Edgar Filing: PUGET ENERGY INC /WA

PE-2014.6.30-10Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

For the quarterly period ended June 30, 2014



[ ]	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 and Six Months Ended June 30, 2014 and 2013	5
	Consolidated Statements of Comprehensive Income – Three and Six Months Ended June 30, 2014 and 2013	6
	Consolidated Balance Sheets – June 30, 2014 and December 31, 2013	7
	Consolidated Statements of Cash Flows – Six Months Ended June 30, 2014 and 2013	8

	Puget Sound Energy, Inc.
	Consolidated Statements of Income – Three and Six Months Ended June 30, 2014 and 2013	9
	Consolidated Statements of Comprehensive Income – Three and Six Months Ended June 30, 2014 and 2013	10
	Consolidated Balance Sheets – June 30, 2014 and December 31, 2013	11
	Consolidated Statements of Cash Flows – Six Months Ended June 30, 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	32

Item 3.	Quantitative and Qualitative Disclosure About Market Risk	51

Item 4.	Controls and Procedures	53

Part II.	Other Information	54

Item 1.	Legal Proceedings	54

Item 1A.	Risk Factors	54

Item 6.	Exhibits	54

Signatures		55

Exhibit Index		56

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.

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.

PART I FINANCIAL INFORMATION

Item 1. Financial Statements

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands)

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Operating revenue:
Electric	$	475,580		$	461,657		$	1,109,133		$	1,076,291
Gas	183,935			180,728			571,378			565,493
Other	3,401			101			7,780			520
Total operating revenue	662,916			642,486			1,688,291			1,642,304
Operating expenses:
Energy costs:
Purchased electricity	114,627			112,543			295,785			287,587
Electric generation fuel	34,795			40,737			110,232			99,823
Residential exchange	(23,621		)	(14,963		)	(53,624		)	(37,515		)
Purchased gas	76,272			79,487			267,578			269,470
Unrealized (gain) loss on derivative instruments, net	(17,094		)	27,376			(24,934		)	(48,316		)
Utility operations and maintenance	134,883			130,286			278,960			259,521
Non-utility expense and other	2,293			(959		)	5,712			(1,953		)
Depreciation	92,462			90,301			183,646			178,480
Amortization	12,735			6,433			23,270			12,177
Conservation amortization	22,526			22,469			51,508			56,576
Taxes other than income taxes	67,772			53,695			168,590			153,638
Total operating expenses	517,650			547,405			1,306,723			1,229,488
Operating income (loss)	145,266			95,081			381,568			412,816
Other income (deductions):
Other income	4,621			10,844			8,863			22,857
Other expense	(1,644		)	(1,454		)	(3,226		)	(2,996		)
Non-hedged interest rate swap (expense) income	(1,360		)	1,232			(2,107		)	2,260
Interest charges:
AFUDC	1,562			3,162			2,714			7,810
Interest expense	(92,173		)	(108,917		)	(182,428		)	(204,733		)
Income (loss) before income taxes	56,272			(52		)	205,384			238,014
Income tax (benefit) expense	15,159			(957		)	56,679			69,634
Net income (loss)	$	41,113		$	905		$	148,705		$	168,380

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

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands)

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Net income (loss)	$	41,113		$	905		$	148,705		$	168,380
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $(421), $(596), $(534) and $(409), respectively	(783		)	(1,107		)	(992		)	(760		)
Reclassification of net unrealized (gain) loss on energy derivative instruments settled during the period, net of tax of $0, $0, $187 and $(57), respectively	—			—			347			(107		)
Reclassification of net unrealized (gain) loss on interest rate swaps during the period, net of tax of $0, $464, $50 and $924, respectively	—			861			94			1,715
Other comprehensive income (loss)	(783		)	(246		)	(551		)	848
Comprehensive income (loss)	$	40,330		$	659		$	148,154		$	169,228

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

PUGET ENERGY, INC. CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) ASSETS

	(Unaudited)
	June 30, 2014			December 31, 2013
Utility plant (at original cost, including construction work in progress of $313,227 and $310,318, respectively):
Electric plant	$	7,046,429		$	7,019,853
Gas plant	2,602,397			2,528,629
Common plant	456,383			504,036
Less: Accumulated depreciation and amortization	(1,478,202		)	(1,373,178		)
Net utility plant	8,627,007			8,679,340
Other property and investments:
Goodwill	1,656,513			1,656,513
Other property and investments	99,877			100,332
Total other property and investments	1,756,390			1,756,845
Current assets:
Cash and cash equivalents	84,707			44,302
Restricted cash	54,964			7,171
Accounts receivable, net of allowance for doubtful accounts of $10,517 and $7,385, respectively	287,374			408,512
Unbilled revenue	112,304			219,884
Purchased Gas Adjustment Receivable	12,539			—
Materials and supplies, at average cost	82,658			88,140
Fuel and gas inventory, at average cost	64,334			66,717
Unrealized gain on derivative instruments	44,405			18,867
Taxes	—			297
Prepaid expense and other	20,043			18,787
Power contract acquisition adjustment gain	49,020			48,509
Deferred income taxes	73,902			86,004
Total current assets	886,250			1,007,190
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes	150,083			146,867
Regulatory assets related to power contracts	31,311			33,753
Other regulatory assets	733,281			749,382
Unrealized gain on derivative instruments	7,678			7,733
Power contract acquisition adjustment gain	370,468			394,556
Other	137,336			130,909
Total other long-term and regulatory assets	1,430,157			1,463,200
Total assets	$	12,699,804		$	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)
	June 30, 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	333,933			323,007
Accumulated other comprehensive income (loss), net of tax	47,164			47,715
Total common shareholder’s equity	3,690,054			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	(224,230		)	(229,796		)
Total long-term debt	5,238,042			5,232,476
Total capitalization	8,928,096			8,912,155
Current liabilities:
Accounts payable	245,760			296,681
Short-term debt	—			162,000
Purchased gas adjustment liability	—			5,938
Accrued expenses:
Taxes	92,023			109,559
Salaries and wages	32,256			38,491
Interest	78,759			79,303
Unrealized loss on derivative instruments	23,690			48,049
Power contract acquisition adjustment loss	3,720			3,937
Other	68,671			60,335
Total current liabilities	544,879			804,293
Other long-term and regulatory liabilities:
Deferred income taxes	1,534,501			1,487,005
Unrealized loss on derivative instruments	21,761			38,162
Power cost adjustment mechanism	5,445			5,345
Regulatory liabilities	694,486			689,060
Regulatory liabilities related to power contracts	419,488			443,065
Power contract acquisition adjustment loss	27,592			29,816
Other deferred credits	523,556			497,674
Total other long-term and regulatory liabilities	3,226,829			3,190,127
Commitments and contingencies
Total capitalization and liabilities	$	12,699,804		$	12,906,575

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

PUGET ENERGY, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in Thousands) (Unaudited)

	Six Months Ended June 30,
	2014			2013
Operating activities:
Net income (loss)	$	148,705		$	168,380
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation	183,646			178,480
Amortization	23,270			12,177
Conservation amortization	51,508			56,576
Deferred income taxes and tax credits, net	56,679			69,635
Net unrealized (gain) loss on derivative instruments	(25,664		)	(53,496		)
Derivative contracts classified as financing activities due to merger	8,026			26,013
AFUDC – Equity	(3,405		)	(11,222		)
Funding of pension liability	(6,000		)	(10,200		)
Regulatory assets	(80,365		)	(66,102		)
Regulatory liabilities	3,668			10,341
Other long-term assets	(6,477		)	10,842
Other long-term liabilities	37,739			54,837
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	228,718			136,457
Materials and supplies	5,482			(2,184		)
Fuel and gas inventory	2,359			11,104
Taxes	297			4,795
Prepayments and other	(1,273		)	(7,340		)
Purchased gas adjustment	(18,477		)	(18,078		)
Accounts payable	(64,794		)	(74,666		)
Taxes payable	(17,536		)	(11,589		)
Accrued expenses and other	(8,884		)	(15,507		)
Net cash provided by operating activities	517,222			469,253
Investing activities:
Construction expenditures – excluding equity AFUDC	(217,381		)	(326,082		)
Treasury grants received	107,794			—
Proceeds from disposition of assets	—			108,166
Restricted cash	(47,793		)	(1,023		)
Other	(11,058		)	(5,119		)
Net cash used in investing activities	(168,438		)	(224,058		)
Financing activities:
Change in short-term debt and leases, net	(165,789		)	(184,789		)
Dividends paid	(137,779		)	(84,609		)
Long-term notes and bonds issued	299,000			161,860
Redemption of bonds and notes	(299,000		)	(216,860		)
Derivative contracts classified as financing activities due to merger	(8,026		)	(26,013		)
Issuance cost of bonds and other	3,215			(2,722		)
Net cash provided by (used in) financing activities	(308,379		)	(353,133		)
Net increase (decrease) in cash and cash equivalents	40,405			(107,938		)
Cash and cash equivalents at beginning of period	44,302			135,542
Cash and cash equivalents at end of period	$	84,707		$	27,604
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	172,106		$	162,588
Cash payments (refunds) for income taxes	—			(4,500		)

