10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2014

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

		Page
Definitions		3
Filing Format		4
Forward-Looking Statements		4
Part I.	Financial Statements
	Puget Energy, Inc.
	Consolidated Statements of Income – Three Months Ended March 31, 2014 and 2013	5
	Consolidated Statements of Comprehensive Income – Three Months Ended March 31, 2014 and 2013	6
	Consolidated Balance Sheets – March 31, 2014 and December 31, 2013	7
	Consolidated Statements of Cash Flows – Three Months Ended March 31, 2014 and 2013	8
	Puget Sound Energy, Inc.
	Consolidated Statements of Income – Three Months Ended March 31, 2014 and 2013	9
	Consolidated Statements of Comprehensive Income – Three Months Ended March 31, 2014 and 2013	10
	Consolidated Balance Sheets – March 31, 2014 and December 31, 2013	11
	Consolidated Statements of Cash Flows – Three Months Ended March 31, 2014 and 2013	13
	Notes
	Combined Notes to Consolidated Financial Statements	14
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Item 3.	Quantitative and Qualitative Disclosure About Market Risk	48
Item 4.	Controls and Procedures	50
Part II.	Other Information	50
Item 1.	Legal Proceedings	50
Item 1A.	Risk Factors	51
Item 6.	Exhibits	51
Signatures		52
Exhibit Index		53

2

DEFINITIONS

AFUDC	Allowance for Funds Used During Construction
ASU	Accounting Standards Update
ASC	Accounting Standards Codification
BPA	Bonneville Power Administration
EBITDA	Earnings Before Interest, Tax, Depreciation and Amortization
ERF	Expedited Rate filing
FERC	Federal Energy Regulatory Commission
GAAP	U.S. Generally Accepted Accounting Principles
ICNU	Industrial Customers of Northwest Utilities
IRP	Integrated Resource Plan
ISDA	International Swaps and Derivatives Association
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
REP	Residential Exchange Program
SERP	Supplemental Executive Retirement Plan
Washington Commission	Washington Utilities and Transportation Commission
WSPP	WSPP, Inc.

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 jurisdiction;
Ÿ	Inability to realize deferred tax assets and use production tax credits due to insufficient future taxable income;
Ÿ	Inability to manage costs during the rate stay out period through March 31, 2016, due to unforeseen events which would cause increases in costs of operations;
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 as a result of municipalization or other government action or negotiated settlement, 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, asset-based or cyber-based attacks, 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,
	2014			2013
Operating revenue:
Electric	$	633,553		$	614,634
Gas	387,443			384,765
Other	4,379			419
Total operating revenue	1,025,375			999,818
Operating expenses:
Energy costs:
Purchased electricity	181,157			175,043
Electric generation fuel	75,436			59,087
Residential exchange	(30,003		)	(22,551		)
Purchased gas	191,306			189,983
Unrealized (gain) loss on derivative instruments, net	(7,839		)	(75,692		)
Utility operations and maintenance	144,076			129,235
Non-utility expense and other	3,422			(994		)
Depreciation	91,184			88,178
Amortization	10,535			5,744
Conservation amortization	28,982			34,107
Taxes other than income taxes	100,818			99,943
Total operating expenses	789,074			682,083
Operating income (loss)	236,301			317,735
Other income (deductions):
Other income	4,242			12,012
Other expense	(1,582		)	(1,542		)
Non-hedged interest rate swap (expense) income	(747		)	1,028
Interest charges:
AFUDC	1,153			4,648
Interest expense	(90,255		)	(95,816		)
Income (loss) before income taxes	149,112			238,065
Income tax (benefit) expense	41,520			70,590
Net income (loss)	$	107,592		$	167,475

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,
	2014			2013
Net income (loss)	$	107,592		$	167,475
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $(113) and $186, respectively	(209		)	347
Reclassification of net unrealized (gain) loss on energy derivative instruments settled during the period, net of tax of $187 and $(57), respectively	347			(107		)
Reclassification of net unrealized (gain) loss on interest rate swaps during the period, net of tax of $50 and $460, respectively	94			854
Other comprehensive income (loss)	232			1,094
Comprehensive income (loss)	$	107,824		$	168,569

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, 2014			December 31, 2013
Utility plant (at original cost, including construction work in progress of $299,952 and $310,318, respectively):
Electric plant	$	7,079,136		$	7,019,853
Gas plant	2,557,017			2,528,629
Common plant	457,071			504,036
Less: Accumulated depreciation and amortization	(1,401,652		)	(1,373,178		)
Net utility plant	8,691,572			8,679,340
Other property and investments:
Goodwill	1,656,513			1,656,513
Other property and investments	101,572			100,332
Total other property and investments	1,758,085			1,756,845
Current assets:
Cash and cash equivalents	23,581			44,302
Restricted cash	25,437			7,171
Accounts receivable, net of allowance for doubtful accounts of $8,551 and $7,385, respectively	432,641			408,512
Unbilled revenue	167,105			219,884
Materials and supplies, at average cost	87,926			88,140
Fuel and gas inventory, at average cost	31,245			66,717
Unrealized gain on derivative instruments	44,889			18,867
Taxes	149			297
Prepaid expense and other	18,232			18,787
Power contract acquisition adjustment gain	48,243			48,509
Deferred income taxes	77,343			86,004
Total current assets	956,791			1,007,190
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes	144,166			146,867
Regulatory assets related to power contracts	32,985			33,753
Other regulatory assets	709,094			749,382
Unrealized gain on derivative instruments	6,820			7,733
Power contract acquisition adjustment gain	380,204			394,556
Other	134,186			130,909
Total other long-term and regulatory assets	1,407,455			1,463,200
Total assets	$	12,813,903		$	12,906,575

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, 2014			December 31, 2013
Capitalization:
Common shareholder’s equity:
Common stock $0.01 par value, 1,000 shares authorized, 200 shares outstanding	$	—		$	—
Additional paid-in capital	3,308,957			3,308,957
Earnings reinvested in the business	388,518			323,007
Accumulated other comprehensive income (loss), net of tax	47,947			47,715
Total common shareholder’s equity	3,745,422			3,679,679
Long-term debt:
First mortgage bonds and senior notes	3,351,412			3,351,412
Pollution control bonds	161,860			161,860
Junior subordinated notes	250,000			250,000
Long-term debt	1,699,000			1,699,000
Debt discount and other	(227,013		)	(229,796		)
Total long-term debt	5,235,259			5,232,476
Total capitalization	8,980,681			8,912,155
Current liabilities:
Accounts payable	288,420			296,681
Short-term debt	—			162,000
Purchased gas adjustment liability	2,859			5,938
Accrued expenses:
Taxes	121,035			109,559
Salaries and wages	28,245			38,491
Interest	74,173			79,303
Unrealized loss on derivative instruments	33,213			48,049
Power contract acquisition adjustment loss	3,889			3,937
Other	84,199			60,335
Total current liabilities	636,033			804,293
Other long-term and regulatory liabilities:
Deferred income taxes	1,517,287			1,487,005
Unrealized loss on derivative instruments	27,444			38,162
Power cost adjustment mechanism	5,394			5,345
Regulatory liabilities	676,750			689,060
Regulatory liabilities related to power contracts	428,447			443,065
Power contract acquisition adjustment loss	29,095			29,816
Other deferred credits	512,772			497,674
Total other long-term and regulatory liabilities	3,197,189			3,190,127
Commitments and contingencies
Total capitalization and liabilities	$	12,813,903		$	12,906,575

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,
	2014			2013
Operating activities:
Net income (loss)	$	107,592		$	167,475
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation	91,184			88,178
Amortization	10,535			5,744
Conservation amortization	28,982			34,107
Deferred income taxes and tax credits, net	41,520			70,591
Net unrealized (gain) loss on derivative instruments	(8,793		)	(75,937		)
Derivative contracts classified as financing activities due to merger	8,026			26,049
AFUDC – Equity	(1,436		)	(6,524		)
Funding of pension liability	(3,000		)	(5,100		)
Regulatory assets	(38,240		)	(28,953		)
Regulatory liabilities	6,407			3,029
Other long-term assets	(5,667		)	3,099
Other long-term liabilities	21,532			17,586
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	28,650			31,548
Materials and supplies	214			1,827
Fuel and gas inventory	35,451			27,097
Taxes	148			148
Prepayments and other	539			(3,732		)
Purchased gas adjustment	(3,079		)	(5,718		)
Accounts payable	(13,886		)	(47,935		)
Taxes payable	11,476			16,746
Accrued expenses and other	(7,621		)	(18,060		)
Net cash provided by operating activities	310,534			301,265
Investing activities:
Construction expenditures – excluding equity AFUDC	(96,318		)	(168,337		)
Proceeds from disposition of assets	—			108,166
Restricted cash	(18,266		)	599
Other	(4,125		)	(4,248		)
Net cash used in investing activities	(118,709		)	(63,820		)
Financing activities:
Change in short-term debt and leases, net	(163,903		)	(157,895		)
Dividends paid	(42,081		)	(42,071		)
Redemption of bonds and notes	—			(29,000		)
Derivative contracts classified as financing activities due to merger	(8,026		)	(26,049		)
Issuance cost of bonds and other	1,464			(3,984		)
Net cash provided by (used in) financing activities	(212,546		)	(258,999		)
Net increase (decrease) in cash and cash equivalents	(20,721		)	(21,554		)
Cash and cash equivalents at beginning of period	44,302			135,542
Cash and cash equivalents at end of period	$	23,581		$	113,988
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	90,756		$	78,346

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,
	2014			2013
Operating revenue:
Electric	$	633,553		$	614,634
Gas	387,443			384,765
Other	4,379			308
Total operating revenue	1,025,375			999,707
Operating expenses:
Energy costs:
Purchased electricity	181,157			175,043
Electric generation fuel	75,436			59,087
Residential exchange	(30,003		)	(22,551		)
Purchased gas	191,306			189,983
Unrealized (gain) loss on derivative instruments, net	(7,270		)	(72,740		)
Utility operations and maintenance	144,076			129,235
Non-utility expense and other	6,177			3,091
Depreciation	91,184			88,178
Amortization	10,535			5,744
Conservation amortization	28,982			34,107
Taxes other than income taxes	100,818			99,943
Total operating expenses	792,398			689,120
Operating income (loss)	232,977			310,587
Other income (deductions):
Other income	4,240			12,012
Other expense	(1,582		)	(1,542		)
Interest charges:
AFUDC	1,153			4,648
Interest expense	(64,137		)	(65,977		)
Interest expense on parent note	(26		)	(29		)
Income (loss) before income taxes	172,625			259,699
Income tax (benefit) expense	51,542			79,761
Net income (loss)	$	121,083		$	179,938

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,
	2014		2013
Net income (loss)	$	121,083	$	179,938
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $1,078 and $1,823, respectively	2,001		3,386
Reclassification of net unrealized (gain) loss on energy derivative instruments, net of tax of $386 and $975, respectively	718		1,811
Amortization of treasury interest rate swaps to earnings, net of tax of $43 and $43, respectively	79		79
Other comprehensive income (loss)	2,798		5,276
Comprehensive income (loss)	$	123,881	$	185,214

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, 2014			December 31, 2013
Utility plant (at original cost, including construction work in progress of $299,952 and $310,318, respectively):
Electric plant	$	9,331,849		$	9,276,400
Gas plant	3,162,703			3,134,880
Common plant	498,184			565,072
Less:  Accumulated depreciation and amortization	(4,301,164		)	(4,297,012		)
Net utility plant	8,691,572			8,679,340
Other property and investments:
Other property and investments	93,159			91,919
Total other property and investments	93,159			91,919
Current assets:
Cash and cash equivalents	23,556			44,111
Restricted cash	25,437			7,171
Accounts receivable, net of allowance for doubtful accounts of $8,551 and $7,385, respectively	432,915			408,827
Unbilled revenue	167,105			219,884
Materials and supplies, at average cost	87,926			88,140
Fuel and gas inventory, at average cost	28,463			63,914
Unrealized gain on derivative instruments	44,889			18,867
Taxes	149			297
Prepaid expense and other	18,232			18,770
Deferred income taxes	132,248			141,058
Total current assets	960,920			1,011,039
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes	143,628			146,350
Other regulatory assets	709,094			749,382
Unrealized gain on derivative instruments	6,820			7,733
Other	127,202			123,125
Total other long-term and regulatory assets	986,744			1,026,590
Total assets	$	10,732,395		$	10,808,888

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, 2014			December 31, 2013
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	336,401			289,432
Accumulated other comprehensive income (loss), net of tax	(92,941		)	(95,739		)
Total common shareholder’s equity	3,490,524			3,440,757
Long-term debt:
First mortgage bonds and senior notes	3,351,412			3,351,412
Pollution control bonds	161,860			161,860
Junior subordinated notes	250,000			250,000
Debt discount	(14		)	(14		)
Total long-term debt	3,763,258			3,763,258
Total capitalization	7,253,782			7,204,015
Current liabilities:
Accounts payable	288,415			296,675
Short-term debt	—			162,000
Short-term note owed to parent	29,598			29,598
Purchased gas adjustment liability	2,859			5,938
Accrued expenses:
Taxes	121,035			109,559
Salaries and wages	28,245			38,491
Interest	57,094			55,262
Unrealized loss on derivative instruments	26,461			41,465
Other	84,199			60,334
Total current liabilities	637,906			799,322
Other long-term and regulatory liabilities:
Deferred income taxes	1,626,368			1,584,850
Unrealized loss on derivative instruments	22,070			31,523
Power cost adjustment mechanism	5,394			5,345
Regulatory liabilities	674,103			686,176
Other deferred credits	512,772			497,657
Total other long-term and regulatory liabilities	2,840,707			2,805,551
Commitments and contingencies
Total capitalization and liabilities	$	10,732,395		$	10,808,888

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,
	2014			2013
Operating activities:
Net income (loss)	$	121,083		$	179,938
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation	91,184			88,178
Amortization	10,535			5,744
Conservation amortization	28,982			34,107
Deferred income taxes and tax credits, net	51,543			79,761
Net unrealized (gain) loss on derivative instruments	(7,270		)	(72,740		)
AFUDC – Equity	(1,436		)	(6,524		)
Funding of pension liability	(3,000		)	(5,100		)
Regulatory assets	(38,240		)	(28,953		)
Regulatory liabilities	6,407			3,029
Other long-term assets	(3,251		)	2,922
Other long-term liabilities	19,275			18,162
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	28,691			31,313
Materials and supplies	214			1,827
Fuel and gas inventory	35,451			27,097
Taxes	148			148
Prepayments and other	539			(3,732		)
Purchased gas adjustment	(3,079		)	(5,718		)
Accounts payable	(13,886		)	(47,721		)
Taxes payable	11,476			16,746
Accrued expenses and other	(1,276		)	(8,783		)
Net cash provided by operating activities	334,090			309,701
Investing activities:
Construction expenditures – excluding equity AFUDC	(96,318		)	(168,337		)
Proceeds from disposition of assets	—			108,166
Restricted cash	(18,266		)	599
Other	(3,507		)	(4,184		)
Net cash used in investing activities	(118,091		)	(63,756		)
Financing activities:
Change in short-term debt and leases, net	(163,903		)	(157,895		)
Dividends paid	(74,114		)	(105,648		)
Issuance cost of bonds and other	1,463			(3,985		)
Net cash provided by (used in) financing activities	(236,554		)	(267,528		)
Net increase (decrease) in cash and cash equivalents	(20,555		)	(21,583		)
Cash and cash equivalents at beginning of period	44,111			135,530
Cash and cash equivalents at end of period	$	23,556		$	113,947
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	59,666		$	57,646

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 is an energy services holding company that owns PSE.  PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering approximately 6,000 square miles, primarily in the Puget Sound region.  Following the merger with Puget Holdings LLC (Puget Holdings) in 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 subsidiary.  Puget Energy and PSE are collectively referred to herein as “the Company.”  The consolidated financial statements are presented after elimination of intercompany transactions.  PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any purchase accounting adjustments.

The consolidated financial statements contained in this Form 10-Q are unaudited.  In the respective opinions of the management of Puget Energy and PSE, all adjustments necessary for a fair statement of the results for the interim periods have been reflected and were of a normal recurring nature.  These consolidated financial statements should be read in conjunction with the audited financial statements (and the Combined Notes thereto) included in the combined Puget Energy and PSE Annual Report on Form 10-K for the year ended December 31, 2013.

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.

PSE collected Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes totaling $77.9 million and $76.9 million for the three months ended March 31, 2014 and 2013, respectively.  The Company reports the collection of such taxes on a gross basis in operating revenue and as expense in taxes other than income taxes in the accompanying consolidated statements of income.

Beginning July 1, 2013, PSE's electric and gas operations contain a revenue decoupling mechanism under which PSE's actual energy delivery revenues related to electric transmission and distribution, gas operations and general administrative costs are compared with authorized revenues allowed under the mechanism. Any differences are deferred to a regulatory asset for under recovery or regulatory liability for over recovery. Revenues associated with power costs under the Power Cost Adjustment (PCA) mechanism and Purchased Gas Adjustment (PGA) rates are excluded from the decoupling mechanism.

Statements of Cash Flows

The Company revised its Consolidated Statement of Cash Flows due to an immaterial error. Revisions were made in the second quarter ended June 30, 2013 on the Company's Consolidated Statement of Cash Flows to reflect energy efficiency expenditures as operating cash outflows instead of investing cash outflows. The Company determined energy efficiency expenditures should have been classified as operating activities instead of investing activities. These revisions decreased net cash provided by operating activities and decreased net cash used by investing activities. The revision does not affect the net change in cash and cash equivalents for any of the periods, and has no effect on the Company's Consolidated Statements of Income, Consolidated Statements of Comprehensive Income, Consolidated Balance Sheets, and Consolidated Statement of Common Shareholder's Equity. The Company has evaluated the effects of these errors and concluded that none of them are material to any of the Company's previously issued quarterly or annual Financial Statements. Nevertheless, the Company elected to revise the Consolidated Statement of Cash Flows in this report to correct for the effect of these errors and properly reflect the revised values.

14

The amounts on prior period Consolidated Statements of Cash Flows which have been revised are summarized below:

	As Reported			As Revised
Puget Energy	Three Months Ended			Three Months Ended
(Dollars in Thousands)	March 31, 2013			March 31, 2013
Operating Activities:
Regulatory Assets	$	(6,411	)	$	(28,953	)
Net Cash Provided by Operating Activities	$	323,807		$	301,265
Investing Activities:
Energy Efficiency Expenditures	$	(22,542	)	$	—
Net Cash Used in Investing Activities	$	(86,362	)	$	(63,820	)

	As Reported			As Revised
Puget Sound Energy	Three Months Ended			Three Months Ended
(Dollars in Thousands)	March 31, 2013			March 31, 2013
Operating Activities:
Regulatory Assets	$	(6,411	)	$	(28,953	)
Net Cash Provided by Operating Activities	$	332,243		$	309,701
Investing Activities:
Energy Efficiency Expenditures	$	(22,542	)	$	—
Net Cash Used in Investing Activities	$	(86,298	)	$	(63,756	)

(2) Accounting for Derivative Instruments and Hedging Activities

PSE employs various energy 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 and related hedging strategy objective is to minimize costs and risks where feasible thus reducing volatility in costs in the portfolio. In order to manage its exposure to the variability in future cash flows for forecasted energy transactions, PSE utilizes a programmatic hedging strategy which extends out three years. 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 forward physical electric and natural gas purchase and sale agreements, fixed-for-floating swap contracts, and commodity call/put options. The forward physical electric agreements are both fixed and variable (at index), while the physical natural gas agreements are variable. To fix the price of wholesale electricity and natural gas, PSE may enter into fixed-for-floating swap (financial) contracts with various counterparties. PSE also utilizes natural gas call and put options as an additional hedging instrument to increase the hedging portfolio's flexibility to react to commodity price fluctuations.

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, borrowings under its commercial paper program, and its credit facilities to meet short-term funding needs. 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, 2014, Puget Energy had two interest rate swap contracts outstanding which extend to January 2017. PSE did not have any outstanding interest rate swap instruments.

15

The following table presents the volumes, fair values and locations of the Company's derivative instruments recorded on the balance sheets:

Puget Energy and Puget Sound Energy	March 31, 2014					December 31, 2013
(Dollars in Thousands)	Volumes	Assets 1		Liabilities 2		Volumes	Assets 1		Liabilities 2
Interest rate swap derivatives 3	$450 million	$	—	$	12,126	$450 million	$	—	$	13,223
Electric portfolio derivatives	*	23,906		34,365		*	18,479		37,312
Natural gas derivatives (MMBtus) 4	380.5 million	27,803		14,166		423.5 million	8,121		35,676
Total derivative contracts		$	51,709	$	60,657		$	26,600	$	86,211
Current		$	44,889	$	33,213		$	18,867	$	48,049
Long-term		6,820		27,444			7,733		38,162
Total derivative contracts		$	51,709	$	60,657		$	26,600	$	86,211

___________

¹  Balance sheet location: Current and Long-term Unrealized gain on derivative instruments.

²  Balance sheet location: Current and Long-term Unrealized loss on derivative instruments.

³  Interest rate swap contracts are only held at Puget Energy.

⁴  All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations” (ASC 980) due to the PGA mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers.

^*  Electric portfolio derivatives consist of electric generation fuel of 129.3 million One Million British Thermal Units (MMBtus) and purchased electricity of 7.6 million Megawatt Hours (MWhs) at March 31, 2014, and 145.6 million MMBtus and 8.6 million MWhs at December 31, 2013.

For further details regarding the fair value of derivative instruments, see Note 3.

16

ASU 2013-01 requires disclosure of both gross and net information for recognized derivative assets and liabilities. It is the Company's policy to record all derivative transactions on a gross basis at the contract level, without offsetting assets or liabilities. The Company generally enters into transactions using the following master agreements: WSPP, Inc. (WSPP) agreements which standardize physical power contracts; International Swaps and Derivatives Association (ISDA) agreements which standardize financial gas and electric contracts; and North American Energy Standards Board (NAESB) agreements which standardize 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 as well as right of set-off in the event of counterparty default. The set-off provision can be used as a final settlement of accounts which extinguishes the mutual debts owed between the parties in exchange for a new net amount.

The following tables present the potential effect of netting arrangements, including rights of set-off associated with the Company's derivative assets and liabilities:

Puget Energy and Puget Sound Energy
March 31, 2014
	Gross Amount Recognized in the Statement of Financial Position 1		Gross Amounts Offset in the Statement of Financial Position		Net of Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position
(Dollars in Thousands)							Commodity Contracts			Cash Collateral Received/Posted		Net Amount
Assets
Energy Derivative Contracts	$	51,709	$	—	$	51,709	$	(26,319	)	$	—	$	25,390
Liabilities
Energy Derivative Contracts	$	48,531	$	—	$	48,531	$	(26,319	)	$	—	$	22,212
Interest Rate Swaps 2	$	12,126	$	—	$	12,126	$	—		$	—	$	12,126
Puget Energy and Puget Sound Energy
December 31, 2013
	Gross Amount Recognized in the Statement of Financial Position 1		Gross Amounts Offset in the Statement of Financial Position		Net of Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position
(Dollars in Thousands)							Commodity Contracts			Cash Collateral Received/Posted		Net Amount
Assets
Energy Derivative Contracts	$	26,600	$	—	$	26,600	$	(19,491	)	$	—	$	7,109
Liabilities
Energy Derivative Contracts	$	72,988	$	—	$	72,988	$	(19,491	)	$	—	$	53,497
Interest Rate Swaps 2	$	13,223	$	—	$	13,223	$	—		$	—	$	13,223

___________

¹  All Derivative Contract deals are executed under ISDA, NAESB and WSPP Master Netting Agreements with Right of Offset.

²  Interest Rate Swap Contracts are only held at Puget Energy.

Due to the merger in 2009, Puget Energy recorded all derivative contracts at fair value as either assets or liabilities. Certain contracts meeting the criteria defined in ASC 815 were subsequently designated as Normal Purchase Normal Sale (NPNS) or cash flow hedges, thereby causing differences in the derivative unrealized gains/losses to be recorded through earnings between Puget Energy and PSE. These differences will occur through February 2015.

17

The following tables present the effect and locations of the Company's derivatives not designated as hedging instruments, recorded on the statements of income:

Puget Energy		Three Months Ended March 31,
(Dollars in Thousands)	Location	2014			2013
Interest rate contracts:	Non-hedged interest rate swap (expense) income	$	(747	)	$	1,028
	Interest expense	(125		)	(2,578		)
Commodity contracts:
Electric derivatives	Unrealized gain (loss) on derivative instruments, net	7,839			75,692
	Electric generation fuel	7,827			(12,638		)
	Purchased electricity	5,383			(31,485		)
Total gain (loss) recognized in income on derivatives		$	20,177		$	30,019

Puget Sound Energy		Three Months Ended March 31,
(Dollars in Thousands)	Location	2014		2013
Commodity contracts:
Electric derivatives	Unrealized gain (loss) on derivative instruments, net	$	7,270	$	72,740
	Electric generation fuel	7,827		(12,638		)
	Purchased electricity	5,383		(31,485		)
Total gain (loss) recognized in income on derivatives		$	20,480	$	28,617

The unrealized gain or loss on derivative contracts is reported in the statement of cash flows under the operating activities section. However, at the time of the merger in 2009, all derivative contracts at Puget Energy were assessed to identify contracts that have a “more than an insignificant” fair value. If the fair value was greater than 10% of the notional value, the contract was deemed as having a financing element. For those contracts, the cash inflows (outflows) are presented in the financing activities section of the statement of cash flows. For the three months ended March 31, 2014 and 2013, cash outflows related to financing activities of $8.0 million and $26.0 million, respectively, were reported on the Puget Energy statement of cash flows.

For derivative instruments previously designated as cash flow hedges (including both commodity contracts and interest rate swaps), the effective portion of the gain or loss on the derivative was recorded as a component of Other Comprehensive Income (OCI), and then is reclassified into earnings in the same period(s) during which the hedged transaction affects earnings.

Puget Energy and PSE expect $0.5 million and $2.0 million of losses, respectively, in accumulated OCI will be reclassified into earnings within the next twelve months. The Company does not attempt cash flow hedging for any new transactions and records all mark-to-market adjustments through earnings.

18

The following tables present the Company's pre-tax gain (loss) of derivatives that were previously in a cash flow hedge relationship, and subsequently reclassified out of accumulated OCI into income:

Puget Energy		Three Months Ended March 31,
(Dollars in Thousands)	Location	2014			2013
Interest rate contracts:	Interest expense	$	(144	)	$	(1,314	)
Commodity contracts:
Electric derivatives	Electric generation fuel	—			—
	Purchased electricity	(534		)	164
Total		$	(678	)	$	(1,150	)

Puget Sound Energy		Three Months Ended March 31,
(Dollars in Thousands)	Location	2014			2013
Interest rate contracts:	Interest expense	$	(122	)	$	(122	)
Commodity contracts:
Electric derivatives	Electric generation fuel	—			—
	Purchased electricity	(1,104		)	(2,786		)
Total		$	(1,226	)	$	(2,908	)

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 distress. 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 could suffer a material financial loss. However, as of March 31, 2014, 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.

As the Company generally enters into transactions using the WSPP, ISDA and NAESB master agreements, it believes that such agreements reduce credit risk exposure because they 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 the 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 to derive 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. Credit reserves are booked as contra accounts to unrealized gain (loss) positions. As of March 31, 2014, the Company was in a net liability position with many of its counterparties, so the default factors of counterparties did not have a significant impact on reserves for the period. The majority of the Company's derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council. As of March 31, 2014, PSE has posted a $1.0 million letter of credit as a condition of transacting on a physical energy exchange and clearinghouse in Canada.

19

PSE did not trigger any collateral requirements with any of its counterparties, nor were any of PSE's counterparties required to post collateral resulting from credit rating downgrades.

The table below presents the fair value of the overall contractual contingent liability positions for the Company's derivative activity at March 31, 2014:

Puget Energy and Puget Sound Energy Contingent Feature	Fair Value 1			Posted		Contingent
(Dollars in Thousands)	Liability			Collateral		Collateral
Credit rating 2	$	(10,290	)	$	—	$	10,290
Requested credit for adequate assurance	(10,596		)	—		—
Forward value of contract 3	(1,931		)	—		—
Total	$	(22,817	)	$	—	$	10,290

__________

¹  Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions. 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 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.

(3) Fair Value Measurements

ASC 820 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.

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 measured at fair value are classified in their entirety in the appropriate fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. The Company primarily determines fair value measurements classified as Level 2 or Level 3 using a combination of the income and market valuation approaches. The process of determining the fair values is the responsibility of the derivative accounting department which reports to the Controller and Principal Accounting Officer. Inputs used to estimate the fair value of forwards, swaps and options include market-price curves; contract terms and prices; credit-risk adjustments; and discount factors. Additionally, for options, the Black-Scholes option valuation model and implied market volatility curves are used. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs because substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments. On a daily basis, the Company obtains quoted forward prices for the electric and natural gas market from an independent external pricing service. For interest rate swaps, the Company obtains monthly mark-to-market values from an independent external pricing service for London Interbank Offered Rate (LIBOR) forward rates, which is a significant input. Some of the inputs of the interest rate swap valuations, which are less significant, include the credit standing of the counterparties, assumptions for time value and the impact of the Company's nonperformance risk of its liabilities. The Company classifies cash and cash equivalents, and restricted cash as Level 1 financial instruments due to cash being at stated value, and cash equivalents at quoted market prices.

20

The Company considers its electric, natural gas and interest rate swap contracts as Level 2 derivative instruments as such contracts are commonly traded as over-the-counter forwards with indirectly observable price quotes. Management's assessment was based on the trading activity 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. However, certain energy derivative instruments with maturity dates falling outside the range of observable price quotes are classified as Level 3 in the fair value hierarchy.

Assets and Liabilities with Estimated Fair Value

The following table presents the fair value hierarchy by level, the carrying value for cash, cash equivalents, restricted cash, notes receivable and short-term debt. The carrying values below are representative of fair values due to the short-term nature of these financial instruments.

	Carrying / Fair Value						Carrying / Fair Value
Puget Energy	At March 31, 2014						At December 31, 2013
(Dollars in Thousands)	Level 1		Level 2		Total		Level 1		Level 2		Total
Assets:
Cash and Cash Equivalents	$	23,581	$	—	$	23,581	$	44,302	$	—	$	44,302
Restricted Cash	25,437		—		25,437		7,171		—		7,171
Notes Receivable and Other	—		54,542		54,542		—		53,449		53,449
Total assets	$	49,018	$	54,542	$	103,560	$	51,473	$	53,449	$	104,922
Liabilities:
Short-term debt	$	—	$	—	$	—	$	162,000	$	—	$	162,000
Total liabilities	$	—	$	—	$	—	$	162,000	$	—	$	162,000

	Carrying / Fair Value						Carrying / Fair Value
Puget Sound Energy	At March 31, 2014						At December 31, 2013
(Dollars in Thousands)	Level 1		Level 2		Total		Level 1		Level 2		Total
Assets:
Cash and Cash Equivalents	$	23,556	$	—	$	23,556	$	44,111	$	—	$	44,111
Restricted Cash	25,437		—		25,437		7,171		—		7,171
Notes Receivable and Other	—		54,542		54,542		—		53,449		53,449
Total assets	$	48,993	$	54,542	$	103,535	$	51,282	$	53,449	$	104,731
Liabilities:
Short-term debt	$	—	$	—	$	—	$	162,000	$	—	$	162,000
Short-term debt owed to parent	—		29,598		29,598		—		29,598		29,598
Total liabilities	$	—	$	29,598	$	29,598	$	162,000	$	29,598	$	191,598

21

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. Carrying values and estimated fair values were as follows:

Puget Energy		March 31, 2014				December 31, 2013
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Junior subordinated notes	2	$	250,000	$	280,137	$	250,000	$	269,366
Long-term debt (fixed-rate), net of discount	2	4,686,259		5,875,347		4,683,476		5,594,314
Long-term debt (variable-rate)	2	299,000		299,000		299,000		299,000
Total		$	5,235,259	$	6,454,484	$	5,232,476	$	6,162,680
Puget Sound Energy		March 31, 2014				December 31, 2013
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Junior subordinated notes	2	$	250,000	$	280,137	$	250,000	$	269,366
Long-term debt (fixed-rate), net of discount	2	3,513,258		4,239,741		3,513,258		4,038,455
Total		$	3,763,258	$	4,519,878	$	3,763,258	$	4,307,821

22

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:

Puget Energy	Fair Value						Fair Value
	At March 31, 2014						At December 31, 2013
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total
Interest rate derivative instruments	$	12,126	$	—	$	12,126	$	13,223	$	—	$	13,223
Total derivative liabilities	$	12,126	$	—	$	12,126	$	13,223	$	—	$	13,223

Puget Energy and	Fair Value						Fair Value
Puget Sound Energy	At March 31, 2014						At December 31, 2013
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	18,866	$	5,040	$	23,906	$	14,661	$	3,818	$	18,479
Natural gas derivative instruments	25,253		2,550		27,803		5,448		2,673		8,121
Total assets	$	44,119	$	7,590	$	51,709	$	20,109	$	6,491	$	26,600
Liabilities:
Electric derivative instruments	$	14,719	$	19,646	$	34,365	$	18,073	$	19,239	$	37,312
Natural gas derivative instruments	10,513		3,653		14,166		32,642		3,034		35,676
Total liabilities	$	25,232	$	23,299	$	48,531	$	50,715	$	22,273	$	72,988

The following table presents the Company's reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy:

Puget Energy and Puget Sound Energy	Three Months Ended March 31,
Level 3 Roll-Forward Net Asset/(Liability)	2014									2013
(Dollars in Thousands)	Electric			Gas			Total			Electric			Gas			Total
Balance at beginning of period	$	(15,421	)	$	(361	)	$	(15,782	)	$	(33,924	)	$	(1,602	)	$	(35,526	)
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings 1	(2,745		)	—			(2,745		)	1,598			—			1,598
Included in regulatory assets / liabilities	—			259			259			—			674			674
Settlements 2	321			(410		)	(89		)	6,384			(733		)	5,651
Transferred into Level 3	3,100			(585		)	2,515			(7,700		)	—			(7,700		)
Transferred out of Level 3	139			(6		)	133			7,200			127			7,327
Balance at end of period	$	(14,606	)	$	(1,103	)	$	(15,709	)	$	(26,442	)	$	(1,534	)	$	(27,976	)

_________

¹  Income Statement location: Unrealized (gain) loss on derivative instruments, net. Includes unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $(9.2) millionand $1.4 million for the three months ended March 31, 2014 and 2013, respectively.

² The Company had no purchases, sales 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.

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In order to determine which 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. The changes of fair value classification into or out of Level 3 are recognized each month, and reported in the Level 3 Roll-forward table above. The Company did not have any transfers between Level 2 and Level 1 during the reported periods. The Company does periodically transact at locations, or market price points, that are illiquid 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 for the Company's purchased commodity contracts, as of March 31, 2014:

(Dollars in Thousands)
	Fair Value						Range
Derivative Instrument	Assets 1		Liabilities 1		Valuation Technique	Unobservable Input	Low	High	Weighted Average
Electric	$	5,040	$	19,646	Discounted cash flow	Power Prices	$4.38 per MWh	$49.95 per MWh	$35.67 per MWh
Natural gas	$	2,550	$	3,653	Discounted cash flow	Natural Gas Prices	$3.62 per MMBtu	$4.63 per MMBtu	$4.04 per MMBtu

__________

¹  The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.

The significant unobservable inputs listed above would have a direct impact on the fair values of the above instruments if they were adjusted. Consequently significant increases or decreases in the forward prices of electricity or natural gas in isolation would result in a significantly higher or lower fair value for Level 3 assets and liabilities. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets. At March 31, 2014, 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 $12.1 million.

