Puget Sound Energy 10-Q 2009 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2009

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

1-4393 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 registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes /X/ No /  /

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes /   / No /  /

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company.  See the definitions of “large accelerated filer, accelerated filer and smaller reporting company” in Rule 12b-2 of the Exchange Act.

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)

Yes /  / No /X/

All of the outstanding shares of voting stock of Puget Sound Energy, Inc. are held by its parent company, Puget Energy, Inc.

Table of Contents

Definitions
Forward Looking Statements
Part I.	Financial Information
Item 1.	Financial Statements
	Puget Sound Energy, Inc.
	Consolidated Statements of Income – Three and Six Months Ended June 30, 2009 and 2008
	Consolidated Statements of Comprehensive Income – Three and Six Months Ended June 30, 2009 and 2008
	Consolidated Balance Sheets – June 30, 2009 and December 31, 2008
	Consolidated Statement of Common Shareholder’s Equity – June 30, 2009 and December 31, 2008
	Consolidated Statements of Cash Flows –Six Months Ended June 30, 2009 and 2008
	Notes
	Notes to Consolidated Financial Statements
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3.	Quantitative and Qualitative Disclosure About Market Risk
Item 4.	Controls and Procedures
Part II.	Other Information
Item 1.	Legal Proceedings
Item 1A.	Risk Factors
Item 6.	Exhibits
Signatures
Exhibit Index

DEFINITIONS

AFUDC	Allowance for Funds Used During Construction
ASC	Average System Cost
BPA	Bonneville Power Administration
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
ISDA	International Swaps and Derivatives Association
kW	Kilowatt
kWh	Kilowatt Hour
LIBOR	London Interbank Offered Rate
MMBtus	One Million British Thermal Units
MW	Megawatt (one MW equals one thousand kW)
MWh	Megawatt Hour (one MWh equals one thousand kWh)
NAESB	North American Energy Standards Board
NERC	North American Electric Reliability Corporation
Ninth Circuit	United States Court of Appeals for the Ninth Circuit
NPNS	Normal Purchase Normal Sale
OCI	Other Comprehensive Income
PCA	Power Cost Adjustment
PCORC	Power Cost Only Rate Case
PF	BPA Priority Firm Exchange Rate
PGA	Purchased Gas Adjustment
PSE	Puget Sound Energy, Inc.
Puget Energy	Puget Energy, Inc.
Puget Holdings	Puget Holdings LLC
PURPA	Public Utility Regulatory Policies Act
REP	Residential Exchange Program
RPSA	Residential Purchase and Sale Agreement
SFAS	Statement of Financial Accounting Standards
VIE	Variable Interest Entity
Washington Commission	Washington Utilities and Transportation Commission
WSPP	Western Systems Power Pool

FORWARD-LOOKING STATEMENTS

Puget Sound Energy, Inc. (PSE) is 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 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.  PSE’s expectations, beliefs and projections are expressed in good faith and are believed by PSE 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 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 PSE to differ materially from those discussed in forward-looking statements include:

· Governmental policies and regulatory actions, including those of the Federal Energy Regulatory Commission (FERC) and the Washington Utilities and Transportation Commission (Washington Commission), with respect to allowed rates of return, cost recovery, financing, industry and rate structures, transmission and generation business structures within PSE, acquisition and disposal of assets and facilities, operation, maintenance and construction of electric generating facilities, maintenance, construction and operation of natural gas and electric 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;

· Accidents or 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 its suppliers;

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

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

· Changes in weather conditions in the Pacific Northwest, which could have effects on customer usage and PSE’s revenues;

· Weather, which can have a potentially serious impact on PSE’s ability to procure adequate supplies of natural gas, fuel or purchased power to serve its customers and the cost of procuring such supplies;

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

· Electric plant generation and transmission system outages, which can have an adverse impact on PSE’s expenses with respect to repair costs, added costs to replace energy or higher costs associated with dispatching a more expensive 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 electric generation facilities following a regional transmission disruption;

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

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

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

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

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

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

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

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

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

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

· Changes in PSE’s credit ratings, which may have an adverse impact on the availability and cost of capital for PSE;  and

· Deteriorating values of the equity, fixed income and other markets which could significantly impact the value of investments of PSE’s retirement plan and postretirement medical benefit plan trusts and the funding of obligations thereunder.

Any forward-looking statement speaks only as of the date on which such statement is made and except as required by law, PSE undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events.  New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.  You are also advised to consult Item 1A-“Risk Factors” in PSE’s most recent annual report on Form 10-K.

PART I              FINANCIAL INFORMATION

Item 1.              Financial Statements

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

 (Dollars in thousands)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Operating revenues:
Electric	$	456,754		$	478,038		$	1,056,984		$	1,084,172
Gas		226,922			233,840			733,357			677,077
Other		2,604			526			3,493			2,088
Total operating revenues		686,280			712,404			1,793,834			1,763,337
Operating expenses:
Energy costs:
Purchased electricity		188,918			198,886			449,167			471,718
Electric generation fuel		17,832			32,687			65,960			79,701
Residential exchange		(20,929	)		(20,298	)		(53,333	)		(20,305	)
Purchased gas		132,140			137,718			452,203			413,913
Net unrealized gain on derivative instruments		(9,920	)		(2,364	)		(7,590	)		(2,277	)
Utility operations and maintenance		122,107			116,449			237,000			228,608
Non-utility expense and other		2,088			1,657			3,395			1,713
Merger and related costs		(3,655	)		--			23,908			--
Depreciation and amortization		82,385			76,322			163,746			151,688
Conservation amortization		13,730			15,525			34,559			28,891
Taxes other than income taxes		66,697			63,674			168,039			157,947
Total operating expenses		591,393			620,256			1,537,054			1,511,597
Operating income		94,887			92,148			256,780			251,740
Other income (deductions):
Other income		12,387			8,068			22,319			14,878
Other expense		(1,691	)		(841	)		(4,134	)		(1,818	)
Interest charges:
AFUDC		2,218			1,782			3,900			4,211
Interest expense		(50,428	)		(48,543	)		(103,004	)		(99,591	)
Interest expense on Puget Energy note		(68	)		(209	)		(142	)		(446	)
Income before income taxes		57,305			52,405			175,719			168,974
Income tax expense		13,528			13,295			46,965			48,960
Net income	$	43,777		$	39,110		$	128,754		$	120,014

