Edgar Filing: PUGET ENERGY INC /WA

10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

For the quarterly period ended September 30, 2015



[ ]	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 Information	5

Item 1.	Financial Statements	5
	Puget Energy, Inc.
	Consolidated Statements of Income – Three and Nine Months Ended September 30, 2015 and 2014	5
	Consolidated Statements of Comprehensive Income – Three and Nine Months Ended September 30, 2015 and 2014	6
	Consolidated Balance Sheets – September 30, 2015 and December 31, 2014	7
	Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2015 and 2014	8

	Puget Sound Energy, Inc.
	Consolidated Statements of Income – Three and Nine Months Ended September 30, 2015 and 2014	9
	Consolidated Statements of Comprehensive Income – Three and Nine Months Ended September 30, 2015 and 2014	10
	Consolidated Balance Sheets – September 30, 2015 and December 31, 2014	11
	Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2015 and 2014	13

	Notes
	Combined Notes to Consolidated Financial Statements	14

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	34

Item 3.	Quantitative and Qualitative Disclosure About Market Risk	50

Item 4.	Controls and Procedures	51

Part II.	Other Information	52

Item 1.	Legal Proceedings	52

Item 1A.	Risk Factors	52

Item 6.	Exhibits	52

Signatures		53

Exhibit Index		54

DEFINITIONS



AOCI	Accumulated Other Comprehensive Income
ARO	Asset Retirement and Environmental Obligations
ASU	Accounting Standards Update
ASC	Accounting Standards Codification
EBITDA	Earnings Before Interest, Tax, Depreciation and Amortization
ERF	Expedited Rate Filing
FASB	Financial Accounting Standards Board
GAAP	U.S. Generally Accepted Accounting Principles
GRC	General Rate Case
ISDA	International Swaps and Derivatives Association
LIBOR	London Interbank Offered Rate
MMBtu	One Million British Thermal Units
MWh	Megawatt Hour (one MWh equals one thousand kWh)
NAESB	North American Energy Standards Board
NPNS	Normal Purchase Normal Sale
PCA	Power Cost Adjustment
PCORC	Power Cost Only Rate Case
PGA	Purchased Gas Adjustment
PSE	Puget Sound Energy, Inc.
Puget Energy	Puget Energy, Inc.
Puget 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 (PTCs) 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, the availability of insurance for certain specific losses, 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 September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Operating revenue:
Electric	$	482,786		$	468,530		$	1,526,029		$	1,577,663
Natural gas	119,582			121,402			653,385			692,780
Other	3,365			3,783			11,495			11,563
Total operating revenue	605,733			593,715			2,190,909			2,282,006
Operating expenses:
Energy costs:
Purchased electricity	97,694			67,984			355,645			363,769
Electric generation fuel	76,863			92,510			180,531			202,741
Residential exchange	(19,530		)	(30,963		)	(92,297		)	(84,587		)
Purchased natural gas	46,436			42,550			282,334			310,128
Unrealized (gain) loss on derivative instruments, net	5,588			32,648			(6,339		)	7,714
Utility operations and maintenance	131,208			132,109			400,355			411,068
Non-utility expense and other	1,573			2,911			7,106			8,627
Depreciation and amortization	107,759			105,905			314,348			312,821
Conservation amortization	24,224			23,047			78,389			74,554
Taxes other than income taxes	64,030			59,945			228,942			228,534
Total operating expenses	535,845			528,646			1,749,014			1,835,369
Operating income (loss)	69,888			65,069			441,895			446,637
Other income (deductions):
Other income	4,732			10,956			14,770			19,817
Other expense	(1,621		)	(1,806		)	(4,843		)	(5,032		)
Non-hedged interest rate swap (expense) income	(1,156		)	(323		)	(4,571		)	(2,430		)
Interest charges:
AFUDC	2,102			1,474			5,262			4,189
Interest expense	(88,753		)	(93,258		)	(267,484		)	(275,685		)
Income (loss) before income taxes	(14,808		)	(17,888		)	185,029			187,496
Income tax (benefit) expense	(6,880		)	(4,930		)	51,665			51,749
Net income (loss)	$	(7,928	)	$	(12,958	)	$	133,364		$	135,747

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 September 30,						Nine Months Ended September 30,
	2015			2014			2015		2014
Net income (loss)	$	(7,928	)	$	(12,958	)	$	133,364	$	135,747
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $303, $(169), $1,303 and $(703), respectively	562			(314		)	2,418		(1,306		)
Reclassification of net unrealized (gain) loss on energy derivative instruments settled during the period, net of tax of $0, $0, $179 and $187, respectively	—			—			333		347
Reclassification of net unrealized (gain) loss on interest rate swaps during the period, net of tax of $0, $0, $0 and $50, respectively	—			—			—		94
Other comprehensive income (loss)	562			(314		)	2,751		(865		)
Comprehensive income (loss)	$	(7,366	)	$	(13,272	)	$	136,115	$	134,882

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

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

	(Unaudited)
	September 30, 2015			December 31, 2014
Utility plant (at original cost, including construction work in progress of $353,388 and $239,690, respectively):
Electric plant	$	7,352,382		$	7,135,206
Natural gas plant	2,805,551			2,680,067
Common plant	481,184			472,926
Less: Accumulated depreciation and amortization	(1,804,201		)	(1,611,220		)
Net utility plant	8,834,916			8,676,979
Other property and investments:
Goodwill	1,656,513			1,656,513
Other property and investments	87,410			91,139
Total other property and investments	1,743,923			1,747,652
Current assets:
Cash and cash equivalents	20,200			37,527
Restricted cash	7,036			32,863
Accounts receivable, net of allowance for doubtful accounts of $11,488 and $7,472, respectively	245,344			306,923
Unbilled revenue	127,620			168,039
Purchased gas adjustment receivable	—			21,073
Materials and supplies, at average cost	84,489			83,189
Fuel and gas inventory, at average cost	68,360			69,433
Unrealized gain on derivative instruments	18,771			21,178
Taxes	31			301
Prepaid expense and other	39,306			20,905
Power contract acquisition adjustment gain	40,348			43,843
Deferred income taxes	162,336			161,445
Total current assets	813,841			966,719
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes	71,499			95,432
Power cost adjustment mechanism	4,717			4,623
Regulatory assets related to power contracts	26,843			29,816
Other regulatory assets	893,869			866,835
Unrealized gain on derivative instruments	3,309			3,170
Power contract acquisition adjustment gain	300,325			347,547
Other	95,978			96,275
Total other long-term and regulatory assets	1,396,540			1,443,698
Total assets	$	12,789,220		$	12,835,048

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

PUGET ENERGY, INC. CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) CAPITALIZATION AND LIABILITIES

	(Unaudited)
	September 30, 2015			December 31, 2014
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	212,188			271,414
Accumulated other comprehensive income (loss), net of tax	(34,292		)	(37,043		)
Total common shareholder’s equity	3,486,853			3,543,328
Long-term debt:
First mortgage bonds and senior notes	3,364,412			3,189,412
Pollution control bonds	161,860			161,860
Junior subordinated notes	250,000			250,000
Long-term debt	1,800,000			1,699,000
Debt discount and other	(212,555		)	(218,664		)
Total long-term debt	5,363,717			5,081,608
Total capitalization	8,850,570			8,624,936
Current liabilities:
Accounts payable	233,582			307,578
Short-term debt	79,500			85,000
Current maturities of long-term debt	—			162,000
Purchased gas adjustment liability	8,347			—
Accrued expenses:
Taxes	80,055			107,782
Salaries and wages	36,161			40,970
Interest	78,011			78,914
Unrealized loss on derivative instruments	133,061			142,195
Power contract acquisition adjustment loss	3,624			3,593
Other	57,509			62,464
Total current liabilities	709,850			990,496
Other long-term and regulatory liabilities:
Deferred income taxes	1,552,461			1,522,357
Unrealized loss on derivative instruments	55,602			62,913
Regulatory liabilities	637,195			633,471
Regulatory liabilities related to power contracts	340,673			391,389
Power contract acquisition adjustment loss	23,219			26,223
Other deferred credits	619,650			583,263
Total other long-term and regulatory liabilities	3,228,800			3,219,616
Commitments and contingencies (Note 8)
Total capitalization and liabilities	$	12,789,220		$	12,835,048

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

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

	Nine Months Ended September 30,
	2015			2014
Operating activities:
Net income (loss)	$	133,364		$	135,747
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	314,348			312,821
Conservation amortization	78,389			74,554
Deferred income taxes and tax credits, net	51,664			51,749
Net unrealized (gain) loss on derivative instruments	(7,789		)	4,194
Derivative contracts classified as financing activities due to merger	8,045			8,026
AFUDC – Equity	(6,490		)	(5,257		)
Funding of pension liability	(13,500		)	(9,000		)
Regulatory assets	(140,958		)	(115,710		)
Regulatory liabilities	26,070			(6,907		)
Other long-term assets	21,042			(5,287		)
Other long-term liabilities	(2,570		)	36,822
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	101,998			274,463
Materials and supplies	(1,300		)	4,735
Fuel and gas inventory	255			(10,032		)
Taxes	270			297
Prepayments and other	(18,399		)	(14,433		)
Purchased gas adjustment	29,420			(38,331		)
Accounts payable	(65,736		)	(54,197		)
Taxes payable	(27,727		)	(27,737		)
Accrued expenses and other	(14,400		)	(11,350		)
Net cash provided by (used in) operating activities	465,996			605,167
Investing activities:
Construction expenditures – excluding equity AFUDC	(419,389		)	(343,619		)
Treasury grants received	—			107,876
Restricted cash	25,827			(47,080		)
Other	2,902			(18,439		)
Net cash provided by (used in) investing activities	(390,660		)	(301,262		)
Financing activities:
Change in short-term debt, net	(5,500		)	(142,864		)
Dividends paid	(192,590		)	(179,614		)
Long-term notes and bonds issued	825,000			299,000
Redemption of bonds and notes	(711,000		)	(299,000		)
Derivative contracts classified as financing activities due to merger	(8,045		)	(8,026		)
Issuance cost of bonds and other	(528		)	8,767
Net cash provided by (used in) financing activities	(92,663		)	(321,737		)
Net increase (decrease) in cash and cash equivalents	(17,327		)	(17,832		)
Cash and cash equivalents at beginning of period	37,527			44,302
Cash and cash equivalents at end of period	$	20,200		$	26,470
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	252,251		$	263,921
Cash payments (refunds) for income taxes	—			—
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows	$	43,522		$	61,112

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 September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Operating revenue:
Electric	$	482,786		$	468,530		$	1,526,029		$	1,577,663
Natural gas	119,582			121,402			653,385			692,780
Other	3,545			4,019			11,683			11,799
Total operating revenue	605,913			593,951			2,191,097			2,282,242
Operating expenses:
Energy costs:
Purchased electricity	97,694			67,984			355,645			363,769
Electric generation fuel	76,863			92,510			180,531			202,741
Residential exchange	(19,530		)	(30,963		)	(92,297		)	(84,587		)
Purchased natural gas	46,436			42,550			282,334			310,128
Unrealized (gain) loss on derivative instruments, net	5,588			32,648			(5,795		)	8,284
Utility operations and maintenance	131,208			132,109			400,355			411,068
Non-utility expense and other	5,605			5,899			18,953			17,451
Depreciation and amortization	107,759			105,905			314,348			312,821
Conservation amortization	24,224			23,047			78,389			74,554
Taxes other than income taxes	64,030			59,945			228,942			228,534
Total operating expenses	539,877			531,634			1,761,405			1,844,763
Operating income (loss)	66,036			62,317			429,692			437,479
Other income (deductions):
Other income	4,731			10,953			14,770			19,815
Other expense	(1,621		)	(1,806		)	(4,843		)	(5,032		)
Interest charges:
AFUDC	2,102			1,474			5,262			4,189
Interest expense	(60,731		)	(68,936		)	(186,547		)	(198,596		)
Interest expense on parent note	—			(103		)	(63		)	(156		)
Income (loss) before income taxes	10,517			3,899			258,271			257,699
Income tax (benefit) expense	641			842			76,596			75,726
Net income (loss)	$	9,876		$	3,057		$	181,675		$	181,973

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 September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Net income (loss)	$	9,876	$	3,057	$	181,675	$	181,973
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $1,815, $1,227, $5,840 and $3,070, respectively	3,370		1,880		10,845		5,305
Reclassification of net unrealized (gain) loss on energy derivative instruments, net of tax of $0, $0, $369 and $386, respectively	—		—		686		718
Amortization of treasury interest rate swaps to earnings, net of tax of $43, $43 $128 and $128, respectively	79		79		237		237
Other comprehensive income (loss)	3,449		1,959		11,768		6,260
Comprehensive income (loss)	$	13,325	$	5,016	$	193,443	$	188,233