(4) 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.  Beginning January 1, 2014, all new UA employees and those new non-represented employees who elect to accumulate the Company contribution in the Cash Balance pension, will receive annual pay credits of 4% each year. They will also receive interest credits like other participants in the Cash Balance pension, which are at least 1% per quarter. When a newly-hired employee with a vested Cash Balance benefit leaves PSE, he or she will have annuity and lump sum options for distribution, with annuities calculated according to the Pension Protection Act. Those who select the lump sum option will receive their current cash balance amount. Participation by continuing employees in the Cash Balance pension plan is not affected.

In addition to providing pension benefits, PSE provides group health care and life insurance benefits for certain retired employees.  PSE also maintains a non-qualified Supplemental Executive Retirement Plan (SERP) for its key senior management 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 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 re-measurement 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, 2014 and 2013:

Puget Energy	Qualified Pension Benefits						SERP Pension Benefits					Other Benefits
	Three Months Ended March 31,
(Dollars in Thousands)	2014			2013			2014		2013			2014			2013
Components of net periodic benefit cost:
Service cost	$	4,512		$	4,709		$	261	$	375		$	29		$	34
Interest cost	7,055			6,194			577		511			183			176
Expected return on plan assets	(10,721		)	(9,851		)	—		—			(133		)	(108		)
Amortization of prior service cost	(495		)	(495		)	11		(4		)	—			—
Amortization of net loss (gain)	—			650			228		365			(66		)	17
Net periodic benefit cost	$	351		$	1,207		$	1,077	$	1,247		$	13		$	119

Puget Sound Energy	Qualified						SERP					Other
	Pension Benefits						Pension Benefits					Benefits
	Three Months Ended March 31,
(Dollars in Thousands)	2014			2013			2014		2013			2014			2013
Components of net periodic benefit cost:
Service cost	$	4,512		$	4,709		$	261	$	375		$	29		$	34
Interest cost	7,055			6,194			577		511			183			176
Expected return on plan assets	(10,919		)	(10,249		)	—		—			(133		)	(108		)
Amortization of prior service cost	(393		)	(393		)	11		(4		)	1			8
Amortization of net loss (gain)	3,239			5,085			365		548			(143		)	(34		)
Net periodic benefit cost	$	3,494		$	5,346		$	1,214	$	1,430		$	(63	)	$	76

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The following table summarizes the Company’s change in benefit obligation for the periods ended March 31, 2014 and December 31, 2013:

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, 2014			December 31, 2013			March 31, 2014			December 31, 2013			March 31, 2014			December 31, 2013
Change in benefit obligation:
Benefit obligation at beginning of period	$	573,317		$	616,290		$	47,279		$	51,795		$	14,939		$	17,672
Service cost	4,512			19,285			261			1,498			29			134
Interest cost	7,055			24,754			577			2,045			183			664
Amendment	—			—			—			478			—			—
Actuarial loss/(gain)	—			(48,559		)	—			(1,687		)	—			(2,240		)
Benefits paid	(10,001		)	(38,453		)	(460		)	(6,850		)	(391		)	(1,536		)
Medicare part D subsidiary received	—			—			—			—			42			245
Benefit obligation at end of period	$	574,883		$	573,317		$	47,657		$	47,279		$	14,802		$	14,939

The aggregate expected contributions by the Company to fund the qualified pension plan, SERP and the other postretirement plans for the year ending December 31, 2014 are expected to be at least $12.0 million, $4.0 million and $0.4 million, respectively. During the three months ended March 31, 2014, the Company contributed $3.0 million, $0.5 million, and $0.2 million to fund the qualified pension plan, SERP and the other postretirement plan, respectively.

(5) Regulation and Rates

On January 31, 2013, the Washington Commission approved a rate change to PSE's Federal Incentive Tracker tariff, effective February 1, 2013, which incorporated the effects of the Treasury Grant related to the Lower Snake River wind generation project and keeping the ten year amortization period and inclusion of interest on the unamortized balance of the grants. The rate change will pass through eleven months of amortization for both grants to eligible customers beginning February 1, 2013, including grant amortization pass-back of $34.6 million and interest pass-back of $23.8 million. This represents an overall average rate decrease of 2.76%.

On June 25, 2013, the Washington Commission approved PSE's electric and natural gas decoupling mechanism and expedited rate filing (ERF) tariff filings, effective July 1, 2013. The estimated revenue impact of the decoupling mechanism is an increase for electric of $21.4 million, or 1.0% annually, and an increase for natural gas of $10.8 million, or 1.1% annually. The allowed decoupling revenue per customer for the recovery of delivery system costs will subsequently increase by 3.0% for the electric customers and 2.2% for the gas customers on January 1 of each year, until the conclusion of PSE's next general rate case.

The estimated revenue impact of the ERF filings is an increase for electric of $30.7 million, or 1.5% annually, while the revenue impact for natural gas is a decrease of $2.0 million, or a decrease of 0.2% annually. The ERF filings also provided for the collection of property taxes through a property tax tracker mechanism. The property tax rate tracker will initially produce no incremental revenue, but is intended to reduce regulatory lag associated with the recovery of future increases in property tax expenses. PSE's 2012 and 2013 property taxes that are not in current rates will be recovered in later years. In its order, the Washington Commission approved a weighted cost of capital of 7.77% and a capital structure that included 48.0% common equity with a return on equity of 9.8%.

Subsequently, certain parties to this proceeding petitioned the Washington Commission to reconsider the order. On December 13, 2013, the Washington Commission approved the settlement agreements for rates effective January 1, 2014. These settlement agreements do not materially change the revenues originally approved in June 2013. As a result, certain high volume natural gas industrial customers' rate schedules are excluded from the decoupling mechanism and will be subject to certain effects of abnormal weather, conservation impacts and changes in customer usage patterns.

On July 24, 2013, the Public Counsel Division of the Washington State Attorney General's Office (Public Counsel) and the Industrial Customers of Northwest Utilities (ICNU) each filed a petition in Thurston County Superior Court (the Court) seeking

26

judicial reviews of various aspects of the Washington Commission's ERF and decoupling mechanism final order. The parties' petition argues that the order violates various procedural and substantive requirements of the Washington Administrative Procedure Act, and so requests that it be vacated and that the matter be remanded to the Washington Commission. Oral arguments regarding this matter are scheduled for May 9, 2014.

On October 23, 2013, the Washington Commission approved an update on the Company's power cost only rate case (PCORC), effective November 1, 2013, which reflected decreases in the overall normalized power supply costs. This resulted in an estimated revenue decrease of $10.5 million or 0.5% annually.

On October 30, 2013, the Washington Commission approved PSE's PGA natural gas tariff, effective November 1, 2013, which reflected changes in wholesale gas and pipeline transportation costs and changes in deferral amortization rates. The estimated revenue impact of the approved change is an increase of $4.0 million, or 0.4% annually, with no impact on net operating income.

On October 30, 2013, the Washington Commission approved PSE's Pipeline Replacement Program Plan (PRPP) that would accelerate and enhance the safety of the natural gas system and ultimately reduce costs. Under the PRPP plan, PSE would be allowed to file a tariff revision to recover its costs associated with the acceleration of the replacement of natural gas pipelines with the Washington Commission.

On December 27, 2013, the Washington Commission approved the annual true-up and rate filing to the PSE's Federal Incentive Tracker tariff, effective January 1, 2014. The true-up filing resulted in a total credit of $58.5 million to be passed back to eligible customers over the twelve months beginning January 1, 2014. Of the total credit, $37.8 million represents the pass-back of grant amortization and $20.6 million represents the pass through of interest, in addition to a minor true-up associated with the 2013 rate period. This filing represents an overall average rate increase of 0.26% as compared to the previous rate.

On April 24, 2014, the Washington Commission approved PSE’s request to change rates under its electric and natural gas decoupling mechanism, effective May 1, 2014.  The rate change incorporated the effects of an increase to the allowed delivery revenue per customer as well as true-ups to the rate from the prior year.  This represents a rate increase for electric of $10.6 million, or 0.5% annually, and a rate decrease for natural gas of $1.0 million, or 0.1% annually.  

On April 24, 2014, the Washington Commission also approved PSE’s request to change rates under its electric and natural gas property tax tracker mechanism, effective May 1, 2014.  The rate change incorporated the effects of an increase in the amount of property taxes paid as well as true-ups to the rate from the prior year.  This represents a rate increase for electric of $11.0 million, or 0.5% annually, and a rate increase for natural gas of $5.6 million, or 0.6% annually.  

(6) Litigation

Residential Exchange

The Northwest Power Act, through the Residential Exchange Program (REP), provides access to the benefits of low-cost federal power for residential and small farm customers of regional utilities, including PSE.  The program is administered by the Bonneville Power Administration (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 United States Court of Appeals for the Ninth Circuit (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 fiscal year 2002 through fiscal year 2011 period 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 (2012 REP Settlement) that by its terms, if upheld in its entirety, would resolve the disputes between BPA and PSE regarding REP benefits paid for fiscal years 2002-2011 and determine REP benefits for fiscal years 2012-2028.  In October 2011, certain other parties challenged BPA decisions with regard to its entering into the 2012 REP Settlement agreement.  On October 28, 2013, the Ninth Circuit issued an order dismissing this challenge to this settlement. In light of the disposition of this challenge, the stay of the other pending Ninth Circuit litigation regarding REP benefits was lifted in January 2014. In the order lifting the stay, petitioners (unless they move to voluntarily dismiss their petitions) and intervenors (unless they move to voluntarily withdraw) were directed to file a statement explaining which issues, if any, remain pending. Subsequent to the order lifting the stay, in February 2014, one group of petitioners in the other pending Ninth Circuit litigation moved to dismiss its petition and its motion was granted. Two of the remaining petitioners may seek dismissal of their petitions, but other remaining petitioners have not submitted such a motion but rather have stated to the Ninth Circuit that they are pursuing certain claims. PSE is unable to determine what impact these proceedings 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 directly to REP customers.

With the Ninth Circuit’s decision affirming the 2012 REP Settlement, PSE will receive $62.9 million in REP payments owed under a 2008 agreement, which are in addition to scheduled monthly REP benefits received from BPA under the 2012 REP

27

Settlement. These payments will be given back to PSE's residential and small farm customers through a higher residential exchange credit.

Colstrip

PSE has a 50% ownership interest in Colstrip Units 1 and 2, and a 25% interest in Colstrip Units 3 and 4. On March 6, 2013, Sierra Club and Montana Environmental Information Center (MEIC) filed a Clean Air Act citizen suit against all Colstrip owners (including PSE) alleging numerous claims for relief, most which relate to alleged prevention of significant deterioration (PSD) violations. One claim relates to the alleged failure to update the Title V permit to reflect the major modifications alleged in the first thirty-six claims, another claim alleges that the previous Title V compliance certifications have been incomplete because they did not address the alleged major modifications, and the last claim alleges opacity violations since 2007. The lawsuit was filed in U.S. District of Montana, Billings Division, requesting injunctive relief and civil penalties, including a request that the owners remediate environmental damage and that $100,000 of the civil penalties be used for beneficial mitigation projects. This lawsuit followed various Notices of Intent to Sue sent to Colstrip owners (including PSE) from the Sierra Club and the MEIC between July and December 2012.  Discovery in the case has begun, and the case has been bifurcated into separate liability and remedy trials. The liability trial is currently set for June 2015, and a date for the remedy trial has yet to be determined. PSE is litigating the allegations set forth in the notices and cannot at this time 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 $1.36 million and $1.38 million relating to these claims as of March 31, 2014 and December 31, 2013, respectively.

(7) Accumulated Other Comprehensive Income (Loss)

The following tables present the changes in the Company’s accumulated other comprehensive income (loss) (AOCI) by component for the three months ended March 31, 2014:

Puget Energy	Net unrealized gain (loss) and prior service cost on pension plans			Net unrealized gain (loss) on energy derivative instruments			Net unrealized gain (loss) on interest rate swaps
Changes in AOCI, net of tax
(Dollars in Thousands)										Total
Balance at December 31, 2013	$	48,514		$	(705	)	$	(94	)	$	47,715
Other comprehensive income (loss) before reclassifications	—			—			—			—
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	(209		)	347			94			232
Net current-period other comprehensive income (loss)	(209		)	347			94			232
Balance at March 31, 2014	$	48,305		$	(358	)	$	—		$	47,947

Puget Sound Energy	Net unrealized gain (loss) and prior service cost on pension plans			Net unrealized gain (loss) on energy derivative instruments			Net unrealized gain (loss) on treasury interest rate swaps
Changes in AOCI, net of tax
(Dollars in Thousands)										Total
Balance at December 31, 2013	$	(87,405	)	$	(2,027	)	$	(6,307	)	$	(95,739	)
Other comprehensive income (loss) before reclassifications	—			—			—			—
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	2,001			718			79			2,798
Net current-period other comprehensive income (loss)	2,001			718			79			2,798
Balance at March 31, 2014	$	(85,404	)	$	(1,309	)	$	(6,228	)	$	(92,941	)

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Details about these reclassifications out of accumulated other comprehensive income (loss) for the three months ended March 31, 2014 and March 31, 2013, respectively, are as follows:

Puget Energy		Three Months Ended			Three Months Ended
(Dollars in Thousands)		March 31, 2014			March 31, 2013
Details about accumulated other comprehensive income (loss) components	Affected line item in the statement where net income (loss) is presented	Amount reclassified from accumulated other comprehensive income (loss)
Net unrealized gain (loss) and prior service cost on pension plans:
Amortization of prior service cost	(a)	484			499
Amortization of net gain (loss)	(a)	(162		)	(1,032		)
	Total before tax	322			(533		)
	Tax (expense) or benefit	(113		)	186
	Net of Tax	$	209		$	(347	)
Net unrealized gain (loss) on energy derivative instruments:
Commodity contracts: electric derivatives	Purchased electricity	(534		)	164
	Tax (expense) or benefit	187			(57		)
	Net of Tax	$	(347	)	$	107
Net unrealized gain (loss) on interest rate swaps:
Interest rate contracts	Interest expense	$	(144	)	$	(1,314	)
	Tax (expense) or benefit	50			460
	Net of Tax	$	(94	)	$	(854	)
Total reclassification for the period	Net of Tax	$	(232	)	$	(1,094	)

__________

^(a)  These accumulated other comprehensive income components are included in the computation of net periodic pension cost (see Note 4 for additional details).

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Puget Sound Energy		Three Months Ended			Three Months Ended
(Dollars in Thousands)		March 31, 2014			March 31, 2013
Details about accumulated other comprehensive income (loss) components	Affected line item in the statement where net income (loss) is presented	Amount reclassified from accumulated other comprehensive income (loss)
Net unrealized gain (loss) and prior service cost on pension plans:
Amortization of prior service cost	(a)	$	381		$	389
Amortization of net gain (loss)	(a)	(3,461		)	(5,599		)
	Total before tax	(3,080		)	(5,210		)
	Tax (expense) or benefit	1,079			1,824
	Net of Tax	$	(2,001	)	$	(3,386	)
Net unrealized gain (loss) on energy derivative instruments:
Commodity contracts: electric derivatives	Purchased electricity	(1,104		)	(2,786		)
	Tax (expense) or benefit	386			975
	Net of Tax	$	(718	)	$	(1,811	)
Net unrealized gain (loss) on treasury interest rate swaps:
Interest rate contracts	Interest expense	(122		)	(122		)
	Tax (expense) or benefit	43			43
	Net of Tax	$	(79	)	$	(79	)
Total reclassification for the period	Net of Tax	$	(2,798	)	$	(5,276	)

__________

^(a)  These accumulated other comprehensive income components are included in the computation of net periodic pension cost (see Note 4 for additional details).

(8) Other

Jefferson County Public Utility District (JPUD)

PSE completed the sale of its electric infrastructure assets located in Jefferson County and the transition of electrical services in the county to JPUD on March 31, 2013. The proceeds from the sale exceeded the transferred assets' net carrying value of $46.7 million resulting in a pre-tax gain of approximately $60.0 million. In its 2010 order on the subject, the Washington Commission stated that PSE must file an accounting and ratemaking petition with the Washington Commission to determine how this gain will be allocated between customers and shareholders. As a result, the gain was deferred and recorded as a regulatory liability until the Washington Commission determines the accounting and ratemaking treatment. On October 31, 2013, PSE filed an accounting petition for a Washington Commission order that authorizes PSE to retain the gain of $45.0 million and return $15.0 million to its remaining customers over a period of forty-eight months. On March 28, 2014, intervenors filed response testimonies containing their respective proposals for allocation of the gain, which included a proposal of up to $57.0 million to customers and $3.0 million to PSE. The Washington Commission will hold evidentiary hearings in this matter beginning May 21, 2014.

For federal income tax purposes, the Company will elect to treat the transaction as an involuntary conversion under the Internal Revenue Code which allows for deferral of the tax gain if PSE acquires qualified replacement property by December 31, 2015. Based on PSE's current construction program projection, it anticipates meeting this requirement through such purchases by that date.

Bond Issuances

On May 23, 2013, PSE refinanced $161.9 million of its Pollution Control Revenue Refunding Bonds (the Bonds) to a lower weighted average interest rate from 5.01% to 3.91%. The Bonds will mature on March 1, 2031. On or after March 1, 2023, the Company may elect to call the bonds at a redemption price of 100% of the principal amount thereof, without premium, plus accrued interest, if any, to the redemption date. Due to the refinance of the Bonds, Puget Energy wrote off $18.0 million of fair value related to the Bonds that were redeemed to interest expense. 

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Credit Facilities

In April 2014, subsequent to the close of the first quarter, the Company completed a one-year extension on both of the liquidity and hedging facilities of PSE, extending the maturity from February 2018 to April 2019. All other terms and conditions of the facilities remain unchanged from when they were committed in 2013. At this same time, the Company completed a one-year extension on the senior secured credit facility of Puget Energy, extending the maturity from February 2017 to April 2018. There were no significant changes to other terms and conditions.

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 and 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” included elsewhere in this report and in the section entitled "Risk Factors" included in Part I, Item 1A in Puget Energy's and Puget Sound Energy's Form 10-K for the period ended December 31, 2013. 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. In 2009, Puget Holdings completed its merger with Puget Energy. Puget Holdings is owned by a consortium of long-term infrastructure investors including Macquarie Infrastructure Partners I, Macquarie Infrastructure Partners II, Macquarie Capital Group Limited, FSS Infrastructure Trust, the Canada Pension Plan Investment Board, 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.”

The Company's mission is to be a safe, dependable, and efficient utility. The Company's objectives are to focus on safety, employees, operational excellence, customer service and financial strength. The Company's strategies are aligned to achieve the objectives and ultimately the Company's mission.

These commitments and investments related to utility infrastructure and customer service may give rise to expenditures that may not be recovered timely through the ratemaking process.  PSE has undertaken several initiatives to reduce the volatility and regulatory lag in the business. During 2013, PSE completed an ERF, which is a limited scope rate proceeding, and established a decoupling mechanism for gas operations and electric transmission, distribution and administrative costs. The ERF proceeding established baseline rates on which the decoupling mechanism will operate on going forward. The ERF also established a property tax tracker mechanism in which any difference between amounts in rates and property tax valuation accruals will be deferred and recovered in an annual filing based on the annual cash payments for the year.

The decoupling mechanism allows PSE to recover costs on a per customer basis rather than on a consumption basis. Included in the decoupling petition was a rate plan that allowed PSE to earn its rate of return over the rate plan period. The rate plan included predetermined annual increases to PSE’s allowed electric and natural gas revenue. This plan, with limited exceptions (Power Cost Only Rate Cases (PCORC) or emergency rate relief), requires PSE to file a general rate case no sooner than April 1, 2015 and no later than April 1, 2016. The decoupling mechanism also allows for decoupling revenue on a per customer basis to subsequently

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increase by 3.0% for electric customers and 2.2% for natural gas customers on January 1 on each year, until the conclusion of PSE’s next general rate case.

In October 2013, PSE completed a power cost only rate case (PCORC) filing which allows PSE to recovery certain generation investments and updates PSE’s overall normalized power supply costs. As a result, PSE decreased electric rates by $10.5 million, annually, effective November 1, 2013.

In October 2013, PSE received approval of its pipeline integrity program that would accelerate and enhance the safety of the natural gas system and ultimately reduce costs. Under the plan, PSE would be allowed to file a tariff revision to recover its costs associated with the acceleration of the replacement of natural gas pipelines with the Washington Commission.

Washington state law also requires PSE to pursue conservation initiatives that promote efficient use of energy. PSE’s mandate to pursue conservation initiatives may have a negative impact on the electric business financial performance due to lost margins from lower sales volumes as power costs are not part of the decoupling mechanism. This mandate, however, will only have a slight negative impact on natural gas business financial performance due to the natural gas business being almost fully decoupled. 

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. PSE is currently in balance between its load and generation equipments for the next couple of years. 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, 2014, as compared to the same period in 2013, PSE's net income was affected primarily by the following factors: (1) a decrease in unrealized gain in derivatives instruments for energy contracts; (2) an increase in operations and maintenance expense; and (3) an increase in electric margin and gas margin.

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 2014 and future years. Because PSE intends to seek recovery of these 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 reduces 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	PSE’s ability to manage costs during the rate stay out period through March 31, 2016;
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	Equal sharing between PSE and its customers of earnings which exceed PSE's authorized rate of return;
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;
Ÿ	Wholesale commodity prices of electricity and natural gas;
Ÿ	Increasing depreciation; 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 Commission. The Washington Commission has traditionally required that 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 have not provided 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 currently allowed to be recovered in rates, revenue may not be sufficient to permit PSE to earn its allowed return. In addition, the Washington

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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.

Recent Rate Proceedings

On December 27, 2013, the Washington Commission approved the annual true-up and rate filing to the PSE's Federal Incentive Tracker tariff, effective January 1, 2014. The true-up filing resulted in a total credit of $58.5 million to be passed back to eligible customers over the twelve months beginning January 1, 2014. Of the total credit, $37.8 million represents the pass-back of grant amortization and $20.6 million represents the pass through of interest, in addition to a minor true-up associated with the 2013 rate period. This filing represents an overall average rate increase of 0.26%.

Expedited Rate Filing (ERF). On February 4, 2013, PSE filed revised tariffs seeking to update its rates established in its base rate proceedings in May 2012 known as an ERF. The ERF was limited in scope and rate impact. This filing was primarily intended to establish baseline rates on which the decoupling mechanisms, described below, are proposed to operate. The filing also provided for the collection of property taxes through a property tax tracker mechanism based on cash payments of property tax made by PSE during the year. Any difference between the amounts in rates and property tax valuation accruals will be deferred and recovered in a property tax tracker based on the annual cash payments for the year.

Decoupling. On October 25, 2012, PSE and the Northwest Energy Coalition (NWEC) filed a petition for an order seeking approval of an electric and a natural gas decoupling mechanism for the recovery of its delivery-system costs and authority to record accounting entries associated with the mechanisms. After the petition and supporting testimony were filed, the Washington Commission held two technical conferences to allow interested stakeholders to further discuss the proposed decoupling mechanisms. PSE also responded to inquiries of interested stakeholders seeking additional information about the decoupling proposal.     

On March 4, 2013, PSE and NWEC, taking this process into account, reached an agreement on certain modifications to the decoupling mechanisms and filed an amended petition and testimony in support of these modifications to the original decoupling proposal. The Washington Commission's regulatory staff (Commission Staff) filed testimony in support of the revised proposal on the same day. Included in the amended decoupling petition was a rate plan that allows PSE an opportunity to earn its authorized rate of return without the need for another general rate case process over the plan period. The rate plan includes predetermined annual increases (K factor) to PSE's allowed electric and gas revenue which are effective January of each year. Under this plan, PSE, with limited exceptions, would be allowed to file its next general rate case no sooner than April 1, 2015 and no later than April 1, 2016 unless agreed to otherwise by the parties. PSE would continue to be authorized to file for rate changes under existing rate mechanisms such as the PCA and PGA mechanism, and emergency rate relief during the rate plan period.

PSE's rates related to the cumulative deferred decoupling mechanism accrued by each rate group through the calendar year and effective May 1 in the following year will be subject to a 3.0% “soft cap” on rate increases. Any amount in excess of the soft cap will be added to the decoupling tracker in subsequent rate periods, subject to a 3.0% soft cap on rate increases in the subsequent year. In addition, PSE and the customers would have shared 50.0% each in any earnings in excess of the authorized rate of return of 7.77%. The customer's share of any over earnings will be returned to customers over the subsequent 12 month period beginning May 1 of each year.

Washington Commission Decision. PSE filed a settlement agreement with the Washington Commission on March 22, 2013. The agreement was intended to settle all issues regarding decoupling, the power purchase agreement with TransAlta Centralia and the ERF which included the property tax tracker. The Washington Commission placed these filings under a common procedural schedule. On June 25, 2013, the Washington Commission issued three final orders resolving the amended decoupling petition, the ERF filing and the Petition for Reconsideration. One of the orders rejected the multi-party settlement agreement between PSE, NWEC and Commission Staff due to uncertainty regarding the legality of approving a settlement that would resolve multiple filings. An order also approved PSE's ERF filing with a small change to its cost of capital from 7.80% to 7.77% to update long term debt costs. The second order approved the property tax tracker discussed above. In addition, this order approved the amended decoupling and rate plan filing as filed by PSE and NWEC on March 4, 2013 with the requirement that PSE update the underlying ERF rates for the change in cost of capital, and with the further condition that PSE and the customers will share 50.0% each in earnings in excess of the 7.77% authorized rate of return. The third order granted in part, and denied in part, PSE’s Petition for Reconsideration with respect to the power purchase agreement with Transalta, clarifying certain portions of the Washington Commission’s original order.

The property tax rate tracker will reduce regulatory lag associated with the recovery of future increases in property tax expenses. PSE's property taxes which are not in current rates will be recovered in later years. The allowed decoupling revenue per customer for the recovery of delivery system costs will subsequently increase by 3.0% for the electric customers and 2.2% for the gas customers on January 1 of each year, until the conclusion of PSE's next general rate case.

Subsequently, certain parties to this proceeding petitioned the Washington Commission to reconsider the order. On December 13, 2013, the Washington Commission approved the settlement agreements for rates effective January 1, 2014. These settlement

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agreements do not materially change the revenues originally approved in June 2013. As a result, certain high volume natural gas industrial customers rate schedules are excluded from the decoupling mechanism and will be subject to certain effects of abnormal weather, conservation impacts and changes in customer usage patterns.

On July 24, 2013, the Public Counsel Division of the Washington State Attorney General's Office (Public Counsel) and the Industrial Customers of Northwest Utilities (ICNU) each filed a petition in Thurston County Superior Court (the Court) seeking judicial review of various aspects of the Washington Commission's ERF and decoupling mechanism final order. The parties' petition argues that the order violates various procedural and substantive requirements of the Washington Administrative Procedure Act, and so requests that it be vacated and that the matter be remanded to the Washington Commission. Oral arguments regarding this matter are scheduled for May 9, 2014.

On April 24, 2014, the Washington Commission approved PSE’s request to change rates under its electric and natural gas decoupling mechanism, effective May 1, 2014.  The rate change incorporated the effects of an increase to the allowed delivery revenue per customer as well as true-ups to the rate from the prior year.  This represents a rate increase for electric of $10.6 million, or 0.5% annually, and a rate decrease for natural gas of $1.0 million, or 0.1% annually.  

On April 24, 2014, the Washington Commission also approved PSE’s request to change rates under its electric and natural gas property tax tracker mechanism, effective May 1, 2014.  The rate change incorporated the effects of an increase in the amount of property taxes paid as well as true-ups to the rate from the prior year.  This represents a rate increase for electric of $11.0 million, or 0.5% annually, and a rate increase for natural gas of $5.6 million, or 0.6% annually.  

Electric Rates

PSE has a 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 an unfavorable PCA imbalance for the three months ended March 31, 2014, which was $19.0 millionabove the “power cost baseline” level, of which no amount was apportioned to customers. This compares to a favorable imbalance for the three months ended March 31, 2013 of $15.3 million, of which no amount was apportioned to customers.

Power Cost Only Rate Case (PCORC). On October 23, 2013, the Washington Commission approved an update on the Company's PCORC, effective November 1, 2013, which reflected decreases in the overall normalized power supply costs. This resulted in an estimated revenue decrease of $10.5 million or 0.5% annually.

As discussed above, the Washington Commission approved rate increases related to the recovery of PSE's electric delivery system costs. The following table sets forth the associated electric 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 Rates (Dollars in Millions)
Decoupling Rate Filing	May 1, 2014	0.5	%	$	10.6
Property Tax Tracker	May 1, 2014	0.5		11.0
PCORC	November 1, 2013	(0.5	)	(10.5		)
Decoupling Rate Filing	July 1, 2013	1.0		21.4
Expedited Rate Filing	July 1, 2013	1.5		30.7

In addition, PSE will be increasing the allowed delivery revenue per customer under the ERF filing by 3.0% for electric customers on January 1 of each year until the conclusion of PSE's next general rate case.

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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 these natural gas costs 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.

On October 30, 2013, the Washington Commission approved PSE's PGA natural gas tariff, effective on November 1, 2013, which reflected changes in wholesale gas and pipeline transportation costs and changes in deferral amortization rates. The estimated revenue impact of the approved change is an increase of $4.0 million, or 0.4% annually, with no impact on net operating income.

On October 30, 2013, the Washington Commission approved PSE's Pipeline Replacement Program Plan (PRPP) that would accelerate and enhance the safety of the natural gas system and ultimately reduce costs. Under the PRPP plan, PSE would be allowed to file a tariff revision to recover its costs associated with the acceleration of the replacement of natural gas pipelines with the Washington Commission.

As discussed above, the Washington Commission approved rate increases related to the recovery of PSE's gas delivery system costs. The following table sets forth the associated natural gas rate adjustments, including those for the PGA, that were 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 Rates (Dollars in Millions)
Decoupling Rate Filing	May 1, 2014	(0.1	)%	$	(1.0	)
Property Tax Tracker	May 1, 2014	0.6		5.6
Purchased Gas Adjustment	November 1, 2013	0.4		4.0
Decoupling Rate Filing	July 1, 2013	1.1		10.8
Expedited Rate Filing	July 1, 2013	(0.2	)	(2.0		)

In addition, PSE will be increasing the allowed delivery revenue per customer under the ERF filing by 2.2% for natural gas customers on January 1 of each year until the conclusion of PSE's next general rate case.

Weather Conditions. Weather conditions in PSE's service territory have a significant impact on customer energy usage, affecting PSE's billed 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 lower customer usage in the three months ended March 31, 2014, primarily due to Pacific Northwest temperatures being warmer on average as compared to the same period in the prior year. The actual average temperature during the three months ended March 31, 2014 was 45.34 degrees, or 1.90 degrees warmer than the same period in the prior year, and 1.35 degrees warmer when compared to the historical average.

Revenue Decoupling. While fluctuations in weather conditions will continue to affect PSE's billed revenue and energy supply expenses from month to month, PSE's decoupling mechanisms which went into effect on July 1, 2013 for electric and gas operations, will greatly diminish the impact of weather on operating revenue and net income. The Washington Commission has allowed PSE to record a monthly adjustment to its electric and gas operating revenues related to electric transmission and distribution, gas operations and general administrative costs from residential, commercial and industrial customers to eliminate the effects of abnormal weather, conservation impacts and changes in usage patterns per customer with the exception of the electric business where power costs are not part of the decoupling mechanism. As a result, these electric and gas revenues will be recovered on a per customer basis regardless of actual consumption levels. The energy supply costs, which are part of the PCA and PGA mechanisms, are not included in the decoupling mechanism. The revenue recorded under the decoupling mechanisms will be affected by customer growth and not actual consumption. Following each calendar year, PSE will bill or refund the difference between allowed decoupling revenue and the corresponding actual revenue to affected customers during the following May to April time period.

Effective January 1, 2014, certain high volume natural gas industrial customers' rate schedules are excluded from the decoupling mechanism. As a result, PSE will be subject to certain effects of abnormal weather, conservation impacts and changes in customer usage patterns for these customers.

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

Access to Debt Capital. PSE relies on access to bank borrowings and short-term money markets as sources of liquidity and longer-term capital 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 increase as their respective credit ratings decline due to increases in credit spreads and commitment fees. 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 2019 and Puget Energy's senior secured credit facility expires in 2018. (See discussion on credit facilities in the section entitled “Financing Program - Credit Facilities and Commercial Paper”).

Regulatory Compliance Costs and Expenditures. PSE's operations are subject to extensive federal, state and local laws and regulations. These 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

Competition. PSE’s electric and natural gas utility retail customers currently do not have the ability to choose their electric or natural gas supplier and therefore, PSE’s business has historically been recognized as a natural monopoly. However, PSE faces increasing competition for sales to its retail customers.  Alternative methods of electric energy generation, including solar and other self-generation methods, compete with PSE for sales to existing electric retail customers.  In addition, PSE’s natural gas customers may elect to use heating oil, propane or other fuels instead of using and purchasing natural gas from PSE.  Further, PSE faces competition from public utility districts and municipalities that want to establish their own municipal-owned utility, as a result of which PSE may lose a number of customers in its service territory.

Energy Supply. As noted in PSE's Integrated Resource Plan (IRP) filed with the Washington Commission, PSE projects that beginning in 2017, its future energy needs will exceed current resources in its supply portfolio.  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.

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.

PSE owns a 25% share of Colstrip Unit 4 coal fired plant in eastern Montana. PSE's share of the unit's net maximum capacity is 185.0 Megawatt (MWs). On July 1, 2013, Colstrip Unit 4 was tripped off-line.  Upon inspection of the unit, significant damage

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was observed to the generator which required repairs to the stator, core and rotor. The unit was returned to service in February 2014. PSE's share of the repair costs, which are capital expenditures, was $8.0 million. The repair costs for the plant are covered by insurance and are subject to PSE's share of the deductible of $0.6 million. In addition, power costs increased approximately $2.4 million in 2014. The power costs are subject to the PCA mechanism sharing bands, of which PSE's share of the cost increase was $2.4 million.

Grant County PUD Purchase Power Contract. On February 27, 2014, Grant County PUD discovered a sixty-five foot long, two inch wide crack in a spillway pier at its Wanapum Development Project. PSE is party to a purchased power contract with Grant County PUD, pursuant to which PSE takes 0.8% of the output from the project and pays a proportional share of the operating cost of the project. Grant County PUD has lowered the reservoir level 26 feet below normal for the foreseeable future which also impacts the operations of Chelan County PUD Rock Island Project which is upstream from Wanapum Development Project. An engineering assessment of the crack repairs and water flow protocols are in the early stages of development and it is not possible to predict crack repair nor replacement power costs, if any, at this time. Any additional power cost increases are subject to the Company’s PCA mechanism sharing bands.

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 and carbon financial instruments. The Company supports the development of regional and national markets for these products that are open, transparent and liquid.

IBEW Contract. The term of PSE and the International Brotherhood of Electrical Workers Local Union 77 (IBEW) contract expired on March 31, 2014.  Since the expiration, the IBEW has been working without a contract.  PSE extended an offer to the IBEW, which PSE believes enables PSE to attract and retain a highly skilled workforce to safely and efficiently perform their duties.

