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, 2008

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 registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.

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

Indicate by check mark whether 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	/X/	Accelerated filer	/  /	Non-accelerated filer	/  /	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 October 31, 2008, (i) the number of shares of Puget Energy, Inc. common stock outstanding was 129,678,489 ($.01 par value) and (ii) all of the outstanding shares of Puget Sound Energy, Inc. common stock were held by Puget Energy, Inc.

Table of Contents

Definitions
Filing Format
Forward Looking Statements
Part I.	Financial Information
Item 1.	Financial Statements
	Puget Energy, Inc.
	Consolidated Statements of Income – Three and Nine Months Ended September 30, 2008 and 2007
	Consolidated Statements of Comprehensive Income – Three and Nine Months Ended September 30, 2008 and 2007
	Consolidated Balance Sheets – September 30, 2008 and December 31, 2007
	Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2008 and 2007
	Puget Sound Energy, Inc.
	Consolidated Statements of Income – Three and Nine Months Ended September 30, 2008 and 2007
	Consolidated Statements of Comprehensive Income – Three and Nine Months Ended September 30, 2008 and 2007
	Consolidated Balance Sheets – September 30, 2008 and December 31, 2007
	Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2008 and 2007
	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 5.	Other Information
Item 6.	Exhibits
Signatures
Exhibit Index

DEFINITIONS

AFUDC	Allowance for Funds Used During Construction
ALJ	Administrative Law Judge
ASC	Average System Cost
BPA	Bonneville Power Administration
Consortium	Infrastructure investors led by Macquarie Infrastructure Partners, the Canada Pension Plan Investment Board and British Columbia Investment Management Corporation, and also includes Alberta Investment Management Corporation, Macquarie-FSS Infrastructure Trust and Macquarie Capital Group Limited
DOR	Montana Department of Revenue
EITF	Emerging Issues Task Force
EPA	U. S. Environmental Protection Agency
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN	Financial Accounting Standards Board Interpretation
FSP	FASB Staff Position
GAAP	Generally Accepted Accounting Principles
Goldendale	Goldendale Electric Generating Facility
InfrastruX	InfrastruX Group, Inc.
ISDA	International Swaps and Derivatives Association
kW	Kilowatt
kWh	Kilowatt Hour
Lehman	Lehman Brothers Bank FSB
LIBOR	London Interbank Offered Rate
MMS	Mineral Management Service of the United States
MW	Megawatt (one MW equals one thousand kW)
MWh	Megawatt Hour (one MWh equals one thousand kWh)
NAESB	North American Energy Standards Board
NERC	North American Electric Reliability Corporation
Ninth Circuit	United States Court of Appeals for the Ninth Circuit
NPNS	Normal Purchase Normal Sale
PCA	Power Cost Adjustment
PCORC	Power Cost Only Rate Case
PF	BPA Preference Rate
PGA	Purchased Gas Adjustment
PSE	Puget Sound Energy, Inc.
PSE Funding	PSE Funding, Inc.
Puget Energy	Puget Energy, Inc.
PURPA	Public Utility Regulatory Policy Act
REP	Residential Exchange Program
RPSA	Residential Purchase and Sale Agreement
SFAS	Statement of Financial Accounting Standards
Tenaska	Tenaska Power Fund, L.P.
Washington Commission	Washington Utilities and Transportation Commission
WECC	Western Electricity Coordinating Council
WECO	Western Energy Co
WSPP	Western Systems Power Pool

FILING FORMAT

This Report on Form 10-Q is a combined Quarterly Report filed separately by two different registrants, Puget Energy, Inc. (Puget Energy) and Puget Sound Energy, Inc. (PSE).  Any references in this report to the “Company” are to Puget Energy and PSE collectively.  PSE makes no representation as to the information contained in this report relating to Puget Energy and the subsidiaries of Puget Energy other than PSE and its subsidiaries.

FORWARD-LOOKING STATEMENTS

Puget Energy and PSE are including 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, 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, operation of distribution and transmission facilities (natural gas and electric), 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 and present or prospective wholesale and retail competition;

· Failure to comply with FERC or Washington Commission standards and/or rules, which could result in penalties based on the discretion of either commission;

· Failure to comply with electric reliability standards developed by the North American Electric Reliability Corporation (NERC) for users, owners and operators of the power system, which could result in penalties of up to $1.0 million per day per violation;

· Changes in, adoption of, and compliance with, laws and regulations, including decisions and policies concerning the environment, climate change, emissions, natural resources, and fish and wildlife (including the Endangered Species Act);

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

· Changes in tax law, related regulations, or differing interpretation or enforcement of applicable law by the Internal Revenue Service or other taxing jurisdiction, which could have a material adverse impact on the financial statements;

· Natural disasters, such as hurricanes, windstorms, earthquakes, floods, fires and landslides, which can interrupt service and/or 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;

· 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 and also adversely affect the availability of and access to capital and credit markets and/or impact delivery of energy to PSE from it 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 weather conditions in the Pacific Northwest, which could have effects on customer usage and PSE’s revenues, thus impacting net income;
·	Weather, which can have a potentially serious impact on PSE’s ability to procure adequate supplies of natural gas, fuel or purchased power to serve its customers and on the cost of procuring such supplies;
·	Variable hydro conditions, which can impact streamflow and PSE’s ability to generate electricity from hydroelectric facilities;
·	Plant 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 resource;
·	The ability of 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;
·	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;
·	The amount of collection, if any, of PSE’s receivables from the California Independent System Operator (CAISO) and other parties and the amount of refunds found to be due from PSE to the CAISO or other parties;
·	Industrial, commercial and residential growth and demographic patterns in the service territories of PSE;
·	General economic conditions in the Pacific Northwest, which might impact customer consumption or affect PSE’s accounts receivable;
·	The loss of significant customers or 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; and
·	With respect to the merger transaction Puget Energy announced on October 26, 2007:
	§	The risk that the merger may not be consummated in a timely manner, if at all, including due to the failure to receive any required regulatory approvals;
	§	The risk that the merger agreement may be terminated in circumstances that require Puget Energy to pay a termination fee of up to $40.0 million, plus out-of-pocket expenses of the acquiring entity and its members of up to $10.0 million (or if no termination fee is payable, up to $15.0 million); and
	§	The effect of the announcement of the merger on our business relationships, operating results and business generally, including our ability to retain key employees.

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 except per share amounts)

(Unaudited)

	Three Months Ended  September 30,						Nine Months Ended  September 30,
	2008			2007			2008			2007
Operating revenues:
Electric	$	467,355		$	456,100		$	1,551,528		$	1,418,980
Gas		133,249			142,120			810,326			834,304
Other		5,558			3,460			7,646			13,439
Total operating revenues		606,162			601,680			2,369,500			2,266,723
Operating expenses:
Energy costs:
Purchased electricity		173,667			185,778			645,385			640,627
Electric generation fuel		64,899			43,528			144,599			93,312
Residential exchange		(170	)		(384	)		(20,475	)		(52,424	)
Purchased gas		70,125			80,914			484,038			530,616
Net unrealized loss on derivative instruments		3,516			5,276			1,240			1,031
Utility operations and maintenance		105,995			94,433			334,608			291,539
Non-utility expense and other		5,002			3,301			7,063			8,199
Merger related costs		1,271			--			8,320			--
Depreciation and amortization		77,678			68,909			229,366			204,351
Conservation amortization		13,832			8,530			42,723			27,608
Taxes other than income taxes		56,873			56,907			214,820			207,269
Total operating expenses		572,688			547,192			2,091,687			1,952,128
Operating income		33,474			54,488			277,813			314,595
Other income (deductions):
Other income		6,865			6,725			21,782			17,710
Other expense		(2,281	)		(686	)		(4,098	)		(4,546	)
Interest charges:
AFUDC		2,167			3,554			6,378			8,915
Interest expense		(50,730	)		(54,681	)		(150,322	)		(158,133	)
Income (loss) from continuing operations before income taxes		(10,505	)		9,400			151,553			178,541
Income tax (benefit) expense		(2,280	)		(2,218	)		46,310			49,262
Income (loss) from continuing operations		(8,225	)		11,618			105,243			129,279
Loss from discontinued segment (net of tax)		--			(224	)		--			(212	)
Net income (loss)	$	(8,225	)	$	11,394		$	105,243		$	129,067
Common shares outstanding weighted-average (in thousands)		129,447			116,821			129,433			116,650
Diluted shares outstanding weighted-average (in thousands)		130,045			117,365			129,924			117,225
Basic earnings (loss) per common share	$	(0.06	)	$	0.10		$	0.81		$	1.11
Basic earnings per common share from discontinued operations		--			--			--			--
Basic earnings (loss) per common share	$	(0.06	)	$	0.10		$	0.81		$	1.11
Diluted earnings (loss) per common share	$	(0.06	)	$	0.10		$	0.81		$	1.10
Diluted earnings per common share from discontinued operations		--			--			--			--
Diluted earnings (loss) per common share	$	(0.06	)	$	0.10		$	0.81		$	1.10

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

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in thousands)

(Unaudited)

	Three Months Ended  September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
Net income (loss)	$	(8,225	)	$	11,394		$	105,243		$	129,067
Other comprehensive income:
Unrealized gain (loss) from pension and postretirement plans, net of tax of $2,754, $943, $(1,459) and $2,228, respectively		5,114			1,752			(2,709	)		4,138
Net unrealized losses on energy derivative instruments during the period, net of tax of $(90,975), $(5,752), $(4,808) and $(11,303), respectively		(168,954	)		(10,683	)		(8,930	)		(20,992	)
Reversal of net unrealized gains (losses) on energy derivative instruments settled during the period, net of tax of $(13,158), $2,488, $(14,003) and $3,556, respectively		(24,436	)		4,620			(26,005	)		6,604
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 loss		(188,197	)		(4,232	)		(37,406	)		(10,012	)
Comprehensive income (loss)	$	(196,422	)	$	7,162		$	67,837		$	119,055

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

PUGET ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

ASSETS

	September 30, 2008 (Unaudited)			December 31, 2007
Utility plant: (at original cost, including construction work in progress of $309,247 and $267,595, respectively)
Electric plant	$	6,225,756		$	5,914,127
Gas plant		2,436,155			2,313,477
Common plant		529,666			506,211
Less:  Accumulated depreciation and amortization		(3,319,165	)		(3,091,176	)
Net utility plant		5,872,412			5,642,639
Other property and investments:
Investment in Bonneville Exchange Power contract		30,858			33,503
Other property and investments		109,179			114,083
Total other property and investments		140,037			147,586
Current assets:
Cash		157,929			40,797
Restricted cash		18,957			4,793
Accounts receivable, net of allowance for doubtful accounts		38,585			218,781
Secured pledged accounts receivable		171,000			152,000
Unbilled revenues		109,466			210,025
Materials and supplies, at average cost		60,035			62,114
Fuel and gas inventory, at average cost		132,471			99,772
Unrealized gain on derivative instruments		15,831			17,130
Prepaid income tax		30,025			44,303
Prepaid expense and other		30,435			11,910
Deferred income taxes		3,049			4,011
Total current assets		767,783			865,636
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes		94,747			104,928
Regulatory asset for PURPA buyout costs		117,906			140,520
Power cost adjustment mechanism		2,018			3,114
Other regulatory assets		617,175			510,998
Unrealized gain on derivative instruments		6,391			11,845
Other		156,348			171,470
Total other long-term and regulatory assets		994,585			942,875
Total assets	$	7,774,817		$	7,598,736

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

PUGET ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

CAPITALIZATION AND LIABILITIES

	September 30, 2008 (Unaudited)			December 31, 2007
Capitalization:
Common shareholders’ investment:
Common stock $0.01 par value, 250,000,000 shares authorized, 129,678,489 and 129,678,489 shares outstanding, respectively	$	1,297		$	1,297
Additional paid-in capital		2,274,542			2,278,500
Earnings reinvested in the business		242,216			240,079
Accumulated other comprehensive income (loss), net of tax		(43,748	)		2,078
Total shareholders’ equity		2,474,307			2,521,954
Redeemable securities and long-term debt:
Preferred stock subject to mandatory redemption		1,889			1,889
Junior subordinated notes		250,000			250,000
Long-term debt		2,278,860			2,428,860
Total redeemable securities and long-term debt		2,530,749			2,680,749
Total capitalization		5,005,056			5,202,703
Current liabilities:
Accounts payable		230,765			310,398
Short-term debt		581,485			260,486
Current maturities of long-term debt		150,000			179,500
Accrued expenses:
Purchased gas liability		16,191			77,864
Taxes		58,816			84,756
Salaries and wages		29,500			28,516
Interest		57,966			45,133
Unrealized loss on derivative instruments		146,675			27,089
Other		67,444			48,918
Total current liabilities		1,338,842			1,062,660
Long-term liabilities and regulatory liabilities:
Deferred income taxes		852,973			818,161
Unrealized loss on derivative instruments		64,235			--
Regulatory liabilities		211,872			210,311
Other deferred credits		301,839			304,901
Total long-term liabilities and regulatory liabilities		1,430,919			1,333,373
Total capitalization and liabilities	$	7,774,817		$	7,598,736

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

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

 (Dollars in thousands, Unaudited)

	Nine Months Ended September 30,
	2008			2007
Operating activities:
Net income	$	105,243		$	129,067
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		229,366			204,351
Conservation amortization		42,723			27,608
Deferred income taxes and tax credits, net		71,729			38,567
Power cost adjustment mechanism		1,096			11,198
Goldendale deferred costs		(883	)		(11,211	)
Amortization of gas pipeline capacity assignment		(6,869	)		(8,169	)
Non cash return on regulatory assets		(7,427	)		(7,676	)
Net unrealized loss on derivative instruments		1,240			1,031
Change in residential exchange program		32,303			(27,205	)
Storm damage deferred costs		(252	)		(16,460	)
Other		18,695			7,835
Cash receipt from lease purchase option settlement		--			18,898
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue		261,755			215,363
Materials and supplies		2,078			(17,698	)
Fuel and gas inventory		(32,699	)		(1,045	)
Prepaid income taxes		14,278			13,122
Prepayments and other		(18,525	)		(51,816	)
Purchased gas receivable/payable		(61,673	)		100,980
Accounts payable		(76,048	)		(134,002	)
Taxes payable		(25,940	)		5,766
Accrued expenses and other		9,249			(6,874	)
Net cash provided by operating activities		559,439			491,630
Investing activities:
Construction and capital expenditures - excluding equity AFUDC		(424,280	)		(548,043	)
Energy efficiency expenditures		(43,730	)		(30,054	)
Restricted cash		(14,164	)		(139	)
Refundable cash received for customer construction projects		8,806			16,950
Cash proceeds from property sales		2,221			5,747
Other		(13,783	)		(340	)
Net cash used by investing activities		(484,930	)		(555,879	)
Financing activities:
Change in short-term debt and leases, net		320,999			49,984
Dividends paid		(97,257	)		(79,135	)
Issuance of common stock		--			4,379
Long term bond issued		--			250,000
Redemption of trust preferred stock		--			(37,750	)
Redemption of bonds, notes and leases		(179,500	)		(125,000	)
Issuance and redemption costs of bonds and other		(1,619	)		3,423
Net cash  provided by financing activities		42,623			65,901
Net increase in cash		117,132			1,652
Cash at beginning of year		40,797			28,117
Cash at end of period	$	157,929		$	29,769
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	132,290		$	128,755
Cash payments (refunds) from income taxes		(42,392	)		23,000

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,
	2008			2007			2008			2007
Operating revenues:
Electric	$	467,355		$	456,100		$	1,551,528		$	1,418,980
Gas		133,249			142,120			810,326			834,304
Other		5,558			3,460			7,646			13,439
Total operating revenues		606,162			601,680			2,369,500			2,266,723
Operating expenses:
Energy costs:
Purchased electricity		173,667			185,778			645,385			640,627
Electric generation fuel		64,899			43,528			144,599			93,312
Residential exchange		(170	)		(384	)		(20,475	)		(52,424	)
Purchased gas		70,125			80,914			484,038			530,616
Net unrealized loss on derivative instruments		3,516			5,276			1,240			1,031
Utility operations and maintenance		105,995			94,433			334,608			291,539
Non-utility expense and other		4,977			2,178			6,690			6,755
Depreciation and amortization		77,678			68,909			229,366			204,351
Conservation amortization		13,832			8,530			42,723			27,608
Taxes other than income taxes		56,873			56,907			214,820			207,269
Total operating expenses		571,392			546,069			2,082,994			1,950,684
Operating income		34,770			55,611			286,506			316,039
Other income (deductions):
Other income		6,865			6,725			21,747			17,710
Other expense		(2,281	)		(686	)		(4,098	)		(4,546	)
Interest charges:
AFUDC		2,167			3,554			6,378			8,915
Interest expense		(50,730	)		(54,681	)		(150,322	)		(158,133	)
Interest expense on Puget Energy note		(187	)		(352	)		(633	)		(1,027	)
Income (loss) before income taxes		(9,396	)		10,171			159,578			178,958
Income tax (benefit) expense		(2,120	)		(1,875	)		46,840			49,777
Net income (loss)	$	(7,276	)	$	12,046		$	112,738		$	129,181

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,
	2008			2007			2008			2007
Net income (loss)	$	(7,276	)	$	12,046		$	112,738		$	129,181
Other comprehensive income:
Unrealized gain (loss) from pension and postretirement plans, net of tax of $2,754, $943, $(1,459) and $2,228, respectively		5,114			1,752			(2,709	)		4,138
Net unrealized losses on energy derivative instruments during the period, net of tax of $(90,975), $(5,752), $(4,808) and $(11,303), respectively		(168,954	)		(10,683	)		(8,930	)		(20,992	)
Reversal of net unrealized gains (losses) on energy derivative instruments settled during the period, net of tax of $(13,158), $2,488, $(14,003) and $3,556, respectively		(24,436	)		4,620			(26,005	)		6,604
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 loss		(188,197	)		(4,232	)		(37,406	)		(10,012	)
Comprehensive income (loss)	$	(195,473	)	$	7,814		$	75,332		$	119,169

