Puget Energy (PSD) 10-Q 2010 Q4 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, 2010

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

As of February 6, 2009, 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 Months Ended September 30, 2010 and 2009
	Consolidated Statements of Income – Nine Months Ended September 30, 2010, February 6, 2009 to September 30, 2009 (Successor) and January 1, 2009 to February 5, 2009 (Predecessor)
	Consolidated Statements of Comprehensive Income – Three Months Ended September 30, 2010 and 2009
	Consolidated Statements of Comprehensive Income – Nine Months Ended September 30, 2010, February 6, 2009 to September 30, 2009 (Successor) and January 1, 2009 to February 5, 2009 (Predecessor)
	Consolidated Balance Sheets – September 30, 2010 and December 31, 2009
	Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2010, February 6, 2009 to September 30, 2009 (Successor) and January 1, 2009 to February 5, 2009 (Predecessor)
	Puget Sound Energy, Inc.
	Consolidated Statements of Income – Three and Nine Months Ended September 30, 2010 and 2009
	Consolidated Statements of Comprehensive Income – Three and Nine Months Ended September 30, 2010 and 2009
	Consolidated Balance Sheets – September 30, 2010 and December 31, 2009
	Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2010 and 2009
	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
ASU	Accounting Standards Update
BPA	Bonneville Power Administration
EBITDA	Earnings Before Interest, Tax, Depreciation and Amortization
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	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 different registrants, Puget Energy, Inc. (Puget Energy) as a voluntary Securities and Exchange Commission filer, 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,” “estimates,” “expects,” “future,” “intends,” “plans,” “predicts,” “projects,” “will likely result,” “will continue” or similar expressions identify forward-looking statements.

Forward-looking statements 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 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, financings, 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 FERC or 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 jurisdiction;

·   Inability to realize deferred tax assets and use production tax credits 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 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 Companies’ 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, Puget Energy and PSE undertake 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,
	2010			2009
Operating revenue:
Electric	$	489,608		$	449,658
Gas		132,571			142,128
Other		650			840
Total operating revenue		622,829			592,626
Operating expenses:
Energy costs:
Purchased electricity		127,792			160,723
Electric generation fuel		96,712			77,164
Residential exchange		(15,173	)		(19,271	)
Purchased gas		60,284			72,463
Net unrealized (gain) loss on derivative instruments		63,275			(74,831	)
Utility operations and maintenance		117,155			116,129
Non-utility expense and other		4,207			4,542
Depreciation		73,111			66,932
Amortization		18,355			16,522
Conservation amortization		20,392			12,836
Taxes other than income taxes		58,903			57,785
Total operating expenses		625,013			490,994
Operating income (loss)		(2,184	)		101,632
Other income (deductions):
Other income		11,073			13,272
Other expense		(1,074	)		(1,299	)
Interest charges:
AFUDC		3,924			2,661
Interest expense		(84,473	)		(72,930	)
Income (loss) before income taxes		(72,734	)		43,336
Income tax (benefit) expense		(34,835	)		18,829
Net income (loss)	$	(37,899	)	$	24,507

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

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands)

(Unaudited)

	Successor						Predecessor
	Nine Months Ended September 30, 2010			February 6, 2009 – September 30, 2009			January 1, 2009 – February 5, 2009
Operating revenue:
Electric	$	1,507,549		$	1,293,024		$	213,618
Gas		664,423			685,484			190,001
Other		2,350			4,597			94
Total operating revenue		2,174,322			1,983,105			403,713
Operating expenses:
Energy costs:
Purchased electricity		556,788			518,912			90,737
Electric generation fuel		194,649			131,163			11,961
Residential exchange		(54,510	)		(60,063	)		(12,542	)
Purchased gas		343,779			403,741			120,925
Net unrealized (gain) loss on derivative instruments		109,183			(125,166	)		3,867
Utility operations and maintenance		355,569			315,479			37,650
Non-utility expense and other		11,965			11,332			112
Merger and related costs		--			2,731			44,324
Depreciation		217,765			177,269			21,773
Amortization		53,011			43,113			4,969
Conservation amortization		60,874			39,803			7,592
Taxes other than income taxes		210,304			188,889			36,935
Total operating expenses		2,059,377			1,647,203			368,303
Operating income		114,945			335,902			35,410
Other income (deductions):
Other income		32,887			31,938			3,653
Other expense		(4,147	)		(5,064	)		(369	)
Charitable foundation funding		--			(5,000	)		--
Interest charges:
AFUDC		9,832			6,210			350
Interest expense		(244,839	)		(189,458	)		(17,291	)
Income (loss) before income taxes		(91,322	)		174,528			21,753
Income tax (benefit) expense		(37,895	)		54,391			8,997
Net income (loss)	$	(53,427	)	$	120,137		$	12,756

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,
	2010			2009
Net income (loss)	$	(37,899	)	$	24,507
Other comprehensive loss:
Net unrealized loss on interest rate swaps during the period, net of tax of $(10,640) and $(11,681), respectively		(19,761	)		(21,694	)
Reclassification of net unrealized loss on interest rate swaps during the period, net of tax of $3,024 and $2,959, respectively		5,614			5,495
Net unrealized loss from pension and postretirement plans, net of tax of $(90) and $0, respectively		(166	)		--
Net unrealized gain on energy derivative instruments during the period, net of tax of $0 and $16, respectively		--			30
Reclassification of net unrealized loss on energy derivative instruments settled during the period, net of tax of $1,276 and $6,699, respectively		2,370			12,440
Other comprehensive loss		(11,943	)		(3,729	)
Comprehensive income (loss)	$	(49,842	)	$	20,778

	Successor						Predecessor
	Nine Months Ended September 30, 2010			February 6, 2009 – September 30, 2009			January 1, 2009 – February 5, 2009
Net income (loss)	$	(53,427	)	$	120,137		$	12,756
Other comprehensive loss:
Net unrealized loss on interest rate swaps during the period, net of tax of $(34,105), $(12,493) and $0, respectively		(63,338	)		(23,203	)		--
Reclassification of net unrealized loss on interest rate swaps during the period, net of tax of $8,932, $7,178 and $0, respectively		16,588			13,330			--
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $(91), $0 and $170, respectively		(169	)		--			315
Net unrealized loss on energy derivative instruments during the period, net of tax of $0, $(14,120) and $(13,010), respectively		--			(26,222	)		(24,162	)
Reclassification of net unrealized loss on energy derivative instruments settled during the period, net of tax of $1,952, $7,824 and $2,428, respectively		3,625			14,531			4,509
Amortization of financing cash flow hedge contracts to earnings, net of tax of $0, $0 and $15, respectively		--			--			26
Other comprehensive loss		(43,294	)		(21,564	)		(19,312	)
Comprehensive income (loss)	$	(96,721	)	$	98,573		$	(6,556	)

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

PUGET ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

(Unaudited)

ASSETS

	September 30, 2010			December 31, 2009
Utility plant (including construction work in progress of $601,366 and $358,732, respectively):
Electric plant	$	5,124,065		$	4,705,900
Gas plant		2,097,944			1,995,219
Common plant		287,505			284,758
Less: Accumulated depreciation and amortization		(375,034	)		(185,474	)
Net utility plant		7,134,480			6,800,403
Other property and investments:
Goodwill		1,656,513			1,656,513
Investment in Bonneville Exchange Power contract		23,805			26,450
Other property and investments		123,899			127,073
Total other property and investments		1,804,217			1,810,036
Current assets:
Cash and cash equivalents		86,316			78,527
Restricted cash		5,613			19,844
Accounts receivable, net of allowance for doubtful accounts of $8,057 and $8,094, respectively		230,708			320,016
Unbilled revenue		96,772			208,948
Purchased gas adjustment receivable		3,546			--
Materials and supplies, at average cost		95,710			75,035
Fuel and gas inventory, at average cost		108,043			96,483
Unrealized gain on derivative instruments		8,082			14,948
Income taxes		72,627			134,617
Prepaid expense and other		34,725			13,117
Power contract acquisition adjustment gain		173,860			169,171
Deferred income taxes		81,685			39,977
Total current assets		997,687			1,170,683
Other long-term and regulatory assets:
Regulatory assets for deferred income taxes		75,942			89,303
Regulatory asset for PURPA buyout costs		50,012			78,162
Power cost adjustment mechanism		9,489			8,529
Regulatory assets related to power contracts		137,543			210,340
Other regulatory assets		836,972			751,999
Unrealized gain on derivative instruments		4,550			25,459
Power contract acquisition adjustment gain		731,883			865,020
Other		111,347			90,206
Total other long-term and regulatory assets		1,957,738			2,119,018
Total assets	$	11,894,122		$	11,900,140

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, 2010			December 31, 2009
Capitalization:
Common shareholder’s equity:
Common stock $0.01 par value, 1,000 shares authorized, 200 shares outstanding	$	--		$	--
Additional paid-in capital		3,308,957			3,308,957
Earnings (deficit) reinvested in the business		(65,609	)		91,024
Accumulated other comprehensive income (loss) – net of tax		(19,807	)		23,487
Total common shareholder’s equity		3,223,541			3,423,468
Long-term debt:
PSE first mortgage bonds and senior notes		2,953,860			2,638,860
PSE junior subordinated notes		250,000			250,000
Puget Energy long-term debt		1,161,508			1,151,838
Total long-term debt		4,365,368			4,040,698
Total capitalization		7,588,909			7,464,166
Current liabilities:
Accounts payable		303,701			321,287
Short-term debt		77,000			105,000
Current maturities of long-term debt		260,000			232,000
Accrued expenses:
Purchased gas adjustment liability		--			49,587
Taxes		57,462			77,302
Salaries and wages		29,622			30,654
Interest		55,340			52,540
Unrealized loss on derivative instruments		312,225			168,783
Power contract acquisition adjustment loss		72,816			94,223
Other		124,811			194,786
Total current liabilities		1,292,977			1,326,162
Long-term and regulatory liabilities:
Deferred income taxes		1,074,626			1,147,667
Unrealized loss on derivative instruments		264,436			89,717
Regulatory liabilities		306,878			261,990
Regulatory liabilities related to power contracts		905,743			1,034,192
Power contract acquisition adjustment loss		65,449			117,272
Other deferred credits		395,104			458,974
Total long-term and regulatory liabilities		3,012,236			3,109,812
Commitments and contingencies
Total capitalization and liabilities	$	11,894,122		$	11,900,140

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

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

	Successor						Predecessor
	Nine Months Ended September 30, 2010			February 6, 2009 – September 30, 2009			January 1, 2009 – February 5, 2009
Operating activities:
Net income (loss)	$	(53,427	)	$	120,137		$	12,756
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation		217,765			177,269			21,773
Amortization		53,011			43,113			4,969
Conservation amortization		60,874			39,803			7,592
Deferred income taxes and tax credits, net		(78,075	)		203,757			(512	)
Amortization of gas pipeline capacity assignment		(6,474	)		(6,236	)		(791	)
Carrying value adjustment related to California wholesale energy sale regulatory asset		17,763			--			--
Non cash return on regulatory assets		(15,122	)		(18,431	)		(2,185	)
Net unrealized loss (gain) on derivative instruments		109,183			(125,166	)		3,867
Power cost adjustment mechanism		(960	)		--			(7	)
Deferred regulatory costs for generation facilities		(3,169	)		744			(2,058	)
Renewable energy credit payments received		33,296			22,090			942
Pension funding		(12,000	)		(18,000	)		--
Change in residential exchange program		1,077			(634	)		1,927
Derivative contracts classified as financing activities due to merger		279,073			349,695			--
Other		10,061			(30,065	)		4,295
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue		201,486			309,376			(31,332	)
Materials and supplies		(20,675	)		1,522			(3,388	)
Fuel and gas inventory		(11,560	)		(14,681	)		7,605
Income taxes		61,990			(163,246	)		18,277
Prepayments and other		(22,127	)		(12,432	)		(3,295	)
Purchased gas adjustment		(53,133	)		59,748			1,711
Accounts payable		7,958			(181,082	)		(40,203	)
Taxes payable		(19,840	)		9,468			(3,340	)
Accrued expenses and other		10,881			(39,599	)		59,172
Net cash provided by operating activities		767,856			727,150			57,775
Investing activities:
Construction expenditures – excluding equity AFUDC		(667,597	)		(537,027	)		(49,531	)
Energy efficiency expenditures		(67,165	)		(55,270	)		(4,918	)
Treasury grant payment received		28,675			--			--
Restricted cash		14,231			816			(10	)
Other		2,268			14,035			959
Net cash used in investing activities		(689,588	)		(577,446	)		(53,500	)
Financing activities:
Change in short-term debt and leases, net		(28,059	)		(61,191	)		(151,800	)
Dividends paid		(103,206	)		(120,878	)		--
Long-term notes and bonds issued		575,000			400,211			250,000
Redemption of preferred stock		--			--			(1,889	)
Redemption of bonds and notes		(232,000	)		(150,000	)		--
Derivative contracts classified as financing activities due to merger		(279,073	)		(349,695	)		--
Issuance cost of bonds and other		(3,141	)		(16,577	)		7,133
Net cash provided by (used in) financing activities		(70,479	)		(298,130	)		103,444
Net increase (decrease) in cash and cash equivalents		7,789			(148,426	)		107,719
Cash and cash equivalents at beginning of period		78,527			231,963			38,526
Cash and cash equivalents at end of period	$	86,316		$	83,537		$	146,245
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	208,282		$	177,839		$	1,239
Cash payments (refunds) for income taxes		(20,622	)		129			--

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,
	2010			2009			2010			2009
Operating revenue:
Electric	$	489,608		$	449,658		$	1,507,549		$	1,506,642
Gas		132,571			142,128			664,423			875,485
Other		650			840			2,350			4,333
Total operating revenue		622,829			592,626			2,174,322			2,386,460
Operating expenses:
Energy costs:
Purchased electricity		127,936			160,867			557,221			610,034
Electric generation fuel		96,712			77,164			194,649			143,124
Residential exchange		(15,173	)		(19,271	)		(54,510	)		(72,604	)
Purchased gas		60,284			72,463			343,779			524,666
Net unrealized (gain) loss on derivative instruments		78,559			(27,144	)		200,702			(34,734	)
Utility operations and maintenance		117,155			116,129			355,569			353,129
Non-utility expense and other		3,188			2,282			7,742			5,677
Merger and related costs		--			--			--			23,908
Depreciation		73,111			66,978			217,765			199,164
Amortization		18,355			16,522			53,011			48,082
Conservation amortization		20,392			12,836			60,874			47,395
Taxes other than income taxes		58,903			57,785			210,304			225,824
Total operating expenses		639,422			536,611			2,147,106			2,073,665
Operating income (loss)		(16,593	)		56,015			27,216			312,795
Other income (deductions):
Other income		11,033			13,272			32,846			35,591
Other expense		(1,074	)		(1,299	)		(4,147	)		(5,432	)
Interest charges:
AFUDC		3,924			2,661			9,832			6,560
Interest expense		(61,620	)		(52,900	)		(178,323	)		(155,904	)
Interest expense on Puget Energy note		(42	)		(66	)		(152	)		(207	)
Income (loss) before income taxes		(64,372	)		17,683			(112,728	)		193,403
Income tax (benefit) expense		(34,813	)		9,841			(45,402	)		56,806
Net income (loss)	$	(29,559	)	$	7,842		$	(67,326	)	$	136,597

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,
	2010			2009		2010			2009
Net income (loss)	$	(29,559	)	$	7,842	$	(67,326	)	$	136,597
Other comprehensive income:
Net unrealized gain from pension and postretirement plans, net of tax of $596, $516, $2,189 and $284, respectively		1,107			958		4,018			527
Net unrealized gain (loss) on energy derivative instruments during the period, net of tax of $0, $167, $244 and $(33,542), respectively		--			310		453			(62,293	)
Reclassification of net unrealized loss on energy derivative instruments settled during the period, net of tax of $6,598, $22,516, $20,414 and $34,454, respectively		12,253			41,815		37,911			63,985
Amortization of financing cash flow hedge contracts to earnings, net of tax of $43, $43, $128 and $128, respectively		79			79		238			238
Other comprehensive income		13,439			43,162		42,620			2,457
Comprehensive income (loss)	$	(16,120	)	$	51,004	$	(24,706	)	$	139,054