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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 which impacted PSE's results of operations:

	Three Months Ended March 31,
Puget Sound Energy (Dollars in Thousands)	2014			2013			Favorable/ (Unfavorable)
Operating revenue:
Electric
Residential sales	$	358,843		$	360,918		(0.6	)%
Commercial sales	229,084			225,956			1.4
Industrial sales	27,035			26,810			0.8
Other retail sales, including unbilled revenue	(25,391		)	(11,282		)	*
Total retail sales	589,571			602,402			(2.1	)
Transportation sales	1,988			1,846			7.7
Sales to other utilities and marketers	14,040			8,986			56.2
Decoupling revenue	12,677			—			*
Other	15,277			1,400			*
Total electric operating revenue	633,553			614,634			3.1
Gas
Residential sales	265,407			261,184			1.6
Commercial sales	104,770			106,557			(1.7	)
Industrial sales	8,791			9,718			(9.5	)
Total retail sales	378,968			377,459			0.4
Transportation sales	4,265			4,061			5.0
Decoupling revenue	787			—			*
Other	3,423			3,245			5.5
Total gas operating revenue	387,443			384,765			0.7
Non-utility operating revenue	4,379			308			*
Total operating revenue	1,025,375			999,707			2.6
Operating expenses:
Energy costs
Purchased electricity	181,157			175,043			(3.5	)
Electric generation fuel	75,436			59,087			(27.7	)
Residential exchange	(30,003		)	(22,551		)	33.0
Purchased gas	191,306			189,983			(0.7	)
Net unrealized (gain) loss on derivative instruments	(7,270		)	(72,740		)	*
Utility operations and maintenance	144,076			129,235			(11.5	)
Non-utility expense and other	6,177			3,091			(99.8	)
Depreciation	91,184			88,178			(3.4	)
Amortization	10,535			5,744			(83.4	)
Conservation amortization	28,982			34,107			15.0
Taxes other than income taxes	100,818			99,943			(0.9	)
Total operating expenses	792,398			689,120			(15.0	)
Operating income (loss)	232,977			310,587			(25.0	)
Other income	4,240			12,012			(64.7	)
Other expense	(1,582		)	(1,542		)	(2.6	)
Interest expense	(63,010		)	(61,358		)	(2.7	)
Income (loss) before income taxes	172,625			259,699			(33.5	)
Income tax (benefit) expense	51,542			79,761			35.4
Net income (loss)	$	121,083		$	179,938		(32.7	)%

__________

^*  Not meaningful

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NON-GAAP FINANCIAL MEASURES - Electric and Gas Margins

The following discussion includes financial information prepared in accordance with GAAP, as well as two other financial measures, electric margin and gas margin, that are considered “non-GAAP financial measures.” Generally, a non-GAAP financial measure is a numerical measure of a company's financial performance, financial position or cash flows that exclude (or include) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. The presentation of electric margin and gas margin is intended to supplement 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

Electric margin represents electric sales to retail and transportation customers less the cost of generating and purchasing electric energy sold to customers, including transmission costs to bring electric energy to PSE's service territory. The following table displays the details of PSE's electric margin changes:

Electric Margin	Three Months Ended March 31,						Favorable/ (Unfavorable)
(Dollars in Thousands)	2014			2013
Electric operating revenue:
Residential sales	$	358,843		$	360,918		(0.6	)%
Commercial sales	229,084			225,956			1.4
Industrial sales	27,035			26,810			0.8
Other retail sales, including unbilled revenues	(25,391		)	(11,282		)	*
Total retail sales	589,571			602,402			(2.1	)
Transportation sales	1,988			1,846			7.7
Sales to other utilities and marketers	14,040			8,986			56.2
Decoupling revenue	12,677			—			*
Other	15,277			1,400			*
Total electric operating revenues1	633,553			614,634			3.1
Minus power costs:
Purchased electricity1	181,157			175,043			(3.5	)
Electric generation fuel1	75,436			59,087			(27.7	)
Residential exchange1	(30,003		)	(22,551		)	33.0
Total electric power costs	226,590			211,579			(7.1	)
Electric margin2	$	406,963		$	403,055		1.0	%

______________

^*  Not meaningful

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.

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Electric margin increased$3.9 million, or 1.0%, to $407.0 million from $403.1 million for the three months ended March 31, 2014 as compared to the same period in 2013. 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 operatingrevenuesincreased$18.9 million, or 3.1%, to $633.6 million from $614.6 million for the three months ended March 31, 2014 as compared to the same period in 2013. The increase in operating revenues was primarily due to higher miscellaneous operating revenues of $13.9 million, decoupling revenue related to under-collection of $12.7 million, and higher sales to other utilities and marketers of $5.1 million. The increase was partially offset by lower electric retail sales of $12.8 million. These items are discussed in more detail below.

Electric retail sales decreased$12.8 million, or 2.1%, to $589.6 million from $602.4 million for the three months ended March 31, 2014 as compared to the same period in 2013. The decrease in electric retail sales primarily resulted from a revenue decrease of $17.0 million due to lower retail electricity usage of 169,440 MWhs, or 2.8% during the three months ended March 31, 2014 as compared to the same period in the prior year. The decrease was also driven by a net revenue increase of $4.1 million due to the rate increase primarily related to PSE's ERF and decoupling rate increase which became effective on July 1, 2013.

Sales to other utilities and marketersincreased$5.1 million, or 56.2%, to $14.0 million from $9.0 million for the three months ended March 31, 2014 as compared to the same period in 2013. The increase was primarily driven by an increase of $4.9 million due to higher wholesale electricity prices for the three months ended March 31, 2014.

Decoupling revenue increased $12.7 million due to an under-collection of lower volumetric revenues over the allowed decoupled revenues per customer under the decoupling mechanism for the three months ended March 31, 2014. The offset is recorded in a regulatory asset and after all monthly offsets are recognized for the calendar year, the balance in this account will either be a regulatory asset or liability and will be recovered from or passed back to customers through a future rate filing.

Other electric operating revenueincreased$13.9 million to $15.3 million from $1.4 million for the three months ended March 31, 2014 as compared to the same period in 2013. The increase was primarily the result of an increase of $9.1 million due to higher non-core gas sales and an increase of $4.5 million due to higher miscellaneous electric revenue for the three months ended March 31, 2014.

Electric Energy Costs

Purchased electricity expense increased$6.1 million, or 3.5%, to $181.2 million from $175.0 million for the three months ended March 31, 2014 as compared to the same period in 2013. The increase was primarily the result of a $7.1 million increase primarily related to higher market prices nationally driven up by increased demand resulting from an unusually cold winter during the three months ended March 31, 2014. Also contributing to the increase was an increase of $3.2 million in transmission expense. The increase was partially offset by $4.1 million due to a market price offset related to generation plant in the PCA mechanism. The PCA mechanism provides the customer an offset for the market power purchases built into current rates that will not be incurred during the deferral period.

To meet customer demand, PSE economically dispatches resources in its power supply portfolio, such as, fossil-fuel generation, owned and contracted hydroelectric energy and long-term contracted power. However, depending principally upon availability of hydroelectric and wind 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$16.3 million, or 27.7%, to $75.4 million from $59.1 million for the three months ended March 31, 2014 as compared to the same period in 2013. The increase was primarily due to a $16.8 million increase in fuel expense at PSE's combustion turbine facilities primarily resulting from an increase in electric generation at combustion turbine facilities of 101,438 MWhs, or 9.9%, for the three months ended March 31, 2014 as compared to the same period in 2013.

Residential exchange creditsincreased$7.5 million, or 33.0%, to $30.0 million from $22.6 million for the three months ended March 31, 2014 as compared to the same period in 2013 as a result of higher electric residential and farm customer sales volumes associated with the BPA REP. The REP credit is a pass-through tariff item with a corresponding credit in electric operating revenue, with no impact on net income.

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Natural Gas Margin

Gas margin is natural gas sales to retail and transportation customers less the cost of natural gas purchased, including transportation costs to bring natural gas to PSE's service territory. The following table displays the details of PSE's natural gas

margin:

Natural Gas Margin	Three Months Ended March 31,				Favorable/ (Unfavorable)
(Dollars in Thousands)	2014		2013
Gas operating revenue:
Residential sales	$	265,407	$	261,184	1.6	%
Commercial sales	104,770		106,557		(1.7	)
Industrial sales	8,791		9,718		(9.5	)
Total retail sales	378,968		377,459		0.4
Transportation sales	4,265		4,061		5.0
Decoupling revenue	787		—		*
Other	3,423		3,245		5.5
Total gas operating revenues1	387,443		384,765		0.7
Minus purchased gas costs1	191,306		189,983		(0.7	)
Natural gas margin2	$	196,137	$	194,782	0.7	%

______________

^*  Not meaningful

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.

Natural gas margin increased$1.4 million, or 0.7%, to $196.1 million from $194.8 million for the three months ended March 31, 2014 as compared to the same period in 2013. 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 revenuesincreased$2.7 million, or 0.7%, to $387.4 million from $384.8 million for three months ended March 31, 2014 as compared to the same period in 2013. The increase was due primarily to higher natural gas retail sales as discussed in more detail below.

Natural gas retail salesincreased$1.5 million, or 0.4%, to $379.0 million from $377.5 million for the three months ended March 31, 2014 as compared to the same period in 2013. The increase was primarily the result of a net revenue increase of $1.8 million for the three months ended March 31, 2014 primarily due to the rate increase primarily related to PSE's decoupling rate increase which became effective on July 1, 2013 and PGA rate increase which became effective on November 1, 2013.

Gas Energy Costs

Purchased gasexpenses increased$1.3 million, or 0.7%, to $191.3 million from $190.0 million for the three months ended March 31, 2014 as compared to the same period in 2013. The increase was primarily due to higher natural gas costs reflected in PGA rates effective November 1, 2013; and was partially offset by a decrease in customer usage of 0.4% for the three months ended March 31, 2014 as compared to the same period in 2013.

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 payable, 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 natural gas cost through rates. A payable balance reflects overrecovery of natural gas cost through rates. The PGA mechanism payable balance at March 31, 2014 was $2.9 million, which will be reflected on customers' bills through a future PGA rate filing.

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Non-utility Operating Revenue

Non-utility operating revenue increased$4.1 million to $4.4 million from $0.3 million for the three months ended March 31, 2014 as compared to the same period in 2013. The increase was primarily driven by $4.0 million revenue related to PSE's renewable gas (Biogas) sales during the three months ended March 31, 2014.

Other Operating Expenses

Net unrealized gain on derivative instrumentsdecreased$65.5 million to $7.3 million from $72.7 million for the three months ended March 31, 2014 as compared to the same period in 2013. The net gain during the three months ended March 31, 2014 was due to a gain of $15.4 million related to PSE's natural gas derivative instruments and a loss of $8.1 million related to electric derivative instruments, respectively. This compares to gains of $49.2 million and $23.5 million related to PSE's electric and natural gas derivative instruments, respectively, during the same period in 2013. The decrease was primarily due to an increase in the price of natural gas and the wholesale electricity forward prices were flat over the three-year tenor of PSE's energy supply hedging program.

Utility operations and maintenanceexpense increased$14.8 million, or 11.5%, to $144.1 million from $129.2 million for the three months ended March 31, 2014 as compared to the same period in 2013. The increase was primarily driven by an increase of $7.7 million in storm expenses, an increase of $5.6 million in customer service expenses mostly related to uncollectible accounts expense, and an increase of $1.3 million in production operations and maintenance expenses for the three months ended March 31, 2014.

Non-utility operations and maintenanceexpense increased$3.1 million to $6.2 million from $3.1 million for the three months ended March 31, 2014 as compared to the same period in 2013. The increase was primarily driven by an increase of $3.0 million in expense related to PSE's renewable gas sales during the three months ended March 31, 2014.

Depreciation expense increased$3.0 million, or 3.4%, to $91.2 million from $88.2 million for the three months ended March 31, 2014 as compared to the same period in 2013. The increase was primarily due to additional capital expenditures placed into service, net of retirements, such as Snoqualmie Falls Plant 1 and 2 which returned to service in September 2013 and April 2013, respectively, and the additions at the Baker hydroelectric generating facility which went into service in July 2013.

Amortization expense increased$4.8 million, or 83.4%, to $10.5 million from $5.7 million for the three months ended March 31, 2014 as compared to the same period in 2013. The increase was primarily due to an increase of $3.4 million in computer software system amortization for the three months ended March 31, 2014 related to a new Customer Information System placed in service in April 2013. Also contributing to the increase was the deferral of generating plants fixed costs of $1.6 million for the three months ended March 31, 2014 as compared to the same period in 2013.

Conservation amortizationdecreased$5.1 million, or 15.0%, to $29.0 million from $34.1 million for the three months ended March 31, 2014 as compared to the same period in 2013. The decrease was primarily due to a decrease of $5.9 million in gas conservation amortization for the three months ended March 31, 2014.

Other Income and Income Tax Expense

Other incomedecreased$7.8 million, or 64.7%, to $4.2 million from $12.0 million for the three months ended March 31, 2014 as compared to the same period in 2013. The decrease was primarily due to a decrease of $5.1 million in Allowance for Funds Used During Construction (AFUDC) income mostly related to the decrease in average construction work in process, and a decrease of $3.2 million in interest and dividend income for the three months ended March 31, 2014 as compared to the same period in 2013. The decrease was partially offset by an increase of $0.6 million in life insurance gains for the three months ended March 31, 2014 as compared to the same period in 2013.

Income taxexpense decreased$28.2 million, or 35.4%, to $51.5 million from $79.8 million for the three months ended March 31, 2014 as compared to the same period in 2013, primarily due to lower pre-tax income due primarily to lower gains on unrealized derivative instruments.

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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, 2014 and 2013 was as follows:

Benefit/(Expense)	Three Months Ended March 31,						Percent Change
(Dollars in Thousands)	2014			2013
PSE net income	$	121,083		$	179,938		(32.7	)%
Other operating revenue	—			111			*
Net unrealized gain on energy derivative instruments	570			2,952			*
Non-utility expense and other	2,755			4,085			(32.6	)
Unhedged interest rate swap (expense) income	(747		)	1,028			*
Interest expense 1	(26,092		)	(29,810		)	12.5
Income tax benefit (expense)	10,023			9,171			9.3
Puget Energy net income (loss)	$	107,592		$	167,475		(35.8	)%

__________

^*  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, 2014 was $107.6 million with operating revenue of $1.0 billion as compared to a net income of $167.5 million with operating revenue of $1.0 billion for the same period in 2013. The following are significant factors that impacted Puget Energy's net income, which are not included in PSE's discussion:

Interest expense decreased$3.7 million, or 12.5%, to $26.1 million from $29.8 million for the three months ended March 31, 2014 as compared to the same period in 2013. The decrease was primarily due to a reduction of $1.9 million in mark-to-market gains on hedged interest rate swap contracts. Also contributing to the decrease was a decrease of $1.0 million in interest expense related to Puget Energy's revolving senior secured credit facility as its balance was reduced by $26.0 million and $80.0 million during the second and third quarter of 2013, respectively; and the commitment fees and spreads were reduced due to rating upgrade in the first quarter of 2014.

Capital Requirements

Contractual Obligations and Commercial Commitments

There have been no material changes to the contractual obligations 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, 2013.

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The following are PSE’s and Puget Energy’s aggregate availability under commercial commitments as of March 31, 2014:

	Amount of Available Commitments Expiration Per Period
Commercial Commitments (Dollars in Thousands)	Total			2014			2015-2016		2017-2018		Thereafter
PSE liquidity facility 1	$	650,000		$	—		$	—	$	650,000	$	—
PSE energy hedging facility 1	350,000			—			—		350,000		—
Inter-company short-term debt 2	402			402			—		—		—
Total PSE commercial commitments	$	1,000,402		$	402		$	—	$	1,000,000	$	—
Puget Energy revolving credit facility 3	501,000			—			—		501,000		—
Less: Inter-company short-term debt elimination 2	(402		)	(402		)	—		—		—
Total Puget Energy commercial commitments	$	1,501,000		$	—		$	—	$	1,501,000	$	—

_____________

¹  As of March 31, 2014, PSE had credit facilities totaling $1.0 billion and no amount had been drawn. These facilities consisted of $650.0 million to fund operating expenses and $350.0 million to support electric and natural gas hedging. The $650.0 million liquidity facility includes a swingline feature allowing same day availability on borrowings up to $75.0 million. The credit facilities also have an accordion feature that, upon the banks' approval, would increase the total size of these facilities to $1.450 billion. As of March 31, 2014, no letter of credit was outstanding under the facilities and no amount was outstanding under the commercial paper program. Outside of the credit agreements, PSE had a $4.6 million letter of credit in support of a long-term transmission contract and a $1.0 million letter of credit in support of natural gas purchases in Canada. In April 2014, subsequent to the close of the first quarter, the Company completed a one-year extension on both of the liquidity and hedging facilities, extending the maturity from February 2018 to April 2019. The credit agreements are syndicated among numerous lenders. All other terms and conditions of that facility remain unchanged from when it was committed in 2013.

²  As of March 31, 2014, PSE had a revolving credit facility with Puget Energy in the form of a promissory note to borrow up to $30.0 million of which$29.6 million was drawn.

³  As of March 31, 2014, Puget Energy had incurred a $299.0 million draw under its $800.0 million Puget Energy revolving senior secured credit facility. The Puget Energy revolving credit facility also has an accordion feature that, upon the banks' approval, would increase the size of the facility to $1.3 billion. In April 2014, subsequent to the quarter close, the Company completed a one-year extension on the senior secured credit facility extending the maturity from February 2017 to April 2018. There were no significant changes to other terms and conditions.

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 $96.3 million for the three months ended March 31, 2014.  Presently planned utility construction expenditures, excluding AFUDC, are as follows:

Capital Expenditure Projections (Dollars in Thousands)	2014		2015		2016
Total energy delivery, technology and facilities expenditures	$	514,278	$	649,240	$	622,487

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.  

Capital Resources

Cash From Operations

Puget Sound Energy

Cash generated from operations for the three months ended March 31, 2014increased by $24.4 million from $309.7 million generated during the same period in 2013.  The increase in cash flow was primarily the result of a decrease in cash out flow related to accounts payable of $33.1 million and fuel and gas inventory of $8.1 million as compared to prior year for related expenses.

Net income decreased by $58.9 million and non-cash items decreased by $65.5 million related to the fair value adjustment of derivative instruments and deferred income taxes of $28.2 million. This was partially offset by an increase of $7.8 million related to depreciation and amortization.

44

Puget Energy

Cash generated from operations for the three months ended March 31, 2014 was $310.5 million, an increase of $9.2 million from the $301.3 million generated during the three months ended March 31, 2013.  The net increase was positively impacted by $24.4 million from cash provided by the operating activities of PSE as previously discussed. As a result of the merger with Puget Holdings in February 2009, $8.0 million in derivative settlement payments were reclassified to financing activities for the three months ended March 31, 2014 as compared to $26.1 million during the same period in 2013, resulting in a decrease in operating cash flows of $18.0 million.  This decrease was due to a decline in the number of contracts settled during 2014 as compared to the prior period.  These contracts represent proceeds received from derivative instruments that included financing elements at the merger date. Partially offsetting this decrease is increases in cash in various other items.

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 has two unsecured revolving credit facilities which provide, in aggregate, $1.0 billion of short-term liquidity needs. These facilities consist of a $650.0 million revolving liquidity facility (which includes a liquidity letter of credit facility and a swingline facility) to be used for general corporate purposes, including a backstop to the Company's commercial paper program and a $350.0 million revolving energy hedging facility (which includes an energy hedging letter of credit facility). The $650.0 million liquidity facility includes a swingline feature allowing same day availability on borrowings up to $75.0 million. The credit facilities also have an accordion feature which, upon the banks' approval, would increase the total size of these facilities to $1.450 billion.

In April 2014, subsequent to the close of the first quarter, the Company completed a one-year extension on both of the liquidity and hedging facilities, extending the maturity from February 2018 to April 2019. All other terms and conditions of the facilities remain unchanged from when they were committed in 2013. The credit agreements are syndicated among numerous lenders and 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 a financial covenant of total debt to total capitalization of 65% or less. PSE certifies its compliance with such covenants to participating banks each quarter. As of March 31, 2014, PSE was in compliance with all applicable covenants.

The credit agreements provide PSE with the ability to borrow at different interest rate options. 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. PSE must 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 1.25% and the commitment fee is 0.175%.

As of March 31, 2014, no amount was drawn and outstanding under PSE's $650.0 million liquidity facility. No letter of credit was outstanding under the facility, and no amount was outstanding under the commercial paper program. Outside of the credit agreements, PSE had a $4.6 million letter of credit in support of a long-term transmission contract and a $1.0 million letter of credit in support of natural gas purchases in Canada.

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, 2014, $29.6 million was outstanding under the Note. 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 March 31, 2014, Puget Energy maintained an $800.0 million five-year revolving senior secured credit facility. In April, 2014, subsequent to the quarter close, the Company completed a one-year extension on the senior secured credit facility, extending the maturity from February 2017 to April 2018. There were no significant changes to other terms and conditions. The Puget

45

Energy revolving senior secured credit facility also has an accordion feature which, upon the banks' approval, would increase the size of the facility to $1.3 billion.

The revolving senior secured credit facility contains usual and customary affirmative and negative covenants. The agreement also contains a Maximum Leverage Ratio financial covenant as defined in the agreement governing the senior secured credit facility. As of March 31, 2014, Puget Energy was in compliance with all applicable covenants.

The revolving 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 bank's 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, 2014, $299.0 million was drawn and outstanding under the facility. As a result of Puget Energy's credit rating upgrade in 2014, the spread over LIBOR was 1.75% and the commitment fee was 0.275% as of the date of this report, Puget Energy entered into interest rate swap contracts to manage the interest rate risk associated with the credit facility (see Note 2 and the "Interest Rate Risk" section in Item 3).

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, 2014, approximately $511.8 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 Earnings Before Interest, Tax, Depreciation and Amortization (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 48.7% at March 31, 2014 and the EBITDA to interest expense was 4.4 to one for the twelve 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 (as defined in the facilities), or if the payment of dividends would result in an Event of Default, 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. Puget Energy's EBITDA to interest expense was 2.9 to one for the twelve months ended March 31, 2014.

At March 31, 2014, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.

Debt Restrictive Covenants

The type and amount of future long-term financings for PSE may be limited by provisions in PSE's electric and natural gas mortgage indentures.

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, 2014, PSE could issue:

• Approximately $1.7 billion of additional first mortgage bonds under PSE's electric mortgage indenture based on approximately $2.9 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, 2014; and

• Approximately $311.0 million of additional first mortgage bonds under PSE's natural gas mortgage indenture based on approximately $443.6 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, 2014.

At March 31, 2014, PSE had approximately $7.1 billion in electric and natural gas ratebase to support the interest coverage ratio limitation test for net earnings available for interest.

Upon approval of the merger in 2009, the Company was required to refinance its debt in place at the time of the merger. The Company has met this refinancing requirement as of March 31, 2014.

46

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, up to $800.0 million aggregate principal amount of 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.

On May 23, 2013, PSE refinanced $161.9 million of its Pollution Control Revenue Refunding Bonds to a lower weighted average interest rate from 5.01% to 3.91%. The bonds will mature on March 1, 2031. On or after March 1, 2023, the Company may elect to call the bonds at a redemption price of 100% of the principal amount thereof, without premium, plus accrued interest, if any, to the redemption date.

Other

Residential Exchange

The Northwest Power Act, through the REP, provides access to the benefits of low-cost federal power for residential and small farm customers of regional utilities, including PSE.  The program is administered by 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 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 fiscal year 2002 through fiscal year 2011 period 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 (2012 REP Settlement) that by its terms, if upheld in its entirety, would resolve the disputes between BPA and PSE regarding REP benefits paid for fiscal years 2002-2011 and determine REP benefits for fiscal years 2012-2028.  In October 2011, certain other parties challenged BPA decisions with regard to its entering into the 2012 REP Settlement agreement.  On October 28, 2013, the Ninth Circuit issued an order dismissing this challenge to this settlement. In light of the disposition of this challenge, the stay of the other pending Ninth Circuit litigation regarding REP benefits was lifted in January 2014. In the order lifting the stay, petitioners (unless they move to voluntarily dismiss their petitions) and intervenors (unless they move to voluntarily withdraw) were directed to file a statement explaining which issues, if any, remain pending. Subsequent to the order lifting the stay, in February 2014, one group of petitioners in the other pending Ninth Circuit litigation moved to dismiss its petition and its motion was granted. Two of the remaining petitioners may seek dismissal of their petitions, but other remaining petitioners have not submitted such a motion but rather have stated to the Ninth Circuit that they are pursuing certain claims. PSE is unable to determine what impact these proceedings 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 directly to REP customers.

With the Ninth Circuit’s decision affirming the 2012 REP Settlement, PSE will receive $62.9 million in REP payments owed under a 2008 agreement, which are in addition to scheduled monthly REP benefits received from BPA under the 2012 REP Settlement. These payments will be given back to PSE's residential and small farm customers through a higher residential exchange credit on their bills.

Colstrip

PSE has a 50% ownership interest in Colstrip Units 1 and 2, and a 25% interest in Colstrip Units 3 and 4. On March 6, 2013, Sierra Club and Montana Environmental Information Center (MEIC) filed a Clean Air Act citizen suit against all Colstrip owners (including PSE) alleging numerous claims for relief, most which relate to alleged prevention of significant deterioration (PSD) violations. One claim relates to the alleged failure to update the Title V permit to reflect the major modifications alleged in the first thirty-six claims, another claim alleges that the previous Title V compliance certifications have been incomplete because they did not address the alleged major modifications, and the last claim alleges opacity violations since 2007. The lawsuit was filed in U.S. District of Montana, Billings Division requesting injunctive relief and civil penalties, including a request that the owners remediate environmental damage and that $100,000 of the civil penalties be used for beneficial mitigation projects. This lawsuit followed various Notices of Intent to Sue sent to Colstrip owners (including PSE) from the Sierra Club and the MEIC between July and December 2012.  Discovery in the case has begun, and a prehearing conference took place in July 2013. The case has been bifurcated into separate liability and remedy trials. The liability trial is currently set for June 2015, and a date for the remedy trial has yet to be determined. PSE is litigating the allegations set forth in the notices and cannot at this time 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 (EMC) establishes PSE’s risk management policies and procedures and monitors compliance.  The EMC is comprised of certain PSE officers and is overseen by the PSE Board of Directors.  

PSE's objective is to minimize commodity price exposure and risks associated with volumetric variability in the natural gas and electric portfolios and related effects. It is not engaged in the business of assuming risk for the purpose of speculative trading.  PSE hedges open natural 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 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. 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 and related hedging strategies are focused on reducing costs and risks where feasible, thus reducing volatility in costs 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 forward physical electric and natural gas purchase and sale agreements, fixed-for-floating swap contracts, and commodity call/put options. The forward physical electric contracts are both fixed and variable (at index), while the physical natural gas contracts are variable. To fix the price of wholesale electricity and natural gas, PSE may enter into fixed-for-floating swap (financial) contracts. PSE also utilizes natural gas call and put options as an additional hedging instrument to increase the hedging portfolio's flexibility to react to commodity price fluctuations. Approximately 65% of these contracts, including NPNS transactions, are entered into with investment grade counterparties which, in the majority of cases, do not require collateral calls on the contracts.

The following table presents the fair values of the Company's energy derivative instruments, recorded on the balance sheets:

Puget Energy and Puget Sound Energy
(Dollars in thousands)	March 31, 2014				December 31, 2013
	Assets		Liabilities		Assets		Liabilities
Electric portfolio:
Current	$	20,633	$	19,356	$	14,565	$	17,731
Long-term	3,273		15,009		3,914		19,581
Total electric derivatives	$	23,906	$	34,365	$	18,479	$	37,312
Natural Gas portfolio:
Current	$	24,256	$	7,105	$	4,302	$	23,734
Long-term	3,547		7,061		3,819		11,942
Total natural gas derivatives	$	27,803	$	14,166	$	8,121	$	35,676
Total energy derivatives	$	51,709	$	48,531	$	26,600	$	72,988

At March 31, 2014, the Company had total assets of $51.7 million and total liabilities of $48.5 million related to derivative contracts used to hedge the supply and cost of electricity and natural gas to serve PSE customers. As the gains and losses in the electric portfolio are realized, they will be recorded as either purchased power costs or electric generation fuel costs under the PCA mechanism. Any fair value adjustments relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations” (ASC 980) due to the PGA mechanism, which passes the cost of natural gas supply to customers. 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 on March 31, 2014, of natural gas and electricity would change the fair value of the Company's derivative contracts by $38.1 million.

For further details regarding both the fair value of derivative instruments and the impacts such instruments have on current period earnings and OCI, see Notes 2 and 3 to the consolidated financial statements.

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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, 2014, PSE held approximately $1.1 billion in standby letters of credit or limited parental guarantees, and had 20 counterparties with unlimited parental guarantees, in support of various electric and natural gas 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.

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: WSPP agreements which standardize physical power contracts in the electric industry; ISDA agreements which standardize financial gas and electric contracts; and NAESB agreements which standardize physical gas contracts. PSE believes that entering into such agreements reduces the risk credit risk exposure because such agreements provide for the netting and offsetting of monthly payments as well as right of set-off in the event of counterparty default.

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). If a forecasted transaction associated with cash flow hedge is probable of not 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 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 credit and non-performance reserves. As of March 31, 2014, the Company was in a net liability position with many of its counterparties, therefore the default factors of counterparties did not have a significant impact on reserves for the period. As of March 31, 2014, PSE has posted a $1.0 million letter of credit as a condition of transacting on a physical energy exchange and clearinghouse in Canada. PSE did not trigger collateral requirements with any of its counterparties, nor were any of PSE's counterparties required to post 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, borrowings under its commercial paper program, and its 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 these debts. As of March 31, 2014, Puget Energy had two interest rate swap contracts outstanding and PSE did not have any outstanding interest rate swap instruments.

At March 31, 2014, the fair value of the interest rate swaps was a $12.1 million pre-tax loss. This fair value considers the risk of Puget Energy's non-performance by using Puget Energy's incremental borrowing rate on unsecured debt over the risk-free rate in the valuation estimate.

A hypothetical 10% increase or decrease in interest rates on March 31, 2014, would change the fair value of Puget Energy's interest rate swaps by $1.1 million.

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The following table presents the fair values of Puget Energy's interest rate swaps, recorded on the balance sheet:

Puget Energy (Dollars in Thousands)	March 31, 2014		December 31, 2013
	Liabilities		Liabilities
Interest rate swaps:
Current	$	6,752	$	6,584
Long-term	5,374		6,639
Total interest rate swaps	$	12,126	$	13,223

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, 2014 was a net loss of $6.2 million after tax compared to an after-tax loss of $6.3 million in OCI as of December 31, 2013. 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 approved prior to execution. PSE had no treasury locks or forward starting swap contracts outstanding at March 31, 2014.

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, 2014, 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 were no changes in the Company's internal control over financial reporting that occurred during the period covered by this quarterly report that have materially affected, or are reasonably likely to materially affect, its 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, 2014, 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 were no changes in the Company's internal control over financial reporting that occurred during the period covered by this quarterly report that have materially affected, or are reasonably likely to materially affect, its internal control over financial reporting.

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, 2014.  Litigation is subject to numerous uncertainties and PSE is unable to predict the ultimate outcome of these matters.

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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, 2013.

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/ Michael J. Stranik
		Michael J. Stranik Controller and Principal Accounting Officer
Date:	May 1, 2014	Officer duly authorized to sign this report on behalf of each registrant

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EXHIBIT INDEX

3(i).1	Amended Articles of Incorporation of Puget Energy (incorporated herein by reference to Exhibit 3.1 to Puget Energy’s Current Report on Form 8-K, dated February 6, 2009, Commission File No. 1-16305).
3(i).2	Amended and Restated Articles of Incorporation of Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit 3.2 to Puget Sound Energy’s Current Report on Form 8-K, dated February 6, 2009, Commission File No. 1-4393).
3(ii).1	Amended and Restated Bylaws of Puget Energy dated February 6, 2009 (incorporated herein by reference to Exhibit 3.3 to Puget Energy’s Current Report on Form 8-K, Commission File No. 1-16305).
3(ii).2	Amended and Restated Bylaws of Puget Sound Energy, Inc. dated February 6, 2009 (incorporated herein by reference to Exhibit 3.4 to Puget Sound Energy’s Current Report on Form 8-K, Commission File No. 1-4393).
10.1*	Amendment No. 2 dated April 15, 2014 to Credit Agreement dated as of February 10, 2012 among Puget Energy, Inc., as Borrower, JPMorgan Chase Bank, National Association, as Administrative Agent and the Lenders party thereto.
10.2*	Amendment No. 1 dated April 15, 2014 to Credit Agreement dated as of February 4, 2013 among Puget Sound Energy, Inc., as Borrower, Wells Fargo Bank, National Association, as Administrative Agent and the Lenders party thereto.
12.1*	Statement setting forth computation of ratios of earnings to fixed charges of Puget Energy, Inc. (2009 through 2013 and 12 months ended March 31, 2014).
12.2*	Statement setting forth computation of ratios of earnings to fixed charges of Puget Sound Energy, Inc. (2009 through 2013 and 12 months ended March 31, 2014).
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, 2014, filed on May 1, 2014 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 (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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EX-10.1

Exhibit 10.1

AMENDMENT NO. 2

to

CREDIT AGREEMENT

THIS AMENDMENT NO. 2 (“Amendment”) is made as of April 15, 2014 by and among Puget Energy, Inc. (“Borrower”), the Lenders party hereto (the “Lenders”) and JPMorgan Chase Bank, N.A., as Administrative Agent (in such capacity, the “Administrative Agent”).

WHEREAS, Borrower, Lenders and Administrative Agent are parties to that certain Credit Agreement, dated as of February 10, 2012 (as amended, restated, supplemented or otherwise modified prior to the date hereof, the “Credit Agreement”). Capitalized terms used herein and not otherwise defined shall have the meanings ascribed to them in the Credit Agreement;

WHEREAS, the Borrower has requested that the Lenders and the Administrative Agent agree to certain amendments to the Credit Agreement;

WHEREAS, the Lenders party hereto and the Administrative Agent have agreed to such amendments on the terms and conditions set forth herein;

NOW, THEREFORE, in consideration of the premises set forth above, the terms and conditions contained herein, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Borrower, the Lenders party hereto and the Administrative Agent have agreed to enter into this Amendment.

1.Amendments to Credit Agreement. Effective as of the date of satisfaction of the conditions precedent set forth in Section 2 below, the Credit Agreement is hereby amended as follows:

(a)The definition of “Aggregate Commitment” appearing in Section 1.01 of the Credit Agreement is hereby amended and restated in its entirety to read as follows:

“Aggregate Commitment” means the aggregate of the Commitments of all of the Lenders, as reduced or increased from time to time pursuant to the terms and conditions hereof. As of the Amendment No. 2 Effective Date, the Aggregate Commitment is $800,000,000.

(b)The definition of “Applicable Rate” appearing in Section 1.01 of the Credit Agreement is hereby amended by deleting the pricing grid in its entirety and replacing it with the following pricing grid:

Pricing Level	Commitment Fee Rate	Eurodollar Spread for Eurodollar Loans	ABR Spread for ABR Loans
Level I	0.175%	1.25%	0.25%
Level II	0.225%	1.50%	0.50%
Level III	0.275%	1.75%	0.75%
Level IV	0.350%	2.00%	1.00%
Level V	0.450%	2.50%	1.50%
Level VI	0.525%	3.00%	2.00%

(c)The definition of “Business Plan” appearing in Section 1.01 of the Credit Agreement is hereby amended and restated in its entirety to read as follows:

“Business Plan” has the meaning assigned to such term in this Agreement prior to the Amendment No. 2 Effective Date.

(d)The definition of “Excluded Taxes” appearing in Section 1.01 of the Credit Agreement is hereby amended and restated in its entirety to read as follows:

“Excluded Taxes” means any of the following Taxes imposed on or with respect to a Recipient or required to be withheld or deducted from a payment to a Recipient, (a) Taxes imposed on or measured by net income (however denominated), franchise Taxes, and branch profits Taxes, in each case, (i) imposed as a result of such Recipient being organized under the laws of, or having its principal office or, in the case of any Lender, its applicable lending office located in, the jurisdiction imposing such Tax (or any political subdivision thereof) or (ii) that are Other Connection Taxes, (b) in the case of a Lender, U.S. Federal withholding Taxes imposed on amounts payable to or for the account of such Lender with respect to an applicable interest in a Loan or Commitment pursuant to a law in effect on the date on which (i) such Lender acquires such interest in the Loan or Commitment (other than pursuant to an assignment request by the Borrower under Section 2.19(b)) or (ii) such Lender changes its lending office, except in each case to the extent that, pursuant to Section 2.17, amounts with respect to such Taxes were payable either to such Lender’s assignor immediately before such Lender acquired the applicable interest in a Loan or Commitment or to such Lender immediately before it changed its lending office, (c) Taxes attributable to such Recipient’s failure to comply with Section 2.17(f), (d) any U.S. Federal withholding Taxes imposed under FATCA and (e) any Business and Occupation Taxes imposed by the State of Washington.