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

ASSETS

	September 30, 2008 (Unaudited)			December 31, 2007
Utility plant: (at original cost, including construction work in progress of $309,247 and $267,595, respectively)
Electric plant	$	6,225,756		$	5,914,127
Gas plant		2,436,155			2,313,477
Common plant		529,666			506,211
Less:  Accumulated depreciation and amortization		(3,319,165	)		(3,091,176	)
Net utility plant		5,872,412			5,642,639
Other property and investments:
Investment in Bonneville Exchange Power contract		30,858			33,503
Other property and investments		109,179			114,083
Total other property and investments		140,037			147,586
Current assets:
Cash		157,873			40,773
Restricted cash		18,957			798
Accounts receivable, net of allowance for doubtful accounts		42,416			219,345
Secured pledged accounts receivable		171,000			152,000
Unbilled revenues		109,466			210,025
Materials and supplies, at average cost		60,035			62,114
Fuel and gas inventory, at average cost		132,471			99,772
Unrealized gain on derivative instruments		15,831			17,130
Prepaid income taxes		26,994			41,814
Prepaid expenses and other		29,890			11,365
Deferred income taxes		3,049			4,011
Total current assets		767,982			859,147
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes		94,747			104,928
Regulatory asset for PURPA buyout costs		117,906			140,520
Power cost adjustment mechanism		2,018			3,114
Other regulatory assets		617,175			512,103
Unrealized gain on derivative instruments		6,391			11,845
Other		156,293			170,328
Total other long-term and regulatory assets		994,530			942,838
Total assets	$	7,774,961		$	7,592,210

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

CAPITALIZATION AND LIABILITIES

	September 30, 2008 (Unaudited)			December 31, 2007
Capitalization:
Common shareholder’s investment:
Common stock ($10 stated value) - 150,000,000 shares authorized, 85,903,791 shares outstanding	$	859,038		$	859,038
Additional paid-in capital		1,295,323			1,297,076
Earnings reinvested in the business		339,368			345,899
Accumulated other comprehensive income (loss), net of tax		(43,748	)		2,078
Total shareholder’s equity		2,449,981			2,504,091
Redeemable securities and long-term debt:
Preferred stock subject to mandatory redemption		1,889			1,889
Junior subordinated notes		250,000			250,000
Long-term debt		2,278,860			2,428,860
Total redeemable securities and long-term debt		2,530,749			2,680,749
Total capitalization		4,980,730			5,184,840
Current liabilities:
Accounts payable		229,771			310,083
Short-term debt		581,485			260,486
Short-term note owed to Puget Energy		24,728			15,766
Current maturities of long-term debt		150,000			179,500
Accrued expenses:
Purchased gas liability		16,191			77,864
Taxes		58,816			84,756
Salaries and wages		29,500			28,516
Interest		58,029			45,209
Unrealized loss on derivative instruments		146,675			27,089
Other		67,443			48,918
Total current liabilities		1,362,638			1,078,187
Long-term liabilities and regulatory liabilities:
Deferred income taxes		853,647			821,382
Unrealized loss on derivative instruments		64,235			--
Regulatory liabilities		211,872			210,372
Other deferred credits		301,839			297,429
Total long-term liabilities and regulatory liabilities		1,431,593			1,329,183
Total capitalization and liabilities	$	7,774,961		$	7,592,210

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,
	2008			2007
Operating activities:
Net income	$	112,738		$	129,181
Adjustments to reconcile net income to net cash provided by operating    activities:
Depreciation and amortization		229,366			204,351
Conservation amortization		42,723			27,608
Deferred income taxes and tax credits, net		69,182			38,216
Power cost adjustment mechanism		1,096			11,198
Goldendale deferred costs		(883	)		(11,211	)
Amortization of gas pipeline capacity assignment		(6,869	)		(8,169	)
Non cash return on regulatory assets		(7,427	)		(7,676	)
Net unrealized loss on derivative instruments		1,240			1,031
Change in residential exchange program		32,303			(27,205	)
Storm damage deferred costs		(252	)		(16,460	)
Other		28,325			8,118
Cash receipt from lease purchase option settlement		--			18,898
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue		258,487			215,142
Materials and supplies		2,078			(17,698	)
Fuel and gas inventory		(32,699	)		(1,045	)
Prepaid income taxes		14,820			13,122
Prepayments and other		(18,525	)		(50,774	)
Purchased gas receivable/payable		(61,673	)		100,980
Accounts payable		(76,727	)		(134,503	)
Taxes payable		(25,940	)		5,378
Accrued expenses and other		9,236			(6,340	)
Net cash provided by operating activities		570,599			492,142
Investing activities:
Construction expenditures - excluding equity AFUDC		(424,280	)		(548,043	)
Energy efficiency expenditures		(43,730	)		(30,054	)
Restricted cash		(18,159	)		(3	)
Refundable cash received for customer construction projects		8,806			16,950
Cash proceeds from property sales		2,221			5,747
Other		(13,783	)		(340	)
Net cash used by investing activities		(488,925	)		(555,743	)
Financing activities:
Change in short-term debt, net		320,999			49,984
Dividends paid		(113,421	)		(79,136	)
Loan from/to Puget Energy		8,962			(21	)
Long term bond issued		--			250,000
Redemption of trust preferred stock		--			(37,750	)
Redemption of bonds and notes		(179,500	)		(125,000	)
Investment from Puget Energy		--			3,684
Issuance and redemption cost of bonds and other		(1,614	)		3,425
Net cash provided by financing activities		35,426			65,186
Net increase in cash from net income		117,100			1,585
Cash at beginning of year		40,773			28,092
Cash at end of period	$	157,873		$	29,677
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	132,290		$	128,755
Cash payments (refunds) from income taxes		(39,730	)		23,000

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 a 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.

The 2008 and 2007 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.

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 condensed 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 Report on Form 10-K for the year ended December 31, 2007.

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 revenues 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 of $42.4 million and $172.3 million for the three and nine months ended September 30, 2008, respectively, and $40.5 million and $163.4 million for the three and nine months ended September 30, 2007, respectively.  The Company’s policy is to report such taxes on a gross basis in operating revenues and taxes other than income taxes in the accompanying consolidated statements of income.

(2)   Earnings per Common Share (Puget Energy Only)

Puget Energy’s basic earnings per common share have been computed based on weighted-average common shares outstanding of 129,447,000 and 129,433,000 for the three and nine months ended September 30, 2008, respectively, and 116,821,000 and 116,650,000 for the three and nine months ended September 30, 2007, respectively.

Puget Energy’s diluted earnings per common share have been computed based on weighted-average common shares outstanding and issuable upon exercise of options or expiration of vesting periods of 130,045,000 and 129,924,000 for the three and nine months ended September 30, 2008, respectively, and 117,365,000 and 117,225,000 for the three and nine months ended September 30, 2007, respectively.  These shares include the dilutive effect of securities related to employee and director equity plans.

(3)   Accounting for Derivative Instruments and Hedging Activities

Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133), as amended, requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair value.  The Company enters into contracts to manage its energy resource portfolio and interest rate exposure including forward physical and financial contracts, option contracts and swaps.  The majority of these contracts qualify for the normal purchase normal sale (NPNS) exception to derivative accounting rules provided they meet certain criteria.  Generally, NPNS applies if PSE deems the counterparty creditworthy, if the counterparty owns or controls energy resources within the western region to allow for physical delivery of the energy and if the transaction is within PSE’s forecasted load requirements as adjusted from time to time.  Those contracts that do not meet the NPNS exception or cash flow hedge criteria are marked-to-market to current earnings in the income statement, subject to deferral under SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71), for energy related derivatives due to the Power Cost Adjustment (PCA) mechanism and Purchased Gas Adjustment (PGA) mechanism.

The nature of serving regulated electric customers with its portfolio of owned and contracted electric generation resources exposes the Company and its customers to some volumetric and commodity price risks within the sharing mechanism of the PCA.  The Company’s energy risk portfolio management function monitors and manages these risks using analytical models and tools.  The Company is not engaged in the business of assuming risk for the purpose of realizing speculative trading revenues.  Therefore, wholesale market transactions are focused on balancing the Company’s energy portfolio, reducing costs and risks where feasible and reducing volatility in wholesale costs and margin in the portfolio.  In order to manage risks effectively, the Company enters into physical and financial transactions which are appropriate for the service territory of the Company and are relevant to its regulated electric and gas portfolios.

The following table presents the fair value of electric derivatives that are designated as cash flow hedges or contracts that do not meet the NPNS exception at September 30, 2008 and December 31, 2007:

	Electric Derivatives
(Dollars in Millions)	September 30, 2008		December 31, 2007
Short-term asset	$	2.9	$	11.1
Long-term asset		2.6		6.6
Total assets	$	5.5	$	17.7
Short-term liability	$	34.6	$	9.8
Long-term liability		26.9		--
Total liabilities	$	61.5	$	9.8

If it is determined that it is uneconomical to operate Company-controlled electric generating facilities in the future period, the fuel supply cash flow hedge relationship is terminated and the hedge is de-designated which results in the unrealized gains and losses associated with the contracts being recorded in the income statement.  As these contracts are settled, the costs are recognized as energy costs and are included as part of the PCA mechanism.

At December 31, 2007, the Company had an unrealized day one loss deferral of $9.0 million related to a three-year locational power exchange contract which was computed based on a company model and therefore, the day one loss was deferred under Emerging Issues Task Force (EITF) Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (EITF No. 02-3).  The contract has economic benefit to the Company over its terms.  The locational exchange will help ease electric transmission congestion across the Cascade Mountains during the winter months as PSE will take delivery of energy at a location that interconnects with PSE’s transmission system in western Washington.  At the same time, PSE will make available the quantities of power at the Mid-Columbia trading hub location.  The day one loss deferral was transferred to retained earnings on January 1, 2008 as required by SFAS No. 157, “Fair Value Measurements” (SFAS No. 157) and any future day one loss on contracts will be recorded in the income statement beginning January 1, 2008 in accordance with the statement.

The following tables present the impact of changes in the market value of derivative instruments not meeting the NPNS or cash flow hedge criteria, and ineffectiveness related to highly effective cash flow hedges, to the Company’s earnings during the three and nine months ended September 30, 2008 and September 30, 2007:

(Dollars in Millions) Three Months Ended September 30,	2008	2007	Change
Decrease in earnings	$ (3.5)	$ (5.3)	$1.8

(Dollars in Millions) Nine Months Ended September 30,	2008	2007	Change
Decrease in earnings	$(1.2)	$ (1.0)	$ (0.2)

The amount of net unrealized loss, net of tax, related to the Company’s cash flow hedges under SFAS No. 133 consisted of the following at September 30, 2008 and December 31, 2007:

(Dollars in Millions, net of tax)	September 30, 2008	December 31, 2007
Other comprehensive income – unrealized loss	$  (31.5)	$  (3.4)

The following table presents the fair value of derivative hedges of natural gas contracts to serve natural gas customers at September 30, 2008 and December 31, 2007:

	Gas Derivatives
(Dollars in Millions)	September 30, 2008		December 31, 2007
Short-term asset	$	12.9	$	6.0
Long-term asset		3.8		5.3
Total assets	$	16.7	$	11.3
Short-term liability	$	112.1	$	17.3
Long-term liability		37.3		--
Total liabilities	$	149.4	$	17.3

At September 30, 2008, the Company had total assets of $16.7 million and total liabilities of $149.4 million related to hedges of natural gas contracts to serve natural gas customers.  All mark-to-market adjustments relating to the natural gas business have been reclassified to a deferred account in accordance with SFAS No. 71 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.

(4)   Fair Value Measurements

As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).  However, as permitted under SFAS No. 157, the Company utilizes a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical expedient for valuing the majority of its assets and liabilities measured and reported at fair value.  The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique.  These inputs can be readily observable, market corroborated or generally unobservable.  The Company primarily applies the market approach for recurring fair value measurements and endeavors to utilize the best available information.  Accordingly, the Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.

The Company values derivative instruments based on daily quoted prices from an independent external pricing service.  When external quoted market prices are not available for derivative contracts, PSE uses a valuation model that uses volatility assumptions relating to future energy prices based on specific energy markets and utilizes externally available forward market price curves.  All derivative instruments are sensitive to market price fluctuations that can occur on a daily basis.  The Company is focused on commodity price exposure and risks associated with volumetric variability in the natural gas and electric portfolios.  It is not engaged in the business of assuming risk for the purpose of speculative trading.  The Company hedges open natural gas and electric positions to reduce both the portfolio risk and the volatility risk in prices.  The exposure position is determined by using a probabilistic risk system that models 100 scenarios of how the Company’s natural gas and power portfolios will perform under various weather, hydro and unit performance conditions.  PSE has not made any material changes during the reporting period to those techniques or models.

The Company is able to classify fair value balances based on the observability of those inputs.  SFAS No. 157 establishes 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 SFAS No. 157 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 marketplace.  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, the Company performs an analysis of all instruments subject to SFAS No. 157 and includes in Level 3 all of those whose fair value is based on significant unobservable inputs.

The following table sets 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 as of September 30, 2008.  As required by SFAS No. 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.  The determination of the fair values incorporates various factors required under SFAS No. 157.  These factors include not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), but also the impact of the Company’s nonperformance risk on its liabilities.

Recurring Fair Value Measures	At Fair Value as of September 30, 2008
(Dollars in Millions)	Level 1	Level 2	Level 3	Total
Assets:
Energy derivative instruments	$         --	$   21.2	$    1.0	$   22.2
Credit reserves on energy derivative instruments	--	--	--	--
Money market accounts	119.7	--	1.4	121.1
Total assets	$   119.7	$   21.2	$  2.4	$ 143.3
Liabilities:
Energy derivative instruments	$         --	$ 175.2	$  39.0	$ 214.2
Credit reserves on energy derivative instruments	--	(2.5)	(0.8)	(3.3)
Total liabilities	$         --	$ 172.7	$  38.2	$ 210.9

The following table sets forth a reconciliation of changes in the fair value of derivatives classified as Level 3 in the fair value hierarchy:

(Dollars in Millions)	Three Months Ended September 30, 2008			Nine Months Ended September 30, 2008
Balance at beginning of period  (net credit reserve on energy derivatives)	$	148.8		$	(6.1	)
Changes during period (reported gross credit reserve):
Realized energy derivatives		1.0			(0.7	)
Unrealized energy derivatives
- included in earnings		1.5			(1.5	)
- included in other comprehensive income		(93.9	)		(21.6	)
- included in regulatory assets/liabilities		(11.3	)		(10.8	)
Energy derivatives transferred in/out of Level 3		(41.8	)		(1.8	)
Terminations		(41.4	)		(1.5	)
Other financial items settled		--			7.2
Money market accounts		--			0.2
Credit reserve		1.3			0.8
Balance as of September 30, 2008 (net credit reserve on energy derivatives)	$	(35.8	)	$	(35.8	)

The Company believes energy derivative instruments classified as Level 3 should take into account items that are generally economically hedged as a portfolio with instruments that may be classified in Levels 1 and 2.  Realized gains and losses on energy derivatives for Level 3 recurring items are included in Energy Costs in the Company's income statement under purchased electricity, electric generation fuel or purchased gas when settled.

Unrealized gains and losses for Level 3 on energy derivatives recurring items are included in net unrealized (gain) loss on derivative instruments in the Company's income statement and other comprehensive income.  SFAS No. 157 requires that financial assets and liabilities be classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  As of September 30, 2008, energy derivative instruments are classified in Level 3 because Level 3 inputs are significant to their fair value measurement; however, the valuation of these derivative instruments is primarily based upon observable inputs (Level 2).  The net unrealized lossrecognized during the reporting period is primarily due to a significant decrease in market prices.

Energy derivatives transferred out of Level 3 represent existing assets or liabilities that were either previously classified as Level 3 for which the lowest significant input became observable during the period.

As a result of the recent credit crisis, the FASB recently issued FSP FAS No. 157-3, “Determining the Fair Value of a Financial Asset in a Market That is Not Active.”  This FSP clarifies the application of SFAS No. 157 in a market that is not active.  As of September 30, 2008, the Company considers the markets for its electric and natural gas 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 broker 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 Company has concluded that markets are liquid and there was no impact to the Company’s regular practice of classifying fair value measurements summarized within the SFAS No. 157 hierarchy for the third quarter 2008.

The Company does not believe that the fair values diverge materially from the amounts the Company currently anticipates realizing on settlement or maturity.

(5)   Retirement Benefits

The Company has a defined benefit pension plan covering substantially all PSE employees, with a cash balance feature for all but International Brotherhood of Electrical Workers employees.  Benefits are a function of age, salary and service.  Puget Energy also maintains a non-qualified supplemental retirement plan for officers and certain director-level employees. 

The following table summarizes the net periodic benefit cost for the three months ended September 30:

	Pension Benefits						Other Benefits
(Dollars in Thousands)	2008			2007			2008			2007
Service cost	$	3,421		$	3,328		$	28		$	33
Interest cost		7,205			6,628			296			204
Expected return on plan assets		(10,391	)		(9,715	)		(197	)		(210	)
Amortization of prior service cost		315			510			21			43
Recognized net actuarial (gain) loss		419			1,297			(177	)		(493	)
Amortization of transition obligation		--			--			13			12
Net periodic benefit cost	$	969		$	2,048		$	(16	)	$	(411	)

The following table summarizes the net periodic benefit cost for the nine months ended September 30:

	Pension Benefits						Other Benefits
(Dollars in Thousands)	2008			2007			2008			2007
Service cost	$	10,264		$	9,983		$	115		$	216
Interest cost		21,614			19,884			862			962
Expected return on plan assets		(31,172	)		(29,144	)		(592	)		(620	)
Amortization of prior service cost		946			1,532			63			310
Recognized net actuarial (gain) loss		1,257			3,890			(575	)		(605	)
Amortization of transition obligation		--			--			38			222
Net periodic benefit cost	$	2,909		$	6,145		$	(89	)	$	485

The Company previously disclosed in its financial statements for the year ended December 31, 2007 that it expected to pay benefits of $4.0 million and make a contribution of less than $0.1 million to the non-qualified pension and other benefits plans for the year ending December 31, 2008, respectively.  During the three and nine months ended September 30, 2008, payments of benefits related to the Company’s non-qualified pension plans were $0.4 million and $0.9 million, respectively.  Based on this activity, the Company anticipates paying additional benefits of $2.9 million for the Company’s non-qualified pension plan during the fourth quarter 2008.

During the three and nine months ended September 30, 2008, actual other post-retirement medical benefit plan contributions were less than $0.1 million, respectively, and the Company does not expect to make additional contributions during the fourth quarter 2008. 

The Company’s qualified pension plan includes investments that are invested by professional managers in a diversified portfolio of equity, fixed income securities and short-term investments.  During the three months ended September 30, 2008, the Company made a one time pension plan contribution in the amount of $0.4 million to the qualified retirement plan.  The qualified pension plan was also amended during the same time period to approve an ad hoc monthly benefit increase for plan participants receiving current benefits and who retired and commenced receiving benefits prior to January 1, 1999 which resulted in a prior service cost adjustment of $5.3 million to the benefit obligation.  During September 2008 and subsequent to the close at September 30, 2008, equity market conditions have been unpredictable and extremely volatile.  The qualified pension plan assets declined by more than 13.0% during the third quarter 2008 and as a result, PSE is evaluating if a qualified pension plan contribution will be made in the fourth quarter 2008.  Management will continue to monitor conditions, plan assets and obligations.

