Puget Energy (PSD) 10-Q 2011 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2011

OR

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

For the Transition period from ________ to ________

Commission File Number	Exact name of registrant as specified in its charter, state of incorporation, address of principal executive offices, telephone number	I.R.S. Employer Identification Number
1-16305	PUGET ENERGY, INC. A Washington Corporation 10885 NE 4th Street, Suite 1200 Bellevue, Washington 98004-5591 (425) 454-6363	91-1969407
1-4393	PUGET SOUND ENERGY, INC. A Washington Corporation 10885 NE 4th 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

Part I.	Financial Statements
	Puget Energy, Inc.
	Consolidated Statements of Income – Three and Nine Months Ended September 30, 2011 and 2010
	Consolidated Statements of Comprehensive Income – Three and Nine Months Ended September 30, 2011 and 2010
	Consolidated Balance Sheets – September 30, 2011 and December 31, 2010
	Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2011 and 2010
	Puget Sound Energy, Inc.
	Consolidated Statements of Income – Three and Nine Months Ended September 30, 2011 and 2010
	Consolidated Statements of Comprehensive Income – Three and Nine Months Ended September 30, 2011 and 2010
	Consolidated Balance Sheets – September 30, 2011 and December 31, 2010
	Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2011 and 2010
	Notes
	Combined Notes to Consolidated Financial Statements
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3.	Quantitative and Qualitative Disclosure About Market Risk
Item 4.	Controls and Procedures
Part II.	Other Information
Item 1.	Legal Proceedings
Item 1A.	Risk Factors
Item 6.	Exhibits

DEFINITIONS

AFUDC	Allowance for Funds Used During Construction
ASC	Accounting Standards Codification
BPA	Bonneville Power Administration
EBITDA	Earnings Before Interest, Tax, Depreciation and Amortization
FERC	Federal Energy Regulatory Commission
GAAP	U.S. Generally Accepted Accounting Principles
IRP	Integrated Resource Plan
IRS	Internal Revenue Service
ISDA	International Swaps and Derivatives Association
kW	Kilowatt
kWh	Kilowatt Hour
LIBOR	London Interbank Offered Rate
MMBtus	One Million British Thermal Units
MW	Megawatt (one MW equals one thousand kW)
MWh	Megawatt Hour (one MWh equals one thousand kWh)
NAESB	North American Energy Standards Board
NPNS	Normal Purchase Normal Sale
OCI	Other Comprehensive Income
PCA	Power Cost Adjustment
PGA	Purchased Gas Adjustment
PSE	Puget Sound Energy, Inc.
Puget Energy	Puget Energy, Inc.
Puget Equico	Puget Equico LLC
Puget Holdings	Puget Holdings LLC
PTC	Production Tax Credit
PURPA	Public Utility Regulatory Policies Act
REC	Renewable Energy Credit
REP	Residential Exchange Program
SERP	Supplemental Executive Retirement Plan
VIE	Variable Interest Entity
Washington Commission	Washington Utilities and Transportation Commission

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:

·   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;

·   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;

·   Findings of noncompliance with electric reliability standards developed by the North American Electric Reliability Corporation or the Western Electricity Coordinating Council for users, owners and operators of the power system, which could result in penalties;

·   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;

·   The ability to recover costs arising from changes in enacted federal, state or local tax laws in a timely manner;

·   Changes in tax law, related regulations or differing interpretation or enforcement of applicable law by the Internal Revenue Service (IRS) or other taxing jurisdictions;

·   Inability to realize deferred tax assets and use production tax credits (PTCs) due to insufficient future taxable income;

·   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;

·   Commodity price risks associated with procuring natural gas and power in wholesale markets or counterparties extending credit to PSE without collateral posting requirements;

·   Wholesale market disruption, which may result in a deterioration of market liquidity, increase the risk of counterparty default, affect the regulatory and legislative process in unpredictable ways, negatively affect wholesale energy prices and/or impede PSE’s ability to manage its energy portfolio risks and procure energy supply, affect the availability and access to capital and credit markets and/or impact delivery of energy to PSE from its suppliers;

·   Financial or operational 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;

·   The effect of wholesale market structures (including, but not limited to, regional market designs or transmission organizations) or other related federal initiatives;

·   PSE electric or natural gas distribution system failure, which may impact PSE’s ability to deliver energy supply to its customers;

·   Changes in climate or weather conditions in the Pacific Northwest, which could affect customer usage and PSE’s revenue and expenses;

·   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 the cost of procuring such supplies;

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

·   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;

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

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

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

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

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

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

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

·   The loss of significant customers, changes in the business of significant customers or the condemnation of PSE’s facilities, which may result in changes in demand for PSE’s services;

·   The failure of information systems or the failure to secure information system data, which may impact the operations and cost of PSE’s customer service, generation, distribution and transmission;

·   The impact of acts of God, terrorism, flu pandemic or similar significant events;

·   Capital market conditions, including changes in the availability of capital and interest rate fluctuations;

·   Employee workforce factors, including strikes, work stoppages, availability of qualified employees or the loss of a key executive;

·   The ability to obtain insurance coverage and the cost of such insurance;

·   The ability to maintain effective internal controls over financial reporting and operational processes;

·   Changes in 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

·   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,
	2011			2010			2011			2010
Operating revenue:
Electric	$	458,010		$	489,608		$	1,545,464		$	1,507,549
Gas		139,246			132,571			802,884			664,423
Other		520			650			1,696			2,350
Total operating revenue		597,776			622,829			2,350,044			2,174,322
Operating expenses:
Energy costs:
Purchased electricity		137,674			127,792			545,592			556,788
Electric generation fuel		61,596			96,712			132,705			194,649
Residential exchange		(12,546	)		(15,173	)		(49,521	)		(54,510	)
Purchased gas		63,087			60,284			427,016			343,779
Unrealized (gain) loss on derivative instruments, net		30,193			63,275			(19,920	)		109,183
Utility operations and maintenance		121,049			117,155			362,868			355,569
Non-utility expense and other		2,175			4,207			7,117			11,965
Depreciation		74,062			73,111			222,422			217,765
Amortization		18,562			18,355			54,985			53,011
Conservation amortization		20,438			20,392			76,522			60,874
Taxes other than income taxes		60,823			58,903			236,757			210,304
Total operating expenses		577,113			625,013			1,996,543			2,059,377
Operating income		20,663			(2,184	)		353,501			114,945
Other income (deductions):
Other income		15,089			11,073			43,307			32,887
Other expense		(1,239	)		(1,074	)		(3,472	)		(4,147	)
Non-hedged interest rate derivative expense		(3,395	)		--			(28,855	)		--
Interest charges:
AFUDC		8,764			3,924			20,764			9,832
Interest expense		(96,278	)		(84,473	)		(286,287	)		(244,839	)
Income (loss) before income taxes		(56,396	)		(72,734	)		98,958			(91,322	)
Income tax (benefit) expense		(19,926	)		(34,835	)		22,962			(37,895	)
Net income (loss)	$	(36,470	)	$	(37,899	)	$	75,996		$	(53,427	)

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,
	2011			2010			2011		2010
Net income (loss)	$	(36,470	)	$	(37,899	)	$	75,996	$	(53,427	)
Other comprehensive income (loss):
Net unrealized gain (loss) on interest rate swaps during the period, net of tax		--			(19,761	)		--		(63,338	)
Reclassification of net unrealized loss on interest rate swaps during the period, net of tax		2,802			5,614			22,795		16,588
Net unrealized gain (loss) from pension and postretirement plans, net of tax		2,154			(166	)		1,630		(169	)
Reclassification of net unrealized loss on energy derivative instruments during the period, net of tax		782			2,370			1,146		3,625
Other comprehensive income (loss)		5,738			(11,943	)		25,571		(43,294	)
Comprehensive income (loss)	$	(30,732	)	$	(49,842	)	$	101,567	$	(96,721	)

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

PUGET ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

(Unaudited)

ASSETS

	September 30, 2011			December 31, 2010
Utility plant (including construction work in progress of $1,163,951 and $628,387, respectively):
Electric plant	$	5,888,741		$	5,253,786
Gas plant		2,202,350			2,129,200
Common plant		390,995			318,615
Less: Accumulated depreciation and amortization		(609,646	)		(429,038	)
Net utility plant		7,872,440			7,272,563
Other property and investments:
Goodwill		1,656,513			1,656,513
Investment in exchange power contract		20,278			22,923
Other property and investments		124,733			125,918
Total other property and investments		1,801,524			1,805,354
Current assets:
Cash and cash equivalents		26,086			36,557
Restricted cash		4,261			5,470
Accounts receivable, net of allowance for doubtful accounts of $8,122 and $9,784, respectively		205,916			327,615
Unbilled revenue		100,834			194,088
Purchased gas adjustment receivable		--			5,992
Materials and supplies, at average cost		76,741			85,413
Fuel and gas inventory, at average cost		100,151			96,633
Unrealized gain on derivative instruments		6,876			7,500
Income taxes		12,119			76,183
Prepaid expense and other		37,231			14,835
Power contract acquisition adjustment gain		84,351			134,553
Deferred income taxes		78,075			83,086
Total current assets		732,641			1,067,925
Other long-term and regulatory assets:
Power cost adjustment mechanism		1,106			15,618
Regulatory assets related to power contracts		64,727			116,116
Other regulatory assets		780,402			887,940
Unrealized gain on derivative instruments		10,671			8,233
Power contract acquisition adjustment gain		562,432			624,667
Other		158,876			130,920
Total other long-term and regulatory assets		1,578,214			1,783,494
Total assets	$	11,984,819		$	11,929,336

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

PUGET ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

(Unaudited)

CAPITALIZATION AND LIABILITIES

	September 30, 2011			December 31, 2010
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		(24,171	)		17,024
Accumulated other comprehensive income (loss), net of tax		22,502			(3,069	)
Total common shareholder’s equity		3,307,288			3,322,912
Long-term debt:
First mortgage bonds and senior notes		3,092,000			2,792,000
Pollution control bonds		161,860			161,860
Junior subordinated notes		250,000			250,000
Long-term debt		1,793,000			1,490,000
Debt discount and other		(290,684	)		(311,147	)
Total long-term debt		5,006,176			4,382,713
Total capitalization		8,313,464			7,705,625
Current liabilities:
Accounts payable		239,524			291,148
Short-term debt		119,000			247,000
Current maturities of long-term debt		--			260,000
Accrued expenses:
Purchased gas adjustment liability		11,023			--
Taxes		64,504			81,505
Salaries and wages		34,410			34,453
Interest		66,442			59,182
Unrealized loss on derivative instruments		280,302			273,100
Power contract acquisition adjustment loss		26,274			69,915
Other		78,348			114,409
Total current liabilities		919,827			1,430,712
Long-term and regulatory liabilities:
Deferred income taxes		1,158,745			1,127,611
Unrealized loss on derivative instruments		158,464			183,135
Regulatory liabilities		331,753			305,936
Regulatory liabilities related to power contracts		646,782			759,220
Power contract acquisition adjustment loss		38,597			46,779
Other deferred credits		417,187			370,318
Total long-term and regulatory liabilities		2,751,528			2,792,999
Commitments and contingencies
Total capitalization and liabilities	$	11,984,819		$	11,929,336

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,
	2011			2010
Operating activities:
Net income (loss)	$	75,996		$	(53,427	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation		222,422			217,765
Amortization		54,985			53,011
Conservation amortization		76,522			60,874
Deferred income taxes and tax credits, net		23,391			(78,075	)
Net unrealized (gain) loss on derivative instruments		16,589			109,183
Long-term service prepayment		(27,200	)		--
Pension funding		(5,000	)		(12,000	)
Derivative contracts classified as financing activities due to merger		149,462			279,073
AFUDC – Equity		(22,016	)		(8,529	)
Regulatory assets		37,993			37,838
Regulatory liabilities		11,789			31,453
Other long-term assets		(4,125	)		(30,173	)
Other long-term liabilities		43,424			7,936
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue		214,953			201,486
Materials and supplies		7,481			(20,914	)
Fuel and gas inventory		(3,166	)		(8,405	)
Income taxes		64,064			61,990
Prepayments and other		(22,640	)		(22,127	)
Purchased gas adjustment		17,015			(53,133	)
Accounts payable		(45,553	)		7,958
Taxes payable		(17,001	)		(19,840	)
Accrued expenses and other		24,785			5,912
Net cash provided by operating activities		894,170			767,856
Investing activities:
Construction expenditures – excluding equity AFUDC		(784,608	)		(667,597	)
Energy efficiency expenditures		(57,173	)		(67,165	)
Treasury grant payment received		--			28,675
Restricted cash		1,209			14,231
Other		(5,898	)		2,268
Net cash used in investing activities		(846,470	)		(689,588	)
Financing activities:
Change in short-term debt and leases, net		(131,789	)		(28,059	)
Dividends paid		(117,191	)		(103,206	)
Long-term notes and bonds issued		1,087,000			575,000
Redemption of bonds and notes		(744,000	)		(232,000	)
Derivative contracts classified as financing activities due to merger		(149,462	)		(279,073	)
Issuance cost of bonds and other		(2,729	)		(3,141	)
Net cash provided by (used in) financing activities		(58,171	)		(70,479	)
Net increase (decrease) in cash and cash equivalents		(10,471	)		7,789
Cash and cash equivalents at beginning of period		36,557			78,527
Cash and cash equivalents at end of period	$	26,086		$	86,316
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	222,657		$	208,282
Cash payments (refunds) for income taxes		(64,016	)		(20,622	)

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,
	2011			2010			2011			2010
Operating revenue:
Electric	$	458,010		$	489,608		$	1,545,464		$	1,507,549
Gas		139,246			132,571			802,884			664,423
Other		520			650			2,385			2,350
Total operating revenue		597,776			622,829			2,350,733			2,174,322
Operating expenses:
Energy costs:
Purchased electricity		137,818			127,936			546,025			557,221
Electric generation fuel		61,596			96,712			132,705			194,649
Residential exchange		(12,546	)		(15,173	)		(49,521	)		(54,510	)
Purchased gas		63,087			60,284			427,016			343,779
Unrealized (gain) loss on derivative instruments, net		33,280			78,559			17,649			200,702
Utility operations and maintenance		121,049			117,155			362,868			355,569
Non-utility expense and other		2,409			3,188			8,289			7,742
Depreciation		74,062			73,111			222,422			217,765
Amortization		18,562			18,355			54,985			53,011
Conservation amortization		20,438			20,392			76,522			60,874
Taxes other than income taxes		60,823			58,903			236,757			210,304
Total operating expenses		580,578			639,422			2,035,717			2,147,106
Operating income (loss)		17,198			(16,593	)		315,016			27,216
Other income (deductions):
Other income		15,088			11,033			43,299			32,846
Other expense		(1,239	)		(1,074	)		(3,472	)		(4,147	)
Interest charges:
AFUDC		8,764			3,924			20,764			9,832
Interest expense		(57,379	)		(61,620	)		(171,796	)		(178,323	)
Interest expense on parent note		(29	)		(42	)		(124	)		(152	)
Income (loss) before income taxes		(17,597	)		(64,372	)		203,687			(112,728	)
Income tax (benefit) expense		(8,490	)		(34,813	)		58,442			(45,402	)
Net income (loss)	$	(9,107	)	$	(29,559	)	$	145,245		$	(67,326	)