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in thousands)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Net income	$	43,777		$	39,110		$	128,754		$	120,014
Other comprehensive income:
Unrealized gain (loss) from pension and postretirement plans, net of tax of $(741), $277, $(232) and $322, respectively		(1,376	)		422			(431	)		598
Net unrealized gain (loss) on energy derivative instruments during the period, net of tax of $3,202, $60,710, $(33,709) and $86,167, respectively		5,946			112,747			(62,603	)		160,024
Reclassification of net unrealized gain (loss) on energy derivative instruments settled during the period, net of tax of $4,418, $(1,802), $11,938 and $(845), respectively		8,204			(3,347	)		22,171			(1,569	)
Amortization of financing cash flow hedge contracts to earnings, net of tax of $43, $43, $86 and $86, respectively		79			79			159			159
Other comprehensive income (loss)		12,853			109,901			(40,704	)		159,212
Comprehensive income	$	56,630		$	149,011		$	88,050		$	279,226

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

ASSETS

	June 30, 2009 (Unaudited)			December 31, 2008
Utility plant: (at original cost, including construction work in progress of $335,620 and $255,214, respectively)
Electric plant	$	6,825,902		$	6,596,359
Gas plant		2,579,551			2,500,236
Common plant		587,213			550,368
Less:  Accumulated depreciation and amortization		(3,511,142	)		(3,358,816	)
Net utility plant		6,481,524			6,288,147
Other property and investments:
Investment in Bonneville Exchange Power contract		28,213			29,976
Other property and investments		115,317			118,039
Total other property and investments		143,530			148,015
Current assets:
Cash		43,457			38,470
Restricted cash		15,760			18,889
Accounts receivable, net of allowance for doubtful accounts		229,110			207,776
Secured pledged accounts receivable		--			158,000
Unbilled revenues		84,084			248,649
Materials and supplies, at average cost		70,579			62,024
Fuel and gas inventory, at average cost		98,215			120,205
Unrealized gain on derivative instruments		13,765			15,618
Prepaid income taxes		38,988			17,317
Prepaid expenses and other		10,877			14,420
Deferred income taxes		41,341			9,439
Total current assets		646,176			910,807
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes		90,562			95,417
Regulatory asset for PURPA buyout costs		94,500			110,838
Power cost adjustment mechanism		2,733			3,126
Other regulatory assets		715,758			766,732
Unrealized gain on derivative instruments		10,479			6,712
Other		103,753			40,365
Total other long-term and regulatory assets		1,017,785			1,023,190
Total assets	$	8,289,015		$	8,370,159

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

CAPITALIZATION AND LIABILITIES

	June 30, 2009 (Unaudited)			December 31, 2008
Capitalization:
Common shareholder’s investment:
Common stock ($10 stated value) - 150,000,000 shares authorized, 85,903,791 shares outstanding	$	--		$	859,038
Common stock ($0.01 par value) - 150,000,000 shares authorized, 85,903,791 shares outstanding		859			--
Additional paid-in capital		2,959,205			1,296,005
Earnings reinvested in the business		339,279			356,947
Accumulated other comprehensive loss, net of tax		(303,508	)		(262,804	)
Total shareholder’s equity		2,995,835			2,249,186
Redeemable securities and long-term debt:
Preferred stock subject to mandatory redemption		--			1,889
Junior subordinated notes		250,000			250,000
Long-term debt		2,295,860			2,270,860
Total redeemable securities and long-term debt		2,545,860			2,522,749
Total capitalization		5,541,695			4,771,935
Current liabilities:
Accounts payable		167,867			341,255
Short-term debt		125,000			964,700
Short-term note owed to parent		22,852			26,053
Current maturities of long-term debt		233,000			158,000
Accrued expenses:
Purchased gas liability		62,897			8,892
Taxes		65,449			85,068
Salaries and wages		22,045			35,280
Interest		40,032			36,112
Unrealized loss on derivative instruments		275,419			236,866
Other		111,648			117,223
Total current liabilities		1,126,209			2,009,449
Long-term liabilities and regulatory liabilities:
Deferred income taxes		824,249			750,440
Unrealized loss on derivative instruments		123,217			158,423
Regulatory liabilities		223,188			219,221
Other deferred credits		450,457			460,691
Total long-term liabilities and regulatory liabilities		1,621,111			1,588,775
Total capitalization and liabilities	$	8,289,015		$	8,370,159

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY

 (Dollars in thousands)

(Unaudited)

	Common Stock					Additional						Accumulated Other
For Six Months Ended June 30, 2009	Shares		Amount			Paid-in Capital			Retained Earnings			Comprehensive  Loss			Total Amount
Balance at December 31, 2008		85,903,791	$	859,038		$	1,296,005		$	356,947		$	(262,804	)	$	2,249,186
Net income		--		--			--			128,754			--			128,754
Common stock dividend declared		--		--			--			(146,422	)		--			(146,422	)
Change in par value		--		(858,179	)		858,179			--			--			--
Other comprehensive income		--		--			--			--			(40,704	)		(40,704	)
Investment from Parent		--		--			805,283			--			--			805,283
Employee common stock award transferred to liability award		--		--			(690	)		--			--			(690	)
Tax windfall		--		--			428			--			--			428
Balance at June 30, 2009		85,903,791	$	859		$	2,959,205		$	339,279		$	(303,508	)	$	2,995,835

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

 (Dollars in thousands)

(Unaudited)

	Six Months Ended June 30,
	2009			2008
Operating activities:
Net income	$	128,754		$	120,014
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		163,746			151,688
Conservation amortization		34,559			28,891
Deferred income taxes and tax credits, net		68,695			39,037
Amortization of gas pipeline capacity assignment		(4,651	)		(5,257	)
Non cash return on regulatory assets		(4,793	)		(4,972	)
Net unrealized loss on derivative instruments		(7,590	)		(2,277	)
Mint Farm deferred costs		(14,125	)		--
Pension funding		(6,000	)		--
Change in residential exchange program		1,666			32,473
Other		(250	)		12,977
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue		280,168			196,963
Materials and supplies		(8,554	)		(642	)
Fuel and gas inventory		21,990			14,119
Prepaid income taxes		(21,670	)		41,540
Prepayments and other		3,543			1,583
Purchased gas receivable/payable		54,005			(51,100	)
Accounts payable		(151,137	)		(46,780	)
Taxes payable		(19,192	)		(7,909	)
Accrued expenses and other		(8,147	)		(1,757	)
Net cash provided by operating activities		511,017			518,591
Investing activities:
Construction expenditures - excluding equity AFUDC		(363,514	)		(255,776	)
Energy efficiency expenditures		(37,548	)		(26,963	)
Restricted cash		3,128			(12,216	)
Other		9,061			2,486
Net cash used by investing activities		(388,873	)		(292,469	)
Financing activities:
Change in short-term debt, net		(87,991	)		26,080
Dividends paid		(146,422	)		(81,001	)
Loan from (payment to) parent		(3,202	)		9,260
Long term bond issued		250,000			--
Redemption of trust preferred stock		(1,889	)		--
Redemption of bonds and notes		(150,000	)		(150,000	)
Investment from parent		25,960			--
Issuance cost of bonds and other		(3,613	)		(2,255	)
Net cash used by financing activities		(117,157	)		(197,916	)
Net increase in cash		4,987			28,206
Cash at beginning of year		38,470			40,773
Cash at end of period	$	43,457		$	68,979
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	93,553		$	101,286
Cash refunds from income taxes		129			(39,730	)