(6)   Regulation and Rates

On October 8, 2008, the Washington Utilities and Transportation Commission (Washington Commission) issued its order in PSE’s consolidated electric and natural gas general rate case filed in December 2007, approving a general rate increase for electric customers of $130.2 million or 7.1% annually, and an increase in natural gas rates of $49.2 million or 4.6% annually.  The rate increases for electric and natural gas customers were effective November 1, 2008.  In its order, the Washington Commission approved a weighted cost of capital of 8.25% and a capital structure that included 46.0% common equity with a return on equity of 10.15%.  The Washington Commission will determine by a separate order certain contested issues related to the Power Cost Only Rate Case (PCORC) mechanism.

On September 25, 2008, the Washington Commission approved PSE’s requested revisions to its purchased gas adjustment (PGA) tariff schedules resulting in an increase of $108.8 million or 11.1% on an annual basis in gas sales revenues effective October 1, 2008.  The rate increase was the result of higher costs of natural gas in the forward market and a reduction of the credit for the accumulated PGA payable balance.  The PGA rate change will increase PSE’s revenue but will not impact the Company’s net income as the increased revenue will be offset by increased purchased gas costs.

On April 11, 2007, the Washington Commission issued an accounting order that authorized PSE to defer certain ownership and operating costs (and associated carrying costs) related to its purchase of the Goldendale electric generating facility (Goldendale) during the period prior to inclusion in PSE’s retail electric rates in the PCORC.  The deferral was for the time period from March 15, 2007 through September 1, 2007, at which time the Company began recovering Goldendale ownership and operation costs in electric rates.  As of September 30, 2008, PSE had established a regulatory asset of $12.4 million.  PSE began amortization of the costs on November 1, 2008 over a three year period as determined in PSE’s electric general rate case.

In March 2008, Bonneville Power Administration (BPA) and PSE signed an agreement pursuant to which BPA (on April 2, 2008) paid PSE $53.7 million in Residential Exchange Program (REP) benefits for fiscal year ending September 30, 2008, which payment is subject to true-up depending upon the amount of any REP benefits ultimately determined to be payable to PSE.  In April 2008, the Washington Commission approved PSE’s tariff filing seeking to pass-through the net amount of the benefits under the interim agreements to residential and small farm customers.  The Washington Commission also approved PSE’s request to credit the regulatory asset amount of $33.7 million against the $53.7 million payment and pass-through to customers the remaining amount of approximately $20.0 million, which occurred during the second quarter 2008.  These amounts did not affect PSE’s net income.  PSE began amortization of the accrued carrying charges on the regulatory asset totaling $3.1 million at September 30, 2008 on November 1, 2008 over a two year period as determined in PSE’s electric general rate case.  On October 8, 2008, the Washington Commission approved PSE’s tariff request to resume the REP pass-through credits to residential electric customers. The result is a 9.9% reduction to residential electric customers bill without an impact on earnings.

In November 2007, the Western Electricity Coordinating Council (WECC) audited PSE’s compliance with electric reliability standards adopted by Federal Energy Regulatory Commission (FERC), the North American Electric Reliability Corporation (NERC) and/or WECC.  Compliance with these standards includes periodic self-certifications of compliance, self-reports of violations after discovery of the violation, spot checks to review self-certifications and external audits that review compliance with designated standards in detail.  The WECC audit team identified four potential violations of the standards that PSE had not previously self-reported.  Several months after the audit, WECC issued a “Notice of Alleged Violations” to PSE, adding details and proposed penalties to the proposed findings.  Under the rules for the process, PSE met with WECC representatives in July 2008 to discuss settlement.  PSE believes that all issues concerning the four potential violations will be resolved.  Resolution of reliability standards issues will be an ongoing concern; however, PSE self-reports violations when they are discovered.  Such self-reports could result in settlement of issues or issuances of penalties in the future.  PSE has established a loss reserve of $0.6 million related to these alleged violations.

On October 17, 2008, FERC issued a new license for the Baker River hydroelectric project for a 50-year term.  The new license incorporates the measures proposed in the comprehensive Settlement Agreement that was filed on November 30, 2004 and signed by PSE and 23 parties (federal, state and local governmental organizations, Native American Indian tribes, environmental and other non-governmental entities).  The new license will require an investment of approximately $360.0 million (capital expenditures and operations and maintenance cost) over 30 years in order to implement the license conditions.  The license provides protection and enhancements for fish and wildlife, water quality, recreation and cultural and historic resources.  Parties may seek rehearing of the order issuing the new license within 30 days of license issuance.

On December 18, 2007, PSE received a data request from the Investigations Division of the Office of Enforcement at FERC seeking information about certain natural gas pipeline capacity release transactions PSE entered into in 2005 and 2006.  PSE responded to the data requests on January 23, 2008 and met with FERC staff on January 31, 2008.  At this meeting, PSE discussed with FERC staff additional transactions discovered in the course of responding to the data requests that potentially may be in violation of FERC regulations.  PSE received additional data requests from FERC on February 20, 2008.  In October 2008, PSE received preliminary notification from FERC staff that PSE had violated several FERC regulations and was subject to potential civil penalties and other remedies.  FERC has not yet issued a formal investigation report and thus, PSE is not able to predict the ultimate outcome of this investigation, including the amount of any penalties, at this time.

(7)   Litigation

Residential Exchange.  Petitioners in several actions in the United States Court of Appeals for the Ninth Circuit (Ninth Circuit) against BPA asserted that BPA acted contrary to law in entering into or performing or implementing a number of agreements, including the amended settlement agreement (and the May 2004 agreement) between BPA and PSE regarding the REP.  Petitioners in several actions in the Ninth Circuit against BPA also asserted that BPA acted contrary to law in adopting or implementing the rates upon which the benefits received or to be received from BPA during the October 1, 2001 through September 30, 2006 period were based.  A number of parties claimed that the BPA rates proposed or adopted in the BPA rate proceeding to develop BPA rates to be used in the agreements for determining the amounts of money to be paid to PSE by BPA during the period October 1, 2006 through September 30, 2009 are contrary to law and that BPA acted contrary to law or without authority in deciding to enter into, or in entering into or performing or implementing such agreements.

On May 3, 2007, the Ninth Circuit issued an opinion in Portland Gen. Elec. v. BPA, No. 01-70003, in which proceeding the actions of BPA in entering into settlement agreements regarding the REP with PSE and with other investor-owned utilities were challenged.  In this opinion, the Ninth Circuit granted petitions for review and held the settlement agreements entered into between BPA and the investor-owned utilities being challenged in that proceeding to be inconsistent with statute.  On May 3, 2007, the Ninth Circuit also issued an opinion in Golden Northwest Aluminum v. BPA, No. 03-73426, in which proceeding the petitioners sought review of BPA’s 2002-2006 power rates.  In this opinion, the Ninth Circuit granted petitions for review and held that BPA unlawfully shifted onto its preference customers the costs of its settlements with the investor-owned utilities.  On October 5, 2007, petitions for rehearing of these two opinions were denied.  On February 1, 2008, PSE and other utilities filed in the Supreme Court of the United States a petition for a writ of certiorari to review the decisions of the Ninth Circuit, which petition was denied in June 2008.

In May 2007, following the Ninth Circuit’s issuance of these two opinions, BPA suspended payments to PSE under the amended settlement agreement (and the May 2004 agreement).  On October 11, 2007, the Ninth Circuit remanded the May 2004 agreement to BPA in light of the Portland Gen. Elec. v. BPA opinion and dismissed the remaining three pending cases regarding settlement agreements.

In March 2008, BPA and PSE signed an agreement pursuant to which BPA made a payment to PSE related to the REP benefits for the fiscal year ending September 30, 2008, which payment is subject to true-up depending upon the amount of any REP benefits ultimately determined to be payable to PSE.  This BPA's authority to enter into, and the validity of, this agreement and similar agreements with other utilities is being challenged by several BPA customers in the Ninth Circuit Court of Appeals.  In March and April 2008, Clatskanie People’s Utility District (PUD) filed petitions in the Ninth Circuit for review of BPA actions in connection with offering or entering into such agreement with PSE and similar agreements with other investor-owned utilities.  Clatskanie PUD asserts that BPA’s actions in entering into and executing the 2008 REP agreements were contrary to law or without authority and that such agreements are null and void and result in overpayments of REP benefits to PSE and other regional investor-owned utilities.

In September 2008, BPA issued its record of decision in its reopened WP-07 rate proceeding to respond to the various Ninth Circuit opinions.  In the record of decision, BPA adjusted its fiscal year 2009 rates, determined the amounts of REP benefits it considered to have been improperly paid after fiscal year 2001 to PSE and the other regional investor-owned utilities and determined that such amounts are to be recovered through reductions in REP benefit payments to be made over a number of years.  The amount to be recovered (with interest) through reductions in REP payments for PSE’s residential and small farm customers is approximately $207.2 million to the extent that PSE receives any REP benefits in the future.  However, this BPA determination is subject to subsequent administrative and judicial review which may alter or reverse such determination.  PSE is also reviewing its options in determining if it will contest the amounts withheld as improper payments made after 2001.

In September 2008, BPA and PSE signed a Residential Purchase and Sale Agreement (RPSA) under which BPA is to pay REP benefits to PSE for fiscal years ending September 30, 2009–2011.  Generally, REP benefit payments under a RPSA are based on the amount, if any, by which a utility’s average system cost (ASC) exceeds BPA’s Preference Rate (PF) Exchange rate for such utility.  The ASC for a utility is determined using an ASC methodology adopted by BPA.  The ASC methodology adopted by BPA and the ASC determinations, REP overpayment determinations and the PF Exchange rate determinations by BPA are all subject to FERC review or judicial review or both and are subject to adjustment, which may affect the amount of REP benefits paid or to be paid by BPA to PSE.  As discussed above, BPA has determined to reduce such payments based on its determination of REP benefit overpayments after fiscal year 2001.

It is not clear what impact, if any, such development or review of such BPA rates, review of such ASC, ASC Methodology, BPA determination of REP overpayments, review of such agreements and the above described Ninth Circuit litigation may ultimately have on PSE.

Colstrip Matters.  In May 2003, approximately 50 plaintiffs initiated an action against the owners of Colstrip 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 the amount of $10.7 million in July 2008.  PSE had previously expensed the settlement in the first quarter 2008.  PSE has also filed an accounting petition with the Washington Commission to recover such costs in the future.

The Minerals Management Service of the United States Department of Interior (MMS) has issued a series of orders to Western Energy Company (WECO) to pay additional taxes and royalties concerning coal WECO sold to the owners of Colstrip 3 & 4, and similar orders have been issued in the administrative appellate process.  The orders assert that additional royalties are owed in connection with payments received by WECO from Colstrip 3 & 4 owners (including PSE) for the construction and operation of a conveyor system that runs several miles from the mine to Colstrip 3 & 4.  The state of Montana has also issued a demand to WECO consistent with the MMS position.  WECO has challenged these orders, and the issue has been on appeal for several years.  WECO has won some points during the appellate process that have reduced the claims; however under applicable law, to pursue the appeals, the principal in dispute cannot be paid, which causes interest to accrue.  Moreover, because the conveyor system continues to be used, the amount in dispute grows.  PSE and the other Colstrip 3 & 4 owners authorized WECO to make a settlement offer to the Montana Department of Revenue (DOR) and the MMS in connection with these claims.  Discussions with the DOR and with the MMS continue.  PSE has recorded a $1.7 million pre-tax loss reserve in this matter.

Proceedings Related to the Western Power Market.  Puget Energy’s and PSE’s Annual Report on Form 10-K for the year ended December 31, 2007 includes a summary relating to the western power market proceedings.  The following discussion provides a summary of material developments during the third quarter 2008.  PSE is vigorously defending each of these cases.  Litigation is subject to numerous uncertainties and PSE is unable to predict the ultimate outcome of these matters.  Accordingly, there can be no guarantee that these proceedings, either individually or in the aggregate, will not materially and/or adversely affect PSE’s financial condition, results of operations or liquidity.

Lockyer Case.  In March and April 2008, FERC issued orders establishing procedures for the Lockyer remand.  The orders commence a seller-by-seller inquiry into the transaction reports filed by entities that sold power in California during 2000.  The inquiry is to determine if the transaction reports as filed masked the gathering of more than 20% of the market during the period by that seller.  The California parties sought rehearing on a variety of these issues.  On October 6, 2008, FERC issued a decision on the rehearing request that reaffirmed its intent to impose seller-specific remedies rather than the market-wide remedy sought by the California parties.  The rehearing decision also reconfirms the Commission’s method for determining market share, limits the scope of the proceeding and declines to defer the proceeding pending remand from the Ninth Circuit of the California Refund Proceeding and the Port of Seattle (Pacific Northwest Refund) case.  PSE believes that it will not be found to have possessed 20% of any relevant market during any relevant time.  The proceeding continues, including a settlement process before an Administrative Law Judge (ALJ).  Settlement talks among various parties continue but PSE cannot predict the ultimate outcome of any negotiations or subsequent process before FERC or the ALJ.

California Receivable and California Refund Proceeding. The California Independent System Operator (CAISO) filed status reports in this matter from time to time, but has yet to report its “who owes what to whom” calculation.

Orders to Show Cause.  On June 25, 2003, FERC issued two show cause orders pertaining to its western market investigations that commenced individual proceedings against many sellers.  One show cause order investigated 26 entities that allegedly had potential “partnerships” with Enron.  PSE was not named in that show cause order.  On January 22, 2004, FERC stated that it did not intend to proceed further against other parties.

The second show cause order named PSE (Docket No. EL03-169) and approximately 54 other entities that alleg­edly had engaged in potential “gaming” practices in the CAISO and California PX markets.  PSE and FERC staff filed a proposed settlement of all issues pending against PSE in those proceedings on August 28, 2003.  The proposed settlement, which admits no wrongdoing on the part of PSE, would result in a payment of a nominal amount to settle all claims.  FERC approved the settlement on January 22, 2004.  The California parties filed for rehearing of that order.  On March 17, 2004, PSE moved to dismiss the California parties’ rehearing request and awaits FERC action on that motion.

Pacific Northwest Refund Proceeding.  In October 2000, PSE filed a complaint at FERC (Docket No. EL01-10) against “all jurisdictional sellers” in the Pacific Northwest seeking prospective price caps consistent with any result FERC ordered for the California markets.  FERC dismissed PSE’s complaint, but PSE challenged that dismissal.  On June 19, 2001, FERC ordered price caps on energy sales throughout the West.  Various parties, including the Port of Seattle and the cities of Seattle and Tacoma, then moved to intervene in the proceeding seeking retroactive refunds for numerous transactions.  The proceeding became known as the “Pacific Northwest Refund Proceeding,” though refund claims were outside the scope of the original complaint.  On June 25, 2003, FERC terminated the proceeding on procedural, jurisdictional and equitable grounds and on November 10, 2003, FERC on rehearing, confirmed the order terminating the proceeding.  On August 24, 2007, the Ninth Circuit issued a decision concluding that FERC should have evaluated and considered evidence of market manipulation in California and its potential impact in the Pacific Northwest.  It also decided that FERC should have considered purchases made by the California Energy Resources Scheduler and/or the California Department of Water Resources in the Pacific Northwest Proceeding.  On December 17, 2007, PSE and PowerEx Corp. separately filed requests for rehearing with the Ninth Circuit of this decision.  Those requests remain pending.  PSE intends to vigorously defend its position in this proceeding, but it is unable to predict the outcome of this matter.

Proceeding Relating to the Proposed Merger.  On February 6, 2008, the Company entered into a memorandum of understanding providing for the settlement of the consolidated shareholder lawsuit, subject to customary conditions including completion of appropriate settlement documentation, confirmatory discovery and court approval.  Pursuant to the memorandum of understanding, the Company agreed to include certain additional disclosures in its proxy statement relating to the merger.  The Company does not admit, however, that its prior disclosures were in any way materially misleading or inadequate.  In addition, the Company and the other defendants in the consolidated lawsuit deny the plaintiffs’ allegations of wrongdoing and violation of law in connection with the merger.  The settlement, if completed and approved by the court, will result in dismissal with prejudice and release of all claims of the plaintiffs and settlement class of the Company’s shareholders that were or could have been brought on behalf of the plaintiffs and the settlement class.  In connection with such settlement, the plaintiffs intend to seek a court-approved award of attorneys’ fees and expenses in an amount up to $290,000, which the Company has agreed to pay.  As of September 30, 2008, the Company has a loss reserve of $290,000 related to this matter.

Snoqualmie Falls project.  The Snoqualmie Falls project was granted a new 40-year operating license by FERC on June 29, 2004.  The Snoqualmie Tribe asked for rehearing of the order and requested a stay of the new license.  On March 1, 2005, FERC issued an Order on Rehearing and Dismissing Stay Request.  The order required additional flows at Snoqualmie Falls during certain times of the year, but otherwise denied the Snoqualmie Tribe’s request.  The Snoqualmie Tribe sought further review by the U.S. Court of Appeals arguing, among other issues, that FERC violated the Religious Freedom Restoration Act (RFRA) and that the license decision substantially burdened the Snoqualmie Tribe’s free exercise of religion.  PSE also sought review of FERC’s decision to require additional flows during certain times of the year because the action appeared to interfere with the Washington State Department of Ecology’s jurisdiction to determine water quality issues.  On October 7, 2008, the court issued a decision denying the appeals and determined that FERC did not violate RFRA and that FERC’s adoption of water flows greater than those prescribed in the water quality certification did not contradict or weaken the water quality certification’s minimum flow requirements.  Parties may seek review of the decision by the United States Supreme Court.  Such review is discretionary and PSE is unable to determine whether the Supreme Court will elect to review the matter if further review is sought.  In addition, on December 6, 2007, PSE filed an application for a non-capacity amendment to the 2004 license.  The application seeks to amend the license to account for technology improvements and hydrologic and other changes that occurred post-license.  The license amendment application remains pending and its ultimate outcome remains uncertain.

(8)   Related Party Transactions

On June 1, 2006, PSE entered into a revolving credit facility with its parent, Puget Energy, in the form of a Demand Promissory Note (Note).  Through the 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; (b) PSE’s senior unsecured revolving credit facility; or (c) the interest rate available under the receivable securitization facility of PSE Funding, Inc. (PSE Funding), a PSE subsidiary, which is the London Interbank Offered Rate (LIBOR) plus a marginal rate.  At September 30, 2008 and December 31, 2007, the outstanding balance of the Note was $24.7 million and $15.8 million, respectively and the interest rate was 3.05% and 5.31% respectively.  The outstanding balance and the related interest under the Note are eliminated by Puget Energy upon consolidation of PSE’s financial statements.  The $30.0 million credit facility with Puget Energy is unaffected by the pending merger.