(e)The definition of “Existing Indebtedness” appearing in Section 1.01 of the Credit Agreement is hereby amended and restated in its entirety to read as follows:

“Existing Indebtedness” means (a) Indebtedness under this Agreement, (b) Indebtedness of the Borrower or any Subsidiary that is outstanding on the Effective Date and listed on Schedule 1.01(a) and (c) any Permitted Refinancing Indebtedness thereof.

(f)The definition of “FATCA” appearing in Section 1.01 of the Credit Agreement is hereby amended and restated in its entirety to read as follows:

“FATCA” means Sections 1471 through 1474 of the Code, as of the date of this Agreement (or any amended or successor version that is substantively comparable and not materially more onerous to comply with), any current or future regulations or official interpretations thereof and any agreement entered into pursuant to Section 1471(b)(1) of the Code.

(g)The definition of “LIBO Rate” appearing in Section 1.01 of the Credit Agreement is hereby amended and restated in its entirety to read as follows:

“LIBO Rate” means, with respect to any Eurodollar Borrowing for any applicable Interest Period, the London interbank offered rate administered by ICE Benchmark Administration (or any other Person that takes over the administration of such rate) for Dollars for a period equal in length to such Interest Period as displayed on pages LIBOR01 or LIBOR02 of the Reuters screen or, in the event such rate does not appear on either of such Reuters pages, on any successor or substitute page on such screen that displays such

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rate, or on the appropriate page of such other information service that publishes such rate as shall be selected by the Administrative Agent from time to time in its reasonable discretion (in each case the “LIBOR Screen Rate”) at approximately 11:00 a.m., London time, two (2) Business Days prior to the commencement of such Interest Period; provided that, if the LIBOR Screen Rate shall be less than zero, such rate shall be deemed to be zero for purposes of this Agreement; provided, further, that if a LIBOR Screen Rate shall not be available at such time for such Interest Period (the “Impacted Interest Period”), then the LIBO Rate for such Interest Period shall be the Interpolated Rate; provided, that, if any Interpolated Rate shall be less than zero, such rate shall be deemed to be zero for purposes of this Agreement. It is understood and agreed that all of the terms and conditions of this definition of “LIBO Rate” shall be subject to Section 2.14.

(h)The definition of “Maturity Date” appearing in Section 1.01 of the Credit Agreement is hereby amended by deleting “February 10, 2017” and inserting therefor “April 15, 2018, as such date may be extended in accordance with Section 2.22”.

(i)The definition of “Other Connection Taxes” appearing in Section 1.01 of the Credit Agreement is hereby amended and restated in its entirety to read as follows:

“Other Connection Taxes” means, with respect to any Recipient, Taxes imposed as a result of a present or former connection between such Recipient and the jurisdiction imposing such Tax (other than connections arising from such Recipient having executed, delivered, become a party to, performed its obligations under, received payments under, received or perfected a security interest under, engaged in any other transaction pursuant to or enforced any Financing Document, or sold or assigned an interest in any Loan or Financing Document).

(j)Clause (viii) of the definition of “Permitted Acquisition” appearing in Section 1.01 of the Credit Agreement is hereby amended by deleting “covenants” and inserting therefor “covenant”.

(k)The definition of “Permitted Refinancing Indebtedness” appearing in Section 1.01 of the Credit Agreement is hereby amended and restated in its entirety to read as follows:

“Permitted Refinancing Indebtedness” means any Indebtedness of any Borrower Group Member, as applicable, issued in exchange for, or the Net Cash Proceeds of which are used to refund, refinance, replace, defease or discharge Existing Indebtedness; provided, that such Indebtedness shall not be required to reduce any commitment with respect to such Existing Indebtedness; and provided further, that:

(i)    The principal amount (or accreted value, if applicable) of such Permitted Refinancing Indebtedness does not exceed the principal amount (or accreted value, if applicable) of and any unfunded commitment under the Indebtedness extended, refinanced, renewed, replaced, defeased or refunded (plus (x) all refinancing fees and expenses incurred in connection therewith including, without limitation, underwriting fees, closing fees, agency fees, premiums, make-whole amounts or original issue discount and LIBOR breakage costs due in accordance with Section 2.16 of this Agreement and other reasonable out-of-pocket expenses incurred by the Borrower and (y) an amount equal to any termination payment paid pursuant to an Interest Hedging Agreement which has been terminated

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by the Borrower in connection with the incurrence of any Permitted Refinancing Indebtedness);

(ii)    Such Permitted Refinancing Indebtedness has weighted average life to maturity equal to or greater than the weighted average life to maturity of, the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded;

(iii)    If the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded is subordinated in right of payment to this Agreement, such Permitted Refinancing Indebtedness is subordinated in right of payment to this Agreement on terms, taken as whole, at least as favorable to the Lenders as the subordination terms contained in the documentation governing the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded; provided that a certificate of an Authorized Officer of the Borrower is delivered to the Administrative Agent at least five (5) Business Days (or such shorter period as the Administrative Agent may reasonably agree) prior to the incurrence of such Indebtedness, together with a reasonably detailed description of the material terms and conditions of such subordination terms or drafts of the documentation relating thereto, stating that the Borrower has determined in good faith that such terms and conditions satisfy the foregoing requirement, and such certificate shall be conclusive evidence that such terms and conditions satisfy the foregoing requirement unless the Administrative Agent notifies the Borrower within such period that it disagrees with such determination (including a reasonable description of the basis upon which it disagrees);

(iv)    Such Indebtedness is incurred by the Person who is the obligor on the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded;

(v)    The Permitted Refinancing Indebtedness is not secured by any Collateral not granted to the holders of the Indebtedness being financed, renewed, replaced, defeased or refunded; and

(vi)    Such Permitted Refinancing Indebtedness shall have terms which shall be no more restrictive taken as a whole, and shall not, taken as a whole, be materially less favorable, in any respect on the Borrower or the Operating Companies than the provisions of the Indebtedness being refinanced, renewed, replaced, defeased or refunded; provided, however, that the foregoing requirements shall not apply to pricing terms in respect of any Indebtedness being so refinanced so long as such pricing is consistent with then-prevailing market pricing.

(l)The definition of “Recipient” appearing in Section 1.01 of the Credit Agreement is hereby amended and restated in its entirety to read as follows:

“Recipient” means (a) the Administrative Agent, (b) any Lender and (c) the Issuing Bank, as applicable.

(m)Section 1.01 of the Credit Agreement is hereby amended to insert the following defined terms in the appropriate alphabetical order:

“Additional Commitment Lender” has the meaning assigned to such term in Section 2.22.

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“Amendment No. 2 Effective Date” means April 15, 2014.

“Anti-Corruption Laws” means all laws, rules, and regulations of any jurisdiction applicable to the Borrower or its Subsidiaries from time to time concerning or relating to bribery or corruption.

“Connection Income Taxes” means Other Connection Taxes that are imposed on or measured by net income (however denominated) or that are franchise Taxes or branch profits Taxes.

“Existing Revolving Credit Maturity Date” has the meaning assigned to such term in Section 2.22(a).

“Extending Lender” has the meaning assigned to such term in Section 2.22(b).

“Extension Date” has the meaning assigned to such term in Section 2.22(a).

“Impacted Interest Period” has the meaning assigned to such term in the definition of “LIBO Rate”.

“Interpolated Rate” means, at any time, the rate per annum determined by the Administrative Agent (which determination shall be conclusive and binding absent manifest error) to be equal to the rate that results from interpolating on a linear basis between: (a) the LIBOR Screen Rate for the longest period (for which the LIBOR Screen Rate is available) that is shorter than the Impacted Interest Period and (b) the LIBOR Screen Rate for the shortest period (for which the LIBOR Screen Rate is available) that exceeds the Impacted Interest Period, in each case, at such time.

“Lender Notice Date” has the meaning assigned to such term in Section 2.22(a).

“LIBOR Screen Rate” has the meaning assigned to such term in the definition of “LIBO Rate”.

“Non-Extending Lender” has the meaning assigned to such term in Section 2.22(b).

“OFAC” means the Office of Foreign Assets Control of the U.S. Department of the Treasury.

“Receivables Facility” means any receivables or securitization facility or facilities made available to the Borrower or any of its Subsidiaries pursuant to which assets and related security are sold, pledged or otherwise transferred to one or more special purpose entities and thereafter to certain investors or creditors.

“Revolving Credit Maturity Date” has the meaning assigned to such term in Section 2.22(a).

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“Sanctioned Country” means, at any time, a country or territory which is the subject or target of any Sanctions.

“Sanctioned Person” means, at any time, (a) any Person listed in any Sanctions-related list of designated Persons maintained by OFAC, the U.S. Department of State, the United Nations Security Council, the European Union or any EU member state, (b) any Person operating, organized or resident in a Sanctioned Country or (c) any Person controlled by any such Person.

“Sanctions” means economic or financial sanctions or trade embargoes imposed, administered or enforced from time to time by (a) the U.S. government, including those administered by OFAC or the U.S. Department of State or (b) the United Nations Security Council, the European Union or Her Majesty’s Treasury of the United Kingdom.

(n)Section 1.01 of the Credit Agreement is hereby amended by deleting in their entirety the definitions of “AFUDC”, “Cash Interest Expense”, “Consolidated Capital Expenditures”, “Consolidated Current Assets”, “Consolidated EBITDA”, “Consolidated Interest Expense”, “Consolidated Net Income”, “Consolidated Working Capital”, “Group FFO”, “Group FFO Coverage Ratio”, “Group Interest”, “Projections”, “Quarter End Date” and “Test Period”.

(o)Section 2.19(b) of the Credit Agreement is hereby amended by inserting “a Non-Extending Lender pursuant to Section 2.22 or” before the phrase “a Defaulting Lender” in the first clause (iii).

(p)Clause (i)(B) of Section 2.20 of the Credit Agreement is hereby amended by deleting “covenants” and inserting therefor “covenant”.

(q)The Credit Agreement is hereby amended to insert a new Section 2.22 as follows:

Extension of Revolving Credit Maturity Date.

(a)    The Borrower may, at any time, from time to time, not more than ninety (90) days and not less than thirty (30) days prior to any anniversary of the Amendment No. 2 Effective Date, by notice to the Administrative Agent (who shall promptly notify the Lenders) not later than 10 Business Days (or such shorter period as the Administrative Agent may agree in its reasonable discretion) prior to the date on which the Lenders are requested to respond thereto (each such date, a “Lender Notice Date”), request that each Lender extend (each such date on which such extension occurs, an “Extension Date”) the Maturity Date with respect to such Lender’s Loans (such Lender’s “Revolving Credit Maturity Date”) to the date that is one year after the Revolving Credit Maturity Date then in effect for such Lender (such Lender’s “Existing Revolving Credit Maturity Date”).

(b)    Each Lender, acting in its sole and individual discretion, shall, by notice to the Administrative Agent given not later than the applicable Lender Notice Date, advise the Administrative Agent whether or not such Lender agrees to such extension (each Lender that determines to so extend its Revolving Credit Maturity Date, an “Extending Lender”). Each Lender that determines not to so extend its Revolving Credit Maturity Date (a “Non-Extending Lender”) shall notify the Administrative Agent of such fact promptly after such determination (but in any event no later than the Lender Notice Date), and any Lender that does not advise the Administrative Agent of its election to agree to such an extension on or before the Lender Notice Date shall be deemed to be a Non-Extending Lender. The election of any Lender to agree to such extension shall

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not obligate any other Lender to so agree, and it is understood and agreed that no Lender shall have any obligation whatsoever to agree to any request made by the Borrower for extension of its Revolving Credit Maturity Date.

(c)    The Administrative Agent shall promptly notify the Borrower of each Lender’s determination under this Section.

(d)    The Borrower shall have the right, but shall not be obligated, on or before the applicable Revolving Credit Maturity Date for any Non-Extending Lender to replace such Non-Extending Lender with, and add as “Lenders” under this Agreement in place thereof, one or more financial institutions (each, an “Additional Commitment Lender”) approved by the Administrative Agent and the Issuing Banks in accordance with the procedures provided in Section 2.19(b), each of which Additional Commitment Lenders shall have entered into an Assignment and Assumption (in accordance with and subject to the restrictions contained in Section 9.04, with the Borrower or replacement Lender obligated to pay any applicable processing or recordation fee) with such Non-Extending Lender, pursuant to which such Additional Commitment Lenders shall, effective on or before the Revolving Credit Maturity Date for such Non-Extending Lender, assume a Commitment (and, if any such Additional Commitment Lender is already a Lender, its Commitment shall be in addition to such Lender’s Commitment hereunder on such effective date).  Prior to any Non-Extending Lender being replaced by one or more Additional Commitment Lenders pursuant hereto, such Non-Extending Lender may elect, in its sole discretion, by giving irrevocable notice thereof to the Administrative Agent and the Borrower (which notice shall set forth such Lender’s new Revolving Credit Maturity Date), to become an Extending Lender.  The Administrative Agent may effect such amendments to this Agreement as are reasonably necessary to provide for any such extensions with the consent of the Borrower but without the consent of any other Lenders.

(e)    If (and only if) the total of the Commitments of the Lenders that have agreed to extend their Revolving Credit Maturity Date is more than 50% of the aggregate amount of the Commitments in effect immediately prior to the applicable Extension Date, then, effective as of the applicable Extension Date, the Revolving Credit Maturity Date of each Extending Lender and of each Additional Commitment Lender shall be extended to the date that is one year after the Existing Revolving Credit Maturity Date (except that, if such date is not a Business Day, such Revolving Credit Maturity Date as so extended shall be the next preceding Business Day) and each Additional Commitment Lender shall thereupon become a “Lender” for all purposes of this Agreement and shall be bound by the provisions of this Agreement as a Lender hereunder and shall have the obligations of a Lender hereunder.

(f)    Notwithstanding the foregoing, (x) no more than two (2) extensions of the Revolving Credit Maturity Date shall be permitted hereunder (and not more than one such extension may be requested during any nine-month period) and (y) any extension of any Revolving Credit Maturity Date pursuant to this Section 2.22 shall not be effective with respect to any Extending Lender unless:

(i)    there shall exist no Default or Event of Default on the applicable Extension Date and immediately after giving effect thereto;

(ii)    the representations and warranties made by the Borrower contained herein shall be true and correct in all material respects (other than to the extent qualified by materiality or “Material Adverse Effect”, in which case, such representations and warranties shall be true and

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correct) with the same effect as though such representations and warranties had been made on and as of the date of such extension (or to the extent that such representations and warranties specifically refer to an earlier date as of such earlier date); and

(iii)    the Administrative Agent shall have received a certificate from the Borrower signed by an Authorized Officer of the Borrower (A) certifying the accuracy of the foregoing clauses (i) and (ii) and (B) certifying and attaching the resolutions adopted by the Borrower approving or consenting to such extension.

(g)    On the Revolving Credit Maturity Date of each Non-Extending Lender, (i) the Revolving Credit Commitment of each Non-Extending Lender shall automatically terminate and (ii) the Borrower shall repay such Non-Extending Lender in accordance with Section 2.10 (and shall pay to such Non-Extending Lender all of the other obligations owing to it under this Agreement) and after giving effect thereto shall prepay any Loans outstanding on such date (and pay any additional amounts required pursuant to Section 2.16) to the extent necessary to keep outstanding Loans ratable with any revised Applicable Percentage of the respective Lenders effective as of such date, and the Administrative Agent shall administer any necessary reallocation of the Revolving Credit Exposures (without regard to any minimum borrowing, pro rata borrowing and/or pro rata payment requirements contained elsewhere in this Agreement).

(h)    This Section shall supersede any provisions in Section 9.02 to the contrary.

(r)Section 3.12 of the Credit Agreement is hereby amended by deleting “the Projections and any other” and inserting therefor “any” and deleting “Projections or”.

(s)The Credit Agreement is hereby amended to insert a new Section 3.23 as follows:

Anti-Corruption Laws and Sanctions. The Borrower has implemented and maintains in effect policies and procedures designed to ensure compliance by the Borrower, its Subsidiaries and their respective directors, officers, employees and agents with Anti-Corruption Laws and applicable Sanctions, and the Borrower, its Subsidiaries and their respective officers and employees and to the knowledge of the Borrower its directors and agents, are in compliance with Anti-Corruption Laws and applicable Sanctions in all material respects. None of (a) the Borrower, any Subsidiary or to the knowledge of the Borrower or such Subsidiary any of their respective directors, officers or employees, or (b) to the knowledge of the Borrower, any agent of the Borrower or any Subsidiary that will act in any capacity in connection with or benefit from the credit facility established hereby, is a Sanctioned Person. No Borrowing or Letter of Credit, use of proceeds or other Transactions will violate Anti-Corruption Laws or applicable Sanctions.

(t)Section 5.01(c) of the Credit Agreement is hereby amended by deleting it in its entirety and inserting therefor “[reserved];”.

(u)Section 5.04 of the Credit Agreement is hereby amended to insert a new clause (c) as follows: “The Borrower will maintain in effect and enforce policies and procedures designed to ensure compliance by the Borrower, its Subsidiaries and their respective directors, officers, employees and agents with Anti-Corruption Laws and applicable Sanctions.”

(v)Section 5.09 of the Credit Agreement is hereby amended by adding the following sentence to the end: “The Borrower will not request any Borrowing or Letter of Credit, and the Borrower shall not use, and shall procure that its Subsidiaries and its or their respective directors, officers,

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employees and agents shall not use, the proceeds of any Borrowing or Letter of Credit (i) in furtherance of an offer, payment, promise to pay, or authorization of the payment or giving of money, or anything else of value, to any Person in violation of any Anti-Corruption Laws, (ii) for the purpose of funding, financing or facilitating any activities, business or transaction of or with any Sanctioned Person, or in any Sanctioned Country or (iii) in any manner that would result in the violation of any Sanctions applicable to any party hereto.”

(w)Section 6.01(u) of the Credit Agreement is hereby amended and restated in its entirety to read as follows:

Liens securing Permitted Refinancing Indebtedness of the Borrower and other Indebtedness of the Borrower of the type described in clauses (a) and (b) of the definition of “Indebtedness” (but not of any Indebtedness of any other Borrower Group Member); provided that such Liens and any rights in respect thereof are subject to the terms of the Collateral Agency Agreement, and the Borrower shall be in compliance (on a Pro Forma Basis reasonably acceptable to the Administrative Agent) with the covenant contained in Section 6.09;

(x)Section 6.01(v) of the Credit Agreement is hereby renumbered as Section 6.01(w).

(y)The Credit Agreement is hereby amended to insert a new Section 6.01(v) as follows:

Liens securing Indebtedness or arising in connection with Receivables Facilities, provided, that the sum (without duplication) of all such Indebtedness, plus the aggregate investment or claim held at any time by all purchasers, assignees or other transferees of (or of interests in) receivables and other rights to payment in all Receivables Facilities shall not at any time exceed $250,000,000; and

(z)Section 6.02(d) of the Credit Agreement is hereby amended by deleting “15%” and inserting therefor “20%”.

(aa)Section 6.02(i) of the Credit Agreement is hereby amended by deleting “$5,000,000” and inserting therefor “$10,000,000”.

(bb)Section 6.02(j) of the Credit Agreement is hereby amended by deleting it in its entirety and inserting therefor “[reserved];”.

(cc)Section 6.02(k) of the Credit Agreement is hereby amended by deleting “.” from the end of the paragraph and inserting therefor “; and”.

(dd)The Credit Agreement is hereby amended to insert a new Section 6.02(l) as follows:

the sale, assignment or other transfer of accounts receivable or other rights to payment pursuant to any Receivables Facility.

(ee)The final paragraph of Section 6.02 of the Credit Agreement is hereby amended by deleting “covenants” and inserting therefor “covenant”.

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(ff)Section 6.09(a) of the Credit Agreement is hereby amended by deleting it in its entirety and inserting therefor “RESERVED”.

(gg)Section 9.02(b) of the Credit Agreement is hereby amended by deleting from the first sentence “Neither” and inserting therefor “Except as provided in Section 2.22 with respect to the extension of the then-existing Revolving Credit Maturity Date, neither”.

(hh)Section 9.04(b)(iii) of the Credit Agreement is hereby amended by inserting “(and stated interest)” after “principal amount”.

(ii)Schedule 2.01 to the Credit Agreement is hereby amended by deleting the Lender commitment table and inserting therefor the following table:

Lender	Commitment
CoBank, ACB	110,000,000
Export Development Canada	80,000,000
JPMorgan Chase Bank, N.A.	80,000,000
Wells Fargo Bank, National Association	48,000,000
Bank of America, N.A.	52,000,000
Barclays Bank plc	40,000,000
SunTrust Bank	60,000,000
The Bank of Nova Scotia	60,000,000
The Royal Bank of Scotland plc	60,000,000
Union Bank, N.A.	60,000,000
US Bank, National Association	52,000,000
KeyBank National Association	42,000,000
Canadian Imperial Bank of Commerce	40,000,000
Associated Bank, N.A.	16,000,000
Aggregate Commitments		$800,000,000

2.Conditions of Effectiveness. The effectiveness of this Amendment is subject to the conditions precedent that the Administrative Agent shall have received:

(a)counterparts of this Amendment duly executed by the Borrower, the Lenders and the Administrative Agent;

(b)such documents, opinion letters and certificates as the Administrative Agent or its counsel may reasonably request relating to the organization, existence and good standing (or the equivalent in the applicable jurisdiction) of the Borrower, the authorization of the transactions contemplated by this Amendment and any other legal matters relating to the Borrower, the Financing Documents or the transactions contemplated by this Amendment, all in form and substance reasonably satisfactory to the Administrative Agent and its counsel; and

(c)all fees and other amounts due and payable on or prior to the Amendment No. 2 Effective Date, including, to the extent invoiced, reimbursement or payment of all out-of-pocket expenses required to be reimbursed or paid by the Borrower under the Financing Documents.

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3.Representations and Warranties of the Borrower. The Borrower hereby represents and warrants as follows:

(a)This Amendment and the Credit Agreement, as amended hereby, constitute legal, valid and binding obligations of the Borrower and are enforceable against the Borrower in accordance with their terms, subject to applicable bankruptcy, insolvency, reorganization, moratorium or other laws affecting creditors’ rights generally and subject to general principles of equity, regardless of whether considered in a proceeding in equity or at law.

(b)As of the date hereof and giving effect to the terms of this Amendment, (i) no Default shall have occurred and be continuing and (ii) the representations and warranties of the Borrower set forth in the Credit Agreement, as amended hereby, are true and correct as of the date hereof.

4.Reference to and Effect on the Credit Agreement.

(a)Upon the effectiveness hereof, each reference to the Credit Agreement in the Credit Agreement or any other Financing Document shall mean and be a reference to the Credit Agreement as amended hereby. This Amendment shall constitute a Financing Document.

(b)Except as specifically amended above, the Credit Agreement and all other documents, instruments and agreements executed and/or delivered in connection therewith shall remain in full force and effect and are hereby ratified and confirmed.

(c)The execution, delivery and effectiveness of this Amendment shall not operate as a waiver of any right, power or remedy of the Administrative Agent or the Lenders, nor constitute a waiver of any provision of the Credit Agreement or any other documents, instruments and agreements executed and/or delivered in connection therewith.

5.Governing Law. This Amendment shall be construed in accordance with and governed by the law of the State of New York.

6.Headings. Section headings in this Amendment are included herein for convenience of reference only and shall not constitute a part of this Amendment for any other purpose.

7.Counterparts. This Amendment may be executed by one or more of the parties hereto on any number of separate counterparts, and all of said counterparts taken together shall be deemed to constitute one and the same instrument. Signatures delivered by facsimile or PDF shall have the same force and effect as manual signatures delivered in person.

[SIGNATURE PAGES FOLLOW]

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IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed by their respective authorized officers as of the day and year first above written.

PUGET ENERGY, INC.

as the Borrower

By: /s/ Brandon Lohse

Name:    Brandon Lohse

Title:    Corporate Treasurer

Signature Page to

Amendment No. 2 to Credit Agreement

(Puget Energy, Inc.)

JPMORGAN CHASE BANK, N.A.

as a Lender and as the Administrative Agent

By: /s/ Helen D. Davis

Name: Helen D. Davis

Title: Vice President

Signature Page to

Amendment No. 2 to Credit Agreement

(Puget Energy, Inc.)

COBANK, ACB

as a Lender

By: /s/ Dave James

Name: Dave James

Title: Vice President

Signature Page to

Amendment No. 2 to Credit Agreement

(Puget Energy, Inc.)

EXPORT DEVELOPMENT CANDADA,

as a Lender

By: /s/ Oscar Klinge

Name: Oscar Klinge

Title: Senior Associate

Structure and Project Finance

By: /s/ Guillermo Freire

Name: Guillermo Freire

Title: Directors, Power & Utilities

Structure and Project Finance

Signature Page to

Amendment No. 2 to Credit Agreement

(Puget Energy, Inc.)

WELLS FARGO BANK, NATIONAL ASSOCIATION

as a Lender,

By: /s/ Yann Blinert

Name: Yann Blinert

Title: Director

Signature Page to

Amendment No. 2 to Credit Agreement

(Puget Energy, Inc.)

BANK OF AMERICA, N.A.

as a Lender

By: /s/ Stephen Maloney

Name: Stephen Maloney

Title: Senior Vice President

Signature Page to

Amendment No. 2 to Credit Agreement

(Puget Energy, Inc.)

BARCLAYS BANK PLC

as a Lender

By: /s/ Vanessa A. Kurbatskiy

Name: Vanessa A. Kurbatskiy

Title: Vice President

Signature Page to

Amendment No. 2 to Credit Agreement

(Puget Energy, Inc.)

SUNTRUST BANK

as a Lender

By: /s/ Yann Pirio

Name: Yann Pirio

Title: Managing Director

Signature Page to

Amendment No. 2 to Credit Agreement

(Puget Energy, Inc.)

The Bank of Nova Scotia

as a Lender

By: /s/ Thane Rattew

Name: Thane Rattew    

Title: Managing Director

Signature Page to

Amendment No. 2 to Credit Agreement

(Puget Energy, Inc.)

THE ROYAL BANK OF SCOTLAND PLC

as a Lender and an Energy Hedging Issuing Bank

By: /s/ Andrew N Taylor

Name: Andrew N Taylor

Title: Vice President

Signature Page to

Amendment No. 2 to Credit Agreement

(Puget Energy, Inc.)

UNION BANK, N.A.

as a Lender

By: /s/ Jeff Fesenmaier

Name: Jeff Fesenmaier

Title: Director

Signature Page to

Amendment No. 2 to Credit Agreement

(Puget Energy, Inc.)

US BANK, NATIONAL ASSOCIATION

as a Lender

By: /s/ Holland H. Williams

Name: Holland H. Williams

Title: Vice President & Portfolio Manager

Signature Page to

Amendment No. 2 to Credit Agreement

(Puget Energy, Inc.)

KEYBANK NATIONAL ASSOCIATION

as a Lender

By: /s/ Keith D Smith

Name: Keith D Smith

Title: Senior Vice President

Signature Page to

Amendment No. 2 to Credit Agreement

(Puget Energy, Inc.)

Canadian Imperial Bank of Commerce, New York Branch

as a Lender

By: /s/ Anju Abraham

Name: Anju Abraham

Title:

By: /s/ Robert Casey

Name: Robert Casey

Title:

Signature Page to

Amendment No. 2 to Credit Agreement

(Puget Energy, Inc.)

Associated Bank, N.A.

as a Lender

By: /s/ Kristin Isleib

Name: Kristin Isleib

Title: Senior Vice President

Signature Page to

Amendment No. 2 to Credit Agreement

(Puget Energy, Inc.)

EX-10.2

Exhibit 10.2

AMENDMENT NO. 1

to

CREDIT AGREEMENT

THIS AMENDMENT NO. 1 (“Amendment”) is made as of April 15, 2014 by and among Puget Sound Energy, Inc. (“Borrower”), the Lenders party hereto (the “Lenders”) and Wells Fargo Bank, National Association, as Administrative Agent (in such capacity, the “Administrative Agent”).

WHEREAS, Borrower, Lenders and Administrative Agent are parties to that certain Credit Agreement, dated as of February 4, 2013 (as amended, restated, supplemented or otherwise modified prior to the date hereof, the “Credit Agreement”). Capitalized terms used herein and not otherwise defined shall have the meanings ascribed to them in the Credit Agreement;

WHEREAS, the Borrower has requested that the Lenders and the Administrative Agent agree to certain amendments to the Credit Agreement;

WHEREAS, the Lenders party hereto and the Administrative Agent have agreed to such amendments on the terms and conditions set forth herein;

NOW, THEREFORE, in consideration of the premises set forth above, the terms and conditions contained herein, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Borrower, the Lenders party hereto and the Administrative Agent have agreed to enter into this Amendment.

1.Amendments to Credit Agreement. Effective as of the date of satisfaction of the conditions precedent set forth in Section 2 below, the Credit Agreement is hereby amended as follows:

(a)The definition of “Excluded Taxes” appearing in Section 1.01 of the Credit Agreement is hereby amended and restated in its entirety to read as follows:

“Excluded Taxes” means any of the following Taxes imposed on or with respect to a Recipient or required to be withheld or deducted from a payment to a Recipient, (a) Taxes imposed on or measured by net income (however denominated), franchise Taxes, and branch profits Taxes, in each case, (i) imposed as a result of such Recipient being organized under the laws of, or having its principal office or, in the case of any Lender, its applicable lending office located in, the jurisdiction imposing such Tax (or any political subdivision thereof) or (ii) that are Other Connection Taxes, (b) in the case of a Lender, U.S. Federal withholding Taxes imposed on amounts payable to or for the account of such Lender with respect to an applicable interest in a Loan or Commitment pursuant to a law in effect on the date on which (i) such Lender acquires such interest in the Loan or Commitment (other than pursuant to an assignment request by the Borrower under Section 2.20(b)) or (ii) such Lender changes its lending office, except in each case to the extent that, pursuant to Section 2.18, amounts with respect to such Taxes were payable either to such Lender’s assignor immediately before such Lender acquired the applicable interest in a Loan or Commitment or to such Lender immediately before it changed its lending office, (c) Taxes attributable to such Recipient’s failure to comply with Section 2.18(f), (d) any U.S. Federal withholding Taxes imposed under FATCA and (e) any Business and Occupation Taxes imposed by the State of Washington.

(b)The definition of “FATCA” appearing in Section 1.01 of the Credit Agreement is hereby amended and restated in its entirety to read as follows:

“FATCA” means Sections 1471 through 1474 of the Code, as of the date of this Agreement (or any amended or successor version that is substantively comparable and not materially more onerous to comply with), any current or future regulations or official interpretations thereof and any agreement entered into pursuant to Section 1471(b)(1) of the Code.

(c)The definition of “Interest Payment Date” is amended by deleting the text “(other than a Swingline Loan)”.

(d)The definition of “LIBO Rate” appearing in Section 1.01 of the Credit Agreement is hereby amended and restated in its entirety to read as follows:

“LIBO Rate” means, with respect to any Eurodollar Borrowing for any applicable Interest Period, the London interbank offered rate administered by ICE Benchmark Administration (or any other Person that takes over the administration of such rate) for Dollars for a period equal in length to such Interest Period as displayed on pages LIBOR01 or LIBOR02 of the Reuters screen or, in the event such rate does not appear on either of such Reuters pages, on any successor or substitute page on such screen that displays such rate, or on the appropriate page of such other information service that publishes such rate as shall be selected by the Administrative Agent from time to time in its reasonable discretion (in each case the “LIBOR Screen Rate”) at approximately 11:00 a.m., London time, two (2) Business Days prior to the commencement of such Interest Period; provided that, if the LIBOR Screen Rate shall be less than zero, such rate shall be deemed to be zero for purposes of this Agreement; provided, further, that if a LIBOR Screen Rate shall not be available at such time for such Interest Period (the “Impacted Interest Period”), then the LIBO Rate for such Interest Period shall be the Interpolated Rate; provided, that, if any Interpolated Rate shall be less than zero, such rate shall be deemed to be zero for purposes of this Agreement. It is understood and agreed that all of the terms and conditions of this definition of “LIBO Rate” shall be subject to Section 2.15.

(e)The definition of “Maturity Date” appearing in Section 1.01 of the Credit Agreement is hereby amended by deleting “February 4, 2018” and inserting therefor “April 15, 2019, as such date may be extended in accordance with Section 2.24”.

(f)The definition of “Other Connection Taxes” appearing in Section 1.01 of the Credit Agreement is hereby amended and restated in its entirety to read as follows:

“Other Connection Taxes” means, with respect to any Recipient, Taxes imposed as a result of a present or former connection between such Recipient and the jurisdiction imposing such Tax (other than connections arising from such Recipient having executed, delivered, become a party to, performed its obligations under, received payments under, received or perfected a security interest under, engaged in any other transaction pursuant to or enforced any Financing Document, or sold or assigned an interest in any Loan or Financing Document).

(g)Clause (viii) of the definition of “Permitted Acquisition” appearing in Section 1.01 of the Credit Agreement is hereby amended by deleting “covenants” and inserting therefor “covenant”.

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(h)The definition of “Recipient” appearing in Section 1.01 of the Credit Agreement is hereby amended and restated in its entirety to read as follows:

“Recipient” means (a) the Administrative Agent, (b) any Lender and (c) the Issuing Bank, as applicable.

(i)Section 1.01 of the Credit Agreement is hereby amended to insert the following defined terms in the appropriate alphabetical order:

“Additional Commitment Lender” has the meaning assigned to such term in Section 2.24.

“Amendment No. 1 Effective Date” means April 15, 2014.

“Anti-Corruption Laws” means all laws, rules, and regulations of any jurisdiction applicable to the Borrower or its Subsidiaries from time to time concerning or relating to bribery or corruption.

“Connection Income Taxes” means Other Connection Taxes that are imposed on or measured by net income (however denominated) or that are franchise Taxes or branch profits Taxes.

“Existing Revolving Credit Maturity Date” has the meaning assigned to such term in Section 2.24(a).

“Extending Lender” has the meaning assigned to such term in Section 2.24(b).

“Extension Date” has the meaning assigned to such term in Section 2.24(a).

“Impacted Interest Period” has the meaning assigned to such term in the definition of “LIBO Rate”.

“Interpolated Rate” means, at any time, the rate per annum determined by the Administrative Agent (which determination shall be conclusive and binding absent manifest error) to be equal to the rate that results from interpolating on a linear basis between: (a) the LIBOR Screen Rate for the longest period (for which the LIBOR Screen Rate is available) that is shorter than the Impacted Interest Period and (b) the LIBOR Screen Rate for the shortest period (for which the LIBOR Screen Rate is available) that exceeds the Impacted Interest Period, in each case, at such time.

“Lender Notice Date” has the meaning assigned to such term in Section 2.24(a).

“LIBOR Market Index Rate” means, for any day, the London interbank offered rate administered by ICE Benchmark Administration (or any other Person that takes over the administration of such rate) for Dollars for a period equal to one month as displayed on pages LIBOR01 or LIBOR02 of the Reuters screen or, in the event such rate does not appear on either of such Reuters pages, on any successor or substitute page on such screen that displays such rate, or on the appropriate page of such other information service that

3

publishes such rate as shall be selected by the Administrative Agent from time to time in its reasonable discretion (in each case the “LIBOR Screen Rate”) at approximately 11:00 a.m., London time, on such day, or if such day is not a London Banking Day, then the immediately preceding London Banking Day (or if not so reported, then as determined by the Administrative Agent from another recognized source or interbank quotation), or another rate as agreed to by the Administrative Agent and the Borrower. Any change in the Swing Line LIBOR Rate due to a change in the LIBOR Market Index Rate shall be effective from and including the effective date of such change in the LIBOR Market Index Rate.