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands)

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Operating revenue:
Electric	$	475,580		$	461,657		$	1,109,133		$	1,076,291
Gas	183,935			180,728			571,378			565,493
Other	3,401			101			7,780			409
Total operating revenue	662,916			642,486			1,688,291			1,642,193
Operating expenses:
Energy costs:
Purchased electricity	114,627			112,543			295,785			287,587
Electric generation fuel	34,795			40,737			110,232			99,823
Residential exchange	(23,621		)	(14,963		)	(53,624		)	(37,515		)
Purchased gas	76,272			79,487			267,578			269,470
Unrealized (gain) loss on derivative instruments, net	(17,094		)	27,376			(24,364		)	(45,365		)
Utility operations and maintenance	134,883			130,286			278,960			259,521
Non-utility expense and other	5,374			3,028			11,548			6,120
Depreciation	92,462			90,301			183,646			178,480
Amortization	12,735			6,433			23,270			12,177
Conservation amortization	22,526			22,469			51,508			56,576
Taxes other than income taxes	67,772			53,695			168,590			153,638
Total operating expenses	520,731			551,392			1,313,129			1,240,512
Operating income (loss)	142,185			91,094			375,162			401,681
Other income (deductions):
Other income	4,621			10,846			8,860			22,857
Other expense	(1,644		)	(1,454		)	(3,226		)	(2,996		)
Interest charges:
AFUDC	1,562			3,162			2,714			7,810
Interest expense	(65,522		)	(65,773		)	(129,659		)	(131,749		)
Interest expense on parent note	(27		)	(32		)	(52		)	(61		)
Income (loss) before income taxes	81,175			37,843			253,799			297,542
Income tax (benefit) expense	23,341			11,180			74,883			90,941
Net income (loss)	$	57,834		$	26,663		$	178,916		$	206,601

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands)

(Unaudited)



	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
Net income (loss)	$	57,834	$	26,663	$	178,916	$	206,601
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $766, $1,011, $1,844 and $2,835, respectively	1,424		1,879		3,425		5,265
Reclassification of net unrealized (gain) loss on energy derivative instruments, net of tax of $0, $0, $386 and $975, respectively	—		—		718		1,811
Amortization of treasury interest rate swaps to earnings, net of tax of $43, $43, $85 and $85, respectively	79		79		158		158
Other comprehensive income (loss)	1,503		1,958		4,301		7,234
Comprehensive income (loss)	$	59,337	$	28,621	$	183,217	$	213,835

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

ASSETS



	(Unaudited)
	June 30, 2014			December 31, 2013
Utility plant (at original cost, including construction work in progress of $313,227 and $310,318, respectively):
Electric plant	$	9,296,198		$	9,276,400
Gas plant	3,207,261			3,134,880
Common plant	497,495			565,072
Less: Accumulated depreciation and amortization	(4,373,947		)	(4,297,012		)
Net utility plant	8,627,007			8,679,340
Other property and investments:
Other property and investments	91,465			91,919
Total other property and investments	91,465			91,919
Current assets:
Cash and cash equivalents	69,160			44,111
Restricted cash	54,964			7,171
Accounts receivable, net of allowance for doubtful accounts of $10,517 and $7,385, respectively	287,848			408,827
Unbilled revenue	112,304			219,884
Purchased gas adjustment receivable	12,539			—
Materials and supplies, at average cost	82,658			88,140
Fuel and gas inventory, at average cost	61,555			63,914
Unrealized gain on derivative instruments	44,405			18,867
Taxes	—			297
Prepaid expense and other	20,043			18,770
Deferred income taxes	129,122			141,058
Total current assets	874,598			1,011,039
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes	149,573			146,350
Other regulatory assets	733,215			749,382
Unrealized gain on derivative instruments	7,678			7,733
Other	130,131			123,125
Total other long-term and regulatory assets	1,020,597			1,026,590
Total assets	$	10,613,667		$	10,808,888

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

CAPITALIZATION AND LIABILITIES



	(Unaudited)
	June 30, 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	264,720			289,432
Accumulated other comprehensive income (loss), net of tax	(91,438		)	(95,739		)
Total common shareholder’s equity	3,420,346			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	7,183,604			7,204,015
Current liabilities:
Accounts payable	245,753			296,675
Short-term debt	—			162,000
Short-term note owed to parent	28,933			29,598
Purchased gas adjustment liability	—			5,938
Accrued expenses:
Taxes	92,023			109,559
Salaries and wages	32,256			38,491
Interest	55,216			55,262
Unrealized loss on derivative instruments	16,895			41,465
Other	68,671			60,334
Total current liabilities	539,747			799,322
Other long-term and regulatory liabilities:
Deferred income taxes	1,653,337			1,584,850
Unrealized loss on derivative instruments	16,208			31,523
Power cost adjustment mechanism	5,445			5,345
Regulatory liabilities	691,642			686,176
Other deferred credits	523,684			497,657
Total other long-term and regulatory liabilities	2,890,316			2,805,551
Commitments and contingencies
Total capitalization and liabilities	$	10,613,667		$	10,808,888

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)



	Six Months Ended June 30,
	2014			2013
Operating activities:
Net income (loss)	$	178,916		$	206,601
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation	183,646			178,480
Amortization	23,270			12,177
Conservation amortization	51,508			56,576
Deferred income taxes and tax credits, net	74,883			90,940
Net unrealized (gain) loss on derivative instruments	(24,364		)	(45,365		)
AFUDC – Equity	(3,405		)	(11,222		)
Funding of pension liability	(6,000		)	(10,200		)
Regulatory assets	(80,365		)	(66,102		)
Regulatory liabilities	3,668			10,341
Other long-term assets	(1,650		)	14,921
Other long-term liabilities	33,339			33,285
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	228,559			130,617
Materials and supplies	5,482			(2,184		)
Fuel and gas inventory	2,359			11,104
Taxes	297			4,795
Prepayments and other	(1,273		)	(7,340		)
Purchased gas adjustment	(18,477		)	(18,078		)
Accounts payable	(64,794		)	(68,819		)
Taxes payable	(17,536		)	(11,589		)
Accrued expenses and other	(9,620		)	(17,586		)
Net cash provided by operating activities	558,443			491,352
Investing activities:
Construction expenditures – excluding equity AFUDC	(217,381		)	(326,082		)
Treasury grants received	107,794			—
Proceeds from disposition of assets	—			108,166
Restricted cash	(47,793		)	(1,023		)
Other	(9,818		)	(4,902		)
Net cash used in investing activities	(167,198		)	(223,841		)
Financing activities:
Change in short-term debt and leases, net	(165,789		)	(184,789		)
Dividends paid	(203,628		)	(188,064		)
Loan from (payment to) parent	(665		)	—
Long-term notes and bonds issued	—			161,860
Redemption of bonds and notes	—			(161,860		)
Issuance cost of bonds and other	3,886			(2,725		)
Net cash provided by (used in) financing activities	(366,196		)	(375,578		)
Net increase (decrease) in cash and cash equivalents	25,049			(108,067		)
Cash and cash equivalents at beginning of period	44,111			135,530
Cash and cash equivalents at end of period	$	69,160		$	27,463
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	123,345		$	122,892
Cash payments (refunds) for income taxes	—			(4,500		)

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

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 Western, Inc. 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 $50.6 million and $128.5 million for the three and six months ended June 30, 2014, respectively, and $51.5 million and $128.4 million for the three and six months ended June 30, 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.

(2) New Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers, that outlines a single comprehensive model for use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The ASU is based on the principle that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The ASU also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to fulfill a contract.

ASU 2014-09 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. Early adoption of the ASU is not permitted. Entities have the option of using either a full retrospective or a modified retrospective approach for the adoption of the new standard. The company is currently evaluating the new guidance. At this time we can not determine the impact this standard will have on its consolidated financial statements.


(3)	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 June 30, 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	June 30, 2014					December 31, 2013
(Dollars in Thousands)	Volumes	Assets ¹		Liabilities ²		Volumes	Assets ¹		Liabilities ²
Interest rate swap derivatives ³	$450 million	$	—	$	12,349	$450 million	$	—	$	13,223
Electric portfolio derivatives	*	26,902		20,266		*	18,479		37,312
Natural gas derivatives (MMBtus) ⁴	359.0 million	25,181		12,836		423.5 million	8,121		35,676
Total derivative contracts		$	52,083	$	45,451		$	26,600	$	86,211
Current		$	44,405	$	23,690		$	18,867	$	48,049
Long-term		7,678		21,761			7,733		38,162
Total derivative contracts		$	52,083	$	45,451		$	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 139.8 million One Million British Thermal Units (MMBtus) and purchased electricity of 5.5 million Megawatt Hours (MWhs) at June 30, 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 4.