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,
	2011			2010			2011		2010
Net income (loss)	$	(9,107	)	$	(29,559	)	$	145,245	$	(67,326	)
Other comprehensive income:
Net unrealized gain (loss) from pension and postretirement plans, net of tax		4,107			1,107			7,232		4,018
Reclassification of net unrealized loss on energy derivative instruments during the period, net of tax		2,764			12,253			18,541		38,364
Amortization of financing cash flow hedge contracts to earnings, net of tax		79			79			237		238
Other comprehensive income (loss)		6,950			13,439			26,010		42,620
Comprehensive income (loss)	$	(2,157	)	$	(16,120	)	$	171,255	$	(24,706	)

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

(Unaudited)

ASSETS

	September 30, 2011			December 31, 2010
Utility plant (at original cost, including construction work in progress of $1,163,951 and $628,387, respectively):
Electric plant	$	8,214,105		$	7,586,208
Gas plant		2,820,371			2,752,962
Common plant		491,077			427,227
Less:  Accumulated depreciation and amortization		(3,656,974	)		(3,509,277	)
Net utility plant		7,868,579			7,257,120
Other property and investments:
Investment in exchange power contract		20,278			22,923
Other property and investments		114,561			115,056
Total other property and investments		134,839			137,979
Current assets:
Cash and cash equivalents		19,532			36,320
Restricted cash		4,261			5,470
Accounts receivable, net of allowance for doubtful accounts of $8,122 and $9,784, respectively		205,869			327,341
Unbilled revenue		100,834			194,088
Purchased gas adjustment receivable		--			5,992
Materials and supplies, at average cost		76,741			84,222
Fuel and gas inventory, at average cost		95,388			92,222
Unrealized gain on derivative instruments		6,876			7,500
Income taxes		11,987			62,114
Prepaid expense and other		37,052			14,412
Deferred income taxes		85,628			80,215
Total current assets		644,168			909,896
Other long-term and regulatory assets:
Power cost adjustment mechanism		1,106			15,618
Other regulatory assets		766,843			843,081
Unrealized gain on derivative instruments		10,671			8,233
Other		161,670			138,857
Total other long-term and regulatory assets		940,290			1,005,789
Total assets	$	9,587,876		$	9,310,784

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

(Unaudited)

CAPITALIZATION AND LIABILITIES

	September 30, 2011			December 31, 2010
Common shareholder’s equity:
Common stock $0.01 par value – 150,000,000 shares authorized, 85,903,791 shares outstanding	$	859		$	859
Additional paid-in capital		3,246,205			2,959,205
Earnings reinvested in the business		132,560			172,490
Accumulated other comprehensive income (loss), net of tax		(131,637	)		(157,647	)
Total common shareholder’s equity		3,247,987			2,974,907
Long-term debt:
First mortgage bonds and senior notes		3,092,000			2,792,000
Pollution control bonds		161,860			161,860
Junior subordinated notes		250,000			250,000
Debt discount		(15	)		--
Total long-term debt		3,503,845			3,203,860
Total capitalization		6,751,832			6,178,767
Current liabilities:
Accounts payable		239,823			291,765
Short-term debt		119,000			247,000
Short-term note owed to parent		29,998			22,598
Current maturities of long-term debt		--			260,000
Accrued expenses:
Purchased gas adjustment liability		11,023			--
Taxes		64,504			81,505
Salaries and wages		34,410			34,453
Interest		53,143			54,723
Unrealized loss on derivative instruments		254,476			243,053
Other		61,079			49,661
Total current liabilities		867,456			1,284,758
Long-term and regulatory liabilities:
Deferred income taxes		1,112,254			1,034,517
Unrealized loss on derivative instruments		124,848			155,179
Regulatory liabilities		324,839			296,884
Other deferred credits		406,647			360,679
Total long-term and regulatory liabilities		1,968,588			1,847,259
Commitments and contingencies
Total capitalization and liabilities	$	9,587,876		$	9,310,784

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,
	2011			2010
Operating activities:
Net income (loss)	$	145,245		$	(67,326	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation		222,422			217,765
Amortization		54,985			53,011
Conservation amortization		76,522			60,874
Deferred income taxes and tax credits, net		58,819			(66,126	)
Net unrealized (gain) loss on derivative instruments		17,649			200,702
Long-term service prepayment		(27,200	)		--
Pension funding		(5,000	)		(12,000	)
AFUDC – Equity		(22,016	)		(8,529	)
Regulatory assets		37,993			37,838
Regulatory liabilities		11,789			31,453
Other long-term assets		(4,815	)		(27,793	)
Other long-term liabilities		25,957			(2,790	)
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue		214,726			201,407
Materials and supplies		7,481			(22,038	)
Fuel and gas inventory		(3,166	)		(8,405	)
Income taxes		50,127			41,040
Prepayments and other		(22,640	)		(22,127	)
Purchased gas adjustment		17,015			(53,133	)
Accounts payable		(45,871	)		9,330
Taxes payable		(17,001	)		(19,840	)
Accrued expenses and other		2,217			8,430
Net cash provided by operating activities		795,238			551,743
Investing activities:
Construction expenditures – excluding equity AFUDC		(784,608	)		(667,597	)
Energy efficiency expenditures		(57,173	)		(67,165	)
Treasury grant payment received		--			28,675
Restricted cash		1,209			14,231
Other		7,830			2,268
Net cash used in investing activities		(832,742	)		(689,588	)
Financing activities:
Change in short-term debt and leases, net		(131,789	)		(28,059	)
Dividends paid		(185,175	)		(166,084	)
Long-term notes and bonds issued		300,000			575,000
Loan from (payment to) parent		7,400			--
Redemption of bonds and notes		(260,000	)		(232,000	)
Investment from parent		287,000			--
Issuance cost of bonds and other		3,280			(3,141	)
Net cash provided by (used in) financing activities		20,716			145,716
Net increase (decrease) in cash and cash equivalents		(16,788	)		7,871
Cash and cash equivalents at beginning of period		36,320			78,407
Cash and cash equivalents at end of period	$	19,532		$	86,278
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	146,152		$	147,388
Cash payments (refunds) for income taxes		(50,022	)		(19,087	)

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, Inc. (Puget Energy) is an energy services holding company that owns Puget Sound Energy, Inc. (PSE).  PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering 6,000 square miles, primarily in the Puget Sound region.  Following the merger with Puget Holdings LLC (Puget Holdings) on February 6, 2009, Puget Energy is an indirect wholly-owned subsidiary of Puget Holdings.

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

The consolidated financial statements contained in this Form 10-Q are unaudited.  In the respective opinions of the management of Puget Energy and PSE, all adjustments necessary for a fair statement of the results for the interim periods have been reflected and were of a normal recurring nature.  These consolidated financial statements should be read in conjunction with the audited financial statements (and the Combined Notes thereto) included in the combined Puget Energy and PSE Annual Report on Form 10-K for the year ended December 31, 2010.

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 $44.7 million and $182.1 million for the three and nine months ended September 30, 2011, respectively, and $44.4 million and $164.0 million for the three and nine months ended September 30, 2010, respectively.  The Company reports such taxes on a gross basis in operating revenue and in taxes other than income taxes in the accompanying consolidated statements of income.

Accumulated Other Comprehensive Income (Loss)

The following tables present the components of the Company’s accumulated other comprehensive income (OCI) at September 30, 2011 and December 31, 2010:

Puget Energy (Dollars in Thousands)	September 30, 2011			December 31, 2010
Net unrealized loss on energy derivative instruments	$	(1,512	)	$	(2,658	)
Net unrealized loss on interest rate swaps		(17,246	)		(40,041	)
Net unrealized gain and prior service cost on pension plans		41,260			39,630
Total Puget Energy, net of tax	$	22,502		$	(3,069	)

Puget Sound Energy (Dollars in Thousands)	September 30, 2011			December 31, 2010
Net unrealized loss on energy derivative instruments	$	(16,071	)	$	(34,612	)
Settlement of treasury rate cash flow hedge contracts		(7,020	)		(7,257	)
Net unrealized loss and prior service cost on pension plans		(108,546	)		(115,778	)
Total PSE, net of tax	$	(131,637	)	$	(157,647	)

Adjustments.  During the three months ended September 30, 2011, PSE recorded adjustments to increase after-tax income totaling $2.6 million to correct certain accounting estimates that originated in prior periods.  These adjustments resulted in an increase to operating revenue of $4.7 million, energy costs of $2.4 million and income taxes of $0.1 million and a decrease to utility operations and maintenance of $0.4 million.  Because the adjustments were not material to any prior periods and the cumulative amount is not material to the estimated results of operations for the year ending December 31, 2011, the Company recorded the cumulative effect of these adjustments during the three months ended September 30, 2011.  The adjustments had no impact to the cash flows from operations or total cash flows.

(2)   New Accounting Pronouncements

Intangibles - Goodwill and Other

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

ASU 2011-08 is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011, and therefore will become effective for the Company on January 1, 2012.  The Company does not currently plan to optionally adopt ASU 2011-08 early.

Comprehensive Income

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

ASU 2011-05 should be applied retrospectively, and is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011, and therefore will become effective for the Company on January 1, 2012.  The Company already complies with the presentation requirement, as the Company presents the total of comprehensive income, the components of net income, and the components of OCI in two separate statements.  Therefore ASU 2011-05 will not have an impact on the Company’s consolidated financial statements.

Fair Value Measurement

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

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

ASU 2011-04 is effective during interim and annual periods beginning after December 15, 2011, and therefore will become effective for the Company on January 1, 2012.  Adoption of ASU 2011-04 is not expected to have a significant impact on the Company’s consolidated financial statements.

(3)   Accounting for Derivative Instruments and Hedging Activities

PSE employs various portfolio optimization strategies, but is not in the business of assuming risk for the purpose of realizing speculative trading revenue.  The nature of serving regulated electric customers with its portfolio of owned and contracted electric generation resources exposes PSE and its customers to volumetric and commodity price risks within the sharing mechanism of the Power Cost Adjustment (PCA).  Therefore, wholesale market transactions are focused on balancing PSE’s energy portfolio management function monitors and manages these risks using analytical models and tools.  In order to manage risks effectively, PSE enters into physical and financial transactions which are appropriate for the service territory of PSE and are relevant to its regulated electric and natural gas portfolios.

The Company manages its interest rate risk primarily through the issuance of fixed-rate debt of various maturities.  The Company utilizes internal cash from operations, commercial paper and credit facilities to meet short-term funding needs.  Short-term obligations are commonly refinanced with fixed-rate bonds or notes when needed and when interest rates are considered favorable.  The Company may also enter into swap instruments or other financial hedge instruments to manage interest rate risk associated with its debt.  At the date of the merger in 2009, Puget Energy entered into interest rate swap transactions to hedge the risk associated with its one-month London Interbank Offered Rate (LIBOR) floating rate debt.  As of September 30, 2011, Puget Energy had four remaining interest rate swap contracts outstanding and PSE did not have any outstanding interest rate swap instruments.

Effective December 6, 2010, Puget Energy de-designated its interest rate derivatives previously recorded as cash flow hedges, with the intent to refinance the underlying debt prior to its maturity in February 2014.  A portion of the outstanding interest rate swap derivative loss on December 6, 2010 remained in OCI and continues to be amortized as the future interest payments on the debt occur.  The remaining portion of the outstanding interest rate swap derivative loss, associated with interest payments on the debt where future occurrence of debt payments became remote, was reclassified from OCI into earnings.  To date, Puget Energy has refinanced the underlying debt on several occasions and correspondingly, has net settled three interest rate swaps with a total notional amount of $205.6 million.  Puget Energy intends to continue refinancing this debt, and settling related interest rate swaps, as market conditions warrant.  After December 6, 2010, all gains or losses associated with the interest rate swaps are marked-to-market and recorded in Puget Energy’s earnings.

  In July 2009, the Company discontinued cash flow hedge accounting for all energy related derivatives. As a result, the natural gas and electric derivative portfolios are marked-to-market and changes in value are recorded in earnings. However, amounts previously recorded in accumulated OCI continue to be deferred until the forecasted transaction occurs or management determines that the forecasted transaction is probable of not occurring, at which time the amounts   are then reclassified into.

The following tables present the fair value and locations of the Company’s derivative instruments recorded on the balance sheets at September 30, 2011 and December 31, 2010:

Derivatives Not Designated as Hedging Instruments
Puget Energy	September 30, 2011				December 31, 2010
(Dollars in Thousands)	Assets 1		Liabilities 2		Assets 1		Liabilities 2
Interest rate swaps:
Current	$	--	$	25,826	$	--	$	30,047
Long-term		--		33,616		--		27,956
Electric portfolio:
Current		4,905		155,966		4,716		142,780
Long-term		6,280		77,163		5,046		99,801
Natural gas portfolio: 3
Current		1,971		98,510		2,784		100,273
Long-term		4,391		47,685		3,187		55,378
Total derivatives	$	17,547	$	438,766	$	15,733	$	456,235

Derivatives Not Designated as Hedging Instruments
Puget Sound Energy	September 30, 2011				December 31, 2010
(Dollars in Thousands)	Assets 1		Liabilities 2		Assets 1		Liabilities 2
Electric portfolio:
Current	$	4,905	$	155,966	$	4,716	$	142,780
Long-term		6,280		77,163		5,046		99,801
Natural gas portfolio: 3
Current		1,971		98,510		2,784		100,273
Long-term		4,391		47,685		3,187		55,378
Total derivatives	$	17,547	$	379,324	$	15,733	$	398,232

___________

1	Balance sheet location: Unrealized gain on derivative instruments.
2	Balance sheet location: Unrealized loss on derivative instruments.
3	The Company net derivative liability had a regulatory asset of $139.8 million and $149.7 million at September 30, 2011 and December 31, 2010, respectively, related to financial contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers.  All fair value adjustments on derivatives relating to the natural gas business have been reclassified to a deferred account in accordance with ASC 980, “Regulated Operations” (ASC 980), due to the Purchased Gas Adjustment (PGA) mechanism.  All increases and decreases in the cost of natural gas supply are passed on to customers with the PGA mechanism and the gains and losses on the hedges in future periods will be recorded as gas costs.

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

The following tables present the net unrealized (gain) loss of the Company’s derivative instruments recorded on the statements of income for the three and nine months ended September 30, 2011 and 2010:

Puget Energy	Three Months Ended September 30,						Nine Months Ended September 30,
(Dollars in Thousands)	2011			2010			2011			2010
Natural gas / Power NPNS 1	$	(37	)	$	(78	)	$	(10,806	)	$	(33,662	)
Natural gas for power generation		(382	)		18,232			(40,644	)		67,151
Power exchange		--			(639	)		--			(2,096	)
Power		30,612			45,760			31,530			77,790
Total net unrealized (gain) loss on derivative instruments	$	30,193		$	63,275		$	(19,920	)	$	109,183
Interest expense – interest rate swaps	$	9,107		$	--		$	21,352		$	--
Other deductions – interest rate swaps	$	828		$	--		$	15,154		$	--

___________

1 Gains related to Normal Purchase Normal Sale (NPNS) contracts at the merger date are subsequently amortized over the remaining life.