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, 2010			December 31, 2009
Utility plant (at original cost, including construction work in progress of $601,366 and $358,732, respectively):
Electric plant	$	7,464,484		$	7,046,379
Gas plant		2,730,448			2,637,003
Common plant		397,209			539,296
Less:  Accumulated depreciation and amortization		(3,476,967	)		(3,453,165	)
Net utility plant		7,115,174			6,769,513
Other property and investments:
Investment in Bonneville Exchange Power contract		23,805			26,450
Other property and investments		113,038			116,267
Total other property and investments		136,843			142,717
Current assets:
Cash and cash equivalents		86,278			78,407
Restricted cash		5,613			19,844
Accounts receivable, net of allowance for doubtful accounts of $8,057 and $8,094, respectively		230,835			320,065
Unbilled revenue		96,772			208,948
Purchased gas adjustment receivable		3,546			--
Materials and supplies, at average cost		86,642			64,604
Fuel and gas inventory, at average cost		104,218			95,813
Unrealized gain on derivative instruments		8,082			14,948
Income taxes		58,908			99,948
Prepaid expenses and other		34,194			12,067
Deferred income taxes		93,293			38,781
Total current assets		808,381			953,425
Other long-term and regulatory assets:
Regulatory assets for deferred income taxes		75,942			89,303
Regulatory asset for PURPA buyout costs		50,012			78,162
Power cost adjustment mechanism		9,489			8,529
Other regulatory assets		781,643			665,272
Unrealized gain on derivative instruments		4,550			4,605
Other		125,684			105,045
Total other long-term and regulatory assets		1,047,320			950,916
Total assets	$	9,107,718		$	8,816,571

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, 2010			December 31, 2009
Capitalization:
Common shareholder’s equity:
Common stock $0.01 par value – 150,000,000 shares authorized, 85,903,791 shares outstanding	$	859		$	859
Additional paid-in capital		2,959,205			2,959,205
Earnings reinvested in the business		99,718			333,128
Accumulated other comprehensive loss – net of tax		(167,500	)		(210,120	)
Total common shareholder’s equity		2,892,282			3,083,072
Long-term debt:
First mortgage bonds and senior notes		2,953,860			2,638,860
Junior subordinated notes		250,000			250,000
Total long-term debt		3,203,860			2,888,860
Total capitalization		6,096,142			5,971,932
Current liabilities:
Accounts payable		305,074			321,287
Short-term debt		77,000			105,000
Short-term note owed to Puget Energy		22,898			22,898
Current maturities of long-term debt		260,000			232,000
Accrued expenses:
Purchased gas adjustment liability		--			49,587
Taxes		57,462			77,302
Salaries and wages		29,622			30,654
Interest		52,471			47,154
Unrealized loss on derivative instruments		281,784			137,530
Other		54,155			104,148
Total current liabilities		1,140,466			1,127,560
Long-term and regulatory liabilities:
Deferred income taxes		994,576			996,576
Unrealized loss on derivative instruments		216,964			89,717
Regulatory liabilities		297,183			250,586
Other deferred credits		362,387			380,200
Total long-term and regulatory liabilities		1,871,110			1,717,079
Commitments and contingencies
Total capitalization and liabilities	$	9,107,718		$	8,816,571

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,
	2010			2009
Operating activities:
Net income (loss)	$	(67,326	)	$	136,597
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation		217,765			199,164
Amortization		53,011			48,082
Conservation amortization		60,874			47,395
Deferred income taxes and tax credits, net		(66,126	)		174,580
Amortization of gas pipeline capacity assignment		(6,474	)		(7,027	)
Carrying value adjustment related to California wholesale energy sale regulatory asset		17,763			--
Non cash return on regulatory assets		(15,122	)		(20,515	)
Net unrealized loss (gain) on derivative instruments		200,702			(34,734	)
Power cost adjustment mechanism		(960	)		--
Deferred regulatory costs for generation facilities		(3,169	)		(1,414	)
Renewable energy credit payments received		33,296			23,032
Pension funding		(12,000	)		(18,000	)
Change in residential exchange program		1,077			1,292
Other		3,768			(35,073	)
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue		201,407			282,184
Materials and supplies		(22,038	)		(3,926	)
Fuel and gas inventory		(8,405	)		13,135
Income taxes		41,040			(117,243	)
Prepayments and other		(22,127	)		(15,824	)
Purchased gas adjustment		(53,133	)		61,459
Accounts payable		9,330			(131,274	)
Taxes payable		(19,840	)		(10,099	)
Accrued expenses and other		8,430			2,341
Net cash provided by operating activities		551,743			594,132
Investing activities:
Construction expenditures – excluding equity AFUDC		(667,597	)		(586,558	)
Energy efficiency expenditures		(67,165	)		(60,188	)
Treasury grant payment received		28,675			--
Restricted cash		14,231			806
Other		2,268			14,994
Net cash used in investing activities		(689,588	)		(630,946	)
Financing activities:
Change in short-term debt and leases, net		(28,059	)		(212,991	)
Dividends paid		(166,084	)		(167,141	)
Long-term notes and bonds issued		575,000			600,000
Loan payment to Puget Energy		--			(3,156	)
Redemption of preferred stock		--			(1,889	)
Redemption of bonds and notes		(232,000	)		(150,000	)
Investment from parent		--			25,960
Issuance cost of bonds and other		(3,141	)		(8,933	)
Net cash provided by financing activities		145,716			81,850
Net increase in cash and cash equivalents		7,871			45,036
Cash and cash equivalents at beginning of period		78,407			38,470
Cash and cash equivalents at end of period	$	86,278		$	83,506
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	147,388		$	132,277
Cash payments (refunds) for income taxes		(19,087	)		129

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.  On February 6, 2009, Puget Holdings LLC (Puget Holdings) acquired Puget Energy.  The acquisition of Puget Energy was accounted for in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 805, “Business Combinations” (ASC 805), as of the date of the merger.  ASC 805 requires the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the merger date.  Puget Energy’s co nsolidated financial statements and accompanying footnotes have been segregated to present pre-merger activity as the “Predecessor” Company and post-merger activity as the “Successor” Company.

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 accounting continues to be on a historical basis and PSE’s financial statements do not include any ASC 805 purchase accounting adjustments.

The consolidated financial statements contained in this Form 10-Q are unaudited.  In the respective opinions of the management of Puget Energy and PSE, all adjustments necessary for a fair statement of the results for the interim periods have been reflected and were of a normal recurring nature.  These consolidated financial statements should be read in conjunction with the audited financial statements (and the Combined Notes thereto) included in the combined Puget Energy and PSE Annual Report on Form 10-K for the year ended December 31, 2009.

The preparation of financial statements in conformity with 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 rates) and municipal taxes totaling $44.4 million and $164.0 million for the three and nine months ended September 30, 2010, respectively, and $43.0 million and $182.6 million for the three and nine months ended September 30, 2009, respectively.  The Company’s policy is to report 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 set forth the components of the Company’s accumulated other comprehensive income (loss) at September 30, 2010 and December 31, 2009:

Puget Energy (Dollars in Thousands)	September 30, 2010			December 31, 2009
Net unrealized loss on energy derivatives	$	(3,453	)	$	(7,078	)
Net unrealized loss on interest rate swaps		(50,643	)		(3,893	)
Net unrealized gain and prior service cost on pension plans		34,289			34,458
Total Puget Energy, net of tax	$	(19,807	)	$	23,487

Puget Sound Energy (Dollars in Thousands)	September 30, 2010			December 31, 2009
Net unrealized loss on energy derivatives	$	(44,794	)	$	(83,158	)
Settlement of cash flow hedge contracts		(7,336	)		(7,574	)
Net unrealized loss and prior service cost on pension plans		(115,370	)		(119,388	)
Total PSE, net of tax	$	(167,500	)	$	(210,120	)

(2)   New Accounting Pronouncements

Fair Value Measurements and Disclosures. In January 2010, the FASB issued Accounting Standards Update (ASU) 2010-6, “Improving Disclosures About Fair Value Measurements” (ASU 2010-6), which requires new disclosures about recurring or nonrecurring fair value measurements including significant transfers into and out of Level 1 and Level 2 fair value measurements and information on purchases, sales, issuances, and settlements on a gross basis in the reconciliation of Level 2 fair value measurements.  ASU 2010-6 is effective for annual reporting periods beginning after December 15, 2009, except for Level 3 reconciliation disclosures which are effective for annual periods beginning after December 15, 2010.  As these new requirements relate solely to dis closures, the adoption of this guidance will not impact the Company’s consolidated financial statements.

Variable Interest Entities. In December 2009, the FASB issued ASU 2009-17, Topic 810, “Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities,” which amended the FASB ASC for the issuance of pre-codification FASB Statement No. 167, “Amendments to FASB Interpretation No. 46(R).”  This standard replaces the quantitative-based risks and rewards calculation for determining which reporting entity, if any, has a controlling financial interest in a variable interest entity (VIE).  An approach focused on identifying which reporting entity has the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and: (1) the obligation to absorb losses of the entit y; or (2) the right to receive benefits from the entity.  An approach that is primarily qualitative is expected to be more effective for identifying which reporting entity has a controlling financial interest in a VIE.  This standard also requires additional disclosures about a reporting entity’s involvement in VIE relationships.  The Company adopted the standard as of January 1, 2010, and such adoption did not have an impact on the consolidated financial statements.

(3)   Accounting for Derivative Instruments and Hedging Activities

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 enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts.  In February 2009, Puget Energy entered into interest rate swap transactions to hedge the risk associated with the one-month London Interbank Offered Rate (LIBOR) floating debt rate.  As of September 30, 2010, Puget Energy had interest rate swap contracts outstanding and PSE did not have any outstanding interest rate swap instruments.

On the date of the merger, Puget Energy de-designated its derivative contracts that were designated on PSE’s books as Normal Purchase Normal Sale (NPNS) or cash flow hedges and recorded such contracts at fair value as either assets or liabilities.  Certain contracts meeting the criteria defined in ASC 815, “Derivatives and Hedging” (ASC 815), were subsequently re-designated as NPNS or cash flow hedges.  The amount recorded in accumulated other comprehensive income (OCI) at the time of the merger was reflected as goodwill.

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

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

The following tables present the fair value and locations of Puget Energy’s derivative instruments recorded on the balance sheets at September 30, 2010 and December 31, 2009:

Derivatives Designated as Hedging Instruments
Puget Energy	September 30, 2010				December 31, 2009
(Dollars in Thousands)	Assets 1		Liabilities 1		Assets 1		Liabilities 1
Interest rate swaps:
Current	$	--	$	30,441	$	--	$	26,844
Long-term		--		47,472		20,854		--
Total derivatives	$	--	$	77,913	$	20,854	$	26,844

Derivatives Not Designated as Hedging Instruments
Puget Energy	September 30, 2010				December 31, 2009
(Dollars in Thousands)	Assets 1		Liabilities 1		Assets 1		Liabilities 1
Electric portfolio:
Current	$	3,504	$	146,407	$	4,137	$	79,732
Long-term		1,598		140,923		1,003		70,367
Gas portfolio: 2
Current		4,578		135,377		10,811		62,207
Long-term		2,952		76,041		3,602		19,350
Total derivatives	$	12,632	$	498,748	$	19,553	$	231,656

___________

1

Balance sheet location: Unrealized (gain) loss on derivative instruments.

2

Puget Energy had a derivative liability and an offsetting regulatory asset of $203.9 million at September 30, 2010 and $67.1 million at December 31, 2009 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.

The following table presents the fair value and locations of PSE’s derivative instruments recorded on the balance sheet at September 30, 2010 and December 31, 2009:

Derivatives Not Designated as Hedging Instruments
Puget Sound Energy	September 30, 2010				December 31, 2009
(Dollars in Thousands)	Assets 1		Liabilities 1		Assets 1		Liabilities 1
Electric portfolio:
Current	$	3,504	$	146,407	$	4,137	$	75,323
Long-term		1,598		140,923		1,003		70,367
Gas portfolio: 2
Current		4,578		135,377		10,811		62,207
Long-term		2,952		76,041		3,602		19,350
Total derivatives	$	12,632	$	498,748	$	19,553	$	227,247

___________

1

Balance sheet location: Unrealized (gain) loss on derivative instruments.

2

PSE had a derivative liability and an offsetting regulatory asset of $203.9 million at September 30, 2010 and $67.1 million at December 31, 2009 related to financial contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers.  All fair value adjustments on derivatives relating to the natural gas business have been reclassified to a deferred account in accordance with ASC 980 due to the PGA mechanism.  All increases and decreases in the cost of natural gas supply are passed on to customers with the PGA mechanism and the gains and losses on the hedges in future periods will be recorded as gas costs.

For further details regarding the fair value of derivative instruments and their Level categorization please see Note 4 of the notes to the consolidated financial statements.

The following table presents the net unrealized (gain) loss of Puget Energy’s derivative instruments recorded on the statements of income for the three months ended September 30, 2010 and 2009:

Puget Energy	Three Months Ended September 30,
(Dollars in Thousands)	2010			2009
Gas / Power NPNS	$	(78	)	$	1,538
Gas for power generation		18,232			(62,219	)
Power exchange		(639	)		(163	)
Power		45,760			(13,987	)
Total net unrealized (gain) loss on derivative instruments	$	63,275		$	(74,831	)

The following table presents the net unrealized (gain) loss of Puget Energy’s derivative instruments recorded on the statements of income for the nine months ended September 30, 2010 and 2009:

	Successor						Predecessor
Puget Energy (Dollars in Thousands)	Nine Months Ended September 30, 2010			February 6, 2009 – September 30, 2009			January 1, 2009 – February 5, 2009
Gas / Power NPNS	$	(33,662	)	$	(34,215	)	$	--
Gas for power generation		67,151			(70,776	)		3,696
Power exchange		(2,096	)		(1,563	)		(588	)
Power		77,790			(30,205	)		759
Credit reserve 1		--			11,593			--
Total net unrealized (gain) loss on derivative instruments	$	109,183		$	(125,166	)	$	3,867

  ___________

1 Beginning in the second quarter 2009, the credit reserve was incorporated as a component of the individual derivative value and not recorded separately.

The following table presents the net unrealized (gain) loss of PSE’s derivative instruments recorded on the statements of income for the three and nine months ended September 30, 2010 and 2009:

Puget Sound Energy	Three Months Ended September 30,						Nine Months Ended September 30,
(Dollars in Thousands)	2010			2009			2010			2009
Gas for power generation	$	31,801		$	(21,743	)	$	109,523		$	(30,057	)
Power exchange		(639	)		(163	)		(2,096	)		(2,138	)
Power		47,397			(5,238	)		93,275			(2,621	)
Credit reserve 1		--			--			--			82
Total net unrealized (gain) loss on derivative instruments	$	78,559		$	(27,144	)	$	200,702		$	(34,734	)

  ___________

1 Beginning in the second quarter 2009, the credit reserve was incorporated as a component of the individual derivative value and not recorded separately.

The following table presents the effect of hedging instruments on Puget Energy’s OCI and statements of income for the three months ended September 30, 2010 and 2009:

Puget Energy (Dollars in Thousands)	Three Months Ended September 30,
Derivatives in Cash Flow Hedging Relationships	Gain (Loss) Recognized in OCI on Derivatives 1 (Effective Portion 2)						Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion 3)							Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion and Amount Excluded from Effectiveness Testing 3)
	2010			2009			Location	2010			2009			Location	2010		2009
Interest rate contracts:	$	(19,761	)	$	(21,694	)	Interest Expense	$	(8,638	)	$	(8,454	)		$	--	$	--
Commodity contracts: Electric derivatives:		--			30		Electric generation fuel		(3,285	)		(18,361	)	Net unrealized gain on derivative instruments		--		--
Electric derivatives		--			--		Purchased electricity		(361	)		(778	)	Net unrealized loss on derivative instruments		--		--
Total	$	(19,761	)	$	(21,664	)		$	(12,284	)	$	(27,593	)		$	--	$	--

___________

1	On July 1, 2009 all electric and gas related cash flow hedge relationships were de-designated.  Subsequent measurements of fair value are recorded through earnings, not OCI.
2	Changes in OCI are reported in after-tax dollars.
3	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 Puget Energy’s OCI and statements of income for the nine months ended September 30, 2010 and 2009:

Puget Energy (Dollars in Thousands)	Nine Months Ended September 30, 2010
Derivatives in Cash Flow Hedging Relationships	Gain (Loss) Recognized in OCI on Derivatives 1 (Effective Portion 2)			Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion 3)				Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion and Amount Excluded from Effectiveness Testing 3)
				Location				Location
Interest rate contracts:	$	(63,338	)	Interest expense	$	(25,520	)		$	--
Commodity contracts: Electric derivatives		--		Electric generation fuel		(3,407	)	Net unrealized gain on derivative instruments		--
Electric derivatives		--		Purchased electricity		(2,170	)	Net unrealized loss on derivative instruments		--
Total	$	(63,338	)		$	(31,097	)		$	--

___________

1	On July 1, 2009 all electric and gas related cash flow hedge relationships were de-designated.  Subsequent measurements of fair value are recorded through earnings, not OCI.
2	Changes in OCI are reported in after-tax dollars.
3	A reclassification of a loss in OCI increases accumulated OCI and decreases earnings.  Amounts reported are in pre-tax dollars.