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1)   Summary of Consolidation Policy

Basis of Presentation

Puget Sound Energy, Inc. (PSE) is a subsidiary of Puget Energy, Inc. (Puget Energy), an energy services holding company incorporated in the state of Washington in 1999.  On February 6, 2009, Puget Holdings LLC (Puget Holdings) completed its merger with Puget Energy.  PSE’s basis of accounting will continue to be on a historical basis and PSE’s financial statements will not include any Statement of Financial Accounting Standards (SFAS) No. 141R, “Business Combinations” purchase accounting adjustments.

PSE’s consolidated financial statements include the accounts of PSE and its subsidiaries.  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 opinion of PSE’s management, all adjustments necessary for a fair statement of the results for the interim periods have been reflected.  These 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, 2008.

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 customer retail rates) and municipal taxes of $53.7 million and $139.6 million for the three and six months ended June 30, 2009, respectively, and $53.2 million and $129.9 million for the three and six months ended June 30, 2008, respectively.  PSE’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)   Merger

In conjunction with the merger on February 6, 2009, Puget Energy contributed $805.3 million in capital to PSE, of which $779.3 million was used to pay off short-term debt owed by PSE, including $188.0 million in short-term debt outstanding through the PSE Funding accounts receivable securitization program that was terminated upon completion of the merger.  The $779.3 million is excluded as cash provided by financing activities in the statement of cash flows.  An additional $26.0 million of the capital contribution was used to pay for change in control costs associated with the merger and is included as cash provided by financing activities in the statement of cash flows.  The stated value of the outstanding common stock was changed from $10.00 to a par value of $0.01 per share.  The remaining $9.99 of the original stated value was transferred to additional paid in capital.

During the six months ended June 30, 2009, PSE incurred $23.9 million pre-tax in merger costs.  These costs include compensation costs as a result of the change in control, write-off of deferred debt costs associated with the termination of the pre-merger credit facilities, expenses associated with new credit facilities and the impact of deferred compensation liabilities as a result of the merger.  Pursuant to the Washington Utilities and Transportation Commission (Washington Commission) merger order commitments, PSE will not seek recovery of these costs.  In addition, a requirement of the merger was that Puget Energy be the sole shareholder of PSE.  Accordingly, PSE defeased and redeemed its two outstanding series of preferred stock in conjunction with the merger.

The merger order issued by the Washington Commission was subject to a Settlement Stipulation which included 78 conditions.  The conditions provided for, among other matters, minimum equity to capitalization ratio, dividend restrictions, financial reporting and rate credits of $10.0 million per year for ten years.

(3)   Accounting for Derivative Instruments and Hedging Activities

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. PSE 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 PSE’s physical contracts qualify for the Normal Purchase Normal Sale (NPNS) exception to derivative accounting rules, provided they meet certain criteria.  Generally, NPNS applies to contracts with creditworthy counterparties, for which physical delivery is probable and in quantities that will be used in the normal course of business.  Power purchases designated as NPNS must meet additional criteria if the transaction is within PSE’s forecasted load requirements and if the counterparty owns or controls energy resources within the western region to allow for physical delivery of the energy.  PSE may enter into financial fixed contracts to hedge the variability of certain NPNS contracts.  The contracts that do not meet 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), through the Power Cost Adjustment (PCA) mechanism and Purchased Gas Adjustment (PGA) mechanism for energy related derivatives.

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

If it is determined that it is uneconomical to operate PSE’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 recognition of future changes in value in the income statements.  As these contracts are settled, amounts previously deferred in other comprehensive income (OCI) are recognized as energy costs and are included as part of the PCA mechanism.

The ending balance in OCI related to the settled treasury lock contracts at June 30, 2009 was a net loss of $7.7 million after tax and accumulated amortization.  The settlements will be amortized through September 30, 2036.  This compares to a loss of $7.9 million in OCI after tax and accumulated amortization at December 31, 2008.

SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – An Amendment of Financial Accounting Standards Board (FASB) Statement No. 133” (SFAS No. 161), requires enhanced disclosures about a company’s derivative activities and how the related hedged items affect a company’s financial position, financial performance and cash flows.  To meet the objectives, SFAS No. 161 requires qualitative disclosures about PSE’s fair value amounts of gains and losses associated with derivative instruments, as well as disclosures about credit-risk-related contingent features in derivative agreements.  PSE elected to early adopt SFAS No. 161 and began reporting such activities at December 31, 2008.

The following table presents the fair values and locations of derivative instruments recorded on the balance sheet at June 30, 2009 and December 31, 2008:

Derivatives Designated as Hedging Instruments
	At June 30, 2009				At December 31, 2008
(Dollars in Millions)	Asset Derivatives1		Liability Derivatives2		Asset Derivatives1		Liability Derivatives2
Electric portfolio:
Current	$	--	$	99.2	$	0.1	$	85.3
Long-term		0.5		60.6		0.4		93.1
Total derivatives	$	0.5	$	159.8	$	0.5	$	178.4

____________

1	Balance sheet location: Unrealized gain on derivative instruments.
2	Balance sheet location: Unrealized loss on derivative instruments.

Derivatives Not Designated as Hedging Instruments
	At June 30, 2009				At December 31, 2008
(Dollars in Millions)	Asset Derivatives1		Liability Derivatives2		Asset Derivatives1		Liability Derivatives2
Electric portfolio:
Current	$	1.0	$	53.8	$	0.3	$	5.3
Long-term		2.8		31.1		0.1		3.0
Gas portfolio:
Current		12.7		122.4		15.2		146.3
Long-term		7.2		31.5		6.2		62.3
Total derivatives	$	23.7	$	238.8	$	21.8	$	216.9

____________

1	Balance sheet location: Unrealized gain on derivative instruments.
2	Balance sheet location: Unrealized loss on derivative instruments.