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
June 30, 2014
	Gross Amount Recognized in the Statement of Financial Position¹		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	$	52,083	—		$	52,083	$	(22,446	)	$	—	$	29,637
Liabilities
Energy Derivative Contracts	$	33,102	$	—	$	33,102	$	(22,446	)	$	43	$	10,699
Interest Rate Swaps ²	$	12,349	$	—	$	12,349	$	—		$	—	$	12,349

Puget Energy and Puget Sound Energy
December 31, 2013
	Gross Amount Recognized in the Statement of Financial Position¹		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 June 30,						Six Months Ended June 30,
(Dollars in Thousands)	Location	2014			2013			2014			2013
Interest rate contracts:	Non-hedged interest rate swap (expense) income	$	(1,360	)	$	1,232		$	(2,107	)	$	2,260
	Interest expense	(718		)	1,902			(843		)	(676		)
Commodity contracts:
Electric derivatives	Unrealized gain (loss) on derivative instruments, net	17,094			(27,376		)	24,934			48,316
	Electric generation fuel	864			(930		)	8,691			(13,568		)
	Purchased electricity	(3,668		)	(3,704		)	1,715			(35,189		)
Total gain (loss) recognized in income on derivatives		$	12,212		$	(28,876	)	$	32,390		$	1,143



Puget Sound Energy		Three Months Ended June 30,						Six Months Ended June 30,
(Dollars in Thousands)	Location	2014			2013			2014		2013
Commodity contracts:
Electric derivatives	Unrealized gain (loss) on derivative instruments, net	$	17,094		$	(27,376	)	$	24,364	$	45,365
	Electric generation fuel	864			(930		)	8,691		(13,568		)
	Purchased electricity	(3,668		)	(3,704		)	1,715		(35,189		)
Total gain (loss) recognized in income on derivatives		$	14,290		$	(32,010	)	$	34,770	$	(3,392	)

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 six months ended June 30, 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 June 30,					Six Months Ended June 30,
(Dollars in Thousands)	Location	2014		2013			2014			2013
Interest rate contracts:	Interest expense	$	—	$	(1,325	)	$	(144	)	$	(2,639	)
Commodity contracts:
Electric derivatives	Electric generation fuel	—		—			—			—
	Purchased electricity	—		—			(534		)	164
Total		$	—	$	(1,325	)	$	(678	)	$	(2,475	)



Puget Sound Energy		Three Months Ended June 30,						Six Months Ended June 30,
(Dollars in Thousands)	Location	2014			2013			2014			2013
Interest rate contracts:	Interest expense	$	(122	)	$	(122	)	$	(244	)	$	(244	)
Commodity contracts:
Electric derivatives	Electric generation fuel	—			—			—			—
	Purchased electricity	—			—			(1,104		)	(2,786		)
Total		$	(122	)	$	(122	)	$	(1,348	)	$	(3,030	)

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 June 30, 2014, approximately 99.9% of the Company's energy portfolio exposure, excluding NPNS transactions, is with counterparties that are rated at least investment grade and 0.1% are either rated below investment grade or not rated. The Company assesses credit risk internally for counterparties that are not rated by the major rating agencies.

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 June 30, 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 June 30, 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 June 30, 2014:



Puget Energy and Puget Sound Energy Contingent Feature	Fair Value ¹			Posted		Contingent
(Dollars in Thousands)	Liability			Collateral		Collateral
Credit rating ²	$	(6,909	)	$	—	$	6,909
Requested credit for adequate assurance	(10,207		)	—		—
Forward value of contract ³	(43		)	43		—
Total	$	(17,159	)	$	43	$	6,909

__________


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.


(4)	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 June 30, 2014						At December 31, 2013
(Dollars in Thousands)	Level 1		Level 2		Total		Level 1		Level 2		Total
Assets:
Cash and Cash Equivalents	$	84,707	$	—	$	84,707	$	44,302	$	—	$	44,302
Restricted Cash	54,964		—		54,964		7,171		—		7,171
Notes Receivable and Other	—		52,692		52,692		—		53,449		53,449
Total assets	$	139,671	$	52,692	$	192,363	$	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 June 30, 2014						At December 31, 2013
(Dollars in Thousands)	Level 1		Level 2		Total		Level 1		Level 2		Total
Assets:
Cash and Cash Equivalents	$	69,160	$	—	$	69,160	$	44,111	$	—	$	44,111
Restricted Cash	54,964		—		54,964		7,171		—		7,171
Notes Receivable and Other	—		52,692		52,692		—		53,449		53,449
Total assets	$	124,124	$	52,692	$	176,816	$	51,282	$	53,449	$	104,731
Liabilities:
Short-term debt	$	—	$	—	$	—	$	162,000	$	—	$	162,000
Short-term debt owed to parent	—		28,933		28,933		—		29,598		29,598
Total liabilities	$	—	$	28,933	$	28,933	$	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		June 30, 2014				December 31, 2013
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Junior subordinated notes	2	$	250,000	$	296,696	$	250,000	$	269,366
Long-term debt (fixed-rate), net of discount	2	4,689,042		6,018,770		4,683,476		5,594,314
Long-term debt (variable-rate)	2	299,000		299,000		299,000		299,000
Total		$	5,238,042	$	6,614,466	$	5,232,476	$	6,162,680

Puget Sound Energy		June 30, 2014				December 31, 2013
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Junior subordinated notes	2	$	250,000	$	296,696	$	250,000	$	269,366
Long-term debt (fixed-rate), net of discount	2	3,513,258		4,352,590		3,513,258		4,038,455
Total		$	3,763,258	$	4,649,286	$	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
Puget Energy	At June 30, 2014						At December 31, 2013
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total
Interest rate derivative instruments	$	12,349	$	—	$	12,349	$	13,223	$	—	$	13,223
Total derivative liabilities	$	12,349	$	—	$	12,349	$	13,223	$	—	$	13,223



Puget Energy and	Fair Value						Fair Value
Puget Sound Energy	At June 30, 2014						At December 31, 2013
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	15,882	$	11,020	$	26,902	$	14,661	$	3,818	$	18,479
Natural gas derivative instruments	22,356		2,825		25,181		5,448		2,673		8,121
Total assets	$	38,238	$	13,845	$	52,083	$	20,109	$	6,491	$	26,600
Liabilities:
Electric derivative instruments	$	4,554	$	15,713	$	20,267	$	18,073	$	19,239	$	37,312
Natural gas derivative instruments	9,737		3,098		12,835		32,642		3,034		35,676
Total liabilities	$	14,291	$	18,811	$	33,102	$	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 June 30,
Level 3 Roll-Forward Net Asset/(Liability)	2014									2013
(Dollars in Thousands)	Electric			Gas			Total			Electric			Gas			Total
Balance at beginning of period	$	(14,606	)	$	(1,103	)	$	(15,709	)	$	(26,442	)	$	(1,534	)	$	(27,976	)
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings ¹	7,800			—			7,800			(12,799		)	—			(12,799		)
Included in regulatory assets / liabilities	—			2,120			2,120			—			(684		)	(684		)
Settlements³	1,757			(166		)	1,591			2,678			(495		)	2,183
Transferred into Level 3	—			—			—			(830		)	—			(830		)
Transferred out of Level 3	356			(1,124		)	(768		)	494			(160		)	334
Balance at end of period	$	(4,693	)	$	(273	)	$	(4,966	)	$	(36,899	)	$	(2,873	)	$	(39,772	)



Puget Energy and Puget Sound Energy	Six Months Ended June 30,
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 ²	5,055			—			5,055			(11,201		)	—			(11,201		)
Included in regulatory assets / liabilities	—			2,379			2,379			—			(10		)	(10		)
Settlements³	2,078			(576		)	1,502			9,062			(1,228		)	7,834
Transferred into Level 3	3,100			(585		)	2,515			(8,530		)	—			(8,530		)
Transferred out of Level 3	495			(1,130		)	(635		)	7,694			(33		)	7,661
Balance at end of period	$	(4,693	)	$	(273	)	$	(4,966	)	$	(36,899	)	$	(2,873	)	$	(39,772	)

__________


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 $4.7 million and $(15.6) million for the three months ended June 30, 2014 and 2013, respectively.


²	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 $0.1 million and $(14.2) million for the six months ended June 30, 2014 and 2013, respectively.


³	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 June 30, 2014:




	Fair Value						Range
(Dollars in Thousands)	Assets ¹		Liabilities ¹		Valuation Technique	Unobservable Input	Low	High	Weighted Average
Electric	$	11,020	$	15,713	Discounted cash flow	Power Prices	$19.08 per MWh	$44.36 per MWh	$35.77 per MWh
Natural gas	$	2,825	$	3,098	Discounted cash flow	Natural Gas Prices	$3.84 per MMBtu	$4.09 per MMBtu	$4.02 per MMBtu

__________


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

Below are the forward price ranges for the Company's purchased commodity contracts, as of December 31, 2013:




	Fair Value						Range
(Dollars in Thousands)	Assets ¹		Liabilities ¹		Valuation Technique	Unobservable Input	Low	High	Weighted Average
Electric	$	3,818	$	19,239	Discounted cash flow	Power Prices	$17.06 per MWh	$47.09 per MWh	$38.74 per MWh
Natural gas	$	2,673	$	3,034	Discounted cash flow	Natural Gas Prices	$3.62 per MMBtu	$4.19 per MMBtu	$3.78 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 June 30, 2014 and December 31, 2013, 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 $8.7 million and $7.0 million, respectively.