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

ASSETS



	(Unaudited)
	September 30, 2015			December 31, 2014
Utility plant (at original cost, including construction work in progress of $353,388 and $239,690, respectively):
Electric plant	$	9,529,759		$	9,330,999
Natural gas plant	3,400,818			3,282,818
Common plant	521,100			512,842
Less: Accumulated depreciation and amortization	(4,616,761		)	(4,449,680		)
Net utility plant	8,834,916			8,676,979
Other property and investments:
Other property and investments	83,372			86,913
Total other property and investments	83,372			86,913
Current assets:
Cash and cash equivalents	19,419			37,466
Restricted cash	7,036			32,863
Accounts receivable, net of allowance for doubtful accounts of $11,488 and $7,472, respectively	245,422			307,046
Unbilled revenue	127,620			168,039
Purchased gas adjustment receivable	—			21,073
Materials and supplies, at average cost	84,489			83,189
Fuel and gas inventory, at average cost	66,401			66,656
Unrealized gain on derivative instruments	18,771			21,178
Taxes	31			301
Prepaid expense and other	39,306			20,907
Deferred income taxes	166,982			208,447
Total current assets	775,477			967,165
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes	70,994			94,913
Power cost adjustment mechanism	4,717			4,623
Other regulatory assets	893,849			866,793
Unrealized gain on derivative instruments	3,309			3,170
Other	87,036			89,306
Total other long-term and regulatory assets	1,059,905			1,058,805
Total assets	$	10,753,670		$	10,789,862

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)
	September 30, 2015			December 31, 2014
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	3,275,105			3,246,205
Earnings reinvested in the business	209,018			202,622
Accumulated other comprehensive income (loss), net of tax	(159,189		)	(170,957		)
Total common shareholder’s equity	3,325,793			3,278,729
Long-term debt:
First mortgage bonds and senior notes	3,364,412			3,189,412
Pollution control bonds	161,860			161,860
Junior subordinated notes	250,000			250,000
Debt discount	(1,903		)	(13		)
Total long-term debt	3,774,369			3,601,259
Total capitalization	7,100,162			6,879,988
Current liabilities:
Accounts payable	233,582			307,572
Short-term debt	79,500			85,000
Short-term note owed to parent	—			28,933
Current maturities of long-term debt	—			162,000
Purchased gas adjustment liability	8,347			—
Accrued expenses:
Taxes	80,055			107,782
Salaries and wages	36,161			40,970
Interest	55,360			55,346
Unrealized loss on derivative instruments	127,077			135,973
Other	57,510			62,464
Total current liabilities	677,592			986,040
Other long-term and regulatory liabilities:
Deferred income taxes	1,667,405			1,649,857
Unrealized loss on derivative instruments	53,963			60,063
Regulatory liabilities	635,216			630,651
Other deferred credits	619,332			583,263
Total other long-term and regulatory liabilities	2,975,916			2,923,834
Commitments and contingencies (Note 8)
Total capitalization and liabilities	$	10,753,670		$	10,789,862

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)



	Nine Months Ended September 30,
	2015			2014
Operating activities:
Net income (loss)	$	181,675		$	181,973
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	314,348			312,821
Conservation amortization	78,389			74,554
Deferred income taxes and tax credits, net	76,595			75,727
Net unrealized (gain) loss on derivative instruments	(5,795		)	8,284
AFUDC – Equity	(6,490		)	(5,257		)
Funding of pension liability	(13,500		)	(9,000		)
Regulatory assets	(140,958		)	(115,710		)
Regulatory liabilities	26,070			(6,907		)
Other long-term assets	19,526			1,827
Other long-term liabilities	1,932			30,224
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	102,043			274,636
Materials and supplies	(1,300		)	4,735
Fuel and gas inventory	255			(10,032		)
Taxes	270			297
Prepayments and other	(18,399		)	(14,433		)
Purchased gas adjustment	29,420			(38,331		)
Accounts payable	(65,736		)	(54,197		)
Taxes payable	(27,727		)	(27,737		)
Accrued expenses and other	(17,305		)	(6,130		)
Net cash provided by (used in) operating activities	533,313			677,344
Investing activities:
Construction expenditures – excluding equity AFUDC	(419,389		)	(343,619		)
Treasury grants received	—			107,876
Restricted cash	25,827			(47,080		)
Other	6,733			(16,571		)
Net cash provided by (used in) investing activities	(386,829		)	(299,394		)
Financing activities:
Change in short-term debt, net	(5,500		)	(142,864		)
Dividends paid	(175,279		)	(261,557		)
Loan from (payment to) parent	(28,933		)	(665		)
Investment from parent	28,900			—
Long-term notes and bonds issued	425,000			—
Redemption of bonds and notes	(412,000		)	—
Issuance cost of bonds and other	3,281			9,437
Net cash provided by (used in) financing activities	(164,531		)	(395,649		)
Net increase (decrease) in cash and cash equivalents	(18,047		)	(17,699		)
Cash and cash equivalents at beginning of period	37,466			44,111
Cash and cash equivalents at end of period	$	19,419		$	26,412
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	177,759		$	185,157
Cash payments (refunds) for income taxes	—			—
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flow	$	43,522		$	61,112

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


(1)	Summary of Consolidation Policy

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. Puget Energy is an indirect wholly-owned subsidiary of Puget Holdings (Puget Holdings LLC).

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, 2014.

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 $47.6 million and $167.5 million for the three and nine months ended September 30, 2015, respectively, and $43.6 million and $172.1 million for the three and nine months ended September 30, 2014, 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.

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 in revenue are deferred to a regulatory asset for under recovery or regulatory liability for over recovery under alternative revenue recognition. To record revenues under this program, the Company must be able to collect the revenue within 24 months based on alternative revenue recognition guidance. Decoupled rate increases are effective May 1 of each year subject to a 3.0% cap of total revenue for decoupled rate schedules. Any excess revenue above 3.0% will be included in the following year's decoupled rate. The Company will be able to recognize revenue deferred below the 3.0% cap of total revenue for decoupled rate schedules. For revenue deferrals exceeding the annual 3.0% rate cap of total revenue for decoupled rate schedules, the Company will need to review the excess amount for its ability to be collected within 24 months. If the excess amount cannot be collected within 24 months, for GAAP purposes only, the Company will not record any decoupling revenue until it is within the 24 months of collection. Revenues associated with energy costs under the Power Cost Adjustment (PCA) mechanism and Purchased Gas Adjustment (PGA) mechanism are excluded from the decoupling mechanism.

(2) New Accounting Pronouncements

Revenue Recognition

In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-09, "Revenue from Contracts with Customers (Topic 606)", which 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.

In August 2015, the FASB issued ASU 2015-14, "Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date," deferring the effective date for ASU 2014-09 to fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. In addition to the FASB's deferral decision, FASB provided reporting entities with an option to adopt ASU 2014-09 for the fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, the original effective date. The Company plans to adopt ASU 2014-09 according to the original effective date. Reporting entities also have the option of using either a full retrospective or a modified retrospective approach for the adoption of the new standard. The Company

initiated a steering committee and project team to evaluate the impact of this standard, update any policies and procedures that may be affected and implement the new revenue recognition guidance. At this time, the Company cannot determine the impact this standard will have on its consolidated financial statements.

Consolidation - Variable Interest Entities

In February 2015, the FASB issued ASU 2015-02, "Consolidation (Topic 810): Amendments to the Consolidation Analysis." ASU 2015-02 affects how a reporting entity determines if it has a variable interest in the legal entity being evaluated for consolidation. Specifically, this amendment eliminates three of the six criteria used for determining whether fees paid by a legal entity to a decision maker represent a variable interest entity. As a result, certain fees paid by legal entities to decision makers that required consolidation of the legal entities may no longer require consolidation under ASU 2015-02.

ASU 2015-02 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted, including adoption in an interim period. Currently, the Company does not have any fee arrangements described under this new amendment with any legal entities. As such, the Company does not expect this guidance to have a material impact on our results of operations or financial position.

Debt Issuance Costs

In April 2015, the FASB issued ASU 2015-03, "Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs." ASU 2015-03 requires debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the debt liability, consistent with the presentation of a debt discount. This new guidance affects only the presentation of debt issuance costs and not the recognition and measurement of debt issuance costs. ASU 2015-03 is to be applied on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance.

In August 2015, the FASB issued ASU 2015-15, "Interest-Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangement." In accordance with the SEC Staff Announcement at the June 18, 2015 Emerging Issues Task Force (EITF) meeting about debt issuance costs, ASU 2015-15 amended the accounting guidance updated by ASU 2015-03 to allow reporting entities the option to defer and present debt issuance costs related to line-of-credit arrangements as an asset and subsequently amortize the deferred debt issuance costs ratably over the term of the line-of-credit arrangement.

ASU 2015-03 and ASU 2015-15 are effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption of the amendments is permitted for financial statements that have not been previously issued. The Company plans to adopt the amendments during the first quarter of fiscal year 2016. The amount of unamortized debt issuance costs as of September 30, 2015 and December 31, 2014 totaled $39.6 million and $35.7 million, respectively.

Internal-Use Software

In April 2015, the FASB issued ASU 2015-05, "Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer's Accounting for Fees Paid in a Cloud Computing Arrangement." ASU 2015-05 requires a customer in a cloud computing arrangement to follow internal-use software guidance if both of the following criteria are met: the customer has the contractual right to take possession of the software at any time during the cloud computing arrangement and can feasibly run the software on its own hardware. If the customer does not meet both criteria, the cloud computing arrangement is considered a service contract and separate accounting for a license would not be permitted.

ASU 2015-05 is effective for annual reporting periods, including interim periods within those annual reporting periods, beginning after December 15, 2015. Early adoption is permitted. The Company plans to adopt ASU 2015-05 during the first quarter of fiscal year 2016 and is in the process of evaluating the potential impacts, if any, of this new guidance on its financial statements.

Fair Value Measurement

In May 2015, the FASB issued ASU 2015-07, "Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent)," which removes the requirement to categorize within the fair value hierarchy all investments for which their fair value is measured using the net asset value per share practical expedient. This ASU also removes the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient. Instead, those disclosures will be limited to investments for which the Company has elected to measure the fair value using that practical expedient.

ASU 2015-07 is effective for annual reporting periods, and interim periods within those reporting periods, beginning after December 15, 2015 and requires reporting entities to apply this ASU retrospectively to all periods presented. Early adoption is permitted. The Company plans to adopt ASU 2015-07 during the first quarter of fiscal year 2016. At this time, the Company cannot determine the impact this standard will have on its consolidated financial statements.

Inventory

In July 2015, the FASB issued ASU 2015-11, "Inventory (Topic 330): Simplifying the Measurement of Inventory." ASU 2015-11 requires inventory within scope of this Topic 330 to be measured at the lower of cost and net realizable value. This amendment does not apply to inventory that is measured using last-in, first-out (LIFO) or the retail inventory method. This amendment applies to all other inventory, including inventory measured using first-in, first-out (FIFO) or average cost.

The new accounting guidance is effective for annual reporting periods, and interim periods within those annual reporting periods, beginning after December 15, 2016 with early adoption permitted. At this time, the Company cannot determine the impact this standard will have on its consolidated financial statements. The Company plans to adopt ASU 2015-11 during the first quarter of fiscal year 2017.

Retirement Benefits

In July 2015, the FASB issued ASU 2015-12, "Plan Accounting: Defined Benefit Pension Plans (Topic 960), Defined Contribution Pension Plans (Topic 962), and Health and Welfare Benefit Plans (Topic 965)." ASU 2015-12 is made up of three parts: Part I, Fully Benefit-Responsive Investment Contracts (Part I); Part II, Plan Investment Disclosures (Part II); and Part III, Measurement Date Practical Expedient (Part III).

Part I requires fully benefit-responsive contracts to be measured, presented and disclosed only at contract value. Part II requires both participant-directed and nonparticipant-directed investments of employee benefit plans be grouped only by general type, and removes the requirement to include the disclosure of (i) the investment strategy of an investment measured using the net asset value per share practical expedient and is part of a fund that files a U.S. Department of Labor Form 5500; and (ii) the net appreciation or depreciation for investments by general type. Part III provides entities that have a fiscal year-end that does not coincide with a month-end a practical expedient to permit plans to measure investments and investment-related accounts as of a month-end date that is closest to the plan's fiscal year-end.

All three parts are effective for fiscal years beginning after December 15, 2015, and early adoption is permitted for each part. Parts I and II must be applied retrospectively for all financial statements presented. The amendments in Part III must be applied prospectively. The Company plans to adopt ASU 2015-12 during the first quarter of fiscal year 2016 and is in the process of evaluating the potential impacts, if any, of this new guidance on its financial statements.

Derivatives and Hedging

In August 2015, the FASB Issues ASU 2015-13, "Derivatives and Hedging (Topic 815): Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Markets." ASU 2015-13 allows certain reporting entities that enter into derivative contracts for the purchase or sale of electricity on a forward basis and arrange for transmission through a nodal energy market, to designate those contracts as normal purchase or normal sale contracts, if the physical delivery criterion is met. This designation removes the Accounting Standards Codification (ASC) Topic 815, Derivatives and Hedging, requirement to measure those derivative contracts at fair value.

This amendment was effective upon issuance, and if elected, the guidance must be applied prospectively. The Company does not expect this guidance to have a material impact on our results of operations or financial position.