PSE had a current derivative liability and an offsetting regulatory asset of $134.0 million at June 30, 2009 and $187.2 million at December 31, 2008 related to financial contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers.  All fair value adjustments on derivatives relating to the natural gas business have been reclassified to a deferred account in accordance with 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 gas costs under the PGA mechanism.

The following table presents the effect of hedging instruments on OCI and income for the three months ended June 30, 2009:

(Dollars in Millions) Three Months Ended June 30, 2009	Amount of Gain Recognized in OCI on Derivatives	Location of Loss Reclassified from Accumulated OCI into Income	Amount of Loss Reclassified from Accumulated OCI into Income	Location of Gain Recognized in Income on Derivatives		Amount of Gain Recognized in Income on Derivatives
Derivatives in SFAS No. 133 Cash Flow Hedging  Relationships	Effective Portion 1	Effective Portion 2		Ineffective Portion and Amount Excluded from Effectiveness Testing 2, 3
Interest rate contracts:	$       --	Interest expense	$      0.1		$      --
Commodity contracts: Electric derivatives	1.3	Electric generation fuel	5.5	Net unrealized gain on derivative instruments	--
Electric derivatives	12.8	Purchased electricity	7.2	Net unrealized gain on derivative instruments	0.5
Gas derivatives	--	Purchased gas	--	Net unrealized gain on derivative instruments	--
Total	$    14.1		$    12.8		$    0.5

____________  

1	Changes in OCI are reported in after tax dollars.
2	A reclassification of a loss in OCI increases Accumulated OCI and decreases earnings.  Amounts reported are in pre-tax dollars.
3	Ineffective portion of long-term power supply contracts that are designated as cash flow hedges.

The following table presents the effect of hedging instruments on OCI and income for the six months ended June 30, 2009:

(Dollars in Millions) Six Months Ended June 30, 2009	Amount of Loss Recognized in OCI on Derivatives	Location of Loss Reclassified from Accumulated OCI into Income	Amount of Loss Reclassified from Accumulated OCI into Income	Location of Loss Recognized in Income on Derivatives		Amount of Loss Recognized in Income on Derivatives
Derivatives in SFAS No. 133 Cash Flow Hedging   Relationships	Effective Portion 1	Effective Portion 2		Ineffective Portion and Amount Excluded from Effectiveness Testing 2, 3
Interest rate contracts:	$        --	Interest expense	$      0.2		$      --
Commodity contracts: Electric derivatives	(38.1)	Electric generation fuel	19.4	Net unrealized loss on derivative instruments	--
Electric derivatives	(1.7)	Purchased electricity	14.7	Net unrealized loss on derivative instruments	(2.7)
Gas derivatives	--	Purchased gas	--	Net unrealized loss on derivative instruments	--
Total	$  (39.8)		$    34.3		$  (2.7)

____________ 

 

1	Changes in OCI are reported in after tax dollars.
2	A reclassification of a loss in OCI increases Accumulated OCI and decreases earnings.  Amounts reported are in pre-tax dollars.
3	Ineffective portion of long-term power supply contracts that are designated as cash flow hedges.

For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. Gains and losses on the derivatives representing hedge ineffectiveness are recognized in current earnings.  PSE expects that $145.2 million of losses in OCI will be reclassified into earnings within the next 12 months.  The maximum length of time over which PSE is hedging its exposure to the variability in future cash flows extends to February 2015 for physical electric contracts and to January 2012 for electric generation fuel financial contracts.  During the current reporting period, PSE reclassified $0.5 million of after-tax losses from OCI into earnings related to transactions that are probable of not occurring.

The following table presents the effect of derivatives not designated as hedging instruments on income during the three months and six months ended June 30, 2009:

(Dollars in Millions)	Location of Gain/(Loss) in Income on Derivatives	Three Months Ended June 30, 2009 Amount of Gain/(Loss) Recognized in Income on Derivatives			Six Months Ended June 30, 2009 Amount of Gain/(Loss) Recognized in Income on Derivatives
Commodity contracts: Electric derivatives	Net unrealized gain on derivative instruments	$	9.4		$	10.3
	Electric generation fuel		(5.0	)		(12.0	)
	Purchased electricity		(0.1	)		(0.6	)
Gas derivatives1	Net unrealized gain on derivative instruments		--			--
Total		$	4.3		$	(2.3	)

________________

1 Gas derivatives are deferred in accordance with SFAS No. 71.

PSE had the following outstanding commodity contracts that were entered into as of June 30, 2009:

	Number of Units
Six Months Ended June 30, 2009
Derivatives designated as hedging instruments:
Electric generation fuel	27,645,000 MMBtus
Purchased electricity	4,648,500 MWh
Derivatives not designated as hedging instruments:
Gas derivatives1	86,088,661 MMBtus
Electric generation fuel	58,295,000 MMBtus
Purchased electricity	2,417,000 MWh

________________

1 Gas derivatives are deferred in accordance with SFAS No. 71.

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

Where deemed appropriate, PSE may request collateral or other security from its counterparties to mitigate the potential credit default losses.  Criteria employed in this decision include, among other things, the perceived creditworthiness of the counterparty and the expected credit exposure. 

PSE monitors counterparties’ credit standing, including those 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.

It is possible that volatility in energy commodity prices could cause PSE to have material credit risk exposures with one or more counterparties.  If such counterparties fail to perform their obligations under one or more agreements, PSE could suffer a material financial loss.  However, as of June 30, 2009, approximately 99.9% of PSE’s energy portfolio exposure, excluding NPNS transactions, is with counterparties that are rated at least investment grade by the major rating agencies and 0.1% are either rated below investment grade or are not rated by rating agencies.  PSE assesses credit risk internally for counterparties that are not rated.

PSE generally executes commodity transactions with its counterparties pursuant to the terms of the following agreements:  (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.  These agreements allow the netting of payments, which PSE believes reduces credit exposure.

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

PSE applies the counterparty’s default factor to compute credit reserves for counterparties that are in a net asset position.  Moreover, PSE applies its own default factor to compute credit reserves for counterparties in a net liability position. PSE’s S&P rating at June 30, 2009 was BBB.  Credit reserves are booked as contra accounts to unrealized gain (loss) positions. As of June 30, 2009, PSE was in a net liability position with the majority of counterparties, so the default factors of counterparties did not have a significant impact on reserves for the year.  The majority of PSE’s derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council.

PSE enters into energy contracts with various credit-risk-related contingent features, which could result in a counterparty requesting immediate payment or demanding immediate and ongoing full overnight collateralization on derivative instruments in a net liability position.