(5)	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. PSE also maintains a non-qualified Supplemental Executive Retirement Plan (SERP) for its key senior management employees.

In addition to providing pension benefits, PSE provides group health care and life insurance benefits for certain retired employees. These benefits are provided principally through an insurance company. The insurance premiums, paid primarily by retirees, are based on the benefits provided during the year.

The 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 and six months ended June 30, 2014 and 2013:



Puget Energy	Qualified Pension Benefits						SERP Pension Benefits					Other Benefits
	Three Months Ended June 30,
(Dollars in Thousands)	2014			2013			2014		2013			2014			2013
Components of net periodic benefit cost:
Service cost	$	4,206		$	4,934		$	261	$	375		$	26		$	32
Interest cost	6,965			6,182			577		511			159			155
Expected return on plan assets	(10,511		)	(9,696		)	—		—			(134		)	(109		)
Amortization of prior service cost	(495		)	(495		)	11		(4		)	—			—
Amortization of net loss (gain)	—			794			228		365			(130		)	18
Net periodic benefit cost	$	165		$	1,719		$	1,077	$	1,247		$	(79	)	$	96




Puget Energy	Qualified Pension Benefits						SERP Pension Benefits					Other Benefits
	Six Months Ended June 30,
(Dollars in Thousands)	2014			2013			2014		2013			2014			2013
Components of net periodic benefit cost:
Service cost	$	8,718		$	9,643		$	521	$	749		$	56		$	67
Interest cost	14,020			12,377			1,155		1,022			342			332
Expected return on plan assets	(21,232		)	(19,548		)	—		—			(267		)	(218		)
Amortization of prior service cost	(990		)	(990		)	22		(9		)	(197		)	—
Amortization of net loss (gain)	—			1,444			456		731			—			34
Net periodic benefit cost	$	516		$	2,926		$	2,154	$	2,493		$	(66	)	$	215



Puget Sound Energy	Qualified						SERP					Other
	Pension Benefits						Pension Benefits					Benefits
	Three Months Ended June 30,
(Dollars in Thousands)	2014			2013			2014		2013			2014			2013
Components of net periodic benefit cost:
Service cost	$	4,206		$	4,934		$	261	$	375		$	26		$	32
Interest cost	6,965			6,182			577		511			159			155
Expected return on plan assets	(10,708		)	(10,094		)	—		—			(134		)	(109		)
Amortization of prior service cost	(393		)	(393		)	11		(4		)	1			8
Amortization of net loss (gain)	3,359			5,221			365		548			(208		)	(108		)
Net periodic benefit cost	$	3,429		$	5,850		$	1,214	$	1,430		$	(156	)	$	(22	)



Puget Sound Energy	Qualified						SERP					Other
	Pension Benefits						Pension Benefits					Benefits
	Six Months Ended June 30,
(Dollars in Thousands)	2014			2013			2014		2013			2014			2013
Components of net periodic benefit cost:
Service cost	$	8,718		$	9,643		$	521	$	749		$	56		$	67
Interest cost	14,020			12,377			1,155		1,022			342			332
Expected return on plan assets	(21,626		)	(20,343		)	—		—			(267		)	(218		)
Amortization of prior service cost	(786		)	(787		)	22		(8		)	2			14
Amortization of net loss (gain)	6,597			10,306			730		1,096			(352		)	(142		)
Net periodic benefit cost	$	6,923		$	11,196		$	2,428	$	2,859		$	(219	)	$	53

The following table summarizes the Company’s change in benefit obligation for the periods ended June 30, 2014 and December 31, 2013:



Puget Energy and Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
	Six Months Ended			Year Ended			Six Months Ended			Year Ended			Six Months Ended			Year Ended
(Dollars in Thousands)	June 30, 2014			December 31, 2013			June 30, 2014			December 31, 2013			June 30, 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	8,718			19,285			521			1,498			56			134
Interest cost	14,020			24,754			1,155			2,045			342			664
Amendment	—			—			—			478			—			—
Actuarial Net loss/(gain) BOY Census, remeasurement	1,878			(48,559		)	—			(1,687		)	(932		)	(2,240		)
Benefits paid	(25,408		)	(38,453		)	(942		)	(6,850		)	(739		)	(1,536		)
Medicare part D subsidy received	—			—			—						117			245
Benefit obligation at end of period	$	572,525		$	573,317		$	48,013		$	47,279		$	13,783		$	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 $0.3 million, respectively. During the three months ended June 30, 2014, the Company contributed $3.0 million, $0.5 million, and $0.1 million to fund the qualified pension plan, SERP and the other postretirement plan, respectively. During the six months ended June 30, 2014, the Company contributed $6.0 million, $0.9 million, and $0.3 million to fund the qualified pension plan, SERP and the other postretirement plan, respectively.


(6)	Regulation and Rates

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 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.

On April 24, 2014, the Washington Commission also approved PSE’s request to change rates under its electric and natural gas conservation riders, effective May 1, 2014. The rate change incorporated the effects of changes in the annual conservation budgets as well as true-ups to the rate from the prior year. The rate change represents a rate increase for electric of $12.2 million, or 0.5% annually, and a rate increase for natural gas of $0.3 million.

On May 23, 2014, PSE filed its 2014 power cost only rate case (PCORC). The filing proposes a decrease of $9.6 million (or an average of approximately 0.5%) in the Company's overall power supply costs with an effective date of December 1, 2014.

On May 30, 2014, PSE filed a rate change under its natural gas cost recovery mechanism (CRM). The purpose of the CRM filing was to submit a tariff filing to recover the incremental cost of investments made under PSE’s approved Pipeline Replacement Program Plan (PRPP). This filing will be subsequently updated for actual investments to coincide with the requested recovery period of November 1, 2013, through October 31, 2014.

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 were held on May 9, 2014. On June 25, 2014, the court issued a letter decision in which it affirmed the attrition adjustment (escalating factors referred to as the K-Factor) and the Washington Commission's decision not to consider the case as a general rate case, but reversed and remanded the cost of equity for further adjudication consistent with the court's decision.

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.


(7)	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 are pursuing certain claims relating to the amount of REP benefits paid to utilities, including PSE, for the period of fiscal years 2002 through 2011. 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 during the period June 1, 2014 to May 31, 2015.

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 $1.29 million and $1.38 million relating to these claims as of June 30, 2014 and December 31, 2013, respectively.


(8)	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 and six months ended June 30, 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 March 31, 2014	$	48,305		$	(358	)	$	—	$	47,947
Other comprehensive income (loss) before reclassifications	(615		)	—			—		(615		)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	(168		)	—			—		(168		)
Net current-period other comprehensive income (loss)	(783		)	—			—		(783		)
Balance at June 30, 2014	$	47,522		$	(358	)	$	—	$	47,164



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	(615		)	—			—			(615		)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	(377		)	347			94			64
Net current-period other comprehensive income (loss)	(992		)	347			94			(551		)
Balance at June 30, 2014	$	47,522		$	(358	)	$	—		$	47,164



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 March 31, 2014	$	(85,404	)	$	(1,309	)	$	(6,228	)	$	(92,941	)
Other comprehensive income (loss) before reclassifications	(615		)	—			—			(615		)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	2,039			—			79			2,118
Net current-period other comprehensive income (loss)	1,424			—			79			1,503
Balance at June 30, 2014	$	(83,980	)	$	(1,309	)	$	(6,149	)	$	(91,438	)



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	(615		)	—			—			(615		)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	4,040			718			158			4,916
Net current-period other comprehensive income (loss)	3,425			718			158			4,301
Balance at June 30, 2014	$	(83,980	)	$	(1,309	)	$	(6,149	)	$	(91,438	)

Details about these reclassifications out of accumulated other comprehensive income (loss) for the three and six months ended June 30, 2014 and three and six months ended June 30, 2013, respectively, are as follows:



Puget Energy		Three Months Ended June 30,						Six Months Ended June 30,
(Dollars in Thousands)		2014			2013			2014			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		$	1,165		$	999
Amortization of net gain (loss)	^(a)	(98		)	(1,177		)	(456		)	(2,209		)
	Total before tax	386			(678		)	709			(1,210		)
	Tax (expense) or benefit	(135		)	237			(248		)	422
	Net of Tax	$	251		$	(441	)	$	461		$	(788	)
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	—			(1,325		)	(144		)	(2,639		)
	Tax (expense) or benefit	—			464			50			924
	Net of Tax	$	—		$	(861	)	$	(94	)	$	(1,715	)
Total reclassification for the period	Net of Tax	$	251		$	(1,302	)	$	20		$	(2,396	)

__________


^(a)	These accumulated OCI components are included in the computation of net periodic pension cost (see Note 5 for additional details).