(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 PSE's related hedging strategies are focused on reducing 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 September 30, 2015, Puget Energy had two interest rate swap contracts outstanding which extend to January 2017. As of the date of this report, these swap instruments are no longer hedging any variable interest rate debt. Management continues to monitor the economics of terminating the swaps, and unless the economics of terminating the swaps

become more favorable, management intends to let them expire naturally in 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
	September 30, 2015					December 31, 2014
(Dollars in Thousands)	Volumes	Assets ¹		Liabilities ²		Volumes	Assets ¹		Liabilities ²
Interest rate swap derivatives ³	$450 million	$	—	$	7,622	$450 million	$	—	$	9,073
Electric portfolio derivatives	*	15,916		111,472		*	4,822		107,228
Natural gas derivatives (MMBtus) ⁴	345.6 million	6,164		69,569		360.4 million	19,526		88,807
Total derivative contracts		$	22,080	$	188,663		$	24,348	$	205,108
Current		$	18,771	$	133,061		$	21,178	$	142,195
Long-term		3,309		55,602			3,170		62,913
Total derivative contracts		$	22,080	$	188,663		$	24,348	$	205,108

_______________


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


²	Balance sheet locations: 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,” 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 175.1 million One Million British Thermal Units (MMBtu) and purchased electricity of 1.1 million Megawatt Hours (MWhs) at September 30, 2015, and 140.2 million MMBtus and 5.4 million MWhs at December 31, 2014.

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

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 the 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
September 30, 2015
	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	$	22,080	$	—	$	22,080	$	(18,416	)	$	—		$	3,664
Liabilities:
Energy derivative contracts	181,041		—		181,041		(18,416		)	—			162,625
Interest rate swaps ²	7,622		—		7,622		—			—			7,622

Puget Energy and Puget Sound Energy
December 31, 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	$	24,348	$	—	$	24,348	$	(23,066	)	$	—		$	1,282
Liabilities:
Energy derivative contracts	196,035		—		196,035		(23,066		)	(20		)	172,949
Interest rate swaps ²	9,073		—		9,073		—			—			9,073

_______________


¹	All derivative contract deals are executed under ISDA, NAESB and WSPP master netting agreements with right of set-off.


²	Interest rate swap contracts are only held at Puget Energy.

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 September 30,						Nine Months Ended September 30,
(Dollars in Thousands)	Location	2015			2014			2015			2014
Interest rate contracts:	Non-hedged interest rate swap (expense) income	$	(1,156	)	$	(323	)	$	(4,571	)	$	(2,430	)
	Interest expense	—			1,241			560			398
Commodity contracts:
Electric derivatives	Unrealized gain (loss) on derivative instruments, net ¹	(5,588		)	(32,648		)	6,339			(7,714		)
	Electric generation fuel	(11,768		)	(420		)	(27,512		)	8,271
	Purchased electricity	(8,344		)	972			(34,489		)	2,687
Total gain (loss) recognized in income on derivatives		$	(26,856	)	$	(31,178	)	$	(59,673	)	$	1,212



Puget Sound Energy		Three Months Ended September 30,						Nine Months Ended September 30,
(Dollars in Thousands)	Location	2015			2014			2015			2014
Commodity contracts:
Electric derivatives	Unrealized gain (loss) on derivative instruments, net ¹	$	(5,588	)	$	(32,648	)	$	5,795		$	(8,284	)
	Electric generation fuel	(11,768		)	(420		)	(27,512		)	8,271
	Purchased electricity	(8,344		)	972			(34,489		)	2,687
Total gain (loss) recognized in income on derivatives		$	(25,700	)	$	(32,096	)	$	(56,206	)	$	2,674

_______________


¹	Differences between Puget Energy and PSE for the nine months ending September 30, 2015 and September 30, 2014 are due to certain derivative contracts recorded at fair value in 2009 and subsequently designated as Normal Purchase Normal Sale (NPNS) or cash flow hedges. These differences occurred through February 2015.

The unrealized gain or loss on derivative contracts is reported in the statement of cash flows under the operating activities section. However, due to purchase accounting requirements, 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 nine months ended September 30, 2015 and 2014, cash outflows related to financing activities of $8.0 million, for both periods, 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 reclassified into earnings in the same period(s) during which the hedged transaction affected earnings. As of March 31, 2015, all gains or losses on purchased electricity derivatives recorded in OCI have been reclassified into earnings. 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 Other Comprehensive Income (AOCI) into income:



Puget Energy		Three Months Ended September 30,				Nine Months Ended September 30,
(Dollars in Thousands)	Location	2015		2014		2015			2014
Interest rate contracts:	Interest expense	$	—	$	—	$	—		$	(144	)
Commodity contracts:
Electric derivatives	Purchased electricity	—		—		(512		)	(534		)
Total		$	—	$	—	$	(512	)	$	(678	)



Puget Sound Energy		Three Months Ended September 30,						Nine Months Ended September 30,
(Dollars in Thousands)	Location	2015			2014			2015			2014
Interest rate contracts:	Interest expense ¹	$	(122	)	$	(122	)	$	(366	)	$	(366	)
Commodity contracts:
Electric derivatives	Purchased electricity	—			—			(1,055		)	(1,104		)
Total		$	(122	)	$	(122	)	$	(1,421	)	$	(1,470	)

_______________


¹	Within the next twelve months, $0.5 million of losses in AOCI will be reclassified into earnings.

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 September 30, 2015, approximately 99.8% of the Company's energy portfolio exposure, excluding NPNS transactions, is with counterparties that are rated at least investment grade by rating agencies and 0.2% are either rated below investment grade or not rated by rating agencies. The Company assesses credit risk internally for counterparties that are not rated by the major rating agencies.

The Company computes credit reserves at a master agreement level by counterparty. 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 determined 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 netted against the unrealized gain (loss) positions. As of September 30, 2015, 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 September 30, 2015, 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 during the quarter ended September 30, 2015, 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 September 30, 2015:



Puget Energy and Puget Sound Energy
(Dollars in Thousands)
	Fair Value ¹		Posted		Contingent
Contingent Feature	Liability		Collateral		Collateral
Credit rating ²	$	27,360	$	—	$	27,360
Requested credit for adequate assurance	66,785		—		—
Forward value of contract ³	—		—		—
Total	$	94,145	$	—	$	27,360

_______________


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 as 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 markets from an independent external pricing service. For interest rate swaps, the Company obtains monthly market values from an independent external pricing service using 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. 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. Management's assessment is 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 used to value Level 2 commodity contracts with the actual prices of commodity contracts entered into during the most recent quarter.

Assets and Liabilities with Estimated Fair Value

The following table presents the carrying value for cash, cash equivalents, restricted cash, notes receivable and short-term debt by fair value hierarchy level. 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 September 30, 2015						At December 31, 2014
(Dollars in Thousands)	Level 1		Level 2		Total		Level 1		Level 2		Total
Assets:
Cash and cash equivalents	$	20,200	$	—	$	20,200	$	37,527	$	—	$	37,527
Restricted cash	7,036		—		7,036		32,863		—		32,863
Notes receivable and other investments	—		50,294		50,294		—		53,503		53,503
Total assets	$	27,236	$	50,294	$	77,530	$	70,390	$	53,503	$	123,893
Liabilities:
Short-term debt	$	79,500	$	—	$	79,500	$	85,000	$	—	$	85,000
Total liabilities	$	79,500	$	—	$	79,500	$	85,000	$	—	$	85,000



	Carrying / Fair Value						Carrying / Fair Value
Puget Sound Energy	At September 30, 2015						At December 31, 2014
(Dollars in Thousands)	Level 1		Level 2		Total		Level 1		Level 2		Total
Assets:
Cash and cash equivalents	$	19,419	$	—	$	19,419	$	37,466	$	—	$	37,466
Restricted cash	7,036		—		7,036		32,863		—		32,863
Notes receivable and other investments	—		50,294		50,294		—		53,503		53,503
Total assets	$	26,455	$	50,294	$	76,749	$	70,329	$	53,503	$	123,832
Liabilities:
Short-term debt	$	79,500	$	—	$	79,500	$	85,000	$	—	$	85,000
Short-term debt owed to parent	—		—		—		—		28,933		28,933
Total liabilities	$	79,500	$	—	$	79,500	$	85,000	$	28,933	$	113,933

The fair value of the junior subordinated and long-term notes was estimated using the discounted cash flow method with the U.S. Treasury yields and the Company's credit spreads as inputs, interpolating to the maturity date of each issue. Carrying values and estimated fair values were as follows:



Puget Energy		September 30, 2015				December 31, 2014
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Junior subordinated notes	2	$	250,000	$	269,915	$	250,000	$	276,235
Long-term debt (fixed-rate), net of discount	2	5,113,717		6,364,901		4,694,608		6,083,554
Long-term debt (variable-rate)	2	—		—		299,000		299,000
Total liabilities		$	5,363,717	$	6,634,816	$	5,243,608	$	6,658,789

Puget Sound Energy		September 30, 2015				December 31, 2014
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Junior subordinated notes	2	$	250,000	$	269,915	$	250,000	$	276,235
Long-term debt (fixed-rate), net of discount	2	3,524,369		4,358,964		3,513,259		4,437,473
Total liabilities		$	3,774,369	$	4,628,879	$	3,763,259	$	4,713,708

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:



	Fair Value						Fair Value
Puget Energy	At September 30, 2015						At December 31, 2014
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total
Liabilities:
Interest rate derivative instruments	$	7,622	$	—	$	7,622	$	9,073	$	—	$	9,073
Total liabilities	$	7,622	$	—	$	7,622	$	9,073	$	—	$	9,073



Puget Energy and	Fair Value						Fair Value
Puget Sound Energy	At At September 30, 2015						At December 31, 2014
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	9,369	$	6,547	$	15,916	$	1,654	$	3,168	$	4,822
Natural gas derivative instruments	3,535		2,629		6,164		18,064		1,462		19,526
Total assets	$	12,904	$	9,176	$	22,080	$	19,718	$	4,630	$	24,348
Liabilities:
Electric derivative instruments	$	92,483	$	18,989	$	111,472	$	91,998	$	15,230	$	107,228
Natural gas derivative instruments	66,560		3,009		69,569		85,305		3,502		88,807
Total liabilities	$	159,043	$	21,998	$	181,041	$	177,303	$	18,732	$	196,035

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 September 30,
(Dollars in Thousands)	2015									2014
Level 3 Roll-Forward Net Asset/(Liability)	Electric			Natural Gas			Total			Electric			Natural Gas			Total
Balance at beginning of period	$	(15,370	)	$	823		$	(14,547	)	$	(4,693	)	$	(273	)	$	(4,966	)
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings ¹	(1,403		)	—			(1,403		)	(3,116		)	—			(3,116		)
Included in regulatory assets / liabilities	—			1,295			1,295			—			(725		)	(725		)
Settlements³	1,017			(2,122		)	(1,105		)	(965		)	(680		)	(1,645		)
Transferred into Level 3	—			—			—			2,055			—			2,055
Transferred out of Level 3	3,314			(376		)	2,938			(6,488		)	(60		)	(6,548		)
Balance at end of period	$	(12,442	)	$	(380	)	$	(12,822	)	$	(13,207	)	$	(1,738	)	$	(14,945	)

Puget Energy and Puget Sound Energy	Nine Months Ended September 30,
(Dollars in Thousands)	2015									2014
Level 3 Roll-Forward Net Asset/(Liability)	Electric			Natural Gas			Total			Electric			Natural Gas			Total
Balance at beginning of period	$	(12,061	)	$	(2,039	)	$	(14,100	)	$	(15,421	)	$	(361	)	$	(15,782	)
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings²	(10,505		)	—			(10,505		)	1,939			—			1,939
Included in regulatory assets / liabilities	—			4,233			4,233			—			1,654			1,654
Settlements ³	1,182			(2,420		)	(1,238		)	1,114			(1,256		)	(142		)
Transferred into Level 3	(787		)	—			(787		)	5,155			(585		)	4,570
Transferred out of Level 3	9,729			(154		)	9,575			(5,994		)	(1,190		)	(7,184		)
Balance at end of period	$	(12,442	)	$	(380	)	$	(12,822	)	$	(13,207	)	$	(1,738	)	$	(14,945	)

_______________


¹	Income Statement locations: 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 $(1.5) million and $(3.3) million for the three months ended September 30, 2015 and 2014, respectively.


²	Income Statement locations: 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 $(10.4) million and $(3.3) million for the nine months ended September 30, 2015 and 2014, 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. The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of September 30, 2015:



	Fair Value						Range
(Dollars in Thousands)	Assets ¹		Liabilities ¹		Valuation Technique	Unobservable Input	Low	High	Weighted Average
Electric	$	6,547	$	18,989	Discounted cash flow	Power Prices	$13.39 per MWh	$30.06 per MWh	$24.05 per MWh
Natural gas	$	2,629	$	3,009	Discounted cash flow	Natural Gas Prices	$1.56 per MMBtu	$3.13 per MMBtu	$2.40 per MMBtu

_______________


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

The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of December 31, 2014:



	Fair Value						Range
(Dollars in Thousands)	Assets ¹		Liabilities ¹		Valuation Technique	Unobservable Input	Low	High	Weighted Average
Electric	$	3,168	$	15,230	Discounted cash flow	Power Prices	$21.79 per MWh	$35.46 per MWh	$32.89 per MWh
Natural gas	$	1,462	$	3,502	Discounted cash flow	Natural Gas Prices	$3.11 per MMBtu	$3.83 per MMBtu	$3.28 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 September 30, 2015 and December 31, 2014, a hypothetical 10% increase or decrease in market prices of natural gas and electricity would change the fair value of the Company's derivative portfolio, classified as Level 3 within the fair value hierarchy, by $0.3 million and $3.9 million, respectively.