“LIBOR Screen Rate” has the meaning assigned to such term in the definition of “LIBO Rate”.

“London Banking Day” means any day on which dealings in Dollar deposits are conducted by and between banks in the London interbank eurodollar market.

“Non-Extending Lender” has the meaning assigned to such term in Section 2.24(b).

“OFAC” means the Office of Foreign Assets Control of the U.S. Department of the Treasury.

“Revolving Credit Maturity Date” has the meaning assigned to such term in Section 2.24(a).

“Sanctioned Country” means, at any time, a country or territory which is the subject or target of any Sanctions.

“Sanctioned Person” means, at any time, (a) any Person listed in any Sanctions-related list of designated Persons maintained by OFAC, the U.S. Department of State, the United Nations Security Council, the European Union or any EU member state, (b) any Person operating, organized or resident in a Sanctioned Country or (c) any Person controlled by any such Person.

“Sanctions” means economic or financial sanctions or trade embargoes imposed, administered or enforced from time to time by (a) the U.S. government, including those administered by OFAC or the U.S. Department of State or (b) the United Nations Security Council, the European Union or Her Majesty’s Treasury of the United Kingdom.

“Swing Line ABR Rate” means, for any day, with respect to any Swingline Loan, a rate per annum equal to (i) the Alternate Base Rate for such day, plus (ii) the Applicable Rate for ABR Loans.

“Swing Line LIBOR Rate” means, for any day, with respect to any Swingline Loan, a rate per annum equal to (i) the LIBOR Market Index Rate for such day, plus (ii) the Applicable Rate for Eurodollar Loans.

(j)Section 1.01 of the Credit Agreement is hereby amended by deleting in its entirety the definition of “Quarter End Date”.

4

(k)Section 2.02(b) of the Credit Agreement is hereby amended by deleting the sentence “Each Swingline Loan shall be an ABR Loan.”

(l)Section 2.05(b) of the Credit Agreement is hereby amended by (i) replacing the second sentence therein with the following:

Each such notice shall be irrevocable and shall specify the requested date (which shall be a Business Day), the amount of the requested Swingline Loan, whether the requested Swingline Loan will bear interest at the Swing Line ABR Rate or the Swing Line LIBOR Rate, and identify the account, including routing information, where such Swingline Loan shall be deposited.

and (ii) adding the following immediately after the last sentence of Section 2.05(b):

If no election is specified as to whether a requested Swingline Loan will bear interest at the Swing Line ABR Rate or the Swing Line LIBOR Rate, then the requested Swingline Loan shall bear interest at the Swing Line ABR Rate.

(m)Section 2.06(e) is hereby amended by replacing each occurrence of the text “Swingline Loan” with the text “Swingline Loan bearing interest at the Swing Line ABR Rate”.

(n)Section 2.14(a) is hereby amended and restated in its entirety to read as follows:

The Loans comprising each ABR Borrowing shall bear interest at the Alternate Base Rate plus the Applicable Rate. Swingline Loans shall bear interest at the Swing Line ABR Rate or the Swing Line LIBOR Rate, as elected by the Borrower or otherwise determined pursuant to Section 2.05(b).

(o)Section 2.14(e) is amended by adding the text “, LIBOR Market Index Rate” immediately after the text “Adjusted LIBO Rate”.

(p)Section 2.20(b) of the Credit Agreement is hereby amended by inserting “a Non-Extending Lender pursuant to Section 2.24 or” before the phrase “a Defaulting Lender” in the first clause (iii).

(q)The Credit Agreement is hereby amended to insert a new Section 2.24 as follows:

Extension of Revolving Credit Maturity Date.

(a)    The Borrower may, at any time, from time to time, not more than ninety (90) days and not less than thirty (30) days prior to any anniversary of the Amendment No. 1 Effective Date, by notice to the Administrative Agent (who shall promptly notify the Lenders) not later than 10 Business Days (or such shorter period as the Administrative Agent may agree in its reasonable discretion) prior to the date on which the Lenders are requested to respond thereto (each such date, a “Lender Notice Date”), request that each Lender extend (each such date on which such extension occurs, an “Extension Date”) the Maturity Date with respect to such Lender’s Loans (such Lender’s “Revolving Credit Maturity Date”) to the date that is one year after the Revolving Credit Maturity Date then in effect for such Lender (such Lender’s “Existing Revolving Credit Maturity Date”).

(b)    Each Lender, acting in its sole and individual discretion, shall, by notice to the Administrative Agent given not later than the applicable Lender Notice Date, advise the

5

Administrative Agent whether or not such Lender agrees to such extension (each Lender that determines to so extend its Revolving Credit Maturity Date, an “Extending Lender”). Each Lender that determines not to so extend its Revolving Credit Maturity Date (a “Non-Extending Lender”) shall notify the Administrative Agent of such fact promptly after such determination (but in any event no later than the Lender Notice Date), and any Lender that does not advise the Administrative Agent of its election to agree to such an extension on or before the Lender Notice Date shall be deemed to be a Non-Extending Lender. The election of any Lender to agree to such extension shall not obligate any other Lender to so agree, and it is understood and agreed that no Lender shall have any obligation whatsoever to agree to any request made by the Borrower for extension of its Revolving Credit Maturity Date.

(c)    The Administrative Agent shall promptly notify the Borrower of each Lender’s determination under this Section.

(d)    The Borrower shall have the right, but shall not be obligated, on or before the applicable Revolving Credit Maturity Date for any Non-Extending Lender to replace such Non-Extending Lender with, and add as “Lenders” under this Agreement in place thereof, one or more financial institutions (each, an “Additional Commitment Lender”) approved by the Administrative Agent and the Issuing Banks in accordance with the procedures provided in Section 2.20(b), each of which Additional Commitment Lenders shall have entered into an Assignment and Assumption (in accordance with and subject to the restrictions contained in Section 9.04, with the Borrower or replacement Lender obligated to pay any applicable processing or recordation fee) with such Non-Extending Lender, pursuant to which such Additional Commitment Lenders shall, effective on or before the Revolving Credit Maturity Date for such Non-Extending Lender, assume a Commitment (and, if any such Additional Commitment Lender is already a Lender, its Commitment shall be in addition to such Lender’s Commitment hereunder on such effective date).  Prior to any Non-Extending Lender being replaced by one or more Additional Commitment Lenders pursuant hereto, such Non-Extending Lender may elect, in its sole discretion, by giving irrevocable notice thereof to the Administrative Agent and the Borrower (which notice shall set forth such Lender’s new Revolving Credit Maturity Date), to become an Extending Lender.  The Administrative Agent may effect such amendments to this Agreement as are reasonably necessary to provide for any such extensions with the consent of the Borrower but without the consent of any other Lenders.

(e)    If (and only if) the total of the Commitments of the Lenders that have agreed to extend their Revolving Credit Maturity Date is more than 50% of the aggregate amount of the Commitments in effect immediately prior to the applicable Extension Date, then, effective as of the applicable Extension Date, the Revolving Credit Maturity Date of each Extending Lender and of each Additional Commitment Lender shall be extended to the date that is one year after the Existing Revolving Credit Maturity Date (except that, if such date is not a Business Day, such Revolving Credit Maturity Date as so extended shall be the next preceding Business Day) and each Additional Commitment Lender shall thereupon become a “Lender” for all purposes of this Agreement and shall be bound by the provisions of this Agreement as a Lender hereunder and shall have the obligations of a Lender hereunder.

(f)    Notwithstanding the foregoing, (x) no more than two (2) extensions of the Revolving Credit Maturity Date shall be permitted hereunder (and not more than one such extension may be requested during any nine-month period) and (y) any extension of any Revolving Credit Maturity Date pursuant to this Section 2.24 shall not be effective with respect to any Extending Lender unless:

6

(i)    there shall exist no Default or Event of Default on the applicable Extension Date and immediately after giving effect thereto;

(ii)    the representations and warranties made by the Borrower contained herein shall be true and correct in all material respects (other than to the extent qualified by materiality or “Material Adverse Effect”, in which case, such representations and warranties shall be true and correct) with the same effect as though such representations and warranties had been made on and as of the date of such extension (or to the extent that such representations and warranties specifically refer to an earlier date, as of such earlier date); and

(iii)    the Administrative Agent shall have received a certificate from the Borrower signed by an Authorized Officer of the Borrower (A) certifying the accuracy of the foregoing clauses (i) and (ii) and (B) certifying and attaching the resolutions adopted by the Borrower approving or consenting to such extension.

(g)    On the Revolving Credit Maturity Date of each Non-Extending Lender, (i) the Revolving Credit Commitment of each Non-Extending Lender shall automatically terminate and (ii) the Borrower shall repay such Non-Extending Lender in accordance with Section 2.11 (and shall pay to such Non-Extending Lender all of the other obligations owing to it under this Agreement) and after giving effect thereto shall prepay any Loans outstanding on such date (and pay any additional amounts required pursuant to Section 2.17) to the extent necessary to keep outstanding Loans ratable with any revised Applicable Percentage of the respective Lenders effective as of such date, and the Administrative Agent shall administer any necessary reallocation of the Revolving Credit Exposures (without regard to any minimum borrowing, pro rata borrowing and/or pro rata payment requirements contained elsewhere in this Agreement).

(h)    This Section shall supersede any provisions in Section 9.02 to the contrary.

(r)The Credit Agreement is hereby amended to insert a new Section 3.22 as follows:

Anti-Corruption Laws and Sanctions. The Borrower has implemented and maintains in effect policies and procedures designed to ensure compliance by the Borrower, its Subsidiaries and their respective directors, officers, employees and agents with Anti-Corruption Laws and applicable Sanctions, and the Borrower, its Subsidiaries and their respective officers and employees and to the knowledge of the Borrower its directors and agents, are in compliance with Anti-Corruption Laws and applicable Sanctions in all material respects. None of (a) the Borrower, any Subsidiary or to the knowledge of the Borrower or such Subsidiary any of their respective directors, officers or employees, or (b) to the knowledge of the Borrower, any agent of the Borrower or any Subsidiary that will act in any capacity in connection with or benefit from the credit facility established hereby, is a Sanctioned Person. No Borrowing or Letter of Credit, use of proceeds or other Transactions will violate Anti-Corruption Laws or applicable Sanctions.

(s)Section 5.04 of the Credit Agreement is hereby amended to insert a new clause (c) as follows: “The Borrower will maintain in effect and enforce policies and procedures designed to ensure compliance by the Borrower, its Subsidiaries and their respective directors, officers, employees and agents with Anti-Corruption Laws and applicable Sanctions.”

(t)Section 5.09 of the Credit Agreement is hereby amended by adding the following sentence to the end: “The Borrower will not request any Borrowing or Letter of Credit, and the Borrower shall not use, and shall procure that its Subsidiaries and its or their respective directors, officers,

7

employees and agents shall not use, the proceeds of any Borrowing or Letter of Credit (i) in furtherance of an offer, payment, promise to pay, or authorization of the payment or giving of money, or anything else of value, to any Person in violation of any Anti-Corruption Laws, (ii) for the purpose of funding, financing or facilitating any activities, business or transaction of or with any Sanctioned Person, or in any Sanctioned Country or (iii) in any manner that would result in the violation of any Sanctions applicable to any party hereto.”

(u)Section 9.02(b) of the Credit Agreement is hereby amended by deleting from the first sentence “Neither” and inserting therefor “Except as provided in Section 2.24 with respect to the extension of the then-existing Revolving Credit Maturity Date, neither”.

(v)Section 9.04(b)(iii) of the Credit Agreement is hereby amended by inserting “(and stated interest)” after “principal amount”.

(w)Schedule 2.01 to the Credit Agreement is hereby amended by deleting the Lender commitment table and inserting therefor the following table:

Lender	Liquidity Commitment		Energy Hedging Commitment		Total Commitment
Wells Fargo Bank, National Association		$33,800,000.00		$18,200,000.00		$52,000,000.00
CoBank, ACB		$81,250,000.00		$43,750,000.00		$125,000,000.00
Export Development Canada		$55,250,000.00		$29,750,000.00		$85,000,000.00
JPMorgan Chase Bank, N.A.		$13,000,000.00		$7,000,000.00		$20,000,000.00
Bank of America, N.A.		$31,200,000.00		$16,800,000.00		$48,000,000.00
Barclays Bank plc		$39,000,000.00		$21,000,000.00		$60,000,000.00
SunTrust Bank		$26,000,000.00		$14,000,000.00		$40,000,000.00
The Bank of Nova Scotia		$26,000,000.00		$14,000,000.00		$40,000,000.00
The Royal Bank of Scotland plc		$26,000,000.00		$14,000,000.00		$40,000,000.00
Union Bank, N.A.		$26,000,000.00		$14,000,000.00		$40,000,000.00
US Bank, National Association		$31,200,000.00		$16,800,000.00		$48,000,000.00
KeyBank National Association		$30,116,666.67		$16,216,666.67		$46,333,333.34
Canadian Imperial Bank of Commerce		$31,416,666.66		$16,916,666.67		$48,333,333.33
TD Bank, N.A.		$57,416,666.67		$30,916,666.66		$88,333,333.33
Royal Bank of Canada		$48,750,000.00		$26,250,000.00		$75,000,000.00
The Bank of New York Mellon		$48,750,000.00		$26,250,000.00		$75,000,000.00
National Cooperative Services Corporation		$32,500,000.00		$17,500,000.00		$50,000,000.00
Associated Bank, N.A.		$12,350,000.00		$6,650,000.00		$19,000,000.00
Total		$650,000,000.00		$350,000,000.00		$1,000,000,000.00

2.Conditions of Effectiveness. The effectiveness of this Amendment is subject to the conditions precedent that the Administrative Agent shall have received:

8

(a)counterparts of this Amendment duly executed by the Borrower, the Lenders, the Liquidity Issuing Banks (other than the Existing Liquidity Issuing Banks), the Energy Hedging Issuing Banks and the Administrative Agent;

(b)such documents, opinion letters and certificates as the Administrative Agent or its counsel may reasonably request relating to the organization, existence and good standing (or the equivalent in the applicable jurisdiction) of the Borrower, the authorization of the transactions contemplated by this Amendment and any other legal matters relating to the Borrower, the Financing Documents or the transactions contemplated by this Amendment, all in form and substance reasonably satisfactory to the Administrative Agent and its counsel; and

(c)all fees and other amounts due and payable on or prior to the Amendment No. 1 Effective Date, including, to the extent invoiced, reimbursement or payment of all out-of-pocket expenses required to be reimbursed or paid by the Borrower under the Financing Documents.

3.Representations and Warranties of the Borrower. The Borrower hereby represents and warrants as follows:

(a)This Amendment and the Credit Agreement, as amended hereby, constitute legal, valid and binding obligations of the Borrower and are enforceable against the Borrower in accordance with their terms, subject to applicable bankruptcy, insolvency, reorganization, moratorium or other laws affecting creditors’ rights generally and subject to general principles of equity, regardless of whether considered in a proceeding in equity or at law.

(b)As of the date hereof and giving effect to the terms of this Amendment, (i) no Default shall have occurred and be continuing and (ii) the representations and warranties of the Borrower set forth in the Credit Agreement, as amended hereby, are true and correct as of the date hereof.

4.Reference to and Effect on the Credit Agreement.

(a)Upon the effectiveness hereof, each reference to the Credit Agreement in the Credit Agreement or any other Financing Document shall mean and be a reference to the Credit Agreement as amended hereby. This Amendment shall constitute a Financing Document.

(b)Except as specifically amended above, the Credit Agreement and all other documents, instruments and agreements executed and/or delivered in connection therewith shall remain in full force and effect and are hereby ratified and confirmed.

(c)The execution, delivery and effectiveness of this Amendment shall not operate as a waiver of any right, power or remedy of the Administrative Agent or the Lenders, nor constitute a waiver of any provision of the Credit Agreement or any other documents, instruments and agreements executed and/or delivered in connection therewith.

5.Governing Law. This Amendment shall be construed in accordance with and governed by the law of the State of New York.

6.Headings. Section headings in this Amendment are included herein for convenience of reference only and shall not constitute a part of this Amendment for any other purpose.

9

7.Counterparts. This Amendment may be executed by one or more of the parties hereto on any number of separate counterparts, and all of said counterparts taken together shall be deemed to constitute one and the same instrument. Signatures delivered by facsimile or PDF shall have the same force and effect as manual signatures delivered in person.

[SIGNATURE PAGES FOLLOW]

10

IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed by their respective authorized officers as of the day and year first above written.

PUGET SOUND ENERGY, INC.

as the Borrower

By: /s/ Brandon Lohse

Name:    Brandon Lohse

Title:    Corporate Treasurer

Signature Page to

Amendment No. 1 to Credit Agreement

(Puget Sound Energy, Inc.)

WELLS FARGO BANK, NATIONAL ASSOCIATION

as a Lender, a Liquidity Issuing Bank, an Energy Hedging Issuing Bank and the Administrative Agent

By: /s/ Yann Blinert

Name: Yann Blinert

Title: Director

Signature Page to

Amendment No. 1 to Credit Agreement

(Puget Sound Energy, Inc.)

COBANK, ACB

as a Lender

By: /s/ Dave James

Name: Dave James

Title: Vice President

Signature Page to

Amendment No. 1 to Credit Agreement

(Puget Sound Energy, Inc.)

EXPORT DEVELOPMENT CANDADA,

as a Lender

By: /s/ Oscar Klinge

Name: Oscar Klinge

Title: Senior Associate

Structure and Project Finance

By: /s/ Guillermo Freire

Name: Guillermo Freire

Title: Directors, Power & Utilities

Structure and Project Finance

Signature Page to

Amendment No. 1 to Credit Agreement

(Puget Sound Energy, Inc.)

JPMORGAN CHASE BANK, N.A.

as a Lender

By: /s/ Helen D. Davis

Name: Helen D. Davis

Title: Vice President

Signature Page to

Amendment No. 1 to Credit Agreement

(Puget Sound Energy, Inc.)

BANK OF AMERICA, N.A.

as a Lender

By: /s/ Stephen Maloney

Name: Stephen Maloney

Title: Senior Vice President

Signature Page to

Amendment No. 1 to Credit Agreement

(Puget Sound Energy, Inc.)

BARCLAYS BANK PLC

as a Lender

By: /s/ Vanessa A. Kurbatskiy

Name: Vanessa A. Kurbatskiy

Title: Vice President

Signature Page to

Amendment No. 1 to Credit Agreement

(Puget Sound Energy, Inc.)

SUNTRUST BANK

as a Lender

By: /s/ Yann Pirio

Name: Yann Pirio

Title: Managing Director

Signature Page to

Amendment No. 1 to Credit Agreement

(Puget Sound Energy, Inc.)

The Bank of Nova Scotia

as a Lender

By: /s/ Thane Rattew

Name: Thane Rattew    

Title: Managing Director

Signature Page to

Amendment No. 1 to Credit Agreement

(Puget Sound Energy, Inc.)

THE ROYAL BANK OF SCOTLAND PLC

as a Lender and an Energy Hedging Issuing Bank

By: /s/ Andrew N Taylor

Name: Andrew N Taylor

Title: Vice President

Signature Page to

Amendment No. 1 to Credit Agreement

(Puget Sound Energy, Inc.)

UNION BANK, N.A.

as a Lender

By: /s/ Jeff Fesenmaier

Name: Jeff Fesenmaier

Title: Director

Signature Page to

Amendment No. 1 to Credit Agreement

(Puget Sound Energy, Inc.)

US BANK, NATIONAL ASSOCIATION

as a Lender

By: /s/ Holland H. Williams

Name: Holland H. Williams

Title: Vice President & Portfolio Manager

Signature Page to

Amendment No. 1 to Credit Agreement

(Puget Sound Energy, Inc.)

KEYBANK NATIONAL ASSOCIATION

as a Lender

By: /s/ Keith D Smith

Name: Keith D Smith

Title: Senior Vice President

Signature Page to

Amendment No. 1 to Credit Agreement

(Puget Sound Energy, Inc.)

Canadian Imperial Bank of Commerce, New York Branch

as a Lender

By: /s/ Anju Abraham

Name: Anju Abraham

Title:

By: /s/ Robert Casey

Name: Robert Casey

Title:

Signature Page to

Amendment No. 1 to Credit Agreement

(Puget Sound Energy, Inc.)

TD BANK, N.A.

as a Lender

By: /s/ Stephen Levi

Name: Stephen Levi

Title: Senior Vice President

Signature Page to

Amendment No. 1 to Credit Agreement

(Puget Sound Energy, Inc.)

ROYAL BANK OF CANDA

as a Lender

By: /s/ Frank Lambrinos

Name: Frank Lambrinos

Title:

Signature Page to

Amendment No. 1 to Credit Agreement

(Puget Sound Energy, Inc.)

THE BANK OF NEW YORK MELLON

as a Lender

By: /s/ Mark W. Rogers

Name: Mark W. Rogers

Title: Vice President

Signature Page to

Amendment No. 1 to Credit Agreement

(Puget Sound Energy, Inc.)

NATIONAL COOPERATIVE SERVICES COOPERATION

as a Lender

By: /s/ Daniel Lyzinski

Name: Daniel Lyzinski

Title: Assistant Secretary Treasurer

Signature Page to

Amendment No. 1 to Credit Agreement

(Puget Sound Energy, Inc.)

Associated Bank, N.A.

as a Lender

By: /s/ Kristin Isleib

Name: Kristin Isleib

Title: Senior Vice President

Signature Page to

Amendment No. 1 to Credit Agreement

(Puget Sound Energy, Inc.)

EX-12.1

																			Exhibit 12.1
PUGET ENERGY
STATEMENT SETTING FORTH COMPUTATIONS OF RATIOS OF
EARNINGS TO FIXED CHARGES
(Dollars in Thousands)
	Successor																		Predecessor
																Period from			Period from
	12 Months															February 6, 2009			January 1, 2009
	Ended			Years Ended												through			through
	March 31,			December 31,												December 31,			February 5,
	2014			2013			2012			2011			2010			2009			2009
Earnings Available For Fixed Charges:
Pre-tax income:
Income from continuing operations before income taxes	$	319,182		$	408,136		$	378,546		$	157,050		$	32,792		$	256,056		$	21,753
AFUDC - equity	(10,842		)	(15,930		)	(25,469		)	(32,430		)	(12,677		)	(4,108		)	(69		)
AFUDC - debt	(7,766		)	(11,261		)	(22,216		)	(29,949		)	(14,157		)	(8,864		)	(350		)
Total	$	300,574		$	380,945		$	330,861		$	94,671		$	5,958		$	243,084		$	21,334
Fixed charges:
Interest expense	$	386,702		$	392,264		$	392,216		$	371,910		$	321,167		$	265,675		$	17,291
Other interest	10,842			15,930			25,469			32,430			12,677			4,108			69
Portion of rentals representative of the interest factor	10,153			10,257			10,251			8,767			5,391			9,131			1,081
Total	$	407,697		$	418,451		$	427,936		$	413,107		$	339,235		$	278,914		$	18,441
Earnings available for combined fixed charges	$	708,271		$	799,396		$	758,797		$	507,778		$	345,193		$	521,998		$	39,775
Ratio of Earnings to Fixed Charges	1.74x			1.91x			1.77x			1.23x			1.02x			1.87x			2.16x

EX-12.2

														Exhibit 12.2
PUGET SOUND ENERGY
STATEMENT SETTING FORTH COMPUTATIONS OF RATIOS OF
EARNINGS TO FIXED CHARGES
(Dollars in Thousands)
		12 Months
		Ended
		March 31,			Years Ended December 31,
		2014			2013			2012			2011			2010			2009
Earnings Available For Fixed Charges:
Pre-tax income:
Income from continuing operations before        income taxes	$	429,942		$	517,015		$	505,478		$	282,237		$	26,217		$	226,896
AFUDC - equity		(10,842	)		(15,930	)		(25,469	)		(32,430	)		(12,677	)		(4,177	)
AFUDC - debt		(7,766	)		(11,261	)		(22,216	)		(29,949	)		(14,157	)		(9,215	)
Total	$	411,334		$	489,824		$	457,793		$	219,858		$	(617	)	$	213,504
Fixed charges:
Interest expense	$	259,534		$	261,377		$	247,013		$	231,416		$	235,011		$	211,742
Other interest		10,842			15,930			25,469			32,430			12,677			4,177
Portion of rentals representative of the interest factor		10,153			10,257			10,251			8,767			5,391			10,212
Total	$	280,529		$	287,564		$	282,733		$	272,613		$	253,079		$	226,131
Earnings available for combined fixed charges	$	691,863		$	777,388		$	740,526		$	492,471		$	252,462		$	439,635
Ratio of Earnings to Fixed Charges		2.47x			2.70x			2.62x			1.81x			1.00x			1.94x

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Kimberly J. Harris, certify that:

I have reviewed this report on Form 10-Q of Puget Energy, Inc.;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

May 1, 2014

/s/ Kimberly J. Harris

Kimberly J. Harris

President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Daniel A. Doyle, certify that:

I have reviewed this report on Form 10-Q of Puget Energy, Inc.;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

May 1, 2014

/s/ Daniel A. Doyle

Daniel A. Doyle

Senior Vice President and Chief Financial Officer

EX-31.3

Exhibit 31.3

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Kimberly J. Harris, certify that:

I have reviewed this report on Form 10-Q of Puget Sound Energy, Inc.;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

May 1, 2014

/s/ Kimberly J. Harris

Kimberly J. Harris

President and Chief Executive Officer

EX-31.4

Exhibit 31.4

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Daniel A. Doyle, certify that:

I have reviewed this report on Form 10-Q of Puget Sound Energy, Inc.;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

May 1, 2014

/s/ Daniel A. Doyle

Daniel A. Doyle

Senior Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Report of Puget Energy, Inc. and Puget Sound Energy, Inc. (the “Companies”) on Form 10-Q for the period endedMarch 31, 2014 as filed with the Securities and Exchange Commission on the date hereof (the “Form 10-Q”), I, Kimberly J. Harris, President and Chief Executive Officer of the Companies, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Companies.

May 1, 2014

/s/ Kimberly J. Harris

Kimberly J. Harris

President and Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Report of Puget Energy, Inc. and Puget Sound Energy, Inc. (the “Companies”) on Form 10-Q for the period endedMarch 31, 2014 as filed with the Securities and Exchange Commission on the date hereof (the “Form 10-Q”), I, Daniel A. Doyle, Senior Vice President and Chief Financial Officer of the Companies, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Companies.

May 1, 2014

/s/ Daniel A. Doyle

Daniel A. Doyle

Senior Vice President and Chief Financial Officer

XML

Accumulated Other Comprehensive Income - Changes by Component (Details) (USD $) In Thousands, unless otherwise specified					3 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2014 Subsidiaries [Member]	Dec. 31, 2013 Subsidiaries [Member]	Mar. 31, 2014 Accumulated Defined Benefit Plans Adjustment [Member] PUGET ENERGY [Member]	Mar. 31, 2014 Accumulated Defined Benefit Plans Adjustment [Member] Subsidiaries [Member]	Mar. 31, 2014 Derivative [Member] PUGET ENERGY [Member]	Mar. 31, 2014 Derivative [Member] Subsidiaries [Member]	Mar. 31, 2014 Interest Rate Swap [Member] PUGET ENERGY [Member]	Mar. 31, 2014 Interest Rate Swap [Member] Subsidiaries [Member]	Mar. 31, 2014 Comprehensive Income [Member] PUGET ENERGY [Member]	Mar. 31, 2014 Comprehensive Income [Member] Subsidiaries [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance	$ 47,947	$ 47,715	$ (92,941)	$ (95,739)	$ 48,514	$ (87,405)	$ (705)	$ (2,027)	$ (94)	$ (6,307)	$ 47,715	$ (95,739)
Other comprehensive income (loss) before reclassifications					0	0	0	0	0	0	0	0
Amounts reclassified from accumulated other comprehensive income (loss), net of tax					(209)	2,001	347	718	94	79	232	2,798
Net current-period other comprehensive income (loss)					(209)	2,001	347	718	94	79	232	2,798
Ending balance	$ 47,947	$ 47,715	$ (92,941)	$ (95,739)	$ 48,305	$ (85,404)	$ (358)	$ (1,309)	$ 0	$ (6,228)	$ 47,947	$ (92,941)

XML

Fair Value Measurements Valuation Technicques for Measurement with Unobservable Inputs (Details) (USD $)				3 Months Ended
	Mar. 31, 2014	Mar. 31, 2014 Commodity Contract [Member]	Dec. 31, 2013 Commodity Contract [Member]	Mar. 31, 2014 Electric portfolio [Member] Discounted cash flow [Member] Low [Member]	Mar. 31, 2014 Electric portfolio [Member] Discounted cash flow [Member] High [Member]	Mar. 31, 2014 Electric portfolio [Member] Discounted cash flow [Member] Weighted Average [Member]	Mar. 31, 2014 Natural gas portfolio [Member] Discounted cash flow [Member] Low [Member]	Mar. 31, 2014 Natural gas portfolio [Member] Discounted cash flow [Member] High [Member]	Mar. 31, 2014 Natural gas portfolio [Member] Discounted cash flow [Member] Weighted Average [Member]	Mar. 31, 2014 Level 3 [Member] Fair Value, Measurements, Recurring [Member] Subsidiaries [Member]	Dec. 31, 2013 Level 3 [Member] Fair Value, Measurements, Recurring [Member] Subsidiaries [Member]	Mar. 31, 2014 Level 3 [Member] Fair Value, Measurements, Recurring [Member] PUGET ENERGY [Member]	Dec. 31, 2013 Level 3 [Member] Fair Value, Measurements, Recurring [Member] PUGET ENERGY [Member]	Mar. 31, 2014 Electric portfolio [Member] Level 3 [Member] Fair Value, Measurements, Recurring [Member] Subsidiaries [Member] Commodity Contract [Member]		Dec. 31, 2013 Electric portfolio [Member] Level 3 [Member] Fair Value, Measurements, Recurring [Member] Subsidiaries [Member] Commodity Contract [Member]	Mar. 31, 2014 Natural gas portfolio [Member] Level 3 [Member] Fair Value, Measurements, Recurring [Member] Subsidiaries [Member] Commodity Contract [Member]		Dec. 31, 2013 Natural gas portfolio [Member] Level 3 [Member] Fair Value, Measurements, Recurring [Member] Subsidiaries [Member] Commodity Contract [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets		$ 51,709,000	$ 26,600,000							$ 7,590,000	$ 6,491,000			$ 5,040,000	[1]	$ 3,818,000	$ 2,550,000	[1]	$ 2,673,000
Derivative Liabilities										23,299,000	22,273,000	0	0	19,646,000	[1]	19,239,000	3,653,000	[1]	3,034,000
Price (per MWh)				4.38	49.95	35.67
Price (per MMBtu)							3.62	4.63	4.04
Fair Value measurement, sensitivity analysis, hypothetical increase or decrease of market prices, result on fair value	10.00%
Fair Value Measurements, Sensitivity Analysis, Hypothetical Increase or Decrease of Market Prices, Result on Fair Value	$ 12,100,000

[1] 1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions

XML

Accounting for Derivative Instruments and Hedging Activities Derivative Assets and Liabilities (Details) (USD $)	3 Months Ended
	Mar. 31, 2014		Dec. 31, 2013
Derivative [Line Items]
Document Period End Date	Mar. 31, 2014
Unrealized gain on derivative instruments	$ 44,889,000		$ 18,867,000
Assets, Long-term	6,820,000		7,733,000
Unrealized loss on derivative instruments	33,213,000		48,049,000
Unrealized loss on derivative instruments	27,444,000		38,162,000
Subsidiaries [Member]
Derivative [Line Items]
Document Period End Date	Mar. 31, 2014
Unrealized gain on derivative instruments	44,889,000		18,867,000
Assets, Long-term	6,820,000		7,733,000
Unrealized loss on derivative instruments	26,461,000		41,465,000
Unrealized loss on derivative instruments	22,070,000		31,523,000
Commodity Contract [Member]
Derivative [Line Items]
Assets	51,709,000		26,600,000
Liabilities	48,531,000		72,988,000
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Assets	51,709,000	[1]	26,600,000	[1]
Liabilities	60,657,000	[2]	86,211,000	[2]
Not Designated as Hedging Instrument [Member] | PUGET ENERGY [Member]
Derivative [Line Items]
Unrealized gain on derivative instruments	44,889,000	[1]	18,867,000	[1]
Assets, Long-term	6,820,000	[1]	7,733,000	[1]
Unrealized loss on derivative instruments	33,213,000	[2]	48,049,000	[2]
Unrealized loss on derivative instruments	27,444,000	[2]	38,162,000	[2]
Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	450,000,000	[3]	450,000,000	[3]
Assets	0	[1],[3]	0	[1],[3]
Liabilities	12,126,000	[2],[3]	13,223,000	[2],[3]
Not Designated as Hedging Instrument [Member] | Electric portfolio [Member]
Derivative [Line Items]
Assets	23,906,000	[1]	18,479,000	[1]
Liabilities	34,365,000	[2]	37,312,000	[2]
Not Designated as Hedging Instrument [Member] | Natural gas portfolio [Member]
Derivative [Line Items]
Assets	27,803,000	[1],[4]	8,121,000	[1],[4]
Liabilities	$ 14,166,000	[2],[4]	$ 35,676,000	[2],[4]
Not Designated as Hedging Instrument [Member] | Natural Gas Derivatives [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	380,500,000	[4]	423,500,000	[4]

[1] 1 Balance sheet location: Current and Long-term Unrealized gain on derivative instruments.

[2] 2 Balance sheet location: Current and Long-term Unrealized loss on derivative instruments.

[3] 3 Interest rate swap contracts are only held at Puget Energy.

[4] 4 All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations” (ASC 980) due to the PGA mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers.