Puget Sound Energy		Three Months Ended June 30,						Six Months Ended June 30,
(Dollars in Thousands)		2014			2013			2014			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		$	762		$	781
Amortization of net gain (loss)	^(a)	(3,516		)	(5,661		)	(6,975		)	(11,260		)
	Total before tax	(3,135		)	(5,272		)	(6,213		)	(10,479		)
	Tax (expense) or benefit	1,097			1,845			2,175			3,666
	Net of Tax	$	(2,038	)	$	(3,427	)	$	(4,038	)	$	(6,813	)
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		)	(244		)	(244		)
	Tax (expense) or benefit	43			43			86			86
	Net of Tax	$	(79	)	$	(79	)	$	(158	)	$	(158	)
Total reclassification for the period	Net of Tax	$	(2,117	)	$	(3,506	)	$	(4,914	)	$	(8,782	)

__________


^(a)	These accumulated OCI components are included in the computation of net periodic pension cost (see Note 5 for additional details).


(9)	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 maintain such separate accounts and accounting entries as are necessary to preserve fully the Washington Commission’s opportunity to consider in an appropriate proceeding the disposition of proceeds of sale and rate treatment of this transaction. 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 authorizing PSE to retain $45.0 million of the gain and to 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. PSE filed rebuttal testimony and intervenors filed cross-answering testimony on April 22, 2014. The Washington Commission held evidentiary hearings in this matter on May 21, 2014. Initial legal briefs were filed on June 10, 2014 and reply briefs were filed on June 17, 2014. A final order is anticipated in the third quarter of this year.

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.

Credit Facilities

In April 2014, subsequent to the close of the first quarter, the Company completed a one-year extension on the liquidity and hedging facilities of PSE, extending the maturity from February 2018 to April 2019 and updating or clarifying the definitions of other terms and conditions of the facilities from when they were committed in 2013. At this same time, the Company completed an amendment to the senior secured credit facility of Puget Energy, extending the maturity from February 2017 to April 2018, updating the fee structure, eliminating a financial covenant and updating or clarifying the definitions of other terms and conditions of the facility.

Term Loans

In June 2014, Puget Energy entered into three bilateral term loans, with two and three year maturities, which in total, equal $299.0 million . The proceeds of these term loans were used to pay off the outstanding Puget Energy credit facility balance, which subsequently allows the Company to carry the debt with lower interest expense. The terms, conditions and covenants are consistent with each other and the credit facility agreements, with the exception of maturity and price.

Treasury Grants

PSE received two treasury grants in the amount of $107.8 million, related to Baker and Snoqualmie hydro facilities. These grants have been accounted as a reduction to utility plant and will be amortized over the life of the plant based on Washington Commission authorization. The previous treatment of grants by the Washington Commission is to amortize the grants over 10 years instead of the plant life. The grants are also recorded as a regulatory liability due to the 10 year amortization and treatment.

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 payments 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 increase by 3.0% for electric customers and 2.2% for natural gas customers on January 1 of 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 recover 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 requirements and generation resources 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 and six months ended June 30, 2014, as compared to the same periods in 2013, PSE's net income was affected primarily by the following factors: (1) changes in unrealized gain and loss in derivatives instruments for energy contracts; (2) an increase in electric and natural gas margin; and (3) a decrease in other income due to lower regulatory income and interest and dividend income.

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 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. With the implementation of PSE’s electric and gas decoupling mechanisms, which went into effect on July 1, 2013, PSE is able to recover its delivery-system cost based on number of customers as opposed to volumetric sales.

Recent Rate Proceedings

Power Cost Only Rate Case. 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.

On May 23, 2014, PSE filed its 2014 PCORC. The filing proposes a decrease of $9.6 million (or an average of approximately 0.5%) in the Company's overall power supply costs with an effective date of December 1, 2014.

Expedited Rate Filing. On February 4, 2013, PSE filed revised tariffs seeking to update its rates established in its base rate proceedings in May 2012. This filing, known as 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 payments 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 its customers share 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 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 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 were held on May 9, 2014. On June 25, 2014, the court issued a letter decision in which it affirmed the attrition adjustment (escalating factors referred to as the K-Factor) and the Washington Commission's decision not to consider the case as a general rate case, but reversed and remanded the cost of equity for further adjudication consistent with the court's decision.

Other Proceedings. 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.

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 a favorable PCA imbalance for the three months ended June 30, 2014, which was $0.6 million below the “power cost baseline” level, of which no amount was apportioned to customers. PSE had an unfavorable PCA imbalance for the six months ended June 30, 2014 which was $18.5 million above the "power cost baseline" level, of which no amount was apportioned to customers. This compares to a favorable imbalance for the three and six months ended June 30, 2013 of $23.7 million and $39.0 million, respectively, of which $9.5 million was apportioned to customers.

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)
Conservation Rider	May 1, 2014	0.5	%	$	12.2
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 Decoupling filing by 3.0% for electric customers on January 1 of each year until the conclusion of PSE's next general rate case.

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.

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 Decoupling 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 six months ended June 30, 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 six months ended June 30, 2014 was 51.68 degrees, or 1.01 degrees warmer than the same period in the prior year, and 1.79 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.

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 was observed to the generator which required repairs to the stator, core and rotor. The unit was returned to service in January 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. As a result of the outage, 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 is $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 on April 2, 2014, which was rejected by the IBEW. PSE extended another offer to the IBEW on June 24, 2014, which PSE believes enables PSE to attract and retain a highly skilled workforce to safely and efficiently perform their duties. The IBEW negotiation committee declined to recommend ratification. The parties met with a federal mediator in July.

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 June 30,								Six Months Ended June 30,
Puget Sound Energy (Dollars in Thousands)	2014			2013			Favorable/ (Unfavorable)		2014			2013			Favorable/ (Unfavorable)
Operating revenue:
Electric
Residential sales	$	237,365		$	246,267		(3.6	)%	$	596,208		$	607,185		(1.8	)%
Commercial sales	200,114			188,162			6.4		429,199			414,118			3.6
Industrial sales	26,887			22,715			18.4		53,922			49,525			8.9
Other retail sales, including unbilled revenue	(21,383		)	(11,714		)	(82.5	)	(46,775		)	(22,996		)	(103.4	)
Total retail sales	442,983			445,430			(0.5	)	1,032,554			1,047,832			(1.5	)
Transportation sales	2,381			2,334			2.0		4,369			4,180			4.5
Sales to other utilities and marketers	6,583			9,156			(28.1	)	20,622			18,142			13.7
Decoupling revenue	13,494			—			*		26,171			—			*
Other	10,139			4,737			*		25,417			6,137			*
Total electric operating revenue	475,580			461,657			3.0		1,109,133			1,076,291			3.1
Gas
Residential sales	109,394			113,159			(3.3	)	374,802			374,343			0.1
Commercial sales	54,408			54,751			(0.6	)	159,177			161,307			(1.3	)
Industrial sales	5,088			5,287			(3.8	)	13,879			15,005			(7.5	)
Total retail sales	168,890			173,197			(2.5	)	547,858			550,655			(0.5	)
Transportation sales	4,180			3,929			6.4		8,445			7,990			5.7
Decoupling revenue	7,306			—			*		8,093			—			*
Other	3,559			3,602			(1.2	)	6,982			6,848			2.0
Total gas operating revenue	183,935			180,728			1.8		571,378			565,493			1.0
Non-utility operating revenue	3,401			101			*		7,780			409			*
Total operating revenue	662,916			642,486			3.2		1,688,291			1,642,193			2.8
Operating expenses:
Energy costs
Purchased electricity	114,627			112,543			(1.9	)	295,785			287,587			(2.9	)
Electric generation fuel	34,795			40,737			14.6		110,232			99,823			(10.4	)
Residential exchange	(23,621		)	(14,963		)	57.9		(53,624		)	(37,515		)	42.9
Purchased gas	76,272			79,487			4.0		267,578			269,470			0.7
Net unrealized (gain) loss on derivative instruments	(17,094		)	27,376			*		(24,364		)	(45,365		)	(46.3	)
Utility operations and maintenance	134,883			130,286			(3.5	)	278,960			259,521			(7.5	)
Non-utility expense and other	5,374			3,028			(77.5	)	11,548			6,120			(88.7	)
Depreciation	92,462			90,301			(2.4	)	183,646			178,480			(2.9	)
Amortization	12,735			6,433			(98.0	)	23,270			12,177			(91.1	)
Conservation amortization	22,526			22,469			(0.3	)	51,508			56,576			9.0
Taxes other than income taxes	67,772			53,695			(26.2	)	168,590			153,638			(9.7	)
Total operating expenses	520,731			551,392			5.6		1,313,129			1,240,512			(5.9	)
Operating income (loss)	142,185			91,094			56.1		375,162			401,681			(6.6	)
Other income	4,621			10,846			(57.4	)	8,860			22,857			(61.2	)
Other expense	(1,644		)	(1,454		)	(13.1	)	(3,226		)	(2,996		)	(7.7	)
Interest expense	(63,987		)	(62,643		)	(2.1	)	(126,997		)	(124,000		)	(2.4	)
Income (loss) before income taxes	81,175			37,843			114.5		253,799			297,542			(14.7	)
Income tax (benefit) expense	23,341			11,180			(108.8	)	74,883			90,941			17.7
Net income (loss)	$	57,834		$	26,663		116.9	%	$	178,916		$	206,601		(13.4	)%