Long-Lived Assets Measured at Fair Value on a Nonrecurring Basis

Puget Energy records fair value of its intangible assets in accordance with ASC 360, “Property, Plant, and Equipment,” (ASC 360). The fair value assigned to the power contracts was determined using an income approach comparing the contract rate to the market rate for power over the remaining period of the contracts incorporating non-performance risk. Management also incorporated certain assumptions related to quantities and market presentation that it believes market participants would make in the valuation. The fair value of the power contracts is amortized as the contracts settle.

ASC 360 requires long-lived assets to be tested for impairment on an annual basis, and upon the occurrence of any events or circumstances that would be more likely than not to reduce the fair value of the long-lived assets below their carrying value. One such triggering event is a significant decrease in the forward market prices of power.

At September 30, 2015, Puget Energy completed a valuation and impairment test of its purchased power contracts classified as intangible assets. The valuation indicated an impairment to the Wells hydro contract. As of September 30, 2015, the carrying value for this contract was $42.4 million and its fair value on a discounted basis was $35.7 million, thereby requiring a write-down of $6.7 million to this intangible asset with a corresponding reduction in the regulatory liability. The forward market prices of power for the duration of the Wells hydro contract decreased on average 11% from March 31, 2015 to September 30, 2015, which caused the impairments.

Below are significant unobservable inputs used in valuing the impaired long-term purchased power contract on September 30, 2015:



Valuation Technique	Unobservable Input	Low			High			Average
Discounted cash flow	Power prices	$	18.38	per MWh	$	27.92	per MWh	$	24.88	per MWh
Discounted cash flow	Power contract costs (in thousands)	$	4,100	per qtr.	$	4,659	per qtr.	$	4,388	per qtr.


(5)	Retirement Benefits

PSE has a defined benefit pension plan (Qualified Pension Benefits) covering the largest portion of 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. Starting with January 1, 2014 all newly hired non-represented employees, United Association of Journeymen and Apprentices of the Plumbing and Pipe Fitting Industry employees, and International Brotherhood of Electrical Workers Local Union 77 hired on or after December 12, 2014 who elect to accumulate the Company contribution in the cash balance formula portion of the pension plan, will receive annual pay credits of 4% each year. They will also receive interest credits like other participants in the cash balance pension formula of the pension plan, which are at least 1% per quarter. When an employee with a vested cash balance formula benefit leaves PSE, he or she will have annuity and lump sum options for distribution. Those who select the lump sum option will receive their current cash balance amount. 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 legacy group health care and life insurance benefits (Other 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 prior year.

Puget Energy records purchase accounting adjustments associated with the re-measurement of the retirement plans.

The following tables summarize the Company’s net periodic benefit cost for the three and nine months ended September 30, 2015 and 2014:



Puget Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
	Three Months Ended September 30,
(Dollars in Thousands)	2015			2014			2015		2014		2015			2014
Components of net periodic benefit cost:
Service cost	$	5,322		$	4,359		$	277	$	261	$	28		$	28
Interest cost	7,022			7,010			570		577		156			171
Expected return on plan assets	(11,260		)	(10,616		)	—		—		(133		)	(134		)
Amortization of prior service cost	(495		)	(495		)	11		12		—			—
Amortization of net loss (gain)	972			—			410		228		(33		)	(228		)
Net periodic benefit cost	$	1,561		$	258		$	1,268	$	1,078	$	18		$	(163	)



Puget Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
	Nine Months Ended September 30,
(Dollars in Thousands)	2015			2014			2015		2014		2015			2014
Components of net periodic benefit cost:
Service cost	$	15,966		$	13,077		$	831	$	782	$	84		$	84
Interest cost	21,066			21,030			1,710		1,732		467			513
Expected return on plan assets	(33,779		)	(31,848		)	—		—		(399		)	(401		)
Amortization of prior service cost	(1,485		)	(1,485		)	33		33		—			—
Amortization of net loss (gain)	2,915			—			1,230		684		(99		)	(296		)
Net periodic benefit cost	$	4,683		$	774		$	3,804	$	3,231	$	53		$	(100	)



Puget Sound Energy	Qualified						SERP				Other
	Pension Benefits						Pension Benefits				Benefits
	Three Months Ended September 30,
(Dollars in Thousands)	2015			2014			2015		2014		2015			2014
Components of net periodic benefit cost:
Service cost	$	5,322		$	4,359		$	277	$	261	$	28		$	28
Interest cost	7,022			7,010			570		577		156			171
Expected return on plan assets	(11,366		)	(10,813		)	—		—		(133		)	(134		)
Amortization of prior service cost	(393		)	(393		)	11		11		—			1
Amortization of net loss (gain)	5,139			3,298			530		365		(101		)	(175		)
Net periodic benefit cost	$	5,724		$	3,461		$	1,388	$	1,214	$	(50	)	$	(109	)



Puget Sound Energy	Qualified						SERP				Other
	Pension Benefits						Pension Benefits				Benefits
	Nine Months Ended September 30,
(Dollars in Thousands)	2015			2014			2015		2014		2015			2014
Components of net periodic benefit cost:
Service cost	$	15,966		$	13,077		$	831	$	782	$	84		$	84
Interest cost	21,066			21,030			1,710		1,732		467			513
Expected return on plan assets	(34,097		)	(32,439		)	—		—		(399		)	(401		)
Amortization of prior service cost	(1,179		)	(1,179		)	33		33		2			3
Amortization of net loss (gain)	15,416			9,895			1,590		1,095		(304		)	(527		)
Net periodic benefit cost	$	17,172		$	10,384		$	4,164	$	3,642	$	(150	)	$	(328	)

The following table summarizes the Company’s change in benefit obligation for the periods ended September 30, 2015 and December 31, 2014:



Puget Energy and Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
	Nine Months Ended			Year Ended			Nine Months Ended			Year Ended			Nine Months Ended			Year Ended
(Dollars in Thousands)	September 30, 2015			December 31, 2014			September 30, 2015			December 31, 2014			September 30, 2015			December 31, 2014
Change in benefit obligation:
Benefit obligation at beginning of period	$	690,194		$	573,317		$	55,855		$	47,279		$	15,688		$	14,939
Service cost	15,966			17,437			831			1,042			84			112
Interest cost	21,066			28,039			1,710			2,310			467			684
Actuarial loss (gain)	(588		)	104,618			—			7,162			(540		)	1,108
Benefits paid	(41,804		)	(33,217		)	(3,026		)	(1,938		)	(1,045		)	(1,424		)
Medicare part D subsidy received	—			—			—			—			221			269
Benefit obligation at end of period	$	684,834		$	690,194		$	55,370		$	55,855		$	14,875		$	15,688

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, 2015 are expected to be at least $18.0 million, $4.4 million and $0.4 million, respectively. During the three months ended September 30, 2015, the Company contributed $4.5 million, $0.5 million, and $0.1 million to fund the qualified pension plan, SERP and other postretirement plan, respectively. During the nine months ended September 30, 2015, the Company contributed $13.5 million, $3.0 million, and $0.5 million to fund the qualified pension plan, SERP and other postretirement plan, respectively.


(6)	Regulation and Rates

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 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 (GRC). Rate increases are subject to a cap of 3.0% of total revenue for customers.

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.

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 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. 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%. Following an appeal and remand, the Washington Commission issued a final order on remand on June 29, 2015, in which it found that 9.8% is a reasonable return on equity for PSE for the term of the rate plan, taking decoupling and other relevant factors into account.

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 customers of $10.6 million, or 0.5% annually, and a rate decrease for natural gas customers 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 customers of $11.0 million, or 0.5% annually, and a rate increase for natural gas customers of $5.6 million, or 0.6% annually.

budgets as well as true-ups to the rate from the prior year. The rate change represents a rate increase for electric customers of $12.2 million, or 0.6% annually, and a rate increase for natural gas customers of $0.3 million.

On October 30, 2014, the Washington Commission approved the PGA natural gas tariff which proposed to reflect changes in wholesale gas and pipeline transportation costs and changes in deferral amortization rates. The impact of PGA rates is an annual revenue increase of $23.3 million, or 2.5%, with no impact on net operating income.

On November 3, 2014, the Washington Commission issued an order approving the settlement of the power cost only rate case (PCORC) which was filed on May 23, 2014. The original filing proposed a decrease of $9.6 million (or an average of approximately 0.5%) in the Company's overall power supply costs. PSE filed joint testimony supporting a settlement stipulation. Customer rates decreased by approximately $19.4 million, or 0.9% annually, as a result of the settlement, effective December 1, 2014.

On March 26, 2015, PSE filed a request with the Washington Commission to change rates under its electric and natural gas property tax tracker mechanism, effective May 1, 2015. PSE filed a substitute filing with the Washington Commission on April 15, 2015 for the electric property tax tracker mechanism. The proposed rate change incorporates the effects of an increase to property taxes paid, as well as true-ups to the rate from the prior year. This represents a rate increase for electric customers of $6.5 million, or 0.3% annually. PSE made a subsequent substitute natural gas filing with the Washington Commission on May 1, 2015, which changed the rate effective date to June 1, 2015, and represented a rate decrease for natural gas customers of $2.3 million, or 0.2% annually.

On August 7, 2015 the Washington Commission issued an order approving the settlement proposing changes to the PCA mechanism. The settlement agreement will not take effect until January 1, 2017. Key components of the settlement will include the following changes to the PCA mechanism:



		Company's Share				Customers' Share
Annual Power Cost Variability		Over		Under		Over		Under
+/-	$17 million	100	%	100	%	—	%	—	%
+/-	$17 million - $40 million	35		50		65		50
+/-	$40+ million	10		10		90		90


•	Reducing the cumulative deferral trigger for surcharge or refund from $30.0 million to $20.0 million;


•	Removing fixed production costs from the PCA mechanism and placing them in the decoupling mechanism if the decoupling mechanism continues as part of the next GRC;


•	Suspending the requirement that a GRC must be filed within three months after rates are approved in a PCORC, and agreeing, for a five-year period, that PSE will not file a GRC or PCORC within six months of the date that rates go into effect for a PCORC filing; and


•	Establishing a five-year moratorium on changes to the PCA/PCORC.

On April 22, 2015, the Washington Commission approved PSE's request to change rates under its electric and natural gas decoupling mechanism, effective May 1, 2015. As part of this filing, PSE also requested to change the methodology of how decoupling deferrals are calculated going forward and adjust deferrals calculated in 2014. The change was done to ensure that the amortization of prior years’ accumulated decoupling deferrals were not included in the calculation of the current year decoupling deferrals. The effect of the methodology change was a reduction of approximately $12.0 million previously recognized revenue from May through December of 2014. The overall changes represent a rate increase for electric customers of $53.8 million, or 2.6% annually, and a rate increase for natural gas customers of $22.0 million, or 2.1% annually, effective May 1, 2015. In addition, PSE exceeded the earnings test threshold for its natural gas business in 2014. As a result, PSE recorded a reduction in natural gas decoupling deferral and revenue of $1.3 million. This was reflected as a reduction to the natural gas rate increases noted above. As noted earlier, the Company is also limited to a 3.0% annual decoupling related cap on increases in total revenue. This limitation was triggered for certain rate classes. The resulting amount of deferral that was not included in the 2015 rate increase is $1.9 million for electric revenue and $8.2 million for natural gas revenue that was accrued through December 31, 2014. These amounts may be included in customer rates beginning in May 2016, subject to subsequent application of the earnings test and the 3.0% cap on decoupling related rate increases.

On September 18, 2015, PSE filed the PGA natural gas tariff which proposed to reflect changes in wholesale gas and pipeline transportation costs and changes in deferral amortization rates. The impact of PGA rates is an annual revenue decrease of $185.9 million, or 17.4%, with no impact on net operating income.


(7)	Asset Retirement Obligation

The Company has recorded liabilities for steam generation sites, combustion turbine generation sites, combined cycle generation sites, wind generation sites, distribution and transmission poles, gas mains, and leased facilities where disposal is governed by ASC 410 “Asset Retirement and Environmental Obligations (ARO)”.

On April 17, 2015, the U.S. Environmental Protection Agency (EPA) published a final rule, effective October 19, 2015, that regulates Coal Combustion Residuals (CCR) under the Resource Conservation and Recovery Act, Subtitle D. The CCR rule addresses the risks from coal ash disposal, such as leaking of contaminants into ground water, blowing of contaminants into the air as dust, and the catastrophic failure of coal ash surface impoundments by establishing technical requirements for CCR landfills and surface impoundments. The rule also sets out recordkeeping and reporting requirements including requirements to post specific information to a publicly-accessible website.