Puget Sound Energy	Three Months Ended September 30,					Nine Months Ended September 30,
(Dollars in Thousands)	2011		2010			2011			2010
Natural gas for power generation	$	1,833	$	31,801		$	(21,368	)	$	109,523
Power exchange		--		(639	)		--			(2,096	)
Power		31,447		47,397			39,017			93,275
Total net unrealized (gain) loss on derivative instruments	$	33,280	$	78,559		$	17,649		$	200,702

The following tables present the effect of hedging instruments on the Puget Energy’s OCI and statements of income, which are based on derivatives that were in a previous cash flow hedging relationship, for the three and nine months ended September 30, 2011 and 2010:

Puget Energy (Dollars in Thousands)	Three Months Ended September 30,
Derivatives in Cash Flow Hedging Relationships	Gain (Loss) Recognized  in OCI on Derivatives (Effective Portion 1)					Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion 2)
	2011		2010			Location	2011			2010
Interest rate contracts:	$	--	$	(19,761	)	Interest expense	$	(4,311	)	$	(8,638	)
Commodity contracts: Electric derivatives		--		--		Electric generation fuel		(676	)		(3,286	)
						Purchased electricity		(528	)		(361	)
Total	$	--	$	(19,761	)		$	(5,515	)	$	(12,285	)

Puget Energy (Dollars in Thousands)	Nine Months Ended September 30,
Derivatives in Cash Flow Hedging Relationships	Gain (Loss) Recognized  in OCI on Derivatives (Effective Portion 1)					Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion 2)
	2011		2010			Location	2011			2010
Interest rate contracts:	$	--	$	(63,338	)	Interest expense	$	(35,069	)	$	(25,520	)
Commodity contracts: Electric derivatives		--		--		Electric generation fuel		(726	)		(3,407	)
				--		Purchased electricity		(1,038	)		(2,170	)
Total	$	--	$	(63,338	)		$	(36,833	)	$	(31,097	)

___________

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

The following tables present the effect of hedging instruments on PSE’s OCI and statements of income, which are based on derivatives that were in a previous cash flow hedging relationship, for the three and nine months ended September 30, 2011 and 2010:

Puget Sound Energy (Dollars in Thousands)	Three Months Ended September 30,
Derivatives in Cash Flow Hedging Relationships	Gain (Loss) Recognized  in OCI on Derivatives  (Effective Portion 1)				Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion 2)
	2011		2010		Location	2011			2010
Interest rate contracts:	$	--	$	--	Interest expense	$	(122	)	$	(122	)
Commodity contracts: Electric derivatives		--		--	Electric generation fuel		(2,890	)		(16,855	)
					Purchased electricity		(1,362	)		(1,996	)
Total	$	--	$	--		$	(4,374	)	$	(18,973	)

Puget Sound Energy (Dollars in Thousands)	Nine Months Ended September 30,
Derivatives in Cash Flow Hedging Relationships	Gain (Loss) Recognized  in OCI on Derivatives  (Effective Portion 1)				Gain (Loss) Reclassified from Accumulated  OCI into Income (Effective Portion 2)
	2011		2010		Location	2011			2010
Interest rate contracts:	$	--	$	--	Interest expense	$	(364	)	$	(366	)
Commodity contracts: Electric derivatives		--		--	Electric generation fuel		(19,999	)		(45,778	)
					Purchased electricity		(8,526	)		(13,243	)
Total	$	--	$	--		$	(28,889	)	$	(59,387	)

___________

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

For derivative instruments that met cash flow hedge criteria, the effective portion of the gain or loss on the derivative was reported as a component of accumulated OCI during the hedging period and will be reclassified into earnings in the same period or periods during which the hedged transaction affected earnings.  Gains and losses on the derivatives representing hedge ineffectiveness are recognized in current earnings.  As of September 30, 2011, Puget Energy expects that $15.6 million of losses in accumulated OCI will be reclassified into earnings within the next twelve months.  PSE expects that $14.4 million of losses in accumulated OCI will be reclassified into earnings within the next twelve months.  The maximum length of time over which the Company is economically hedging its exposure to the variability of future cash flows extends to February 2015 for purchased electricity contracts, October 2015 for gas for power generation contracts and February 2014 for interest rate swaps.  Additionally, the maximum length of contract transactions deferred in accumulated OCI extends to February 2015 for purchased electricity contracts, January 2012 for gas for power generation contracts and February 2014 for interest rate swaps.

The following tables present the effect of the Company’s derivatives not designated as hedging instruments on income during the three and nine months ended September 30, 2011 and 2010:

Puget Energy		Three Months Ended September 30,						Nine Months Ended September 30,
(Dollars in Thousands)	Location	2011			2010			2011			2010
Interest rate contracts:	Other deductions	$	(3,395	)	$	--		$	(28,855	)	$	--
	Interest expense		(14,087	)		--			(41,363	)		--
Commodity contracts:
Electric derivatives	Unrealized gain (loss) on derivative instruments, net 1	$	(30,230	)	$	(63,353	)	$	9,114		$	(142,846	)
	Electric generation fuel		(22,763	)		(36,571	)		(72,385	)		(69,571	)
	Purchased electricity		(10,141	)		(9,329	)		(43,971	)		(27,529	)
Total gain (loss) recognized in income on derivatives		$	(80,616	)	$	(109,253	)	$	(177,460	)	$	(239,946	)

___________

1 Differs from the amounts stated in the statements of income as it does not include amortization expense related to contracts that were recorded at fair value at the time of the February 2009 merger and subsequently designated as NPNS of $0.4 million and $10.8 million for the three and nine months ended September 30, 2011 and $0.1 million and $33.7 million for the three and nine months ended September 30, 2010, respectively.

Puget Sound Energy		Three Months Ended September 30,						Nine Months Ended September 30,
(Dollars in Thousands)	Location	2011			2010			2011			2010
Commodity contracts:
Electric derivatives	Unrealized gain (loss) on derivative instruments, net	$	(33,280	)	$	(78,559	)	$	(17,649	)	$	(200,702	)
	Electric generation fuel		(22,763	)		(36,571	)		(72,385	)		(69,571	)
	Purchased electricity		(10,141	)		(9,329	)		(43,971	)		(27,529	)
Total gain (loss) recognized in income on derivatives		$	(66,184	)	$	(124,459	)	$	(134,005	)	$	(297,802	)

The Company had the following outstanding commodity contracts as of September 30, 2011:

Derivatives not designated as hedging instruments:	Number of Units
Puget Energy:
Interest rate swaps	$1.277 billion
Puget Energy and Puget Sound Energy:
Natural gas derivatives 1	452,755,192  MMBtus
Electric generation fuel	108,882,500  MMBtus
Purchased electricity	11,636,692      MWhs

 __________

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

The Company is exposed to credit risk primarily through buying and selling electricity and natural gas to serve its customers and through interest rate swaps.  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 with significant swings in credit default swap rates, credit rating changes by external rating agencies, changes in ownership or that are experiencing financial problems.  Where deemed appropriate, the Company may request collateral or other security from its counterparties to mitigate potential credit default losses.  Criteria employed in this decision include, among other things, the perceived creditworthiness of the counterparty and the expected credit exposure.

It is possible that volatility of 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.  As of September 30, 2011, approximately 99.9% of the Company’s energy portfolio exposure, excluding NPNS transactions, is with counterparties that are rated at least investment grade by the major rating agencies while 0.1% are either rated below investment grade or are not rated by rating agencies.  The Company assesses credit risk internally for counterparties that are not rated.

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

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

The Company applies the counterparty’s default factor to compute credit reserves for counterparties that are in a net asset position.  The Company applies its own default factor to compute credit reserves for counterparties that are in a net liability position.  Credit reserves are recorded as offsetting amounts to unrealized gain (loss) positions.  As of September 30, 2011, the Company was in a net liability position with the majority of counterparties, so the default factors of counterparties did not have a significant impact on reserves for the quarter.  The majority of the Company’s derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council.  Despite its net liability position, PSE was not required to post additional collateral with any of its counterparties.  Additionally, PSE did not trigger collateral requirements with any of its counterparties nor were any of PSE’s counterparties required to post additional collateral resulting from credit rating downgrades.

As of September 30, 2011, the Company did not have any outstanding energy supply and interest rate swap contracts with counterparties that contained credit risk-related contingent features, which could result in a counterparty requesting immediate payment or demanding immediate and ongoing full overnight collateralization on derivative instruments in a net liability position.

The following table presents the fair value of the Company’s outstanding derivative contracts with contractually contingent features which are in a liability position at September 30, 2011:

Puget Energy and Puget Sound Energy Contingent Feature (Dollars in Thousands)	Fair Value 1 Liability			Posted Collateral		Contingent Collateral
Credit rating 2	$	(47,067	)	$	--	$	47,067
Requested credit for adequate assurance		(119,906	)		--		--
Forward value of contract 3		(11,710	)		--		--
Total	$	(178,683	)	$	--	$	47,067

__________

1	Excludes NPNS, accounts payable and accounts receivable.
2	Failure by PSE to maintain an investment grade credit rating from each of the major credit rating’s agencies provides counterparties a contractual right to demand collateral.
3	Collateral requirements may vary, based on changes in the forward value of underlying transactions relative to contractually defined collateral thresholds.

(4)   Fair Value Measurements

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

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date.  Level 1 primarily consists of financial instruments such as exchange-traded derivatives and listed equities.  Equity securities that are also classified as cash equivalents are considered Level 1 if there are unadjusted quoted prices in active markets for identical assets or liabilities.

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.  Level 2 includes those financial instruments that are valued using models or other valuation methodologies.  Instruments in this category include non-exchange-traded derivatives such as over-the-counter forwards and options.

Level 3 – Pricing inputs include significant inputs that have little or no observability as of the reporting date.  These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. If a fair value measurement relies on inputs from different levels of the hierarchy, the entire measurement must be placed based on the lowest level input that is significant to the fair value measurement.  The Company primarily determines fair value measurements classified as Level 2 or Level 3 using a combination of the income and market valuation approaches.  On a daily basis, the Company obtains quoted forward prices for the electric and natural gas market from an independent external pricing service.  These forward price quotes are used in addition to other various inputs to determine the reported fair value.  Some of the inputs include the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), assumptions for time value, and also the impact of the Company’s nonperformance risk of its liabilities.

As of September 30, 2011, the Company considered the markets for its electric and natural gas as Level 2 derivative instruments, since such contracts are commonly traded as over-the-counter forwards with indirectly observable price quotes.  However, certain energy derivative instruments are classified as Level 3 in the fair value hierarchy since Level 3 inputs are significant to the fair value measurement.  Management’s assessment was based on the trading activity volume in real-time and forward electric and natural gas markets.  The Company regularly confirms the validity of pricing service quoted prices (e.g., Level 2 in the fair value hierarchy) used to value commodity contracts with the actual prices of commodity contracts entered into during the most recent quarter.

The following tables present the Company’s financial assets and liabilities by level, within the fair value hierarchy, that were accounted for at fair value on a recurring basis and the reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy as of September 30, 2011 and December 31, 2010:

Puget Energy	Fair Value Measurement at September 30, 2011								Fair Value Measurement at December 31, 2010
(Dollars in Thousands)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	--	$	1,646	$	9,539	$	11,185	$	--	$	1,874	$	7,888	$	9,762
Natural gas derivative instruments		--		440		5,922		6,362		--		1,487		4,484		5,971
Cash equivalents		5,607		4,664		--		10,271		15,184		5,450		--		20,634
Restricted cash		2,192		--		--		2,192		3,246		--		--		3,246
Total assets	$	7,799	$	6,750	$	15,461	$	30,010	$	18,430	$	8,811	$	12,372	$	39,613
Liabilities:
Electric derivative instruments	$	--	$	143,870	$	89,259	$	233,129	$	--	$	147,257	$	95,324	$	242,581
Natural gas derivative instruments		--		138,695		7,500		146,195		--		147,308		8,343		155,651
Interest rate derivative instruments		--		59,442		--		59,442		--		58,003		--		58,003
Total liabilities	$	--	$	342,007	$	96,759	$	438,766	$	--	$	352,568	$	103,667	$	456,235

Puget Sound Energy	Fair Value Measurement at September 30, 2011								Fair Value Measurement at December 31, 2010
(Dollars in Thousands)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	--	$	1,646	$	9,539	$	11,185	$	--	$	1,874	$	7,888	$	9,762
Natural gas derivative instruments		--		440		5,922		6,362		--		1,487		4,484		5,971
Cash equivalents		--		4,664		--		4,664		15,184		5,450		--		20,634
Restricted cash		2,192		--		--		2,192		3,246		--		--		3,246
Total assets	$	2,192	$	6,750	$	15,461	$	24,403	$	18,430	$	8,811	$	12,372	$	39,613
Liabilities:
Electric derivative instruments	$	--	$	143,870	$	89,259	$	233,129	$	--	$	147,257	$	95,324	$	242,581
Natural gas derivative instruments		--		138,695		7,500		146,195		--		147,308		8,343		155,651
Total liabilities	$	--	$	282,565	$	96,759	$	379,324	$	--	$	294,565	$	103,667	$	398,232

Puget Energy and Puget Sound Energy Level 3 Roll-Forward Net (Liability)	Three Months Ended September 30,						Nine Months Ended September 30,
(Dollars in Thousands)	2011			2010			2011			2010
Balance at beginning of period	$	(81,537	)	$	(135,121	)	$	(91,295	)	$	(100,333	)
Changes during period:
Realized and unrealized energy derivatives
- included in earnings		(10,491	) 1		(46,223	) 2		(30,442	) 1		(125,839	) 2
- included in regulatory assets / liabilities		(272	)		(1,017	)		2,707			(1,856	)
Settlements 3		6,431			7,798			23,978			21,138
Transferred into Level 3		126			761			489			225
Transferred out of Level 3		4,445			52,815			13,265			85,678
Balance at end of period	$	(81,298	)	$	(120,987	)	$	(81,298	)	$	(120,987	)

__________

1	Includes unrealized gains (losses) on derivatives still held in position as of the reporting date for electric and natural gas derivatives of $(15.1) million and $2.9 million, respectively, for the three months ended September 30, 2011 and $(32.6) million and $2.1 million for electric and natural gas derivatives for the nine months ended September 30, 2011, respectively.
2	Includes unrealized gains (losses) on derivatives still held in position as of the reporting date for electric and natural gas derivatives of $(37.0) million and $0.6 million, respectively, for the three months ended September 30, 2010 and $(76.3) million and $(27.4) million for electric and natural gas derivatives for the nine months ended September 30, 2010, respectively.
3	The Company had no purchases or issuances during the reported periods.

Realized gains and losses on energy derivatives for Level 3 recurring items are included in energy costs in the Company’s consolidated statements of income under purchased electricity, electric generation fuel or purchased natural gas when settled.

Unrealized gains and losses on energy derivatives for Level 3 recurring items are included in net unrealized (gain) loss on derivative instruments in the Company’s consolidated statements of income.  Energy derivatives transferred out of Level 3 represent existing assets or liabilities that were classified as Level 3 at the beginning of the reporting period for which the lowest significant input became observable during the current reporting period and were transferred into Level 2.  Conversely, energy derivatives transferred into Level 3 from Level 2 represent scenarios in which the lowest significant input became unobservable during the current reporting period.  The Company did not have any transfers between Level 2 and Level 1 during the three and nine months ended September 30, 2011 or 2010.