XML

Other Bond Issuances (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Jun. 30, 2013 Pollution Control Bonds [Member]	May 23, 2013 Pollution Control Bonds [Member] Subsidiaries [Member]	May 23, 2013 5.000% Series Due 2031 [Member] Subsidiaries [Member]	May 23, 2013 3.910% Series Due 2031 [Member] Subsidiaries [Member]	Mar. 01, 2023 Scenario, Forecast [Member] Pollution Control Bonds [Member] Subsidiaries [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 161.9
Debt Instrument, Interest Rate, Stated Percentage			5.01%	3.91%
Debt Instrument, Redemption Payment Term, Percentage of Principal Amount					100.00%
Gains (Losses) on Extinguishment of Debt	$ (18.0)

XML

Regulation and Rates (Details) (USD $) In Millions, unless otherwise specified	11 Months Ended										12 Months Ended
	Dec. 31, 2013 Subsidiaries [Member]	Jul. 02, 2013 Subsidiaries [Member]	Jan. 02, 2014 Decoupling Mechanism [Member] Electric [Member]	Jan. 02, 2014 Decoupling Mechanism [Member] Natural Gas [Member]	Jul. 02, 2013 Decoupling Mechanism [Member] Subsidiaries [Member] Electric [Member]	Jul. 02, 2013 Decoupling Mechanism [Member] Subsidiaries [Member] Natural Gas [Member]	Jul. 02, 2013 Expedited Rate Filing [Member] Subsidiaries [Member] Electric [Member]	Jul. 02, 2013 Expedited Rate Filing [Member] Subsidiaries [Member] Natural Gas [Member]	Nov. 01, 2013 Power Cost Only Rate Case (PCORC) [Member] Subsidiaries [Member] Electric [Member]	Nov. 01, 2013 Purchased Gas Adjustment (PGA) [Member] Subsidiaries [Member] Natural Gas [Member]	Dec. 31, 2014 Scenario, Forecast [Member] Subsidiaries [Member]	May 01, 2014 Subsequent Event [Member] Decoupling Mechanism [Member] Subsidiaries [Member] Electric [Member]	May 01, 2014 Subsequent Event [Member] Decoupling Mechanism [Member] Subsidiaries [Member] Natural Gas [Member]	May 01, 2014 Subsequent Event [Member] Property tax tracker [Member] [Domain] [Domain] Subsidiaries [Member] Electric [Member]	May 01, 2014 Subsequent Event [Member] Property tax tracker [Member] [Domain] [Domain] Subsidiaries [Member] Natural Gas [Member]
Regulatory Assets [Line Items]
American Recovery and Reinvestment Tax Act of 2009, Grant Amortization Period	10 years
American Recovery and Reinvestment Tax Act of 2009, Grant, Amortization Period Included in Customer Pass Through	11 months
American Recovery and Reinvestment Tax Act of 2009, Grant Pass Through Amount	$ 34.6										$ 37.8
American Recovery and Reinvestment Tax Act of 2009, Grant Pass Through Interest Amount	23.8										20.6
American Recovery and Reinvestment Tax Act of 2009, Grant, Overall Average Rate Reduction	2.76%										(0.26%)
American Recovery and Reinvestment Tax Act of 2009, Total Grant Pass Through Amount											58.5
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)					$ 21.4	$ 10.8	$ 30.7	$ (2.0)	$ (10.5)	$ 4.0		$ 10.6	$ (1.0)	$ 11.0	$ 5.6
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)			3.00%	2.20%	1.00%	1.10%	1.50%	(0.20%)	(0.50%)	0.40%		0.50%	(0.10%)	0.50%	0.60%
Rate Case, Approved Effective Weighted Cost of Capital		7.77%
Rate Case, Approved Effective Common Equity in Capital Structure		48.00%
Rate Case, Approved Effective Return on Equity		9.80%

XML

Accounting for Derivative Instruments and Hedging Activities

3 Months Ended

Mar. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Accounting for Derivative Instruments and Hedging Activities

Accounting for Derivative Instruments and Hedging Activities

PSE employs various energy 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 and related hedging strategy objective is to minimize costs and risks where feasible thus reducing volatility in costs in the portfolio. In order to manage its exposure to the variability in future cash flows for forecasted energy transactions, PSE utilizes a programmatic hedging strategy which extends out three years. 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 forward physical electric and natural gas purchase and sale agreements, fixed-for-floating swap contracts, and commodity call/put options. The forward physical electric agreements are both fixed and variable (at index), while the physical natural gas agreements are variable. To fix the price of wholesale electricity and natural gas, PSE may enter into fixed-for-floating swap (financial) contracts with various counterparties. PSE also utilizes natural gas call and put options as an additional hedging instrument to increase the hedging portfolio's flexibility to react to commodity price fluctuations.

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, borrowings under its commercial paper program, and its credit facilities to meet short-term funding needs. 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, 2014, Puget Energy had two interest rate swap contracts outstanding which extend to January 2017. PSE did not have any outstanding interest rate swap instruments.

The following table presents the volumes, fair values and locations of the Company's derivative instruments recorded on the balance sheets:

Puget Energy and Puget Sound Energy	March 31, 2014					December 31, 2013
(Dollars in Thousands)	Volumes	Assets 1		Liabilities 2		Volumes	Assets 1		Liabilities 2
Interest rate swap derivatives 3	$450 million	$	—	$	12,126	$450 million	$	—	$	13,223
Electric portfolio derivatives	*	23,906		34,365		*	18,479		37,312
Natural gas derivatives (MMBtus) 4	380.5 million	27,803		14,166		423.5 million	8,121		35,676
Total derivative contracts		$	51,709	$	60,657		$	26,600	$	86,211
Current		$	44,889	$	33,213		$	18,867	$	48,049
Long-term		6,820		27,444			7,733		38,162
Total derivative contracts		$	51,709	$	60,657		$	26,600	$	86,211

___________

¹  Balance sheet location: Current and Long-term Unrealized gain on derivative instruments.

²  Balance sheet location: Current and Long-term Unrealized loss on derivative instruments.

³  Interest rate swap contracts are only held at Puget Energy.

⁴  All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations” (ASC 980) due to the PGA mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers.

^*  Electric portfolio derivatives consist of electric generation fuel of 129.3 million One Million British Thermal Units (MMBtus) and purchased electricity of 7.6 million Megawatt Hours (MWhs) at March 31, 2014, and 145.6 million MMBtus and 8.6 million MWhs at December 31, 2013.

For further details regarding the fair value of derivative instruments, see Note 3.

ASU 2013-01 requires disclosure of both gross and net information for recognized derivative assets and liabilities. It is the Company's policy to record all derivative transactions on a gross basis at the contract level, without offsetting assets or liabilities. The Company generally enters into transactions using the following master agreements: WSPP, Inc. (WSPP) agreements which standardize physical power contracts; International Swaps and Derivatives Association (ISDA) agreements which standardize financial gas and electric contracts; and North American Energy Standards Board (NAESB) agreements which standardize 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 as well as right of set-off in the event of counterparty default. The set-off provision can be used as a final settlement of accounts which extinguishes the mutual debts owed between the parties in exchange for a new net amount.

The following tables present the potential effect of netting arrangements, including rights of set-off associated with the Company's derivative assets and liabilities:

Puget Energy and Puget Sound Energy
March 31, 2014
	Gross Amount Recognized in the Statement of Financial Position 1		Gross Amounts Offset in the Statement of Financial Position		Net of Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position
(Dollars in Thousands)							Commodity Contracts			Cash Collateral Received/Posted		Net Amount
Assets
Energy Derivative Contracts	$	51,709	$	—	$	51,709	$	(26,319	)	$	—	$	25,390
Liabilities
Energy Derivative Contracts	$	48,531	$	—	$	48,531	$	(26,319	)	$	—	$	22,212
Interest Rate Swaps 2	$	12,126	$	—	$	12,126	$	—		$	—	$	12,126
Puget Energy and Puget Sound Energy
December 31, 2013
	Gross Amount Recognized in the Statement of Financial Position 1		Gross Amounts Offset in the Statement of Financial Position		Net of Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position
(Dollars in Thousands)							Commodity Contracts			Cash Collateral Received/Posted		Net Amount
Assets
Energy Derivative Contracts	$	26,600	$	—	$	26,600	$	(19,491	)	$	—	$	7,109
Liabilities
Energy Derivative Contracts	$	72,988	$	—	$	72,988	$	(19,491	)	$	—	$	53,497
Interest Rate Swaps 2	$	13,223	$	—	$	13,223	$	—		$	—	$	13,223

___________

¹  All Derivative Contract deals are executed under ISDA, NAESB and WSPP Master Netting Agreements with Right of Offset.

²  Interest Rate Swap Contracts are only held at Puget Energy.

Due to the merger in 2009, Puget Energy recorded all derivative contracts at fair value as either assets or liabilities. Certain contracts meeting the criteria defined in ASC 815 were subsequently designated as Normal Purchase Normal Sale (NPNS) or cash flow hedges, thereby causing differences in the derivative unrealized gains/losses to be recorded through earnings between Puget Energy and PSE. These differences will occur through February 2015.

The following tables present the effect and locations of the Company's derivatives not designated as hedging instruments, recorded on the statements of income:

Puget Energy		Three Months Ended March 31,
(Dollars in Thousands)	Location	2014			2013
Interest rate contracts:	Non-hedged interest rate swap (expense) income	$	(747	)	$	1,028
	Interest expense	(125		)	(2,578		)
Commodity contracts:
Electric derivatives	Unrealized gain (loss) on derivative instruments, net	7,839			75,692
	Electric generation fuel	7,827			(12,638		)
	Purchased electricity	5,383			(31,485		)
Total gain (loss) recognized in income on derivatives		$	20,177		$	30,019

Puget Sound Energy		Three Months Ended March 31,
(Dollars in Thousands)	Location	2014		2013
Commodity contracts:
Electric derivatives	Unrealized gain (loss) on derivative instruments, net	$	7,270	$	72,740
	Electric generation fuel	7,827		(12,638		)
	Purchased electricity	5,383		(31,485		)
Total gain (loss) recognized in income on derivatives		$	20,480	$	28,617

The unrealized gain or loss on derivative contracts is reported in the statement of cash flows under the operating activities section. However, at the time of the merger in 2009, all derivative contracts at Puget Energy were assessed to identify contracts that have a “more than an insignificant” fair value. If the fair value was greater than 10% of the notional value, the contract was deemed as having a financing element. For those contracts, the cash inflows (outflows) are presented in the financing activities section of the statement of cash flows. For the three months ended March 31, 2014 and 2013, cash outflows related to financing activities of $8.0 million and $26.0 million, respectively, were reported on the Puget Energy statement of cash flows.

For derivative instruments previously designated as cash flow hedges (including both commodity contracts and interest rate swaps), the effective portion of the gain or loss on the derivative was recorded as a component of Other Comprehensive Income (OCI), and then is reclassified into earnings in the same period(s) during which the hedged transaction affects earnings.

Puget Energy and PSE expect $0.5 million and $2.0 million of losses, respectively, in accumulated OCI will be reclassified into earnings within the next twelve months. The Company does not attempt cash flow hedging for any new transactions and records all mark-to-market adjustments through earnings.

The following tables present the Company's pre-tax gain (loss) of derivatives that were previously in a cash flow hedge relationship, and subsequently reclassified out of accumulated OCI into income:

Puget Energy		Three Months Ended March 31,
(Dollars in Thousands)	Location	2014			2013
Interest rate contracts:	Interest expense	$	(144	)	$	(1,314	)
Commodity contracts:
Electric derivatives	Electric generation fuel	—			—
	Purchased electricity	(534		)	164
Total		$	(678	)	$	(1,150	)

Puget Sound Energy		Three Months Ended March 31,
(Dollars in Thousands)	Location	2014			2013
Interest rate contracts:	Interest expense	$	(122	)	$	(122	)
Commodity contracts:
Electric derivatives	Electric generation fuel	—			—
	Purchased electricity	(1,104		)	(2,786		)
Total		$	(1,226	)	$	(2,908	)

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 distress. 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 could suffer a material financial loss. However, as of March 31, 2014, 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.

As the Company generally enters into transactions using the WSPP, ISDA and NAESB master agreements, it believes that such agreements reduce credit risk exposure because they 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 the 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 to derive 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. Credit reserves are booked as contra accounts to unrealized gain (loss) positions. As of March 31, 2014, the Company was in a net liability position with many of its counterparties, so the default factors of counterparties did not have a significant impact on reserves for the period. The majority of the Company's derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council. As of March 31, 2014, PSE has posted a $1.0 million letter of credit as a condition of transacting on a physical energy exchange and clearinghouse in Canada. PSE did not trigger any collateral requirements with any of its counterparties, nor were any of PSE's counterparties required to post collateral resulting from credit rating downgrades.

The table below presents the fair value of the overall contractual contingent liability positions for the Company's derivative activity at March 31, 2014:

Puget Energy and Puget Sound Energy Contingent Feature	Fair Value 1			Posted		Contingent
(Dollars in Thousands)	Liability			Collateral		Collateral
Credit rating 2	$	(10,290	)	$	—	$	10,290
Requested credit for adequate assurance	(10,596		)	—		—
Forward value of contract 3	(1,931		)	—		—
Total	$	(22,817	)	$	—	$	10,290

__________

¹  Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions. 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 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.

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Accounting for Derivative Instruments and Hedging Activities Contractual Contingent Liability (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014
Electric portfolio [Member]
Derivative [Line Items]
Fair Value Liability	$ (22,817)	[1]
Posted Collateral	0
Additional Collateral, Aggregate Fair Value	10,290
Electric portfolio [Member] | Credit rating [Member]
Derivative [Line Items]
Fair Value Liability	(10,290)	[1],[2]
Posted Collateral	0	[2]
Additional Collateral, Aggregate Fair Value	10,290	[2]
Electric portfolio [Member] | Requested credit for adequate assurance [Member]
Derivative [Line Items]
Fair Value Liability	(10,596)	[1]
Posted Collateral	0
Additional Collateral, Aggregate Fair Value	0
Electric portfolio [Member] | Forward value of contract [Member]
Derivative [Line Items]
Fair Value Liability	(1,931)	[1],[3]
Posted Collateral	0	[3]
Additional Collateral, Aggregate Fair Value	0	[3]
Electric portfolio [Member] | External Credit Rating, Investment Grade [Member]
Derivative [Line Items]
Derivative, Credit Risk Exposure, Percentage	99.90%
Electric portfolio [Member] | External Credit Rating, Non Investment Grade [Member]
Derivative [Line Items]
Derivative, Credit Risk Exposure, Percentage	0.10%
Natural gas portfolio [Member] | Credit rating [Member]
Derivative [Line Items]
Posted Collateral	$ 1,000	[2]

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

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

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

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Accounting for Derivative Instruments and Hedging Activities Recognized in Other Comprehensive Income (Details) (USD $)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Derivative Instruments, Gain (Loss) [Line Items]
Document Period End Date	Mar. 31, 2014
PUGET ENERGY [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Cash Flow Hedge Loss to be Reclassified within Twelve Months	$ (500,000)
Subsidiaries [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Document Period End Date	Mar. 31, 2014
Cash Flow Hedge Loss to be Reclassified within Twelve Months	(2,000,000)
Cash Flow Hedging [Member] | PUGET ENERGY [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(678,000)	(1,150,000)
Cash Flow Hedging [Member] | PUGET ENERGY [Member] | Electric generation fuel [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	0	0
Cash Flow Hedging [Member] | Subsidiaries [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(1,226,000)	(2,908,000)
Cash Flow Hedging [Member] | Subsidiaries [Member] | Electric generation fuel [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ 0	$ 0

XML

Fair Value Measurements Carrying Value (Details) (Carrying Value [Member], USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
PUGET ENERGY [Member]
Assets:
Cash and Cash Equivalents	$ 23,581	$ 44,302
Restricted Cash	25,437	7,171
Notes Receivable and Other	54,542	53,449
Total assets	103,560	104,922
Liabilities:
Short-term Debt	0	162,000
Total liabilities	0	162,000
PUGET ENERGY [Member] | Level 1 [Member]
Assets:
Cash and Cash Equivalents	23,581	44,302
Restricted Cash	25,437	7,171
Notes Receivable and Other	0	0
Total assets	49,018	51,473
Liabilities:
Short-term Debt	0	162,000
Total liabilities	0	162,000
PUGET ENERGY [Member] | Level 2 [Member]
Assets:
Cash and Cash Equivalents	0	0
Restricted Cash	0	0
Notes Receivable and Other	54,542	53,449
Total assets	54,542	53,449
Liabilities:
Short-term Debt	0	0
Total liabilities	0	0
Subsidiaries [Member]
Assets:
Cash and Cash Equivalents	23,556	44,111
Restricted Cash	25,437	7,171
Notes Receivable and Other	54,542	53,449
Total assets	103,535	104,731
Liabilities:
Short-term Debt	0	162,000
Short-term Debt owed by PSE to PE	29,598	29,598
Total liabilities	29,598	191,598
Subsidiaries [Member] | Level 1 [Member]
Assets:
Cash and Cash Equivalents	23,556	44,111
Restricted Cash	25,437	7,171
Notes Receivable and Other	0	0
Total assets	48,993	51,282
Liabilities:
Short-term Debt	0	162,000
Short-term Debt owed by PSE to PE	0	0
Total liabilities	0	162,000
Subsidiaries [Member] | Level 2 [Member]
Assets:
Cash and Cash Equivalents	0	0
Restricted Cash	0	0
Notes Receivable and Other	54,542	53,449
Total assets	54,542	53,449
Liabilities:
Short-term Debt	0	0
Short-term Debt owed by PSE to PE	29,598	29,598
Total liabilities	$ 29,598	$ 29,598

XML

Fair Value Measurements Debt at at Carrying and Fair Value (Details) (Discounted cash flow [Member], USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
PUGET ENERGY [Member] | Carrying Value [Member]
Liabilities:
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure	$ 5,235,259	$ 5,232,476
PUGET ENERGY [Member] | Carrying Value [Member] | Level 2 [Member]
Liabilities:
Junior subordinated notes	250,000	250,000
Long-term debt (fixed-rate), net of discount	4,686,259	4,683,476
Long Term Debt (variable rate) net of discount	299,000	299,000
PUGET ENERGY [Member] | Fair Value [Member]
Liabilities:
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure	6,454,484	6,162,680
PUGET ENERGY [Member] | Fair Value [Member] | Level 2 [Member]
Liabilities:
Junior subordinated notes	280,137	269,366
Long-term debt (fixed-rate), net of discount	5,875,347	5,594,314
Long Term Debt (variable rate) net of discount	299,000	299,000
Subsidiaries [Member] | Carrying Value [Member]
Liabilities:
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure	3,763,258	3,763,258
Subsidiaries [Member] | Carrying Value [Member] | Level 2 [Member]
Liabilities:
Junior subordinated notes	250,000	250,000
Long-term debt (fixed-rate), net of discount	3,513,258	3,513,258
Subsidiaries [Member] | Fair Value [Member]
Liabilities:
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure	4,519,878	4,307,821
Subsidiaries [Member] | Fair Value [Member] | Level 2 [Member]
Liabilities:
Junior subordinated notes	280,137	269,366
Long-term debt (fixed-rate), net of discount	$ 4,239,741	$ 4,038,455

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Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 2014

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Summary of Significant Accounting Policies

The Company revised its Consolidated Statement of Cash Flows due to an immaterial error. Revisions were made in the second quarter ended June 30, 2013 on the Company's Consolidated Statement of Cash Flows to reflect energy efficiency expenditures as operating cash outflows instead of investing cash outflows. The Company determined energy efficiency expenditures should have been classified as operating activities instead of investing activities. These revisions decreased net cash provided by operating activities and decreased net cash used by investing activities. The revision does not affect the net change in cash and cash equivalents for any of the periods, and has no effect on the Company's Consolidated Statements of Income, Consolidated Statements of Comprehensive Income, Consolidated Balance Sheets, and Consolidated Statement of Common Shareholder's Equity. The Company has evaluated the effects of these errors and concluded that none of them are material to any of the Company's previously issued quarterly or annual Financial Statements. Nevertheless, the Company elected to revise the Consolidated Statement of Cash Flows in this report to correct for the effect of these errors and properly reflect the revised values.

The amounts on prior period Consolidated Statements of Cash Flows which have been revised are summarized below:

	As Reported			As Revised
Puget Energy	Three Months Ended			Three Months Ended
(Dollars in Thousands)	March 31, 2013			March 31, 2013
Operating Activities:
Regulatory Assets	$	(6,411	)	$	(28,953	)
Net Cash Provided by Operating Activities	$	323,807		$	301,265
Investing Activities:
Energy Efficiency Expenditures	$	(22,542	)	$	—
Net Cash Used in Investing Activities	$	(86,362	)	$	(63,820	)

	As Reported			As Revised
Puget Sound Energy	Three Months Ended			Three Months Ended
(Dollars in Thousands)	March 31, 2013			March 31, 2013
Operating Activities:
Regulatory Assets	$	(6,411	)	$	(28,953	)
Net Cash Provided by Operating Activities	$	332,243		$	309,701
Investing Activities:
Energy Efficiency Expenditures	$	(22,542	)	$	—
Net Cash Used in Investing Activities	$	(86,298	)	$	(63,756	)

XML

Fair Value Measurements Assets and Liabilities (Details) (USD $)	3 Months Ended					3 Months Ended					3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013		Jun. 30, 2013	Mar. 31, 2014 Electric portfolio [Member]		Mar. 31, 2013 Electric portfolio [Member]		Jun. 30, 2013 Electric portfolio [Member]	Mar. 31, 2014 Natural gas portfolio [Member]		Mar. 31, 2013 Natural gas portfolio [Member]		Jun. 30, 2013 Natural gas portfolio [Member]	Mar. 31, 2014 Commodity Contract [Member]	Dec. 31, 2013 Commodity Contract [Member]	Mar. 31, 2014 Fair Value, Measurements, Recurring [Member] PUGET ENERGY [Member] Level 2 [Member]	Dec. 31, 2013 Fair Value, Measurements, Recurring [Member] PUGET ENERGY [Member] Level 2 [Member]	Mar. 31, 2014 Fair Value, Measurements, Recurring [Member] PUGET ENERGY [Member] Level 2 [Member] Interest Rate Contract [Member]	Dec. 31, 2013 Fair Value, Measurements, Recurring [Member] PUGET ENERGY [Member] Level 2 [Member] Interest Rate Contract [Member]	Mar. 31, 2014 Fair Value, Measurements, Recurring [Member] PUGET ENERGY [Member] Level 3 [Member]	Dec. 31, 2013 Fair Value, Measurements, Recurring [Member] PUGET ENERGY [Member] Level 3 [Member]	Mar. 31, 2014 Fair Value, Measurements, Recurring [Member] PUGET ENERGY [Member] Level 3 [Member] Interest Rate Contract [Member]	Dec. 31, 2013 Fair Value, Measurements, Recurring [Member] PUGET ENERGY [Member] Level 3 [Member] Interest Rate Contract [Member]	Mar. 31, 2014 Fair Value, Measurements, Recurring [Member] PUGET ENERGY [Member] Total [Member]	Dec. 31, 2013 Fair Value, Measurements, Recurring [Member] PUGET ENERGY [Member] Total [Member]	Mar. 31, 2014 Fair Value, Measurements, Recurring [Member] PUGET ENERGY [Member] Total [Member] Interest Rate Contract [Member]	Dec. 31, 2013 Fair Value, Measurements, Recurring [Member] PUGET ENERGY [Member] Total [Member] Interest Rate Contract [Member]	Mar. 31, 2014 Fair Value, Measurements, Recurring [Member] Subsidiaries [Member] Level 2 [Member]	Dec. 31, 2013 Fair Value, Measurements, Recurring [Member] Subsidiaries [Member] Level 2 [Member]	Mar. 31, 2014 Fair Value, Measurements, Recurring [Member] Subsidiaries [Member] Level 2 [Member] Commodity Contract [Member] Electric portfolio [Member]	Dec. 31, 2013 Fair Value, Measurements, Recurring [Member] Subsidiaries [Member] Level 2 [Member] Commodity Contract [Member] Electric portfolio [Member]	Mar. 31, 2014 Fair Value, Measurements, Recurring [Member] Subsidiaries [Member] Level 2 [Member] Commodity Contract [Member] Natural gas portfolio [Member]	Dec. 31, 2013 Fair Value, Measurements, Recurring [Member] Subsidiaries [Member] Level 2 [Member] Commodity Contract [Member] Natural gas portfolio [Member]	Mar. 31, 2014 Fair Value, Measurements, Recurring [Member] Subsidiaries [Member] Level 3 [Member]	Dec. 31, 2013 Fair Value, Measurements, Recurring [Member] Subsidiaries [Member] Level 3 [Member]	Mar. 31, 2014 Fair Value, Measurements, Recurring [Member] Subsidiaries [Member] Level 3 [Member] Commodity Contract [Member] Electric portfolio [Member]		Dec. 31, 2013 Fair Value, Measurements, Recurring [Member] Subsidiaries [Member] Level 3 [Member] Commodity Contract [Member] Electric portfolio [Member]	Mar. 31, 2014 Fair Value, Measurements, Recurring [Member] Subsidiaries [Member] Level 3 [Member] Commodity Contract [Member] Natural gas portfolio [Member]		Dec. 31, 2013 Fair Value, Measurements, Recurring [Member] Subsidiaries [Member] Level 3 [Member] Commodity Contract [Member] Natural gas portfolio [Member]	Mar. 31, 2014 Fair Value, Measurements, Recurring [Member] Subsidiaries [Member] Total [Member]	Dec. 31, 2013 Fair Value, Measurements, Recurring [Member] Subsidiaries [Member] Total [Member]	Mar. 31, 2014 Fair Value, Measurements, Recurring [Member] Subsidiaries [Member] Total [Member] Commodity Contract [Member] Electric portfolio [Member]	Dec. 31, 2013 Fair Value, Measurements, Recurring [Member] Subsidiaries [Member] Total [Member] Commodity Contract [Member] Electric portfolio [Member]	Mar. 31, 2014 Fair Value, Measurements, Recurring [Member] Subsidiaries [Member] Total [Member] Commodity Contract [Member] Natural gas portfolio [Member]	Dec. 31, 2013 Fair Value, Measurements, Recurring [Member] Subsidiaries [Member] Total [Member] Commodity Contract [Member] Natural gas portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unrealized Gain (Loss) on Derivatives and Commodity Contracts						$ (9,200,000)		$ 1,400,000
Derivative Assets																51,709,000	26,600,000													44,119,000	20,109,000	18,866,000	14,661,000	25,253,000	5,448,000	7,590,000	6,491,000	5,040,000	[1]	3,818,000	2,550,000	[1]	2,673,000	51,709,000	26,600,000	23,906,000	18,479,000	27,803,000	8,121,000
Derivative Liabilities																		12,126,000	13,223,000	12,126,000	13,223,000	0	0	0	0	12,126,000	13,223,000	12,126,000	13,223,000	25,232,000	50,715,000	14,719,000	18,073,000	10,513,000	32,642,000	23,299,000	22,273,000	19,646,000	[1]	19,239,000	3,653,000	[1]	3,034,000	48,531,000	72,988,000	34,365,000	37,312,000	14,166,000	35,676,000
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period	(15,782,000)		(35,526,000)		(27,976,000)	(15,421,000)		(33,924,000)		(26,442,000)	(361,000)		(1,602,000)		(1,534,000)
Included in earnings	(2,745,000)	[2]	1,598,000	[2]		(2,745,000)	[2]	1,598,000	[2]		0	[2]	0	[2]
Included in regulatory assets/liabilities	259,000		674,000			0		0			259,000		674,000
Settlements	(89,000)	[3]	5,651,000	[3]		321,000	[3]	6,384,000	[3]		(410,000)	[3]	(733,000)	[3]
Transferred into Level 3	2,515,000		(7,700,000)			3,100,000		(7,700,000)			(585,000)		0
Transferred out of Level 3	133,000		7,327,000			139,000		7,200,000			(6,000)		127,000
Balance at end of period	$ (15,709,000)				$ (27,976,000)	$ (14,606,000)				$ (26,442,000)	$ (1,103,000)				$ (1,534,000)

[1] 1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions

[2] 1 Income Statement location: Unrealized (gain) loss on derivative instruments, net. Includes unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $(9.2) million and $1.4 million for the three months ended March 31, 2014 and 2013, respectively.

[3] 2 The Company had no purchases, sales or issuances during the reported periods.

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Accumulated Other Comprehensive Income - Reclassification Location (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Comprehensive income (loss)	$ 107,824		$ 168,569
Subsidiaries [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Comprehensive income (loss)	123,881		185,214
Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Comprehensive income (loss)	(232)		(1,094)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Subsidiaries [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Comprehensive income (loss)	(2,798)		(5,276)
Interest Rate Contract [Member] | Interest Expense [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Other Comprehensive Income (Loss), before Tax, Portion Attributable to Parent	(144)		(1,314)
Other Comprehensive Income (Loss), Tax, Portion Attributable to Parent	50		460
Comprehensive income (loss)	(94)		(854)
Interest Rate Contract [Member] | Interest Expense [Member] | Subsidiaries [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Other Comprehensive Income (Loss), before Tax, Portion Attributable to Parent	(122)		(122)
Other Comprehensive Income (Loss), Tax, Portion Attributable to Parent	43		43
Comprehensive income (loss)	(79)		(79)
Electric Derivative [Member] | Purchased Electricity [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Other Comprehensive Income (Loss), before Tax, Portion Attributable to Parent	(534)		164
Other Comprehensive Income (Loss), Tax, Portion Attributable to Parent	187		(57)
Comprehensive income (loss)	(347)		107
Electric Derivative [Member] | Purchased Electricity [Member] | Subsidiaries [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Other Comprehensive Income (Loss), before Tax, Portion Attributable to Parent	(1,104)		(2,786)
Other Comprehensive Income (Loss), Tax, Portion Attributable to Parent	386		975
Comprehensive income (loss)	(718)		(1,811)
Qualified Pension Benefits [Member] | Pension Cost [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Other Comprehensive Income (Loss), before Tax, Portion Attributable to Parent	322		(533)
Other Comprehensive Income (Loss), Tax, Portion Attributable to Parent	(113)		186
Comprehensive income (loss)	209		(347)
Qualified Pension Benefits [Member] | Pension Cost [Member] | Subsidiaries [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Other Comprehensive Income (Loss), before Tax, Portion Attributable to Parent	(3,080)		(5,210)
Other Comprehensive Income (Loss), Tax, Portion Attributable to Parent	1,079		1,824
Comprehensive income (loss)	(2,001)		(3,386)
Amortization of Net Gain (Loss) [Member] | Pension Cost [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Other Comprehensive Income (Loss), before Tax, Portion Attributable to Parent	(162)	[1]	(1,032)	[1]
Amortization of Net Gain (Loss) [Member] | Pension Cost [Member] | Subsidiaries [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Other Comprehensive Income (Loss), before Tax, Portion Attributable to Parent	(3,461)	[2]	(5,599)	[2]
Amortization of Prior Service Cost [Member] | Pension Cost [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Other Comprehensive Income (Loss), before Tax, Portion Attributable to Parent	484	[1]	499	[1]
Amortization of Prior Service Cost [Member] | Pension Cost [Member] | Subsidiaries [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Other Comprehensive Income (Loss), before Tax, Portion Attributable to Parent	$ 381	[2]	$ 389	[2]

[1] (a) These accumulated other comprehensive income components are included in the computation of net periodic pension cost (see Note 4 for additional details).

[2] (a) These accumulated other comprehensive income components are included in the computation of net periodic pension cost (see Note 4 for additional details).

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CONSOLIDATED STATEMENTS OF INCOME (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Operating revenue:
Electric	$ 633,553	$ 614,634
Gas	387,443	384,765
Other	4,379	419
Total operating revenue	1,025,375	999,818
Energy costs:
Purchased electricity	181,157	175,043
Electric generation fuel	75,436	59,087
Residential exchange	(30,003)	(22,551)
Purchased gas	191,306	189,983
Unrealized (gain) loss on derivative instruments, net	(7,839)	(75,692)
Utility operations and maintenance	144,076	129,235
Non-utility expense and other	3,422	(994)
Depreciation	91,184	88,178
Amortization	10,535	5,744
Conservation amortization	28,982	34,107
Taxes other than income taxes	100,818	99,943
Total operating expenses	789,074	682,083
Operating income	236,301	317,735
Other income (deductions):
Other income	4,242	12,012
Other expense	(1,582)	(1,542)
Non-hedged interest rate derivative expense	(747)	1,028
Interest charges:
AFUDC	1,153	4,648
Interest expense	(90,255)	(95,816)
Income (loss) before income taxes	149,112	238,065
Income tax (benefit) expense	41,520	70,590
Net income (loss)	107,592	167,475
Subsidiaries [Member]
Operating revenue:
Electric	633,553	614,634
Gas	387,443	384,765
Other	4,379	308
Total operating revenue	1,025,375	999,707
Energy costs:
Purchased electricity	181,157	175,043
Electric generation fuel	75,436	59,087
Residential exchange	(30,003)	(22,551)
Purchased gas	191,306	189,983
Unrealized (gain) loss on derivative instruments, net	(7,270)	(72,740)
Utility operations and maintenance	144,076	129,235
Non-utility expense and other	6,177	3,091
Depreciation	91,184	88,178
Amortization	10,535	5,744
Conservation amortization	28,982	34,107
Taxes other than income taxes	100,818	99,943
Total operating expenses	792,398	689,120
Operating income	232,977	310,587
Other income (deductions):
Other income	4,240	12,012
Other expense	(1,582)	(1,542)
Interest charges:
AFUDC	1,153	4,648
Interest expense	(64,137)	(65,977)
Interest expense on parent note	(26)	(29)
Income (loss) before income taxes	172,625	259,699
Income tax (benefit) expense	51,542	79,761
Net income (loss)	$ 121,083	$ 179,938

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
ASSETS
Construction work in progress	$ 299,952	$ 310,318
Current assets:
Allowance for doubtful accounts	8,551	7,385
Common shareholder’s equity:
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	1,000	1,000
Common stock, shares outstanding (in shares)	200	200
Subsidiaries [Member]
ASSETS
Construction work in progress	299,952	310,318
Current assets:
Allowance for doubtful accounts	$ 8,551	$ 7,385
Common shareholder’s equity:
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	150,000,000	150,000,000
Common stock, shares outstanding (in shares)	85,903,791	85,903,791

XML

Retirement Benefits Change in Net Benefit Obligation (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended	12 Months Ended
	Mar. 31, 2014	Dec. 31, 2013
Qualified Pension Benefits [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period	$ 573,317	$ 616,290
Service cost	(4,512)	(19,285)
Interest cost	7,055	24,754
Amendments	0	0
Actuarial loss/(gain)	0	(48,559)
Benefits paid	(10,001)	(38,453)
Medicare part D subsidiary received	0	0
Benefit obligation at end of period	574,883	573,317
SERP Pension Benefits [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period	47,279	51,795
Service cost	(261)	(1,498)
Interest cost	577	2,045
Amendments	0	478
Actuarial loss/(gain)	0	(1,687)
Benefits paid	(460)	(6,850)
Medicare part D subsidiary received	0	0
Benefit obligation at end of period	47,657	47,279
Other Benefit [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period	14,939	17,672
Service cost	(29)	(134)
Interest cost	183	664
Amendments	0	0
Actuarial loss/(gain)	0	(2,240)
Benefits paid	(391)	(1,536)
Medicare part D subsidiary received	42	245
Benefit obligation at end of period	$ 14,802	$ 14,939

XML

Summary of Significant Accounting Policies (Details) (Subsidiaries [Member], USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014 sqmi	Mar. 31, 2013
Subsidiaries [Member]
Schedule of Capitalization, Equity [Line Items]
Area of Service Territory (in sqmi)	6,000
Excise taxes collected	$ 77.9	$ 76.9

XML

Retirement Benefits Activity (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended							12 Months Ended
	Mar. 31, 2014 Qualified Pension Benefits [Member]	Mar. 31, 2014 SERP Pension Benefits [Member]	Mar. 31, 2014 Other Benefit [Member]	Mar. 31, 2014 Subsidiaries [Member]	Dec. 31, 2014 Scenario, Forecast [Member] Qualified Pension Benefits [Member]	Dec. 31, 2014 Scenario, Forecast [Member] SERP Pension Benefits [Member]	Dec. 31, 2014 Scenario, Forecast [Member] Other Benefit [Member]	Dec. 31, 2014 Scenario, Forecast [Member] Subsidiaries [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent				1.00%				4.00%
Aggregate expected contributions					$ 12.0	$ 4.0	$ 0.4
Company Contribution	$ 3.0	$ 0.5	$ 0.2

XML

Accounting for Derivative Instruments and Hedging Activities Derivative Activity and Notional Amounts (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014		Dec. 31, 2013
Interest Rate Swap [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Notional Amount	$ 450	[1]	$ 450	[1]
Natural Gas Derivatives [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Notional amount, Nonmonetary	380,500,000	[2]	423,500,000	[2]
Electric generation fuel [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Notional amount, Nonmonetary	129,300,000		145,600,000
Purchased Electricity [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Notional amount, Nonmonetary	7,600,000		8,600,000
PUGET ENERGY [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Number of Interest Rate Derivatives Held	2

[1] 3 Interest rate swap contracts are only held at Puget Energy.

[2] 4 All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations” (ASC 980) due to the PGA mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers.