Puget Energy (Dollars in Thousands)	SuccessorFebruary 6, 2009 - September 30, 2009
Derivatives in Cash Flow Hedging Relationships	Gain (Loss) Recognized in OCI on Derivatives 1  (Effective Portion 2)			Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion 3)				Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion and Amount Excluded from Effectiveness Testing 3)
				Location				Location
Interest rate contracts:	$	(23,203	)	Interest expense	$	(20,508	)		$	--
Commodity contracts: Electric derivatives		(19,933	)	Electric generation fuel		(20,005	)	Net unrealized loss on derivative instruments		325
Electric derivatives		(6,289	)	Purchased electricity		(2,350	)	Net unrealized loss on derivative instruments		(2,897	)
Total	$	(49,425	)		$	(42,863	)		$	(2,572	)

___________

1	On July 1, 2009 all electric and gas related cash flow hedge relationships were de-designated.  Subsequent measurements of fair value are recorded through earnings, not OCI.
2	Changes in OCI are reported in after-tax dollars.
3	A reclassification of a loss in OCI increases accumulated OCI and decreases earnings.  Amounts reported are in pre-tax dollars.

Puget Energy (Dollars in Thousands)	PredecessorJanuary 1, 2009 - February 5, 2009
Derivatives in Cash Flow Hedging Relationships	Gain(Loss) Recognized in OCI on Derivatives (Effective Portion 1,2)			Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion 3)				Gain(Loss) Recognized in Income on Derivatives (Ineffective Portion and Amount Excluded from Effectiveness Testing 3)
				Location				Location
Interest rate contracts:	$	--		Interest expense	$	(41	)		$	--
Commodity contracts: Electric derivatives		(20,791	)	Electric generation fuel		(5,003	)	Net unrealized loss on derivative instruments		--
Electric derivatives		(3,371	)	Purchased electricity		(1,934	)	Net unrealized loss on derivative instruments		(986	)
Total	$	(24,162	)		$	(6,978	)		$	(986	)

____________

1	Changes in OCI are reported in after-tax dollars.
2	The balances associated with the components of accumulated other comprehensive income (loss) on the Predecessor basis were eliminated as a result of push-down accounting effective February 6, 2009, when the Successor period began.
3	Amounts are reported in pre-tax dollars.

The following table presents the effect of hedging instruments on PSE’s OCI and statements of income for the three months ended September 30, 2010 and 2009:

Puget Sound Energy (Dollars in Thousands)	Three Months Ended September 30,
Derivatives in Cash Flow Hedging Relationships	Gain (Loss) Recognized in OCI on Derivatives 1 (Effective Portion 2)					Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion 3)							Gain (Loss) Recognized  in Income on Derivatives (Ineffective Portion and Amount Excluded from Effectiveness Testing)
	2010		2009			Location	2010			2009			Location	2010		2009
Interest rate contracts:	$	--	$	--		Interest Expense	$	(122	)	$	(122	)		$	--	$	--
Commodity contracts: Electric derivatives:		--		438		Electric generation fuel		(16,855	)		(58,480	)	Net unrealized gain on derivative instruments		--		--
Electric derivatives		--		(128	)	Purchased electricity		(1,996	)		(5,851	)	Net unrealized loss on derivative instruments		--		--
Total	$	--	$	310			$	(18,973	)	$	(64,453	)		$	--	$	--

___________

1	On July 1, 2009 all electric and gas related cash flow hedge relationships were de-designated.  Subsequent measurements of fair value are recorded through earnings, not OCI.
2	Changes in OCI are reported in after-tax dollars.
3	A reclassification of a loss in OCI increases accumulated OCI and decreases earnings.  Amounts reported are in pre-tax dollars.

The following table presents the effect of hedging instruments on PSE’s OCI and statements of income for the nine months ended September 30, 2010 and 2009:

Puget Sound Energy (Dollars in Thousands)	Nine Months Ended September 30,
Derivatives in Cash Flow Hedging Relationships	Gain (Loss) Recognized in OCI on Derivatives 1 (Effective Portion 2)					Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion 3)							Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion and Amount Excluded from Effectiveness Testing 3)
	2010		2009			Location	2010			2009			Location	2010		2009
Interest rate contracts:	$	--	$	--		Interest Expense	$	(366	)	$	(366	)		$	--	$	--
Commodity contracts: Electric derivatives:		453		(50,864	)	Electric generation fuel		(45,081	)		(85,429	)	Net unrealized gain on derivative instruments		--		--
Electric derivatives		--		(11,429	)	Purchased electricity		(13,244	)		(13,010	)	Net unrealized loss on derivative instruments		--		(2,749	)
Total	$	453	$	(62,293	)		$	(58,691	)	$	(98,805	)		$	--	$	(2,749	)

___________

1	On July 1, 2009 all electric and gas related cash flow hedge relationships were de-designated.  Subsequent measurements of fair value are recorded through earnings, not OCI.
2	Changes in OCI are reported in after-tax dollars.
3	A reclassification of a loss in OCI increases accumulated OCI and decreases earnings.  Amounts reported are in pre-tax dollars.

For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings.  Gains and losses on the derivatives representing hedge ineffectiveness are recognized in current earnings.  Puget Energy expects that $33.4 million of losses in OCI will be reclassified into earnings within the next twelve months.  PSE expects that $44.2 million of losses in OCI will be reclassified into earnings within the next twelve months.  The maximum length of time over which Puget Energy and PSE are hedging their exposure to the variability in future cash flows extends to February 2015 for purchased electricity contracts and to August 2013 for gas for power generation contracts.  For Puget Energy interest rate swaps, the maximum length extends to February 2014.

The following tables present the effect of Puget Energy’s derivatives not designated as hedging instruments on income during the three and nine months ended September 30, 2010 and 2009:

Puget Energy		Three Months Ended September 30,
(Dollars in Thousands)	Location	2010			2009
Commodity contracts:
Electric derivatives	Net unrealized gain (loss) on derivative instruments	$	(63,353	) 1	$	76,369	2
	Electric generation fuel		(36,571	)		(45,887	)
	Purchased electricity		(9,329	)		(6,747	)
Total gain (loss) recognized in income on derivatives		$	(109,253	)	$	23,735

___________

1	Differs from the amount stated in the statements of income as it does not include $0.1 million of amortization expense related to contracts that were recorded at fair value at the time of the merger and subsequently designated as NPNS.
2	Differs from the amount stated in the statements of income as it does not include $(1.5) million of amortization expense related to contracts that were recorded at fair value at the time of the merger and subsequently designated as NPNS.

Puget Energy		Nine Months Ended September 30,			Successor February 6, 2009 – September 30,			Predecessor January 1, 2009 – February 5,
(Dollars in Thousands)	Location	2010			2009			2009
Commodity contracts:
Electric derivatives	Net unrealized gain (loss) on derivative instruments	$	(142,846	) 1	$	94,192	2	$	(2,881	) 3
	Electric generation fuel		(69,571	)		(56,891	)		(863	)
	Purchased electricity		(27,529	)		(23,042	)		(243	)
Total gain (loss) recognized in income on derivatives		$	(239,946	)	$	14,259		$	(3,987	)

___________

1	Differs from the amount stated in the statements of income as it does not include $33.7 million of amortization expense related to contracts that were recorded at fair value at the time of the merger and subsequently designated as NPNS.
2	Differs from the amount stated in the statements of income as it does not include $33.5 million of amortization expense related to contracts that were recorded at fair value at the time of the merger and subsequently designated as NPNS and $(2.6) million related to hedge ineffectiveness.
3	Differs from the amount stated in the statements of income as it does not include $(1.0) million related to hedge ineffectiveness.

The following table presents the effect of PSE’s derivatives not designated as hedging instruments on income during the three and nine months ended September 30, 2010 and 2009:

Puget Sound Energy		Three Months Ended September 30,						Nine Months Ended September 30,
(Dollars in Thousands)	Location	2010			2009			2010			2009
Commodity contracts:
Electric derivatives	Net unrealized gain (loss) on derivative instruments	$	(78,559	)	$	27,144		$	(200,702	)	$	37,483	1
	Electric generation fuel		(36,571	)		(45,887	)		(69,571	)		(57,962	)
	Purchased electricity		(9,329	)		(6,747	)		(27,529	)		(7,314	)
Total gain (loss) recognized in income on derivatives		$	(124,459	)	$	(25,490	)	$	(297,802	)	$	(27,793	)

___________

1 Differs from the amount stated in the statements of income as it does not include $(2.7) million related to hedge ineffectiveness.

The Company had the following outstanding commodity contracts as of September 30, 2010:

Puget Energy at September 30, 2010	Number of Units
Derivatives designated as hedging instruments:
Interest rate swaps	$1.483 billion
Derivatives not designated as hedging instruments:
Gas derivatives 1	412,179,273 MMBtus
Electric generation fuel	97,230,500 MMBtus
Purchased electricity	8,941,405 MWhs

Puget Sound Energy at September 30, 2010	Number of Units
Derivatives not designated as hedging instruments:
Gas derivatives 1	412,179,273 MMBtus
Electric generation fuel	97,230,500 MMBtus
Purchased electricity	8,941,405 MWhs

__________

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

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

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

It is possible that volatility in energy commodity prices could cause the Company to have material credit risk exposure with one or more counterparties.  If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss.  However, as of September 30, 2010, approximately 99.9% of the Company’s energy portfolio exposure, excluding NPNS transactions, is with counterparties that are rated at least investment grade by the major rating agencies and 0.1% are either rated below investment grade or not rated by rating agencies.  The Company assesses credit risk internally for counterparties that are not rated.

The Company generally enters into the following master agreements: (1) WSPP, Inc. (WSPP) agreements – standardized power sales contract in the electric industry; (2) International Swaps and Derivatives Association (ISDA) agreements – standardized financial gas and electric contracts; and (3) North American Energy Standards Board (NAESB) agreements – standardized physical gas contracts.  The Company believes that such agreements reduce credit risk exposure because such agreements provide for the netting and offset 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 u sed by weighting the fair value and contract tenors for all deals for each counterparty and coming up with an average value.  The default factor used is dependent upon whether the counterparty is in a net asset or a net liability position after applying the master agreement levels.

The Company applies the counterparty’s default factor to compute credit reserves for counterparties that are in a net asset position.  Moreover, the Company applies its own default factor to compute credit reserves for counterparties that are in a net liability position.  Credit reserves are booked as contra accounts to unrealized gain (loss) positions.  As of September 30, 2010, 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 year.  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 req uired to post any additional collateral with any of its counterparties.  Additionally, PSE did not trigger any collateral requirements with any of its counterparties nor were any of PSE’s counterparties required to post additional collateral resulting from credit rating downgrades.

As of September 30, 2010, the Company did not have any outstanding energy supply contracts with counterparties that contained credit risk related contingent features, which could result in a counterparty requesting immediate payment or demanding immediate and ongoing full overnight collateralization on derivative instruments in a net liability position.

The table below presents the fair value of the overall contractual contingent liability positions for the Company’s derivative activity at September 30, 2010:

Puget Energy and Puget Sound Energy Contingent Feature (Dollars in Thousands)	Fair Value 1 Liability			Posted Collateral		Contingent Collateral
Credit rating 2	$	(49,684	)	$	--	$	49,684
Requested credit for adequate assurance		(99,928	)		--		--
Forward value of contract 3		(21,965	)		--		--
Total	$	(171,577	)	$	--	$	49,684

__________

1	Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions at September 30, 2010.  Excludes NPNS, accounts payable and accounts receivable liability.
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 forward value of underlying transactions relative to contractually defined collateral thresholds.

(4)   Fair Value Measurements

ASC 820, “Fair Value Measurements and Disclosures” (ASC 820), established a fair value hierarchy that prioritizes the inputs used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).  The three levels of the fair value hierarchy defined by ASC 820 are as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date.  Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.  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 reported date.  Level 2 includes those financial instruments that are valued using models or other valuation methodologies.  These models are primarily industry-standard models that consider various assumptions including, quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures.  Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplac e.  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 are generally less observable from objective sources.  These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.  Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs.  At each balance sheet date, Puget Energy and PSE perform an analysis of all instruments subject to ASC 820 and include in Level 3 all of those instruments whose fair value is based on significant unobservable inputs.

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’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.  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 then 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, 2010, the Company considered the markets for its electric and natural gas Level 2 derivative instruments to be actively traded.  Management’s assessment is 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 to the actual prices of commodity contracts entered into during the most recent quarter.

The following tables set forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis and the reconciliation of the changes in the fair value of derivatives classified as Level 3 in the fair value hierarchy as of September 30, 2010 and December 31, 2009:

Puget Energy	Fair Value Measurement at September 30, 2010								Fair Value Measurement at December 31, 2009
(Dollars in Thousands)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	--	$	156	$	4,946	$	5,102	$	--	$	2,469	$	2,671	$	5,140
Gas derivative instruments		--		3,091		4,439		7,530		--		14,298		115		14,413
Cash equivalents		68,602		5,327		--		73,929		38,835		5,465		--		44,300
Restricted cash		3,387		--		--		3,387		3,305		--		--		3,305
Interest rate derivative instruments		--		--		--		--		--		20,854		--		20,854
Total assets	$	71,989	$	8,574	$	9,385	$	89,948	$	42,140	$	43,086	$	2,786	$	88,012
Liabilities:
Electric derivative instruments	$	--	$	167,083	$	120,247	$	287,330	$	--	$	51,099	$	99,000	$	150,099
Gas derivative instruments		--		201,293		10,125		211,418		--		77,438		4,119		81,557
Interest rate derivative instruments		--		77,913		--		77,913		--		26,844		--		26,844
Total liabilities	$	--	$	446,289	$	130,372	$	576,661	$	--	$	155,381	$	103,119	$	258,500

Puget Energy Level 3 Roll-Forward Net (Liability)	Three Months Ended September 30,
(Dollars in Thousands)	2010			2009
Balance at beginning of period	$	(135,121	)	$	(136,677	)
Changes during period:
Realized and unrealized energy derivatives
- included in earnings		(46,223	)		14,987
- included in other comprehensive income		--			--
- included in regulatory assets / liabilities		(1,017	)		(962	)
Purchases, issuances and settlements		7,798			5,825
Transferred into Level 3		761			--
Transferred out of Level 3		52,815			14,543
Balance at end of period	$	(120,987	)	$	(102,284	)

	Successor						Predecessor
Puget Energy Level 3 Roll-Forward Net (Liability) (Dollars in Thousands)	Nine Months Ended September 30, 2010			February 6, 2009 – September 30, 2009 1			January 1, 2009 – February 5, 2009
Balance at beginning of period	$	(100,333	)	$	(185,813	)	$	(132,256	)
Changes during period:
Realized and unrealized energy derivatives
- included in earnings		(125,839	)		5,241			(627	)
- included in other comprehensive income		--			(17, 429	)		(14,821	)
- included in regulatory assets / liabilities		(1,856	)		(3,404	)		(1,410	)
Purchases, issuances and settlements		21,138			19,541			2,154
Transferred into Level 3		225			(8,611	)		--
Transferred out of Level 3		85,678			88,191			8,560
Balance end of period	$	(120,987	)	$	(102,284	)	$	(138,400	)

___________

1 The beginning balance for the Successor period was adjusted to reflect the impact of certain fair value adjustments from the merger transaction.