(5)   Estimated Fair Value of Financial Instruments

The following tables present the carrying amounts and estimated fair value of the Company’s financial instruments at September 30, 2011 and December 31, 2010:

	September 30, 2011				December 31, 2010
Puget Energy (Dollars in Thousands)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Assets:
Cash and cash equivalents	$	26,086	$	26,086	$	36,557	$	36,557
Restricted cash		4,261		4,261		5,470		5,470
Notes receivable and other		72,350		72,350		72,419		72,419
Electric derivatives		11,185		11,185		9,762		9,762
Natural gas derivatives		6,362		6,362		5,971		5,971
Liabilities:
Short-term debt	$	119,000	$	119,000	$	247,000	$	247,000
Junior subordinated notes		250,000		249,207		250,000		246,864
Current maturities of long-term debt (fixed-rate)		--		--		260,000		261,472
Long-term debt (fixed-rate), net of discount		3,927,884		5,154,676		3,119,660		3,718,303
Long-term debt (variable-rate), net of discount		828,292		871,786		1,013,053		1,083,117
Electric derivatives		233,129		233,129		242,581		242,581
Natural gas derivatives		146,195		146,195		155,651		155,651
Interest rate derivatives		59,442		59,442		58,003		58,003

	September 30, 2011				December 31, 2010
Puget Sound Energy (Dollars in Thousands)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Assets:
Cash and cash equivalents	$	19,532	$	19,532	$	36,320	$	36,320
Restricted cash		4,261		4,261		5,470		5,470
Notes receivable and other		72,350		72,350		72,419		72,419
Electric derivatives		11,185		11,185		9,762		9,762
Natural gas derivatives		6,362		6,362		5,971		5,971
Liabilities:
Short-term debt	$	119,000	$	119,000	$	247,000	$	247,000
Short-term debt owed by PSE to Puget Energy 1		29,998		29,998		22,598		22,598
Junior subordinated notes		250,000		249,207		250,000		246,864
Current maturities of long-term debt (fixed-rate)		--		--		260,000		261,472
Long-term debt (fixed-rate)		3,253,845		4,204,347		2,953,860		3,267,994
Electric derivatives		233,129		233,129		242,581		242,581
Natural gas derivatives		146,195		146,195		155,651		155,651

___________

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

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

(6)   Retirement Benefits

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

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

The following tables summarize the Company’s net periodic benefit cost for the three and nine months ended September 30, 2011 and 2010:

Puget Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
	Three Months Ended September 30,						Three Months Ended September 30,				Three Months Ended September 30,
(Dollars in Thousands)	2011			2010			2011		2010		2011			2010
Components of net periodic benefit cost:
Service cost	$	3,748		$	4,009		$	310	$	256	$	22		$	26
Interest cost		6,438			6,965			548		541		196			220
Expected return on plan assets		(8,788	)		(8,087	)		--		--		(126	)		(127	)
Amortization of prior service cost		(495	)		--			--		--		--			--
Amortization of net loss (gain)		--			--			90		--		(36	)		(17	)
Net periodic benefit cost	$	903		$	2,887		$	948	$	797	$	56		$	102

Puget Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
	Nine Months Ended September 30,						Nine Months Ended September 30,				Nine Months Ended September 30,
(Dollars in Thousands)	2011			2010			2011		2010		2011			2010
Components of net periodic benefit cost:
Service cost	$	11,867		$	12,083		$	931	$	768	$	85		$	79
Interest cost		19,697			21,030			1,644		1,624		605			660
Expected return on plan assets		(26,508	)		(24,501	)		--		--		(377	)		(381	)
Amortization of prior service cost		(1,485	)		--			--		--		--			--
Amortization of net loss (gain)		--			--			270		--		(34	)		(51	)
Net periodic benefit cost	$	3,571		$	8,612		$	2,845	$	2,392	$	279		$	307

Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
	Three Months Ended September 30,						Three Months Ended September 30,				Three Months Ended September 30,
(Dollars in Thousands)	2011			2010			2011		2010		2011			2010
Components of net periodic benefit cost:
Service cost	$	3,748		$	4,009		$	310	$	256	$	22		$	26
Interest cost		6,438			6,965			548		541		196			220
Expected return on plan assets		(10,984	)		(10,875	)		--		--		(126	)		(127	)
Amortization of prior service cost		(393	)		185			141		141		16			33
Amortization of net loss (gain)		2,298			1,781			298		192		(144	)		(138	)
Amortization of transition obligation		--			--			--		--		12			12
Net periodic benefit cost	$	1,107		$	2,065		$	1,297	$	1,130	$	(24	)	$	26

Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
	Nine Months Ended September 30,						Nine Months Ended September 30,				Nine Months Ended September 30,
(Dollars in Thousands)	2011			2010			2011		2010		2011			2010
Components of net periodic benefit cost:
Service cost	$	11,867		$	12,083		$	931	$	768	$	85		$	79
Interest cost		19,697			21,030			1,644		1,624		605			660
Expected return on plan assets		(33,096	)		(32,864	)		--		--		(377	)		(381	)
Amortization of prior service cost		(1,180	)		555			422		422		47			99
Amortization of net loss (gain)		7,687			5,193			895		576		(361	)		(414	)
Amortization of transition obligation		--			--			--		--		37			36
Net periodic benefit cost	$	4,975		$	5,997		$	3,892	$	3,390	$	36		$	79

The following table summarizes the Company’s change in benefit obligation for the periods ended September 30, 2011 and December 31, 2010:

Puget Energy and Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	September 30, 2011			December 31, 2010			September 30, 2011			December 31, 2010			September 30, 2011			December 31, 2010
Change in benefit obligation:
Benefit obligation at beginning of period	$	532,615		$	504,786		$	44,322		$	39,152		$	16,579		$	15,953
Beginning of year remeasurement		(3,755	)		--			--			--			(234	)		--
Service cost		11,867			16,089			931			1,024			85			106
Interest cost		19,697			27,975			1,644			2,165			605			880
Amendment		--			(21,866	)		--			--			--			--
Actuarial loss		--			32,163			--			3,663			--			867
Benefits paid		(28,350	)		(26,532	)		(1,599	)		(1,682	)		(1,344	)		(2,030	)
Medicare part D subsidiary received		--			--			--			--			408			803
Benefit obligation at end of period	$	532,074		$	532,615		$	45,298		$	44,322		$	16,099		$	16,579

The fair value of the Company’s pension plan assets was $456.8 million and $526.5 million at September 30, 2011 and December 31, 2010, respectively.

The Company anticipates its aggregate contributions to fund the retirement plan, and payments to the SERP and the other post retirement plan to be at least $5.0 million, $3.5 million and $0.5 million, respectively, for the year ending December 31, 2011.  During the three months ended September 30, 2011, the Company contributed $0.4 million and $0.1 million to meet the SERP and the other postretirement obligations, respectively.  During the nine months ended September 30, 2011, the Company contributed $5.0 million, $1.6 million and $0.7 million to fund the qualified retirement plan, SERP and the other postretirement plan, respectively.

As a result of the Patient Protection and Affordable Care Act of 2010, PSE recorded a one-time tax expense of $0.8 million during the nine months ended September 30, 2010, related to a Medicare D subsidy that PSE receives.  These subsidies have been non-taxable in the past and will be subject to federal income taxes after 2012 as a result of the legislation.

(7)   Regulation and Rates

On March 14, 2011, the Washington Commission issued an order authorizing PSE to increase its natural gas general tariff rates by $19.0 million on an annual basis, or 1.8%, effective April 1, 2011.

On April 26, 2011, PSE filed a new tariff for a Natural Gas Pipeline Integrity Program.  This program is intended to enhance pipeline safety by providing for the timely recovery of the Company’s cost to replace certain natural gas system infrastructure that would emphasize system reliability, integrity and safety which would increase natural gas revenues by $1.9 million or 0.2%.  The Washington Commission has set a hearing for November 17, 2011.

On June 13, 2011, PSE filed a general rate increase with the Washington Commission which proposed an increase in electric rates of $160.7 million or 8.1%, and an increase in natural gas rates of $31.9 million or 3.0%, to be effective May 2012.  PSE requested a weighted cost of capital of 8.42%, or 7.29% after-tax, and a capital structure of 48.0% in common equity with a return on equity of 10.8%.  The filing also proposes a conservation savings adjustment mechanism related to energy efficiency services for business and residential customers.  On September 1, 2011, PSE filed supplemental testimony to adjust the electric rate increase to $152.3 million, a 7.7% increase, due to changes in projected power costs.  Hearing related to this matter is set for February 14 through 17, 2012.

On October 27, 2011, the Washington Commission approved PSE’s PGA natural gas tariff filing effective November 1, 2011, to decrease the rates charged to customers under the PGA.  The estimated revenue impact of the approved charge is a decrease of $43.5 million, or 4.3% annually.  The rate adjustment has no impact on PSE’s net income.

(8)   Litigation

Residential Exchange. PSE has been a party to certain agreements with the Bonneville Power Administration (BPA) that provide payments under its Residential Exchange Program (REP) to PSE, which PSE passes through to its residential and small farm electric customers.  In 2008, PSE entered into agreements with the BPA for REP payments to 2012 and for the period 2012 to 2028.  PSE and other parties have sought United States Court of Appeals for the Ninth Circuit (Ninth Circuit) review regarding BPA’s agreements for REP payments during these periods.  In July 2011, BPA, PSE, and other parties (including some but not all litigants in the Ninth Circuit proceedings) entered into an agreement that addresses REP payments to PSE and other investor-owned utilities for periods ending September 30, 2028 and that is intended to resolve disputes in the Ninth Circuit over REP payments.  The amounts of REP payments under these agreements and the methods utilized in setting them are subject to FERC review or judicial review, or both, and are subject to adjustment, which may affect the amount of REP payments made or to be made by BPA to PSE.  It is not clear what impact, if any, these reviews or other REP-related litigation may ultimately have on PSE.

Colstrip Matters. In May 2003, approximately 50 plaintiffs initiated an action against the owners of Colstrip, including PSE, regarding seepage from two different wastewater pond areas and from the Colstrip water supply pond.  The defendants reached an agreement on a global settlement with all plaintiffs and PSE expensed its share of the settlement in 2008.  PSE received a partial reimbursement for its share from insurers in December 2010 and January 2011.

On March 29, 2007, a second complaint related to pond seepage was filed in Montana State District Court in Rosebud County, on behalf of two ranch owners alleging damage due to the Colstrip Units 3 & 4 effluent holding pond.  A mediation between plaintiffs and PPL Montana, LLC, the operator of Units 3 & 4, took place on July 14, 2010 and parties are working toward a final settlement.

Snoqualmie Falls.  On July 7, 2010, a lawsuit was filed in the U.S. District Court for the Western District of Washington by the Snoqualmie Valley Preservation Alliance (SVPA), a group of downstream landowners, against the United States Army Corps of Engineers (Corps) challenging permits issued by the Corps in connection with the redevelopment of the Snoqualmie Falls Hydroelectric Project.  PSE sought and was granted permission to intervene in the proceeding.  Motions for summary judgment were filed by the plaintiffs and the Corps.  PSE joined the Corps’ motion and filed a motion for summary judgment arguing the plaintiffs’ claims were barred as untimely and improper.  On March 30, 2011, the District Court issued an order granting the Corps’ motion for summary judgment, denying the plaintiffs’ motion for summary judgment and dismissing the plaintiffs’ lawsuit.  On May 26, 2011, plaintiffs filed a notice of appeal with the U.S. Court of Appeals for the Ninth Circuit, claiming that the District Court erred in dismissing the lawsuit.  SVPA submitted its opening brief on September 20, 2011, and response briefs were submitted by November 3, 2011.  Oral argument on the appeal will occur thereafter, with a decision by the Court of Appeals to follow.  Litigation is subject to numerous uncertainties and PSE is unable to predict the ultimate outcome of this matter.

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

(9)   Variable Interest Entities

In accordance with ASC 810, “Consolidation” (ASC 810), a business entity which has a controlling financial interest in a Variable Interest Entity (VIE) should consolidate the VIE in its financial statements.  A primary beneficiary of a VIE is the variable interest holder that has both the power to direct matters that significantly impact the activities of the VIE and has the obligation to absorb losses or the right to receive benefits.  The Company enters into a variety of contracts for energy with other counterparties and evaluates all contracts to determine if they are variable interests.  The Company’s variable interests primarily arise through power purchase agreements where it is required to buy all or a majority of generation from a plant at rates set forth in the agreement.

The Company evaluated its power purchase agreements and determined it was not the primary beneficiary of any VIEs.  The Company previously disclosed two potentially significant variable interests in prior periods, both of which are qualifying facilities contracts that expire at the end of 2011.  The Company does not have an equity interest in either of those qualifying facilities.  The Company requested information from the relevant entities; however, they refused to provide the necessary information to the Company since they are not required to do so under their contracts.  If the variable interests were determined to be VIEs, the Company has concluded it is not the primary beneficiary of these entities based on available information and it has no exposure to losses on these contracts.  For the three months ended September 30, 2011 and 2010, the Company’s purchased power expense for these entities was $43.6 million and $54.0 million, respectively.  For the nine months ended September 30, 2011 and 2010, the Company’s purchased power expense for these entities was $129.1 million and $141.1 million, respectively.

(10)   Other

Bond Issuances. On June 3, 2011, Puget Energy issued $500.0 million of senior secured notes.  The notes are secured by an interest in substantially all of Puget Energy’s assets, which consists mainly of all the issued and outstanding stock of PSE and the stock of Puget Energy held by Puget Equico LLC (Puget Equico).  The notes mature on September 1, 2021 and have an interest rate of 6.0%.  Net proceeds from the note offering were used by Puget Energy to repay $484.0 million of its five-year term-loans and $9.9 million to unwind three outstanding interest rate swaps.

On March 25, 2011, PSE issued $300.0 million of senior secured notes secured by first mortgage bonds.  The notes have a term of 30-years and an interest rate of 5.638%.  Net proceeds from the note offering were used by PSE to repay short-term debt outstanding under its capital expenditures credit facility, which debt was incurred to fund utility capital expenditures and replenish cash used to repay the February 2011 maturity of $260.0 million of medium-term notes with a 7.69% interest rate.

Capital Contribution.  On February 3, 2011, and on May 23, 2011, Puget Energy drew $175.0 million and $112.0 million, respectively, from its capital expenditures credit facility to make capital contributions to PSE.  Proceeds were used by PSE to fund capital expenditures.

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

The AFUDC rates authorized by the Washington Commission for natural gas and electric utility plant additions based on the effective dates are as follows:

Effective Date	Washington Commission AFUDC Rates
April 8, 2010 - present	8.10%
November 1, 2008 - April 7, 2010	8.25

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

The following table presents the Company’s AFUDC amounts for the three and nine months ended September 30, 2011 and 2010:

	Three Months Ended September 30,				Nine Months Ended September 30,
(Dollars in Thousands)	2011		2010		2011		2010
Equity AFUDC	$	9,983	$	4,178	$	22,016	$	8,529
Washington Commission AFUDC		96		--		4,367		2,319
Total in other income		10,079		4,178		26,383		10,848
Debt AFUDC		8,764		3,924		20,764		9,832
Total AFUDC	$	18,843	$	8,102	$	47,147	$	20,680

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

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

Overview

Puget Energy is an energy services holding company and all of its operations are conducted through its subsidiary PSE, a regulated electric and natural gas utility company.  PSE is the largest electric and natural gas utility in the state of Washington, primarily engaged in the business of electric transmission, distribution and generation and natural gas distribution.  Puget Energy’s business strategy is to generate stable cash flows by offering reliable electric and natural gas service in a cost-effective manner through PSE.  Following the merger on February 6, 2009, Puget Energy is a direct wholly-owned subsidiary of Puget Equico LLC (Puget Equico), which is an indirect wholly-owned subsidiary of Puget Holdings LLC (Puget Holdings), a consortium of long-term infrastructure investors including Macquarie Infrastructure Partners I, Macquarie Infrastructure Partners II, Macquarie Capital Group Limited, Macquarie-FSS Infrastructure Trust, the Canada Pension Plan Investment Board, the British Columbia Investment Management Corporation, and the Alberta Investment Management Corporation.  Puget Energy and PSE are collectively referred to herein as “the Company.”