__________


^*	Not meaningful

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 June 30,						Favorable/ (Unfavorable)		Six Months Ended June 30,
(Dollars in Thousands)	2014			2013			Favorable/ (Unfavorable)		2014			2013			Favorable/ (Unfavorable)
Electric operating revenue:
Residential sales	$	237,365		$	246,267		(3.6	)%	$	596,208		$	607,185		(1.8	)%
Commercial sales	200,114			188,162			6.4		429,199			414,118			3.6
Industrial sales	26,887			22,715			18.4		53,922			49,525			8.9
Other retail sales, including unbilled revenues	(21,383		)	(11,714		)	(82.5	)%	(46,775		)	(22,996		)	(103.4	)
Total retail sales	442,983			445,430			(0.5	)	1,032,554			1,047,832			(1.5	)
Transportation sales	2,381			2,334			2.0		4,369			4,180			4.5
Sales to other utilities and marketers	6,583			9,156			(28.1	)	20,622			18,142			13.7
Decoupling revenue	13,494			—			*		26,171			—			*
Other	10,139			4,737			*		25,417			6,137			*
Total electric operating revenues¹	475,580			461,657			3.0		1,109,133			1,076,291			3.1
Minus power costs:
Purchased electricity¹	114,627			112,543			(1.9	)	295,785			287,587			(2.9	)
Electric generation fuel¹	34,795			40,737			14.6		110,232			99,823			(10.4	)
Residential exchange¹	(23,621		)	(14,963		)	57.9		(53,624		)	(37,515		)	42.9
Total electric power costs	125,801			138,317			9.0		352,393			349,895			(0.7	)
Electric margin²	$	349,779		$	323,340		8.2	%	$	756,740		$	726,396		4.2	%

______________


^*	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.

Electric margin increased $26.4 million and $30.3 million, or 8.2% and 4.2%, to $349.8 million and $756.7 million from $323.3 million and $726.4 million for the three and six months ended June 30, 2014, respectively, as compared to the same periods 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 operating revenues increased $13.9 million, or 3.0%, to $475.6 million from $461.7 million for the three months ended June 30, 2014 as compared to the same period in 2013. The increase in operating revenues was primarily due to higher miscellaneous operating revenues of $5.4 million and decoupling revenue related to under-collection of $13.5 million. The increase was partially offset by lower sales to other utilities and marketers of $2.6 million and electric retail sales of $2.4 million. These items are discussed in more detail below.

Electric operating revenues increased $32.8 million, or 3.1%, to $1,109.1 million from $1,076.3 million for the six months ended June 30, 2014 as compared to the same period in 2013. The increase in operating revenues was primarily due to higher decoupling revenue related to under-collection of $26.2 million, miscellaneous operating revenues of $19.3 million, and higher sales to other utilities and marketers of $2.5 million. The increase was partially offset by lower electric retail sales of $15.3 million. These items are discussed in more detail below.

Electric retail sales decreased $2.4 million, or 0.5%, to $443.0 million from $445.4 million for the three months ended June 30, 2014 as compared to the same period in 2013. The decrease in electric retail sales primarily resulted from a revenue decrease of $8.0 million due to lower retail electricity usage of 84,038 MWhs, or 1.8% during the three months ended June 30, 2014 as compared to the same period in the prior year. The decrease was offset by a net revenue increase of $5.5 million due to the rate increase primarily related to PSE's ERF and decoupling rate increase which became effective on July 1, 2013.

Electric retail sales decreased $15.3 million, or 1.5%, to $1,032.6 million from $1,047.8 million for the six months ended June 30, 2014 as compared to the same period in 2013. The decrease in electric retail sales primarily resulted from a revenue decrease of $24.90 million due to lower retail electricity usage of 253,478 MWhs, or 2.4% during the six months ended June 30, 2014 as compared to the same period in the prior year. The decrease was offset by a net revenue increase of $9.6 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 marketers decreased $2.6 million, or 28.1%, to $6.6 million from $9.2 million for the three months ended June 30, 2014 as compared to the same period in 2013. The decrease was primarily driven by a decrease of $2.3 million due to lower wholesale price for the three months ended June 30, 2014.

Sales to other utilities and marketers increased $2.5 million, or 13.7%, to $20.6 million from $18.1 million for the six months ended June 30, 2014 as compared to the same period in 2013. The increase was primarily driven by an increase of $2.6 million due to higher wholesale electricity prices.

Decoupling revenues of $13.5 million and $26.2 million were recorded for the three and six months ended June 30, 2014, respectively, due to lower volumetric revenues compared to the allowed decoupled revenues per customer. The decoupling revenue or liability will be recovered from or passed back to customers through a future rate filing beginning May 1, 2015.

Other electric operating revenue increased $5.4 million to $10.1 million from $4.7 million for the three months ended June 30, 2014 as compared to the same period in 2013. The increase was primarily the result of an increase of $1.5 million due to higher non-core gas sales and an increase of $3.1 million due to higher miscellaneous electric revenue for the three months ended June 30, 2014.

Other electric operating revenue increased $19.3 million to $25.4 million from $6.1 million for the six months ended June 30, 2014 as compared to the same period in 2013. The increase was primarily the result of an increase of $10.5 million due to higher non-core gas sales and an increase of $7.6 million due to higher miscellaneous electric revenue.

Electric Energy Costs

Purchased electricity expense increased $2.1 million, or 1.9%, to $114.6 million from $112.5 million for the three months ended June 30, 2014 as compared to the same period in 2013. The increase was primarily the result of a $9.5 million increase related to higher energy purchases for the three months ended June 30, 2014. Also contributing to the increase was an increase of $3.7 million in transmission expense. The increase was partially offset by $1.8 million 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.

Purchased electricity expense increased $8.2 million, or 2.9%, to $295.8 million from $287.6 million for the six months ended June 30, 2014 as compared to the same period in 2013. The increase was primarily the result of a $12.0 million increase primarily related to higher energy purchases for the six months ended June 30, 2014. Also contributing to the increase was an increase of $7.3 million in transmission expense. The increase was partially offset by $5.9 million 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 decreased $5.9 million, or 14.6%, to $34.8 million from $40.7 million for the three months ended June 30, 2014 as compared to the same period in 2013. The decrease was primarily due to a $6.1 million decrease in fuel expense at PSE's combustion turbine facilities primarily due to lower volumes of electricity generation from PSE's combustion turbine facilities as a result of increases in hydroelectric and wind generation of 194,912 MWhs, or 11.1%, for the three months ended June 30, 2014 as compared to the same period in 2013.

Electric generation fuel expense increased $10.4 million, or 10.4%, to $110.2 million from $99.8 million for the six months ended June 30, 2014 as compared to the same period in 2013. The increase was primarily due to a $10.7 million increase in fuel expense at PSE's combustion turbine facilities.

Residential exchange credits increased $8.7 million, or 57.9%, to $23.6 million from $15.0 million for the three months ended June 30, 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. An additional $62.9 million of REP benefit will be provided to customers between June 1, 2014 and May 31, 2015.

Residential exchange credits increased $16.1 million, or 42.9%, to $53.6 million from $37.5 million for the six months ended June 30, 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.

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 June 30,				Favorable/ (Unfavorable)		Six Months Ended June 30,
(Dollars in Thousands)	2014		2013		Favorable/ (Unfavorable)		2014		2013		Favorable/ (Unfavorable)
Gas operating revenue:
Residential sales	$	109,394	$	113,159	(3.3	)%	$	374,802	$	374,343	0.1	%
Commercial sales	54,408		54,751		(0.6	)	159,177		161,307		(1.3	)
Industrial sales	5,088		5,287		(3.8	)	13,879		15,005		(7.5	)
Total retail sales	168,890		173,197		(2.5	)	547,858		550,655		(0.5	)
Transportation sales	4,180		3,929		6.4		8,445		7,990		5.7
Decoupling revenue	7,306		—		*		8,093		—		*
Other	3,559		3,602		(1.2	)	6,982		6,848		2.0
Total gas operating revenues¹	183,935		180,728		1.8		571,378		565,493		1.0
Minus purchased gas costs¹	76,272		79,487		4.0		267,578		269,470		0.7
Natural gas margin²	$	107,663	$	101,241	6.3	%	$	303,800	$	296,023	2.6	%

______________


^*	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 $6.4 million and $7.8 million, or 6.3% and 2.6%, to $107.7 million and $303.8 million from $101.2 million and $296.0 million for the three and six months ended June 30, 2014, respectively, as compared to the same periods 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 revenues increased $3.2 million and $5.9 million, or 1.8% and 1.0%, to $183.9 million and $571.4 million from $180.7 million and $565.5 million for the three and six months ended June 30, 2014, respectively, as compared to the same periods in 2013. The increase for the three and six months ended June 30, 2014 was due primarily to an increase in decoupling revenue that was partially offset by a decrease in natural gas retail sales, as discussed in more detail below.

Decoupling revenues of $7.3 million and $8.1 million were recorded for the three and six months ended June 30, 2014, respectively, due to lower volumetric revenues compared to the allowed decoupled revenues per customer. The decoupling revenue or liability will be recovered from or passed back to customers through a future rate filing beginning May 1, 2015.