The CCR rule requires significant changes to the Company’s Colstrip operations and those changes were reviewed by the Company and the plant operator in the second quarter of 2015. PSE had previously recognized a legal obligation under the EPA rules to dispose of coal ash material at Colstrip, in 2003. Due to the CCR rule, additional disposal costs were added to the ARO.

The actual ARO costs related to the CCR rule requirements may vary substantially from the estimates used to record the increased obligation due to uncertainty about the compliance strategies that will be used and the preliminary nature of available data used to estimate costs. We will continue to gather additional data and coordinate with the plant operator to make decisions about compliance strategies and the timing of closure activities. As additional information becomes available, the Company will update the ARO obligation for these changes, which could be material.

The following table describes the changes to the Company’s ARO for the nine months ended September 30, 2015:



Puget Sound Energy
Changes in ARO
(Dollars in Thousands)
Balance at December 31, 2014	$	48,909
New asset retirement obligation recognized in the period	34,534
Liability adjustments	(3,696		)
Revisions in estimated cash flows	450
Accretion expense	1,220
Balance at September 30, 2015	$	81,417


(8)	Contingencies

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, the Sierra Club and the Montana Environmental Information Center filed a Clean Air Act citizen suit against all Colstrip owners in the U.S. District Court, District of Montana. Based on a second amended complaint filed in August 2014, plaintiffs' lawsuit currently alleges violations of permitting requirements under the New Source Review program of the Clean Air Act and the Montana State Implementation Plan arising from seven projects undertaken at Colstrip during 2001-2012. Plaintiffs have since indicated that they do not intend to pursue three of the seven projects, leaving a total of four projects remaining. The lawsuit claims that, for each project, the Colstrip plant should have obtained a permit and installed pollution control equipment at Colstrip. The Plaintiffs' complaint also seeks civil penalties and other appropriate relief. The case has been bifurcated into separate liability and remedy trials. The liability trial is currently set for March 2016, and a date for the remedy trial has yet to be determined. PSE is litigating the allegations set forth in the complaint, and as such, it is not reasonably possible to estimate 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 $0.4 million and $1.7 million relating to these claims as of September 30, 2015 and December 31, 2014, respectively.


(9)	Accumulated Other Comprehensive Income (Loss)

The following tables present the changes in the Company’s AOCI (loss) by component for the three and nine months ended September 30, 2015:



Puget Energy	Net unrealized gain (loss) and prior service cost on pension plans			Net unrealized gain (loss) on energy derivative instruments
Changes in AOCI, net of tax
(Dollars in Thousands)						Total
Balance at June 30, 2015	$	(34,854	)	$	—	$	(34,854	)
Other comprehensive income (loss) before reclassifications	—			—		—
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	562			—		562
Net current-period other comprehensive income (loss)	562			—		562
Balance at September 30, 2015	$	(34,292	)	$	—	$	(34,292	)



Puget Energy	Net unrealized gain (loss) and prior service cost on pension plans			Net unrealized gain (loss) on energy derivative instruments
Changes in AOCI, net of tax
(Dollars in Thousands)							Total
Balance at December 31, 2014	$	(36,710	)	$	(333	)	$	(37,043	)
Other comprehensive income (loss) before reclassifications	696			—			696
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	1,722			333			2,055
Net current-period other comprehensive income (loss)	2,418			333			2,751
Balance at September 30, 2015	$	(34,292	)	$	—		$	(34,292	)



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 June 30, 2015	$	(156,806	)	$	—	$	(5,832	)	$	(162,638	)
Other comprehensive income (loss) before reclassifications	—			—		—			—
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	3,370			—		79			3,449
Net current-period other comprehensive income (loss)	3,370			—		79			3,449
Balance at September 30, 2015	$	(153,436	)	$	—	$	(5,753	)	$	(159,189	)



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, 2014	$	(164,281	)	$	(686	)	$	(5,990	)	$	(170,957	)
Other comprehensive income (loss) before reclassifications	712			—			—			712
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	10,133			686			237			11,056
Net current-period other comprehensive income (loss)	10,845			686			237			11,768
Balance at September 30, 2015	$	(153,436	)	$	—		$	(5,753	)	$	(159,189	)

Details about these reclassifications out of AOCI for the three and nine months ended September 30, 2015, and 2014, are as follows:



Puget Energy		Three Months Ended September 30,						Nine Months Ended September 30,
(Dollars in Thousands)		2015			2014			2015			2014
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		$	483		$	1,452		$	1,452
Amortization of net gain (loss)	^(a)	(1,349		)	—			(5,172		)	(388		)
	Total before tax	(865		)	483			(3,720		)	1,064
	Tax (expense) or benefit	303			(169		)	1,302			(703		)
	Net of Tax	$	(562	)	$	314		$	(2,418	)	$	361
Net unrealized gain (loss) on energy derivative instruments:
Commodity contracts: electric derivatives	Purchased electricity	—			—			(512		)	(534		)
	Tax (expense) or benefit	—			—			179			187
	Net of Tax	$	—		$	—		$	(333	)	$	(347	)
Net unrealized gain (loss) on interest rate swaps:
Interest rate contracts	Interest expense	—			—			—			(144		)
	Tax (expense) or benefit	—			—			—			50
	Net of Tax	$	—		$	—		$	—		$	(94	)
Total reclassification for the period	Net of Tax	$	(562	)	$	314		$	(2,751	)	$	(80	)

_______________


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



Puget Sound Energy		Three Months Ended September 30,						Nine Months Ended September 30,
(Dollars in Thousands)		2015			2014			2015			2014
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)	$	383		$	381		$	1,145		$	1,143
Amortization of net gain (loss)	^(a)	(5,568		)	(3,488		)	(17,830		)	(10,463		)
	Total before tax	(5,185		)	(3,107		)	(16,685		)	(9,320		)
	Tax (expense) or benefit	1,815			1,227			5,840			3,070
	Net of Tax	$	(3,370	)	$	(1,880	)	$	(10,845	)	$	(6,250	)
Net unrealized gain (loss) on energy derivative instruments:
Commodity contracts: electric derivatives	Purchased electricity	—			—			(1,055		)	(1,104		)
	Tax (expense) or benefit	—			—			369			386
	Net of Tax	$	—		$	—		$	(686	)	$	(718	)
Net unrealized gain (loss) on treasury interest rate swaps:
Interest rate contracts	Interest expense	(122		)	(122		)	(366		)	(366		)
	Tax (expense) or benefit	43			43			129			129
	Net of Tax	$	(79	)	$	(79	)	$	(237	)	$	(237	)
Total reclassification for the period	Net of Tax	$	(3,449	)	$	(1,959	)	$	(11,768	)	$	(7,205	)

_______________


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


(10)	Other

Long-Term Debt

On May 26, 2015, PSE issued $425.0 million of senior notes secured by first mortgage bonds. The notes mature in May 2045 and have an interest rate of 4.30%, which is payable semi-annually in May and November. Net proceeds of the issuance were used to fund the early retirement, including accrued interest and make-whole call premiums, of PSE's $150.0 million 5.197% senior notes maturing in October 2015 and PSE's $250.0 million 6.75% senior notes maturing in January 2016.

On May 12, 2015, Puget Energy issued $400.0 million of senior secured notes. The notes mature in May 2025 and have an interest rate of 3.65%, which is payable semi-annually in May and November. Net proceeds of the issuance were used to repay $299.1 million principal amount outstanding under Puget Energy's term loans, as well as accrued interest, and to fund a special dividend to shareholders of approximately $96.7 million.

Related Party Transactions

Scott Armstrong serves on the Board of Directors of the Company, and is the president and Chief Executive Officer of Group Health Cooperative (Group Health). Group Health provides coverage to over 600,000 residents in Washington and Northern Idaho. Certain employees of PSE elect Group Health as their medical provider and as a result, PSE paid Group Health a total of $14.8 million and $17.7 million for medical coverage for the nine months ended September 30, 2015, and the year ended December 31, 2014, respectively.

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

The following discussion and analysis should be read in conjunction with the financial statements and related notes thereto included elsewhere in this report on Form 10-Q. The discussion contains forward-looking statements that involve risks and uncertainties, such as Puget Energy, Inc. (Puget Energy) and Puget Sound Energy, Inc. (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, 2014. 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 U.S. 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. Puget Holdings LLC (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. All of Puget Energy's common stock is indirectly owned by Puget Holdings. 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, employee engagement, operational excellence, customer service and financial strength. The Company's strategies are aligned to achieve these objectives and ultimately the Company's mission.

These strategies involve numerous commitments and investments related to utility infrastructure and customer service which 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 expedited rate filing (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 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 allows PSE an opportunity to earn its authorized rate of return without the need for another general rate case (GRC) process during 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 (i.e., power cost only rate cases (PCORC) or emergency rate relief), requires PSE to file a GRC 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 GRC. In addition, the decoupling mechanism reduces earnings volatility but does not materially affect the timing of cash flow due to the timing difference between the recognition of decoupling revenue and resulting impacts on rates.

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 continually balances its load requirements and generation resources to meet customer demand. 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 nine months ended September 30, 2015, as compared to the same periods in 2014, PSE's net income was affected primarily by the following factors: (1) a decrease in electric margin due to higher purchased electricity costs and lower decoupling and miscellaneous revenues; (2) a decrease in natural gas margin due to lower residential therm sales due to warmer weather; and (3) changes in unrealized (gain) loss on derivative instruments.

Factors and Trends Affecting PSE's Performance

The principal business, economic and other factors that affect PSE's operations and financial performance include the following:


•	The rates PSE is allowed to charge for its services;


•	PSE’s ability to recover power costs that are included in rates which are based on volume;


•	PSE’s ability to manage costs during the rate stay out period through March 31, 2016;


•	Weather conditions, including snow-pack affecting hydrological conditions;


•	Regulatory decisions allowing PSE to recover purchased power and fuel costs, on a timely basis;


•	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;


•	Equal sharing between PSE and its customers of earnings which exceed PSE's authorized rate of return;


•	Availability and access to capital and the cost of capital;


•	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;


•	Wholesale commodity prices of electricity and natural gas;


•	Increasing depreciation;


•	Bonus depreciation and the impact on rate base;


•	General economic conditions in PSE's service territory and its effects on customer growth and use-per-customer;


•	Conservation investments by customers; and


•	Federal, state, and local taxes.

Further detail regarding the factors and trends affecting performance of the Company during the fiscal quarter ended September 30, 2015 is set forth below in this "Overview" section as well as in other sections of the Management's Discussion & Analysis.

Regulation of PSE Rates and Recovery of PSE Costs

PSE's regulatory requirements and operational needs require the investment of substantial capital in 2015 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. The rates that PSE is allowed to charge for its services influence its financial condition, results of operations and liquidity. PSE is highly regulated and the rates that it charges its retail customers are approved by the Washington Utilities and Transportation Commission (Washington Commission). The Washington Commission 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.

Power Cost Only Rate Case. A limited-scope proceeding was approved in 2002 by the Washington Commission to periodically reset power cost rates. In addition to providing the opportunity to reset all power costs, the PCORC proceeding also provides for timely review of new resource acquisition costs and inclusion of such costs in rates at the time the new resource goes into service. To achieve this objective, the Washington Commission has used an expedited six-month PCORC decision timeline rather than the statutory 11-month timeline for a GRC.

On November 3, 2014 the Washington Commission issued an order on the settlement of the PCORC which PSE filed on May 23, 2014. The original filing proposed a decrease of $9.6 million (or an average of approximately 0.5%) in the Company's overall

power supply costs. PSE filed joint testimony supporting a settlement stipulation. Customer rates decreased by approximately $19.4 million, or 0.9%, annually, as a result of the settlement effective 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 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 cash payments and property tax accruals will be deferred and recovered in a property tax tracker.

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 PSE's delivery-system costs and authority to record accounting entries associated with the mechanisms. 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 GRC process over the plan period. The rate plan includes predetermined annual increases (escalating factors referred to as the K-Factor) to PSE's allowed electric and gas delivery revenue (transmission and distribution), which are effective January 1 of each year, currently 3.0% for electric and 2.2% for natural gas. Under this plan, PSE, with limited exceptions, would be allowed to file its next GRC 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 power cost adjustment (PCA) mechanism, the purchased gas adjustment (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% cap on rate increases. Any amount in excess of the cap will be added to the decoupling tracker in subsequent rate periods, subject to a 3.0% cap on rate increases in the subsequent year. In addition, PSE and its customers would share 50.0% each in any earnings in excess of the authorized rate of return of 7.77%. The customers' share of any earnings would be returned to customers over the subsequent 12-month period beginning May 1 of each year.

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 customers of $10.6 million, or 0.5%, annually on total electric revenue, and a rate decrease for natural gas customers of $1.0 million, or 0.1%, annually on total gas revenue.

The Company is also limited to a 3.0% annual decoupling related cap on increases in total revenue. This limitation was triggered for certain rate classes. The resulting amount of deferral that was not included in the 2015 rate increase is $1.9 million for electric revenue and $8.2 million for natural gas revenue that was accrued through December 31, 2014. These amounts may be included in customer rates beginning in May 2016, subject to subsequent application of the earnings test and the 3.0% cap on decoupling related rate increases.