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

For the three months ended September 30, 2011 as compared to the same periods in 2010, PSE’s net income was positively affected by the following four factors:  (1) a decrease in net unrealized loss on derivative instruments primarily due to reversal of prior period losses that were settled during the period related to natural gas and power contracts; (2) lower power costs resulting from above-average hydroelectric and wind conditions that positively impacted PSE’s electric generation in 2011 as compared to higher costs resulting from below-average hydroelectric and wind conditions in 2010; (3) an increase in allowance for funds used during construction (AFUDC) debt and equity components due to higher construction expenditures in 2011 as compared to 2010 which are capitalized to construction projects: and (4) an increase in natural gas retail sales.

For the nine months ended September 30, 2011 as compared to the same periods in 2010, PSE’s net income was positively affected by the following four factors;  (1) a decrease in net unrealized loss on derivative instruments primarily due to reversal of prior period losses that were settled during the period related to natural gas and power contracts due to declining wholesale electricity and natural gas prices which were slightly offset by losses associated with lower forward wholesale prices of natural gas and electricity; (2) an increase in electric and natural gas retail sales primarily due to cooler temperatures in 2011 as compared to warmer than normal temperatures in 2010 during the first quarter; (3) lower power costs resulting from above-average hydroelectric and wind conditions that positively impacted PSE’s electric generation in 2011 as compared to higher costs resulting from below-average hydroelectric and wind conditions in 2010; and (4) an increase in AFUDC debt and equity components due to higher construction expenditures in 2011 as compared to 2010 which are capitalized to construction projects.

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

Factors and Trends Affecting PSE’s Performance.  PSE’s regulatory requirements and operational needs require the investment of substantial capital in 2011 and future years.  Because PSE intends to seek recovery of such investments through the regulatory process, its financial results depend heavily upon favorable outcomes from that process.  Further, PSE’s financial performance is heavily influenced by general economic conditions in its service territory, which affect customer growth and use-per-customer and thus utility sales, as well as by its customers’ conservation investments, which also tend to reduce energy sales.  The principal business, economic and other factors that affect PSE’s operations and financial performance include:

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

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

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

·   Demand for electricity and natural gas among customers in PSE’s service territory;

·   Regulatory decisions allowing PSE to recover costs, including 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;

·   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;

·   The impact of energy efficiency programs on sales and margins;

·   Wholesale commodity prices of electricity and natural gas;

·   Increasing depreciation and related property taxes; and

·   Federal, state, and local taxes.

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

Electric Rates

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

The graduated scale is as follows:

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

PSE had a favorable PCA imbalance for the three and nine months ended September 30, 2011, which was $16.4 million and $46.8 million, respectively, below the “power cost baseline” level as compared to a favorable imbalance of $3.2 million for the three months ended September 30, 2010 and an unfavorable imbalance of $21.7 million for the nine months ended September 30, 2010.

On June 13, 2011, PSE filed a general rate increase with the Washington Commission which proposed an increase in electric rates of $160.7 million or 8.1%, to be effective May 2012.  PSE requested a weighted cost of capital of 8.42%, or 7.29% after-tax, and a capital structure of 48.0% in common equity with a return on equity of 10.8%.  The filing also proposes a conservation savings adjustment mechanism related to energy efficiency services for business and residential customers.  On September 1, 2011, PSE filed supplemental testimony to adjust the electric rate increase to $152.3 million, a 7.7% increase, due to changes in projected power costs.  Hearing related to this matter is set for February 14 through 17, 2012.

The following table sets forth electric rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s annual revenue based on the effective dates:

Type of Rate Adjustment	Effective Date	Average Percentage Increase in Rates	Annual Increase in Revenue (Dollars in Millions)
Electric General Rate Case	April 8, 2010	3.7%	$  74.1

Natural Gas Rates

On October 27, 2011, the Washington Commission approved PSE’s Purchased Gas Adjustment (PGA) natural gas tariff filing effective November 1, 2011, to decrease the rates charged to customers under the PGA.  The estimated revenue impact of the approved charge is a decrease of $43.5 million, or 4.3% annually.  The rate adjustment has no impact on PSE’s net income.

PSE has a PGA mechanism in retail natural gas rates to recover variations in natural gas supply and transportation costs.  Variations in natural gas rates are passed through to customers, therefore, PSE’s net income is not affected by such variations.  Changes in the PGA rates affect PSE’s revenue, but do not impact net income as the changes to revenue are offset by increased or decreased purchased gas and gas transportation costs.

On June 13, 2011, PSE filed a general rate increase with the Washington Commission which proposed an increase in natural gas rates of $31.9 million or 3.0%, to be effective May 2012.  PSE requested a weighted cost of capital of 8.42%, or 7.29% after-tax, and a capital structure of 48.0% in common equity with a return on equity of 10.8%.  The filing also proposes a conservation savings adjustment mechanism related to energy efficiency services for business and residential customers.  Hearing related to this matter is set for February 14 through 17, 2012.

On April 26, 2011, PSE filed a new tariff for a Natural Gas Pipeline Integrity Program.  This program is intended to enhance pipeline safety by providing for the timely recovery of the Company’s cost to replace certain natural gas system infrastructure that would emphasize system reliability, integrity and safety which would increase natural gas revenues by $1.9 million or 0.2%.  The Washington Commission has set a hearing for November 17, 2011.

On March 14, 2011, the Washington Commission issued its order authorizing PSE to increase its natural gas general tariff rates by $19.0 million or 1.8% on an annual basis effective April 1, 2011.

The following table sets forth natural gas rate adjustments approved by the Washington Commission and the corresponding impact to PSE’s annual revenue based on the effective dates:

Type of Rate Adjustment	Effective Date	Average Percentage Increase (Decrease) in Rates	Annual Increase (Decrease) in Revenue (Dollars in Millions)
Purchased Gas Adjustment	November 1, 2011	(4.3)%	$    (43.5)
Natural Gas General Tariff Adjustment	April 1, 2011	1.8	19.0
Purchased Gas Adjustment	November 1, 2010	1.9	18.3
Natural Gas General Rate Case	April 8, 2010	0.8	10.1
Purchased Gas Adjustment	October 1, 2009	(17.1)	(198.1)
Purchased Gas Adjustment	June 1, 2009 – May 31, 2010	(1.8)	(21.2)

Weather Conditions.  Weather conditions in PSE’s service territory have a significant impact on customer energy usage, affecting PSE’s revenue and energy supply expenses.  PSE’s operating revenue and associated energy supply expenses are not generated evenly throughout the year.  While both PSE’s electric and natural gas sales are generally greatest during winter months, variations in energy usage by customers occur from season to season and month to month within a season, primarily as a result of weather conditions.  PSE normally experiences its highest retail energy sales, and subsequently higher power costs, during the winter heating season in the first and fourth quarters of the year and its lowest sales in the third quarter of the year.  Varying wholesale electric prices and the amount of hydroelectric energy supplies available to PSE also make quarter-to-quarter comparisons difficult.  PSE reported higher customer usage in the nine months ended September 30, 2011 primarily due to Pacific Northwest temperatures being 1.52 degrees cooler, as compared to the same periods in 2010.

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

Access to Debt Capital. PSE relies on access to bank borrowings and short-term money markets as sources of liquidity and longer-term debt markets to fund its utility construction program and to meet maturing debt obligations and other capital expenditure requirements not satisfied by cash flow from 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, both of which expire in 2014, the borrowing costs and commitment fees increase as their respective credit ratings decline.  If PSE is unable to access debt capital on reasonable terms, its ability to pursue improvements or acquisitions, including generating capacity, which may be relied on for future growth and to otherwise implement its strategy, could be adversely affected.  PSE monitors the credit environment and expects to continue to be able to access the capital markets to meet its short-term and long-term borrowing needs.

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

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

Other Challenges and Strategies

Energy Supply.  PSE’s current Integrated Resource Plan (IRP), on file with the Washington Commission, projects that future energy needs will exceed current resources from long-term power purchase agreements and Company-controlled power resources.  The IRP identifies reductions in contractual supplies of energy and capacity available under certain long-term power purchase agreements, requiring replacement of supplies to meet projected demands over its 20 year planning horizon.  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.  Factors influencing the Company’s decision-making as to the development or purchase of electric generation (and the timing of such development or purchase) include forecasted future customer energy demands, trends in energy markets, existing and proposed state and federal legislation, regulation and, especially with respect to PSE’s wind development assets, the status and availability of production tax credits (PTCs), treasury grants, or other supportive programs.

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 and operating expenses, which are not recovered through the ratemaking process in a timely manner.  This “regulatory lag” is expected to continue for the foreseeable future.

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

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

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

Results of Operations

Puget Sound Energy

The following discussion should be read in conjunction with the consolidated financial statements and the related notes included elsewhere in this report.  The following table presents the consolidated financial results of PSE for the three and nine months ended September 30, 2011 and 2010:

	Three Months Ended September 30,									Nine Months Ended September 30,
Puget Sound Energy (Dollars in Thousands)	2011			2010			Favorable/ (Unfavorable)			2011			2010			Favorable/ (Unfavorable)
Operating revenue:
Electric
Residential sales	$	210,056		$	215,651			(2.6	)%	$	845,469		$	790,457			7.0	%
Commercial sales		202,926			205,240			(1.1	)		632,142			620,193			1.9
Industrial sales		26,738			26,429			1.2			80,122			76,466			4.8
Other retail sales, including unbilled revenue		5,851			10,736			(45.5	)		(26,458	)		(35,818	)		(26.1	)
Total retail sales		445,571			458,056			(2.7	)		1,531,275			1,451,298			5.5
Transportation sales		2,887			2,594			11.3			7,726			8,477			(8.9	)
Sales to other utilities and marketers		16,844			31,963			(47.3	)		31,287			45,878			(31.8	)
Other		(7,292	)		(3,005	)		142.7			(24,824	)		1,896			*
Total electric operating revenue		458,010			489,608			(6.5	)		1,545,464			1,507,549			2.5
Gas
Residential sales		77,818			73,817			5.4			514,783			418,770			22.9
Commercial sales		47,830			45,595			4.9			241,111			201,204			19.8
Industrial sales		6,390			6,158			3.8			25,087			22,610			11.0
Total retail sales		132,038			125,570			5.2			780,981			642,584			21.5
Transportation sales		3,702			3,474			6.6			11,090			10,516			5.5
Other		3,506			3,527			(0.6	)		10,813			11,323			(4.5	)
Total gas operating revenue		139,246			132,571			5.0			802,884			664,423			20.8
Non-utility operating revenue		520			650			(20.0	)		2,385			2,350			1.5
Total operating revenue		597,776			622,829			(4.0	)		2,350,733			2,174,322			8.1
Operating expenses:
Energy costs:
Purchased electricity		137,818			127,936			(7.7	)		546,025			557,221			2.0
Electric generation fuel		61,596			96,712			36.3			132,705			194,649			31.8
Residential exchange		(12,546	)		(15,173	)		17.3			(49,521	)		(54,510	)		9.2
Purchased gas		63,087			60,284			(4.6	)		427,016			343,779			(24.2	)
Net unrealized (gain) loss on derivative instruments		33,280			78,559			57.6			17,649			200,702			91.2
Utility operations and maintenance		121,049			117,155			(3.3	)		362,868			355,569			(2.1	)
Non-utility expense and other		2,409			3,188			24.4			8,289			7,742			(7.1	)
Depreciation		74,062			73,111			(1.3	)		222,422			217,765			(2.1	)
Amortization		18,562			18,355			(1.1	)		54,985			53,011			(3.7	)
Conservation amortization		20,438			20,392			(0.2	)		76,522			60,874			(25.7	)
Taxes other than income taxes		60,823			58,903			(3.3	)		236,757			210,304			(12.6	)
Total operating expenses		580,578			639,422			9.2			2,035,717			2,147,106			5.2
Operating income (loss)		17,198			(16,593	)		*			315,016			27,216			*
Other income		15,088			11,033			36.8			43,299			32,846			31.8
Other expense		(1,239	)		(1,074	)		(15.4	)		(3,472	)		(4,147	)		16.3
Interest expense		(48,644	)		(57,738	)		15.8			(151,156	)		(168,643	)		10.4
Income (loss) before income taxes		(17,597	)		(64,372	)		72.7			203,687			(112,728	)		*
Income tax (benefit) expense		(8,490	)		(34,813	)		75.6			58,442			(45,402	)		*
Net income (loss)	$	(9,107	)	$	(29,559	)		69.2	%	$	145,245		$	(67,326	)		*	%

__________

* Not meaningful

Non-GAAP Financial Measures – Electric and Gas Margins

The following discussion includes financial information prepared in accordance with U.S. Generally Accepted Accounting Principles (GAAP), as well as two other financial measures, electric margin and gas margin, that are considered “non-GAAP financial measures.”  Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that exclude (or include) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP.  The presentation of electric margin and gas margin is intended to supplement an understanding of PSE’s operating performance.  Electric margin and gas margin are used by PSE to determine whether PSE is collecting the appropriate amount of energy costs from its customers to allow recovery of operating costs.  PSE’s electric margin and gas margin measures may not be comparable to other companies’ electric margin and gas margin measures.  Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.

Electric Margin

The following table displays the details of PSE’s electric margin changes for the three and nine months ended September 30, 2011 as compared to the same periods in 2010.  Electric margin represents electric sales to retail and transportation customers less pass-through tariff items, revenue-sensitive taxes and the cost of generating and purchasing electric energy sold to customers, including transmission costs to bring electric energy to PSE’s service territory.

	Three Months Ended September 30,									Nine Months Ended September 30,
Electric Margin (Dollars in Thousands)	2011			2010			Percent Change			2011			2010			Percent Change
Electric operating revenue1	$	458,010		$	489,608			(6.5	)%	$	1,545,464		$	1,507,549			2.5	%
Add (less): Other electric operating revenue		7,292			3,005			*			24,824			(1,896	)		*
Less: Other electric operating revenue-gas supply resale		(9,657	)		(12,053	)		19.9			(48,302	)		(24,159	)		99.9
Add (less): Other electric operating revenue-RECs & PTCs		(7,208	)		116			*			(7,276	)		116			*
Total electric revenue for margin		448,437			480,676			(6.7	)		1,514,710			1,481,610			2.2
Adjustments for amounts included in revenue:
Pass-through tariff items		(21,321	)		(21,857	)		2.5			(74,284	)		(62,423	)		19.0
Pass-through revenue-sensitive taxes		(33,840	)		(33,954	)		0.3			(115,657	)		(108,966	)		6.1
Net electric revenue for margin		393,276			424,865			(7.4	)		1,324,769			1,310,221			1.1
Minus power costs:
Purchased electricity1		(137,818	)		(127,936	)		7.7			(546,025	)		(557,221	)		(2.0	)
Electric generation fuel1		(61,596	)		(96,712	)		(36.3	)		(132,705	)		(194,649	)		(31.8	)
Residential exchange1		12,546			15,173			(17.3	)		49,521			54,510			(9.2	)
Total electric power costs		(186,868	)		(209,475	)		(10.8	)		(629,209	)		(697,360	)		(9.8	)
Electric margin2	$	206,408		$	215,390			(4.2	)%	$	695,560		$	612,861			13.5	%

______________

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 $9.0 million and increased $82.7 million for the three and nine months ended September 30, 2011, respectively, as compared to the same periods in 2010.  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 decreased $31.6 million, or 6.5%, to $458.0 million from $489.6 million for the three months ended September 30, 2011 as compared to the same period in 2010.  The decrease in operating revenues of $31.6 million was due to lower electric retail sales of $12.5 million, lower sales to other utilities and marketers of $15.1 million and lower miscellaneous operating revenues of $4.3 million.  These items are discussed in detail below.