The Company has a general liability claim from AEGIS Insurance Services Inc. (AEGIS) for $7.0 million as of September 30, 2008.  One nonemployee director of Puget Energy and PSE also serves on the board of AEGIS and a PSE management employee serves on one of AEGIS’ risk management committees.

 PSE has property insurance with various companies and approximately 35% of the property insurance coverage is with American International Group, Inc (AIG).  On October 23, 2008, AIG named the wife of Puget Energy’s and PSE’s Chairman, President and Chief Executive as its Vice Chairman and Chief Restructuring Officer.

(9)   Other

Financial Accounting Standards Board (FASB) Interpretation No. 46R, “Consolidation of Variable Interest Entities” (FIN 46R) requires that if a business entity has a controlling financial interest in a variable interest entity, the financial statements of the variable interest entity must be included in the consolidated financial statements of the business entity.  The Company has evaluated its power purchase agreements and determined that two counterparties during the nine months ended September 30, 2008 may be considered variable interest entities.  Consistent with FIN 46R, PSE submitted requests for information to those two entities; however, the entities have refused to submit to PSE the necessary information for PSE to determine whether they meet the requirements of a variable interest entity.  PSE also determined that it does not have a contractual right to such information.  PSE will continue to submit requests for information to the counterparties in accordance with FIN 46R.

For the two power purchase agreements that may be considered variable interest entities under FIN 46R as of the third quarter 2008, PSE is required to buy all the generation from these plants, subject to displacement by PSE, at rates set forth in the power purchase agreements.  If at any time the counterparties cannot deliver energy to PSE, PSE would have to buy energy in the wholesale market at prices which could be higher or lower than the power purchase agreement prices.  PSE’s purchased electricity expense for the three months ended September 30, 2008 and 2007 was $55.9 million and $60.0 million, respectively, and for the nine months ended September 30, 2008, and 2007 was $147.7 million and $157.2 million, respectively.

In November 2006, PSE’s Crystal Mountain Generation Station had an accidental release of approximately 18,000 gallons of diesel fuel.  PSE crews and consultants responded and worked with applicable state and federal agencies to control and remove the spilled diesel.  On July 11, 2007, PSE received a Notice of Completion for work performed pursuant to the Administrative Order for Removal from the U. S. Environmental Protection Agency (EPA).  The Notice stated that PSE had met the requirements of the Order and the accompanying scope of work.  Total removal costs as of September 30, 2008 were approximately $14.5 million.  PSE estimates the total remediation cost to be approximately $15.0 million, which has been accrued or paid.  PSE received a partial insurance payment of $5.0 million on this receivable in January 2008.  At September 30, 2008, PSE had an insurance receivable recorded in the amount of $7.0 million associated with this fuel release.  PSE is in discussions with the insurance provider on the remaining outstanding balance which management believes to be collectible.

On September 25, 2008, PSE executed a purchase agreement to acquire a 310 megawatt (MW) natural gas-fired power plant, the Mint Farm project, located in Washington State, for approximately $240.0 million.  The transaction is expected to close by the end of 2008 and is subject to FERC approval.

On November 4, 2008, Election Day, there will be three measures appearing on the ballot in three Washington State counties for voter approval to form or authorize, in each case, a public utility district to pursue efforts to acquire or construct electric facilities within PSE service territory.  These ballot measures impact an aggregate of approximately 109,000 current PSE customers across the three counties.  If these ballots measures are passed, the Company believes it will take several years before any change in PSE’s service territory takes effect.

(10)   New Accounting Pronouncements

On September 15, 2006, FASB issued SFAS No. 157, which clarifies how companies should use fair value measurements in accordance with GAAP for recognition and disclosure purposes.  SFAS No. 157 establishes a common definition of fair value and a framework for measuring fair value under GAAP, along with expanding disclosures about fair value to eliminate differences in current practice that exist in measuring fair value under the existing accounting standards.  The definition of fair value in SFAS No. 157 retains the notion of exchange price; however, it focuses on the price that would be received to sell the asset or paid to transfer a liability (i.e. an exit price), rather than the price that would be paid to acquire the asset or received to assume the liability (i.e. an entrance price).  Under SFAS No. 157, a fair value measure should reflect all of the assumptions that market participants would use in pricing the asset or liability, including assumptions about the risk inherent in a particular valuation technique, the effect of a restriction on the sale or use of an asset, and the risk of nonperformance.  To increase consistency and comparability in fair value measures, SFAS No. 157 establishes a three-level fair value hierarchy to prioritize the inputs used in valuation techniques between observable inputs that reflect quoted market prices in active markets, inputs other than quoted prices with observable market data, and unobservable data (e.g. a company’s own data).

SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, which was the year beginning January 1, 2008, for the Company.  On February 28, 2008, the FASB issued a final FASB Staff Position (FSP) that partially deferred the effective date of SFAS No. 157 for one year for non-financial assets and non-financial liabilities that are recognized or disclosed at fair value, except for those that are recognized or disclosed at fair value on an annual or more frequent basis.  The Company adopted SFAS No. 157 on January 1, 2008, prospectively, as required by the Statement, with certain exceptions,  including the initial impact of changes in fair value measurements of existing derivative financial instruments measured initially using the transaction price under EITF No. 02-3.  On January 1, 2008, the difference between the carrying amounts and the fair values of those instruments originally recorded under guidance in EITF No. 02-3 was recognized as a cumulative-effect adjustment to the opening balance of retained earnings.  SFAS No. 157 nullified a portion of EITF No. 02-3.  Under EITF No. 02-3, the transaction price presumption prohibited recognition of a trading profit at inception of a derivative unless the positive fair value of that derivative was substantially based on quoted prices or a valuation process incorporating observable inputs.  For transactions that did not meet this criterion at inception, trading profits that had been deferred were recognized in the period that inputs to value the derivative became observable or when the contract performed.

As a result of the recent credit crisis, on October 10, 2008, the FASB issued FSP FAS No. 157-3, “Determining the Fair Value of a Financial Asset in a Market That is Not Active.”  This FSP clarifies the application of SFAS No. 157 “Fair Value Measurements,” in a market that is not active.  The FSP addresses how management should consider measuring fair value when relevant observable data does not exist.  The FSP also provides guidance on how observable market information in a market that is not active should be considered when measuring fair value, as well as how the use of market quotes should be considered when assessing the relevance of observable and unobservable data available to measure fair value. This FSP was effective upon issuance, including prior periods for which financial statement have not been issued.  Revisions resulting from a change in the valuation technique or its application shall be accounted for as a change in accounting estimate (FASB Statement No. 154, “Accounting Changes and Error Corrections,” (SFAS No. 154) paragraph 19).  The disclosure provisions of SFAS No. 154 for a change in accounting estimate are not required for revisions resulting from a change in valuation technique or its application.  The Company has reviewed the statement and has assessed that there will be no significant impact to the financial statements.

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (SFAS No. 141(R)).  This Statement replaces FASB Statement No. 141, “Business Combinations,” and addresses the accounting for all transactions or other events in which an entity obtains control of one or more businesses.  The objective of this Statement is to improve the relevance, representational faithfulness and comparability of the information that a reporting entity provides in its financial reports about a business combination and its effects. To accomplish that, this Statement establishes principles and requirements for how the acquirer: 1) Recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree; 2) Recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and 3) Determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination.  This Statement shall be applied prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008.  The Company is currently assessing the impact of SFAS No. 141(R).

On March 19, 2008, FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – An Amendment of FASB Statement No. 133” (SFAS No. 161).  SFAS No. 161 is effective for the fiscal years and interim years beginning after November 15, 2008, which will be the quarter ending March 31, 2009 for the Company.  SFAS No. 161 requires companies with derivative instruments to disclose information that should enable financial statement users to understand how and why a company uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS No. 133 and how derivative instruments and related hedged items affect a company’s financial position, financial performance and cash flows.  SFAS No. 161 requirements will impact the following derivative and hedging disclosures: objectives and strategies, balance sheet, financial performance, contingent features and counterparty credit risk.  The Company is currently assessing the impact of SFAS No. 161.

In May 2008, FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (SFAS No. 162), which identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles.  The FASB Board is responsible for identifying the sources of accounting principles and providing entities with a framework for selecting the principles used in the preparation of financial statements.  The Company has reviewed the statement and has assessed that there will be no significant impact to the financial statements.

On June 16, 2008, FSP EITF No. 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities,” (EITF No. 03-6-1) was issued.  This FSP addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share under the two-class method.  Unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of earnings per share pursuant to the two-class method.  This FSP will be effective for financial statements issued for fiscal years beginning after December 15, 2008, which will be the year ending December 31, 2009 for the Company.  The Company is currently assessing the financial statement presentation impact of FSP EITF No. 03-6-1.

(11)   Corporate Guarantees (Puget Energy Only)

On May 7, 2006, Puget Energy sold InfrastruX Group Inc. (InfrastruX) to an affiliate of Tenaska Power Fund, L.P. (Tenaska) in an all-cash transaction.  Puget Energy accounted for InfrastruX as a discontinued operation under SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS No. 144) in 2006.  As a part of the transaction, Puget Energy made certain representations and warrantees concerning InfrastruX and indemnified Tenaska against certain future losses not to exceed $15.0 million.  At the time of the sale, Puget Energy purchased a warrantee insurance policy and deposited $3.7 million into an escrow account, representing the full retention under the insurance policy.  Additionally at the time of sale, Puget Energy recorded a $5.0 million loss reserve in connection with the indemnifications, which represented management’s measurement of the fair value of the corporate guarantees using a probability weighted approach.

On April 29, 2008, Puget Energy and Tenaska entered into a Joint Notice of Distribution and Termination Agreement (Termination Agreement) which resulted in the extinguishment of all InfrastruX corporate guarantees made by Puget Energy which management believed involved a risk of loss in connection with the sale of InfrastruX.  In the second quarter 2008, Puget Energy made the remaining payments under the terms of the Termination Agreement totaling $7.1 million bringing total cash outlays equal to the Company’s original aggregate loss reserve amounts recorded in the second quarter of 2006.

(12)   Agreement and Plan of Merger (Puget Energy only)

On October 26, 2007, Puget Energy announced that it had entered into a definitive Agreement and Plan of Merger, dated as of October 25, 2007, pursuant to which Puget Energy will be acquired by a consortium of long-term infrastructure investors led by Macquarie Infrastructure Partners, the Canada Pension Plan Investment Board and British Columbia Investment Management Corporation and which also includes Alberta Investment Management Corporation, Macquarie-FSS Infrastructure Trust and Macquarie Capital Group (collectively, the Consortium).  At the effective time of the merger, each issued and outstanding share of common stock of Puget Energy, other than any shares in respect of which dissenter’s rights are perfected and other than any shares owned by the Consortium, shall be cancelled and shall be converted automatically into the right to receive $30.00 in cash, without interest.

The consummation of the merger is subject to the satisfaction or waiver of certain closing conditions, including the receipt of shareholder approval of the merger and approval of it by various state and federal regulatory authorities.  As of the date of this Quarterly Report, these conditions have either been satisfied or are in process.  On April 16, 2008, Puget Energy shareholders approved the merger by more than the required two-thirds vote.  Also, on April 17, 2008, FERC conditionally approved the transaction pursuant to section 203 of the Federal Power Act subject to reviewing the final conditions of merger approval by the Washington Commission.  On December 17, 2007, PSE and the Consortium filed a joint application seeking approval of the merger with the Washington Commission.

On July 22, 2008, Puget Energy, the Consortium and several parties involved in the merger proceeding reached a settlement to resolve all issues before the Washington Commission.  On July 23, 2008, the parties to the merger agreement filed a multiparty stipulated settlement with the Washington Commission.  On October 9, 2008, the Washington Commission issued a notice to all parties to the merger case that they may submit reply briefs in the proceeding.  These documents were filed on October 23, 2008.  The filing of reply briefs by the parties is expected to be the last step before a final order is issued by the Washington Commission.  If approved by the Washington Commission in the fourth quarter 2008, closing is expected to occur during the fourth quarter 2008.

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

The following discussion of the Company’s financial condition and results of operations contains forward-looking statements that involve risks and uncertainties, such as statements of the Company’s plans, objectives, expectations and intentions.  Words or phrases such as “anticipates,” “believes,” “estimates,” “expects,” “future,” “intends,” “plans,” “projects,” “predicts,” “will likely result,” and “will continue” and similar expressions are used to identify 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.  The Company’s actual results could differ materially from those anticipated in these forward-looking statements for many reasons, including the factors described below and under the caption “Forward-Looking Statements” at the beginning of this report.  Readers should not place undue reliance on these forward-looking statements, which apply only as of the date of this Form 10-Q.

Overview

Puget Energy, Inc. (Puget Energy) is an energy services holding company and all of its operations are conducted through its subsidiary Puget Sound Energy, Inc. (PSE), a regulated electric and natural gas utility company.  Puget Energy is dependent upon the results of PSE since PSE is its most significant asset.  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 earnings and cash flow by offering reliable electric and natural gas service in a cost effective manner through PSE.

Puget Energy Merger

On October 26, 2007, Puget Energy announced that it had entered into a definitive Agreement and Plan of Merger, dated as of October 25, 2007, pursuant to which Puget Energy will be acquired by a consortium of long-term infrastructure investors led by Macquarie Infrastructure Partners, the Canada Pension Plan Investment Board and British Columbia Investment Management Corporation and which also includes Alberta Investment Management Corporation, Macquarie-FSS Infrastructure Trust and Macquarie Capital Group (collectively, the Consortium).  At the effective time of the merger, each issued and outstanding share of common stock of Puget Energy, other than any shares in respect of which dissenter’s rights are perfected and other than any shares owned by the Consortium, shall be cancelled and shall be converted automatically into the right to receive $30.00 in cash, without interest.

The consummation of the merger is subject to the satisfaction or waiver of certain closing conditions, including the receipt of shareholder approval of the merger and approval of it by various state and federal regulatory authorities.  As of the date of this Quarterly Report, these conditions have either been satisfied or are in process.  On April 16, 2008, Puget Energy shareholders approved the merger.  Also, on April 17, 2008 the Federal Energy Regulatory Commission (FERC) conditionally approved the transaction pursuant to section 203 of the Federal Power Act subject to reviewing the final conditions of merger approval by the Washington Utilities and Transportation Commission (Washington Commission).  On December 17, 2007, PSE and the Consortium filed a joint application seeking approval of the merger with the Washington Commission.

On July 22, 2008, Puget Energy, the Consortium and several parties involved in the merger proceeding reached a settlement to resolve all issues before the Washington Commission.  On July 23, 2008, the parties to the merger agreement filed a multiparty stipulated settlement with the Washington Commission.  On October 9, 2008, the Washington Commission issued a notice to all parties to the merger case that they may submit reply briefs in the proceeding.  These documents were filed on October 23, 2008.  The filing of reply briefs by the parties is expected to be the last step before a final order is issued by the Washington Commission.  If approved by the Washington Commission in the fourth quarter 2008, closing is expected to occur during the fourth quarter 2008.

Puget Sound Energy

PSE generates revenues primarily from the sale of electric and natural gas services to residential and commercial customers within Washington State.  PSE’s operating revenues and associated expenses are not generated evenly throughout the year.  Variations in energy usage by consumers 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.

As a regulated utility company, PSE is subject to FERC and Washington Commission regulation which may impact a large array of business activities, including limitation of future rate increases; directed accounting requirements that may negatively impact earnings; licensing of PSE-owned generation facilities; and other FERC and Washington Commission directives that may impact PSE’s long-term goals.  In addition, PSE is subject to risks inherent to the utility industry as a whole, including weather changes affecting purchases and sales of energy; outages at owned and contracted generation plants where energy is obtained; storms or other events which can damage natural gas and electric distribution and transmission lines; increasing regulatory standards for system reliability; wholesale market stability over time; and significant evolving environmental legislation.

PSE is investing heavily in its utility infrastructure and customer service functions in order to meet increasing regulatory requirements, customer growth and aging infrastructure needs.  Such investments and operating requirements give rise to significant growth in depreciation expense and operating expense which costs are not timely recovered via the ratemaking process which relies predominately on a historic test year to fix rates and revenue requirements.  Such “regulatory lag” is expected to continue for the foreseeable future.

PSE’s main business objective is to provide reliable, safe and cost-effective energy to its customers.  To help accomplish this objective, PSE seeks to become more energy efficient and environmentally responsible in its energy supply portfolio on an ongoing basis.  PSE filed its most recent Integrated Resource Plan on May 31, 2007 with the Washington Commission.  The plan supports a strategy of significantly increasing energy efficiency programs, pursuing additional renewable resources (primarily wind) and additional base load natural gas fired generation to meet the growing needs of its customers.  On July 28, 2008, PSE announced that it had completed the purchase of the 125 megawatt (MW) Sumas cogeneration power plant.  On September 25, 2008, PSE executed a purchase agreement to acquire a 310 MW natural gas-fired power plant, the Mint Farm project, which is located in Washington State, for approximately $240.0 million.  The transaction is expected to close by the end of 2008 and is subject to FERC approval.  These acquisitions are part of PSE’s long-range initiative for meeting its customers’ steadily growing electricity needs.

Non-GAAP Financial Measures – Energy Margins

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

Results of Operations

Puget Energy

All the operations of Puget Energy are conducted through its subsidiary PSE.  Net loss for the three months ended September 30, 2008 was $8.2 million on operating revenues of $606.2 million as compared to net income of $11.4 million on operating revenues of $601.7 million for the same period in 2007.

Basic and diluted loss per share for the three months ended September 30, 2008 was $0.06 as compared to basic and diluted earnings per share for the three months ended September 30, 2007 of $0.10.  Net income for the three months ended September 30, 2008 as compared to the same period in 2007 was negatively impacted by a $4.6 million decrease in electric margin while it was positively impacted by a $2.1 million increase in gas margin.  Net income was negatively impacted by an $11.6 million increase in utility operation and maintenance and an increase in depreciation and amortization of $8.8 million. The increase in expenses was partially offset by a decrease in interest expense of $2.7 million.  In the third quarter 2008, Puget Energy incurred $1.3 million in costs related to the proposed merger with the Consortium.

For the nine months ended September 30, 2008, Puget Energy’s net income was $105.2 million on operating revenues of $2.4 billion compared to net income of $129.1 million on operating revenues of $2.3 billion for the same period in 2007.  Basic and diluted earnings per share for the nine months ended September 30, 2008 was $0.81 compared to basic and diluted earnings per share of $1.11 and $1.10, respectively, for the same period in 2007.