Due to the 3.0% annual decoupling increase cap noted above and the growing size of decoupling deferrals, PSE performed an analysis as of September 30, 2015 to determine if electric and natural gas decoupling revenue deferrals would be collected from customers within 24 months of December 31, 2015. The analysis indicated $5.0 million of natural gas decoupling revenue will not be collected within 24 months, therefore PSE did not recognize this portion of decoupling revenue. However, once it is determined to be collectible within 24 months it will be recognized.

Washington Commission Decision. 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 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' petitions argued that the order violated various procedural and substantive requirements of the Washington Administrative Procedure Act, and so requested 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 decision in which it affirmed the attrition adjustment K-Factor and the Washington Commission's decision not to consider the case as a GRC, but reversed and remanded the cost of equity for further adjudication consistent with the court's decision. In the remand proceeding evidentiary hearings regarding return on equity were held in February 2015 and initial briefs and reply briefs were filed in March 2015. The

Washington Commission issued a final order on remand on June 29, 2015, in which it found that 9.8% is a reasonable return on equity for PSE for the term of the rate plan, taking decoupling and other relevant factors into account.

Other Proceedings. On August 11, 2015, PSE filed with the Washington Commission, a petition for approval of a special contract for the liquefied natural gas (LNG) fuel service with Totem Ocean Trailer Express, Inc. (TOTE) which upon the Washington Commission approval, has a delivery term that commences January 1, 2019. Additionally, the filing contained a request for a declaratory order approving the methodology for allocating costs between regulated and non-regulated LNG services. A prehearing conference was held on October 13, 2015, which provided for simultaneous briefs on November 20, 2015 and hearings on January 29, 2016.

On March 26, 2015, PSE filed a request with the Washington Commission to change rates under its electric and natural gas property tax tracker mechanism, effective May 1, 2015. PSE filed a substitute filing with the Washington Commission on April 15, 2015 for the electric property tax tracker mechanism. The proposed rate change incorporates the effects of an increase to property taxes paid as well as true-ups to the rate from the prior year. This represents a rate increase for electric customers of $6.5 million, or 0.3% annually. PSE made a subsequent substitute natural gas filing with the Washington Commission on May 1, 2015, which changed the rate effective date to June 1, 2015, and represented a rate decrease for natural gas customers of $2.3 million or 0.2% 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 customers of $12.2 million, or 0.6% annually, and a rate increase for natural gas customers of $0.3 million.

Electric Rates

PSE currently 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 currently applicable is as follows:



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

On August 7, 2015, the Washington Commission issued an order approving the settlement proposing changes to the PCA mechanism. The settlement agreement will not take effect until January 1, 2017. Key components of the settlement will include the following changes to the PCA mechanism:



Annual Power Cost Variability	Company's Share				Customers’ Share
	Over		Under		Over		Under
+/- $17 million	100	%	100	%	—	%	—	%
+/- $17 million - $40 million	35		50		65		50
+/- $40 + million	10		10		90		90


•	Reducing the cumulative deferral trigger for surcharge or refund from $30.0 million to $20.0 million;


•	Removing fixed production costs from the PCA mechanism and placing them in the decoupling mechanism if the decoupling mechanism continues as part of the next GRC;


•	Suspending the requirement that a GRC must be filed within three months after rates are approved in a PCORC, and agreeing, for a five-year period, that PSE will not file a GRC or PCORC within six months of the date rates go into effect for a PCORC filing; and


•	Establishing a five-year moratorium on changes to the PCA/PCORC.

PSE had an unfavorable PCA imbalance for the three and nine months ended September 30, 2015, which was $9.8 million and $14.8 million, respectively, above the “power cost baseline” level, of which no amount was apportioned to customers. This compares to an unfavorable imbalance for the three months ended September 30, 2014 of $9.8 million of which $4.1 million was apportioned to customers, and an unfavorable imbalance for the nine months ended September 30, 2014 of $24.1 million of which $4.1 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)
Decoupling rate filing	May 1, 2015	2.6	%	$	53.8
PCORC	December 1, 2014	(0.9	)	(19.4		)
Conservation rider	May 1, 2014	0.6		12.2
Decoupling rate filing	May 1, 2014	0.5		10.6
Property tax tracker	May 1, 2014	0.5		11.0

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 GRC.

Natural Gas Rates

PSE has a PGA mechanism that allows PSE to recover expected natural gas supply and transportation costs and defer, as a receivable or liability, any natural gas supply and transportation costs that exceed or fall short of this expected natural gas cost amount in PGA mechanism rates, including accrued interest. PSE is authorized by the Washington Commission to accrue carrying costs on PGA receivable and payable balances. A receivable balance in the PGA mechanism reflects an under-recovery of natural gas cost through rates.

On September 18, 2015, PSE filed its PGA natural gas tariff filing with an effective date of November 1, 2015, which reflected changes in wholesale natural gas and pipeline transportation costs and changes in deferral amortization rates. The impact to the PGA rates is an annual revenue decrease of $185.9 million, or 17.4%, with no impact on net operating income.

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)
Purchased gas adjustment	November 1, 2015	(17.4	)%	$	(185.9	)
Decoupling rate filing	May 1, 2015	2.1		22.0
Purchased gas adjustment	November 1, 2014	2.5		23.3
Decoupling rate filing	May 1, 2014	(0.1	)	(1.0		)
Property tax tracker	May 1, 2014	0.6		5.6

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 GRC.

Other Factors and Trends

Weather Conditions. Weather conditions in PSE's service territory have an 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 also 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 nine months ended September 30, 2015, 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 nine months ended September 30, 2015 was 58.44 degrees, or 1.31 degrees warmer than the same period in the prior year, and 3.66 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 natural gas operations, are expected to 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 natural gas operating revenues related to electric transmission and distribution, natural 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 natural 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 recover or refund the difference between allowed decoupling revenue and the corresponding actual revenue to affected customers during the following May to April time period.

Customer Demand. PSE expects the number of natural gas customers to grow at rates slightly above that 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 mature in 2019 and Puget Energy's senior secured credit facility matures in 2018. (See discussion on credit facilities in Item 2, “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 by-products 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 on measures including, but not limited to, resource planning, remediation, monitoring, pollution control equipment and emissions-related abatement and fees.

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. In PSE's draft Integrated Resource Plan (IRP), final to be filed with the Washington Commission on November 30, 2015, PSE projects that beginning in 2021 its future energy needs will exceed current resources in its supply portfolio. The IRP identifies declining regional surpluses, 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. Therefore, PSE, for the first time, explicitly incorporated physical risk in the wholesale markets into the Company's needs assessment.

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. The 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.

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.

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:



Puget Sound Energy	Three Months Ended September 30,								Nine Months Ended September 30,
(Dollars in Thousands)	2015			2014			Favorable/ (Unfavorable)		2015			2014			Favorable/ (Unfavorable)
Operating revenue:
Electric
Residential sales	$	222,619		$	200,640		11.0	%	$	728,988		$	753,496		(3.3	)%
Commercial sales	215,621			208,203			3.6		636,350			624,486			1.9
Industrial sales	28,810			27,981			3.0		84,570			81,466			3.8
Other retail sales	4,970			4,071			22.1		15,204			14,001			8.6
Total retail sales	472,020			440,895			7.1		1,465,112			1,473,449			(0.6	)
Transportation sales	2,949			2,764			6.7		7,478			7,133			4.8
Sales to other utilities and marketers	18,642			10,427			78.8		30,911			31,049			(0.4	)
Decoupling revenue	(12,050		)	2,797			*		13,891			28,967			(52.0	)
Other	1,225			11,647			(89.5	)	8,637			37,065			(76.7	)
Total electric operating revenue	482,786			468,530			3.0		1,526,029			1,577,663			(3.3	)
Natural gas
Residential sales	69,836			64,616			8.1		398,090			439,418			(9.4	)
Commercial sales	41,006			38,266			7.2		188,728			197,444			(4.4	)
Industrial sales	3,680			3,993			(7.8	)	15,858			17,872			(11.3	)
Total retail sales	114,522			106,875			7.2		602,676			654,734			(8.0	)
Transportation sales	4,478			4,150			7.9		13,728			12,595			9.0
Decoupling revenue	(2,674		)	7,112			(137.6	)	27,087			15,205			78.1
Other	3,256			3,265			(0.3	)	9,894			10,246			(3.4	)
Total natural gas operating revenue	119,582			121,402			(1.5	)	653,385			692,780			(5.7	)
Non-utility operating revenue	3,545			4,019			(11.8	)	11,683			11,799			(1.0	)
Total operating revenue	605,913			593,951			2.0		2,191,097			2,282,242			(4.0	)
Operating expenses:
Energy costs
Purchased electricity	97,694			67,984			(43.7	)	355,645			363,769			2.2
Electric generation fuel	76,863			92,510			16.9		180,531			202,741			11.0
Residential exchange	(19,530		)	(30,963		)	(36.9	)	(92,297		)	(84,587		)	9.1
Purchased natural gas	46,436			42,550			(9.1	)	282,334			310,128			9.0
Net unrealized (gain) loss on derivative instruments	5,588			32,648			82.9		(5,795		)	8,284			170.0
Utility operations and maintenance	131,208			132,109			0.7		400,355			411,068			2.6
Non-utility expense and other	5,605			5,899			5.0		18,953			17,451			(8.6	)
Depreciation and amortization	107,759			105,905			(1.8	)	314,348			312,821			(0.5	)
Conservation amortization	24,224			23,047			(5.1	)	78,389			74,554			(5.1	)
Taxes other than income taxes	64,030			59,945			(6.8	)	228,942			228,534			(0.2	)
Total operating expenses	539,877			531,634			(1.6	)	1,761,405			1,844,763			4.5
Operating income (loss)	66,036			62,317			6.0		429,692			437,479			(1.8	)
Other income	4,731			10,953			(56.8	)	14,770			19,815			(25.5	)
Other expense	(1,621		)	(1,806		)	10.2		(4,843		)	(5,032		)	3.8
Interest charges	(58,629		)	(67,565		)	13.2		(181,348		)	(194,563		)	6.8
Income (loss) before income taxes	10,517			3,899			169.7		258,271			257,699			0.2
Income tax (benefit) expense	641			842			23.9		76,596			75,726			(1.1	)
Net income (loss)	$	9,876		$	3,057		*		$	181,675		$	181,973		(0.2	)%

_______________


^*	Percent change not applicable or meaningful.

NON-GAAP FINANCIAL MEASURES - Electric and Natural Gas Margins

The following discussion includes financial information prepared in accordance with U.S. Generally Accepted Accounting Principles (GAAP), as well as two other financial measures, electric margin and natural 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 natural gas margin is intended to supplement an understanding of PSE's operating performance. Electric margin and natural 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 natural gas margin measures may not be comparable to other companies' electric margin and natural 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 September 30,								Nine Months Ended September 30,
(Dollars in Thousands)	2015			2014			Favorable/ (Unfavorable)		2015			2014			Favorable/ (Unfavorable)
Electric operating revenue:
Residential sales	$	222,619		$	200,640		11.0	%	$	728,988		$	753,496		(3.3	)%
Commercial sales	215,621			208,203			3.6		636,350			624,486			1.9
Industrial sales	28,810			27,981			3.0		84,570			81,466			3.8
Other retail sales	4,970			4,071			22.1		15,204			14,001			8.6
Total retail sales	472,020			440,895			7.1		1,465,112			1,473,449			(0.6	)
Transportation sales	2,949			2,764			6.7		7,478			7,133			4.8
Sales to other utilities and marketers	18,642			10,427			78.8		30,911			31,049			(0.4	)
Decoupling revenue	(12,050		)	2,797			*		13,891			28,967			(52.0	)
Other	1,225			11,647			(89.5	)	8,637			37,065			(76.7	)
Total electric operating revenues¹	482,786			468,530			3.0		1,526,029			1,577,663			(3.3	)
Minus electric energy costs:
Purchased electricity¹	97,694			67,984			(43.7	)	355,645			363,769			2.2
Electric generation fuel¹	76,863			92,510			16.9		180,531			202,741			11.0
Residential exchange¹	(19,530		)	(30,963		)	(36.9	)	(92,297		)	(84,587		)	9.1
Total electric energy costs	155,027			129,531			(19.7	)	443,879			481,923			7.9
Electric margin²	$	327,759		$	338,999		(3.3	)%	$	1,082,150		$	1,095,740		(1.2	)%

______________


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


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


^*	Percent change not applicable or meaningful.

Electric margin decreased $11.2 million and $13.5 million, or 3.3% and 1.2%, to $327.8 million and $1,082.2 million from $339.0 million and $1,095.7 million for the three and nine months ended September 30, 2015, respectively, as compared to the same period in 2014. The 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 $14.3 million, or 3.0%, to $482.8 million from $468.5 million for the three months ended September 30, 2015 as compared to the same period in 2014. The increase in operating revenues was primarily due to higher residential sales of $22.0 million and sales to other utilities and marketers of $8.2 million, partially offset by a decrease in decoupling revenue of $14.8 million. These items are discussed in more detail below.