Puget Sound Energy	Fair Value Measurement at September 30, 2010								Fair Value Measurement at December 31, 2009
(Dollars in Thousands)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	--	$	156	$	4,946	$	5,102	$	--	$	2,469	$	2,671	$	5,140
Gas derivative instruments		--		3,091		4,439		7,530		--		14,298		115		14,413
Cash equivalents		68,602		5,327		--		73,929		38,835		5,465		--		44,300
Restricted cash		3,387		--		--		3,387		3,305		--		--		3,305
Total assets	$	71,989	$	8,574	$	9,385	$	89,948	$	42,140	$	22,232	$	2,786	$	67,158
Liabilities:
Electric derivative instruments	$	--	$	167,083	$	120,247	$	287,330	$	--	$	46,690	$	99,000	$	145,690
Gas derivative instruments		--		201,293		10,125		211,418		--		77,438		4,119		81,557
Total liabilities	$	--	$	368,376	$	130,372	$	498,748	$	--	$	124,128	$	103,119	$	227,247

Puget Sound Energy Level 3 Roll-Forward Net (Liability)	Three Months Ended September 30,						Nine Months Ended September 30,
(Dollars in Thousands)	2010			2009			2010			2009
Balance at beginning of period	$	(135,121	)	$	(136,677	)	$	(100,333	)	$	(132,256	)
Changes during period:
Realized and unrealized energy derivatives
- included in earnings		(46,223	)		14,987			(125,839	)		19,270
- included in other comprehensive income		--			--			--			(38,047	)
- included in regulatory assets / liabilities		(1,017	)		(962	)		(1,856	)		(6,883	)
Purchases, issuances and settlements		7,798			5,825			21,138			21,973
Transferred into Level 3		761			--			225			(6,778	)
Transferred out of Level 3		52,815			14,543			85,678			40,437
Balance at end of period	$	(120,987	)	$	(102,284	)	$	(120,987	)	$	(102,284	)

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

Unrealized gains and losses for Level 3 inputs on energy derivative recurring items are included in the net unrealized (gain) loss on derivative instruments section in the Company’s consolidated income statement.  The Company does not believe that the fair value diverges materially from the amounts the Company currently anticipates realizing on settlement or maturity.

Certain energy derivative instruments are classified as Level 3 in the fair value hierarchy because Level 3 inputs are significant to their fair value measurement.  Energy derivatives transferred out of Level 3 represent existing assets or liabilities that were classified as Level 3 at the start 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 had no transfers between Level 2 and Level 1 during the three and nine months ended September 30, 2010 or 2009.

(5)   Estimated Fair Value of Financial Instruments

Puget Energy

The following table presents the carrying amounts and estimated fair value of Puget Energy’s financial instruments at September 30, 2010 and December 31, 2009:

	September 30, 2010				December 31, 2009
(Dollars in Thousands)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Financial assets:
Cash and cash equivalents	$	86,316	$	86,316	$	78,527	$	78,527
Restricted cash		5,613		5,613		19,844		19,844
Notes receivable and other		70,889		70,889		74,063		74,063
Electric derivatives		5,102		5,102		5,140		5,140
Gas derivatives		7,530		7,530		14,413		14,413
Interest rate derivatives		--		--		20,854		20,854
Financial liabilities:
Short-term debt	$	77,000	$	77,000	$	105,000	$	105,000
Junior subordinated notes		250,000		234,341		250,000		232,684
Current maturities of long-term debt (fixed-rate)		260,000		266,027		232,000		234,632
Long-term debt (fixed-rate)		2,953,860		3,394,700		2,638,860		2,815,048
Long-term debt (variable-rate)		1,483,000		1,523,639		1,483,000		1,478,632
Electric derivatives		287,330		287,330		150,099		150,099
Gas derivatives		211,418		211,418		81,557		81,557
Interest rate derivatives		77,913		77,913		26,844		26,844

Puget Sound Energy

The following table presents the carrying amounts and estimated fair value of PSE’s financial instruments at September 30, 2010 and December 31, 2009:

	September 30, 2010				December 31, 2009
(Dollars in Thousands)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Financial assets:
Cash and cash equivalents	$	86,278	$	86,278	$	78,407	$	78,407
Restricted cash		5,613		5,613		19,844		19,844
Notes receivable and other		70,889		70,889		74,063		74,063
Electric derivatives		5,102		5,102		5,140		5,140
Gas derivatives		7,530		7,530		14,413		14,413
Financial liabilities:
Short-term debt	$	77,000	$	77,000	$	105,000	$	105,000
Short-term debt owed by PSE to Puget Energy 1		22,898		22,898		22,898		22,898
Junior subordinated notes		250,000		234,341		250,000		232,684
Current maturities of long-term debt (fixed-rate)		260,000		266,027		232,000		234,632
Non-current maturities of long-term debt (fixed-rate)		2,953,860		3,394,700		2,638,860		2,815,048
Electric derivatives		287,330		287,330		145,690		145,690
Gas derivatives		211,418		211,418		81,557		81,557

___________

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 and years of service.  The Company also maintains a non-qualified Supplemental Executive Retirement Plan (SERP) for its key senior management employees.  In addition to providing pension benefits, the Company provides certain health care and life insurance benefits for retired employees.  These benefits are provided principally through an insurance company.  The insurance premiums are based on the benefits provided during the year, and are paid primarily by retirees.

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 retirement plans are recorded at Puget Energy.

Puget Energy

The following table summarizes Puget Energy’s net periodic benefit cost for the three months ended September 30, 2010 and 2009:

	Three Months Ended September 30,
	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
(Dollars in Thousands)	2010			2009			2010		2009		2010			2009
Components of net periodic benefit cost:
Service cost	$	4,009		$	3,401		$	256	$	259	$	26		$	31
Interest cost		6,965			7,067			541		594		220			244
Expected return on plan assets		(8,087	)		(7,523	)		--		--		(127	)		(103	)
Amortization of net gain		--			--			--		--		(17	)		--
Net periodic benefit cost	$	2,887		$	2,945		$	797	$	853	$	102		$	172

The following tables summarize Puget Energy’s net periodic benefit cost for the nine months ended September 30, 2010 and 2009:

Qualified Pension Benefits	Successor						Predecessor
(Dollars in Thousands)	Nine Months Ended September 30, 2010			February 6, 2009 – September 30, 2009 1			January 1, 2009 – February 5, 2009
Components of net periodic benefit cost:
Service cost	$	12,083		$	9,068		$	1,090
Interest cost		21,030			18,845			2,302
Expected return on plan assets		(24,501	)		(20,060	)		(3,585	)
Amortization of prior service cost		--			--			95
Amortization of net loss		--			--			269
Net periodic benefit cost	$	8,612		$	7,853		$	171

SERP Pension Benefits	Successor				Predecessor
(Dollars in Thousands)	Nine Months Ended September 30, 2010		February 6, 2009 – September 30, 2009 1		January 1, 2009 – February 5, 2009
Components of net periodic benefit cost:
Service cost	$	768	$	692	$	89
Interest cost		1,624		1,584		193
Amortization of prior service cost		--		--		51
Amortization of net loss (gain)		--		--		74
Net periodic benefit cost	$	2,392	$	2,276	$	407

___________

1 The disclosed information is based on an initial January 31, 2009 measurement date, and as a result, the expense numbers are shown pro-rated for the second quarter 2009.

Other Benefits	Successor						Predecessor
(Dollars in Thousands)	Nine Months Ended September 30, 2010			February 6, 2009 – September 30, 2009 1			January 1, 2009 – February 5, 2009
Components of net periodic benefit cost:
Service cost	$	79		$	83		$	11
Interest cost		660			650			88
Expected return on plan assets		(381	)		(275	)		(37	)
Amortization of prior service cost		--			--			7
Amortization of net gain		(51	)		--			(15	)
Amortization of transition obligation		--			--			4
Net periodic benefit cost	$	307		$	458		$	58

___________

1 The disclosed information is based on an initial January 31, 2009 measurement date, and as a result, the expense numbers are shown pro-rated for the second quarter 2009.

The following table summarizes Puget Energy’s change in benefit obligation for the periods ended September 30, 2010 and December 31, 2009:

	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	September 30, 2010			December 31, 2009			September 30, 2010			December 31, 2009			September 30, 2010			December 31, 2009
Change in benefit obligation:
Benefit obligation at beginning of period	$	504,786		$	453,731		$	39,152		$	38,750		$	15,953		$	15,807
Beginning of year remeasurement		456			--			--			--			86			--
Service cost		12,083			12,469			768			951			79			114
Interest cost		21,030			25,912			1,624			2,178			660			894
Actuarial loss		--			33,458			--			1,433			--			770
Benefits paid		(26,400	)		(20,784	)		(1,262	)		(4,160	)		(1,413	)		(2,050	)
Medicare part D subsidy received		--			--			--			--			803			418
Benefit obligation at end of period	$	511,955		$	504,786		$	40,282		$	39,152		$	16,168		$	15,953

The fair value of plan assets increased from $485.7 million at December 31, 2009 to $497.8 million at September 30, 2010, which includes employer contributions of $12.0 million.

Puget Sound Energy

The following table summarizes PSE’s net periodic benefit cost for the three months ended September 30, 2010 and 2009:

	Three Months Ended September 30,
	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
(Dollars in Thousands)	2010			2009			2010		2009		2010			2009
Components of net periodic benefit cost:
Service cost	$	4,009		$	3,535		$	256	$	267	$	26		$	31
Interest cost		6,965			6,934			541		579		220			240
Expected return on plan assets		(10,875	)		(10,863	)		--		--		(127	)		(114	)
Amortization of prior service cost		185			283			141		154		33			21
Amortization of net loss (gain)		1,781			925			192		221		(138	)		(115	)
Amortization of transition obligation		--			--			--		--		12			13
Net periodic benefit cost	$	2,065		$	814		$	1,130	$	1,221	$	26		$	76

The following table summarizes PSE’s net periodic benefit cost for the nine months ended September 30, 2010 and 2009:

	Nine Months Ended September 30,
	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
(Dollars in Thousands)	2010			2009			2010		2009		2010			2009
Components of net periodic benefit cost:
Service cost	$	12,083		$	10,605		$	768	$	801	$	79		$	94
Interest cost		21,030			20,801			1,624		1,736		660			720
Expected return on plan assets		(32,864	)		(32,590	)		--		--		(381	)		(341	)
Amortization of prior service cost		555			850			422		462		99			62
Amortization of net loss (gain)		5,193			2,777			576		664		(414	)		(345	)
Amortization of transition obligation		--			--			--		--		36			37
Net periodic benefit cost	$	5,997		$	2,443		$	3,390	$	3,663	$	79		$	227

The following table summarizes PSE’s change in benefit obligation for the periods ended September 30, 2010 and December 31, 2009:

	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	September 30, 2010			December 31, 2009			September 30, 2010			December 31, 2009			September 30, 2010			December 31, 2009
Change in benefit obligation:
Benefit obligation at beginning of period	$	504,786		$	460,586		$	39,152		$	39,348		$	15,953		$	18,088
Beginning of year remeasurement		456			--			--			--			86			--
Service cost		12,083			14,141			768			1,068			79			125
Interest cost		21,030			27,734			1,624			2,315			660			960
Actuarial loss (gain)		--			25,094			--			707			--			(1,296	)
Benefits paid		(26,400	)		(22,769	)		(1,262	)		(4,286	)		(1,413	)		(2,342	)
Medicare part D subsidiary received		--			--			--			--			803			418
Benefit obligation at end of period	$	511,955		$	504,786		$	40,282		$	39,152		$	16,168		$	15,953

The fair value of plan assets increased from $485.7 million at December 31, 2009 to $497.8 million at September 30, 2010.

The Company expects contributions to fund the qualified pension plan and to meet SERP and the other postretirement plan obligations for the year ending December 31, 2010 to be $12.0 million, $3.0 million and $0.5 million, respectively.  During the three months ended September 30, 2010, the Company contributed $0.4 million to meet the SERP plan requirements.  During the nine months ended September 30, 2010, the Company contributed $12.0 million to fund the qualified retirement plan and paid participants $1.3 million and $0.3 million for SERP and other postretirement obligations, 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 three months ended March 31, 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.

As part of the Company's new contract with the International Brotherhood of Electrical Workers (IBEW) Local 77 union, which took effect September 1, 2010, the benefit calculation formula has changed for Company employees covered by the contract.  New IBEW represented employees and employees not vested in a plan benefit as of July 31, 2010 will participate in the cash balance formula of the retirement program, with any accrued benefit converted to a beginning cash balance account.  Employees who were vested in a plan benefit as of July 31, 2010 have a choice to convert to the cash balance formula or remain on a final average earnings formula based on qualified pay and years of service.  Participants in the cash balance formula receive an enhanced Company match in the Company’s 401(k) program effectiv e December 1, 2010.

(7)   Regulation and Rates

On April 2, 2010, the Washington Utilities and Transportation Commission (Washington Commission) issued its order in PSE’s consolidated electric and natural gas general rate case filed in May 2009, supplemented by an order of clarification on April 8, 2010, approving a general rate increase for electric customers of 3.7% annually or $74.1 million.  The rate increase was $36.2 million, or 1.8%, less than PSE requested.  The electric general rate order also created a tariff rider intended to allow PSE to collect in electric rates $52.3 million related to the recovery of certain deferred costs that were part of the general rates and will be fully amortized at the end of 2011.  The natural gas rate increase approved was 0.8% annuall y or $10.1 million.  The rate increase was $18.3 million, or 1.5%, less than PSE requested.  The rate increase for electric and natural gas customers was effective April 8, 2010.  In its order, the Washington Commission approved a weighted cost of capital of 8.1% and a capital structure that included 46.0% common equity with an after-tax return on equity of 10.1%.

In response to a petition filed by the Company in 2007, the Washington Commission issued an order on May 20, 2010 relating to how Renewable Energy Credit (REC) proceeds should be handled for regulatory accounting and ratemaking purposes.  In its May 2010 order, the Washington Commission stated that the REC proceeds should be recorded as regulatory liabilities as proposed by the Company and that amounts recorded would accrue interest at a rate to be determined in a later filing.  In its petition, PSE had sought approval for the use of $21.1 million of REC proceeds as an offset against its California wholesale energy sales regulatory asset.  In its May 20, 2010 order, the Washington Commission allowed PSE to use $3.3 million of the REC proceeds to offset the regulatory asset.  In response to the o rder, PSE adjusted the carrying value of its regulatory asset in the second quarter of 2010 by $17.8 million (from $21.1 million to $3.3 million), with the $3.3 million then offset against the Company’s renewable energy credits regulatory liability as provided in the order.  The Company’s California wholesale energy sales regulatory asset represented unpaid bills for power sold into the markets maintained by the California Independent System Operator during the California Energy Crisis, the claims of which were settled along with all counterclaims against PSE in a settlement agreement approved by the Federal Energy Regulatory Commission (FERC) on July 1, 2009.

Effective July 1, 2010, the Washington Commission approved a change in PSE’s Production Tax Credit (PTC) tariff as PSE has not been able to utilize PTCs since 2007, due to insufficient taxable income caused primarily by bonus tax depreciation.  The Washington Commission approved PSE suspending its PTC tariff, effective July 1, 2010.  This resulted in an overall increase in PSE’s electric rates of 1.65%.  PSE anticipates filing a tariff with the Washington Commission no later than November 1, 2010 which will propose that PTCs be provided to customers after PSE is able to utilize the tax credits on its tax return.  

On September 22, 2010, a joint proposal and accounting petition was filed with the Washington Commission by PSE, Washington Commission Staff and Industrial Customers of Northwest Utilities which addressed how to recover PTCs provided to customers that have not been utilized and addresses REC proceeds to be returned to customers.  On October 26, 2010, the Washington Commission issued an order granting the joint proposal and accounting petition.  The order allows the Company to credit customers for REC revenues received and deferred through November 2009.  This credit will reduce rates by $27.7 million, or 2.47%, over five months beginning November 2010 through March 2011.  RECs received after November 2009 will be retained by the Company and will be used to recapture PTCs previously provided to c ustomers.  Once these recaptured PTCs are utilized by the Company on its tax return, the customers will receive the credit.