The table below presents the fair value of the overall contractual contingent liability positions for PSE’s derivative activity at June 30, 2009:

Contingent Feature (Dollars in Millions)	Fair Value 4  Liability			Posted Collateral		Contingent Collateral
Credit rating 1	$	(3.5	)	$	--	$	3.5
Reasonable grounds for adequate assurance 2		(115.6	)		--		--
Forward value of contract 3		(46.1	)		20.0		N/A
Total	$	(165.2	)	$	20.0	$	3.5

_________________

1	PSE is required to maintain an investment grade credit rating from each of the major credit rating agencies.
2	A counterparty with reasonable grounds for insecurity regarding performance of an obligation may request adequate assurance of performance.
3	Collateral requirements may vary, based on changes in forward value of underlying transactions.
4	Represents derivative fair values of contracts with contingent features for counterparties in net derivative liability positions at June 30, 2009.  Excludes NPNS and accounts payable and accounts receivable activity.

(4)   Fair Value Measurements

SFAS No. 157, “Fair Value Measurements” (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, PSE 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.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  If a fair value measurement relies on inputs from different levels of the hierarchy, the entire measurement must be placed into the same level based on the lowest level input that is significant to the fair value measurement.   PSE’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 that not only include 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 PSE’s nonperformance risk on its liabilities.

As of June 30, 2009, PSE considers the markets for its electric and natural gas Level 2 derivative instruments to be actively traded.  Management’s assessment is based on the trading activity volume in real-time and forward electric and natural gas markets.  PSE regularly confirms the validity of pricing service quoted prices (e.g. Level 2 in the fair value hierarchy) used to value commodity contracts to the actual prices of commodity contracts entered into during the most recent quarter.

The following table sets forth by level within the fair value hierarchy PSE’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2009 and December 31, 2008:

Recurring Fair Value Measures	At Fair Value as of June 30, 2009								At Fair Value as of December 31, 2008
(Dollars in Millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets:
Energy derivative instruments	$	--	$	20.9	$	3.3	$	24.2	$	--	$	21.8	$	0.5	$	22.3
Money market accounts		19.5		5.7		--		25.2		24.7		--		1.4		26.1
Total assets	$	19.5	$	26.6	$	3.3	$	49.4	$	24.7	$	21.8	$	1.9	$	48.4
Liabilities:
Energy derivative instruments	$	--	$	258.6	$	140.0	$	398.6	$	--	$	261.2	$	134.1	$	395.3
Other financial items		--		--		--		--		--		--		--		--
Total liabilities	$	--	$	258.6	$	140.0	$	398.6	$	--	$	261.2	$	134.1	$	395.3

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 JUNE 30, 2009			Three Months Ended JUNE 30, 2008			Six Months Ended JUNE 30, 2009			Six Months Ended JUNE 30, 2008
Balance at beginning of period  (net credit reserve on energy derivatives)	$	(176.2	)	$	17.2		$	(132.2	)	$	(7.3	)
Changes during period :
Realized and unrealized energy derivatives
- included in earnings		6.6			3.5			4.2			1.9
- included in other comprehensive income		15.1			116.3			(38.0	)		145.0
- included in regulatory assets/liabilities		1.5			3.0			(5.9	)		3.0
Purchases, issuances, and settlements		8.0			7.7			16.1			5.9
Energy derivatives transferred in/(out) of Level 3		8.3			(0.3	)		19.1			(1.1	)
Balance at end of period (net credit reserve on energy derivatives)	$	(136.7	)	$	147.4		$	(136.7	)	$	147.4

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

Unrealized gains and losses for Level 3 inputs on energy derivatives recurring items are included in the net unrealized (gain) loss on derivative instruments section in PSE’s income statement and as net unrealized (gain) loss on derivative instruments in OCI.  PSE does not believe that the fair values diverge materially from the amounts PSE currently anticipates realizing on settlement or maturity.  Energy derivative instruments are classified as Level 3 in the fair value hierarchy because Level 3 inputs are significant to their fair value measurement.  Energy derivatives transferred out of Level 3 represent existing assets or liabilities that were classified as Level 3 at the end of the prior reporting period for which the lowest significant input became observable during the current reporting period. The net unrealized loss recognized during the reporting period is primarily due to a significant decrease in market prices.

(5)   Estimated Fair Value of Financial Instruments

The following table presents the carrying amounts and estimated fair values of PSE’s financial instruments at June 30, 2009 and December 31, 2008:

	June 30, 2009				December 31, 2008
(Dollars in Millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Financial assets:
Cash	$	43.5	$	43.5	$	38.5	$	38.5
Restricted cash		15.8		15.8		18.9		18.9
Notes receivable and other		72.8		72.8		71.8		71.8
Energy derivatives		24.2		24.2		22.3		22.3
Financial liabilities:
Short-term debt	$	125.0	$	125.0	$	964.7	$	964.7
Short-term debt owed by PSE to Puget Energy		22.9		22.9		26.1		26.1
Preferred stock subject to mandatory redemption		--		--		1.9		1.9
Junior subordinated notes		250.0		176.5		250.0		112.5
Current maturities of long-term debt (fixed-rate)		233.0		241.0		158.0		158.0
Non-current maturities of long-term debt (fixed-rate)		2,295.9		2,303.6		2,270.9		1,951.0
Energy derivatives		398.6		398.6		395.3		395.3

The carrying amount of equity securities is considered to be a reasonable estimate of fair value due to limited market pricing and based on the market value as reported by the fund manager.  The fair value of the senior secured notes was estimated using U.S. Treasury yields and related current market credit spreads, interpolating to the maturity date of each issue.  The fair value of the Junior subordinated notes was priced on a yield to call basis using a market price from an independent financial institution.

The fair value of the preferred stock subject to mandatory redemption as of December 31, 2008 was estimated based on a dealer quotes.  The carrying values of short-term debt and notes receivable are considered to be a reasonable estimate of fair value.  The carrying amount of cash, which includes temporary investments with original maturities of three months or less, is also considered to be a reasonable estimate of fair value.  PSE 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. 