Natural gas retail sales decreased $4.3 million, or 2.5%, to $168.9 million from $173.2 million for the three months ended June 30, 2014 as compared to the same period in 2013. The decrease was primarily due to a decrease of $8.3 million, or 4.8%, in natural gas therm sales and offset by the result of a net revenue increase of $4.0 million for the three months ended June 30, 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.

Natural gas retail sales decreased $2.8 million, or 0.5%, to $547.9 million from $550.7 million for the six months ended June 30, 2014 as compared to the same period in 2013. The decrease was primarily due to a decrease of $8.1 million, or 1.5%, in natural gas therm sales and offset by the result of a net revenue increase of $5.3 million for the six months ended June 30, 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 gas expenses decreased $3.2 million, or 4.0%, to $76.3 million from $79.5 million for the three months ended June 30, 2014 as compared to the same period in 2013. The decrease was primarily due to a reduction in customer usage of 4.8% and partially offset by higher natural gas costs reflected in PGA rates effective November 1, 2013 for the three months ended June 30, 2014 as compared to the same period in 2013.

Purchased gas expenses decreased $1.9 million, or 0.7%, to $267.6 million from $269.5 million for the six months ended June 30, 2014 as compared to the same period in 2013. The decrease was primarily due to a reduction in customer usage of 1.5% and partially offset by higher natural gas costs reflected in PGA rates effective November 1, 2013 for the six months ended June 30, 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 receivable balance at June 30, 2014 was $12.5 million.

Non-utility Operating Revenue

Non-utility operating revenue increased $3.3 million to $3.4 million from $0.1 million for the three months ended June 30, 2014 as compared to the same period in 2013. The increase was primarily driven by $3.2 million revenue related to PSE's Biogas sales during the three months ended June 30, 2014.

Non-utility operating revenue increased $7.4 million to $7.8 million from $0.4 million for the six months ended June 30, 2014 as compared to the same period in 2013. The increase was primarily driven by $7.2 million revenue related to PSE's Biogas sales during the six months ended June 30, 2014.

Other Operating Expenses

Net unrealized gain on derivative instruments increased $44.5 million to a gain of $17.1 million from a loss of $27.4 million for the three months ended June 30, 2014 as compared to the same period in 2013. The net gain during the three months ended June 30, 2014 was due to a gain of $20.0 million related to PSE's electric derivative instruments and a loss of $2.9 million related to natural gas derivative instruments. This compares to losses of $6.0 million and $21.4 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.

Net unrealized gain on derivative instruments decreased $21.0 million to $24.4 million from $45.4 million for the six months ended June 30, 2014 as compared to the same period in 2013. The net gain during the six months ended June 30, 2014 was due to a gain of $12.5 million related to PSE's natural gas derivative instruments and a gain of $11.9 million related to electric derivative instruments. This compares to gains of $43.3 million and $2.1 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 maintenance expense increased $4.6 million, or 3.5%, to $134.9 million from $130.3 million for the three months ended June 30, 2014 as compared to the same period in 2013. The increase was primarily driven by an increase of $5.6 million in customer service expenses, mostly related to uncollectible accounts expense, and an increase of $0.9 million in electric transmission & distribution expenses. The increase was offset by a decrease of $1.4 million in production operations and

maintenance expenses, $0.5 million in administrative & general expense and $0.4 million in gas operations expense, for the three months ended June 30, 2014.

Utility operations and maintenance expense increased $19.4 million, or 7.5%, to $279.0 million from $259.5 million for the six months ended June 30, 2014 as compared to the same period in 2013. The increase was primarily driven by an increase of $11.1 million in customer service expenses, mostly related to uncollectible accounts expense, an increase of $8.5 million in electric transmission & distribution expenses, and an increase of $0.9 million in low income program expenses. Additionally, offsetting the increase was a decrease of $1.0 million in administrative & general expenses for the six months ended June 30, 2014.

Non-utility operations and maintenance expense increased $2.3 million to $5.4 million from $3.0 million for the three months ended June 30, 2014 as compared to the same period in 2013. The increase was primarily driven by an increase of $2.6 million in expense related to PSE's Biogas sales during the three months ended June 30, 2014.

Non-utility operations and maintenance expense increased $5.4 million to $11.5 million from $6.1 million for the six months ended June 30, 2014 as compared to the same period in 2013. The increase was primarily driven by an increase of $5.6 million in expense related to PSE's Biogas sales during the six months ended June 30, 2014.

Depreciation expense increased $2.2 million and $5.2 million, or 2.4% or 2.9%, to $92.5 million and $183.6 million from $90.3 million and $178.5 million for the three and six months ended June 30, 2014 as compared to the same period in 2013. The increase was primarily due to electric depreciation in the amount of $7.2 million caused by additional capital expenditures placed into service, net of retirements, such as Snoqualmie Falls and Baker hydroelectric generating facility projects, which went into service in July 2013. Gas depreciation also increased in the amount of $1.6 million, mainly due to new additions. The increase was offset by a decrease of $3.7 million in common utility plant depreciation, mainly due to the retirement of computer equipment since June 2013.

Amortization expense increased $6.3 million, or 98.0%, to $12.7 million from $6.4 million for the three months ended June 30, 2014 as compared to the same period in 2013. The increase was due to a reduction in regulatory credits of $4.8 million for the three months ended June 30, 2014 mainly related to Ferndale and Snoqualmie fixed costs. Also contributing to the increase was the deferral of generating plants fixed costs of $1.6 million for the three months ended June 30, 2014.

Amortization expense increased $11.1 million, or 91.1%, to $23.3 million from $12.2 million for the six months ended June 30, 2014 as compared to the same period in 2013. The increase was due to a reduction in regulatory credits of $4.5 million for the six months ended June 30, 2014 mainly related to Ferndale and Snoqualmie fixed costs. Also contributing to the increase was $3.2 million of non-PTC regulatory debits and a $3.1 million increase related to CIS project additions related to new computer software which was amortized over the six months ended June 30, 2014.

Conservation amortization decreased $5.1 million, or 9.0%, to $51.5 million from $56.6 million for the six months ended June 30, 2014 as compared to the same period in 2013. The decrease was primarily due to a decrease of $7.5 million in gas conservation amortization, net of the increase of $2.4 million in electric conservation amortization for the six months ended June 30, 2014.

Taxes other than Income Tax increased $14.1 million, or 26.2%, to $67.8 million from $53.7 million for the three months ended June 30, 2014 as compared to the same period in 2013. The increase was primarily due to property and municipal tax for electric utilities of $12.3 million, along with property and municipal tax for gas utilities of $1.7 million for the three months ended June 30, 2014.

Taxes other than Income Tax increased $15.0 million, or 9.7%, to $168.6 million from $153.6 million for the six months ended June 30, 2014 as compared to the same period in 2013. The increase was primarily due to property and municipal tax for electric utilities of $10.4 million, along with property and municipal tax for gas utilities of $4.0 million for the six months ended June 30, 2014.

Other Income and Income Tax Expense

Other income decreased $6.2 million, or 57.4%, to $4.6 million from $10.8 million for the three months ended June 30, 2014, as compared to the same period in 2013. The decrease was primarily due to a decrease of $2.7 million in Allowance for Funds Used During Construction (AFUDC) income mostly related to the decrease in average construction work in process, a decrease of $1.3 million in life insurance gain, and a decrease of $1.8 million in interest income for the three months ended June 30, 2014, as compared to the same period in 2013.

Other income decreased $14.0 million, or 61.2%, to $8.9 million from $22.9 million for the six months ended June 30, 2014, as compared to the same period in 2013. The decrease was primarily due to a decrease of $7.8 million in AFUDC income mostly related to the decrease in average construction work in process, a decrease of $0.8 million in life insurance gain, and a decrease of $5.1 million in interest income for the six months ended June 30, 2014, as compared to the same period in 2013.

Income tax expense increased $12.2 million, or 108.8%, to $23.3 million from $11.2 million for the three months ended June 30, 2014 as compared to the same period in 2013, primarily due to higher federal income tax due to higher pre-tax income largely resulting from higher gains on unrealized derivative instruments.

Income tax expense decreased $16.1 million, or 17.7%, to $74.9 million from $90.9 million for the six months ended June 30, 2014 as compared to the same period in 2013, due to lower federal income tax and lower pre-tax income largely resulting from lower gains on unrealized derivative instruments, and higher utility operations and maintenance costs.