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Operating activities:
Net income (loss)	$ 107,592	$ 167,475
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation	91,184	88,178
Amortization	10,535	5,744
Conservation amortization	28,982	34,107
Deferred income taxes and tax credits, net	41,520	70,591
Net unrealized (gain) loss on derivative instruments	(8,793)	(75,937)
Derivative contracts classified as financing activities due to merger	8,026	26,049
AFUDC - Equity	(1,436)	(6,524)
Funding of pension liability	(3,000)	(5,100)
Regulatory Assets	(38,240)	(28,953)
Regulatory liabilities	6,407	3,029
Other long-term assets	(5,667)	3,099
Other long-term liabilities	21,532	17,586
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	28,650	31,548
Materials and supplies	214	1,827
Fuel and gas inventory	35,451	27,097
Income taxes	148	148
Prepayments and other	539	(3,732)
Purchased gas adjustment	(3,079)	(5,718)
Accounts payable	(13,886)	(47,935)
Taxes payable	11,476	16,746
Accrued expenses and other	(7,621)	(18,060)
Net cash provided by operating activities	310,534	301,265
Investing activities:
Construction expenditures - excluding equity AFUDC	(96,318)	(168,337)
Proceeds from disposition of assets	0	108,166
Restricted cash	(18,266)	599
Other	(4,125)	(4,248)
Net cash used in investing activities	(118,709)	(63,820)
Financing activities:
Change in short-term debt and leases, net	(163,903)	(157,895)
Dividends paid	(42,081)	(42,071)
Redemption of bonds and notes	0	(29,000)
Derivative contracts classified as financing activities due to merger	(8,026)	(26,049)
Issuance cost of bonds and other	1,464	(3,984)
Net cash provided by (used in) financing activities	(212,546)	(258,999)
Net increase (decrease) in cash and cash equivalents	(20,721)	(21,554)
Cash and cash equivalents at beginning of period	44,302	135,542
Cash and cash equivalents at end of period	23,581	113,988
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	90,756	78,346
Subsidiaries [Member]
Operating activities:
Net income (loss)	121,083	179,938
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation	91,184	88,178
Amortization	10,535	5,744
Conservation amortization	28,982	34,107
Deferred income taxes and tax credits, net	51,543	79,761
Net unrealized (gain) loss on derivative instruments	(7,270)	(72,740)
AFUDC - Equity	(1,436)	(6,524)
Funding of pension liability	(3,000)	(5,100)
Regulatory Assets	(38,240)	(28,953)
Regulatory liabilities	6,407	3,029
Other long-term assets	(3,251)	2,922
Other long-term liabilities	19,275	18,162
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	28,691	31,313
Materials and supplies	214	1,827
Fuel and gas inventory	35,451	27,097
Income taxes	148	148
Prepayments and other	539	(3,732)
Purchased gas adjustment	(3,079)	(5,718)
Accounts payable	(13,886)	(47,721)
Taxes payable	11,476	16,746
Accrued expenses and other	(1,276)	(8,783)
Net cash provided by operating activities	334,090	309,701
Investing activities:
Construction expenditures - excluding equity AFUDC	(96,318)	(168,337)
Proceeds from disposition of assets	0	108,166
Restricted cash	(18,266)	599
Other	(3,507)	(4,184)
Net cash used in investing activities	(118,091)	(63,756)
Financing activities:
Change in short-term debt and leases, net	(163,903)	(157,895)
Dividends paid	(74,114)	(105,648)
Issuance cost of bonds and other	1,463	(3,985)
Net cash provided by (used in) financing activities	(236,554)	(267,528)
Net increase (decrease) in cash and cash equivalents	(20,555)	(21,583)
Cash and cash equivalents at beginning of period	44,111	135,530
Cash and cash equivalents at end of period	23,556	113,947
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$ 59,666	$ 57,646

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Parent [Line Items]
Net income (loss)	$ 107,592	$ 167,475
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax	(209)	347
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax	347	(107)
Amortization Of Financing Cash Flow Hedge Contracts To Earnings During Period Net Of Tax	94	854
Other comprehensive income (loss)	232	1,094
Comprehensive income (loss)	107,824	168,569
Subsidiaries [Member]
Parent [Line Items]
Net income (loss)	121,083	179,938
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax	2,001	3,386
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax	718	1,811
Amortization Of Financing Cash Flow Hedge Contracts To Earnings During Period Net Of Tax	79	79
Other comprehensive income (loss)	2,798	5,276
Comprehensive income (loss)	$ 123,881	$ 185,214

XML

Summary of Significant Accounting Policies (Tables)

3 Months Ended

Mar. 31, 2014

Entity Information [Line Items]

Reclassification, Policy [Policy Text Block]

The Company revised its Consolidated Statement of Cash Flows due to an immaterial error. Revisions were made in the second quarter ended June 30, 2013 on the Company's Consolidated Statement of Cash Flows to reflect energy efficiency expenditures as operating cash outflows instead of investing cash outflows. The Company determined energy efficiency expenditures should have been classified as operating activities instead of investing activities. These revisions decreased net cash provided by operating activities and decreased net cash used by investing activities. The revision does not affect the net change in cash and cash equivalents for any of the periods, and has no effect on the Company's Consolidated Statements of Income, Consolidated Statements of Comprehensive Income, Consolidated Balance Sheets, and Consolidated Statement of Common Shareholder's Equity. The Company has evaluated the effects of these errors and concluded that none of them are material to any of the Company's previously issued quarterly or annual Financial Statements. Nevertheless, the Company elected to revise the Consolidated Statement of Cash Flows in this report to correct for the effect of these errors and properly reflect the revised values.

The amounts on prior period Consolidated Statements of Cash Flows which have been revised are summarized below:

	As Reported			As Revised
Puget Energy	Three Months Ended			Three Months Ended
(Dollars in Thousands)	March 31, 2013			March 31, 2013
Operating Activities:
Regulatory Assets	$	(6,411	)	$	(28,953	)
Net Cash Provided by Operating Activities	$	323,807		$	301,265
Investing Activities:
Energy Efficiency Expenditures	$	(22,542	)	$	—
Net Cash Used in Investing Activities	$	(86,362	)	$	(63,820	)

	As Reported			As Revised
Puget Sound Energy	Three Months Ended			Three Months Ended
(Dollars in Thousands)	March 31, 2013			March 31, 2013
Operating Activities:
Regulatory Assets	$	(6,411	)	$	(28,953	)
Net Cash Provided by Operating Activities	$	332,243		$	309,701
Investing Activities:
Energy Efficiency Expenditures	$	(22,542	)	$	—
Net Cash Used in Investing Activities	$	(86,298	)	$	(63,756	)

XML

Document And Entity Information	3 Months Ended
	Mar. 31, 2014
Entity Information [Line Items]
Entity Registrant Name	PUGET ENERGY INC /WA
Entity Central Index Key	0001085392
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	200
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q1
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2014
Subsidiaries [Member]
Entity Information [Line Items]
Entity Registrant Name	PUGET SOUND ENERGY INC
Entity Central Index Key	0000081100
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	85,903,791
Document Fiscal Year Focus	2014
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2014

XML

Accounting for Derivative Instruments and Hedging Activities (Tables)

3 Months Ended

Mar. 31, 2014

Derivative [Line Items]

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value

The following table presents the volumes, fair values and locations of the Company's derivative instruments recorded on the balance sheets:

Puget Energy and Puget Sound Energy	March 31, 2014					December 31, 2013
(Dollars in Thousands)	Volumes	Assets 1		Liabilities 2		Volumes	Assets 1		Liabilities 2
Interest rate swap derivatives 3	$450 million	$	—	$	12,126	$450 million	$	—	$	13,223
Electric portfolio derivatives	*	23,906		34,365		*	18,479		37,312
Natural gas derivatives (MMBtus) 4	380.5 million	27,803		14,166		423.5 million	8,121		35,676
Total derivative contracts		$	51,709	$	60,657		$	26,600	$	86,211
Current		$	44,889	$	33,213		$	18,867	$	48,049
Long-term		6,820		27,444			7,733		38,162
Total derivative contracts		$	51,709	$	60,657		$	26,600	$	86,211

___________

¹  Balance sheet location: Current and Long-term Unrealized gain on derivative instruments.

²  Balance sheet location: Current and Long-term Unrealized loss on derivative instruments.

³  Interest rate swap contracts are only held at Puget Energy.

⁴  All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations” (ASC 980) due to the PGA mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers.

^*  Electric portfolio derivatives consist of electric generation fuel of 129.3 million One Million British Thermal Units (MMBtus) and purchased electricity of 7.6 million Megawatt Hours (MWhs) at March 31, 2014, and 145.6 million MMBtus and 8.6 million MWhs at December 31, 2013.

Offsetting Assets and Liabilities

The following tables present the potential effect of netting arrangements, including rights of set-off associated with the Company's derivative assets and liabilities:

Puget Energy and Puget Sound Energy
March 31, 2014
	Gross Amount Recognized in the Statement of Financial Position 1		Gross Amounts Offset in the Statement of Financial Position		Net of Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position
(Dollars in Thousands)							Commodity Contracts			Cash Collateral Received/Posted		Net Amount
Assets
Energy Derivative Contracts	$	51,709	$	—	$	51,709	$	(26,319	)	$	—	$	25,390
Liabilities
Energy Derivative Contracts	$	48,531	$	—	$	48,531	$	(26,319	)	$	—	$	22,212
Interest Rate Swaps 2	$	12,126	$	—	$	12,126	$	—		$	—	$	12,126
Puget Energy and Puget Sound Energy
December 31, 2013
	Gross Amount Recognized in the Statement of Financial Position 1		Gross Amounts Offset in the Statement of Financial Position		Net of Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position
(Dollars in Thousands)							Commodity Contracts			Cash Collateral Received/Posted		Net Amount
Assets
Energy Derivative Contracts	$	26,600	$	—	$	26,600	$	(19,491	)	$	—	$	7,109
Liabilities
Energy Derivative Contracts	$	72,988	$	—	$	72,988	$	(19,491	)	$	—	$	53,497
Interest Rate Swaps 2	$	13,223	$	—	$	13,223	$	—		$	—	$	13,223

___________

¹  All Derivative Contract deals are executed under ISDA, NAESB and WSPP Master Netting Agreements with Right of Offset.

²  Interest Rate Swap Contracts are only held at Puget Energy.

Schedule of Credit Risk Related Contingent Features

The table below presents the fair value of the overall contractual contingent liability positions for the Company's derivative activity at March 31, 2014:

Puget Energy and Puget Sound Energy Contingent Feature	Fair Value 1			Posted		Contingent
(Dollars in Thousands)	Liability			Collateral		Collateral
Credit rating 2	$	(10,290	)	$	—	$	10,290
Requested credit for adequate assurance	(10,596		)	—		—
Forward value of contract 3	(1,931		)	—		—
Total	$	(22,817	)	$	—	$	10,290

__________

¹  Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions. 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 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.

PUGET ENERGY [Member]

Derivative [Line Items]

Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance

The following tables present the effect and locations of the Company's derivatives not designated as hedging instruments, recorded on the statements of income:

Puget Energy		Three Months Ended March 31,
(Dollars in Thousands)	Location	2014			2013
Interest rate contracts:	Non-hedged interest rate swap (expense) income	$	(747	)	$	1,028
	Interest expense	(125		)	(2,578		)
Commodity contracts:
Electric derivatives	Unrealized gain (loss) on derivative instruments, net	7,839			75,692
	Electric generation fuel	7,827			(12,638		)
	Purchased electricity	5,383			(31,485		)
Total gain (loss) recognized in income on derivatives		$	20,177		$	30,019

Subsidiaries [Member]

Derivative [Line Items]

Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance

Puget Sound Energy		Three Months Ended March 31,
(Dollars in Thousands)	Location	2014		2013
Commodity contracts:
Electric derivatives	Unrealized gain (loss) on derivative instruments, net	$	7,270	$	72,740
	Electric generation fuel	7,827		(12,638		)
	Purchased electricity	5,383		(31,485		)
Total gain (loss) recognized in income on derivatives		$	20,480	$	28,617

Schedule of Derivative Instruments, Effect on Other Comprehensive Income (Loss)

Puget Sound Energy		Three Months Ended March 31,
(Dollars in Thousands)	Location	2014			2013
Interest rate contracts:	Interest expense	$	(122	)	$	(122	)
Commodity contracts:
Electric derivatives	Electric generation fuel	—			—
	Purchased electricity	(1,104		)	(2,786		)
Total		$	(1,226	)	$	(2,908	)

Parent [Member]

Derivative [Line Items]

Schedule of Derivative Instruments, Effect on Other Comprehensive Income (Loss)

The following tables present the Company's pre-tax gain (loss) of derivatives that were previously in a cash flow hedge relationship, and subsequently reclassified out of accumulated OCI into income:

Puget Energy		Three Months Ended March 31,
(Dollars in Thousands)	Location	2014			2013
Interest rate contracts:	Interest expense	$	(144	)	$	(1,314	)
Commodity contracts:
Electric derivatives	Electric generation fuel	—			—
	Purchased electricity	(534		)	164
Total		$	(678	)	$	(1,150	)

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Reclassification of net unrealized loss on interest rate swaps during the period, net of tax	$ 50	$ 460
Net unrealized gain (loss) from pension and postretirement plans, tax	113	(186)
Reclassification of net unrealized loss on energy derivative instruments during the period, net of tax	(187)	57
Subsidiaries [Member]
Reclassification of net unrealized loss on interest rate swaps during the period, net of tax	1,078	1,823
Net unrealized gain (loss) from pension and postretirement plans, tax	(386)	(975)
Reclassification of net unrealized loss on energy derivative instruments during the period, net of tax	$ (43)	$ (43)

XML

Regulation and Rates

3 Months Ended

Mar. 31, 2014

Regulation and Rates [Abstract]

Regulation and Rates

Regulation and Rates

On January 31, 2013, the Washington Commission approved a rate change to PSE's Federal Incentive Tracker tariff, effective February 1, 2013, which incorporated the effects of the Treasury Grant related to the Lower Snake River wind generation project and keeping the ten year amortization period and inclusion of interest on the unamortized balance of the grants. The rate change will pass through eleven months of amortization for both grants to eligible customers beginning February 1, 2013, including grant amortization pass-back of $34.6 million and interest pass-back of $23.8 million. This represents an overall average rate decrease of 2.76%.

On June 25, 2013, the Washington Commission approved PSE's electric and natural gas decoupling mechanism and expedited rate filing (ERF) tariff filings, effective July 1, 2013. The estimated revenue impact of the decoupling mechanism is an increase for electric of $21.4 million, or 1.0% annually, and an increase for natural gas of $10.8 million, or 1.1% annually. The allowed decoupling revenue per customer for the recovery of delivery system costs will subsequently increase by 3.0% for the electric customers and 2.2% for the gas customers on January 1 of each year, until the conclusion of PSE's next general rate case.

The estimated revenue impact of the ERF filings is an increase for electric of $30.7 million, or 1.5% annually, while the revenue impact for natural gas is a decrease of $2.0 million, or a decrease of 0.2% annually. The ERF filings also provided for the collection of property taxes through a property tax tracker mechanism. The property tax rate tracker will initially produce no incremental revenue, but is intended to reduce regulatory lag associated with the recovery of future increases in property tax expenses. PSE's 2012 and 2013 property taxes that are not in current rates will be recovered in later years. In its order, the Washington Commission approved a weighted cost of capital of 7.77% and a capital structure that included 48.0% common equity with a return on equity of 9.8%.

Subsequently, certain parties to this proceeding petitioned the Washington Commission to reconsider the order. On December 13, 2013, the Washington Commission approved the settlement agreements for rates effective January 1, 2014. These settlement agreements do not materially change the revenues originally approved in June 2013. As a result, certain high volume natural gas industrial customers' rate schedules are excluded from the decoupling mechanism and will be subject to certain effects of abnormal weather, conservation impacts and changes in customer usage patterns.

On July 24, 2013, the Public Counsel Division of the Washington State Attorney General's Office (Public Counsel) and the Industrial Customers of Northwest Utilities (ICNU) each filed a petition in Thurston County Superior Court (the Court) seeking judicial reviews of various aspects of the Washington Commission's ERF and decoupling mechanism final order. The parties' petition argues that the order violates various procedural and substantive requirements of the Washington Administrative Procedure Act, and so requests that it be vacated and that the matter be remanded to the Washington Commission. Oral arguments regarding this matter are scheduled for May 9, 2014.

On October 23, 2013, the Washington Commission approved an update on the Company's power cost only rate case (PCORC), effective November 1, 2013, which reflected decreases in the overall normalized power supply costs. This resulted in an estimated revenue decrease of $10.5 million or 0.5% annually.

On October 30, 2013, the Washington Commission approved PSE's PGA natural gas tariff, effective November 1, 2013, which reflected changes in wholesale gas and pipeline transportation costs and changes in deferral amortization rates. The estimated revenue impact of the approved change is an increase of $4.0 million, or 0.4% annually, with no impact on net operating income.

On October 30, 2013, the Washington Commission approved PSE's Pipeline Replacement Program Plan (PRPP) that would accelerate and enhance the safety of the natural gas system and ultimately reduce costs. Under the PRPP plan, PSE would be allowed to file a tariff revision to recover its costs associated with the acceleration of the replacement of natural gas pipelines with the Washington Commission.

On December 27, 2013, the Washington Commission approved the annual true-up and rate filing to the PSE's Federal Incentive Tracker tariff, effective January 1, 2014. The true-up filing resulted in a total credit of $58.5 million to be passed back to eligible customers over the twelve months beginning January 1, 2014. Of the total credit, $37.8 million represents the pass-back of grant amortization and $20.6 million represents the pass through of interest, in addition to a minor true-up associated with the 2013 rate period. This filing represents an overall average rate increase of 0.26% as compared to the previous rate.

On April 24, 2014, the Washington Commission approved PSE’s request to change rates under its electric and natural gas decoupling mechanism, effective May 1, 2014.  The rate change incorporated the effects of an increase to the allowed delivery revenue per customer as well as true-ups to the rate from the prior year.  This represents a rate increase for electric of $10.6 million, or 0.5% annually, and a rate decrease for natural gas of $1.0 million, or 0.1% annually.  

On April 24, 2014, the Washington Commission also approved PSE’s request to change rates under its electric and natural gas property tax tracker mechanism, effective May 1, 2014.  The rate change incorporated the effects of an increase in the amount of property taxes paid as well as true-ups to the rate from the prior year.  This represents a rate increase for electric of $11.0 million, or 0.5% annually, and a rate increase for natural gas of $5.6 million, or 0.6% annually.

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Retirement Benefits

3 Months Ended

Mar. 31, 2014

Compensation and Retirement Disclosure [Abstract]

Retirement Benefits

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.  Beginning January 1, 2014, all new UA employees and those new non-represented employees who elect to accumulate the Company contribution in the Cash Balance pension, will receive annual pay credits of 4% each year. They will also receive interest credits like other participants in the Cash Balance pension, which are at least 1% per quarter. When a newly-hired employee with a vested Cash Balance benefit leaves PSE, he or she will have annuity and lump sum options for distribution, with annuities calculated according to the Pension Protection Act. Those who select the lump sum option will receive their current cash balance amount. Participation by continuing employees in the Cash Balance pension plan is not affected.

In addition to providing pension benefits, PSE provides group health care and life insurance benefits for certain retired employees.  PSE also maintains a non-qualified Supplemental Executive Retirement Plan (SERP) for its key senior management 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 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 re-measurement of the retirement plans are recorded at Puget Energy.

The following tables summarize the Company’s net periodic benefit cost for the three months ended March 31, 2014 and 2013:

Puget Energy	Qualified Pension Benefits						SERP Pension Benefits					Other Benefits
	Three Months Ended March 31,
(Dollars in Thousands)	2014			2013			2014		2013			2014			2013
Components of net periodic benefit cost:
Service cost	$	4,512		$	4,709		$	261	$	375		$	29		$	34
Interest cost	7,055			6,194			577		511			183			176
Expected return on plan assets	(10,721		)	(9,851		)	—		—			(133		)	(108		)
Amortization of prior service cost	(495		)	(495		)	11		(4		)	—			—
Amortization of net loss (gain)	—			650			228		365			(66		)	17
Net periodic benefit cost	$	351		$	1,207		$	1,077	$	1,247		$	13		$	119

Puget Sound Energy	Qualified						SERP					Other
	Pension Benefits						Pension Benefits					Benefits
	Three Months Ended March 31,
(Dollars in Thousands)	2014			2013			2014		2013			2014			2013
Components of net periodic benefit cost:
Service cost	$	4,512		$	4,709		$	261	$	375		$	29		$	34
Interest cost	7,055			6,194			577		511			183			176
Expected return on plan assets	(10,919		)	(10,249		)	—		—			(133		)	(108		)
Amortization of prior service cost	(393		)	(393		)	11		(4		)	1			8
Amortization of net loss (gain)	3,239			5,085			365		548			(143		)	(34		)
Net periodic benefit cost	$	3,494		$	5,346		$	1,214	$	1,430		$	(63	)	$	76

The following table summarizes the Company’s change in benefit obligation for the periods ended March 31, 2014 and December 31, 2013:

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, 2014			December 31, 2013			March 31, 2014			December 31, 2013			March 31, 2014			December 31, 2013
Change in benefit obligation:
Benefit obligation at beginning of period	$	573,317		$	616,290		$	47,279		$	51,795		$	14,939		$	17,672
Service cost	4,512			19,285			261			1,498			29			134
Interest cost	7,055			24,754			577			2,045			183			664
Amendment	—			—			—			478			—			—
Actuarial loss/(gain)	—			(48,559		)	—			(1,687		)	—			(2,240		)
Benefits paid	(10,001		)	(38,453		)	(460		)	(6,850		)	(391		)	(1,536		)
Medicare part D subsidiary received	—			—			—			—			42			245
Benefit obligation at end of period	$	574,883		$	573,317		$	47,657		$	47,279		$	14,802		$	14,939

The aggregate expected contributions by the Company to fund the qualified pension plan, SERP and the other postretirement plans for the year ending December 31, 2014 are expected to be at least $12.0 million, $4.0 million and $0.4 million, respectively. During the three months ended March 31, 2014, the Company contributed $3.0 million, $0.5 million, and $0.2 million to fund the qualified pension plan, SERP and the other postretirement plan, respectively.

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Summary of Significant Accounting Policies Cash Flow Restatements (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Regulatory Assets	$ (38,240)	$ (28,953)
Net Cash Provided by (Used in) Operating Activities	310,534	301,265
Energy Efficiency Expenditures		0
Net Cash Provided by (Used in) Investing Activities	(118,709)	(63,820)
Scenario, Previously Reported [Member]
Regulatory Assets		(6,411)
Net Cash Provided by (Used in) Operating Activities		323,807
Energy Efficiency Expenditures		(22,542)
Net Cash Provided by (Used in) Investing Activities		(86,362)
Subsidiaries [Member]
Regulatory Assets	(38,240)	(28,953)
Net Cash Provided by (Used in) Operating Activities	334,090	309,701
Energy Efficiency Expenditures		0
Net Cash Provided by (Used in) Investing Activities	(118,091)	(63,756)
Subsidiaries [Member] | Scenario, Previously Reported [Member]
Regulatory Assets		(6,411)
Net Cash Provided by (Used in) Operating Activities		332,243
Energy Efficiency Expenditures		(22,542)
Net Cash Provided by (Used in) Investing Activities		$ (86,298)

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2014

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Fair Value, by Balance Sheet Grouping

The following table presents the fair value hierarchy by level, the carrying value for cash, cash equivalents, restricted cash, notes receivable and short-term debt. The carrying values below are representative of fair values due to the short-term nature of these financial instruments.

	Carrying / Fair Value						Carrying / Fair Value
Puget Energy	At March 31, 2014						At December 31, 2013
(Dollars in Thousands)	Level 1		Level 2		Total		Level 1		Level 2		Total
Assets:
Cash and Cash Equivalents	$	23,581	$	—	$	23,581	$	44,302	$	—	$	44,302
Restricted Cash	25,437		—		25,437		7,171		—		7,171
Notes Receivable and Other	—		54,542		54,542		—		53,449		53,449
Total assets	$	49,018	$	54,542	$	103,560	$	51,473	$	53,449	$	104,922
Liabilities:
Short-term debt	$	—	$	—	$	—	$	162,000	$	—	$	162,000
Total liabilities	$	—	$	—	$	—	$	162,000	$	—	$	162,000

	Carrying / Fair Value						Carrying / Fair Value
Puget Sound Energy	At March 31, 2014						At December 31, 2013
(Dollars in Thousands)	Level 1		Level 2		Total		Level 1		Level 2		Total
Assets:
Cash and Cash Equivalents	$	23,556	$	—	$	23,556	$	44,111	$	—	$	44,111
Restricted Cash	25,437		—		25,437		7,171		—		7,171
Notes Receivable and Other	—		54,542		54,542		—		53,449		53,449
Total assets	$	48,993	$	54,542	$	103,535	$	51,282	$	53,449	$	104,731
Liabilities:
Short-term debt	$	—	$	—	$	—	$	162,000	$	—	$	162,000
Short-term debt owed to parent	—		29,598		29,598		—		29,598		29,598
Total liabilities	$	—	$	29,598	$	29,598	$	162,000	$	29,598	$	191,598

Fair Value Inputs, Liabilities, Quantitative Information

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. Carrying values and estimated fair values were as follows:

Puget Energy		March 31, 2014				December 31, 2013
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Junior subordinated notes	2	$	250,000	$	280,137	$	250,000	$	269,366
Long-term debt (fixed-rate), net of discount	2	4,686,259		5,875,347		4,683,476		5,594,314
Long-term debt (variable-rate)	2	299,000		299,000		299,000		299,000
Total		$	5,235,259	$	6,454,484	$	5,232,476	$	6,162,680
Puget Sound Energy		March 31, 2014				December 31, 2013
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Junior subordinated notes	2	$	250,000	$	280,137	$	250,000	$	269,366
Long-term debt (fixed-rate), net of discount	2	3,513,258		4,239,741		3,513,258		4,038,455
Total		$	3,763,258	$	4,519,878	$	3,763,258	$	4,307,821

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation

Puget Energy and Puget Sound Energy	Three Months Ended March 31,
Level 3 Roll-Forward Net Asset/(Liability)	2014									2013
(Dollars in Thousands)	Electric			Gas			Total			Electric			Gas			Total
Balance at beginning of period	$	(15,421	)	$	(361	)	$	(15,782	)	$	(33,924	)	$	(1,602	)	$	(35,526	)
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings 1	(2,745		)	—			(2,745		)	1,598			—			1,598
Included in regulatory assets / liabilities	—			259			259			—			674			674
Settlements 2	321			(410		)	(89		)	6,384			(733		)	5,651
Transferred into Level 3	3,100			(585		)	2,515			(7,700		)	—			(7,700		)
Transferred out of Level 3	139			(6		)	133			7,200			127			7,327
Balance at end of period	$	(14,606	)	$	(1,103	)	$	(15,709	)	$	(26,442	)	$	(1,534	)	$	(27,976	)

_________

¹  Income Statement location: Unrealized (gain) loss on derivative instruments, net. Includes unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $(9.2) millionand $1.4 million for the three months ended March 31, 2014 and 2013, respectively.

² The Company had no purchases, sales or issuances during the reported periods

Fair Value Inputs, Assets and Liabilities, Quantitative Information

Below are the forward price ranges for the Company's purchased commodity contracts, as of March 31, 2014:

(Dollars in Thousands)
	Fair Value						Range
Derivative Instrument	Assets 1		Liabilities 1		Valuation Technique	Unobservable Input	Low	High	Weighted Average
Electric	$	5,040	$	19,646	Discounted cash flow	Power Prices	$4.38 per MWh	$49.95 per MWh	$35.67 per MWh
Natural gas	$	2,550	$	3,653	Discounted cash flow	Natural Gas Prices	$3.62 per MMBtu	$4.63 per MMBtu	$4.04 per MMBtu

__________

¹  The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions

PUGET ENERGY [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis

Puget Energy	Fair Value						Fair Value
	At March 31, 2014						At December 31, 2013
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total
Interest rate derivative instruments	$	12,126	$	—	$	12,126	$	13,223	$	—	$	13,223
Total derivative liabilities	$	12,126	$	—	$	12,126	$	13,223	$	—	$	13,223

Subsidiaries [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis

Puget Energy and	Fair Value						Fair Value
Puget Sound Energy	At March 31, 2014						At December 31, 2013
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	18,866	$	5,040	$	23,906	$	14,661	$	3,818	$	18,479
Natural gas derivative instruments	25,253		2,550		27,803		5,448		2,673		8,121
Total assets	$	44,119	$	7,590	$	51,709	$	20,109	$	6,491	$	26,600
Liabilities:
Electric derivative instruments	$	14,719	$	19,646	$	34,365	$	18,073	$	19,239	$	37,312
Natural gas derivative instruments	10,513		3,653		14,166		32,642		3,034		35,676
Total liabilities	$	25,232	$	23,299	$	48,531	$	50,715	$	22,273	$	72,988

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Other

3 Months Ended

Mar. 31, 2014

Other [Abstract]

Other

Other

Jefferson County Public Utility District (JPUD)

PSE completed the sale of its electric infrastructure assets located in Jefferson County and the transition of electrical services in the county to JPUD on March 31, 2013. The proceeds from the sale exceeded the transferred assets' net carrying value of $46.7 million resulting in a pre-tax gain of approximately $60.0 million. In its 2010 order on the subject, the Washington Commission stated that PSE must file an accounting and ratemaking petition with the Washington Commission to determine how this gain will be allocated between customers and shareholders. As a result, the gain was deferred and recorded as a regulatory liability until the Washington Commission determines the accounting and ratemaking treatment. On October 31, 2013, PSE filed an accounting petition for a Washington Commission order that authorizes PSE to retain the gain of $45.0 million and return $15.0 million to its remaining customers over a period of forty-eight months. On March 28, 2014, intervenors filed response testimonies containing their respective proposals for allocation of the gain, which included a proposal of up to $57.0 million to customers and $3.0 million to PSE. The Washington Commission will hold evidentiary hearings in this matter beginning May 21, 2014.

For federal income tax purposes, the Company will elect to treat the transaction as an involuntary conversion under the Internal Revenue Code which allows for deferral of the tax gain if PSE acquires qualified replacement property by December 31, 2015. Based on PSE's current construction program projection, it anticipates meeting this requirement through such purchases by that date.

Bond Issuances

On May 23, 2013, PSE refinanced $161.9 million of its Pollution Control Revenue Refunding Bonds (the Bonds) to a lower weighted average interest rate from 5.01% to 3.91%. The Bonds will mature on March 1, 2031. On or after March 1, 2023, the Company may elect to call the bonds at a redemption price of 100% of the principal amount thereof, without premium, plus accrued interest, if any, to the redemption date. Due to the refinance of the Bonds, Puget Energy wrote off $18.0 million of fair value related to the Bonds that were redeemed to interest expense. 

Credit Facilities

In April 2014, subsequent to the close of the first quarter, the Company completed a one-year extension on both of the liquidity and hedging facilities of PSE, extending the maturity from February 2018 to April 2019. All other terms and conditions of the facilities remain unchanged from when they were committed in 2013. At this same time, the Company completed a one-year extension on the senior secured credit facility of Puget Energy, extending the maturity from February 2017 to April 2018. There were no significant changes to other terms and conditions.

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Litigation

3 Months Ended

Mar. 31, 2014

Litigation Disclosure [Abstract]

Litigation

Litigation

Residential Exchange

The Northwest Power Act, through the Residential Exchange Program (REP), provides access to the benefits of low-cost federal power for residential and small farm customers of regional utilities, including PSE.  The program is administered by the Bonneville Power Administration (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 United States Court of Appeals for the Ninth Circuit (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 fiscal year 2002 through fiscal year 2011 period 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 (2012 REP Settlement) that by its terms, if upheld in its entirety, would resolve the disputes between BPA and PSE regarding REP benefits paid for fiscal years 2002-2011 and determine REP benefits for fiscal years 2012-2028.  In October 2011, certain other parties challenged BPA decisions with regard to its entering into the 2012 REP Settlement agreement.  On October 28, 2013, the Ninth Circuit issued an order dismissing this challenge to this settlement. In light of the disposition of this challenge, the stay of the other pending Ninth Circuit litigation regarding REP benefits was lifted in January 2014. In the order lifting the stay, petitioners (unless they move to voluntarily dismiss their petitions) and intervenors (unless they move to voluntarily withdraw) were directed to file a statement explaining which issues, if any, remain pending. Subsequent to the order lifting the stay, in February 2014, one group of petitioners in the other pending Ninth Circuit litigation moved to dismiss its petition and its motion was granted. Two of the remaining petitioners may seek dismissal of their petitions, but other remaining petitioners have not submitted such a motion but rather have stated to the Ninth Circuit that they are pursuing certain claims. PSE is unable to determine what impact these proceedings 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 directly to REP customers.

With the Ninth Circuit’s decision affirming the 2012 REP Settlement, PSE will receive $62.9 million in REP payments owed under a 2008 agreement, which are in addition to scheduled monthly REP benefits received from BPA under the 2012 REP Settlement. These payments will be given back to PSE's residential and small farm customers through a higher residential exchange credit.

Colstrip

PSE has a 50% ownership interest in Colstrip Units 1 and 2, and a 25% interest in Colstrip Units 3 and 4. On March 6, 2013, Sierra Club and Montana Environmental Information Center (MEIC) filed a Clean Air Act citizen suit against all Colstrip owners (including PSE) alleging numerous claims for relief, most which relate to alleged prevention of significant deterioration (PSD) violations. One claim relates to the alleged failure to update the Title V permit to reflect the major modifications alleged in the first thirty-six claims, another claim alleges that the previous Title V compliance certifications have been incomplete because they did not address the alleged major modifications, and the last claim alleges opacity violations since 2007. The lawsuit was filed in U.S. District of Montana, Billings Division, requesting injunctive relief and civil penalties, including a request that the owners remediate environmental damage and that $100,000 of the civil penalties be used for beneficial mitigation projects. This lawsuit followed various Notices of Intent to Sue sent to Colstrip owners (including PSE) from the Sierra Club and the MEIC between July and December 2012.  Discovery in the case has begun, and the case has been bifurcated into separate liability and remedy trials. The liability trial is currently set for June 2015, and a date for the remedy trial has yet to be determined. PSE is litigating the allegations set forth in the notices and cannot at this time 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 $1.36 million and $1.38 million relating to these claims as of March 31, 2014 and December 31, 2013, respectively.

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Accumulated Other Comprehensive Income (Notes)

3 Months Ended

Mar. 31, 2014

Equity [Abstract]

Accumulated Other Comprehensive Income (Loss)

Accumulated Other Comprehensive Income (Loss)

The following tables present the changes in the Company’s accumulated other comprehensive income (loss) (AOCI) by component for the three months ended March 31, 2014:

Puget Energy	Net unrealized gain (loss) and prior service cost on pension plans			Net unrealized gain (loss) on energy derivative instruments			Net unrealized gain (loss) on interest rate swaps
Changes in AOCI, net of tax
(Dollars in Thousands)										Total
Balance at December 31, 2013	$	48,514		$	(705	)	$	(94	)	$	47,715
Other comprehensive income (loss) before reclassifications	—			—			—			—
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	(209		)	347			94			232
Net current-period other comprehensive income (loss)	(209		)	347			94			232
Balance at March 31, 2014	$	48,305		$	(358	)	$	—		$	47,947

Puget Sound Energy	Net unrealized gain (loss) and prior service cost on pension plans			Net unrealized gain (loss) on energy derivative instruments			Net unrealized gain (loss) on treasury interest rate swaps
Changes in AOCI, net of tax
(Dollars in Thousands)										Total
Balance at December 31, 2013	$	(87,405	)	$	(2,027	)	$	(6,307	)	$	(95,739	)
Other comprehensive income (loss) before reclassifications	—			—			—			—
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	2,001			718			79			2,798
Net current-period other comprehensive income (loss)	2,001			718			79			2,798
Balance at March 31, 2014	$	(85,404	)	$	(1,309	)	$	(6,228	)	$	(92,941	)

Details about these reclassifications out of accumulated other comprehensive income (loss) for the three months ended March 31, 2014 and March 31, 2013, respectively, are as follows:

Puget Energy		Three Months Ended			Three Months Ended
(Dollars in Thousands)		March 31, 2014			March 31, 2013
Details about accumulated other comprehensive income (loss) components	Affected line item in the statement where net income (loss) is presented	Amount reclassified from accumulated other comprehensive income (loss)
Net unrealized gain (loss) and prior service cost on pension plans:
Amortization of prior service cost	(a)	484			499
Amortization of net gain (loss)	(a)	(162		)	(1,032		)
	Total before tax	322			(533		)
	Tax (expense) or benefit	(113		)	186
	Net of Tax	$	209		$	(347	)
Net unrealized gain (loss) on energy derivative instruments:
Commodity contracts: electric derivatives	Purchased electricity	(534		)	164
	Tax (expense) or benefit	187			(57		)
	Net of Tax	$	(347	)	$	107
Net unrealized gain (loss) on interest rate swaps:
Interest rate contracts	Interest expense	$	(144	)	$	(1,314	)
	Tax (expense) or benefit	50			460
	Net of Tax	$	(94	)	$	(854	)
Total reclassification for the period	Net of Tax	$	(232	)	$	(1,094	)

__________

^(a)  These accumulated other comprehensive income components are included in the computation of net periodic pension cost (see Note 4 for additional details).