(6)   Retirement Benefits

PSE 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.  Pension benefits earned are a function of age, salary and service.  PSE 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 June 30:

	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
(Dollars in Thousands)	2009			2008			2009		2008		2009			2008
Components of net periodic benefit cost:
Service cost	$	3,800		$	3,321		$	267	$	234	$	30		$	43
Interest cost		6,962			6,805			579		553		214			283
Expected return on plan assets		(10,972	)		(10,327	)		--		--		(116	)		(197	)
Amortization of net loss (gain)		1,043			472			221		183		(184	)		(199	)
Amortization of prior service cost		284			162			154		154		21			21
Amortization of transition obligation		--			--			--		--		12			13
Net periodic benefit cost (income)	$	1,117		$	433		$	1,221	$	1,124	$	(23	)	$	(36	)

The following table summarizes the net periodic benefit cost for the six months ended June 30:

	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
(Dollars in Thousands)	2009			2008			2009		2008		2009			2008
Components of net periodic benefit cost:
Service cost	$	7,071		$	6,375		$	534	$	468	$	62		$	87
Interest cost		13,867			13,304			1,157		1,105		480			566
Expected return on plan assets		(21,727	)		(20,782	)		--		--		(227	)		(394	)
Amortization of net loss (gain)		1,851			472			443		366		(230	)		(398	)
Amortization of prior service cost		567			323			308		308		41			42
Amortization of transition obligation		--			--			--		--		25			25
Net periodic benefit cost (income)	$	1,629		$	(308	)	$	2,442	$	2,247	$	151		$	(72	)

PSE expects to make contributions totaling $18.0 million to the qualified pension plan and $4.2 million related to its non-qualified pension plan for the year ending December 31, 2009.  During the three months ending June 30, 2009, PSE contributed $6.0 million to the qualified pension plan and $3.5 million to its non-qualified pension plan.  Employer contributions to other pension benefits totaled $0.6 million for the first six months of 2009 and represent retiree medical plan costs.  PSE anticipates retiree medical plan costs during the last half of 2009 will be paid from plan assets.

(7)   Regulation and Rates

On May 8, 2009, PSE filed a general rate case requesting recovery of increased electric and natural gas revenue requirements.  PSE is requesting an electric general rate increase of approximately $148.1 million or 7.4% annually, and an increase in natural gas rates of $27.2 million or 2.2% annually.  This rate request includes an equity component of 48.0% and a requested return on equity of 10.8%.  A final order from the Washington Commission is expected by April 2010.

On May 28, 2009, the Washington Commission approved a PGA rate decrease of $21.2 million or 1.7% annually effective June 1, 2009.  PGA rate changes do not impact net income.

On April 17, 2009, the Washington Commission issued an order approving and adopting a settlement agreement that authorized PSE to defer certain ownership and operating costs related to its purchase of the Mint Farm Generation Station (Mint Farm) that will be incurred prior to PSE recovering such costs in electric customer rates.  Under Washington State law, a jurisdictional electric utility may defer the costs associated with purchasing and operating a natural gas plant that complies with the greenhouse gases (GHG) emissions performance standard until the plant is included in rates or for two years from the date of purchase, whichever is earlier.  As of June 30, 2009, PSE had established a regulatory asset of $16.4 million per the Washington Commission order.  The prudence of the Mint Farm acquisition, recovery of costs of Mint Farm and compliance with the GHG emissions performance standard will be addressed in PSE’s general rate proceeding.

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 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 issued a separate order on January 15, 2009, that authorized the continuation of the Power Cost Only Rate Case (PCORC) with certain modifications to which the Washington Commission staff and PSE had agreed.  The five procedural modifications to the PCORC include extending the expected procedural schedule from five to six months, limiting the power cost updates to one per PCORC unless an additional update is allowed by the Washington Commission as part of the compliance filing, prohibiting the overlap of PCORC and general rate cases (except for requests for interim rate relief), shortening data request time from ten to five business days and requiring PSE to provide its future energy resource model projections at the outset of a case.

On September 25, 2008, the Washington Commission approved PSE’s requested revisions to its 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 impacted PSE’s revenue but will not impact its net income as the increased revenue will be offset by increased purchased gas costs.

(8)   Litigation

Residential Exchange.  Like other investor-owned utilities in the region, PSE has been a party to certain agreements with the Bonneville Power Administration (BPA) that provide payments to PSE which PSE passes through to its residential and small farm electric customers.  Several actions in the Ninth Circuit against BPA assert that BPA acted contrary to law in connection with this Residential Exchange Program (REP), including with respect to benefits received or to be received by PSE from BPA and the Ninth Circuit has directed BPA to revisit certain REP calculations relating to payments made in the 2001 to 2006 period.  PSE and BPA, separately, also have agreed to certain go-forward REP payment amounts through 2011 and have sought Ninth Circuit review of the agreements related thereto.  The amounts of such payments and the methods utilized in setting them are subject to FERC review or judicial review, or both, and are subject to adjustment, which may affect the amount of REP benefits paid or to be paid by BPA to PSE.  Although it is not clear what impact, if any, these reviews or other REP-related litigation may ultimately have on PSE, any changes to the REP payments pass through to customers with no impact to PSE’s net income.

PSE Settlement of California Matters.  On May 8, 2009, PSE and certain California parties filed a proposed settlement with FERC, that resolved all the matters and disputes pending between PSE and California parties relating to the Western Energy Crisis.  On July 1, 2009, FERC approved the settlement.

Under the settlement, PSE releases all claims to amounts held in—or presumed payable into—certain escrow accounts.  In particular, the California Power Exchange and Pacific Gas & Electric (PG&E) will deliver $59.9 million, plus up to $36.8 million in interest, from escrows they maintain to the California parties.  The release of those funds fully satisfies all claims by the California parties against PSE, and the California parties assume the risk of any shortfalls or adjustments that occur in those accounts.

The settlement resolves all claims by the California parties against PSE in all proceedings and resolves all claims by PSE against California energy purchasers in all proceedings; except that PSE retains any claims or defenses that pertain to the Pacific Northwest Refund Proceedings at FERC.

In addition to the FERC approval obtained on July 1, 2009, PSE’s settlement with the California parties was expressly conditioned upon two other actions: (1) the California Energy Commission approval as qualifying facilities under California renewable energy rules of PSE’s Wild Horse and Hopkins Ridge wind farms; and (2) the approval by the California Public Utilities Commission (CPUC) of a renewable power agreement between PSE and Southern California Edison (SCE), under which PSE will sell qualifying renewable power to SCE in 2009 and 2010.  PSE entered into the SCE contract in January 2009 and all required approvals for that contract were obtained by June 18, 2009.

Use of the proceeds from the renewable power transaction, for ratemaking and accounting purposes, will be determined by the Washington Commission.  PSE anticipates that it will receive full recovery of the net California receivable through this proceeding.

The settlement means that PSE’s exposure to Western Energy Crisis claims is now limited to the Pacific Northwest Refund Proceeding, described previously and updated below.

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.   In April 2009, the Ninth Circuit rejected the requests for rehearing filed in this matter and remanded the proceeding to FERC.  FERC is now considering what response to take to the Court remand order.  PSE intends to vigorously defend its position but is unable to predict the outcome of this matter.