Electric operating revenues increased $38.0 million, or 2.5%, to $1,545.5 million from $1,507.5 million for the nine months ended September 30, 2011 as compared to the same period in 2010.  The increase in operating revenues of $38.0 million was due to higher electric retail sales of $80.0 million offset by lower sales to other utilities and marketers of $14.6 million and by lower miscellaneous operating revenues of $26.7 million.  These items are discussed in detail below.

Electric retail sales. Electric retail sales decreased $12.5 million, or 2.7%, to $445.6 million from $458.1 million for the three months ended September 30, 2011 as compared to the same period in 2010.  This decrease in electric retail sales was due to a $11.5 million decrease in retail electricity usage of 116,952 megawatt hours (MWhs), or 2.5%, primarily due to warmer temperatures in PSE’s service territory during the three months ended September 30, 2011 as compared to the same period in the prior year.  The average temperature during the third quarter of 2011 was 63.8 degrees, or 1.2 degrees warmer than the same period in the prior year, which resulted in a 42.1% decrease in heating degree days.  Also contributing to the decrease in retail sales were pass-through items with no impact to earnings, including a $2.8 million decrease in the residential exchange rate credit and various other pass-through items.  PTCs that are generated and provided to customers are recorded as a reduction in other electric operating revenue until PSE utilizes the tax credit on its tax return, at which time the PTCs will be credited to customers in retail sales.

Electric retail sales increased $80.0 million, or 5.5%, to $1,531.3 million from $1,451.3 million for the nine months ended September 30, 2011 as compared to the same period in 2010.  This increase in electric retail sales was due to a $51.4 million increase in retail electricity usage of 534,962 MWhs, or 3.5%, primarily due to cooler temperatures in PSE’s service territory during the nine months ended September 30, 2011 as compared to the same period in the prior year.  The average temperature during the nine months ended September 2011 was 52.6 degrees, or 1.5 degrees colder than the same period in the prior year, which resulted in a 15.1% increase in heating degree days.  Additionally, the electric rate increase effective April 8, 2010 contributed $20.3 million to the increase in electric retail sales.  Also contributing to the increase in retail sales were pass-through items with no impact to earnings including a $11.5 million increase in conservation rider program rates, a $10.1 million decrease related to the suspension of the PTC tariff credit effective July 1, 2010, a $5.2 million decrease in the residential exchange rate credit and various other pass-through items.  PTCs that are generated and provided to customers are recorded as a reduction in other electric operating revenue until PSE utilizes the tax credit on its tax return, at which time the PTCs will be credited to customers in retail sales.  Additionally, PSE’s customers were credited $21.5 million for REC revenue, effective November 1, 2010, resulting in a decrease in electric retail sales.  The $21.5 million credits to customers are offset in other electric operating revenue with no impact to earnings.  PSE’s customers continued to receive credits through April 30, 2011.

Sales to other utilities and marketers.  Sales to other utilities and marketers decreased $15.1 million and $14.6 million for the three months and nine months ended September 30, 2011 as compared to the same periods in 2010.  This decrease was primarily due to a reduction in sales volumes of 310,390 MWhs, or 33.2% which decreased revenue $10.6 million and a decline in wholesale electricity prices which decreased revenue $4.5 million.  The decrease for the nine months ended September 30, 2011 was primarily due to a reduction in sales volumes of 618,229 MWhs, or 31.5% which decreased revenue $20.1 million and a decline in wholesale electricity prices which decreased revenue by $12.3 million.  Additionally in the prior year there was a carrying value adjustment of $17.8 million related to PSE’s California wholesale energy sales regulatory asset.

Other electric operating revenue.  Other electric operating revenue decreased $4.3 million and $26.7 million for the three and nine months ended September 30, 2011, respectively, as compared to the same periods in 2010.  For the three months ended September 30, 2011, the decrease was primarily due to a decrease of $24.5 million related to PTCs, partially offset by an increase in non-core gas sales of $2.4 million and an increase in REC revenue of $17.2 million.    For the nine months ended September 30, 2011, the decrease was primarily due to a decrease in non-core gas sales of $24.1 million and a decrease of $85.0 related to PTCs, partially offset by an increase in REC revenue of $77.6 million, PTCs are deferred until PSE utilizes the tax credit on its tax return.  As discussed above, REC revenue is an offset of the REC credit provided to PSE’s customers in electric retail sales with no impact to earnings.

Electric Energy Costs

Purchased electricityexpenses increased $9.9 million, or 7.7%, and decreased $11.2 million, or 2.0%, for the three and nine months ended September 30, 2011, respectively, as compared to the same periods in 2010.  The increase for the three months ended September 30, 2011 was primarily the result of an increase in purchased power of 643,258 MWhs, or 24.9%, resulting in an increase of $25.7 million, which was driven by lower wholesale electricity costs which made it economical to purchase electricity rather than to generate the electricity, as compared to the same period in the prior year.  Also contributing to the increase was the overrecovery of power costs from customers of $9.5 million, which reduced the customer PCA deferral, as compared to an overrecovery of power costs of $1.6 million in the same period in 2010.  This increase was partially offset by lower wholesale market prices, which contributed $22.9 million.  The three months ended September 30, 2011 continued to have above-average hydroelectric generation which caused wholesale prices to be low in the Pacific Northwest.

The $11.2 million decrease in purchased electricity expenses for the nine months ended September 30, 2011 was primarily the result of lower wholesale market prices, which contributed $178.6 million to the decrease.  This decrease was partially offset by an increase in purchased power of 3,007,413 MWhs, or 30.4%, resulting in an increase of $149.5 million, which was driven by cooler temperatures during the nine months ended September 30, 2011 as compared to the same period in the prior year.  Partially offsetting the decrease was an overrecovery of power costs from customers of $14.7 million for the nine months ended September 30, 2011, which reduced the customer PCA deferral as compared to an underrecovery of power costs of $0.9 million in the same period in 2010.  The overrecovery of power costs for the nine months ended September 30, 2011 was due to above-average hydroelectric and wind generation resulting in decreased power costs associated with purchased electricity and fuel costs of PSE’s combustion turbines.

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

Electric generation fuel expense decreased $35.1 million, or 36.3%, and $61.9 million, or 31.8%, for the three and nine months ended September 30, 2011, respectively, as compared to the same periods in 2010.  The decrease for the three and nine months ended September 30, 2011 was primarily due to lower volumes of electricity generation from PSE’s combustion turbine facilities as a result of increases in hydroelectric and wind generation of 407,584 MWhs, or 26.3% and 1,354,770 MWhs, or 28.1%, respectively.  Also, coal generation at Colstrip decreased 204,888 MWhs, or 14.8% and 1,036,387 MWhs, or 26.9% for the three and nine months ended September 30, 2011, as compared to the same periods in 2010.  Additionally, due to low wholesale market prices, it was more economical to purchase wholesale energy than to generate energy from PSE’s combustion turbine facilities.

Residential exchange credits decreased $2.6 million, or 17.3%, and $5.0 million, or 9.2%, for the three and nine months ended September 30, 2011, respectively, as compared to the same periods in 2010.  The decreases in credits provided to customers was the result of lower electric residential and farm tariff rates and amounts received from the Bonneville Power Administration (BPA) Residential Exchange Program (REP).  REP credit is a pass-through tariff item with a corresponding credit in electric operating revenue and it has no impact on net income.

Natural Gas Margin

The following table displays the details of PSE’s natural gas margin for the three and nine months ended September 30, 2011 as compared to the same periods in 2010.  Gas margin is natural gas sales to retail and transportation customers less pass-through tariff items and revenue-sensitive taxes and the cost of natural gas purchased, including transportation costs to bring natural gas to PSE’s service territory.

	Three Months Ended September 30,									Nine Months Ended September 30,
Natural Gas Margin (Dollars in Thousands)	2011			2010			Percent Change			2011			2010			Percent Change
Gas operating revenue1	$	139,246		$	132,571			5.0	%	$	802,884		$	664,423			20.8	%
Less: Other gas operating revenue		(3,506	)		(3,527	)		(0.6	)		(10,813	)		(11,324	)		(4.5	)
Total gas revenue for margin		135,740			129,044			5.2			792,071			653,099			21.3
Adjustments for amounts included in revenue:
Pass-through tariff items		(2,890	)		(2,312	)		25.0			(17,058	)		(11,546	)		47.7
Pass-through revenue-sensitive taxes		(10,901	)		(10,478	)		4.0			(66,462	)		(55,026	)		20.8
Net gas revenue for margin		121,949			116,254			4.9			708,551			586,527			20.8
Minus purchased gas costs1		(63,087	)		(60,284	)		4.6			(427,016	)		(343,779	)		24.2
Natural gas margin2	$	58,862		$	55,970			5.2	%	$	281,535		$	242,748			16.0	%

________________

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

Natural gas margin increased $2.9 million and $38.8 million for the three and nine months ended September 30, 2011, respectively, as compared to the same periods in 2010.  Following is a discussion of significant items of gas operating revenue and gas energy costs which are included in gas margin:

Gas Operating Revenue

Gas operating revenues increased $6.6 million, or 5.0%, to $139.2 million from $132.6 million for the three months ended September 30, 2011 as compared to the same period in 2010.  The increase in gas operating revenues of $6.6 million was due primarily to higher natural gas retail sales of $6.4 million.  Gas operating revenues increased $138.5 million, or 20.8%, to $802.9 million from $664.4 million for the nine months ended September 30, 2011 as compared to the same period in 2010.  The increase in gas operating revenues of $138.5 million was due to higher natural gas retail sales of $138.4 million.  These items are discussed in detail below.

Natural gas retail sales.  Natural gas retail sales increased $6.4 million, or 5.2%, to $132.0 million from $125.6 million for the three months ended September 30, 2011 and $138.4 million, or 21.5%, to $781.0 million from $642.6 million for the nine months ended September 30, 2011 as compared to the same periods in 2010.  The increase in natural gas retail sales for the three months ended September 30, 2011 as compared to the same period in 2010 was primarily due to an increase in therm sales of 2.8 million, or 2.0%, that resulted in a $2.0 million increase and $3.9 million increase from 1.8% natural gas general rate tariff effective April 1, 2011 and a 0.8% PGA rate increase effective November 1, 2010.  The increase in natural gas retail sales for the nine months ended September 30, 2011 increased $103.7 million due to an increase in gas therms of 103.4 million, or 14.7% due to cooler temperatures and $35.7 million due to a 1.8% increase in natural gas general rate effective April 8, 2010 and a 0.8% PGA rate increase effective November 1, 2010.  The PGA mechanism passes through to customers increases or decreases in the natural gas supply portion of the natural gas service rates based upon changes in the price of natural gas purchased from producers and wholesale marketers or changes in natural gas pipeline transportation costs.  PSE’s net income is not affected by changes under the PGA mechanism.

Gas Energy Costs

Purchased gasexpenses increased $2.8 million, or 4.6% and $83.2 million, or 24.2%, for the three and nine months ended September 30, 2011, respectively, as compared to the same periods in 2010.  The increase for the three and nine months ended September 30, 2011 was primarily due to higher natural gas costs reflected in PGA rates effective November 1, 2010.  In addition, an increase in customer usage of 2.0% and 14.7% for the three and nine months ended September 30, 2011 as compared to the same period in 2010 contributed to the increase of costs, respectively.  The PGA mechanism provides the rates used to determine natural gas costs based on customer usage.  The rate increase was the result of increasing costs of wholesale natural gas.  The PGA mechanism allows PSE to recover expected natural gas supply and transportation costs and defer, as a receivable or liability, any natural gas supply and transportation costs that exceed or fall short of this expected natural gas cost amount in PGA mechanism rates, including accrued interest.  The PGA mechanism payable balance at September 30, 2011 was $11.0 million as compared to a receivable balance of $6.0 million at December 31, 2010.  PSE is authorized by the Washington Commission to accrue carrying costs on PGA receivable and payable balances.  A receivable balance in the PGA mechanism reflects an under recovery of market natural gas cost through rates.  A payable balance reflects over recovery of market natural gas cost through rates.

Other Operating Expenses

Net unrealized loss on derivative instrumentsdecreased $45.3 million to a loss of $33.3 million during the three months ended September 30, 2011 from a loss of $78.6 million during the same period in 2010.  Net unrealized loss on derivative instruments decreased $183.1 million to a loss of $17.7 million during the nine months ended September 30, 2011 from a loss of $200.7 million during the same period in 2010.  The reduction in losses was primarily due to a reversal of prior period losses due to settlement of derivative contracts offset by losses from declining natural gas and wholesale electricity prices on outstanding derivative contracts.  The contracts that were recorded in previous periods as losses were reversed at settlement, leading to gains.  Forward prices of electricity and natural gas declined by 8.7% and 7.4%, respectively, for the three months ended September 30, 2011 and 16.4% and 8.6%, respectively, for the nine months ended September 30, 2011.

Utility operations and maintenanceexpense increased $3.9 million, or 3.3%, and $7.3 million, or 2.1%, for the three andnine months ended September 30, 2011, respectively, as compared to the same periods in 2010.  The increase for the three and nine months ended September 30, 2011 was primarily driven by electric generation planned maintenance costs .

Depreciation expense increased $4.7 million, or 2.1%, for the nine months ended September 30, 2011 as compared to the same period in 2010.  The increase was primarily due to additional capital expenditures placed into service, net of retirements.

Conservation amortization increased $15.7 million, or 25.7%, for the nine months ended September 30, 2011, as compared to the same period in 2010.  The increase was due to a higher authorized recovery of electric and natural gas conservation expenditures.  Conservation amortization is a pass-through tariff item with no impact on earnings.

Taxes other than income taxes increased $26.5 million, or 12.6%, for the nine months ended September 30, 2011, as compared to the same periods in 2010.  The increase was primarily due to an increase in revenue sensitive taxes due to higher retail sales and an increase in property taxes.

Other Income and Interest Expense and Income Tax Expense

Other Income increased$4.1 million, or 36.8%, and $10.5 million, or 31.8%, for the three and nine months ended September 30, 2011, respectively, as compared to the same periods in 2010.  The increase is primarily due to income related to the equity component of AFUDC and Washington Commission AFUDC.  AFUDC increased $5.8 million and $15.5 million for the three and nine months ended September 30, 2011, respectively, reflecting an increase in the average construction work in progress balance in 2011 due primarily to construction of wind and hydroelectric generation construction projects.

Interest expense decreased $9.1 million, or 15.8%, and $17.5 million, or 10.4%, for the three and nine months ended September 30, 2011, respectively, as compared to the same periods in 2010.  Contributing to the decrease was an increase of $4.8 million and $10.9 million in the debt component of AFUDC for the three and nine months which was included as construction expenditures and which was due to an increase in the average construction work in progress balance in 2011 for wind and hydroelectric generation construction projects.  The decrease for three months ended September 30, 2011 included a $2.9 million decrease due to lower interest expense on the REC liability balance owed to customers.  Also contributing to the nine months ended September 30, 2011 was a decrease related to a $6.9 million write off in the prior year of a regulatory asset of deferred interest paid to the Internal Revenue Service (IRS) related to the Simplified Service Cost Method deduction from prior years, which was disallowed in the general rate case order of April 2, 2010.