On October 1, 2010, PSE filed an electric tariff filing with the Washington Commission to implement changes to rates to pass-through a reduction in the benefits PSE expects to receive from the Bonneville Power Administration’s (BPA) Residential Exchange Program (REP).  PSE is requesting a reduction in the tariff credit rate compared to the amount currently being credited to customers, resulting in a 1.0% increase to electric rates.

On October 1, 2010, PSE filed a natural gas tariff filing with the Washington Commission to implement changes to natural gas rates that would result in an overall increase in revenue of $24.4 million and a customer rate increase of 2.3%.   PSE requested the new rates be made effective by February 1, 2011.  

On October 1, 2010, PSE filed a PGA natural gas tariff filing with the Washington Commission to adjust the PGA rates, which cover expected natural gas costs from sales to customers.  On an average annual basis, the PGA rates included in this filing reflect a 3.1% decrease in natural gas costs due to decreases in forward market prices.  The PGA rates also reflect a decrease in the PGA deferred natural gas cost credit which will result in a 5.0% increase to overall natural gas rates.  Collectively, the annual dollar amount of these changes, if approved, would result in an increase of $18.3 million, or 1.9%.  This rate adjustment will have no impact on PSE’s net income.  PSE requested the new rates be made effective November 1, 2011.  

(8)   Litigation

Residential Exchange. PSE is a party to certain agreements with the BPA that provide payments under its REP to PSE, which PSE passes through to its residential and small farm electric customers.  PSE has agreements with the BPA for REP payments until 2011 and for the period 2011 to 2028.  PSE and other parties have sought United States Court of Appeals for the Ninth Circuit review regarding BPA’s agreements for REP payments during these periods.  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.

Equilon Litigation.  On April 21, 2010, Equilon Enterprises (dba Shell Oil Products), the owner of an oil refinery in Skagit County, Washington, filed suit against PSE in the United States District Court for the Western District of Washington in Seattle.  PSE and Equilon resolved the dispute in October 2010 and dismissal of the court action will follow.

Colstrip Matters. In May 2003, approximately 50 plaintiffs initiated an action against the owners of Colstrip, including PSE, alleging that: (1) seepage from two different wastewater pond areas caused groundwater contamination and threatened to contaminate domestic water wells and the Colstrip water supply pond; and (2) seepage from the Colstrip water supply pond caused structural damage to buildings and toxic mold.  The defendants reached agreement on a global settlement with all plaintiffs on April 29, 2008 and PSE paid its share of the settlement in July 2008.

On March 29, 2007, a second complaint related to pond seepage was filed 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.

The federal Clean Air Mercury Rule, enacted by the Environmental Protection Agency (EPA) in May 2005, was vacated by the D.C. Circuit Court in February 2008.  Final resolution of this matter is still pending.  However the Montana Board of Environmental Review approved a Montana mercury control rule to limit mercury emissions from coal-fired plants on October 16, 2006 (with a limit of 0.9 lbs/Trillion British thermal units for plants burning coal like that used at Colstrip) which remains in effect.  In 2008, the Colstrip owners, based on testing performed in 2006, 2007 and 2008, ordered mercury control equipment intended to achieve the new limit.  The equipment has been fully installed and is in regular operation.  The Colstrip mercury control equipment is operating at a level that meets the current Montana limit, which is based on a rolling 12 month average so compliance cannot be fully confirmed until January 1, 2011.  Optimization of the feed rates of calcium bromide and activated carbon is underway.  An evaluation will be conducted to determine whether additional controls, if any, are necessary, depending on actual long-term performance.

On June 15, 2005, the EPA issued the Clean Air Visibility rule to address regional haze or regionally-impaired visibility caused by multiple sources over a wide area.  The rule defines Best Available Retrofit Technology (BART) requirements for electric generating units, including presumptive limits for sulfur dioxide, particulate matter and nitrogen oxide controls for larger units.  In February 2007, Colstrip was notified by EPA that Colstrip Units 1 & 2 were determined to be subject to EPA’s BART requirements.  PSE submitted a BART engineering analysis for Colstrip Units 1 & 2 in August 2007 and responded to an EPA request for additional analyses with an addendum in June 2008.  PSE cannot yet determine the outcome.

On June 21, 2010, the EPA issued a Proposed Rulemaking for the “Identification and Listing of Special Wastes: Disposal of Coal Combustion Residuals from Electric Utilities” which proposes different regulatory mechanisms to regulate coal combustion residuals, generally referred to as “coal ash,” and requests information from industry on these respective proposals.  PSE has joined other Colstrip owners in requesting an extension to the 120 day comment period, and the owners are currently evaluating the potential impact of these regulations on operations at Colstrip.  PSE’s potential increased cost of operating Colstrip is unknown at this time and dependent on the outcome of this rulemaking.

Snoqualmie Falls.  On July 7, 2010, a lawsuit was filed by the Snoqualmie Valley Preservation Alliance 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 have been filed by the plaintiff and the Corps.  PSE joined the Corps’ motion and filed a motion for summary judgment arguing the plaintiff’s claims are barred as untimely and improper.  The court has set a schedule for summary judgment motions to be heard in November 2010.  The ultimate impact of the suit, if any, on PSE or the w ork currently underway on the project cannot be determined at this time.

(9)   Variable Interest Entities

In accordance with ASC 810, “Consolidation” (ASC 810), a business entity that has a controlling financial interest in a 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 had previously disclosed two potentially significant variable interests in prior periods; both entities are qualifying facilities contracts that expire at the end of 2011.  The Company requested information from the relevant entities; however, they have refused to provide the necessary information to the Company, as they are not required to do so under their contracts.  Due to the short duration of the remaining life of the 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 e nded September 30, 2010 and 2009, the Company’s purchased power expense for these entities was $54.0 million and $52.9 million, respectively.  For the nine months ended September 30, 2010 and 2009, the Company’s purchased power expense for these entities was $141.1 million and $132.0 million, respectively.

(10)   Other

Snoqualmie Falls Project.  Under the Snoqualmie Falls hydroelectric facility’s federal operating license granted by FERC in 2004 and finalized in 2009, PSE is performing a major, three and a half 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 will 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.

Bond Issuances. On June 29, 2010, PSE issued $250.0 million of senior notes, secured by first mortgage bonds.  The notes have a term of 30 years and an interest rate of 5.764%.  Net proceeds from the offering were used to repay $7.0 million of medium-term notes with a 7.12% interest rate that matured on September 13, 2010 and to repay short-term debt outstanding under the $400.0 million capital expenditure credit facility.

On March 8, 2010, PSE issued $325.0 million of senior notes, secured by first mortgage bonds.  The notes have a term of 30 years and an interest rate of 5.795%.  Net proceeds from the offering were used to replenish funds utilized to repay $225.0 million of senior medium-term notes which matured on February 22, 2010 and carried a 7.96% interest rate.  Remaining net proceeds were used to pay down debt under PSE’s capital expenditure credit facility.

(11)   Income Taxes

The Company reported income tax expense for the third quarter using the discrete period method as opposed to the estimated annual effective tax rate (ETR) method, which is the generally prescribed method for interim reporting periods. The Company employed the discrete method in lieu of the estimated annual ETR method because relatively small movements in projected income for the year could result in extreme variability in the ETR.  Therefore, the Company does not believe it can reliably estimate its ETR for the full year.

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,” “estimates,” “expects,” “plans,” “predicts,” “projects,” “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 an 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 cons ider 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 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, generation and natural gas distribution.  Puget Energy’s business strategy is to generate stable cash flows by offering reliable electric and natural gas service in a cost-effective manner through PSE.  On February 6, 2009, Puget Holdings LLC (Puget Holdings) completed its merger with Puget Energy.  Puget Holdings is a consortium of long-term infrastructure investors including Macquarie Infrastructure Partners I, Macquarie Infrastructure Partners II, Macquarie Capital Group Limited, Macquarie-FSS Infrastructure Trust, the Canada Pension Plan Investment Board, the British Columbia Investment Management Corporation, and the Alberta Investment Management Corporation.  As a result of the merger, Puget Energy is a direct wholly owned subsidiary of Puget Equico LLC (Puget Equico), which is an indirect wholly owned subsidiary of Puget Holdings.  In connection with the merger transaction, Puget Energy applied Accounting Standards Codification (ASC) 805, “Business Combinations” (ASC 805).  PSE’s basis of accounting will continue to be on a historical basis and PSE’s financial statements do not include any ASC 805 purchase accounting adjustments.  Puget Energy and PSE are collectively referred to herein as “the Company.”

PSE generates revenue and cash flow primarily from the sale of electric and natural gas services to residential and commercial customers within a service territory covering approximately 6,000 square miles, principally in the Puget Sound region of the state of Washington.  To meet customer growth, to replace expiring power contracts and to meet Washington state’s renewable energy portfolio standards, PSE is increasing its 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.  0;PSE requires access to bank and capital markets to meet its financing needs.

For the three and nine months ended September 30, 2010, PSE’s net income was affected primarily by the following three factors:  (1) the impact of falling natural gas prices on energy derivative contracts; (2) a decline in electric and natural gas sales due largely to weather and weak economic conditions; (3) the effect of higher power costs resulting from below average hydroelectric and wind conditions; and (4) the general tariff increases approved in April 2010 were insufficient to recover capital and operating costs incurred and are anticipated to incur in the future until sufficient rate recoveries are approved.  Further detail on each of these primary drivers, as well as other factors affecting PSE’s performance, are set forth below in this “Overview” section as well as in other section s of the Management’s Discussion & Analysis.

Energy derivatives had a significant negative impact on net income for the three and nine months ended September 30, 2010 due to continued declines in forward wholesale energy prices.  As of July 1, 2009, PSE no longer designates energy derivatives as cash flow hedges, resulting in all of the mark-to-market changes being recorded in the income statement.  Over the tenor of PSE’s outstanding derivative contracts, the forward wholesale prices of electricity and natural gas declined 13.1% and 14.5%, respectively, from June 30, 2010 to September 30, 2010 and declined 24.2% and 27.5%, respectively, from December 31, 2009 to September 30, 2010.  These declines have caused significant unrealized losses on derivative instruments for the three and nine months ended September 30, 2010.  PSE enters i nto energy derivative instruments to balance its energy portfolio, reduce costs where feasible and reduce volatility in costs and margins in the energy portfolio.

The number of PSE’s electric and natural gas customers continued to increase in 2010, but at a significantly slower rate.  Electric retail kilowatt sales and gas therm sales for the nine months ended September 30, 2010 declined 4.9% and 8.7%, respectively, as compared to the same period in 2009.  The decline in sales volumes in 2010 is due primarily to warmer temperatures in the first quarter of 2010 which is one of its highest revenue quarters for the year, and to a lesser extent, the impact of PSE’s residential and commercial customer conservation programs, as well as continued effects of weak economic conditions in the Pacific Northwest.  The average temperature in PSE’s service territory during the first quarter of 2010 was 46.8 degrees, or 6.2 degrees warmer than the same period in 2009 which was 40.6 degrees which caused significant lost of revenue.  Normal temperature for the same period is 43.5 degrees.

The Pacific Northwest also experienced below normal hydroelectric and wind conditions that adversely impacted PSE’s power costs in the first quarter of 2010.  In total, hydroelectric and wind generation for the nine months ended September 30, 2010 decreased by 468,673 megawatt hours (MWhs), or 9.0% as compared to 2009.  As a result, PSE’s power costs increased due to purchasing or generating higher cost electricity to replace the decrease in generation from hydroelectric and wind generating projects.

As a result of the Washington Utilities and Transportation Commission’s (Washington Commission) order of May 20, 2010, PSE adjusted the carrying value of its California wholesale energy sales regulatory asset in the second quarter of 2010 by $17.8 million (from $21.1 million to $3.3 million), with the $3.3 million then offset against the Company’s renewable energy credits regulatory liability as provided in the order.  The Company’s California wholesale energy sales regulatory asset represented unpaid bills for power sold into the markets maintained by the California Independent System Operator during the California Energy Crisis, the claims of which were settled along with a ll counterclaims against PSE in a settlement agreement approved by the Federal Energy Regulatory Commission (FERC) on July 1, 2009.  PSE’s settlement with the California parties was expressly conditioned upon two other actions: (1) the California Energy Commission approval of PSE’s Wild Horse and Hopkins Ridge wind farms as qualifying facilities under California renewable energy rules; and (2) the approval by the California Public Utilities Commission of a renewable power agreement between PSE and Southern California Edison (SCE), under which PSE sold qualifying renewable power to SCE in 2009 and 2010.  PSE had sought approval for the use of $21.1 million of such proceeds be used as an offset against its California wholesale energy sales regulatory asset.

Factors and Trends Affecting PSE’s Performance.  PSE’s regulatory requirements and operational needs require the investment of substantial capital in 2010 and future years.  Because PSE intends to seek recovery of such investments through the regulatory process, its financial results depend heavily upon positive 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 the effects of 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;

·   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 and state environmental standards;

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

·   Wholesale commodity prices of electricity and natural gas.

Regulation of PSE Rates and Recovery of PSE Costs. The rates that PSE is allowed to charge for its services is an important item influencing 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 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 rate 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

On April 2, 2010, the Washington Commission issued its order in PSE’s consolidated electric rate case filed in May 2009, supplemented by an order of clarification on April 8, 2010, approving a general rate increase for electric customers of 3.7% annually, or $74.1 million.  The rate increase was $36.2 million, or 1.8%, less than PSE requested.  The electric general rate order also created a tariff rider intended to allow PSE to collect in electric rates $52.3 million related to the recovery of certain deferred costs that were part of the general rates and will be fully amortized at the end of 2011.  The rate increase for electric customers was effective April 8, 2010.  In its order, the Washington Commission approved a weight ed cost of capital of 8.1% and a capital structure that included 46.0% common equity with an after-tax return on equity of 10.1%.

Effective July 1, 2010, the Washington Commission approved a change in PSE’s Production Tax Credit (PTC) tariff as PSE has not been able to utilize PTCs since 2007, due to insufficient taxable income caused primarily by bonus tax depreciation.  The Washington Commission approved PSE suspending its PTC tariff, effective July 1, 2010.  This resulted in an overall increase in PSE’s electric rates of 1.65%.  PSE anticipates filing a tariff with the Washington Commission no later than November 1, 2010 which will propose that PTCs be provided to customers after PSE is able to utilize the tax credits on its tax return.  

On September 22, 2010, a joint proposal and accounting petition was filed with the Washington Commission by PSE, Washington Commission Staff and Industrial Customers of Northwest Utilities which addressed how to recover PTCs provided to customers that have not been utilized and addresses Renewable Energy Credit (REC) proceeds to be returned to customers.  On October 26, 2010, the Washington Commission issued an order granting the joint proposal and accounting petition.  The order allows the Company to credit customers for REC revenues received and deferred through November 2009.  This credit will reduce rates by $27.7 million, or 2.47%, over five months beginning November 2010 through March 2011.  RECs received after November 2009 will be retained by the Company and will be used to recapture PTC s previously provided to customers.  Once these recaptured PTCs are utilized by the Company on its tax return, the customers will receive the credit.

On October 1, 2010, PSE filed an electric tariff filing with the Washington Commission to implement changes to rates to pass-through a reduction in the benefits PSE expects to receive from the Bonneville Power Administration’s (BPA) Residential Exchange Program (REP).  PSE is requesting a reduction in the tariff credit rate compared to the amount currently being credited to customers, resulting in a 1.0% increase to electric rates.

Currently, PSE has a Power Cost Adjustment (PCA) mechanism that provides for recovery of power costs from customers or refunding of power cost savings to customers, as those costs vary from the “power cost baseline” level of power costs which 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.  As a result, 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%

The following table sets forth electric rate changes that were 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

Gas Rates

On April 2, 2010, the Washington Commission issued its order, effective April 8, 2010, in PSE’s natural gas general rate case filed in May 2009, approving a general rate increase of 0.8% annually or $10.1 million.  The rate increase was $18.3 million, or 1.5%, less than PSE requested.  In its order, the Washington Commission approved a weighted cost of capital of 8.1% and a capital structure that included 46.0% common equity with an after-tax return on equity of 10.1%.

On May 28, 2009, the Washington Commission approved a Purchased Gas Adjustment (PGA) rate decrease of $21.2 million, or 1.8% annually, effective June 1, 2009.  On September 24, 2009, the Washington Commission approved a PGA rate decrease of $198.1 million, or 17.1% annually, effective October 1, 2009.  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.