Electric operating revenues decreased $51.7 million, or 3.3%, to $1,526.0 million from $1,577.7 million for the nine months ended September 30, 2015 as compared to the same period in 2014. The decrease in operating revenues was primarily due to lower non-core gas sales of $19.0 million, lower decoupling revenue of $15.1 million, and lower electric retail sales of $8.3 million. These items are discussed in more detail below.

Electric retail sales increased $31.1 million, or 7.1%, to $472.0 million from $440.9 million for the three months ended September 30, 2015 as compared to the same period in 2014. The increase in electric retail sales primarily resulted from a rate increase of $30.2 million during the three months ended September 30, 2015 as compared to the same period in the prior year.

Electric retail sales decreased $8.3 million, or 0.6%, to $1,465.1 million from $1,473.4 million for the nine months ended September 30, 2015 as compared to the same period in 2014. The decrease in electric retail sales primarily resulted from $21.7 million due to lower retail electricity usage of 221,966 Megawatt Hours (MWhs), or 1.5% and a credit related to Jefferson County gain to customers of $6.5 million, which was partially offset by a rate increase of $19.8 million during the nine months ended September 30, 2015 as compared to the same period in the prior year.

Sales to other utilities and marketers increased $8.2 million, or 78.8%, to $18.6 million from $10.4 million for the three months ended September 30, 2015 as compared to the same period in 2014. The increase was primarily driven by a $12.2 million increase related to higher sales volumes partially offset by a $4.0 million decrease related to lower wholesale prices for the three months ended September 30, 2015 as compared to the same prior year period.

Decoupling revenue decreased $14.8 million due to $3.6 million reduction in decoupling revenue from an increase in retail sales from higher than normal temperatures, amortization of prior year decoupling revenue of $6.1 million and excess earnings over the rate of return of $5.1 million for the three months ended September 30, 2015 as compared to the same period in the prior year.

Decoupling revenue decreased $15.1 million due to amortization of prior year decoupling revenue of $4.9 million, excess earnings over the rate of return of $5.2 million, as well as a reduction in decoupling revenue of $5.0 million for the nine months ended September 30, 2015 as compared to the same period in the prior year. The 2015 decoupling revenue does not include the excess over the rate of return, which will be given back to customers in 2016. The 2015 decoupling receivable will be recovered from customers through a future rate filing beginning May 1, 2016.

Other electric operating revenue decreased $10.4 million, or 89.5%, to $1.2 million from $11.6 million for the three months ended September 30, 2015 as compared to the same period in 2014. The decrease was primarily the result of a decrease of $3.9 million due to lower non-core gas sales.

Other electric operating revenue decreased $28.5 million, or 76.7%, to $8.6 million from $37.1 million for the nine months ended September 30, 2015 as compared to the same period in 2014. The decrease was primarily the result of lower non-core gas sales of $19.0 million.

Electric Energy Costs

Purchased electricity expense increased $29.7 million, or 43.7%, to $97.7 million from $68.0 million for the three months ended September 30, 2015 as compared to the same period in 2014. The increase was primarily the result of an $18.0 million increase related to a new purchase power contract, $5.4 million related to higher secondary purchases and no sharing of power costs in 2015.

Purchased electricity expense decreased $8.2 million, or 2.2%, to $355.6 million from $363.8 million for the nine months ended September 30, 2015 as compared to the same period in 2014. The decrease was primarily the result of a $59.2 million decrease in secondary purchases, which was partially offset by a $52.7 million increase in a new purchase power contract.

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 $15.6 million, or 16.9%, to $76.9 million from $92.5 million for the three months ended September 30, 2015 as compared to the same period in 2014. The decrease was primarily due to a $15.9 million decrease in fuel expense at PSE's combustion turbine facilities due to lower prices of natural gas, partially offset by higher production of 128,436 MWhs.

Electric generation fuel expense decreased $22.2 million, or 11.0%, to $180.5 million from $202.7 million for the nine months ended September 30, 2015 as compared to the same period in 2014. The decrease was primarily due to a $21.3 million decrease in fuel expense at PSE's combustion turbine facilities due to lower prices of natural gas which was offset by an increase in production at PSE's combustion turbine facilities of 895,752 MWhs.

Residential exchange credits decreased $11.5 million, or 36.9%, to $19.5 million from $31.0 million for the three months ended September 30, 2015 as compared to the same period in 2014 as a result of warmer temperatures, lower electric retail sales and higher Residential Exchange Program (REP) tariff prices associated with the Bonneville Power Administration (BPA) REP for the period June 1, 2014 through May 31, 2015. The REP credit is a pass-through tariff item with a corresponding credit in electric operating revenue, with no impact on net income.

Residential exchange credits increased $7.7 million, or 9.1%, to $92.3 million from $84.6 million for the nine months ended September 30, 2015 as compared to the same period in 2014 as a result of higher REP tariff prices associated with the BPA REP for the period June 1, 2014 through May 31, 2015. 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

Natural 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 September 30,							Nine Months Ended September 30,
(Dollars in Thousands)	2015			2014		Favorable/ (Unfavorable)		2015		2014		Favorable/ (Unfavorable)
Natural gas operating revenue:
Residential sales	$	69,836		$	64,616	8.1	%	$	398,090	$	439,418	(9.4	)%
Commercial sales	41,006			38,266		7.2		188,728		197,444		(4.4	)
Industrial sales	3,680			3,993		(7.8	)	15,858		17,872		(11.3	)
Total retail sales	114,522			106,875		7.2		602,676		654,734		(8.0	)
Transportation sales	4,478			4,150		7.9		13,728		12,595		9.0
Decoupling revenue	(2,674		)	7,112		(137.6	)	27,087		15,205		78.1
Other	3,256			3,265		(0.3	)	9,894		10,246		(3.4	)
Total natural gas operating revenues¹	119,582			121,402		(1.5	)	653,385		692,780		(5.7	)
Minus purchased natural gas energy costs¹	46,436			42,550		(9.1	)	282,334		310,128		9.0
Natural gas margin²	$	73,146		$	78,852	(7.2	)%	$	371,051	$	382,652	(3.0	)%

______________


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


²	Natural gas margin does not include any allocation for amortization/depreciation expense or natural gas operations and maintenance expense.

Natural gas margin decreased $5.7 million and $11.6 million, or 7.2% and 3.0%, to $73.1 million and $371.1 million from $78.9 million and $382.7 million for the three and nine months ended September 30, 2015 as compared to the same period in 2014. The following is a discussion of significant items of natural gas operating revenue and natural gas energy costs which are included in gas margin:

Natural Gas Operating Revenue

Natural gas operating revenues decreased $1.8 million, or 1.5%, to $119.6 million from $121.4 million for the three months ended September 30, 2015 as compared to the same period in 2014. The decrease was due to lower decoupling revenue, which was partially offset by an increase in natural gas retail sales, as discussed in more detail below.

Natural gas operating revenues decreased $39.4 million, or 5.7%, to $653.4 million from $692.8 million for the nine months ended September 30, 2015 as compared to the same period in 2014. The decrease was due to lower natural gas retail sales, which was partially offset by an increase in decoupling revenue, as discussed in more detail below.

Natural gas retail sales increased $7.6 million, or 7.2%, to $114.5 million from $106.9 million for the three months ended September 30, 2015 as compared to the same period in 2014. The increase was primarily due to higher natural gas therm sales of $4.8 million, or 4.5%, and due to a rate increase of $2.8 million attributed to a PGA rate increase effective November 1, 2014 and decoupling rate filings.

Natural gas retail sales decreased $52.0 million, or 8.0%, to $602.7 million from $654.7 million for the nine months ended September 30, 2015 as compared to the same period in 2014. The decrease was primarily due to an $84.4 million, or 12.9%, reduction in natural gas therm sales due to warmer weather during nine months ended September 30, 2015 , which was offset by rate increases of $32.3 million attributed to a PGA rate increase effective November 1, 2014 and decoupling rate filings.

Decoupling revenue decreased $9.8 million for the three months ended September 30, 2015 as compared to the same period in the prior year primarily due to a reduction of $8.3 million related to excess earnings over the rate of return, which is shared with customers. PSE is limited to a 3.0% annual decoupling rate increase which resulted in not recognizing $5.0 million of natural gas decoupling revenues which will not be collected within 24 months. PSE will record the decoupling revenue once it meets the 24-month collection period under GAAP or when collected from customers. The 2015 decoupling receivable will be recovered from customers through a future rate filing beginning May 1, 2016 and 2017.

Decoupling revenue increased $11.9 million due to $23.3 million reduction in decoupling revenue from lower volumetric sales as a result of warmer than normal weather, which was partially offset by a reduction of $10.2 million related to excess earnings over the rate of return, which is shared with customers for the nine months ended September 30, 2015 as compared to the same period in 2014. PSE did not recognize $5.0 million of decoupling revenue that will not be collected within a 24-month period due to excess earning over PSE's rate of return. The 2015 decoupling receivable will be recovered from customers through a future rate filing beginning May 1, 2016 and 2017.

Natural Gas Energy Costs

Purchased natural gas expenses increased $3.8 million, or 9.1%, to $46.4 million from $42.6 million for the three months ended September 30, 2015 as compared to the same period in 2014. The increase was primarily due to PGA deferral commodity costs and amortization of $12.4 million, which was partially offset by a decrease in natural gas purchases of $11.1 million.

Purchased natural gas expenses decreased $27.8 million, or 9.0%, to $282.3 million from $310.1 million for the nine months ended September 30, 2015 as compared to the same period in 2014. The decrease was primarily due to a reduction in customer usage of 12.9%, offset by an increase in PGA rates of $23.3 million, annually, that were effective November 1, 2014.

The PGA mechanism provides the rates used to determine natural gas costs based on customer usage. 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 under-recovery of natural gas cost through rates. A payable balance reflects over-recovery of natural gas cost through rates. The PGA mechanism payable balance at September 30, 2015 was $8.3 million.

Other Operating Expenses

Net unrealized loss on derivative instruments decreased $27.0 million, or 82.9%, to $5.6 million from $32.6 million for the three months ended September 30, 2015 as compared to the same period in 2014. The decrease was due to settlements of $20.6 million and an increase in wholesale forward commodity prices of $6.5 million.

Net unrealized gain on derivative instruments increased $14.1 million, or 170.0%, to a gain of $5.8 million from a loss of $8.3 million for the nine months ended September 30, 2015 as compared to the same period in 2014. The increase was due to settlements of $73.8 million, partially offset by a decrease in wholesale forward commodity prices of $59.8 million.

Utility operations and maintenance expense decreased $10.7 million, or 2.6%, to $400.4 million from $411.1 million for the nine months ended September 30, 2015 as compared to the same period in 2014. The decrease was primarily driven by a decrease in customer service expenses, primarily related to $7.1 million in uncollectible accounts expense and $3.3 million in meter reading expense.

Taxes other than income tax increased $4.1 million, or 6.8%, to $64.0 million from $59.9 million for the three months ended September 30, 2015 as compared to the same period in 2014. The increase was primarily due to an increase in state excise and municipal taxes for electric utilities.

Other income decreased $6.3 million, or 56.8%, to $4.7 million from $11.0 million for the three months ended September 30, 2015 as compared to the same period in 2014. The decrease was primarily due to a gain of $7.5 million for the JPUD sale that was recorded in three months ended September 30, 2014.

Other income decreased $5.0 million, or 25.5%, to $14.8 million from $19.8 million for the nine months ended September 30, 2015 as compared to the same period in 2014. The decrease was primarily due to a gain of $7.5 million for the JPUD sale that was recorded in nine months ended September 30, 2014.

Interest expense decreased $9.0 million, or 13.2%, to $58.6 million from $67.6 million due to a reduction of regulatory interest expense on regulatory liabilities for the three months ended September 30, 2015 as compared to the same period in 2014.

Interest expense decreased $13.3 million, or 6.8%, to $181.3 million from $194.6 million for the nine months ended September 30, 2015 as compared to the same period in 2014. The decrease was due to a reduction of regulatory interest expense on regulatory liabilities in 2015 as compared to the same period in 2014.

Puget Energy

All the operations of Puget Energy are conducted through its subsidiary PSE. Puget Energy's net income (loss) for the three and nine months ended September 30, 2015, and the same period in 2014 are as follows:



Benefit/(Expense)	Three Months Ended September 30,								Nine Months Ended September 30,
(Dollars in Thousands)	2015			2014			Percent Change		2015			2014			Percent Change
PSE net income	$	9,876		$	3,057		*		$	181,675		$	181,973		(0.2	)%
Other operating revenue	—			(235		)	100.0		—			(235		)	100.0
Net unrealized gain on energy derivative instruments	—			—			—		544			570			(4.6	)
Non-utility expense and other	3,853			2,987			29.0		11,659			8,823			32.1
Unhedged interest rate swap (expense)	(1,156		)	(322		)	*		(4,571		)	(2,428		)	(88.3	)
Interest expense ¹	(28,022		)	(24,217		)	(15.7	)	(80,874		)	(76,933		)	(5.1	)
Income tax benefit (expense)	7,521			5,772			30.3		24,931			23,977			4.0
Puget Energy net income (loss)	$	(7,928	)	$	(12,958	)	38.8	%	$	133,364		$	135,747		(1.8	)%

_______________


^*	Percent change not applicable or meaningful.