(9)   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 lower of the weighted-average interest rate of: (a) PSE’s outstanding commercial paper interest rate or (b) PSE’s senior unsecured revolving credit facility.  At June 30, 2009 and December 31, 2008, the outstanding balance of the Note was $22.9 million and $26.1 million, respectively, and the interest rate was 1.2% and 1.7%, respectively.  This Note is unaffected by the February 6, 2009 merger.

(10)   Other

In January 2003, FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46), as further revised in December 2003 with FIN 46R, which clarifies the application of Accounting Research Bulletin No. 51, “Consolidated Financial Statements,” to certain entities in which equity investors do not have a controlling interest or sufficient equity at risk for the entity to finance its activities without additional financial support.

A variable interest entity (VIE) is an entity in which the equity of the investors as a group do not have: (1) the characteristics of a controlling financial interest; (2) sufficient equity at risk for the entity to finance its activities without additional subordinated financial support; or (3) symmetry between voting rights and economic interests and where substantially all of the entity’s activities either involve or are conducted on behalf of an investor with disproportionally few voting rights. Variable interests in a VIE are contractual, ownership or other pecuniary interests in an entity that change with changes in the fair value of the entity’s net assets exclusive of variable interest.

FIN 46R requires that if a business entity has a controlling financial interest in a VIE, the financial statements must be included in the consolidated financial statements of the business entity.  The adoption of FIN 46 for all interests in VIEs created after January 31, 2003 was effective immediately.  For VIEs created before February 1, 2003, it was effective July 1, 2003.  The adoption of FIN 46R was effective March 31, 2004 for PSE.

PSE evaluated its power purchase agreements and determined that two power purchase agreements may be considered significant VIEs under FIN 46R.  PSE is required to buy all the generation from the two plants, subject to displacement by PSE, at rates set forth in the relevant power purchase agreements.  As a result, PSE submitted requests for information to those parties; however, the parties have refused to submit to PSE the necessary information for PSE to determine whether they meet the requirements of a VIE that requires consolidation. PSE will continue to submit requests for information to the counterparties annually to determine if FIN 46R is applicable.  PSE’s purchased electricity expense for the three months ended June 30, 2009 and 2008 for these entities was $31.7 million and $36.9 million, respectively, and $79.1 million and $91.8 million for the six months ended June 30, 2009 and 2008, respectively.

In December 2008, FASB issued FIN 46R-8, “Disclosures by Public Entities (Enterprises) about Transfers of Financial Assets and Interests in Variable Interest Entities” (FIN 46R-8), which requires expanded disclosures for VIEs in the quarterly financial statements for periods ending after December 15, 2008.  The disclosures required by FIN 46R-8 are intended to provide users of the financial statements with greater transparency about a transferor’s continuing involvement with transferred financial assets and an enterprise’s involvement with VIEs.

A primary beneficiary of a VIE is the variable interest holder (e.g. a contractual counterparty or capital provider), who is deemed to have the controlling financial interest(s) and is considered to be exposed to the majority of the risks and rewards associated with the VIE and therefore must consolidate it.  PSE enters into a variety of contracts for energy with other counterparties and evaluates all contracts for variable interests.  PSE’s variable interests primarily arise through power purchase agreements where PSE obtains control other than through voting rights and is required to buy all or a majority of generation from a plant at rates set forth in a power purchase agreement, subject to displacement. If a counterparty does not deliver energy to PSE, PSE may have to replace the energy at prices which could be higher or lower than agreed to prices.  Therefore, PSE may be exposed to risk associated with replacement costs of a contract.

PSE evaluates variable interest relationships based on significance.  If PSE did not participate significantly in the design or redesign of an entity and the variable interest is not considered significant to PSE’s financial statements, the variable interest is not considered significant.  Purchase power contracts with governmental organizations do not require disclosure.  When PSE determines a significant variable interest may exist with another party, PSE requests information to determine if it is required to be consolidated.

The following table presents PSE’s VIE relationships, irrespective of significance, related to power purchase agreements as of June 30, 2009:

(Dollars in Millions)	Variable Interests in Power Purchase Agreements For the Quarter Ended June 30, 2009
Nature of Variable Interest	Longest Contract Tenor	Number of Counterparties		Aggregate Carrying Value Liability 2			Level of Activity - 2009 Expenses 2
Electric-combustion turbine co-generation plant 1	2011		2	$	(9.4	)	$	79.1
Electric-hydro	2037		7		(1.6	)		6.4
Other	2011		2		--			0.2
Total			11	$	(11.0	)	$	85.7

_____________

1	Variable interests may be significant.
2	Carrying values are classified in the balance sheet in accounts payable and expenses are classified on the income statement in purchased electricity.

Snoqualmie Falls Project

PSE received a new 40-year operating license for its Snoqualmie Falls hydroelectric project from the Federal Energy Regulatory Commission (FERC) in 2004.  The license contained an array of FERC-approved plans to upgrade the facility.  Due to changed circumstances, on December 6, 2007, PSE filed an application for a non-capacity amendment to the license to account for technology improvements and hydrologic and other changes.  On June 1, 2009, FERC issued an order amending the license that incorporates the changes requested by PSE.  This order is final and no party sought rehearing or review.

(11)   New Accounting Pronouncements

In June 2009, FASB issued, “Accounting Standards Update No. 2009-1, Topic 105 – Generally Accepted Accounting Principles amendments based on the Statement of Financial Standards No. 168 – The FASB Accounting Standard Codifications and the Hierarchy of Generally Accepted Accounting Principles and Statement of Financial Accounting Standard No. 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles, a replacement of FASB Statement No. 62.”  The Accounting Standards Update and SFAS No. 168 make the FASB Codification the authoritative source of GAAP.  The FASB Codification is effective for interim and annual reporting periods ending after September 15, 2009, which will be September 30, 2009 for PSE.  PSE will update GAAP referencing for the third quarter 2009 Form 10-Q.  The FASB Codification is not expected to have a material impact on financial reporting of PSE.

In June 2009, FASB issued Statement of Financial Accounting Standard No. 167, “Amendments to FASB Interpretation No. 46 (R)” (SFAS No. 167).  This Statement replaces a quantitative approach with a qualitative approach to determine whether PSE’s variable interest or interests give it a controlling financial interest in a VIE.  In addition, the Statement requires enhanced disclosures which will provide users of the financial statements with more transparent information about an enterprises involvement in a VIE.  The Statement is effective for the first annual reporting period beginning after November 15, 2009 and for interim periods within that first annual reporting period, which will be the period ending March 31, 2010 for PSE.  PSE is assessing the impact of this Statement.