On October 1, 2010, PSE filed a natural gas tariff filing with the Washington Commission to implement changes to natural gas rates that would result in an overall increase in revenue of $24.4 million and a customer rate increase of 2.3%.  PSE requested the new rates be made effective by February 1, 2011.  

On October 1, 2010, PSE filed a PGA natural gas tariff filing with the Washington Commission to adjust the PGA rates, which cover expected natural gas costs from sales to customers.  On an average annual basis, the PGA rates included in this filing reflect a 3.1% decrease in natural gas costs due to decreases in forward market prices.  The PGA rates also reflect a decrease in the PGA deferred natural gas cost credit which will result in a 5.0% increase to overall natural gas rates.  Collectively, the annual dollar amount of these changes, if approved, would result in an increase of $18.3 million, or 1.9%.  This rate adjustment will have no impact on PSE’s net income.  PSE requested the new rates be made effective November 1, 2011.

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

Type of Rate Adjustment	Effective Date	Average Percentage Increase (Decrease) in Rates	Annual Increase (Decrease) in Revenue (Dollars in Millions)
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 from 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 three months ended September 30, 2010 primarily due to Pacific Northwest temperatures averaging 2.5 degrees cooler than the same period in 2009 tempered by lower customer usage when weather adjusted, reflecting a weak Pacific Northwest economy and PSE’s conservation programs.  PSE reported lower customer usage for the nine months ended September 30, 2010 primarily due to warmer temperatures in the Pacific Northwest during the first quarter of 2010 than the same period in 2009.  The average temperature during the first quarter of 2010 was 46.8 degrees, or 6.2 degrees warmer than the same period in 2009.  The warmer than average temperatures for the first quarter was partially mitigated by cooler than average temperatures for the sec ond and third quarters of 2010 by 3.0 and 2.5 degrees, respectively, compared to the same periods in 2009.

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.  The effects of the current recession on Washington’s economy have exacerbated a decline in customer usage throughout 2010.

Access to Debt Capital. PSE relies on access to bank borrowings and short-term money markets as sources of liquidity and longer-term debt markets to fund its utility construction program, to meet maturing debt obligations and other capital expenditure requirements not satisfied by cash flow from its operations or equity investment from its parent, Puget Energy.  Neither Puget Energy nor PSE have any debt outstanding whose maturity would accelerate upon a credit rating downgrade.  However, a ratings downgrade could adversely affect the 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 20 14, 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 regulations of air and water quality, generation by-products disposal and endangered species protection also impact the Company’s operations, as would possible climate change legislation or the regulation of generation by-products, such as coal ash.  PSE must spend significant amounts funding regulatory agencies, many of which have greatly expanded mandates, and on measures including resource planning, remediation, monitoring, pollution control equipment and emis sions-related abatement and fees in order to comply with these regulatory requirements.

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

Other Challenges and Strategies

Energy Supply.  As noted in PSE’s Integrated Resource Plan (IRP) filed with the Washington Commission, PSE 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.  Therefore, PSE’s IRP sets forth a multi-part strategy of implementing energy efficiency programs and pursuing additional renewable resources (primarily wind) and the additional base load natural gas-fired generation to meet the growing needs of its customers.  If PSE cannot acquire ne eded energy supply resources at a reasonable cost, it may be required to purchase additional power in the open market at a cost that could, in the absence of regulatory relief, significantly increase its expenses and reduce earnings and cash flows.

Infrastructure Investment. PSE is investing in its utility infrastructure and customer service functions in order to meet regulatory requirements, serve customers’ energy needs and replace aging infrastructure.  These investments and operating requirements give rise to significant growth in depreciation expense and operating expense, 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 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 and carbon financial instruments.  The Company supports the development of regional and national markets for such products that are free, open, transparent and liquid.

Results of Operations

The following discussion should be read in conjunction with the consolidated financial statements and the related notes included elsewhere in this document.  Set forth below are the consolidated financial results of PSE for the three and nine months ended September 30, 2010 and 2009:

	Three Months Ended September 30,								Nine Months Ended September 30,
Puget Sound Energy (Dollars in Thousands)	2010			2009			Percent Change		2010			2009			Percent Change
Operating revenue:
Electric
Residential sales	$	215,651		$	195,589		10.3	%	$	790,457		$	794,782		(0.5	)%
Commercial sales		205,240			199,289		3.0			620,193			628,832		(1.4	)
Industrial sales		26,429			23,959		10.3			76,466			74,408		2.8
Other retail sales, including unbilled revenue		10,736			12,847		(16.4	)		(35,818	)		(42,249	)	(15.2	)
Total retail sales		458,056			431,684		6.1			1,451,298			1,455,773		(0.3	)
Transportation sales		2,594			3,076		(15.7	)		8,477			7,919		7.0
Sales to other utilities and marketers		31,963			33,177		(3.7	)		45,878			53,416		(14.1	)
Other		(3,005	)		(18,279	)	(83.6	)		1,896			(10,466	)	(118.1	)
Total electric operating revenue		489,608			449,658		8.9			1,507,549			1,506,642		0.1
Gas
Residential sales		73,817			77,184		(4.4	)		418,770			563,525		(25.7	)
Commercial sales		45,595			50,281		(9.3	)		201,204			257,855		(22.0	)
Industrial sales		6,158			6,619		(7.0	)		22,610			29,638		(23.7	)
Total retail sales		125,570			134,084		(6.3	)		642,584			851,018		(24.5	)
Transportation sales		3,474			3,304		5.1			10,516			9,554		10.1
Other		3,527			4,740		(25.6	)		11,323			14,913		(24.1	)
Total gas operating revenue		132,571			142,128		(6.7	)		664,423			875,485		(24.1	)
Non-utility operating revenue		650			840		(22.6	)		2,350			4,333		(45.8	)
Total operating revenue		622,829			592,626		5.1			2,174,322			2,386,460		(8.9	)
Operating expenses:
Energy costs:
Purchased electricity		127,936			160,867		20.5			557,221			610,034		8.7
Electric generation fuel		96,712			77,164		(25.3	)		194,649			143,124		(36.0	)
Residential exchange		(15,173	)		(19,271	)	21.3			(54,510	)		(72,604	)	24.9
Purchased gas		60,284			72,463		16.8			343,779			524,666		34.5
Net unrealized (gain) loss on derivative instruments		78,559			(27,144	)	*			200,702			(34,734	)	*
Utility operations and maintenance		117,155			116,129		(0.9	)		355,569			353,129		(0.7	)
Non-utility expense and other		3,188			2,282		(39.7	)		7,742			5,677		(36.4	)
Merger and related costs		--			--		--			--			23,908		*
Depreciation		73,111			66,978		(9.2	)		217,765			199,164		(9.3	)
Amortization		18,355			16,522		(11.1	)		53,011			48,082		(10.3	)
Conservation amortization		20,392			12,836		(58.9	)		60,874			47,395		(28.4	)
Taxes other than income taxes		58,903			57,785		(1.9	)		210,304			225,824		6.9
Total operating expenses		639,422			536,611		(19.2	)		2,147,106			2,073,665		(3.5	)
Operating income (loss)		(16,593	)		56,015		(129.6	)		27,216			312,795		(91.3	)
Other income		11,033			13,272		(16.9	)		32,846			35,591		(7.7	)
Other expense		(1,074	)		(1,299	)	(17.3	)		(4,147	)		(5,432	)	(23.7	)
Interest expense		(57,738	)		(50,305	)	14.8			(168,643	)		(149,551	)	12.8
Income (loss) before income taxes		(64,372	)		17,683		*			(112,728	)		193,403		(158.3	)
Income tax (benefit) expense		(34,813	)		9,841		*			(45,402	)		56,806		179.9
Net income (loss)	$	(29,559	)	$	7,842		*	%	$	(67,326	)	$	136,597		(149.3	)%

__________

* Not meaningful

Puget Sound Energy

Summary Results of Operations

PSE’s net loss for the three months ended September 30, 2010 was $(29.6) million with operating revenue of $622.8 million as compared to net income of $7.8 million with operating revenue of $592.6 million for the same period in 2009.  Operating revenue for the three months ended September 30, 2010 included an increase in electric operating revenue of $40.0 million and a decrease in natural gas operating revenue of $9.6 million.

The following are significant factors impacting PSE’s net loss for the three months ended September 30, 2010:

·   Increase in net unrealized loss on derivative instruments of $105.7 million primarily due to falling forward market prices of electricity, natural gas on de-designation cash flow hedges and for derivative contracts initiated after July 1, 2009 related to PSE’s energy contracts.  PSE discontinued cash flow hedge accounting on July 1, 2009.

·   Increase in interest expense of $7.4 million primarily due to increased expense on long-term bonds and interest on regulatory liability associated with RECs.

·   Decrease in purchased electricity and electric generation fuel of $13.4 million primarily due to a 2.4% reduction in electric customer retail sales volumes, lower wholesale costs and higher hydroelectric and wind generation.

·   Increase in depreciation expense of $6.1 million primarily due to additional capital expenditures that were placed in service.

PSE’s net loss for the nine months ended September 30, 2010 was $(67.3) million with operating revenue of $2.2 billion as compared to the net income of $136.6 million with operating revenue of $2.4 billion for the same period in 2009.  Operating revenue for the nine months ended September 30, 2010 included an increase in electric operating revenue of $0.9 million despite a $17.8 million carrying value adjustment related to the California wholesale energy sales regulatory asset and a decrease in natural gas operating revenue of $211.1 million.

The following are significant factors impacting PSE’s net loss for the nine months ended September 30, 2010:

·   Increase in net unrealized loss on derivative instruments of $235.4 million primarily due to falling forward market prices of electricity, natural gas on de-designation cash flow hedges and for derivative contracts initiated after July 1, 2009 related to PSE’s energy contracts.  PSE discontinued cash flow hedge accounting on July 1, 2009.

·   Increase in interest expense of $19.1 million primarily due to a write off of a regulatory asset for deferred interest paid to the Internal Revenue Service (IRS) related to the Simplified Service Cost Method deduction in prior years which was disallowed for the rate of recovery in the general rate case order of April 2, 2010, increase in long-term bonds and interest on regulatory liability associated with RECs.

·   Increase in depreciation expense of $18.6 million primarily due to additional capital expenditures that were placed in service.

·   The above increases were partially offset by a decrease from one-time merger costs of $23.9 million related to the merger of Puget Energy with Puget Holdings.  These costs were primarily related to PSE employee compensation triggered by Puget Energy’s change of control, credit agreement related expenses and the impact of increases in the deferred compensation related liability.

Puget Sound Energy

The following discussion provides the significant items that impact PSE’s results of operations for the three and nine months ended September 30, 2010 and 2009.

Regulated Utility Operating Revenue

Electric Operating Revenue.Electric retail sales increased $26.4 million, or 6.1%, to $458.1 million from $431.7 million for the three months ended September 30, 2010 as compared to the same period in 2009.  This increase was primarily due to a $15.6 million electric rate increase effective April 8, 2010 and a $7.5 million increase related to the suspension of the PTC tariff effective July 1, 2010.  Revenue also increased due to a $7.2 million increase related to conservation rider revenue and a $4.3 million increase attributable to a decrease in benefits of the Residential and Small Farm Energy Exchange Benefit which is a program that provides benefits (or credits) to cust omers.  The Residential and Small Farm Energy Exchange Benefit credits also increase power costs by a corresponding amount resulting in no impact to earnings.  Partially offsetting the increase to electric retail sales was a decrease of $10.3 million due to a decline in retail electricity usage of 114,099 MWhs, or 2.4%.  This decline in retail electricity usage was primarily due to the continued effects of a weak Pacific Northwest economy and an increase in energy conservation programs, partially offset by temperatures which averaged 2.5 degrees cooler than the same period in 2009.

Electric retail sales decreased $4.5 million, or 0.3%, to $1.45 billion from $1.46 billion for the nine months ended September 30, 2010 as compared to the same period in 2009.  This decrease included a $71.8 million decline in retail electricity usage of 780,949 MWhs, or 4.9%, which was primarily due to warmer than average temperatures during the first quarter of 2010 as compared to the same period in 2009.  During the first quarter of 2010, the average temperature was 46.8 degrees, or 6.2 degrees warmer than the same period in 2009.  The average temperature for the nine months ended September 2010 was slightly warmer than the same period in 2009 which had cooler temperatures in the second and third quarters.  The average warmer temperatures translate to an 8.1% decrease in heating degree days f rom the prior year (difference in average daily temperature compared to 65 degrees).  The decline in retail electricity usage was also due to an increase in PSE’s residential and commercial customer conservation programs and the continued effects of a weak Pacific Northwest economy.  Partially offsetting the decrease in electric retail sales was an $18.9 million increase attributable to a decrease in benefits of the Residential and Small Farm Energy Exchange Benefit, a $29.5 million electric rate increase and regulatory asset tracker effective April 8, 2010 and May 1, 2010, an $11.2 million increase related to conservation rider revenue and an $8.5 million increase related to the suspension of the PTC tariff effective July 1, 2010.

Sales to other utilities and marketers decreased $7.5 million, or 14.1%, to $45.9 million from $53.4 million for the nine months ended September 30, 2010 as compared to the same period in 2009.  This decrease was due to a carrying value adjustment of $17.8 million related to PSE’s California wholesale energy sales regulatory asset which offset an increase in actual sales to other utilities of $10.3 million.  The increase in actual sales to other utilities, prior to the carrying value adjustment, was primarily due to favorable wholesale market conditions that made it cost effective for PSE to generate energy at its company-owned combustion turbine facilities and to sell it in the wholesale market.

Gas Operating Revenue.  Natural gas retail sales decreased $8.5 million, or 6.3%, to $125.6 million from $134.1 million for the three months ended September 30, 2010 as compared to the same period in 2009.  This decrease was primarily due to an $18.3 million decrease in natural gas operating revenue as a result of PGA rate decrease on October 1, 2009 which reduced rates by 17.1%.  The PGA mechanism passes through to customer’s 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 mecha nism.  The decrease in natural gas retail sales was partially offset by an increase of 7.2 million in natural gas therm sales, or 5.4%, which increased gas retail sales by $11.6 million due to the third quarter average temperatures which were 2.5 degrees cooler than the same period in 2009 tempered by a reduction in use-per-customer.

Natural gas retail sales decreased $208.4 million, or 24.5%, during the nine months ended September 30, 2010 as compared to the same period in 2009.  This decrease was primarily due to a $127.2 million decrease in gas operating revenue as a result of PGA rate decreases on June 1, 2009 and October 1, 2009.  The PGA mechanism passes through to customer 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.  The decrease in natural gas retail sales is also due to a decrease of 66.9 million in natural gas therm sales, or 8.7%, which decreas ed revenue by $90.1 million.  The decrease was due primarily to warmer than average temperatures in the Pacific Northwest for the current year as compared to colder than normal temperatures in 2009, an increase in PSE’s residential and commercial customer conservation programs and the continued effects of a weak Pacific Northwest economy.

Operating Expenses

Purchased electricityexpenses decreased $32.9 million, or 20.5%, and $52.8 million, or 8.7%, for the three and nine months ended September 30, 2010, respectively, as compared to the same periods in 2009.  The decrease for the three months ended September 30, 2010 was primarily the result of lower wholesale market prices which contributed $28.8 million and a decrease in purchased power of 156,042 MWhs or 5.7% resulting in a decrease of $8.0 million. This decrease was primarily due to lower customer usage related to weak economic conditions and higher hydroelectric and wind generation of 9.5% or 131,308 MWhs and an increase in coal generation of 32.8% or 342,449 MWhs.  This decrease w as partially offset by an increase in transmission and other expenses of $3.9 million.

The decrease for the nine months ended September 30, 2009 was primarily the result of a decrease in purchased power of 1,375,746 MWhs or 12.2% resulting in a decrease of $66.8 million partially offset by higher wholesale market prices which contributed $11.4 million. The decrease for the nine months ended September 30, 2010 was primarily the result of lower customer usage related to warmer than normal temperatures during 2010, a weak economy in the Pacific Northwest and 22.1% higher generation of electricity from PSE’s coal generating facility, Colstrip.  This decrease was further offset by an increase in transmission and other expenses which contributed $3.5 million.