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 and six months ended June 30, 2014 and the same periods in 2013 are as follows:



Benefit/(Expense)	Three Months Ended June 30,						Percent Change		Six Months Ended June 30,
(Dollars in Thousands)	2014			2013			Percent Change		2014			2013			Percent Change
PSE net income	$	57,834		$	26,663		116.9	%	$	178,916		$	206,601		(13.4	)%
Other operating revenue	—			—			*		—			111			*
Net unrealized gain on energy derivative instruments	—			—			*		570			2,952			(80.7	)
Non-utility expense and other	3,081			3,986			(22.7	)	5,836			8,071			(27.7	)
Other income	1			1			—		1			1			—
Unhedged interest rate swap (expense) income	(1,360		)	1,232			*		(2,107		)	2,260			*
Interest expense ¹	(26,625		)	(43,113		)	38.2		(52,715		)	(72,923		)	27.7
Income tax benefit (expense)	8,182			12,136			(32.6	)	18,204			21,307			(14.6	)
Puget Energy net income (loss)	$	41,113		$	905		4,442.9	%	$	148,705		$	168,380		(11.7	)%

__________


^*	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 and six months ended June 30, 2014 was $41.1 million and $148.7 million with operating revenue of $662.9 million and $1.7 billion as compared to a net income of $0.9 million and $168.4 million with operating revenue of $642.5 million and $1.6 billion for the same period in 2013. Other than the items discussed above regarding PSE, which also impacted Puget Energy's net income, interest expense was also a significant factor that impacted Puget Energy's net income.

Interest expense decreased $16.5 million, or 38.2%, to $26.6 million from $43.1 million for the three months ended June 30, 2014 as compared to the same period in 2013. The decrease for the three months ended June 30, 2014 was primarily due to a reduction of $3.0 million in mark-to-market gains on hedged interest rate swap contracts, and 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 during the second quarter of 2013; and the commitment fees and spreads were reduced due to rating upgrade in the first quarter of 2014.

Interest expense decreased $20.2 million, or 27.7%, to $52.7 million from $72.9 million for the six months ended June 30, 2014 as compared to the same period in 2013. The decrease for the six months ended June 30, 2014 was primarily due to a reduction of $1.0 million in mark-to-market gains on hedged interest rate swap contracts, and a decrease of $2.0 million in interest expense related to Puget Energy's revolving senior secured credit facility as its balance was reduced by $80.0 million during the third quarter of 2013; 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.

The following are PSE’s and Puget Energy’s aggregate availability under commercial commitments as of June 30, 2014:



	Amount of Available Commitments Expiration Per Period
Commercial Commitments (Dollars in Thousands)	Total			2014		2015-2017		2018-2019		Thereafter
PSE liquidity facility ¹	$	650,000		$	—	$	—	$	650,000	$	—
PSE energy hedging facility ¹	350,000			—		—		350,000		—
Inter-company short-term debt ²	1,067			—		—		—		1,067
Total PSE commercial commitments	$	1,001,067		$	—	$	—	$	1,000,000	$	1,067
Puget Energy revolving credit facility ³	800,000			—		—		800,000		—
Less: Inter-company short-term debt elimination ²	(1,067		)	—		—		—		(1,067		)
Total Puget Energy commercial commitments	$	1,800,000		$	—	$	—	$	1,800,000	$	—

_____________

As of June 30, 2014, PSE had credit facilities totaling $1.0 billion and no amount had been drawn. These facilities consisted of a $650.0 million liquidity facility to fund operating expenses and serve as a backstop to the Company's commercial paper program, and a $350.0 million hedging facility 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 June 30, 2014, no letters of credit were 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 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 June 30, 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$28.9 million was drawn.

On June 30, 2014, Puget Energy repaid in full the $299.0 million drawn under the $800.0 million revolving credit facility with proceeds from the issuance of three separate term loan agreements. The revolving credit agreement is syndicated among numerous lenders. 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, 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 $217.4 million for the six months ended June 30, 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	$	649,230	$	622,476

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 six months ended June 30, 2014 increased by $67.1 million from $491.4 million generated during the same period in 2013. The increase in cash flow was primarily the result of an increase in cash related to accounts receivable of $70.1 million, partially offset by a net decrease in cash related to regulatory assets and liabilities of $20.9 million.

Net income decreased by $27.7 million and non-cash items increased by $51.8 million primarily related to an increase in unbilled revenue of $27.8 million and an increase in fair value adjustment of derivative instruments of $21.0 million.

Puget Energy

Cash generated from operations for the six months ended June 30, 2014 was $517.2 million, an increase of $47.9 million from the $469.3 million generated during the six months ended June 30, 2013. The net increase was positively impacted by $67.6 million from cash provided by the operating activities of PSE, as previously discussed, and slightly offset by a decrease in other long term liabilities. 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 six months ended June 30, 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.

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, and updating or clarifying the definitions of other terms and conditions of the facilities 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 transact with affiliates, make asset dispositions and investments or permit liens to exist. 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 June 30, 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 June 30, 2014, no amount was drawn and outstanding under either PSE's $650.0 million liquidity facility or the $350.0 million energy hedging facility. No letters of credit were outstanding under either 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 June 30, 2014, $28.9 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 June 30, 2014, Puget Energy maintained an $800.0 million revolving senior secured credit facility. In April, 2014, subsequent to the quarter close, the Company completed an amendment to the senior secured credit facility, extending the maturity from February 2017 to April 2018, updating the fee structure, eliminating a financial covenant and updating or clarifying the definitions of other terms and conditions of the facility. The Puget 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 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 June 30, 2014, there was no amount 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 or similar variable rate debt (see Note 3 and the "Interest Rate Risk" section in Item 3).

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 June 30, 2014, Puget Energy was in compliance with all applicable covenants.

Term Loans

In June 2014, Puget Energy entered into three bilateral term loans, with two and three year maturities, which in total, equal $299.0 million. The proceeds of the term loans were used to pay off the outstanding Puget Energy credit facility balance, which subsequently allows the Company to carry the debt with lower interest expense. All other terms, conditions and covenants are consistent with each other and the credit facility agreements, with the exception of maturity and price.

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 June 30, 2014, approximately $429.0 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 48.1% at June 30, 2014 and the EBITDA to interest expense was 4.5 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 3.1 to one for the twelve months ended June 30, 2014.

At June 30, 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 June 30, 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 June 30, 2014; and

•

Approximately $299.0 million of additional first mortgage bonds under PSE's natural gas mortgage indenture based on approximately $424.5 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 June 30, 2014.

At June 30, 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 June 30, 2014.

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.

New Accounting Pronouncements

For the discussion of new accounting pronouncements, see Note 2 of the notes to the consolidated financial statements.

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.

EPA Draft Rule 111(d)

On June 2, 2014, the EPA issued a proposed rule under Section 111(d) of the Clean Air Act designed to regulate greenhouse gas emissions from existing power plants. The proposed rule includes state-specific goals and guidelines for states to develop plans for meeting these goals. Comments on the proposed rule are due by October 16, 2014. PSE is reviewing this proposed rule and is working with key stakeholders to monitor it as it moves forward towards possible final implementation. However, PSE cannot yet provide a determination of how the final rule, if any, may impact PSE or its existing generation facilities.

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 75% 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)	June 30, 2014				December 31, 2013
	Assets		Liabilities		Assets		Liabilities
Electric portfolio:
Current	$	22,925	$	9,304	$	14,565	$	17,731
Long-term	3,977		10,963		3,914		19,581
Total electric derivatives	$	26,902	$	20,267	$	18,479	$	37,312
Natural Gas portfolio:
Current	$	21,479	$	7,591	$	4,302	$	23,734
Long-term	3,702		5,245		3,819		11,942
Total natural gas derivatives	$	25,181	$	12,836	$	8,121	$	35,676
Total energy derivatives	$	52,083	$	33,103	$	26,600	$	72,988

At June 30, 2014, the Company had total assets of $52.1 million and total liabilities of $33.1 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 June 30, 2014, of natural gas and electricity would change the fair value of the Company's derivative contracts by $39.0 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 3 and 4 to the consolidated financial statements.

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.

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 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. 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.

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 June 30, 2014, PSE held approximately $572.7 million in standby letters of credit or limited parental guarantees, and had seven counterparties with unlimited parental guarantees, in support of outstanding transactions.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 June 30, 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 June 30, 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 June 30, 2014, Puget Energy had two interest rate swap contracts outstanding and PSE did not have any outstanding interest rate swap instruments.

At June 30, 2014, the fair value of the interest rate swaps was a $12.3 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 June 30, 2014, would change the fair value of Puget Energy's interest rate swaps by $0.9 million.

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



Puget Energy (Dollars in Thousands)	June 30, 2014		December 31, 2013
	Liabilities		Liabilities
Interest rate swaps:
Current	$	6,795	$	6,584
Long-term	5,554		6,639
Total interest rate swaps	$	12,349	$	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 June 30, 2014 was a net loss of $6.1 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 June 30, 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 June 30, 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 June 30, 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

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 June 30, 2014. Litigation is subject to numerous uncertainties and PSE is unable to predict the ultimate outcome of these matters.

Item 1A. Risk Factors

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

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:	July 30, 2014	Officer duly authorized to sign this report on behalf of each registrant

EXHIBIT INDEX

As permitted under Item 601(b) (4) (iii) (A) of Regulation S-K, instruments defining the rights of holders of unregistered long-term debt term loans of less than 10 percent of the total consolidated assets of Puget Energy and its subsidiaries, have been omitted and Puget Energy agrees to furnish a copy of such instruments to the Securities and Exchange Commission upon request.



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).
12.1*	Statement setting forth computation of ratios of earnings to fixed charges of Puget Energy, Inc. (2009 through 2013 and 12 months ended June 30, 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 June 30, 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 June 30, 2014, filed on July 30, 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.