Net income for the nine months ended September 30, 2008 was positively impacted by increased electric and gas margins of $19.9 million and $23.1 million, respectively, compared to the same period in 2007.  Net income was negatively impacted by an increase in utility operations and maintenance of $43.1 million and a $25.0 million increase in depreciation and amortization.  The increase in expenses was partially offset by an increase in other income of $4.0 million and a decrease in interest expense of $5.7 million due to lower average debt outstanding as a result of the equity issuance in December 2007.  For the nine months ended September 30, 2008, Puget Energy incurred $8.3 million in costs related to the proposed merger with the Consortium.

Puget Sound Energy

PSE’s operating revenues and expenses are not generated evenly throughout the year.  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.  Power cost recovery is seasonal, with underrecovery normally in the first and fourth quarters when electric sales volumes and power costs are higher and overrecovery in the second and third quarters.  Varying wholesale electric prices and the amount of hydroelectric energy supplies available to PSE also make quarter to quarter comparisons difficult.

Energy Margins

The following table displays the details of electric margin changes for the three months ended September 30, 2008 as compared to the same period in 2007.  Electric margin is electric sales to retail and transportation customers less pass-through tariff items and revenue-sensitive taxes, and the cost of generating and purchasing electric energy sold to customers, including transmission costs to bring electric energy to PSE’s service territory.

	Electric Margin
(Dollars in Millions) Three Months Ended September 30,	2008			2007			Change			Percent Change
Electric operating revenue1	$	467.4		$	456.1		$	11.3			2.5	%
Less: Other electric operating revenue		(15.9	)		(3.2	)		(12.7	)		*
Add: Other electric operating revenue-gas supply resale		7.4			(6.6	)		14.0			*
Total electric revenue for margin		458.9			446.3			12.6			2.8
Adjustments for amounts included in revenue:
Pass-through tariff items		(15.1	)		(9.8	)		(5.3	)		(54.1	)
Pass-through revenue-sensitive taxes		(31.9	)		(29.5	)		(2.4	)		(8.1	)
Net electric revenue for margin		411.9			407.0			4.9			1.2
Minus power costs:
Purchased electricity1		(173.7	)		(185.8	)		12.1			6.5
Electric generation fuel1		(64.9	)		(43.5	)		(21.4	)		(49.2	)
Residential exchange1		0.2			0.4			(0.2	)		(50.0	)
Total electric power costs		(238.4	)		(228.9	)		(9.5	)		(4.2	)
Electric margin2	$	173.5		$	178.1		$	(4.6	)		(2.6	) %

____________________________

1	As reported on PSE’s Consolidated Statement of Income.
2	Electric margin does not include any allocation for amortization/depreciation expense or electric generation operation and maintenance expense.
*	Percent change not applicable or meaningful.

Electric margin decreased $4.6 million for the three months ended September 30, 2008 compared to the same period in 2007.  The decrease in electric margin was impacted by a decrease of $1.8 million in retail sales volumes and higher power supply costs driven by a reduction in hydroelectric generation and an increase in natural gas fuel prices which decreased margin by approximately $4.1 million.

The following table displays the details of electric margin changes for the nine months ended September 30, 2008 compared to the same period in 2007.  Electric margin is electric sales to retail and transportation customers less pass-through tariff items and revenue-sensitive taxes, and the cost of generating and purchasing electric energy sold to customers, including transmission costs to bring electric energy to PSE’s service territory.

	Electric Margin
(Dollars in Millions) Nine Months Ended September 30,	2008			2007			Change			Percent Change
Electric operating revenue1	$	1,551.5		$	1,419.0		$	132.5			9.3	%
Less: Other electric operating revenue		(48.4	)		(29.9	)		(18.5	)		(61.9	)
Add: Other electric revenue-gas supply resale		18.4			(0.2	)		18.6			*
Total electric revenue for margin		1,521.5			1,388.9			132.6			9.5
Adjustments for amounts included in revenue:
Pass-through tariff items		(44.2	)		(30.7	)		(13.5	)		(44.0	)
Pass-through revenue-sensitive taxes		(106.5	)		(95.3	)		(11.2	)		(11.8	)
Net electric revenue for margin		1,370.8			1,262.9			107.9			8.5
Minus power costs:
Purchased electricity1		(645.4	)		(640.6	)		(4.8	)		(0.7	)
Electric generation fuel1		(144.6	)		(93.3	)		(51.3	)		(55.0	)
Residential exchange1		20.5			52.4			(31.9	)		(60.9	)
Total electric power costs		(769.5	)		(681.5	)		(88.0	)		(12.9	)
Electric margin2	$	601.3		$	581.4		$	19.9			3.4	%

____________________________

1	As reported on PSE’s Consolidated Statement of Income.
2	Electric margin does not include any allocation for amortization/depreciation expense or electric generation operation and maintenance expense.
*	Percent change not applicable or meaningful.

Electric margin increased $19.9 million for the nine months ended September 30, 2008 compared to the same period in 2007.  This is primarily due to a 2.8% increase in retail sales volumes which increased electric margin by $15.3 million and $12.4 million related to the recovery of Goldendale electric generating facility (Goldendale) ownership and operating costs.  The increase was partially offset by higher power supply costs of approximately $9.1 million driven by a reduction in hydroelectric generation and an increase in natural gas fuel prices.

The following table displays the details of gas margin changes for the three months ended September 30, 2008 as compared to the same period in 2007.  Gas margin is natural gas sales to retail and transportation customers less pass-through tariff items and revenue-sensitive taxes, and the cost of natural gas purchased, including transportation costs to bring natural gas to PSE’s service territory.

	Gas Margin
(Dollars in Millions) Three Months Ended September 30,	2008			2007			Change			Percent Change
Gas operating revenue1	$	133.2		$	142.1		$	(8.9	)		(6.3	) %
Less: Other gas operating revenue		(4.3	)		(4.1	)		(0.2	)		(4.9	)
Total gas revenue for margin		128.9			138.0			(9.1	)		(6.6	)
Adjustments for amounts included in revenue:
Pass-through tariff items		(1.2	)		(1.1	)		(0.1	)		(9.1	)
Pass-through revenue-sensitive taxes		(10.5	)		(11.0	)		0.5			4.5
Net gas revenue for margin		117.2			125.9			(8.7	)		(6.9	)
Minus purchased gas costs1		(70.1	)		(80.9	)		10.8			13.3
Gas margin2	$	47.1		$	45.0		$	2.1			4.7	%

____________________

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

Gas margin increased $2.1 million for the three months ended September 30, 2008 as compared to the same period in 2007 primarily due to a 3.2% gas therm volume sales increase resulting in a $1.4 million increase to gas margin.  The remainder of the increase is due to a change in customer mix and other favorable pricing variances.

 The following table displays the details of gas margin changes for the nine months ended September 30, 2008 compared to the same period in 2007.  Gas margin is natural gas sales to retail and transportation customers less pass-through tariff items and revenue-sensitive taxes, and the cost of natural gas purchased, including transportation costs to bring natural gas to PSE’s service territory.

	Gas Margin
(Dollars in Millions) Nine Months Ended September 30,	2008			2007			Change			Percent Change
Gas operating revenue1	$	810.3		$	834.3		$	(24.0	)		(2.9	) %
Less: Other gas operating revenue		(13.2	)		(13.3	)		0.1			0.8
Total gas revenue for margin		797.1			821.0			(23.9	)		(2.9	)
Adjustments for amounts included in revenue:
Pass-through tariff items		(7.9	)		(6.0	)		(1.9	)		(31.7	)
Pass-through revenue-sensitive taxes		(65.8	)		(68.1	)		2.3			3.4
Net gas revenue for margin		723.4			746.9			(23.5	)		(3.1	)
Less: Purchased gas costs1		(484.0	)		(530.6	)		46.6			8.8
Gas margin2	$	239.4		$	216.3		$	23.1			10.7	%

____________________

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

Gas margin increased $23.1 million for the nine months ended September 30, 2008 compared to the same period in 2007 primarily due to an increase in margin of $20.8 million related to a 9.6% gas therm volume sales increase and a 2.8% general rate increase effective January 13, 2007 which, combined with a change in customer mix and other pricing variances, resulted in an increase to gas margin of $2.3 million.

Electric Operating Revenues

The table below sets forth changes in electric operating revenues for PSE for the three months ended September 30, 2008 as compared to the same period in 2007.

(Dollars in Millions) Three Months Ended September 30,	2008		2007		Change			Percent Change
Electric operating revenues:
Residential sales	$	199.7	$	184.2	$	15.5			8.4	%
Commercial sales		191.6		177.6		14.0			7.9
Industrial sales		25.7		25.5		0.2			0.8
Other retail sales, including unbilled revenue		4.3		17.6		(13.3	)		(75.6	)
Total retail sales		421.3		404.9		16.4			4.1
Transportation sales		2.6		2.8		(0.2	)		(7.1	)
Sales to other utilities and marketers		27.6		45.3		(17.7	)		(39.1	)
Other		15.9		3.1		12.8			*
Total electric operating revenues	$	467.4	$	456.1	$	11.3			2.5	%

____________________

* Percent change not applicable or meaningful.

Electric retail sales increased $16.4 million for the three months ended September 30, 2008 as compared to the same period in 2007.  The Power Cost Only Rate Case (PCORC) rate increase effective September 1, 2007 increased operating revenues $14.4 million for the three months ended September 30, 2008 as compared to the same period in 2007.  Retail electricity usage decreased 45,863 megawatt hours (MWh) or 1.0% compared to the same period in 2007, which resulted in a decrease of approximately $4.1 million in electric operating revenue.

Sales to other utilities and marketers decreased $17.7 million for the three months ended September 30, 2008 as compared to the same period in 2007 primarily due to a decrease in sales volume of 390,867 MWh or 44.8% as a result of decreased surplus energy due in part to lower hydroelectric generation, which resulted in a decrease of $20.3 million.  This decrease was offset by higher wholesale electric prices in the third quarter 2008 as compared to the same period in 2007, which increased sales by $2.6 million.

Other electric operating revenues increased $12.8 million for the three months ended September 30, 2008 as compared to the same period in 2007 primarily due to an increase of $14.1 million in noncore gas sales.

The table below sets forth changes in electric operating revenues for PSE for the nine months ended September 30, 2008 compared to the same period in 2007.

(Dollars in Millions) Nine Months Ended September 30,	2008			2007			Change			Percent Change
Electric operating revenues:
Residential sales	$	783.3		$	675.7		$	107.6			15.9	%
Commercial sales		593.1			550.6			42.5			7.7
Industrial sales		79.2			77.8			1.4			1.8
Other retail sales, including unbilled revenue		(28.1	)		(14.0	)		(14.1	)		(100.7	)
Total retail sales		1,427.5			1,290.1			137.4			10.7
Transportation sales		5.5			7.6			(2.1	)		(27.6	)
Sales to other utilities and marketers		70.1			91.5			(21.4	)		(23.4	)
Other		48.4			29.8			18.6			62.4
Total electric operating revenues	$	1,551.5		$	1,419.0		$	132.5			9.3	%

Electric retail sales increased $137.4 million for the nine months ended September 30, 2008 compared to the same period in 2007 due primarily to an increase in customer growth and colder average temperatures in the Pacific Northwest during the first half of 2008.  Retail electricity usage increased 436,979 MWh or 2.8% for the nine months ended September 30, 2008 compared to the same period in 2007, which resulted in an increase of approximately $38.9 million in electric operating revenue.  The increase was also related to the PCORC rate increase of September 1, 2007 offset by the electric general rate decrease of January 13, 2007 which resulted in an increase of $65.8 million.  During the nine month period ended September 30, 2008, the benefits of the Residential and Farm Energy Exchange Benefit credited to customers reduced electric operating revenues by $21.4 million compared to $54.9 million for the same period in 2007.  This credit also reduced power costs by a corresponding amount with no impact on earnings.

The following electric rate changes were approved by the Washington Commission in 2007:

Type of Rate Adjustment	Effective Date	Average Percentage Increase (Decrease) in Rates		Annual Increase (Decrease)  in Revenues (Dollars in Millions)
Electric General Rate Case	January 13, 2007	(1.3	) %	$ (22.8)
Power Cost Only Rate Case	September 1, 2007	3.7		64.7

Gas Operating Revenues

The table below sets forth changes in gas operating revenues for PSE for the three months ended September 30, 2008 as compared to the same period in 2007.

(Dollars in Millions) Three Months Ended September 30,	2008		2007		Change			Percent Change
Gas operating revenues:
Residential sales	$	71.3	$	74.7	$	(3.4	)		(4.6	) %
Commercial sales		46.3		49.3		(3.0	)		(6.1	)
Industrial sales		8.0		10.6		(2.6	)		(24.5	)
Total retail sales		125.6		134.6		(9.0	)		(6.7	)
Transportation sales		3.3		3.4		(0.1	)		(2.9	)
Other		4.3		4.1		0.2			4.9
Total gas operating revenues	$	133.2	$	142.1	$	(8.9	)		(6.3	) %

Gas retail sales decreased $9.0 million for the three months ended September 30, 2008 as compared to the same period in 2007 due to a $16.2 million reduction in gas operating revenues as a result of a 13.0% Purchased Gas Adjustment (PGA) mechanism rate decrease for retail customers effective October 1, 2007.  The PGA mechanism passes through to customers increases or decreases in the natural gas supply portion of the natural gas service rates based upon changes in the price of natural gas purchased from producers and wholesale marketers or changes in natural gas pipeline transportation costs.  PSE’s gas margin and net income are not affected by changes under the PGA mechanism.  Offsetting the decrease was a $6.9 million increase in gas therm sales of 4.5 million or 3.2% reflecting customer growth and colder average temperatures in the Pacific Northwest.

The table below sets forth changes in gas operating revenues for PSE for the nine months ended September 30, 2008 compared to the same period in 2007.

(Dollars in Millions) Nine Months Ended September 30,	2008		2007		Change			Percent Change
Gas operating revenues:
Residential sales	$	509.8	$	510.5	$	(0.7	)		(0.1	) %
Commercial sales		246.2		257.2		(11.0	)		(4.3	)
Industrial sales		30.5		43.1		(12.6	)		(29.2	)
Total retail sales		786.5		810.8		(24.3	)		(3.0	)
Transportation sales		10.6		10.2		0.4			3.9
Other		13.2		13.3		(0.1	)		(0.8	)
Total gas operating revenues	$	810.3	$	834.3	$	(24.0	)		(2.9	) %

Gas retail sales decreased $24.3 million for the nine months ended September 30, 2008 compared to the same period in 2007 due to lower PGA mechanism rates and increased customer natural gas usage.  The Washington Commission approved a PGA mechanism rate decrease effective October 1, 2007.  PSE’s gas margin and net income are not affected by changes under the PGA mechanism.  The effects of the PGA mechanism rate decrease of 13.0% were offset by a 2.8% natural gas general rate increase effective January 13, 2007 resulting in a decrease of $103.1 million in natural gas operating revenues.  The decrease was offset by higher gas sales of 72.2 million therms or 9.6% which increased gas operating revenue by $79.1 million.  A 2.3% increase in natural gas customers and colder than average temperatures contributed to the higher natural gas sales.

The following natural gas rate adjustments were approved by the Washington Commission in 2007 and 2008:

Type of Rate Adjustment	Effective Date	Average Percentage Increase (Decrease) in Rates		Annual Increase (Decrease)  in Revenues (Dollars in Millions)
Purchased Gas Adjustment	October 1, 2008	11.1	%	$ 108.8
Gas General Rate Case	January 13, 2007	2.8		29.5
Purchased Gas Adjustment	October 1, 2007	(13.0	)	(148.1	)

Non-Utility Operating Revenues

The table below sets forth changes in non-utility operating revenues for PSE for the nine months ended September 30, 2008 as compared to the same period in 2007.

(Dollars in Millions) Nine Months Ended September 30,	2008		2007		Change			Percent Change
Non-utility operating revenue	$	7.6	$	13.4	$	(5.8	)		(43.3	) %

Non-utility operating revenues decreased $5.8 million for the nine months ended September 30, 2008 as compared to the same period in 2007 due to higher property sales during 2007 by PSE’s real estate subsidiary.

Operating Expenses

The table below sets forth significant changes in operating expenses for PSE and its subsidiaries for the three months ended September 30, 2008 as compared to the same period in 2007.

(Dollars in Millions) Three Months Ended September 30,	2008		2007		Change			Percent Change
Purchased electricity	$	173.7	$	185.8	$	(12.1	)		(6.5	) %
Electric generation fuel		64.9		43.5		21.4			49.2
Purchased gas		70.1		80.9		(10.8	)		(13.3	)
Utility operations and maintenance		106.0		94.4		11.6			12.3
Non-utility expense and other		5.0		2.2		2.8			127.3
Depreciation and amortization		77.7		68.9		8.8			12.8
Conservation amortization		13.8		8.5		5.3			62.4

The table below sets forth significant changes in operating expenses for PSE and its subsidiaries for the nine months ended September 30, 2008 compared to the same period in 2007.

(Dollars in Millions) Nine Months Ended September 30,	2008			2007			Change			Percent Change
Purchased electricity	$	645.4		$	640.6		$	4.8			0.7	%
Electric generation fuel		144.6			93.3			51.3			55.0
Residential exchange credit		(20.5	)		(52.4	)		31.9			60.9
Purchased gas		484.0			530.6			(46.6	)		(8.8	)
Utility operations and maintenance		334.6			291.5			43.1			14.8
Depreciation and amortization		229.4			204.4			25.0			12.2
Conservation amortization		42.7			27.6			15.1			54.7
Taxes other than income taxes		214.8			207.3			7.5			3.6

Purchased electricity expenses decreased $12.1 million and increased $4.8 million for the three and nine months ended September 30, 2008, respectively, as compared to the same period in 2007.  The decrease for the three months ended September 30, 2008 was due to an underrecovery of power costs of $3.3 million for the three months ended September 30, 2008 as compared to overrecovery of power cost of $8.3 million in the same period in 2007.  The underrecovery of power costs for the three months ended September 30, 2008 was due to lower hydroelectric generation and an increase in the amount of generation produced by PSE’s combustion turbines which was lower than the wholesale price of power.  A decrease of $0.8 million in transmission expenses also contributed to the overall reduction in expense.

The increase for the nine months ended September 30, 2008 was primarily the result of higher wholesale market prices which contributed $50.6 million offset by a decrease in purchased power of 800,927 MWh or 6.4%, resulting in a decrease of $36.4 million.  The decrease in purchased power is related to increased production from company-owned combustion turbines, wind facilities and thermal generating facilities.  Also offsetting the increase were decreased transmission costs and other expenses, which contributed $9.0 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 and through other risk management techniques.

Electric generation fuel expense increased $21.4 million and $51.3 million for the three and nine months ended September 30, 2008, respectively, as compared to the same period in 2007.  The increase for the three months ended September 30, 2008 was due to an increase in generation from combustion turbines which contributed $21.0 million and an increase in market prices for natural gas used for electric generation. The increase for the nine months ended September 30, 2008 was due to an increase in generation from combustion turbines which contributed $50.5 million.  The increase in combustion turbine generation was due to lower hydroelectric generation and higher wholesale market price of electricity.