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

Electric generation fuel expense increased $19.6 million, or 25.3%, and $51.5 million, or 36.0%, for the three and nine months ended September 30, 2010, respectively, as compared to the same periods in 2009.  The increase for the three months ended September 30, 2010 was primarily due to an $11.5 million increase in costs related to higher volumes of electricity generation from PSE’s combustion turbine facilities and an $8.1 million increase related to a 22.1% increase in generation of electricity at Colstrip due to the Unit 4 extended outage in 2009.  The increase for the nine months ended September 30, 2010 was primarily due to a $37.4 million increase in costs at PSE’s combustion turbine facilities and a $14.1 million increase related to increas ed generation at Colstrip in 2010 and because of the Colstrip Unit 4 extended outage in 2009.  Increased electric generation fuel expense at company-owned natural gas facilities was primarily the result of a 13.8% decrease in hydroelectric generation at facilities located on the Columbia River where PSE obtains energy produced under take-or-pay purchased electricity contracts.

Residential exchange credits decreased $4.1 million and $18.1 million for the three and nine months ended September 30, 2010, respectively, as compared to the same periods in 2009 as a result of lower electric residential and farm customer sales volumes associated with the BPA REP.  The REP credit is a pass-through tariff item with a corresponding credit in electric operating revenue; thus, it has no impact on net income.

Purchased gasexpenses decreased $12.2 million, or 16.8%, and $180.9 million, or 34.5%, for the three and nine months ended September 30, 2010, respectively, as compared to the same periods in 2009.  The decrease for the three months ended September 30, 2010 was primarily due to a decrease in natural gas costs reflected in PGA rates partially offset by a 5.4% usage increase related to 2.5 degrees cooler than average temperatures than the same period in 2009.  The decrease for the nine months ended September 30, 2010 was primarily due to an 8.7% decrease in customer usage and natural gas costs reflected in PGA rates.  The decrease in customer usage was mainly due to warmer t han average temperatures during 2010 as compared to the same period in 2009, the impact of PSE’s residential and commercial customer conservation programs and the continued effects of a weak Pacific Northwest economy.  The PGA mechanism provides the rates used to determine natural gas costs based on customer usage.  The rate decrease was the result of declining 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 receivable balance at September 30, 2010 was $3.5 million as compared to payable balance of $49.6 million at December 31, 2009.  PSE is authorized by the Washington Commission to accrue carrying costs on PGA receivable and payable balances.  0;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.

Net unrealized loss on derivative instrumentsincreased $105.7 million and $235.4 million during the three and nine months ended September 30, 2010, respectively, as compared to the same periods in 2009.  The loss was primarily due to mark-to-market accounting for PSE’s energy derivative contracts which are no longer cash flow hedges and the decline in wholesale energy prices.  On July 1, 2009, PSE elected to de-designate its energy related derivative contracts previously designated as cash flow hedges.  The contracts that were de-designated were physical electric supply contracts and natural gas swap contracts used to fix the price of natural gas for electric generat ion.  For these contracts and for contracts initiated after such date, all mark-to-market accounting impacts are recognized through earnings.  The amount in accumulated other comprehensive income (OCI) is transferred to earnings when the contracts settle or sooner, if management determines that the forecasted transaction is probable of not occurring.  As a result, PSE will continue to experience the earnings impact of these reversals from OCI in future periods.  For the three months ended September 30, 2010, the forward prices of contracts declined by 13.1% related to electricity prices and 14.5% for natural gas prices as compared to the prior year.  For the three months ended September 30, 2009, the forward price of electricity was flat and the forward price of gas for power contracts decreased 1.0% as compared to June 2009 forward prices.  For the nine months ended September 30, 2010, the mark-to-market accounting was also impacted by declining fo rward energy prices over the tenor of PSE’s derivative contracts outstanding which decreased 24.2% related to electricity prices and 27.5% for natural gas prices as compared to the prior year.  For the nine months ended September 30, 2009, the forward price of electricity increased 4.3% and 5.7% for gas for power hedge contracts as compared to December 2008 forward prices.

Merger and related costs associated with the merger with Puget Holdings incurred for the nine months ended September 30, 2010 decreased $23.9 million.  The decrease relates to a revision to compensation costs as a result of the change in control.  These costs were due to one-time PSE employee compensation costs, expenses related to the termination of credit agreements, legal fees and deferred compensation liability increases triggered by the merger.  Pursuant to the Washington Commission merger order commitments, PSE did not seek recovery of these costs in retail rates.

Depreciation expense increased $6.1 million and $18.6 million for the three and nine months ended September 30, 2010, respectively, as compared to the same periods in 2009.  This increase was primarily due to additional capital expenditures that were placed into service.

Amortization expense increased $1.8 million and $4.9 million for the three and nine months ended September 30, 2010, respectively, due to the inclusion of Mint Farm and Wild Horse expansion operating and ownership costs in general rates effective April 8, 2010.  PSE ceased deferral of these costs effective April 8, 2010.

Conservation amortization increased $7.6 million and $13.5 million for the three and nine months ended September 30, 2010, respectively, as compared to the same periods in 2009.  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 decreased $15.5 million for the nine months ended September 30, 2010, as compared to the same period in 2009.  The decrease was primarily due to a decrease in revenue sensitive taxes due to lower retail sales and property taxes.

Other Income and Interest Expense and Income Tax Expense

Other Income decreased $2.7 million for the nine months ended September 30, 2010, as compared to the same period in 2009.  The decrease was primarily due to the carrying costs associated with the Mint Farm regulatory asset being included in general rates effective April 8, 2010.  Prior to April 8, 2010, the Mint Farm regulatory asset was accruing interest income as authorized by the Washington Commission. This decrease was partially offset by increased income related to PTC carrying costs and the Wild Horse expansion.

Interest expense increased $7.4 million and $19.1 million for the three and nine months ended September 30, 2010, respectively, as compared to the same periods in 2009.  The increase during the three months ended September 30, 2010 was primarily due to increased expense on long-term bonds.  The increase during the nine months ended September 30, 2010, was primarily due to a write off of a regulatory asset of deferred interest paid to the IRS related to the Simplified Service Cost Method deduction from prior years which was disallowed in the Washington Commission general rate case order of April 2, 2010.  Also impacting the increase was higher long-term debt outstanding and interest on regulatory liability associated with RECs.

Income tax expense decreased $44.7 million and $102.2 million for the three and nine months ended September 30, 2010, respectively, as compared to the same periods in 2009.  The decrease was primarily related to lower pre-tax income.

Puget Energy

Summary Results of Operations

All the operations of Puget Energy are conducted through its subsidiary PSE.  “Predecessor” refers to the operations of Puget Energy and PSE prior to the consummation of the merger on February 6, 2009.  “Successor” refers to the operations of Puget Energy and PSE subsequent to the merger.

Puget Energy’s net income (loss) for the three months ended September 30, 2010 and 2009 was as follows:

	Three Months Ended September 30,
Benefit/(Expense) (Dollars in Thousands)	2010			2009			Percent Change
PSE net income (loss)	$	(29,559	)	$	7,842		*	%
Purchased electricity		144			144		--
Net unrealized gain on derivative instruments		15,284			47,687		(67.9	)
Non-utility expense and other		(1,019	)		(2,260	)	54.9
Depreciation and amortization		--			46		*
Interest income/expense 1		(22,771	)		(19,964	)	(14.1	)
Income tax benefit (expense)		22			(8,988	)	*
Puget Energy net income (loss)	$	(37,899	)	$	24,507		*	%

__________

*	Not meaningful
1	Puget Energy’s interest expense includes elimination adjustments of intercompany interest on short-term debt.

Puget Energy’s net income (loss) for the nine months ended September 30, 2010 and 2009 was as follows:

				Successor			Predecessor
Benefit/(Expense) (Dollars in Thousands)	Nine Months Ended September 30, 2010			February 6, 2009 – September 30, 2009			January 1, 2009 – February 5, 2009			2009 Combined			Percent Change
PSE net income (loss)	$	(67,326	)	$	104,986		$	31,611		$	136,597		(149.3	)%
Other operating revenue		--			358			--			358		*
Purchased electricity		433			385			--			385		12.5
Net unrealized gain on derivative instruments		91,519			86,565			--			86,565		5.7
Non-utility expense and other		(4,223	)		(5,763	)		(4	)		(5,767	)	26.8
Merger and related costs		--			(2,731	)		(20,416	)		(23,147	)	*
Depreciation and amortization		--			122			--			122		*
Charitable contribution expense		--			(5,000	)		--			(5,000	)	*
Interest income/expense 1		(66,323	)		(50,663	)		25			(50,638	)	(31.0	)
Income tax benefit (expense)		(7,507	)		(8,122	)		1,540			(6,582	)	(14.1	)
Puget Energy net income (loss)	$	(53,427	)	$	120,137		$	12,756		$	132,893		(140.2	)%

__________

*	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, 2010 was $(37.9) million with operating revenue of $622.8 million as compared to net income of $24.5 million with operating revenue of $592.6 million for the same period in 2009.  Puget Energy’s net loss for the nine months ended September 30, 2010 was $(53.4) million with operating revenue of $2.2 billion as compared to net income of $132.9 million with operating revenue of $2.4 billion for the same period in 2009.

The following are significant factors impacting Puget Energy’s net loss:

·   Puget Energy’s net income for the three months ended September 30, 2010 was negatively impacted by $32.4 million change in net unrealized gain on derivative instruments as a result of the required recognition of all contracts at fair value as part of purchase accounting, including derivative contracts previously designated as Normal Purchase Normal Sale (NPNS).  Certain of these contracts were subsequently redesignated as NPNS.  The unrealized gain represents amortization of the fair value recorded.  Also Puget Energy’s net loss was favorably impacted by a $9.0 million change in income tax.

·   Puget Energy’s net loss for the nine months ended September 30, 2010, as compared to net income for the same period in 2009, was positively impacted by a $5.0 million change in net unrealized gain on derivative instruments as a result of the required recognition of all contracts at fair value as part of purchase accounting, including derivative contracts previously designated as NPNS.  Certain of these contracts were subsequently redesignated as NPNS.  The unrealized gain represents amortization of the fair value recorded.  Puget Energy’s net income for the same period was negatively impacted by $15.7 million of interest income/expense due to the long-term debt at Puget Energy, business combination fair value amortization of PSE’s debt and PSE’s deferred debt costs.

2010 compared to 2009

Operating Expenses

Net unrealized gain on derivative instruments decreased $32.4 million for the three months ended September 30, 2010 as compared to the same period in 2009, and increased by $5.0 million for the nine months ended September 30, 2010 as compared to the same period in 2009 due to the fair value amortization of the derivative contracts.

Merger and related costs decreased $23.1 million for the nine months ended September 30, 2010 as compared to the same period in 2009, due to one-time merger cost of compensation triggered by Puget Energy’s change of control, excise taxes associated with the transaction and financial advisor fees.

Other Income and Expense, Interest Expense and Income Tax Expense

Charitable contribution expense decreased $5.0 million for the nine months ended September 30, 2010 as compared to the same period in 2009, due to a charitable contribution to the PSE Foundation in 2009.

Interest expense increased $2.8 million for the three months ended September 30, 2010 as compared to the same period in 2009 due to the $2.0 million increase in business combination fair value amortization adjustments related to PSE’s long-term debt and deferred debt costs and $0.6 million increase of interest rate swap expense.  Interest expense increased $15.7 million for the nine months ended September 30, 2010 as compared to the same period in 2009 due to the difference in the length of time the term loan and the capital expenditures loan were outstanding and the business combination fair value adjustment amortization.  During the nine months ended September 30, 2010, there were nine months of interest on the term and capital expenditure loans and ni ne months of business combination fair value adjustments amortization related to PSE’s long-term debt and deferred debt costs, as compared to eight months for the same period in 2009.  The interest expense for the term and capital expenditure loans contributed $8.8 million and the business combination fair value amortization contributed $6.7 million.

Income tax expense decreased $9.0 million for the three months ended September 30, 2010 as compared to the same periods in 2009.  The decrease for the three months ended September 30, 2010 is primarily related to lower pre-tax income.

Capital Requirements

Contractual Obligations and Commercial Commitments

With the exception of the $250.0 million senior notes issued on June 29, 2010 and the $325.0 million senior notes issued on March 8, 2010, which increased contractual obligations by $1.3 billion net of redemptions (including accrued interest through the life of the issuance), there have been no other changes from 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, 2009.  The information provided in the contractual obligations and commercial commitments table under “Capital Requirements” in Item 7 “Management’s Discussion and Analysis of Financial Conditions and Results of Operations” in the combined Puget Energy and PSE annual report on Form 10- K for the year ended December 31, 2009 is incorporated herein by reference.

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.  The cash flow from construction expenditures, excluding equity Allowance for Funds Used During Construction (AFUDC), was $667.6 million for the nine months ended September 30, 2010.  As a result of a general slowing in the economy and changes to the Company’s proposed resources, PSE’s projected construction expenditures have been reduced.  Presently planned utility construction expenditures, excluding AFUDC, for 2010, 2011 and 2012 are as follows:

Capital Expenditure Projections (Dollars in Millions)	2010		2011		2012
Energy delivery, technology and facilities	$	550	$	637	$	672
New resources		307		386		46
Total expenditures	$	857	$	1,023	$	718

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

Capital Resources

Cash From Operations

Puget Sound Energy

Cash generated from operations for the nine months ended September 30, 2010 was $551.7 million, a decrease of $42.4 million from the $594.1 million generated during the first nine months of 2009.  The decrease was primarily the result of the following factors:

·   Accounts receivable and unbilled revenue decreased $201.4 million during the first nine months of 2010 compared to a decrease of $282.2 million during the same period in 2009, causing an operating cash flow decrease of $80.8 million.

·   PGA mechanism provided $53.1 million payment to customers related to overcollection of prior year plan related rates during the first nine months of 2010 compared to an overrecovery from customers of $61.5 million during the same period in 2009, which decreased cash flow from operating activities by $114.6 million.

·   PSE’s deferred taxes decreased $66.1 million in 2010 compared to tax savings in 2009 of $174.6 million due to bonus depreciation and repair allowance deductions.

The decrease in cash generated from operating activities in 2010 was partially offset by the following:

·   Net purchases of $9.3 million on accounts payable during the first nine months of 2010 compared to net payments of $131.3 million during the same period in 2009, due to the timing of payments resulting in an increase in operating cash flows of $140.6 million.

·   A decrease in prepaid income taxes of $41.0 million during the first nine months of 2010 compared to an increase of $117.2 million during the same period in 2009, causing an increase in cash from operations of $158.2 million.

·   Cash received from the sale of renewable energy credits of $33.3 million during the first nine months of 2010 compared to payments received of $23.0 million during the same period in 2009, causing an increase in cash from operations of $10.3 million.

·   Pension funding of $12.0 million during the first nine months of 2010 compared to funding of $18.0 million during the same period in 2009, causing an increase in cash from operations of $6.0 million.

·   PSE received tax refunds of $19.1 million during the first nine months of 2010 compared to tax payments of $0.1 million during the same period in 2009, causing an increase of $19.2 million.

Puget Energy

Cash generated from operations for the nine months ended September 30, 2010 was $767.9 million, a decrease of $17.0 million from the $784.9 million generated during the first nine months of 2009.  The decrease included $42.4 million from the cash provided by the operating activities of PSE, discussed above.  In addition, the decrease was the result of the following:

·   As a result of the merger, $279.1 million in derivative settlement payments were reclassified to financing activities during the first nine months of 2010 compared to $349.7 million during the same period in 2009, resulting in a decrease in operating cash flows of $70.6 million.  These contracts represent proceeds received from derivative instruments that included financing elements at the merger date.

The decrease in cash generated from operating activities in 2010 was partially offset by the following:

·   Puget Energy made $88.6 million less net payments on accounts payable during the first nine months of 2010 compared to the same period in 2009, causing an increase 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.  PSE anticipates refinancing the redemption of bonds 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 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, $1.150 billion in short-term borrowing capability and which mature concurrently in February 2014.  Such 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 its 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, to the extent below investment grade, 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, 2010, 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 $400.0 million working capital facility and $350.0 million credit agreement to support energy hedging allow for issuing standby letters of credit.  PSE must also pay a commitment fee on the unused portion of the credit facilities.  The spreads and the commitment fee depend on PSE’s credit ratings.  As of the date of this re port, 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.