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

Puget Energy's net loss for the three months ended September 30, 2015 was $7.9 million with operating revenue of $605.7 million as compared to a net loss of $13.0 million with operating revenue of $593.7 million for the same period in 2014. Puget Energy's net income for the nine months ended September 30, 2015 was $133.4 million with operating revenue of $2.2 billion as compared to a net income of $135.7 million with operating revenue of $2.3 billion for the same period in 2014. In addition to the items discussed above regarding PSE, which also impacted Puget Energy's net income, Puget Energy holds an additional $1.6 billion in long term debt (net of discount), resulting in additional interest expense as shown above.

Capital Requirements

Contractual Obligations and Commercial Commitments

There have been no material changes to the contractual obligations and consolidated commercial commitments set forth in Part II, Item 7 in the Company's Annual Report on Form 10-K for the year ended December 31, 2014.

On May 12, 2015, Puget Energy issued $400.0 million of senior secured notes, and on May 26, 2015, PSE issued $425.0 million of senior notes secured by first mortgage bonds. The net proceeds of these issuances were used to pay down existing long-term debt, as described in more detail elsewhere in this Quarterly Report on Form 10-Q and therefore did not materially impact the contractual obligations and consolidated commercial commitments as previously set forth in Part II, Item 7 in the Company's combined Annual Report on Form 10-K for the year ended December 31, 2014.

The following are the Company's aggregate availability under commercial commitments as of September 30, 2015:



Puget Sound Energy and Puget Energy	Amount of Available Commitments Expiration Per Period
(Dollars in Thousands)	Total			2015		2016-2018		2019-2020		Thereafter
PSE liquidity facility ¹	$	650,000		$	—	$	—	$	650,000	$	—
PSE energy hedging facility ¹	350,000			—		—		350,000		—
Inter-company short-term debt ²	30,000			—		—		—		30,000
Total PSE commercial commitments	$	1,030,000		$	—	$	—	$	1,000,000	$	30,000
Puget Energy revolving credit facility ³	800,000			—		800,000		—		—
Less: Inter-company short-term debt elimination ²	(30,000		)	—		—		—		(30,000		)
Total Puget Energy commercial commitments	$	1,800,000		$	—	$	800,000	$	1,000,000	$	—

_______________

As of September 30, 2015, PSE had credit facilities totaling $1.0 billion which will mature in April 2019. 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 September 30, 2015, no loans or letters of credit were outstanding under the PSE energy hedging facility, no loans or letters of credit were outstanding under the PSE liquidity facility and $79.5 million was outstanding under the commercial paper program. The credit agreements are syndicated among numerous lenders. Outside of the credit agreements, PSE had a $3.9 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.


²	As of September 30, 2015, PSE had a revolving credit facility with Puget Energy in the form of a promissory note to borrow up to $30.0 million. On June 30, 2015 PSE repaid in full the outstanding balance under the note of $28.9 million.

As of September 30, 2015, Puget Energy had a revolving credit facility totaling $800.0 million, which matures in April 2018. The revolving credit facility is syndicated among numerous lenders. The revolving credit facility also has an accordion feature that, upon the banks' approval, would increase the size of the facility to $1.3 billion. As of September 30, 2015, no amount was outstanding under the Puget Energy credit facility.

Utility Construction Program

PSE’s construction programs for generating facilities, the electric transmission system and the natural gas and electric distribution systems are designed to meet regulatory requirements and customer growth and to support reliable energy delivery. Construction expenditures, excluding equity allowance for funds used during construction (AFUDC), were $419.4 million for the nine months ended September 30, 2015. Presently planned utility construction expenditures, excluding AFUDC, are as follows:



Capital Expenditure Projections
(Dollars in Thousands)	2015		2016		2017
Total energy delivery, technology and facilities expenditures	$	593,606	$	671,060	$	674,555

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 nine months ended September 30, 2015 was $533.3 million, a decrease of $144.0 million from $677.3 million generated during the nine months ended September 30, 2014. The decrease was primarily the result of a $172.6 million decrease in the collection of accounts receivable, a $28.3 million decrease in other liabilities and a $25.2 million decrease in regulatory assets cash flow, partially offset by a $67.8 million increase in cash flow related to a PGA rate increase effective November 1, 2014 and a $33.0 million increase related to regulatory liabilities.

Puget Energy. Cash generated from operations for the nine months ended September 30, 2015 was $466.0 million, a decrease of $139.2 million from $605.2 million generated during the nine months ended September 30, 2014. The net decrease was primarily impacted by $144.0 million from cash used in the operating activities of PSE, as previously discussed.

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. The Company believes there is sufficient liquidity to fund its needs over the next twelve months.

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, 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 September 30, 2015, PSE was in compliance with all applicable covenant ratios.

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 London Interbank Offered Rate (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 September 30, 2015, no amounts were drawn under either PSE's $650.0 million liquidity facility or PSE's $350.0 million energy hedging facility. No letters of credit were outstanding under either facility, and $79.5 million was outstanding under the commercial paper program. Outside of the credit agreements, PSE had a $3.9 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 or PSE's senior unsecured revolving credit facility. Absent such borrowings, interest is charged at one-month LIBOR plus 0.25%. On June 30, 2015, PSE repaid in full the $28.9 million outstanding balance under the Note.

Puget Energy Credit Facilities. At September 30, 2015, Puget Energy maintained an $800.0 million revolving senior secured credit facility. In April 2014, 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 September 30, 2015, 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 for more details).

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 September 30, 2015, 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, equaled $299.0 million. The proceeds of the term loans were used to pay off the outstanding Puget Energy revolving credit facility balance, which subsequently allows the Company to carry the debt with lower interest expense. On May 12, 2015, Puget Energy issued $400.0 million of senior secured notes and utilized the net proceeds to repay the three term loans in full.

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 September 30, 2015, approximately $441.0 million of unrestricted retained earnings was available for the payment of dividends under the most restrictive mortgage indenture covenant.

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 September 30, 2015 and the EBITDA to interest expense was 4.5 to one for the twelve months ended September 30, 2015.

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 3.2 to one for the twelve months ended September 30, 2015.

At September 30, 2015, 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, as of September 30, 2015, PSE could issue:


•	Approximately $2.2 billion of additional first mortgage bonds under PSE's electric mortgage indenture based on approximately $3.7 billion of electric bondable property available for issuance, subject to an interest coverage ratio limitation of 2.0 times net earnings available for interest (as defined in the electric utility mortgage), which PSE exceeded at September 30, 2015; and

•

Approximately $331 million of additional first mortgage bonds under PSE's natural gas mortgage indenture based on approximately $551.7 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 September 30, 2015.

At September 30, 2015, PSE had approximately $6.9 billion in electric and natural gas rate base to support the interest coverage ratio limitation test for net earnings available for interest.

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 September 30, 2015.

Shelf Registrations and Long-Term Debt Activity

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

On May 26, 2015, PSE issued $425.0 million of senior notes secured by first mortgage bonds. The notes mature in May 2045 and have an interest rate of 4.30%, which is payable semi-annually in May and November. Net proceeds of the issuance were used to fund the early retirement, including accrued interest and make-whole call premiums, of the Company's $150.0 million 5.197% senior notes maturing in October 2015 and the Company's $250.0 million 6.75% senior notes maturing in January 2016.

Puget Energy. On May 12, 2015, Puget Energy issued $400.0 million of senior secured notes. The notes mature in May 2025 and have an interest rate of 3.65%, which is payable semi-annually in May and November. Net proceeds of the issuance were used to repay all amounts outstanding under Puget Energy's three term loans, and to fund a special dividend to shareholders of approximately $96.7 million.

Other

New Accounting Pronouncements

For the discussion of new accounting pronouncements, see Note 2 in the Combined Notes to the Consolidated Financial Statements in Part I.

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, the Sierra Club and the Montana Environmental Information Center filed a Clean Air Act citizen suit against all Colstrip owners in the U.S. District Court, District of Montana. Based on a second amended complaint filed in August 2014, Plaintiffs' lawsuit currently alleges violations of permitting requirements under the New Source Review program of the Clean Air Act and the Montana State Implementation Plan arising from seven projects undertaken at Colstrip during 2001-2012. Plaintiffs have since indicated that they do not intend to pursue three of the seven projects, leaving a total of four projects remaining. The lawsuit claims that, for each project, the Colstrip plant should have obtained a permit and installed pollution control equipment at Colstrip. The Plaintiffs' complaint also seeks civil penalties and other appropriate relief. The case has been bifurcated into separate liability and remedy trials. The liability trial is currently set for March 2016, and a date for the remedy trial has yet to be determined. PSE is litigating the allegations set forth in the complaint, and as such, it is not reasonably possible to estimate the outcome of this matter.

Coal Combustion Residuals

The CCR rule requires significant changes to the Company’s Colstrip operations and those changes were reviewed by the Company and the plant operator in the second quarter of 2015. PSE had previously recognized a legal obligation under EPA rules to dispose of coal ash material at Colstrip, in 2003. Due to the CCR rule, additional disposal costs were added to the ARO.

EPA Draft Rule 111(d)

In June 2014, the EPA issued a proposed Clean Power Plan 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. PSE filed comments on this rule in December 2014. The EPA issued a pre-publication version of the final Clean Power Plan rule under Section 111(d) on August 3, 2015. To date the rule has not yet been published in the Federal Register, so the effective date has not yet been triggered. PSE is reviewing the final rule and working with key stakeholders in preparation towards implementation. PSE cannot yet provide a determination of how the final rule may impact PSE or its existing generation facilities, if at all.

Related Party Transactions

Item 3. Quantitative and Qualitative Disclosure about Market Risk

The Company is exposed to various forms of market risk, consisting primarily of fluctuations in commodity prices, counterparty credit risk, as well as interest rate risk. PSE maintains risk policies and procedures to help manage the various risks. There have been no material changes to market risks affecting the Company from those set forth in Part II, Item 7A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2014.

Commodity Price Risk

The nature of serving regulated electric and natural gas customers with its portfolio of owned and contracted electric generation resources exposes PSE and its customers to some volumetric and commodity price risks. PSE’s Energy Management Committee (EMC) establishes energy risk management policies and procedures to manage commodity and volatility risks and the related effects on credit, tax, accounting, financing and liquidity.

PSE's objective is to minimize commodity price exposure and risks associated with volumetric variability in the natural gas and electric portfolios. 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.

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 counterparty analysis and measurement, monitoring and mitigation of exposure. Additionally, PSE has entered into commodity master arrangements (i.e., WSPP, Inc. (WSPP), International Swaps and Derivatives Association (ISDA) or North American Energy Standards Board (NAESB)) with its counterparties to mitigate credit exposure to those counterparties.

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 swaps or other financial hedge instruments to manage the interest rate risk associated with the debt.

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 September 30, 2015, 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 September 30, 2015, 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

Contingencies arising out of the Company's normal course of business existed as of September 30, 2015. Litigation is subject to numerous uncertainties and the Company is unable to predict the ultimate outcome of these matters. For details on legal proceedings, see Note 8 in the Combined Notes to Consolidated Financial Statements in Part I.

Item 1A. Risk Factors

There have been no material changes from the risk factors set forth in Part I, Item 1A of the Company's Annual Report on Form 10-K for the period ended December 31, 2014.

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:	November 4, 2015	Officer duly authorized to sign this report on behalf of each registrant

EXHIBIT INDEX



3(i).1	Amended Articles of Incorporation of Puget Energy (incorporated herein by reference to Exhibit 3.1 to Puget Energy’s Current Report on Form 8-K, dated February 6, 2009, Commission File No. 1-16305).
3(i).2	Amended and Restated Articles of Incorporation of Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit 3.2 to Puget Sound Energy’s Current Report on Form 8-K, dated February 6, 2009, Commission File No. 1-4393).
3(ii).1	Amended and Restated Bylaws of Puget Energy dated February 6, 2009 (incorporated herein by reference to Exhibit 3.3 to Puget Energy’s Current Report on Form 8-K, Commission File No. 1-16305).
3(ii).2	Amended and Restated Bylaws of Puget Sound Energy, Inc. dated February 6, 2009 (incorporated herein by reference to Exhibit 3.4 to Puget Sound Energy’s Current Report on Form 8-K, Commission File No. 1-4393).
12.1*	Statement setting forth computation of ratios of earnings to fixed charges of Puget Energy, Inc. (2010 through 2014 and 12 months ended September 30, 2015).
12.2*	Statement setting forth computation of ratios of earnings to fixed charges of Puget Sound Energy, Inc. (2010 through 2014 and 12 months ended September 30, 2015).
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 September 30, 2015, filed on November 4, 2015 formatted in XBRL: (i) the Consolidated Statement of Income (Unaudited), (ii) the Consolidated Statements of Comprehensive Income (Unaudited), (iii) the Consolidated Balance Sheets (Unaudited), (iv) the Consolidated Statements of Cash Flows (Unaudited), and (v) the Notes to Consolidated Financial Statements (submitted electronically herewith).

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*	Filed herewith.