Income tax benefit decreased $26.3 million and income tax expense increased $103.8 million for the three and nine months ended September 30, 2011, respectively, as compared to the same periods in 2010.  The income tax benefit decrease for the three months ended September 30, 2011 was due to a lower pre-tax loss as compared to the same period in 2010.  The increase in income tax expense for the nine months ended September 30, 2011 was due to a higher pre-tax income as compared to the same period in 2010.

Puget Energy

Summary Results of Operations

All the operations of Puget Energy are conducted through its subsidiary PSE.

Puget Energy’s net income (loss) for the three and nine months ended September 30, 2011 and 2010 were as follows:

	Three Months Ended September 30,									Nine Months Ended September 30,
Benefit/(Expense) (Dollars in Thousands)	2011			2010			Percent Change			2011			2010			Percent Change
PSE net income (loss)	$	(9,107	)	$	(29,559	)		(69.2	)%	$	145,245		$	(67,326	)		*	%
Other operating revenue		--			--			*			(689	)		--			*
Purchased electricity		144			144			*			433			433			*
Net unrealized gain on energy derivative instruments		3,087			15,284			(79.8	)		37,569			91,519			(58.9	)
Non-utility expense and other		233			(1,019	)		(122.9	)		1,171			(4,223	)		(127.7	)
Other income		2			--			*			8			--			*
Non-hedged interest rate derivative expense		(3,395	)		--			*			(28,855	)		--			*
Interest expense 1		(38,870	)		(22,771	)		(70.7	)		(114,366	)		(66,323	)		(72.4	)
Income tax benefit (expense)		11,436			22			*			35,480			(7,507	)		*
Puget Energy net income (loss)	$	(36,470	)	$	(37,899	)		(3.8	)%	$	75,996		$	(53,427	)		(242.2	)%

__________

*	Not 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, 2011 was $36.5 million with operating revenue of $597.8 million as compared to net loss of $37.9 million with operating revenue of $622.8 million for the same period in 2010.  Puget Energy’s net loss for the nine months ended September 30, 2011 was $76.0 million with operating revenue of $2.4 billion as compared to a net loss of $53.4 million with operating revenue of $2.2 billion for the same period in 2010.  The following are significant factors that impacted Puget Energy’s net income which are not included in PSE’s discussion:

Net unrealized gain on derivative instrumentsdecreased $12.2 million and $54.0 million for the three and nine months ended September 30, 2011, respectively, as compared to the same periods in 2010 due to the effects of purchase accounting and the fair value amortization of derivative contracts.  The forward prices of electricity and natural gas declined 8.7% and 7.4%, respectively, for the three months ended September 30, 2011 and declined 16.4% and 8.6%, respectively, for the nine months ended September 30, 2011.

Non-hedged interest rate derivative expense increased $3.4 million and $28.9 million for the three and nine months ended September 30, 2011, respectively, as compared to the same periods in 2010 as a result of paying down a portion of a five-year term-loan due February 2014 in December 2010 and June 2011.  The five-year variable rate term-loan was initially fully hedged; however a portion of the hedge was unwound during the three months ended June 30, 2011.  Puget Energy settled three interest rate swap contracts in June 2011.  Puget Energy has $434.4 million notional amount of interest rate swaps that are not presently used to hedge variable interest payments.

Interest expense increased $16.1 million and $48.1 million for the three and nine months ended September 30, 2011, respectively, as compared to the same periods in 2010 due to increased outstanding debt.  In December 2010 and June 2011, Puget Energy issued fixed rate notes with higher interest rates to refinance and extend the debt maturity of a portion of a five-year term-loan due February 2014.

Income tax benefit increased $11.4 million and $43.0 million for the three and nine months ended September 30, 2011, respectively, as compared to the same periods in 2010 due primarily to higher pre-tax loss.

Capital Requirements

Contractual Obligations and Commercial Commitments

The only changes to the contractual obligations and consolidated commercial commitments set forth in Part II, Item 7 in Puget Energy’s and PSE’s combined annual report on Form 10-K for the year ended December 31, 2010 are as follows: (1) PSE’s issuance of $300.0 million senior notes on March 25, 2011 and the maturity of $260.0 million of senior notes in February 2011, which increased contractual obligations by $548.1 million net of redemptions (including accrued interest through the life of the issuance); (2) Puget Energy’s issuance of $500.0 million in senior secured notes on June 3, 2011 and the concurrent paydown of $484.0 million under the Puget Energy term-loan and (3) a $287.0 million draw on Puget Energy’s capital expenditure facility, which increased contractual obligations by $587.8 million net of redemptions (including accrued interest through the life of the issuance).

Utility Construction Program

PSE’s construction programs for generating facilities, the electric transmission system and the natural gas and electric distribution systems are designed to meet regulatory requirements and customer growth and to support reliable energy delivery.  Construction expenditures, excluding equity AFUDC, were $784.6 million for the nine months ended September 30, 2011.  Presently planned utility construction expenditures, excluding AFUDC, for 2011, 2012 and 2013 are as follows:

Capital Expenditure Projections (Dollars in Thousands)	2011		2012		2013
Energy delivery, technology and facilities	$	667,300	$	665,977	$	631,189
New generating resources		376,600		32,481		1,211
Total expenditures	$	1,043,900	$	698,458	$	632,400

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

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

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

Baker Project.  Under the terms of the FERC issued 50-year operating license for the Baker power generating facility, PSE has completed several capital projects and is currently undertaking several more, each of which implements various license provisions and upgrades for the 80-year old facility.

Lower Snake River.  The Lower Snake River wind project is PSE’s newest renewable energy development project.  The project was designed to be built in five phases.  PSE began construction on Phase 1 in 2010 which will total 343 MW of capacity when complete.  PSE anticipates that Phase 1 will be commercially available in April 2012.

Capital Resources

Cash From Operations

Puget Sound Energy

Cash generated from operations for the nine months ended September 30, 2011 was $795.2 million, an increase of $243.5 million from the $551.7 million generated during the nine months ended September 30, 2010.  The increase in cash flow was primarily the result of the following:

·   PSE’s deferred tax increased $58.8 million during the nine months ended September 30, 2011 as compared to a decrease in 2010 of $66.1 million, causing an operating cash flow increase of $124.9 million.

·   PSE’s PGA mechanism had a $17.0 million over recovery from customers during the nine months ended September 30, 2011 as compared to $53.1 million payment to customers related to over collection of prior year plan-related rates during the same period in 2010, causing an operating cash flow increase of $70.1 million.

·   Net income increased $212.6 million during the nine months ended September 30, 2011 as compared to the same period in 2010.  This increase was partially offset by a non-cash unrealized derivative instruments loss of $183.1 million, causing an operating cash flow increase of $29.5 million.

·   Material and supplies inventory increased $7.5 million during the nine months ended September 30, 2011 as compared to a decrease of $22.0 million during the same period in 2010, causing an operating cash flow increase of $29.5 million.

·   Other long term liabilities increased by $26.0 million during the nine months ended September 30, 2011 as compared to a decrease of $2.8 million during the same period in 2010, causing an operating cash flow increase of $28.7 million.

·   Other long term assets decreased by $4.8 million during the nine months ended September 30, 2011 as compared to a decrease of $27.8 million during the same period in 2010, causing an operating cash flow increase of $23.0 million.

·   Conservation amortization increased by $76.5 million during the nine months ended September 30, 2011 as compared to an increase of $60.9 million during the same period in 2010, causing an operating cash flow increase of $15.6 million.

·   Accounts receivable and unbilled revenue decreased $214.7 million during the nine months ended September 30, 2011 as compared to a decrease of $201.4 million during the same period in 2010, causing an operating cash flow increase of $13.3 million.

The increase in cash generated from operating activities in 2011 was partially offset by the following:

·   Accounts payable decreased by $45.9 million during the nine months ended September 30, 2011 as compared to an increase of $9.3 million during the same period in 2010, causing an operating cash flow decrease of $55.2 million.

·   A prepayment of $27.2 million was made for the Lower Snake River wind project in Columbia and Garfield counties during the nine months ended September 30, 2011; whereas no payment was made during the same period in 2010, causing a decrease in cash flow from operating activities.

·   Other regulatory liabilities increased by $11.8 million during the nine months ended September 30, 2011 as compared to an increase of $31.5 million during the same period in 2010, causing an operating cash flow decrease of $19.7 million.

·   AFUDC (equity component) decreased cash flows by $22.0 million during the nine months ended September 30, 2011 as compared to a decrease of $8.5 million during the same period in 2010, causing an operating cash flow decrease of $13.5 million.  AFUDC primarily increased due to an increase in average construction work in progress balances.

Puget Energy

Cash generated from operations for the nine months ended September 30, 2011 was $894.2 million, an increase of $126.3 million from the $767.9 million generated during the nine months ended September 30, 2010.  The increase included $243.5 million from the cash provided by the operating activities of PSE as previously discussed.  Other factors contributing to the increase included the following:

·   Puget Energy’s net unrealized loss (gain) on derivative instruments was a loss of $16.6 million during the nine months ended September 30, 2011 compared to a loss of $109.2 million in the same period in 2010, causing an increase in cash from operations of $90.5 million.

The increase in cash generated from operating activities in 2011 was partially offset by the following:

·   As a result of the merger, $149.5 million in derivative settlement payments were reclassified to financing activities during the nine months ended September 30, 2011 as compared to $279.1 million during the same period in 2010, resulting in a decrease in operating cash flows of $129.6 million.  This decrease was due to a decline in the number of contracts settled during 2011 as compared to the prior period.  These contracts represent proceeds received from derivative instruments that included financing elements at the merger date.

·   Puget Energy’s deferred tax decreased $23.5 million during the nine months ended September 30, 2011 as compared to the same period of the prior year, causing a decrease in cash from operations.

Financing Program

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

Credit Facilities and Commercial Paper

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

Puget Sound Energy Credit Facilities

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

PSE’s credit agreements contain usual and customary affirmative and negative covenants that, among other things, place limitations on PSE’s ability to incur additional indebtedness and liens, issue equity, pay dividends, transact with affiliates and make asset dispositions and investments.  The credit agreements also contain financial covenants which include a cash flow interest coverage ratio and, in addition, if PSE has a below investment grade credit rating, a cash flow to net debt outstanding ratio (each as specified in the facilities).  PSE certifies its compliance with such covenants to participating banks each quarter.  As of September 30, 2011, PSE was in compliance with all applicable covenants.

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

As of September 30, 2011, no loan amounts were drawn or outstanding under PSE’s $400.0 million working capital facility.  A $12.5 million letter of credit supporting contracts was outstanding under the facility and there was $119.0 million outstanding under the commercial paper program.   The $400.0 million capital expenditure facility had no amounts drawn and outstanding.  No amounts were drawn or outstanding (including letters of credit) under PSE’s $350.0 million facility supporting energy hedging.  Outside of the credit agreements, PSE had a $5.3 million letter of credit in support of a long-term transmission contract.

Demand Promissory Note.  On June 1, 2006, PSE entered into a revolving credit facility with Puget Energy in the form of a credit agreement and a Demand Promissory Note (Note) pursuant to which PSE may borrow up to $30.0 million from Puget Energy subject to approval by Puget Energy.  Under the terms of the Note, PSE pays interest on the outstanding borrowings based on the lower of the weighted-average interest rates of PSE’s outstanding commercial paper or PSE’s senior unsecured revolving credit facility.  Absent such borrowings, interest is charged at one-month LIBOR plus 0.25%.  At September 30, 2011, the outstanding balance of the Note was $30.0 million.  The outstanding balance and the related interest under the Note are eliminated by Puget Energy upon consolidation of PSE’s financial statements.

Puget Energy Credit Facilities

At the time of the merger in February 2009, Puget Energy entered into a $1.225 billion five-year term loan and a $1.0 billion credit facility for funding capital expenditures.  As of September 30, 2011, Puget Energy had fully drawn the five-year term-loan which, after previous repayments, had a remaining outstanding balance of $298.0 million.  Also, as of September 30, 2011, Puget Energy had drawn $545.0 million under the $1.0 billion capital expenditure funding facility.   The term-loan and capital expenditure facility mature in February 2014.  These credit agreements contain usual and customary affirmative and negative covenants which are similar to PSE’s credit facilities.  Puget Energy’s credit agreements contain financial covenants based on the following three ratios:  cash flow interest coverage, cash flow to net debt outstanding and debt service coverage (cash available for debt service to borrower interest), each as specified in the facilities.  Puget Energy certifies its compliance with these covenants each quarter.  As of September 30, 2011, Puget Energy was in compliance with all applicable covenants.

In May 2010, Puget Energy’s credit facilities were amended, in part, to include a provision for the sharing of collateral with future note holders when notes are issued to repay and reduce the size of the credit facilities.

These facilities contain similar terms and conditions and are syndicated among numerous committed lenders.  The agreements provide Puget Energy with the ability to borrow at different interest rate options and include variable fee levels.  Borrowings may be at the bank’s prime rate or at floating rates based on LIBOR plus a spread based upon Puget Energy’s credit rating.  Puget Energy must pay a commitment fee on the unused portion of the $1.0 billion facility.  The spreads and the commitment fee depend on Puget Energy’s credit ratings.  As of the date of this report, the spread over prime rate is 1.0%, the spread to the LIBOR is 2.0% and the commitment fee is 0.75%.

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, 2011, approximately $387.4 million of unrestricted retained earnings were available for the payment of dividends under the most restrictive mortgage indenture covenant.

Beginning February 6, 2009, pursuant to the terms of the Washington Commission merger order, PSE may not declare or pay dividends if PSE’s common equity ratio, calculated on a regulatory basis, is 44.0% or below except to the extent a lower equity ratio is ordered by the Washington Commission.  Also, pursuant to the merger order, PSE may not declare or make any distribution unless on the date of distribution PSE’s corporate credit/issuer rating is investment grade, or, if its credit rating is 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 three to one.  The common equity ratio calculated on a regulatory basis, was 49.0% at September 30, 2011 and the EBITDA to interest expense for the twelve months ended September 30, 2011 was 4.4 to one.

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

Puget Energy’s ability to pay dividends is also limited by the merger order issued by the Washington Commission as well as by the terms of its credit facilities.  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 two to one.  For the twelve months ended September 30, 2011, the EBITDA to interest expense ratio was 2.8 to one.  In accordance with the terms of the Puget Energy credit facilities, Puget Energy is limited to paying a dividend within an eight-day period that begins seven days following the delivery of quarterly or annual financial statements to the facility agent.  Puget Energy is not permitted to pay dividends during any Event of Default, or if the payment of dividends would result in an Event of Default (as defined in the facilities), such as failure to comply with certain financial covenants.  In addition, in order to declare or pay unrestricted dividends, Puget Energy’s interest coverage ratio may not be less than 1.5 to one and its cash flow to net debt outstanding ratio may not be less than 8.25% for the 12 months ending each quarter-end.  Puget Energy is also subject to other restrictions, such as a “lock up” provision that, in certain circumstances, such as failure to meet certain cash flow tests, may further restrict Puget Energy’s ability to pay dividends.

At September 30, 2011, 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 financing for Puget Energy and PSE are limited by provisions in their credit agreements, restated articles of incorporation and PSE’s mortgage indentures.  Under its credit agreements, Puget Energy is generally limited to permitted refinancings and borrowings under its credit facilities and by restrictions placed upon its subsidiaries.  One such restriction limits PSE’s long-term debt issuances to not exceed $500.0 million per year, plus any amount needed to refinance maturing bonds.  Unused amounts under this limitation may be carried forward into future years.  Puget Energy’s facilities contain a provision whereby additional capital expenditure loans up to $750.0 million may, under certain conditions, be made available after the $1.0 billion capital expenditure commitment has been fully borrowed.