Residential exchange credits associated with the Bonneville Power Administration (BPA) Residential Exchange Program (REP) decreased $31.9 million for the nine months ended September 30, 2008 as compared to the same period in 2007 as a result of the suspension of the residential and small farm customer electric credit in rates effective June 7, 2007.  The suspension was due to an adverse ruling from the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit) which states that BPA actions in entering into residential exchange settlement agreements with investor owned utilities were not in accordance with the law.  In April 2008, PSE signed an agreement pursuant to which BPA would pay PSE $53.7 million for fiscal year 2008 REP benefits.  Of this amount PSE received approval to pass-through to customers approximately $20.0 million over a one-month period.  The remaining $33.7 million was used to offset PSE’s regulatory asset.  The REP credit is a pass-through tariff item with a corresponding credit in electric operating revenue; thus, it has no impact on electric margin or net income.  Based upon a new REP agreement, PSE began passing through REP credit to customers on November 1, 2008.

Purchased gas expenses decreased $10.8 million and $46.6 million for the three and nine months ended September 30, 2008, respectively, as compared to the same period in 2007 primarily due to a decrease in PGA rates, partially offset by higher customer therm sales.  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 gas cost amount in PGA mechanism rates, including accrued interest.  The PGA mechanism payable balance at September 30, 2008 was $16.2 million as compared to $77.9 million at December 31, 2007.  PSE is authorized by the Washington Commission to accrue carrying costs on PGA receivable and payable balances.  A receivable balance in the PGA mechanism reflects an under recovery of market natural gas cost through rates.  A payable balance reflects over recovery of market natural gas cost through rates.

Utility operations and maintenance expense increased $11.6 million and $43.1 million for the three and nine months ended September 30, 2008, respectively, as compared to the same period in 2007.  The increase for the three months ended September 30, 2008 was primarily due to an increase in planned maintenance of PSE’s generating facilities of $2.2 million, $5.5 million increase in administrative and general expenses primarily related to increases in insurance expenses and self-insurance claim reserve, $2.4 million increase in planned and unplanned gas operations and distribution expenses and a $1.8 million increase in customer service expenses including bad debt expenses.  The increase for the nine months ended September 30, 2008 was primarily due to $20.8 million in planned maintenance of PSE’s generating facilities and settlement, $8.2 million increase in planned and unplanned gas operations and distribution expenses, $9.1 million increase in administrative and general expenses including increases in costs for insurance, self-insurance claim reserve and legal fees associated with general rate filings, $1.2 million increase in planned and unplanned electric transmission and distribution expenses and $4.7 million increase in customer service expenses including bad debt exposure.

Non-utility expense and other increased $2.8 million for the three months ended September 30, 2008, as compared to the same period in 2007 primarily due to energy efficiency projects PSE constructed for the U.S. Navy.

Depreciation and amortization expense increased $8.8 million and $25.0 million for the three and nine months ended September 30, 2008, respectively, as compared to the same period in 2007.  These increases include the benefit of the 2007 deferral of Goldendale ownership and operating costs of $3.9 million and $10.8 million for the three and nine months ended September 30, 2007, respectively, which, had it not been included, would have resulted in an increase to depreciation and amortization expense of $4.9 million and $14.2 million for the three and nine months ended September 30 2008, respectively, as compared to the same periods in 2007.  The Goldendale deferral of ownership and operating costs ceased to be effective September 1, 2007, when PSE was authorized to begin recovering the costs in rates. The increase, excluding Goldendale deferral, was primarily due to placing additional utility plants into service during the last 12 months.

Conservation amortization increased $5.3 million and $15.1 million for the three and nine months ended September 30, 2008, respectively, as compared to the same period in 2007 due to higher authorized recovery of electric conservation expenditures.  Conservation amortization is a pass-through tariff item with no impact on earnings.

Taxes other than income taxes increased $7.5 million for the nine months ended September 30, 2008 as compared to the same period in 2007.  The increase was due to increases in revenue-based Washington State excise tax and municipal tax as a result of increased operating revenues.

Other Income, Other Expenses, Interest Expense and Income Tax Expense

The table below sets forth significant changes in other income, other expenses, interest expense and income tax expense for PSE and its subsidiaries for the three months ended September 30, 2008 as compared to the same period in 2007.

(Dollars in Millions) Three Months Ended September 30,	2008	2007	Change	Percent Change
Interest expense	$ (48.8)	$ (51.5)	$  2.7	5.2%
Income tax benefit	(2.1)	(1.9)	(0.2)	(10.5)

Interest expense decreased $2.7 million due primarily to the decrease in average debt outstanding as a result of the equity issuance in December 2007 and lower average interest rates on outstanding debt.

Income tax benefit increased $0.2 million due to a loss for the three months ended September 30, 2008 compared to income for the same period in 2007.  The income tax benefit for 2008 was offset by an unfavorable federal income tax expense true-up of $1.8 million following the filing of PSE’s 2007 federal income tax return.  The 2007 income tax benefit included a favorable true-up of $1.9 million following the filing of PSE’s 2006 federal income tax return.  The increase in income tax benefit was also affected by an unfavorable true-up of the effective tax for 2008 for such items as depreciation, production tax credits and, injuries and damages.

The table below sets forth significant changes in other income, interest expense and income tax expense for PSE and its subsidiaries for the nine months ended September 30, 2008 compared to the same period in 2007.

(Dollars in Millions) Nine Months Ended September 30,	2008	2007	Change	Percent Change
Other income	$  21.8	$  17.7	$  4.1	23.2%
Interest expense	(144.6)	(150.2)	5.6	3.7
Income tax expense	46.8	49.8	(3.0)	(6.0)

Other income increased $4.1 million for the nine months ended September 30, 2008 compared to the same period in 2007 primarily due to an increase in Washington Commission Allowance for Funds Used During Construction (AFUDC) and equity AFUDC.

Interest expense decreased $5.6 million for the nine months ended September 30, 2008 compared to the same period in 2007 primarily due to lower average debt outstanding as a result of the equity issuance in December 2007 and lower average interest rate on outstanding debt.

Income tax expense decreased $3.0 million for the nine months ended September 30, 2008 compared to the same period in 2007 due primarily to lower taxable income in 2008 as compared to 2007.  The decrease was offset by an unfavorable federal income tax expense true-up of $1.8 million in the third quarter 2008 following the filing of PSE’s 2007 federal income tax return compared to a favorable true-up in the third quarter 2007 of $1.9 million following the filing of PSE’s 2006 federal income tax return.  The decrease in income tax expense was also offset by the true-up of the effective tax rate for such items as depreciation, production tax credits and, injuries and damages.

Capital Requirements

Contractual Obligations and Commercial Commitments

Puget Energy.  The following are Puget Energy’s aggregate consolidated (including PSE) contractual obligations and commercial commitments as of September 30, 2008:

Puget Energy				Payments Due Per Period
Contractual Obligations (Dollars in Millions)	Total		2008		2009- 2010		2011- 2012		2013 & Thereafter
Long-term debt including interest	$	6,118.5	$	44.6	$	712.8	$	520.9	$	4,840.2
Short-term debt including interest		581.5		581.5		--		--		--
Mandatorily redeemable preferred stock		1.9		--		--		--		1.9
Service contract obligations		437.0		16.0		136.2		117.8		167.0
Non-cancelable operating leases		138.9		1.8		17.3		21.2		98.6
Fredonia combustion turbines lease 1		48.3		1.0		7.7		39.6		--
Energy purchase obligations		6,114.5		348.5		2,074.5		1,208.2		2,483.3
Contract initiation payment/collateral requirement		18.5		--		--		18.5		--
Financial hedge obligations		(43.4	)	(9.2	)	(29.0	)	(5.2	)	--
Purchase obligations		298.0		259.0		23.0		--		16.0
Pension and other benefits funding and payments		38.8		3.0		8.1		8.0		19.7
Total contractual cash obligations	$	13,752.5	$	1,246.2	$	2,950.6	$	1,929.0	$	7,626.7

Puget Energy				Amount of Commitment Expiration Per Period
Commercial Commitments (Dollars in Millions)	Total		2008		2009- 2010		2011- 2012		2013 & Thereafter
Credit agreement - available 2	$	762.6	$	--	$	300.00	$	462.6	$	--
Receivable securitization facility 3		29.0		--		29.0		--		--
Energy operations letter of credit		6.9		6.9		--		--		--
Total commercial commitments	$	798.5	$	6.9	$	329.0	$	462.6	$	--

________________

1	See “Fredonia 3 and 4 Operating Lease” under “Off-Balance Sheet Arrangements” below.
2	At September 30, 2008, PSE had available unsecured credit agreements in the amount of $500.0 million and $350.0 million, each expiring in April 2012.  The credit agreements provide credit support for letters of credit and commercial paper.  Lehman Brothers Bank, FSB (Lehman) committed $35.0 million to each of these facilities.  In September 2008, a large Japanese bank acquired $25.0 million of Lehman’s commitment to the $500.0 million facility.  Consequently, at September 30, 2008, Lehman had commitments of $10.0 million and $35.0 million under PSE’s $500.0 million and $350.0 million facilities, respectively.  In September 2008, Lehman informed PSE that it had suspended funding borrowing requests for its portion of these facilities.  The impact of the suspension is to effectively reduce the size of these facilities to $490.0 million and $315.0 million, respectively.  At September 30, 2008, PSE had $6.9 million outstanding under four letters of credit, $55.2 million commercial paper outstanding, and $280.3 million drawn on this facility, effectively reducing the available borrowing capacity to $462.6 million.  In August 2008, PSE entered into a nine month, $375.0 million credit agreement with four banks and as of September 30, 2008, PSE had $75.0 million outstanding under the agreement, effectively reducing the borrowing capacity to $300.0 million.  As of September 30, 2008, PSE had $1,180.0 million in credit facilities excluding Lehman’s share, effectively reduced by draws or commercial paper outstanding of $417.4 million, leaving $762.6 million available.
3	At September 30, 2008, PSE had available a $200.0 million receivables securitization facility that expires in December 2010.  $171.0 million was outstanding under the receivables securitization facility at September 30, 2008 thus leaving $29.0 million available.  The facility allows receivables to be used as collateral to secure short-term loans, not exceeding the lesser of $200.0 million or the borrowing base of eligible receivables, which fluctuate with the seasonality of energy sales to customers.  See “Receivables Securitization Facility” below for further discussion.

Puget Sound Energy.  The following are PSE’s aggregate contractual obligations and commercial commitments as of September 30, 2008:

Puget Sound Energy	Payments Due Per Period
Contractual Obligations (Dollars in Millions)	Total		2008		2009- 2010		2011- 2012		2013 & Thereafter
Long-term debt including interest	$	6,118.5	$	44.6	$	712.8	$	520.9	$	4,840.2
Short-term debt including interest		606.3		606.3		--		--		--
Mandatorily redeemable preferred stock		1.9		--		--		--		1.9
Service contract obligations		437.0		16.0		136.2		117.8		167.0
Non-cancelable operating leases		138.9		1.8		17.3		21.2		98.6
Fredonia combustion turbines lease 1		48.3		1.0		7.7		39.6		--
Energy purchase obligations		6,114.5		348.5		2,074.5		1,208.2		2,483.3
Contract initiation payment/collateral requirement		18.5		--		--		18.5		--
Financial hedge obligations		(43.4	)	(9.2	)	(29.0	)	(5.2	)	--
Purchase obligations		298.0		259.0		23.0		--		16.0
Pension and other benefits funding and payments		38.8		3.0		8.1		8.0		19.7
Total contractual cash obligations	$	13,777.3	$	1,271.0	$	2,950.6	$	1,929.0	$	7,626.7

Puget Sound Energy				Amount of Commitment Expiration Per Period
Commercial Commitments (Dollars in Millions)	Total		2008		2009- 2010		2011- 2012		2013 & Thereafter
Credit agreement - available 2	$	762.6	$	--	$	300.0	$	462.6	$	--
Receivable securitization facility 3		29.0		--		29.0		--		--
Energy operations letter of credit		6.9		6.9		--		--		--
Total commercial commitments	$	798.5	$	6.9	$	329.0	$	462.6	$	--

________________

1	See note 1 under Puget Energy above.
2	See note 2 under Puget Energy above.
3	See note 3 under Puget Energy above.

Off-Balance Sheet Arrangements

Fredonia 3 and 4 Operating Lease.  PSE leases two combustion turbines for its Fredonia 3 and 4 electric generating facility pursuant to a master operating lease that was amended for this purpose in April 2001.  The lease has a term expiring in 2011, but can be canceled by PSE at any time.  Payments under the lease vary with changes in the London Interbank Offered Rate (LIBOR).  At September 30, 2008, PSE’s outstanding balance under the lease was $46.1 million.  The expected residual value under the lease is the lesser of $37.4 million or 60.0% of the cost of the equipment.  In the event the equipment is sold to a third party upon termination of the lease and the aggregate sales proceeds are less than the unamortized value of the equipment, PSE would be required to pay the lessor contingent rent in an amount equal to the deficiency up to a maximum of 87.0% of the unamortized value of the equipment.

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 continuing customer growth and to support reliable energy delivery.  The cash flow construction expenditures, excluding equity AFUDC and customer refundable contributions was $424.3 million for the nine months ended September 30, 2008.  The anticipated utility construction expenditures, excluding AFUDC, for 2008, 2009 and 2010 are:

Capital Expenditure Estimates (Dollars in Millions)	2008		2009		2010
Energy delivery, technology and facilities	$	587.0	$	737.0	$	840.0
New supply resources		346.0		129.0		148.0
Total expenditures	$	933.0	$	866.0	$	988.0

The proposed utility construction expenditures and any new generation resource expenditures that may be incurred are anticipated to be funded with a combination of cash from operations, short-term debt, long-term debt and equity.  Construction expenditure estimates, including any new generation resources, are subject to periodic review and adjustment in light of changing economic, regulatory, environmental and efficiency factors.

Capital Resources

Cash From Operations

Cash generated from operations for the nine months ended September 30, 2008 was $559.4 million, which is 119.5% of the $468.0 million cash used for utility construction expenditures and other capital expenditures. For the nine months ended September 30, 2007, cash from operations was $491.6 million, which was 85.0% of the $578.1 million cash used for utility construction expenditures and other capital expenditures.

The overall cash generated from operating activities for the nine months ended September 30, 2008 increased $67.8 million compared to the same period in 2007.  The increase was primarily the result of the change in the residential exchange program of $59.5 million in 2008 compared to 2007, lower cash payments of $58.0 million related to accounts payable, $46.4 million more cash received related to accounts receivable and income tax refunds of $42.4 million.  Further, cash from operations increased due to lower cash payments for prepaid expenses of $33.3 million, $19.8 million recovery in materials and supplies and a decrease in accrued expenses and other items for the nine months ended September 30, 2008.  The increase was partially offset by a reduction in the purchased gas liability in 2008 of $61.7 million compared to an increase in the purchased gas liability in 2007 of $101.0 million which accounted for a decrease in cash of $162.7 million.  The increases were also offset by $31.7 million increase in fuel and gas inventory costs and a cash receipt of $18.9 million in 2007 from the lease purchase option settlement for the Bellevue offices.

Financing Program

Financing utility construction requirements and operational needs are dependent upon the amount of cash available and the cost and availability of external funds through bank credit facilities and capital markets.  Access to funds depends upon factors such as general economic conditions, conditions in the bank and credit markets, regulatory authorizations and policies and Puget Energy’s and PSE’s credit ratings.

Liquidity Facilities and Commercial Paper

PSE’s cash investments, short-term borrowings and sales of commercial paper are used to provide working capital to fund utility construction programs.  At the present time, the market for commercial paper is limited for A3/P2 rated companies and borrowing cost are significantly higher than under PSE’s credit facilities.  The Company’s committed credit facilities with numerous banks provide a stable liquidity position with sufficient short-term borrowing capacity.  At September 30, 2008, PSE and its subsidiaries held $140.1 million of cash invested mostly in U.S. Treasury related money market funds.  In the event of a credit downgrade, borrowing capacity under the credit facilities would remain the same while borrowing spreads and fees would increase.  PSE has not been significantly impacted by the current credit environment.

PSE Credit Facilities

The Company has four committed credit facilities that provide, in aggregate, $1.4 billion in short-term borrowing capability.  These include a $500.0 million credit agreement, a $200.0 million accounts receivable securitization facility, a $375.0 million short-term credit facility and a $350.0 million credit agreement to support hedging activity.

Credit Agreements.  In August 2008, PSE entered into a nine-month, $375.0 million credit agreement with four banks.  The interest rate on the facility is based either on the agent bank's prime rate or on LIBOR plus a margin that increases over time.  PSE pays a commitment fee on any unused portion of the credit agreement.  At September 30, 2008, there was $75.0 million outstanding under the agreement.

In March 2007, PSE entered into a five-year, $350.0 million credit agreement with a group of banks.  The agreement is used to support the Company’s energy hedging activities and may also be used to provide letters of credit.  The interest rate on outstanding borrowings is based either on the agent bank’s prime rate or on LIBOR plus a marginal rate related to PSE’s long-term credit rating at the time of borrowing.  PSE pays a commitment fee on any unused portion of the credit agreement also related to long-term credit ratings of PSE.  At September 30, 2008, there were no borrowings or letters of credit outstanding under the credit facility.

In March 2005, PSE entered into a five-year $500.0 million unsecured credit agreement with a group of banks.  In March 2007, PSE restated this credit agreement to extend the expiration date to April 2012.  The agreement is primarily used to provide credit support for commercial paper and letters of credit.  The terms of this agreement, as restated, are essentially identical to those contained in the $350.0 million facility described above.  At September 30, 2008, there was $6.9 million outstanding under letters of credit, $55.2 million of commercial paper outstanding and $280.3 million drawn on this facility.

The $500.0 million and $350.0 million credit facilities described above were originally syndicated with a group of 12 banks.  Lehman Brothers Bank, FSB (Lehman) a subsidiary of Lehman Brothers Holdings, Inc., which filed for liquidation on September 14, 2008, committed $35.0 million to each of these facilities.  In September 2008, a large Japanese bank acquired $25.0 million of Lehman’s commitment to the $500.0 million facility.  Consequently, at September 30, 2008, Lehman had commitments of $10.0 million and $35.0 million under PSE’s $500.0 million and $350.0 million facilities, respectively.  In September 2008, Lehman informed PSE that it had suspended funding borrowing requests for its portion of these facilities.  The impact of the suspension is to effectively reduce the size of these facilities to $490.0 million and $315.0 million, respectively.  Under this credit facility, with numerous banks, 30.0% or $60.0 million is the greatest lending commitment exposure by any bank.

