in Puget Energy’s and PSE’s Form 10-K for the period ended December 31, 2011.

Item 6.                      Exhibits

Included in the Exhibit Index are a list of exhibits filed as part of this Quarterly Report on Form 10-Q.

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SIGNATURES

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

		PUGET ENERGY, INC. PUGET SOUND ENERGY, INC.
		/s/ Daniel A. Doyle
		Daniel A. Doyle Senior Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)
Date:	May 9, 2012	Officer duly authorized to sign this report on behalf of each registrant

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EXHIBIT INDEX

4.1*	Eighty-eighth Supplemental Indentures defining the rights of the holders of Puget Sound Energy's Electric Utility First Mortgage Bonds.
4.2*	Eighty-ninth Supplemental Indentures defining the rights of the holders of Puget Sound Energy's Electric Utility First Mortgage Bonds.
4.3*	Ninetieth Supplemental Indentures defining the rights of the holders of Puget Sound Energy's Electric Utility First Mortgage Bonds.
10.1	Credit Agreement dated as of February 10, 2012 among Puget Energy, Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, the other agents party thereto, and the lenders party thereto (incorporated herein by reference to Exhibit 10.1 to Puget Energy's Current Report on Form 8-K filed February 16, 2012, Commission File No. 1-16305, and Puget Sound Energy's Current Report on Form 8-K filed February 16, 2012, Commission File No. 1-4393).
10.2*	Amendment No. 1 dated April 6, 2012 to Credit Agreement dated as of February 10, 2012 among Puget Energy, Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, the other agents party thereto, and the lenders party thereto.
12.1*	Statement setting forth computation of ratios of earnings to fixed charges of Puget Energy, Inc. (2007 through 2011 and 12 months ended March 31, 2012).
12.2*	Statement setting forth computation of ratios of earnings to fixed charges of Puget Sound Energy, Inc. (2007 through 2011 and 12 months ended March 31, 2012).
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*	Principal Financial Officer certification of Puget Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.3*	Chief Executive Officer certification of Puget Sound Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.4*	Principal Financial Officer certification of Puget Sound Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Chief Executive Officer certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	Principal Financial Officer certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101**	Financial statements from the quarterly report on Form 10-Q of Puget Energy, Inc. and Puget Sound Energy, Inc. for the quarter ended March 31, 2012, filed on May 9, 2012, formatted in XBRL: (i) the Consolidated Statement of Income (Unaudited), (ii) the Consolidated Statements of Comprehensive Income (Unaudited), (iii) the Consolidated Balance Sheets (Unaudited), (iii) the Consolidated Statements of Cash Flows (Unaudited), and (iv) the Notes to Consolidated Financial Statements tagged as blocks of text (submitted electronically herewith).

__________________

* Filed herewith.

** In accordance with Rule 406T of Regulation S-T, the XBRL information in Exhibit 101 to this quarterly report on Form 10-Q shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (Exchange Act), or otherwise subject to the liability of that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such filing.

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