Puget Sound Energy		Three Months Ended			Three Months Ended
(Dollars in Thousands)		March 31, 2014			March 31, 2013
Details about accumulated other comprehensive income (loss) components	Affected line item in the statement where net income (loss) is presented	Amount reclassified from accumulated other comprehensive income (loss)
Net unrealized gain (loss) and prior service cost on pension plans:
Amortization of prior service cost	(a)	$	381		$	389
Amortization of net gain (loss)	(a)	(3,461		)	(5,599		)
	Total before tax	(3,080		)	(5,210		)
	Tax (expense) or benefit	1,079			1,824
	Net of Tax	$	(2,001	)	$	(3,386	)
Net unrealized gain (loss) on energy derivative instruments:
Commodity contracts: electric derivatives	Purchased electricity	(1,104		)	(2,786		)
	Tax (expense) or benefit	386			975
	Net of Tax	$	(718	)	$	(1,811	)
Net unrealized gain (loss) on treasury interest rate swaps:
Interest rate contracts	Interest expense	(122		)	(122		)
	Tax (expense) or benefit	43			43
	Net of Tax	$	(79	)	$	(79	)
Total reclassification for the period	Net of Tax	$	(2,798	)	$	(5,276	)

__________

^(a)  These accumulated other comprehensive income components are included in the computation of net periodic pension cost (see Note 4 for additional details).

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Summary of Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2014

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]

Summary of Significant Accounting Policies

Basis of Presentation

Puget Energy is an energy services holding company that owns PSE.  PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering approximately 6,000 square miles, primarily in the Puget Sound region.  Following the merger with Puget Holdings LLC (Puget Holdings) in 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 subsidiary.  Puget Energy and PSE are collectively referred to herein as “the Company.”  The consolidated financial statements are presented after elimination of intercompany transactions.  PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any purchase accounting adjustments.

The consolidated financial statements contained in this Form 10-Q are unaudited.  In the respective opinions of the management of Puget Energy and PSE, all adjustments necessary for a fair statement of the results for the interim periods have been reflected and were of a normal recurring nature.  These consolidated financial statements should be read in conjunction with the audited financial statements (and the Combined Notes thereto) included in the combined Puget Energy and PSE Annual Report on Form 10-K for the year ended December 31, 2013.

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.

PSE collected Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes totaling $77.9 million and $76.9 million for the three months ended March 31, 2014 and 2013, respectively.  The Company reports the collection of such taxes on a gross basis in operating revenue and as expense in taxes other than income taxes in the accompanying consolidated statements of income.

Beginning July 1, 2013, PSE's electric and gas operations contain a revenue decoupling mechanism under which PSE's actual energy delivery revenues related to electric transmission and distribution, gas operations and general administrative costs are compared with authorized revenues allowed under the mechanism. Any differences are deferred to a regulatory asset for under recovery or regulatory liability for over recovery. Revenues associated with power costs under the Power Cost Adjustment (PCA) mechanism and Purchased Gas Adjustment (PGA) rates are excluded from the decoupling mechanism.

Statements of Cash Flows

The Company revised its Consolidated Statement of Cash Flows due to an immaterial error. Revisions were made in the second quarter ended June 30, 2013 on the Company's Consolidated Statement of Cash Flows to reflect energy efficiency expenditures as operating cash outflows instead of investing cash outflows. The Company determined energy efficiency expenditures should have been classified as operating activities instead of investing activities. These revisions decreased net cash provided by operating activities and decreased net cash used by investing activities. The revision does not affect the net change in cash and cash equivalents for any of the periods, and has no effect on the Company's Consolidated Statements of Income, Consolidated Statements of Comprehensive Income, Consolidated Balance Sheets, and Consolidated Statement of Common Shareholder's Equity. The Company has evaluated the effects of these errors and concluded that none of them are material to any of the Company's previously issued quarterly or annual Financial Statements. Nevertheless, the Company elected to revise the Consolidated Statement of Cash Flows in this report to correct for the effect of these errors and properly reflect the revised values.

The amounts on prior period Consolidated Statements of Cash Flows which have been revised are summarized below:

	As Reported			As Revised
Puget Energy	Three Months Ended			Three Months Ended
(Dollars in Thousands)	March 31, 2013			March 31, 2013
Operating Activities:
Regulatory Assets	$	(6,411	)	$	(28,953	)
Net Cash Provided by Operating Activities	$	323,807		$	301,265
Investing Activities:
Energy Efficiency Expenditures	$	(22,542	)	$	—
Net Cash Used in Investing Activities	$	(86,362	)	$	(63,820	)

	As Reported			As Revised
Puget Sound Energy	Three Months Ended			Three Months Ended
(Dollars in Thousands)	March 31, 2013			March 31, 2013
Operating Activities:
Regulatory Assets	$	(6,411	)	$	(28,953	)
Net Cash Provided by Operating Activities	$	332,243		$	309,701
Investing Activities:
Energy Efficiency Expenditures	$	(22,542	)	$	—
Net Cash Used in Investing Activities	$	(86,298	)	$	(63,756	)

Basis of Presentation

Summary of Significant Accounting Policies

Basis of Presentation

Puget Energy is an energy services holding company that owns PSE.  PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering approximately 6,000 square miles, primarily in the Puget Sound region.  Following the merger with Puget Holdings LLC (Puget Holdings) in 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 subsidiary.  Puget Energy and PSE are collectively referred to herein as “the Company.”  The consolidated financial statements are presented after elimination of intercompany transactions.  PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any purchase accounting adjustments.

The consolidated financial statements contained in this Form 10-Q are unaudited.  In the respective opinions of the management of Puget Energy and PSE, all adjustments necessary for a fair statement of the results for the interim periods have been reflected and were of a normal recurring nature.  These consolidated financial statements should be read in conjunction with the audited financial statements (and the Combined Notes thereto) included in the combined Puget Energy and PSE Annual Report on Form 10-K for the year ended December 31, 2013.

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

PSE collected Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes totaling $77.9 million and $76.9 million for the three months ended March 31, 2014 and 2013, respectively.  The Company reports the collection of such taxes on a gross basis in operating revenue and as expense in taxes other than income taxes in the accompanying consolidated statements of income.

Beginning July 1, 2013, PSE's electric and gas operations contain a revenue decoupling mechanism under which PSE's actual energy delivery revenues related to electric transmission and distribution, gas operations and general administrative costs are compared with authorized revenues allowed under the mechanism. Any differences are deferred to a regulatory asset for under recovery or regulatory liability for over recovery. Revenues associated with power costs under the Power Cost Adjustment (PCA) mechanism and Purchased Gas Adjustment (PGA) rates are excluded from the decoupling mechanism.

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Retirement Benefits Net Periodic Benefit Cost (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended	12 Months Ended	3 Months Ended	12 Months Ended	3 Months Ended	12 Months Ended	3 Months Ended
	Mar. 31, 2014 Qualified Pension Benefits [Member]	Dec. 31, 2013 Qualified Pension Benefits [Member]	Mar. 31, 2014 SERP Pension Benefits [Member]	Dec. 31, 2013 SERP Pension Benefits [Member]	Mar. 31, 2014 Other Benefit [Member]	Dec. 31, 2013 Other Benefit [Member]	Mar. 31, 2014 PUGET ENERGY [Member] Qualified Pension Benefits [Member]	Mar. 31, 2013 PUGET ENERGY [Member] Qualified Pension Benefits [Member]	Mar. 31, 2014 PUGET ENERGY [Member] SERP Pension Benefits [Member]	Mar. 31, 2013 PUGET ENERGY [Member] SERP Pension Benefits [Member]	Mar. 31, 2014 PUGET ENERGY [Member] Other Benefit [Member]	Mar. 31, 2013 PUGET ENERGY [Member] Other Benefit [Member]	Mar. 31, 2014 Subsidiaries [Member] Qualified Pension Benefits [Member]	Mar. 31, 2013 Subsidiaries [Member] Qualified Pension Benefits [Member]	Mar. 31, 2014 Subsidiaries [Member] SERP Pension Benefits [Member]	Mar. 31, 2013 Subsidiaries [Member] SERP Pension Benefits [Member]	Mar. 31, 2014 Subsidiaries [Member] Other Benefit [Member]	Mar. 31, 2013 Subsidiaries [Member] Other Benefit [Member]
Components of net periodic benefit cost:
Service cost	$ (4,512)	$ (19,285)	$ (261)	$ (1,498)	$ (29)	$ (134)	$ 4,512	$ 4,709	$ 261	$ 375	$ 29	$ 34	$ 4,512	$ 4,709	$ 261	$ 375	$ 29	$ 34
Interest cost	(7,055)	(24,754)	(577)	(2,045)	(183)	(664)	7,055	6,194	577	511	183	176	7,055	6,194	577	511	183	176
Expected return on plan assets							(10,721)	(9,851)	0	0	(133)	(108)	(10,919)	(10,249)	0	0	(133)	(108)
Amortization of prior service cost							(495)	(495)	11	(4)	0	0	(393)	(393)	11	(4)	1	8
Amortization of net loss (gain)							0	650	228	365	(66)	17	3,239	5,085	365	548	(143)	(34)
Defined Benefit Plan, Net Periodic Benefit Cost							$ 351	$ 1,207	$ 1,077	$ 1,247	$ 13	$ 119	$ 3,494	$ 5,346	$ 1,214	$ 1,430	$ (63)	$ 76

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Accumulated Other Comprehensive Income (Tables)

3 Months Ended

Mar. 31, 2014

PUGET ENERGY [Member]

Accumulated Other Comprehensive Income (Loss) [Line Items]

Schedule of Accumulated Other Comprehensive Income (Loss)

The following tables present the changes in the Company’s accumulated other comprehensive income (loss) (AOCI) by component for the three months ended March 31, 2014:

Puget Energy	Net unrealized gain (loss) and prior service cost on pension plans			Net unrealized gain (loss) on energy derivative instruments			Net unrealized gain (loss) on interest rate swaps
Changes in AOCI, net of tax
(Dollars in Thousands)										Total
Balance at December 31, 2013	$	48,514		$	(705	)	$	(94	)	$	47,715
Other comprehensive income (loss) before reclassifications	—			—			—			—
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	(209		)	347			94			232
Net current-period other comprehensive income (loss)	(209		)	347			94			232
Balance at March 31, 2014	$	48,305		$	(358	)	$	—		$	47,947

Reclassification out of Accumulated Other Comprehensive Income

Details about these reclassifications out of accumulated other comprehensive income (loss) for the three months ended March 31, 2014 and March 31, 2013, respectively, are as follows:

Puget Energy		Three Months Ended			Three Months Ended
(Dollars in Thousands)		March 31, 2014			March 31, 2013
Details about accumulated other comprehensive income (loss) components	Affected line item in the statement where net income (loss) is presented	Amount reclassified from accumulated other comprehensive income (loss)
Net unrealized gain (loss) and prior service cost on pension plans:
Amortization of prior service cost	(a)	484			499
Amortization of net gain (loss)	(a)	(162		)	(1,032		)
	Total before tax	322			(533		)
	Tax (expense) or benefit	(113		)	186
	Net of Tax	$	209		$	(347	)
Net unrealized gain (loss) on energy derivative instruments:
Commodity contracts: electric derivatives	Purchased electricity	(534		)	164
	Tax (expense) or benefit	187			(57		)
	Net of Tax	$	(347	)	$	107
Net unrealized gain (loss) on interest rate swaps:
Interest rate contracts	Interest expense	$	(144	)	$	(1,314	)
	Tax (expense) or benefit	50			460
	Net of Tax	$	(94	)	$	(854	)
Total reclassification for the period	Net of Tax	$	(232	)	$	(1,094	)

Subsidiaries [Member]

Accumulated Other Comprehensive Income (Loss) [Line Items]

Schedule of Accumulated Other Comprehensive Income (Loss)

Puget Sound Energy	Net unrealized gain (loss) and prior service cost on pension plans			Net unrealized gain (loss) on energy derivative instruments			Net unrealized gain (loss) on treasury interest rate swaps
Changes in AOCI, net of tax
(Dollars in Thousands)										Total
Balance at December 31, 2013	$	(87,405	)	$	(2,027	)	$	(6,307	)	$	(95,739	)
Other comprehensive income (loss) before reclassifications	—			—			—			—
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	2,001			718			79			2,798
Net current-period other comprehensive income (loss)	2,001			718			79			2,798
Balance at March 31, 2014	$	(85,404	)	$	(1,309	)	$	(6,228	)	$	(92,941	)

Reclassification out of Accumulated Other Comprehensive Income

Puget Sound Energy		Three Months Ended			Three Months Ended
(Dollars in Thousands)		March 31, 2014			March 31, 2013
Details about accumulated other comprehensive income (loss) components	Affected line item in the statement where net income (loss) is presented	Amount reclassified from accumulated other comprehensive income (loss)
Net unrealized gain (loss) and prior service cost on pension plans:
Amortization of prior service cost	(a)	$	381		$	389
Amortization of net gain (loss)	(a)	(3,461		)	(5,599		)
	Total before tax	(3,080		)	(5,210		)
	Tax (expense) or benefit	1,079			1,824
	Net of Tax	$	(2,001	)	$	(3,386	)
Net unrealized gain (loss) on energy derivative instruments:
Commodity contracts: electric derivatives	Purchased electricity	(1,104		)	(2,786		)
	Tax (expense) or benefit	386			975
	Net of Tax	$	(718	)	$	(1,811	)
Net unrealized gain (loss) on treasury interest rate swaps:
Interest rate contracts	Interest expense	(122		)	(122		)
	Tax (expense) or benefit	43			43
	Net of Tax	$	(79	)	$	(79	)
Total reclassification for the period	Net of Tax	$	(2,798	)	$	(5,276	)

__________

^(a)  These accumulated other comprehensive income components are included in the computation of net periodic pension cost (see Note 4 for additional details).

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Accounting for Derivative Instruments and Hedging Activities Net Amount of Derivatives Reported in the Statement of Financial Position (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014 Commodity Contract [Member]		Dec. 31, 2013 Commodity Contract [Member]		Mar. 31, 2014 Interest Rate Contract [Member]		Dec. 31, 2013 Interest Rate Contract [Member]
Derivative [Line Items]
Derivative contracts classified as financing activities due to merger	$ (8,026)	$ (26,049)
Assets
Gross Amount Recognized in the Statement of Financial Position			51,709	[1]	26,600	[1]
Gross Amounts Offset in the Statement of Financial Position			0		0
Net of Amounts Presented in the Statement of Financial Position			51,709		26,600
Commodity Contracts			(26,319)		(19,491)
Cash Collateral Received			0		0
Net Amount			25,390		7,109
Liabilities
Gross Amount Recognized in the Statement of Financial Position			48,531	[1]	72,988	[1]	12,126	[1],[2]	13,223	[1],[2]
Gross Amounts Offset in the Statement of Financial Position			0		0		0	[2]	0	[2]
Net of Amounts Presented in the Statement of Financial Position			48,531		72,988		12,126	[2]	13,223	[2]
Commodity Contracts			(26,319)		(19,491)		0	[2]	0	[2]
Cash Collateral Posted			0		0		0	[2]	0	[2]
Net Amount			$ 22,212		$ 53,497		$ 12,126	[2]	$ 13,223	[2]

[1] 1 All Derivative Contract deals are executed under ISDA, NAESB and WSPP Master Netting Agreements with Right of Offset.

[2] 2 Interest Rate Swap Contracts are only held at Puget Energy.

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Other Jefferson County Public Utility District (Details) (Jefferson County Public Utility District [Member], USD $) In Millions, unless otherwise specified	Oct. 31, 2013	Mar. 30, 2013	Mar. 28, 2014 Subsidiaries [Member]	Oct. 31, 2013 Subsidiaries [Member]	Mar. 28, 2014 Customers [Member]	Oct. 31, 2013 Customers [Member]
Significant Acquisitions and Disposals [Line Items]
Property, Plant and Equipment, Net Book Value		$ 46.7
Significant Acquisitions and Disposals, Gain (Loss) on Sale or Disposal, Pretax		$ 60.0	$ 3.0	$ 45.0	$ 57.0	$ 15.0
Accounting Petition, Requested Amortization Period	48 months

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CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Utility plant (at original cost, including construction work in progress):
Electric plant	$ 7,079,136	$ 7,019,853
Gas plant	2,557,017	2,528,629
Common plant	457,071	504,036
Less: Accumulated depreciation and amortization	(1,401,652)	(1,373,178)
Net utility plant	8,691,572	8,679,340
Other property and investments:
Goodwill	1,656,513	1,656,513
Other property and investments	101,572	100,332
Total other property and investments	1,758,085	1,756,845
Current assets:
Cash and cash equivalents	23,581	44,302
Restricted cash	25,437	7,171
Accounts receivable, net of allowance for doubtful accounts	432,641	408,512
Unbilled revenue	167,105	219,884
Materials and supplies, at average cost	87,926	88,140
Fuel and gas inventory, at average cost	31,245	66,717
Unrealized gain on derivative instruments	44,889	18,867
Income taxes	149	297
Prepaid expense and other	18,232	18,787
Power contract acquisition adjustment gain	48,243	48,509
Deferred income taxes	77,343	86,004
Total current assets	956,791	1,007,190
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes	144,166	146,867
Regulatory assets related to power contracts	32,985	33,753
Other regulatory assets	709,094	749,382
Unrealized gain on derivative instruments	6,820	7,733
Power contract acquisition adjustment gain	380,204	394,556
Other	134,186	130,909
Total other long-term and regulatory assets	1,407,455	1,463,200
Total assets	12,813,903	12,906,575
Capitalization:
Common stock	0	0
Additional paid-in capital	3,308,957	3,308,957
Earnings reinvested in the business	388,518	323,007
Accumulated Other Comprehensive Income (Loss), Net of Tax	47,947	47,715
Total common shareholder's equity	3,745,422	3,679,679
Long-term debt:
First mortgage bonds and senior notes	3,351,412	3,351,412
Pollution control bonds	161,860	161,860
Junior subordinated notes	250,000	250,000
Long-term debt	1,699,000	1,699,000
Debt discount	(227,013)	(229,796)
Total long-term debt	5,235,259	5,232,476
Total capitalization	8,980,681	8,912,155
Current liabilities:
Accounts payable	288,420	296,681
Short-term debt	0	162,000
Purchased gas adjustment liability	2,859	5,938
Accrued expenses:
Taxes	121,035	109,559
Salaries and wages	28,245	38,491
Interest	74,173	79,303
Unrealized loss on derivative instruments	33,213	48,049
Power contract acquisition adjustment loss	3,889	3,937
Other	84,199	60,335
Total current liabilities	636,033	804,293
Long-term and regulatory liabilities:
Deferred income taxes	1,517,287	1,487,005
Unrealized loss on derivative instruments	27,444	38,162
Power Cost Adjustment Mechanism	5,394	5,345
Regulatory liabilities	676,750	689,060
Regulatory liabilities related to power contracts	428,447	443,065
Power contract acquisition adjustment loss	29,095	29,816
Other deferred credits	512,772	497,674
Total long-term and regulatory liabilities	3,197,189	3,190,127
Commitments and contingencies
Total capitalization and liabilities	12,813,903	12,906,575
Subsidiaries [Member]
Utility plant (at original cost, including construction work in progress):
Electric plant	9,331,849	9,276,400
Gas plant	3,162,703	3,134,880
Common plant	498,184	565,072
Less: Accumulated depreciation and amortization	(4,301,164)	(4,297,012)
Net utility plant	8,691,572	8,679,340
Other property and investments:
Other property and investments	93,159	91,919
Total other property and investments	93,159	91,919
Current assets:
Cash and cash equivalents	23,556	44,111
Restricted cash	25,437	7,171
Accounts receivable, net of allowance for doubtful accounts	432,915	408,827
Unbilled revenue	167,105	219,884
Materials and supplies, at average cost	87,926	88,140
Fuel and gas inventory, at average cost	28,463	63,914
Unrealized gain on derivative instruments	44,889	18,867
Income taxes	149	297
Prepaid expense and other	18,232	18,770
Deferred income taxes	132,248	141,058
Total current assets	960,920	1,011,039
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes	143,628	146,350
Other regulatory assets	709,094	749,382
Unrealized gain on derivative instruments	6,820	7,733
Other	127,202	123,125
Total other long-term and regulatory assets	986,744	1,026,590
Total assets	10,732,395	10,808,888
Capitalization:
Common stock	859	859
Additional paid-in capital	3,246,205	3,246,205
Earnings reinvested in the business	336,401	289,432
Accumulated Other Comprehensive Income (Loss), Net of Tax	(92,941)	(95,739)
Total common shareholder's equity	3,490,524	3,440,757
Long-term debt:
First mortgage bonds and senior notes	3,351,412	3,351,412
Pollution control bonds	161,860	161,860
Junior subordinated notes	250,000	250,000
Debt discount	(14)	(14)
Total long-term debt	3,763,258	3,763,258
Total capitalization	7,253,782	7,204,015
Current liabilities:
Accounts payable	288,415	296,675
Short-term debt	0	162,000
Short-term note owed to parent	29,598	29,598
Purchased gas adjustment liability	2,859	5,938
Accrued expenses:
Taxes	121,035	109,559
Salaries and wages	28,245	38,491
Interest	57,094	55,262
Unrealized loss on derivative instruments	26,461	41,465
Other	84,199	60,334
Total current liabilities	637,906	799,322
Long-term and regulatory liabilities:
Deferred income taxes	1,626,368	1,584,850
Unrealized loss on derivative instruments	22,070	31,523
Power Cost Adjustment Mechanism	5,394	5,345
Regulatory liabilities	674,103	686,176
Other deferred credits	512,772	497,657
Total long-term and regulatory liabilities	2,840,707	2,805,551
Commitments and contingencies
Total capitalization and liabilities	$ 10,732,395	$ 10,808,888

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Fair Value Measurements

3 Months Ended

Mar. 31, 2014

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

ASC 820 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.

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 measured at fair value are classified in their entirety in the appropriate fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. The Company primarily determines fair value measurements classified as Level 2 or Level 3 using a combination of the income and market valuation approaches. The process of determining the fair values is the responsibility of the derivative accounting department which reports to the Controller and Principal Accounting Officer. Inputs used to estimate the fair value of forwards, swaps and options include market-price curves; contract terms and prices; credit-risk adjustments; and discount factors. Additionally, for options, the Black-Scholes option valuation model and implied market volatility curves are used. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs because substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments. On a daily basis, the Company obtains quoted forward prices for the electric and natural gas market from an independent external pricing service. For interest rate swaps, the Company obtains monthly mark-to-market values from an independent external pricing service for London Interbank Offered Rate (LIBOR) forward rates, which is a significant input. Some of the inputs of the interest rate swap valuations, which are less significant, include the credit standing of the counterparties, assumptions for time value and the impact of the Company's nonperformance risk of its liabilities. The Company classifies cash and cash equivalents, and restricted cash as Level 1 financial instruments due to cash being at stated value, and cash equivalents at quoted market prices.

The Company considers its electric, natural gas and interest rate swap contracts as Level 2 derivative instruments as such contracts are commonly traded as over-the-counter forwards with indirectly observable price quotes. Management's assessment was based on the trading activity 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. However, certain energy derivative instruments with maturity dates falling outside the range of observable price quotes are classified as Level 3 in the fair value hierarchy.

Assets and Liabilities with Estimated Fair Value

The following table presents the fair value hierarchy by level, the carrying value for cash, cash equivalents, restricted cash, notes receivable and short-term debt. The carrying values below are representative of fair values due to the short-term nature of these financial instruments.

	Carrying / Fair Value						Carrying / Fair Value
Puget Energy	At March 31, 2014						At December 31, 2013
(Dollars in Thousands)	Level 1		Level 2		Total		Level 1		Level 2		Total
Assets:
Cash and Cash Equivalents	$	23,581	$	—	$	23,581	$	44,302	$	—	$	44,302
Restricted Cash	25,437		—		25,437		7,171		—		7,171
Notes Receivable and Other	—		54,542		54,542		—		53,449		53,449
Total assets	$	49,018	$	54,542	$	103,560	$	51,473	$	53,449	$	104,922
Liabilities:
Short-term debt	$	—	$	—	$	—	$	162,000	$	—	$	162,000
Total liabilities	$	—	$	—	$	—	$	162,000	$	—	$	162,000

	Carrying / Fair Value						Carrying / Fair Value
Puget Sound Energy	At March 31, 2014						At December 31, 2013
(Dollars in Thousands)	Level 1		Level 2		Total		Level 1		Level 2		Total
Assets:
Cash and Cash Equivalents	$	23,556	$	—	$	23,556	$	44,111	$	—	$	44,111
Restricted Cash	25,437		—		25,437		7,171		—		7,171
Notes Receivable and Other	—		54,542		54,542		—		53,449		53,449
Total assets	$	48,993	$	54,542	$	103,535	$	51,282	$	53,449	$	104,731
Liabilities:
Short-term debt	$	—	$	—	$	—	$	162,000	$	—	$	162,000
Short-term debt owed to parent	—		29,598		29,598		—		29,598		29,598
Total liabilities	$	—	$	29,598	$	29,598	$	162,000	$	29,598	$	191,598

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. Carrying values and estimated fair values were as follows:

Puget Energy		March 31, 2014				December 31, 2013
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Junior subordinated notes	2	$	250,000	$	280,137	$	250,000	$	269,366
Long-term debt (fixed-rate), net of discount	2	4,686,259		5,875,347		4,683,476		5,594,314
Long-term debt (variable-rate)	2	299,000		299,000		299,000		299,000
Total		$	5,235,259	$	6,454,484	$	5,232,476	$	6,162,680
Puget Sound Energy		March 31, 2014				December 31, 2013
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Junior subordinated notes	2	$	250,000	$	280,137	$	250,000	$	269,366
Long-term debt (fixed-rate), net of discount	2	3,513,258		4,239,741		3,513,258		4,038,455
Total		$	3,763,258	$	4,519,878	$	3,763,258	$	4,307,821

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:

Puget Energy	Fair Value						Fair Value
	At March 31, 2014						At December 31, 2013
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total
Interest rate derivative instruments	$	12,126	$	—	$	12,126	$	13,223	$	—	$	13,223
Total derivative liabilities	$	12,126	$	—	$	12,126	$	13,223	$	—	$	13,223

Puget Energy and	Fair Value						Fair Value
Puget Sound Energy	At March 31, 2014						At December 31, 2013
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	18,866	$	5,040	$	23,906	$	14,661	$	3,818	$	18,479
Natural gas derivative instruments	25,253		2,550		27,803		5,448		2,673		8,121
Total assets	$	44,119	$	7,590	$	51,709	$	20,109	$	6,491	$	26,600
Liabilities:
Electric derivative instruments	$	14,719	$	19,646	$	34,365	$	18,073	$	19,239	$	37,312
Natural gas derivative instruments	10,513		3,653		14,166		32,642		3,034		35,676
Total liabilities	$	25,232	$	23,299	$	48,531	$	50,715	$	22,273	$	72,988

The following table presents the Company's reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy:

Puget Energy and Puget Sound Energy	Three Months Ended March 31,
Level 3 Roll-Forward Net Asset/(Liability)	2014									2013
(Dollars in Thousands)	Electric			Gas			Total			Electric			Gas			Total
Balance at beginning of period	$	(15,421	)	$	(361	)	$	(15,782	)	$	(33,924	)	$	(1,602	)	$	(35,526	)
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings 1	(2,745		)	—			(2,745		)	1,598			—			1,598
Included in regulatory assets / liabilities	—			259			259			—			674			674
Settlements 2	321			(410		)	(89		)	6,384			(733		)	5,651
Transferred into Level 3	3,100			(585		)	2,515			(7,700		)	—			(7,700		)
Transferred out of Level 3	139			(6		)	133			7,200			127			7,327
Balance at end of period	$	(14,606	)	$	(1,103	)	$	(15,709	)	$	(26,442	)	$	(1,534	)	$	(27,976	)

_________

¹  Income Statement location: Unrealized (gain) loss on derivative instruments, net. Includes unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $(9.2) millionand $1.4 million for the three months ended March 31, 2014 and 2013, respectively.

² The Company had no purchases, sales 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 which 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. The changes of fair value classification into or out of Level 3 are recognized each month, and reported in the Level 3 Roll-forward table above. The Company did not have any transfers between Level 2 and Level 1 during the reported periods. The Company does periodically transact at locations, or market price points, that are illiquid 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 for the Company's purchased commodity contracts, as of March 31, 2014:

(Dollars in Thousands)
	Fair Value						Range
Derivative Instrument	Assets 1		Liabilities 1		Valuation Technique	Unobservable Input	Low	High	Weighted Average
Electric	$	5,040	$	19,646	Discounted cash flow	Power Prices	$4.38 per MWh	$49.95 per MWh	$35.67 per MWh
Natural gas	$	2,550	$	3,653	Discounted cash flow	Natural Gas Prices	$3.62 per MMBtu	$4.63 per MMBtu	$4.04 per MMBtu

__________

¹  The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.

The significant unobservable inputs listed above would have a direct impact on the fair values of the above instruments if they were adjusted. Consequently significant increases or decreases in the forward prices of electricity or natural gas in isolation would result in a significantly higher or lower fair value for Level 3 assets and liabilities. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets. At March 31, 2014, 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 $12.1 million.

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Accounting for Derivative Instruments and Hedging Activities Recognized in Statement of Income (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Derivative Instruments, (Loss) Gain [Line Items]
Document Period End Date	Mar. 31, 2014
Purchased electricity	$ 181,157	$ 175,043
Unrealized (gain) loss on derivative instruments	(7,839)	(75,692)
Subsidiaries [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Document Period End Date	Mar. 31, 2014
Purchased electricity	181,157	175,043
Unrealized (gain) loss on derivative instruments	(7,270)	(72,740)
Not Designated as Hedging Instrument [Member] | PUGET ENERGY [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	(20,177)	(30,019)
Not Designated as Hedging Instrument [Member] | PUGET ENERGY [Member] | Other Income (Deductions) [Member] | Interest Expense [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	747	(1,028)
Not Designated as Hedging Instrument [Member] | PUGET ENERGY [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	125	2,578
Not Designated as Hedging Instrument [Member] | PUGET ENERGY [Member] | Commodity Contract [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	(7,839)	(75,692)
Not Designated as Hedging Instrument [Member] | PUGET ENERGY [Member] | Commodity Contract [Member] | Electric generation fuel [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	(7,827)	12,638
Not Designated as Hedging Instrument [Member] | PUGET ENERGY [Member] | Commodity Contract [Member] | Purchased Electricity [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	(5,383)	31,485
Not Designated as Hedging Instrument [Member] | Subsidiaries [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	(20,480)	(28,617)
Not Designated as Hedging Instrument [Member] | Subsidiaries [Member] | Commodity Contract [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	(7,270)	(72,740)
Not Designated as Hedging Instrument [Member] | Subsidiaries [Member] | Commodity Contract [Member] | Electric generation fuel [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	(7,827)	12,638
Not Designated as Hedging Instrument [Member] | Subsidiaries [Member] | Commodity Contract [Member] | Purchased Electricity [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	(5,383)	31,485
Cash Flow Hedging [Member] | PUGET ENERGY [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(678)	(1,150)
Cash Flow Hedging [Member] | PUGET ENERGY [Member] | Electric generation fuel [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	0	0
Cash Flow Hedging [Member] | Subsidiaries [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(1,226)	(2,908)
Cash Flow Hedging [Member] | Subsidiaries [Member] | Electric generation fuel [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ 0	$ 0

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Litigation (Details) (USD $)						0 Months Ended
	Mar. 31, 2014	Mar. 31, 2014 Colstrip Units 1 and 2 [Member]	Mar. 31, 2014 Colstrip Units 3 and 4 [Member]	Mar. 31, 2014 Pending Litigation [Member]	Dec. 31, 2013 Pending Litigation [Member]	Mar. 06, 2013 Pending Litigation [Member] Sierra Club and Montana Environmental Information Center [Member]	Mar. 06, 2013 Pending Litigation [Member] Failure to Update Title V Permit [Member] Sierra Club and Montana Environmental Information Center [Member] claim	Mar. 06, 2013 Pending Litigation [Member] Major Modifications to Title V Permit [Member] Sierra Club and Montana Environmental Information Center [Member] claim
Loss Contingencies [Line Items]
Residential Exchange Program Repayment	$ 62,900,000
Ownership interest (percent)		50.00%	25.00%
Numbe of claims							1	36
Damages sought, civil penalties to be used for beneficial mitigation projects						100,000
Litigation claims accrual				$ 1,360,000	$ 1,380,000

XML

Retirement Benefits (Tables)

3 Months Ended

Mar. 31, 2014

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Schedule of Changes in Projected Benefit Obligations

The following table summarizes the Company’s change in benefit obligation for the periods ended March 31, 2014 and December 31, 2013:

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, 2014			December 31, 2013			March 31, 2014			December 31, 2013			March 31, 2014			December 31, 2013
Change in benefit obligation:
Benefit obligation at beginning of period	$	573,317		$	616,290		$	47,279		$	51,795		$	14,939		$	17,672
Service cost	4,512			19,285			261			1,498			29			134
Interest cost	7,055			24,754			577			2,045			183			664
Amendment	—			—			—			478			—			—
Actuarial loss/(gain)	—			(48,559		)	—			(1,687		)	—			(2,240		)
Benefits paid	(10,001		)	(38,453		)	(460		)	(6,850		)	(391		)	(1,536		)
Medicare part D subsidiary received	—			—			—			—			42			245
Benefit obligation at end of period	$	574,883		$	573,317		$	47,657		$	47,279		$	14,802		$	14,939

PUGET ENERGY [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Schedule of Net Benefit Costs

The following tables summarize the Company’s net periodic benefit cost for the three months ended March 31, 2014 and 2013:

Puget Energy	Qualified Pension Benefits						SERP Pension Benefits					Other Benefits
	Three Months Ended March 31,
(Dollars in Thousands)	2014			2013			2014		2013			2014			2013
Components of net periodic benefit cost:
Service cost	$	4,512		$	4,709		$	261	$	375		$	29		$	34
Interest cost	7,055			6,194			577		511			183			176
Expected return on plan assets	(10,721		)	(9,851		)	—		—			(133		)	(108		)
Amortization of prior service cost	(495		)	(495		)	11		(4		)	—			—
Amortization of net loss (gain)	—			650			228		365			(66		)	17
Net periodic benefit cost	$	351		$	1,207		$	1,077	$	1,247		$	13		$	119

Subsidiaries [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Schedule of Net Benefit Costs

Puget Sound Energy	Qualified						SERP					Other
	Pension Benefits						Pension Benefits					Benefits
	Three Months Ended March 31,
(Dollars in Thousands)	2014			2013			2014		2013			2014			2013
Components of net periodic benefit cost:
Service cost	$	4,512		$	4,709		$	261	$	375		$	29		$	34
Interest cost	7,055			6,194			577		511			183			176
Expected return on plan assets	(10,919		)	(10,249		)	—		—			(133		)	(108		)
Amortization of prior service cost	(393		)	(393		)	11		(4		)	1			8
Amortization of net loss (gain)	3,239			5,085			365		548			(143		)	(34		)
Net periodic benefit cost	$	3,494		$	5,346		$	1,214	$	1,430		$	(63	)	$	76