Receivables Securitization Facility.  PSE entered into a five-year Receivable Sales Agreement with PSE Funding, Inc. (PSE Funding), a wholly owned subsidiary, on December 20, 2005.  Pursuant to the Receivables Sales Agreement, PSE sells all of its utility customer accounts receivable and unbilled utility revenues to PSE Funding.  In addition, PSE Funding entered into a Loan and Servicing Agreement with PSE and two banks.  The Loan and Servicing Agreement allows PSE Funding to use the receivables as collateral to secure short-term loans, not exceeding the lesser of $200.0 million or the borrowing base of eligible receivables which fluctuate with the seasonality of energy sales to customers.  All loans from this facility are reported as short-term debt in the financial statements.  The PSE Funding facility expires in December 2010 and is terminable by PSE and PSE Funding upon notice to the banks.  There were $171.0 million in loans that were secured by accounts receivable pledged at September 30, 2008.  The remaining borrowing base of eligible receivables at September 30, 2008 was $29.0 million.

Demand Promissory Note.  On June 1, 2006, PSE entered into an uncommitted revolving credit facility with its parent, Puget Energy, pursuant to a Demand Promissory Note (Note) under which PSE may borrow up to $30.0 million from 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; (b) PSE’s senior unsecured revolving credit facility; or (c) the interest rate available under the receivable securitization facility of PSE Funding, a PSE subsidiary.  At September 30, 2008, the outstanding balance of the Note was $24.7 million.  The outstanding balance and the related interest under the Note are eliminated by Puget Energy upon consolidation of PSE’s financial statements.

Long-term Funding and Restrictive Covenants

In determining the type and amount of future financing, PSE may be limited by restrictions contained in its electric and natural gas mortgage indentures, restated articles of incorporation and certain loan agreements.  Under the most restrictive tests, at September 30, 2008, PSE could issue:

·   approximately $721.0 million of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately $1.2 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, 2008;

·   approximately $507.0 million of additional first mortgage bonds under PSE’s natural gas mortgage indenture based on approximately $845.0 million of gas bondable property available for issuance, subject to interest coverage ratio limitations of 1.75 times and 2.0 times net earnings available for interest (as defined in the natural gas utility mortgage), which PSE exceeded at September 30, 2008;

·   approximately $0.7 billion of additional preferred stock at an assumed dividend rate of 9.5%; and

·   approximately $732.1 million of unsecured long-term debt.

At September 30, 2008, PSE had approximately $4.8 billion in electric and natural gas ratebase to support the interest coverage ratio limitation test for net earnings available for interest.

Credit Ratings

Neither Puget Energy nor PSE has any debt outstanding that would accelerate debt maturity upon a credit rating downgrade.  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 PSE’s revolving credit facility, the borrowing costs and commitment fee increase as PSE’s corporate/issuer credit ratings decline.  A downgrade in commercial paper ratings could preclude PSE’s ability to issue commercial paper under its current programs.  The marketability of PSE commercial paper is currently limited by the A-3/P-2 ratings by Standard & Poor’s and Moody’s Investors Service.  In addition, downgrades in PSE’s debt ratings may prompt counterparties to require PSE to post a letter of credit or other collateral, make cash prepayments, obtain a guarantee or provide other security.

The ratings of Puget Energy and PSE, as of October 31, 2008, were as follows:

	Ratings
	Standard & Poor’s1,2	Moody’s3
Puget Sound Energy
Corporate credit/issuer rating	BBB-	Baa3
Senior secured debt	BBB+	Baa2
Junior subordinated notes	BB	Ba1
Preferred stock	BB	Ba2
Commercial paper	A-3	P-2
Revolving credit facility	Note 1	Baa3
Ratings outlook	Note 2	Note 3
Puget Energy
Corporate credit/issuer rating	BBB-	Ba1
Ratings outlook	Note 2	Note 3

_______________

1	Standard & Poor’s does not rate PSE’s credit facilities.
2	On October 26, 2007, Standard & Poor’s placed the ratings of Puget Energy (BBB-) and PSE (BBB-/A-3) on CreditWatch with negative implications.  The CreditWatch listing reflects the possibility that debt ratings for Puget Energy could be lowered dependent on the final outcome of regulatory approval proceedings.
3	On October 29, 2007, Moody’s placed the Ba1 Issuer rating of Puget Energy on review for possible downgrade.  Moody’s also affirmed the long-term ratings of PSE and changed its rating outlook to stable from positive.  On this same date, Moody’s placed PSE’s P-2 short-term rating for commercial paper under review for possible downgrade.

Stock Purchase and Dividend Reinvestment Plan

Puget Energy has a Stock Purchase and Dividend Reinvestment Plan pursuant to which shareholders and other interested investors may invest cash and cash dividends in shares of Puget Energy common stock.  Since new shares of common stock may be purchased directly from Puget Energy, funds received may be used for general corporate purposes.  Puget Energy did not issue common stock under the Stock Purchase and Dividend Reinvestment Plan for the three and nine months ended September 30, 2008, as compared to $3.2 million (140,079 shares) and $9.7 million (395,970 shares) for the three and months ended September 30, 2007, respectively.  The proceeds from sales of stock under the Stock Purchase and Dividend Reinvestment Plan are used for general corporate needs.  Pending the outcome of the merger, Puget Energy intends to fund the Stock Purchase and Dividend Reimbursement Plan with shares acquired in the public markets.

Common Stock Offering Programs

To provide additional financing options, Puget Energy entered into agreements in July 2003 with two financial institutions under which Puget Energy may offer and sell shares of its common stock from time to time through these institutions as sales agents or as principals.  Sales of the common stock, if any, may be made by means of negotiated transactions or in transactions that may be deemed to be “at-the-market” offerings as defined in Rule 415 promulgated under the Securities Act of 1933, including in ordinary brokers’ transactions on the New York Stock Exchange at market prices.

Other

Regulation and Rates

On October 8, 2008, the Washington Commission issued its order in PSE’s consolidated electric and natural gas general rate case filed in December 2007, approving a general rate increase for electric customers of $130.2 million or 7.1% annually, and an increase in natural gas rates of $49.2 million or 4.6% annually.  The rates for electric and natural gas customers were effective November 1, 2008.  In its order, the Washington Commission approved a weighted cost of capital of 8.25% and a capital structure that included 46.0% common equity with a return on equity of 10.15%.  The Washington Commission will determine by a separate order certain contested issues related to the PCORC mechanism.

On September 25, 2008, the Washington Commission approved PSE’s requested revisions to its purchased gas adjustment (PGA) tariff schedules resulting in an increase of $108.8 million or 11.1% on an annual basis in gas sales revenues effective October 1, 2008.  The rate increase was the result of higher costs of natural gas in the forward market and a reduction of the credit for the accumulated PGA payable balance.  The PGA rate change will increase PSE’s revenue but will not impact the Company’s net income as the increased revenue will be offset by increased purchased gas costs.

On December 18, 2007, PSE received a data request from the Investigations Division of the Office of Enforcement at FERC seeking information about certain natural gas pipeline capacity release transactions PSE entered into in 2006 and 2005.  PSE responded to the data requests on January 23, 2008 and met with FERC staff on January 31, 2008.  At this meeting, PSE discussed with FERC staff additional transactions discovered in the course of responding to the data requests that potentially may be in violation of FERC regulations.  PSE received additional data requests from FERC on February 20, 2008.  In October 2008, PSE received preliminary notification from FERC staff that PSE had violated several FERC regulations and was subject to potential civil penalties and other remedies.  FERC has not yet issued a formal investigation report and thus, PSE is not able to predict the ultimate outcome of this investigation, including the amount of any penalties, at this time.

In November 2007, the Western Electricity Coordinating Council (WECC) audited PSE’s compliance with electric reliability standards adopted by FERC, the North American Electric Reliability Corporation (NERC) and/or WECC.  Compliance with these standards includes periodic self-certifications of compliance, self-reports of violations after discovery of the violation, spot checks to review self-certifications and external audits that review compliance with designated standards in detail.  The WECC audit team identified four potential violations of the standards that PSE had not previously self-reported.  Several months after the audit, WECC issued a “Notice of Alleged Violations” to PSE, adding details and proposed penalties to the proposed findings.  Under the rules for the process, PSE met with WECC representatives in July 2008 to discuss settlement.  PSE is hopeful that all issues concerning the four potential violations will be resolved.  Resolution of reliability standards issues will be an ongoing concern; however, PSE self-reports violations when they are discovered.  Such self-reports could result in settlement of issues or issuances of penalties in the future.  PSE has established a loss reserve of $0.6 million related to these alleged violations.

In May 2007, the Washington Commission Staff alleged that PSE’s natural gas system service provider had violated certain Washington Commission recordkeeping rules.  On April 3, 2008, the Washington Commission issued an order approving a settlement agreement that required PSE to pay a regulatory penalty of $1.25 million, to establish a quality assurance program to better monitor its subcontractors and to complete an independent audit of natural gas system recordkeeping procedures.

Accounting Petition.  On August 29, 2007, the Washington Commission approved PSE’s accounting petition to defer as a regulatory asset the excess BPA REP benefit provided to customers and accrue monthly carrying charges on the deferred balance from June 7, 2007 until the deferral is recovered from customers or BPA.

In March 2008, BPA and PSE signed an agreement pursuant to which BPA (on April 2, 2008) paid PSE $53.7 million in REP benefits for fiscal year 2008, which payment is subject to true-up depending upon the amount of any REP benefits ultimately determined to be payable to PSE.  This BPA's authority to enter into, and the validity of, this agreement and similar agreements with other utilities is being challenged by several BPA customers in the Ninth Circuit Court of Appeals.

On April 10, 2008, the Washington Commission approved PSE’s tariff filing seeking to pass-through the net amount of the benefits under the interim agreements to residential and small farm customers.  The Washington Commission also approved PSE’s request to credit the regulatory asset amount of $33.7 million against the $53.7 million payment and pass-through to customers the remaining amount of approximately $20.0 million.  The accrued carrying charges on the regulatory asset totaling $3.1 million at September 30, 2008 began amortization on November 1, 2008 over a two year period as determined in PSE’s electric general rate case.  On September 25, 2008, BPA and PSE signed an agreement pursuant to which BPA will make payments to PSE related to the REP benefit for the fiscal years beginning October 1, 2008 and ending September 30, 2011.  On October 8, 2008, the Washington Commission approved PSE’s tariff request to resume the REP pass-through credits to residential electric customers.  The result is a 9.9% reduction to residential electric customers bill without an impact on earnings.

Colstrip Matters

In May 2003, approximately 50 plaintiffs initiated an action against the owners of Colstrip 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 the amount of $10.7 million in July 2008.  PSE had previously expensed the settlement in the first quarter 2008.  PSE has also filed an accounting petition with the Washington Commission to recover such costs in the future.

The Minerals Management Service of the United States Department of Interior (MMS) has issued a series of orders to Western Energy Company (WECO) to pay additional taxes and royalties concerning coal WECO sold to the owners of Colstrip 3 & 4, and similar orders have been issued in the administrative appellate process.  The orders assert that additional royalties are owed in connection with payments received by WECO from Colstrip 3 & 4 owners (including PSE) for the construction and operation of a conveyor system that runs several miles from the mine to Colstrip 3 & 4.  The state of Montana has also issued a demand to WECO consistent with the MMS position.  WECO has challenged these orders and the issue has been on appeal for several years.  WECO has won some points during the appellate process that have reduced the claims; however under applicable law, to pursue the appeals, the principal in dispute cannot be paid which causes interest to accrue.  Moreover, because the conveyor system continues to be used, the amount in dispute grows.  PSE and the other Colstrip 3 & 4 owners authorized WECO to make a settlement offer to the Montana Department of Revenue (DOR) and the MMS in connection with these claims.  Discussions with the DOR and with the MMS continue.  PSE has recorded a $1.7 million pre-tax loss reserve in this matter.

Proceedings Relating to the Western Power Market

Puget Energy’s and PSE’s Annual Report on Form 10-K for the year ended December 31, 2007 includes a summary relating to the western power market proceedings.  The following discussion provides a summary of material developments during the third quarter 2008.  PSE is vigorously defending each of these cases.  Litigation is subject to numerous uncertainties and PSE is unable to predict the ultimate outcome of these matters.  Accordingly, there can be no guarantee that these proceedings, either individually or in the aggregate, will not materially and/or adversely affect PSE’s financial condition, results of operations or liquidity.

Lockyer Case.  In March and April 2008, FERC issued orders establishing procedures for the Lockyer remand.  The orders commence a seller-by-seller inquiry into the transaction reports filed by entities that sold power in California during 2000.  The inquiry is to determine if the transaction reports as filed masked the gathering of more than 20% of the market during the period, by that seller.  The California parties sought rehearing on a variety of these issues.  On October 6, 2008, FERC issued a decision on the rehearing request that reaffirmed its intent to impose seller-specific remedies rather than the market-wide remedy sought by the California parties.  The rehearing decision also reconfirms the Commission’s method for determining market share, limits the scope of the proceeding and declines to defer the proceeding pending remand from the Ninth Circuit of the California Refund Proceeding and the Port of Seattle (Pacific Northwest Refund) case.  PSE does not believe that it will be found to have possessed 20% of any relevant market during any relevant time.  The proceeding continues, including a settlement process before an Administrative Law Judge (ALJ).  Settlement talks among various parties continue but PSE cannot predict the ultimate outcome of any negotiations or subsequent process before FERC or the ALJ.

Proceedings Relating to the Bonneville Power Administration

Petitioners in several actions in the Ninth Circuit against BPA asserted that BPA acted contrary to law in entering into or performing or implementing a number of agreements, including the amended settlement agreement (and the May 2004 agreement) between BPA and PSE regarding the REP.  Petitioners in several actions in the Ninth Circuit against BPA also asserted that BPA acted contrary to law in adopting or implementing the rates upon which the benefits received or to be received from BPA during the October 1, 2001 through September 30, 2006 period were based.  A number of parties claimed that the BPA rates proposed or adopted in the BPA rate proceeding to develop BPA rates to be used in the agreements for determining the amounts of money to be paid to PSE by BPA during the period October 1, 2006 through September 30, 2009 are contrary to law and that BPA acted contrary to law or without authority in deciding to enter into, or in entering into or performing or implementing such agreements.

On May 3, 2007, the Ninth Circuit issued an opinion in Portland Gen. Elec. v. BPA, No. 01-70003, in which proceeding the actions of BPA in entering into settlement agreements regarding the REP with PSE and with other investor-owned utilities were challenged.  In this opinion, the Ninth Circuit granted petitions for review and held the settlement agreements entered into between BPA and the investor-owned utilities being challenged in that proceeding to be inconsistent with statute.  On May 3, 2007, the Ninth Circuit also issued an opinion in Golden Northwest Aluminum v. BPA, No. 03-73426, in which proceeding the petitioners sought review of BPA’s 2002-2006 power rates.  In this opinion, the Ninth Circuit granted petitions for review and held that BPA unlawfully shifted onto its preference customers the costs of its settlements with the investor-owned utilities.  On October 5, 2007, petitions for rehearing of these two opinions were denied.  On February 1, 2008, PSE and other utilities filed in the Supreme Court of the United States a petition for a writ of certiorari to review the decisions of the Ninth Circuit, which petition was denied in June 2008.

In May 2007, following the Ninth Circuit’s issuance of these two opinions, BPA suspended payments to PSE under the amended settlement agreement (and the May 2004 agreement).  On October 11, 2007, the Ninth Circuit remanded the May 2004 agreement to BPA in light of the Portland Gen. Elec. v. BPA opinion and dismissed the remaining three pending cases regarding settlement agreements.

In March 2008, BPA and PSE signed an agreement pursuant to which BPA made a payment to PSE related to the REP benefits for the fiscal year ended September 30, 2008, which payment is subject to true-up depending upon the amount of any REP benefits ultimately determined to be payable to PSE.  In March and April 2008, Clatskanie People’s Utility District filed petitions in the Ninth Circuit for review of BPA actions in connection with offering or entering into such agreement with PSE and similar agreements with other investor-owned utilities.  Clatskanie People’s Utility District asserts that BPA’s actions in entering into and executing the 2008 REP agreements were contrary to law or without authority and that such agreements are null and void and result in overpayments of REP benefits to PSE and other regional investor-owned utilities.

In September 2008, BPA issued its record of decision in its reopened WP-07 rate proceeding to respond to the various Ninth Circuit opinions.  In the record of decision, BPA adjusted its fiscal year 2009 rates, determined the amounts of REP benefits it considered to have been improperly paid after fiscal year 2001 to PSE and the other regional investor-owned utilities, and determined that such amounts are to be recovered through reductions in REP benefit payments to be made over a number of years.  The amount to be recovered (with interest) through reductions in REP payments for PSE’s residential and small farm customers is approximately $207.2 million to the extent that PSE receives any REP benefits for its customers in the future.  However, this BPA determination is subject to subsequent administrative and judicial review, which may alter or reverse such determination.  PSE is also reviewing its options in determining if it will contest the amounts withheld as improper payments made after 2001.

In September 2008, BPA and PSE signed a Residential Purchase and Sale Agreement (RPSA) under which BPA is to pay REP benefits to PSE for fiscal years ending September 30, 2009–2011.  Generally, REP benefit payments under a RPSA are based on the amount, if any, by which a utility's average system cost (ASC) exceeds BPA’s Preference Rate (PF) Exchange rate for such utility.  The ASC for a utility is determined using an ASC methodology adopted by BPA.  The ASC methodology adopted by BPA and the ASC determinations, REP overpayment determinations, and the PF Exchange rate determinations by BPA are all subject to FERC review or judicial review or both and are subject to adjustment, which may affect the amount of REP benefits paid or to be paid by BPA to PSE.  As discussed above, BPA has determined to reduce such payments based on its determination of REP benefit overpayments after fiscal year 2001.

It is not clear what impact, if any, such development or review of such BPA rates, review of such ASC, ASC Methodology, and BPA determination of REP overpayments, review of such agreements, and the above described Ninth Circuit litigation may ultimately have on PSE.

Proceeding Relating to the Proposed Merger

On February 6, 2008, the Company entered into a memorandum of understanding providing for the settlement of the consolidated shareholder lawsuit, subject to customary conditions including completion of appropriate settlement documentation, confirmatory discovery and court approval.  Pursuant to the memorandum of understanding, the Company agreed to include certain additional disclosures in its proxy statement relating to the merger.  The Company does not admit, however, that its prior disclosures were in any way materially misleading or inadequate.  In addition, the Company and the other defendants in the consolidated lawsuit deny the plaintiffs’ allegations of wrongdoing and violation of law in connection with the merger.  The settlement, if completed and approved by the court, will result in dismissal with prejudice and release of all claims of the plaintiffs and settlement class of the Company’s shareholders that were or could have been brought on behalf of the plaintiffs and the settlement class.  In connection with such settlement, the plaintiffs intend to seek a court-approved award of attorneys’ fees and expenses in an amount up to $290,000, which the Company has agreed to pay.  As of September 30, 2008, the Company has a loss reserve of $290,000.