PSE’s ability to issue additional secured debt may be limited by certain restrictions contained in its electric and natural gas mortgage indentures.  Under the most restrictive tests, at September 30, 2011, PSE could issue:

·   Approximately $1.6 billion of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately $2.6 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, 2011; and

·   Approximately $221.0 million of additional first mortgage bonds under PSE’s natural gas mortgage indenture based on approximately $368.3 million of gas bondable property available for issuance, subject to a combined gas and electric interest coverage test of 1.75 times net earnings available for interest and a gas interest coverage test of 2.0 times net earnings available for interest (as defined in the natural gas utility mortgage), both of which PSE exceeded at September 30, 2011.

At September 30, 2011, PSE had approximately $5.7 billion in electric and natural gas ratebase to support the interest coverage ratio limitation test for net earnings available for interest.

Shelf Registrations and Long-Term Debt Activity

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 March 25, 2011, PSE issued $300.0 million of senior notes secured by first mortgage bonds.  The notes have a term of 30 years and an interest rate of 5.638%.  Net proceeds from the note offering were used by PSE to repay short-term debt outstanding under its capital expenditure credit facility, which debt was incurred to fund utility capital expenditures and replenish cash used to repay the February 2011 maturity of $260.0 million medium-term notes with a 7.69% interest rate.

On June 17, 2011, Puget Energy exchanged $449.9 million of its 6.5% senior secured notes that were originally issued in a December 2010 private placement for registered notes of $450.0 million.

On June 3, 2011, Puget Energy issued $500 million of senior secured notes in a private placement.  The notes have a term of 10 years and 3 months and mature on September 1, 2021.  The interest rate on the notes is 6.0%.  The notes are secured by an interest in substantially all of Puget Energy’s assets, which consists mainly of all the issued and outstanding stock of PSE and the stock of Puget Energy held by Puget Equico.  The notes contain a change of control provision pursuant to which holders of the notes may have the right to require Puget Energy to repurchase all or any part of the notes at a purchase price in cash equal to 101.0% of the principal amount of the notes, plus accrued and unpaid interest.  Net proceeds from the issue of the notes were used to repay a portion of the $782.0 million remaining balance on the $1.225 billion Puget Energy five-year term-loan and to retire a portion of the interest rate hedges associated with that loan.

On August 10, 2011, Puget Energy exchanged $500.0 million of its 6.0% senior secured notes that were originally issued in June 2011 private placement for registered notes of the same amount.

Other

Proceedings Relating to the Bonneville Power Administration

PSE has been a party to certain agreements with BPA that provide payments under its REP to PSE, which PSE passes through to its residential and small farm electric customers.  In 2008, PSE entered into agreements with BPA for REP payments to 2012 and for the period 2012 to 2028.  PSE and other parties have sought United States Court of Appeals for the Ninth Circuit (Ninth Circuit) review regarding BPA’s agreements for REP payments during these periods.  In July 2011, BPA, PSE, and other parties (including some but not all litigants in the Ninth Circuit proceedings) entered into a agreement that addresses REP payments to PSE and other investor-owned utilities for periods ending September 30, 2028 and that is intended to resolve disputes in the Ninth Circuit over REP payments.  The amounts of REP payments under these agreements and the methods utilized in setting them are subject to FERC review or judicial review, or both, and are subject to adjustment, which may affect the amount of REP payments made or to be made by BPA to PSE.  It is not clear what impact, if any, these reviews or other REP-related litigation may ultimately have on PSE.

Proceedings Relating to Snoqualmie Falls

On July 7, 2010, a lawsuit was filed in the U.S. District Court for the Western District of Washington by the Snoqualmie Valley Preservation Alliance (SVPA), a group of downstream landowners, against the United States Army Corps of Engineers (Corps) challenging permits issued by the Corps in connection with the redevelopment of the Snoqualmie Falls Hydroelectric Project.  PSE sought and was granted permission to intervene in the proceeding.  Motions for summary judgment were filed by the plaintiffs and the Corps.  PSE joined the Corps’ motion and filed a motion for summary judgment arguing the plaintiffs’ claims were barred as untimely and improper.  On March 30, 2011, the District Court issued an order granting the Corps’ motion for summary judgment, denying the plaintiffs’ motion for summary judgment and dismissing the plaintiffs’ lawsuit.  On May 26, 2011, plaintiffs filed a notice of appeal with the U.S. Court of Appeals for the Ninth Circuit, claiming that the District Court erred in dismissing the lawsuit.  SVPA submitted its opening brief on September 20, 2011, and response briefs were submitted by November 3, 2011.  Oral argument on the appeal will occur thereafter, with a decision by the Court of Appeals to follow.  Litigation is subject to numerous uncertainties and PSE is unable to predict the ultimate outcome of this matter.

Pacific Northwest Refund Proceeding

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

Colstrip Matters

In May 2003, approximately 50 plaintiffs initiated an action against the owners of Colstrip, including PSE, regarding seepage from two different wastewater pond areas and from the Colstrip water supply pond.  The defendants reached an agreement on a global settlement with all plaintiffs and PSE expensed its share of the settlement in 2008.  PSE received a partial reimbursement for its share from insurers in December 2010 and January 2011.

On March 29, 2007, a second complaint related to pond seepage was filed in Montana State District Court in Rosebud County, on behalf of two ranch owners alleging damage due to the Colstrip Units 3 & 4 effluent holding pond.  A mediation between plaintiffs and PPL Montana, LLC, the operator of Units 3 & 4, took place on July 14, 2010 and parties are working toward a final settlement.

Item 3.                      Quantitative and Qualitative Disclosure about Market Risk

Energy Portfolio Management

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

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

·   Ensure physical energy supplies are available to reliably and cost-effectively serve retail load;

·   Manage the energy portfolio prudently to serve retail load at overall least cost and limit undesired impacts on PSE’s customers and shareholders;

·   Reduce power costs by extracting the value of PSE’s assets; and

·   Meet the credit, liquidity, financing, tax and accounting requirements of PSE.

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

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

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

The following table presents the Company’s energy derivative instruments that do not meet the Normal Purchase Normal Sale (NPNS) exception at September 30, 2011 and December 31, 2010:

Puget Energy and Puget Sound Energy	Energy Derivatives
Derivative Portfolio (Dollars in thousands)	September 30, 2011				December 31, 2010
	Assets		Liabilities		Assets		Liabilities
Electric portfolio:
Current	$	4,905	$	155,966	$	4,716	$	142,780
Long-term		6,280		77,163		5,046		99,801
Total electric derivatives	$	11,185	$	233,129	$	9,762	$	242,581
Natural gas portfolio:
Current	$	1,971	$	98,510	$	2,784	$	100,273
Long-term		4,391		47,685		3,187		55,378
Total natural gas derivatives	$	6,362	$	146,195	$	5,971	$	155,651
Total derivatives	$	17,547	$	379,324	$	15,733	$	398,232

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

At September 30, 2011, the Company had total assets of $6.4 million and total liabilities of $146.2 million related to financial contracts used to economically hedge the cost of physical natural gas purchased to serve natural gas customers.  All fair value adjustments of derivatives relating to the natural gas business have been reclassified to a deferred account in accordance with ASC 980, “Regulated Operations” (ASC 980), due to the PGA mechanism.  All increases and decreases in the cost of natural gas supply are passed on to customers with the PGA mechanism.  As the gains and losses on the hedges are realized in future periods, they will be recorded as natural gas costs under the PGA mechanism.

A hypothetical 10.0% increase or decrease in market prices of natural gas and electricity would change the fair value of the Company derivative contracts by $105.7 million and would impact the fair value of those contracts marked-to-market in earnings by $68.7 million after-tax related to derivatives not designated as hedges.

Contingent Features and Counterparty Credit Risk

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

Where deemed appropriate, and when allowed under the terms of the agreements, PSE may request collateral or other security from its counterparties to mitigate the potential credit default losses.  Criteria employed in this decision include, among other things, the perceived creditworthiness of the counterparty and the expected credit exposure.  As of September 30, 2011, PSE held approximately $11.1 million worth of standby letters of credit in support of various electricity and REC transactions.

It is possible that volatility in energy commodity prices could cause PSE to have material credit risk exposures with one or more counterparties.  If such counterparties fail to perform their obligations under one or more agreements, PSE could suffer a material financial loss.  As of September 30, 2011, approximately 95.4% of PSE’s energy and natural gas portfolio exposure, including NPNS transactions, is with counterparties that are rated at least investment grade by the major rating agencies, while 4.6% are either rated below investment grade or are not rated by rating agencies.  PSE assesses credit risk internally for counterparties that are not rated.

PSE has entered into commodity master arrangements with its counterparties to mitigate credit exposure to those counterparties.  PSE generally enters into the following master arrangements: (1) WSPP, Inc. (WSPP) agreements – standardized power sales contracts in the electric industry; (2) International Swaps and Derivatives Association (ISDA) agreements – standardized financial gas and electric contracts; and (3) North American Energy Standards Board (NAESB) agreements – standardized physical gas contracts.  PSE believes that entering into such agreements reduces the risk of default by allowing a counterparty the ability to make only one net payment.

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

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

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

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

The Company applies the counterparty’s default factor to compute credit reserves for counterparties that are in a net asset position.  The Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate.  The fair value of derivatives includes the impact of taking into account credit and non-performance reserves.  As of September 30, 2011, the Company was in a net liability position with the majority of its counterparties, therefore the default factors of counterparties did not have a significant impact on reserves for the year.  Despite its net liability position, PSE was not required to post any additional collateral with any of its counterparties. Additionally, PSE did not trigger collateral requirements with any of its counterparties, nor were any of PSE’s counterparties required to post additional collateral resulting from credit rating downgrades.

Interest Rate Risk

The Company believes its interest rate risk primarily relates to the use of short-term debt instruments, 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 of various maturities.  The Company utilizes internal cash from operations, commercial paper and credit facilities to meet short-term funding needs.  Short-term obligations are commonly refinanced with fixed-rate bonds or notes when needed and when interest rates are considered favorable.  The Company may also enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with its debt.  As of September 30, 2011, Puget Energy had four interest rate swap contracts outstanding and PSE did not have any outstanding interest rate swap instruments.

In February 2009, Puget Energy entered into interest rate swap transactions to hedge the risk associated with one-month LIBOR floating rate debt.  Subsequently, in order to satisfy a commitment the Company made to the Washington Commission and to mitigate refinancing risk, the Company refinanced a portion of the underlying debt hedged by the interest rate swaps in December 2010.  As a result of the refinance, the Company de-designated the cash flow hedging relationship related to the interest rate swaps.  To date, Puget Energy has refinanced the underlying debt on several occasions and correspondingly, has net settled three interest rate swaps with a total notional amount of $205.6 million.  Puget Energy intends to continue refinancing this debt and settling related interest rate swaps as market conditions warrant.  Going forward, all changes in market value will be recorded in earnings instead of OCI.

At September 30, 2011, the fair value of the interest rate swaps was a $59.4 million pre-tax loss.  This fair value considers the risk of Puget Energy’s non-performance by using Puget Energy’s incremental borrowing rate on unsecured debt over the risk-free rate in the valuation estimate.  The ending balance in OCI includes a loss of $26.5 million pre-tax and $17.2 million after tax, related to the interest rate swaps designated as marked-to-market during the current reporting period. The OCI balance relates to the loss that was recorded when the cash flow hedge was de-designated in December 2010.

A hypothetical 10% increase or decrease in interest rates would change the fair value of Puget Energy interest rate swaps by $1.8 million, with a corresponding after-tax increase in unrealized gain or loss recorded in earnings of $1.2 million that related to interest rates swaps not designated as hedges.

The following table presents Puget Energy’s interest rate swaps at September 30, 2011 and December 31, 2010:

Puget Energy Derivative Portfolio (Dollars in Thousands)	September 30,  2011		December 31,  2010
	Liabilities		Liabilities
Interest rate swaps:
Current	$	25,826	$	30,047
Long-term		33,616		27,956
Total	$	59,442	$	58,003

From time to time PSE may enter into treasury locks or forward starting swap contracts to hedge interest rate exposure related to an anticipated debt issuance.  The ending balance in OCI related to the forward starting swaps and previously settled treasury lock contracts at September 30, 2011 was a net loss of $7.0 million after tax and accumulated amortization.  This compares to an after-tax loss of $7.3 million in OCI as of December 31, 2010.  All financial hedge contracts of this type are reviewed by an officer, presented to the Board of Directors or a committee of the Board, as applicable, and are approved prior to execution.  PSE had no treasury locks or forward starting swap contracts outstanding at September 30, 2011.

Item 4.                      Controls and Procedures

Puget Energy

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of Puget Energy’s management, including the President and Chief Executive Officer and the Vice President Finance, Treasurer and Principal 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, 2011, the end of the period covered by this report.  Based upon that evaluation, the President and Chief Executive Officer and the Vice President Finance, Treasurer and Principal Financial Officer of Puget Energy concluded that these disclosure controls and procedures are effective.

Changes in Internal Control Over Financial Reporting

There have been no changes in Puget Energy’s internal control over financial reporting during the three months ended September 30, 2011 that have materially affected, or are reasonably likely to materially affect, Puget Energy’s internal control over financial reporting.

Puget Sound Energy

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of PSE’s management, including the President and Chief Executive Officer and the Vice President Finance, Treasurer and Principal 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, 2011, the end of the period covered by this report.  Based upon that evaluation, the President and Chief Executive Officer and the Vice President Finance, Treasurer and Principal Financial Officer of PSE concluded that these disclosure controls and procedures are effective.

Changes in Internal Control Over Financial Reporting

There have been no changes in PSE’s internal control over financial reporting during the three months ended September 30, 2011 that have materially affected, or are reasonably likely to materially affect, PSE’s internal control over financial reporting.

Part II                    Other Information

Item 1.                      Legal Proceedings

For details on legal proceedings, see the Litigation footnote in the notes to the consolidated financial statements of this Quarterly Report on Form 10-Q.  Contingencies arising out of the normal course of PSE’s business existed as of September 30, 2011.  Litigation is subject to numerous uncertainties and PSE is unable to predict the ultimate outcome of these matters.

Item 1A.                  Risk Factors

There have been no material changes from the risk factors set forth in Part I, Item 1A in Puget Energy’s and PSE’s Form 10-K for the period ended December 31, 2010 and in Part II, Item 1A in Puget Energy’s and PSE’s Form 10-Q for the period ended March 31, 2011.

Item 6.                      Exhibits

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

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/ James W. Eldredge
	James W. Eldredge Vice President, Controller and Chief Accounting Officer
Date:  November 9, 2011	Chief Accounting Officer and Officer duly authorized to sign this report on behalf of each registrant

EXHIBIT INDEX

12.1*	Statement setting forth computation of ratios of earnings to fixed charges of Puget Energy, Inc. (2006 through 2010, and 12 months ended September 30, 2011).
12.2*	Statement setting forth computation of ratios of earnings to fixed charges of Puget Sound Energy, Inc. (2006 through 2010 and 12 months ended September 30, 2011).
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, 2011, filed on November 9, 2011, formatted in XBRL: (i) the Consolidated Statement of Income (Unaudited), (ii) the Consolidated Statements of Comprehensive Income (Unaudited), (iii) the Consolidated Balance Sheets (Unaudited), (iii) the Consolidated Statements of Cash Flows (Unaudited), and (iv) the Notes to Consolidated Financial Statements tagged as blocks of text (submitted electronically herewith).

__________________

*

Filed herewith.

**

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