In May 2010, PSE’s credit facilities were amended, in part, to include a swing line feature allowing same day availability on such borrowings up to $50.0 million.  This feature does not increase the total lending commitments.

As of September 30, 2010, utilization under PSE’s $400.0 million working capital facility included $77.0 million drawn and outstanding plus a $12.6 million letter of credit supporting BPA contracts.  There was no debt outstanding under the $400.0 million capital expenditure facility and no amount drawn and outstanding (including letters of credit) under the $350.0 million facility supporting energy hedging.  Outside of the credit agreements, PSE had a $5.7 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 its parent, Puget Energy, in the form of a credit agreement and a Demand Promissory Note (Note).  Under the terms of such agreement and Note, 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 lowest of the weighted-average interest rate of: (a) PSE’s outstanding commercial paper interest rate or (b) PSE’s senior unsecured revolving credit facility.  Absent such borrowings, interest is charged at one-month LIBOR plus 0.25%.  At September 30, 2010, the outstanding balance of the Note was $22.9 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

Puget Energy has entered into a $1.225 billion five-year term loan and a $1.0 billion credit facility for funding capital expenditures.  Such loan and 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 such covenants each quarter.  As of September 30, 2010, 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 bank 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 that is based upon Puget Energy’s credit rating.  Puget Energy must also 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 1.25%, the spread to the LIBOR is 2.25% and the commitment fee is 0.84%.  As of September 30, 2010, the term loan was fully drawn and $258.0 million w as outstanding under the $1.0 billion facility.

New Legislation on Derivative Contracts.  In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act was signed into law.  The new legislation established a framework for the regulation of certain over-the-counter derivative contracts which are used for hedging and trading.  The legislation could expand collateral requirements of derivative contracts which may make it more costly for companies.  The Company is evaluating the new legislation to determine its impact, if any, on the Company’s hedging program, results of operations and liquidity.  The Company will not know the full impact of the new legislation until the regulations are finalized.  

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, 2010, approximately $365.9 million of unrestricted retained earnings were available for the payment of dividends under the most restrictive mortgage indenture covenant.

In addition, beginning February 6, 2009, pursuant to the terms of the Washington Commission merger order, dividends may not be declared or paid 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 for the most recently ended four fiscal quarter periods prior to such date is equal to or greater than three to one.

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

Puget Energy’s ability to pay dividends to its shareholder 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.  In accordance with 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 (as defin ed 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, 2010, 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 and restated articles of incorporation as well as 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 t he $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, 2010, PSE could issue:

·   approximately $1.4 billion of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately $2.3 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, 2010; and

·   no additional first mortgage bonds under PSE’s natural gas mortgage indenture until it meets the required net earnings available for interest coverage test.  Although PSE had approximately $384.2 million of gas bondable property available for issuance, the Company is 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).  At September 30, 2010, PSE exceeded the gas 2.0 times net earnings test, but did not meet the combined 1.75 times test primarily as a result of lower energy sales and higher net power costs due to warmer than normal temperatures and lower than normal hydroelectric and wind generation.  The company expects to meet this test by December 2010 as it collects additional revenue from the April 8, 2010 rate increase for electric and natural gas customers.

At September 30, 2010, PSE had approximately $5.6 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 filed a shelf registration statement to provide for the offering of an aggregate amount of $800.0 million of debentures or senior notes of PSE secured by first mortgage bonds.  The Company remains subject to the restrictions of PSE’s indentures on the amount of first mortgage bonds that PSE may issue.

On June 29, 2010, PSE issued $250.0 million of senior notes, secured by first mortgage bonds.  The notes have a term of 30 years and an interest rate of 5.764%.  Net proceeds from the note offering were used to repay $7.0 million of medium-term notes with a 7.12% interest rate that matured on September 13, 2010 and to repay short-term debt outstanding under the $400.0 million capital expenditure credit facility.

On March 8, 2010, PSE issued $325.0 million of senior notes, secured by first mortgage bonds.  The notes have a term of 30 years and an interest rate of 5.795%.  Net proceeds from the offering were used to replenish funds utilized to repay $225.0 million of senior medium-term notes which matured on February 22, 2010 and carried a 7.96% interest rate.  Remaining net proceeds were used to pay down debt under PSE’s capital expenditure credit facility.

Other

Proceedings Relating to the Bonneville Power Administration

PSE has been a party to certain agreements with the BPA that provide payments under its REP to PSE, which PSE passes through to its residential and small farm electric customers.  PSE has agreements with the BPA for REP payments until 2011 and for the period 2011 to 2028.  PSE and other parties have sought United States Court of Appeals for the Ninth Circuit  review regarding BPA’s agreements for REP payments during these periods.  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 ultimatel y have on PSE.

Proceedings Relating to Equilon

On April 21, 2010, Equilon Enterprises (dba Shell Oil Products), the owner of an oil refinery in Skagit County, Washington, filed suit against PSE in the United States District Court for the Western District of Washington in Seattle.  PSE and Equilon resolved the dispute in October 2010 and dismissal of the court action will follow.

Proceedings Relating to Snoqualmie Falls

On July 7, 2010, a lawsuit was filed by the Snoqualmie Valley Preservation Alliance 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 have been filed by the plaintiff and the Corps.  PSE joined the Corps’ motion and filed a motion for summary judgment arguing the plaintiff’s claims are barred as untimely and improper.  The court has set a schedule for summary judgment motions to be heard in November 2010.  The ultimate impact of the suit, if any, on PSE or the work currently underway on the project cannot be determined at this time.

Other

IBEW Union Contract.  The International Brotherhood of Electrical Workers (IBEW) Local 77 union and PSE reached an agreement on a new contract, which took effect September 1, 2010 upon the IBEW vote approving the provisions.  The contract is for four years and will expire March 31, 2014.

UA Union Contract.  The United Association of Journeymen and Apprentices of the Plumbing and Pipefitting Industry (UA) and PSE reached an agreement on a new contact, which took effect October 1, 2010 upon UA vote approving the contract.  The contract is for three years and will expire September 30, 2013.

Colstrip Matters

In May 2003, approximately 50 plaintiffs initiated an action against the owners of Colstrip, including PSE, alleging that: (1) seepage from two different wastewater pond areas caused groundwater contamination and threatened to contaminate domestic water wells and the Colstrip water supply pond; and (2) seepage from the Colstrip water supply pond caused structural damage to buildings and toxic mold.  The defendants reached agreement on a global settlement with all plaintiffs on April 29, 2008 and PSE paid its share of the settlement in July 2008.

On March 29, 2007, a second complaint related to pond seepage was filed 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.

The federal Clean Air Mercury Rule, enacted by the Environmental Protection Agency (EPA) in May 2005, was vacated by the D.C. Circuit Court in February 2008.  Final resolution of this matter is still pending.  However the Montana Board of Environmental Review approved a Montana mercury control rule to limit mercury emissions from coal-fired plants on October 16, 2006 (with a limit of 0.9 lbs/Trillion British thermal units for plants burning coal like that used at Colstrip) which remains in effect.  In 2008, the Colstrip owners, based on testing performed in 2006, 2007 and 2008, ordered mercury control equipment intended to achieve the new limit.  The equipment has been fully installed and is in regular operation.  The Colstrip mercury control equipment is operating at a level that meets the current Montana limit, which is based on a rolling 12 month average so compliance cannot be fully confirmed until January 1, 2011.  Optimization of the feed rates of calcium bromide and activated carbon is underway.  An evaluation will be conducted to determine whether additional controls, if any, are necessary, depending on actual long-term performance.

On June 15, 2005, the EPA issued the Clean Air Visibility rule to address regional haze or regionally-impaired visibility caused by multiple sources over a wide area.  The rule defines Best Available Retrofit Technology (BART) requirements for electric generating units, including presumptive limits for sulfur dioxide, particulate matter and nitrogen oxide controls for larger units.  In February 2007, Colstrip was notified by the EPA that Colstrip Units 1 & 2 were determined to be subject to the EPA’s BART requirements.  PSE submitted a BART engineering analysis for Colstrip Units 1 & 2 in August 2007 and responded to an EPA request for additional analyses with an addendum in June 2008.  PSE cannot yet determine the outcome.

On June 21, 2010, the EPA issued a Proposed Rulemaking for the “Identification and Listing of Special Wastes: Disposal of Coal Combustion Residuals from Electric Utilities” which proposes different regulatory mechanisms to regulate coal combustion residuals, generally referred to as “coal ash,” and requests information from industry on these respective proposals.  PSE has joined other Colstrip owners in requesting an extension to the 120 day comment period, and the owners are currently evaluating the potential impact of these regulations on operations at Colstrip.  PSE’s potential increased cost of operating Colstrip is unknown at this time and dependent on the outcome of this rulemaking.

New Accounting Pronouncements

Fair Value Measurements and Disclosures. In January 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2010-6, “Improving Disclosures About Fair Value Measurements” (ASU 2010-6), which requires new disclosures about recurring or nonrecurring fair value measurements including significant transfers into and out of Level 1 and Level 2 fair value measurements and information on purchases, sales, issuances, and settlements on a gross basis in the reconciliation of Level 2 fair value measurements.  ASU 2010-6 is effective for annual reporting periods beginning after December 15, 2009, except for Level 3 reconciliation disclosures which are effective for annual periods beginning after December 15, 2010.  As thes e new requirements relate solely to disclosures, the adoption of this guidance will not impact the Company’s consolidated financial statements.

Variable Interest Entities. In December 2009, the FASB issued ASU 2009-17, Topic 810, “Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities,” which amended the FASB ASC for the issuance of pre-codification FASB Statement No. 167, “Amendments to FASB Interpretation No. 46(R).”  This standard replaces the quantitative-based risks and rewards calculation for determining which reporting entity, if any, has a controlling financial interest in a variable interest entity (VIE).  An approach focused on identifying which reporting entity has the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and: (1) the obligation to absorb losses of the entit y; or (2) the right to receive benefits from the entity.  An approach that is primarily qualitative is expected to be more effective for identifying which reporting entity has a controlling financial interest in a VIE.  This standard also requires additional disclosures about a reporting entity’s involvement in VIE relationships.  The Company adopted the standard as of January 1, 2010, and such adoption did not have an impact on the consolidated financial statements.

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.

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 (MD&A), which is located under Item 2 of this report.  Further, and as a result of ASC 815 disclosures, summary metrics that may be included in this MD&A discussion may be further expanded upon in the footnotes preceding the MD&A.

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

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

The following tables present the Company’s energy derivatives instruments that do not meet the NPNS exception at September 30, 2010 and December 31, 2009:

	Energy Derivatives
Puget Energy Derivative Portfolio (Dollars in thousands)	September 30, 2010				December 31, 2009
	Assets		Liabilities		Assets		Liabilities
Electric portfolio:
Current	$	3,504	$	146,407	$	4,137	$	79,732
Long-term		1,598		140,923		1,003		70,367
Total electric derivatives	$	5,102	$	287,330	$	5,140	$	150,099
Gas portfolio:
Current	$	4,578	$	135,377	$	10,811	$	62,207
Long-term		2,952		76,041		3,602		19,350
Total gas derivatives	$	7,530	$	211,418	$	14,413	$	81,557
Total derivatives	$	12,632	$	498,748	$	19,553	$	231,656

	Energy Derivatives
Puget Sound Energy Derivative Portfolio (Dollars in thousands)	September 30, 2010				December 31, 2009
	Assets		Liabilities		Assets		Liabilities
Electric portfolio:
Current	$	3,504	$	146,407	$	4,137	$	75,323
Long-term		1,598		140,923		1,003		70,367
Total electric derivatives	$	5,102	$	287,330	$	5,140	$	145,690
Gas portfolio:
Current	$	4,578	$	135,377	$	10,811	$	62,207
Long-term		2,952		76,041		3,602		19,350
Total gas derivatives	$	7,530	$	211,418	$	14,413	$	81,557
Total derivatives	$	12,632	$	498,748	$	19,553	$	227,247

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), please see Note 3 and Note 4 of the notes to the consolidated financial statements.

At September 30, 2010, the Company had total assets of $7.5 million and total liabilities of $211.4 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 $113.4 million and would impact the fair value of those contracts marked-to-market in earnings by $73.7 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, 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, 2010, PSE held approximately $1.1 million worth of standby letters of credit in support of various electricity and renewable energy credit 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.  However, as of September 30, 2010, approximately 92.2% of PSE’s energy and natural gas portfolio exposure, including NPNS transactions, is with counterparties that are rated at least investment grade by the major rating agencies, and 7.8% of PSE’s portfolio 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 that 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, based on the deterioration of counterparty’s credit, PSE records the fair value of the contract on the ba lance sheet with the corresponding amount recorded in the statements of income.

The locked accumulated OCI of the cash flow hedge is impacted by a counterparty’s deterioration of credit under ASC 815 guidelines.  If a forecasted transaction associated with cash flow hedge is no longer probable of occurring, based on deterioration of credit, PSE will record in earnings the locked accumulated OCI.

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 us ed by weighting the fair value and contract tenors for all deals for each counterparty and coming up with an average value.  The default factor used is dependent upon whether the counterparty is in a net asset or a net liability position after applying the master agreement levels.

The Company applies the counterparty’s default factor to compute credit reserves for counterparties that are in a net asset position.  Moreover, the Company 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, 2010, the Company was in a net liability position with the majority of its counterparties so 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 any collateral requirem ents 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 and 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 enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts.  As of September 30, 2010, Puget Energy had seven 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.  As of September 30, 2010, the fair value of the interest rate swaps designated as cash flow hedges was a $77.9 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 $50.6 million after tax related to the interest rate swaps designated as cash flow hedges during the current reporting period.

A hypothetical 10.0% increase or decrease in interest rates would change the fair value of interest rate swaps by $4.4 million, with a corresponding after-tax increase in unrealized loss recorded in accumulated OCI of $2.9 million.

The following table presents Puget Energy’s interest rate derivative instruments designated as cash flow hedges at September 30, 2010 and December 31, 2009:

Puget Energy Derivative Portfolio (Dollars in Thousands)	September 30, 2010				December 31, 2009
Interest Rate Swaps	Assets		Liabilities		Assets		Liabilities
Current	$	--	$	30,441	$	--	$	26,844
Long-term		--		47,472		20,854		--
Total	$	--	$	77,913	$	20,854	$	26,844

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, 2010 is a net loss of $7.4 million after tax and accumulated amortization.  This compares to a loss of $7.6 million in OCI after tax as of December 31, 2009.  All financial hedge contracts of this type are reviewed by an officer, presented to the Asset Management Committee or the Board of Directors, as applicable, and are approved prior to execution.  PSE had no treasury locks or forward starting swap contracts outstanding at September 30, 2010.

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 Chief Executive Officer and the Executive Vice President and Chief Financial Officer, Puget Energy has evaluated the effectiveness of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of September 30, 2010, the end of the period covered by this report.  Based upon that evaluation, the Chief Executive Officer and the Executive Vice President and Chief Financial Officer of Puget Energy concluded that these disclosure controls and procedures are effective.

Changes in Internal Control Over Financial Reporting

There have been no changes in Puget Energy’s internal control over financial reporting during the three months ended September 30, 2010 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 Chief Executive Officer and the Executive Vice President and Chief Financial Officer, PSE has evaluated the effectiveness of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of September 30, 2010, the end of the period covered by this report.  Based upon that evaluation, the Chief Executive Officer and the Executive Vice President and Chief Financial Officer of PSE concluded that these disclosure controls and procedures are effective.

Changes in Internal Control Over Financial Reporting

There have been no changes in PSE’s internal control over financial reporting during the three months ended September 30, 2010 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, 2010.  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 year ended December 31, 2009.

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 2, 2010	Chief Accounting Officer and Officer duly authorized to sign this report on behalf of each registrant

EXHIBIT INDEX

The following exhibits are filed herewith:

12.1	Statement setting forth computation of ratios of earnings to fixed charges (2005 through 2008, January 1, 2009 – February 5, 2009 (Predecessor) and February 6, 2009 – December 31, 2009 and 12 months ended September 30, 2010 (Successor)) for Puget Energy.
12.2	Statement setting forth computation of ratios of earnings to fixed charges (2005 through 2009 and 12 months ended September 30, 2010) for Puget Sound Energy.
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	Chief 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	Chief 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	Chief Financial Officer certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.