Baker River Project License

On October 17, 2008, the FERC issued a new license for the Baker River hydroelectric project for a 50-year term.  The new license incorporates the measures proposed in the comprehensive Settlement Agreement that was filed on November 30, 2004 and signed by PSE and 23 parties (federal, state and local governmental organizations, Native American Indian tribes, environmental and other non-governmental entities).  The new license will require an investment of approximately $360.0 million (capital expenditures and operations and maintenance cost) over 30 years in order to implement the license conditions.  The license provides protection and enhancements for fish and wildlife, water quality, recreation and cultural and historic resources.  Parties may seek rehearing of the order issuing the new license within 30 days of license issuance.

Proceeding Relating to Snoqualmie Falls Project

The Snoqualmie Falls project was granted a new 40-year operating license by FERC on June 29, 2004.  The Snoqualmie Tribe asked for rehearing of the order and requested a stay of the new license.  On March 1, 2005, FERC issued an Order on Rehearing and Dismissing Stay Request.  The order required additional flows at Snoqualmie Falls during certain times of the year, but otherwise denied the Snoqualmie Tribe’s request.  The Snoqualmie Tribe sought further review by the U.S. Court of Appeals arguing, among other issues, that FERC violated the Religious Freedom Restoration Act (RFRA) and that the license decision substantially burdened the Snoqualmie Tribe’s free exercise of religion.  PSE also sought review of FERC’s decision to require additional flows during certain times of the year because the action appeared to interfere with the Washington State Department of Ecology’s jurisdiction to determine water quality issues.  On October 7, 2008, the court issued a decision denying the appeals and determined that FERC did not violate RFRA and that FERC’s adoption of water flows greater than those prescribed in the water quality certification did not contradict or weaken the water quality certification’s minimum flow requirements.  Parties may seek review of the decision by the United States Supreme Court.  Such review is discretionary and PSE is unable to determine whether the Supreme Court will elect to review the matter if further review is sought.  In addition, on December 6, 2007, PSE filed an application for a non-capacity amendment to the 2004 license.  The application seeks to amend the license to account for technology improvements and hydrologic and other changes that occurred post-license.  The license amendment application remains pending and its ultimate outcome remains uncertain.

New Accounting Pronouncements

On September 15, 2006, Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 157, “Fair Value Measurements” (SFAS No. 157), which clarifies how companies should use fair value measurements in accordance with GAAP for recognition and disclosure purposes.  SFAS No. 157 establishes a common definition of fair value and a framework for measuring fair value under GAAP, along with expanding disclosures about fair value to eliminate differences in current practice that exist in measuring fair value under the existing accounting standards.  The definition of fair value in SFAS No. 157 retains the notion of exchange price; however, it focuses on the price that would be received to sell the asset or paid to transfer a liability (i.e. an exit price), rather than the price that would be paid to acquire the asset or received to assume the liability (i.e. an entrance price).  Under SFAS No. 157, a fair value measure should reflect all of the assumptions that market participants would use in pricing the asset or liability, including assumptions about the risk inherent in a particular valuation technique, the effect of a restriction on the sale or use of an asset, and the risk of nonperformance.  To increase consistency and comparability in fair value measures, SFAS No. 157 establishes a three-level fair value hierarchy to prioritize the inputs used in valuation techniques between observable inputs that reflect quoted market prices in active markets, inputs other than quoted prices with observable market data, and unobservable data (e.g. a company’s own data).

SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, which was January 1, 2008, for the Company.  On February 28, 2008, the FASB issued a final FASB Staff Position (FSP) that partially deferred the effective date of SFAS No. 157 for one year for non-financial assets and non-financial liabilities that are recognized or disclosed at fair value, except for those that are recognized or disclosed at fair value on an annual or more frequent basis.  The Company adopted SFAS No. 157 on January 1, 2008, prospectively, as required by the Statement, with certain exceptions,  including the initial impact of changes in fair value measurements of existing derivative financial instruments measured initially using the transaction price under Emerging Issues Task Force (EITF) No. 02-3.  On January 1, 2008, the difference between the carrying amounts and the fair values of those instruments originally recorded under guidance in EITF No. 02-3 was recognized as a cumulative-effect adjustment to the opening balance of retained earnings.  SFAS No. 157 nullified a portion of EITF No. 02-3.  Under EITF No. 02-3, the transaction price presumption prohibited recognition of a trading profit at inception of a derivative unless the positive fair value of that derivative was substantially based on quoted prices or a valuation process incorporating observable inputs.  For transactions that did not meet this criterion at inception, trading profits that had been deferred were recognized in the period that inputs to value the derivative became observable or when the contract performed.

As a result of the recent credit crisis, on October 10, 2008, the FASB issued FSP FAS No. 157-3, “Determining the Fair Value of a Financial Asset in a Market That is Not Active.”  This FSP clarifies the application of SFAS No. 157 in a market that is not active.  The FSP addresses how management should consider measuring fair value when relevant observable data does not exist.  The FSP also provides guidance on how observable market information in a market that is not active should be considered when measuring fair value, as well as how the use of market quotes should be considered when assessing the relevance of observable and unobservable data available to measure fair value. This FSP was effective upon issuance, including prior periods for which financial statement have not been issued.  Revisions resulting from a change in the valuation technique or its application shall be accounting for as a change in accounting estimate (FASB Statement No. 154, “Accounting Changes and Error Corrections,” (SFAS No. 154) paragraph 19).  The disclosure provisions on SFAS No. 154 for a change in accounting estimate are not required for revisions resulting from a change in valuation technique or its application.  The Company has reviewed the statement and has assessed there will be no significant impact to the financial statements.

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (SFAS No. 141(R)).  This Statement replaces FASB Statement No. 141, “Business Combinations” and addresses the accounting for all transactions or other events in which an entity obtains control of one or more businesses.  The objective of this Statement is to improve the relevance, representational faithfulness and comparability of the information that a reporting entity provides in its financial reports about a business combination and its effects. To accomplish that, this Statement establishes principles and requirements for how the acquirer: 1) Recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree; 2) Recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and 3) Determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination.  This Statement shall be applied prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008.  The Company is currently assessing the impact of SFAS No. 141(R).

On March 19, 2008, FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – An Amendment of FASB Statement No. 133” (SFAS No. 161).  SFAS No. 161 is effective for the fiscal years and interim years beginning after November 15, 2008, which will be the quarter ending March 31, 2009 for the Company.  SFAS No. 161 requires companies with derivative instruments to disclose information that should enable financial statement users to understand how and why a company uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133) and how derivative instruments and related hedged items affect a company’s financial position, financial performance and cash flows.  SFAS No. 161 requirements will impact the following derivative and hedging disclosures: objectives and strategies, balance sheet, financial performance, contingent features and counterparty credit risk.  The Company is currently assessing the impact of SFAS No. 161.

In May 2008, FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (SFAS No. 162), which identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles.  The FASB Board is responsible for identifying the sources of accounting principles and providing entities with a framework for selecting the principles used in the preparation of financial statements.  The Company has reviewed the statement and has assessed there will be no significant impact to the financial statements.

On June 16, 2008, FSP EITF No. 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities,” (EITF No. 03-6-1) was issued.  This FSP addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share under the two-class method.  Unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of earnings per share pursuant to the two-class method.  This FSP will be effective for financial statements issued for fiscal years beginning after December 15, 2008, which will be the year ended December 31, 2009 for the Company.  The Company is currently assessing the financial statement presentation impact of FSP EITF No. 03-6-1.

Item 3.              Quantitative and Qualitative Disclosure About Market Risk

Energy Portfolio Management

The Company has energy risk policies and procedures to manage commodity and volatility risks.  The Company’s Energy Management Committee establishes the Company’s energy risk management policies and procedures and monitors compliance.  The Energy Management Committee is comprised of certain Company officers and is overseen by the Audit Committee of the Company’s Board of Directors.

The Company is focused on commodity price exposure and risks associated with volumetric variability in the natural gas and electric portfolios.  It is not engaged in the business of assuming risk for the purpose of speculative trading.  The Company hedges open natural gas and electric positions to reduce both the portfolio risk and the volatility risk in prices.  The exposure position is determined by using a probabilistic risk system that models 100 scenarios of how the Company’s natural gas and power portfolios will perform under various weather, hydro 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 energy portfolio risks prudently to serve retail load at overall least cost and limit undesired impacts on the Company’s customers and shareholders; and

· Reduce power costs by extracting the value of the Company’s assets.

The Company enters into derivative contracts to reduce commodity price risk and volumetric variability.  As a result, the Company’s financial statements will be subject to volatility due to changes in forward market prices of natural gas and electricity.  The Company’s intent when entering into these contracts is to hold the contracts until settlement to serve customers; thus the Company will be exposed to unrealized gains and losses associated with derivative contracts in its financial statements.  When forward market prices are higher than the Company’s contract price of derivative contracts, an unrealized gain is recorded.  When forward market prices are lower than the Company’s contract price of derivative contracts, an unrealized loss is recorded.

The following table presents electric derivatives that are designated as cash flow hedges or contracts that do not meet Normal Purchase Normal Sale (NPNS) at September 30, 2008 and December 31, 2007:

	Electric Derivatives
(Dollars in Millions)	September 30, 2008		December 31, 2007
Short-term asset	$	2.9	$	11.1
Long-term asset		2.6		6.6
Total assets	$	5.5	$	17.7
Short-term liability	$	34.6	$	9.8
Long-term liability		26.9		--
Total liabilities	$	61.5	$	9.8

If it is determined that it is uneconomical to operate the Company’s controlled electric generating facilities in the future period, the fuel supply cash flow hedge relationship is terminated and the hedge is de-designated which results in the unrealized gains and losses associated with the contracts being recorded in the income statement.  As these contracts are settled, the costs are recognized as energy costs and are included as part of the Power Cost Adjustment (PCA) mechanism.

At December 31, 2007, the Company had an unrealized day one loss deferral of $9.0 million related to a three-year locational power exchange contract which was modeled and therefore the day one loss was deferred under EITF No. 02-3.  The contract has economic benefit to the Company over its terms.  The locational exchange will help ease electric transmission congestion across the Cascade Mountains during the winter months as the Company will take delivery of energy at a location that interconnects with the Company’s transmission system in western Washington.  At the same time, the Company will make available the quantities of power at the Mid-Columbia trading hub location.  The day one loss deferral was transferred to retained earnings on January 1, 2008 as required by SFAS No. 157 and any future day one loss on contracts will be recorded in the income statement beginning January 1, 2008 in accordance with the statement.

The following tables present the impact of changes in the market value of derivative instruments not meeting NPNS or cash flow hedge criteria, and ineffectiveness related to highly effective cash flow hedges, to the Company’s earnings during the three and nine months ended September 30, 2008 and September 30, 2007:

(Dollars in Millions) Three Months Ended September 30,	2008	2007	Change
Decrease in earnings	$ (3.5)	$ (5.3)	$  1.8

(Dollars in Millions) Nine Months Ended September 30,	2008	2007	Change
Decrease in earnings	$ (1.2)	$  (1.0)	$ (0.2)

The amount of net unrealized gain (loss), net of tax, related to the Company’s cash flow hedges under SFAS No. 133 consisted of the following at September 30, 2008 and December 31, 2007:

(Dollars in Millions, net of tax)	September 30, 2008	December 31, 2007
Other comprehensive income – unrealized gain (loss)	$ (31.5)	$  3.4

The following table presents derivative hedges of natural gas contracts to serve natural gas customers at September 30, 2008 and December 31, 2007:

	Gas Derivatives
(Dollars in Millions)	September 30, 2008		December 31, 2007
Short-term asset	$	12.9	$	6.0
Long-term asset		3.8		5.3
Total assets	$	16.7	$	11.3
Short-term liability	$	112.1	$	17.3
Long-term liability		37.3		--
Total liabilities	$	149.4	$	17.3

At September 30, 2008, the Company had total assets of $16.7 million and total liabilities of $149.4 million related to hedges of natural gas contracts to serve natural gas customers.  All mark-to-market adjustments relating to the natural gas business have been reclassified to a deferred account in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71) 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% decrease in the market prices of natural gas and electricity would decrease the fair value of qualifying cash flow hedges by $40.7 million after-tax, with a corresponding after-tax impact in comprehensive income and earnings (due to ineffectiveness) of $39.6 million and $1.1 million, respectively.

Credit Risk

The Company 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.  The Company manages credit risk with policies and procedures for, among other things, counterparty analysis, exposure measurement, exposure monitoring and exposure mitigation.  The Company may require collateral, a letter of credit or a parental guarantee in order to minimize the Company’s exposure related to counterparty default.  The Company 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.  The Company monitors its trading limit exposures and may assign an internal credit rating lower than what is issued by external rating agencies.

The Company has entered into commodity master arrangements with its counterparties to mitigate credit exposure to those counterparties.  The Company generally enters into the following master arrangements:  1) Western Systems Power Pool Agreements (WSPP) - standardized power sales contract in the electric industry; 2) International Swaps and Derivatives Association Agreements (ISDA) - standardized financial gas and electric contracts; and 3) North American Energy Standards Board Agreements (NAESB) - standardized physical gas contracts.

It is possible that extreme volatility in energy commodity prices could cause the Company to have credit risk exposures 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, 2008, approximately 99.96% of the counterparties with transaction amounts outstanding in the Company’s energy portfolio are rated at least investment grade by the major rating agencies.  The Company assesses credit risk internally for counterparties that are not rated and also takes credit default swaps into consideration in valuing counterparty credit reserves.

Counterparty credit impacts the Company’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).  SFAS No. 133 specifies the requirements for derivative contracts to qualify for the NPNS scope exception. When performance is no longer probable, based on the deterioration of a counterparty’s credit, the Company records the fair value of the contract on the balance sheet, with the corresponding debit or credit recorded in the income statement.

Cash flow hedge derivative treatment is also impacted by a counterparty’s deterioration of credit under SFAS No. 133 guidelines. If a forecasted transaction associated with a cash flow hedge is no longer probable of occurring, based on deterioration of credit, the Company would discontinue hedge accounting, record in earnings subsequent changes in the derivative’s fair value and freeze amounts previously accounted for in Accumulated Other Comprehensive Income.  If the transaction is remote of occurring, any amounts previously accounted for in Accumulated Other Comprehensive Income would be reclassified into earnings.

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

In conjunction with SFAS No. 157 requirements, the Company calculates credit reserves in order to reflect credit risk in the financial statements. The Company’s assessment of a counterparty’s credit exposure impacts the calculations of credit reserves. The Company considers counterparty internal and external credit ratings, as well as annual study default factors published by Standard and Poor’s (S&P).  Furthermore, the Company computes credits reserves at a master agreement level (i.e. WSPP, ISDA, or NAESB) by counterparty, utilizing default factors applicable to the lower rating of either the S&P or the Company’s assigned internal credit rating.  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 based on the S&P credit rating to compute credit reserves for counterparties in a net liability position. The Company’s S&P rating at September 30, 2008 was BBB-.  The Company applies the default factor for each counterparty at an aggregate master agreement level based on the default factor calculated for the contract with the longest tenor. Credit reserves are booked as contra accounts to unrealized gain/(loss) positions. As of September 30, 2008, 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 this quarter.

Interest Rate Risk

The Company believes its interest rate risk primarily relates to the use of short-term debt instruments, leases and anticipated long-term debt financing needed to fund capital requirements.  The Company manages its interest rate risk through the issuance of mostly fixed-rate debt of various maturities.  The Company utilizes commercial paper, borrowing from its line of credit facilities and accounts receivable securitization facility to meet short-term cash requirements.  These 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.

The ending balance in other comprehensive income related to the forward starting swaps and previously settled treasury lock contracts at September 30, 2008 was a net loss of $8.0 million after-tax and accumulated amortization.  All financial hedge contracts of this type are reviewed by senior management and presented to the Securities Pricing Committee of the Board of Directors and are approved prior to execution.

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 Chairman, President and 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, 2008, the end of the period covered by this report.  Based upon that evaluation, the Chairman, President and 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 quarter ended September 30, 2008 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 Chairman, President and 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, 2008, the end of the period covered by this report.  Based upon that evaluation, the Chairman, President and 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 quarter ended September 30, 2008, 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

See the section titled “Proceedings Relating to the Western Power Market” under Item 2 “Management’s Discussion and Analysis of Financial Conditions and Results of Operations” of this Report on Form 10-Q.  Contingencies arising out of the normal course of the Company’s business exist at September 30, 2008.  The ultimate resolution of these issues in part or in the aggregate is not expected to have a material adverse impact on the financial condition, results of operations or liquidity of the Company.

Item 1A.           Risk Factors

There have been no material changes from the risk factors set forth in Part I, Item 1A in the Company’s Annual Report on Form 10-K for the year ended December 31, 2007.

Item 5.              Other Information

On August 29, 2008, PSE, as borrower, entered into a Credit Agreement with The Bank of Nova Scotia, as Administrative Agent, Wells Fargo Bank, N.A., as Documentation Agent, JPMorgan Chase Bank, N.A. and Barclays Bank PLC as Co-Agents and the lenders party thereto (the Credit Agreement).

The Credit Agreement provides for a $375.0 million unsecured term loan facility (the Credit Facility), to be funded in up to three advances at the request of PSE until May 29, 2009, when the commitment of the lenders to make advances under the Credit Facility terminates.  The Credit Facility is not a revolving credit facility.  The Credit Facility matures on the earlier of May 29, 2009 or the date of the merger of Puget Merger Sub Inc. into Puget Energy, Inc., at which time all outstanding borrowings must be repaid.

 The Credit Agreement also contains customary events of default.  The occurrence of an event of default could result in an increase the applicable rate of interest and could result in the acceleration of PSE’s obligations under the Credit Facility.

Item 6.              Exhibits

See Exhibit Index for list of exhibits.

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 5, 2008
	Chief accounting officer and officer duly authorized to sign this report on behalf of each registrant

EXHIBIT INDEX

The following exhibits are filed herewith:

10.1	Credit Agreement dated as of August 29, 2008 among Puget Sound Energy, Inc., the various financial institutions named therein and The Bank of Nova Scotia, Administrative Agent.
12.1	Statement setting forth computation of ratios of earnings to fixed charges (2003 through 2007 and 12 months ended September 30, 2008) for Puget Energy.
12.2	Statement setting forth computation of ratios of earnings to fixed charges (2003 through 2007 and 12 months ended September 30, 2008) for PSE.
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.