In May 2009, FASB issued SFAS No. 165, “Subsequent Events” (SFAS No. 165).  The standard does not require significant changes regarding recognition or disclosure of subsequent events but does require disclosure of the date through which subsequent events have been evaluated for disclosure and recognition.  The standard is effective for financial statements issued after June 15, 2009 which was the quarter ended June 30, 2009.  The implementation of this standard did not have a significant impact on the financial statements of PSE.  PSE has performed an evaluation of subsequent events through July 28, 2009, which is the date the financial statements were issued.

On April 9, 2009, FASB issued Staff Position (FSP) 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (FSP No. 157-4).  FSP No. 157-4 became effective for PSE as of June 30, 2009.  FSP No. 157-4 provides additional guidance for estimating fair value in accordance with SFAS No. 157, when the volume and level of activity for the asset or liability have significantly decreased. FSP No. 157-4 also includes guidance on identifying circumstances that indicate a transaction is not orderly.  As of June 30, 2009, PSE has determined that FSP No. 157-4 has no impact to its consolidated financial position or results of operations. 

On December 30, 2008, FASB issued FSP No. 132(R) -1, “Employers’ Disclosures about Postretirement Benefit Plan Assets” (FSP No. 132(R)-1).  FSP No. 132(R)-1 directs companies to provide additional disclosures about plan assets of a defined benefit pension or other postretirement plan.  The objectives of the disclosures are  to disclose the following: (1)  how investment allocation decisions are made, including the factors that are pertinent to an understanding of investment policies and strategies, (2) major categories of plan assets, (3) inputs and valuation techniques used to measure the fair value of plan assets, (4) effect of fair value measurements using significant unobservable inputs (Level 3) on changes in plan assets for the period and (5) significant concentrations of risk within plan assets.  FSP No. 132(R)-1 is effective for the fiscal year December 15, 2009, which will be effective for PSE for the fiscal year end December 31, 2009.  PSE is currently assessing the impact of FSP No. 132(R)-1.

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

The following discussion of PSE’s financial condition and results of operations contains forward-looking statements that involve risks and uncertainties, such as statements of PSE’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.  PSE’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 Sound Energy, Inc. (PSE) is a subsidiary of Puget Energy, Inc. (Puget Energy), an energy services holding company incorporated in the state of Washington in 1999.  On February 6, 2009, Puget Holdings LLC (Puget Holdings) completed its merger with Puget Energy.  PSE’s basis of accounting will continue to be on a historical basis and PSE’s financial statements will not include any Statement of Financial Accounting Standards (SFAS) No. 141R, “Business Combinations” purchase accounting adjustments.

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.  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.  For 2009, PSE is experiencing lower customer usage due to warmer temperatures in 2009 as compared to 2008 and the effects of the recession on Washington State’s economy.

As a regulated utility company, PSE is subject to Federal Energy Regulatory Commission (FERC) regulations, North American Electric Reliability Corporation (NERC) standards and Washington Utilities and Transportation Commission (Washington Commission) regulations which affects a wide array of business activities, including regulating 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 attainment of PSE’s business objectives.  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 non-owned 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 and 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 energy needs 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 draft 2009 Integrated Resource Plan (IRP) (to be filed by the end of July 2009) 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.  The IRP suggests that PSE develop another 1,200 megawatts (MWs) of wind power by 2029, which would ensure PSE’s compliance with the Washington State Energy Independence and Security Act.

Colstrip Unit 4 has been out of service since March 2009 due to significant repair work required to the unit which was discovered during its routine overhaul.  It is estimated that the unit will be out of service until early-November 2009 and that PSE will incur higher power costs of approximately $16.0 million from July through October 2009.  PSE has a 25.0% ownership interest in the 370 MW electric generating facility.  The Colstrip owners are assessing the need to inspect and/or repair Colstrip Unit 3 based on the causes of the Colstrip Unit 4 repairs.  No decision by the Colstrip owners has been made at this time.

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 PSE’s operating performance.  Electric margin and gas margin are used by PSE to determine whether PSE is collecting the appropriate amount of energy costs from its customers to allow recovery of operating costs.  PSE’s electric margin and gas margin measures may not be comparable to other companies’ electric margin and gas margin measures.  Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.

Results of Operations

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.

Net income for the three months ended June 30, 2009 was $43.8 million on operating revenues of $686.3 million as compared to net income of $39.1 million on operating revenues of $712.4 million for the same period in 2008.  Net income was positively impacted by a $5.0 million pre-tax increase in electric margin and partially offset by a $2.3 million pre-tax decrease in gas margin.  Electric and natural gas margins were favorably impacted by general tariff rate increases of 7.1% and 4.6%, respectively, that were approved by the Washington Commission and were effective November 1, 2008.  Electric and natural gas margins were impacted by lower customer usage which declined 4.8% and 16.0%, respectively.  Electric margin was also impacted due to the extended Colstrip outage which resulted in the purchase of electricity priced approximately $2.0 million higher than Colstrip production cost.  Net income was negatively impacted by an increase in utility operations and maintenance expenses of $5.7 million, a $2.6 million increase in taxes other than income taxes and an increase in depreciation and amortization of $6.1 million.  These decreases to electric margin were partially offset by an increase in unrealized gains related to derivatives of $7.6 million primarily driven by warmer temperatures in the Pacific Northwest during the second quarter of 2009 as compared to the same period of 2008.  Also adversely impacting 2009 revenue is the impact of a weaker economy.

Net income for the six months ended June 30, 2009 was $128.8 million on operating revenues of $1.8 billion as compared to net income of $120.0 million on operating revenues of $1.8 billion for the same period in 2008.  Net income for the six months ended June 30, 2009 as compared to the same period in 2008 was positively impacted by a $31.1 million pre-tax increase in electric margin and a $9.9 million pre-tax increase in gas margin.  Electric and natural gas margins were favorably impacted by general tariff rate increases of 7.1% and 4.6%, respectively, that were approved by the Washington Commission and were effective November 1, 2008.  Electric and natural gas margins were impacted by lower customer usage which declined 2.4% and 6.7%, respectively.  Electric margin was also impacted due to the extended Colstrip outage which resulted in purchasing higher priced electricity than the Colstrip production cost.

Net income was negatively impacted by one-time merger costs of $23.9 million related to the merger of Puget Energy with Puget Holdings.  These costs were primarily related to PSE employee compensation triggered by the Puget Energy’s change of control, credit agreement related expenses and the income statement impact of deferred compensation related liability increases triggered by the merger.  Net income was also negatively impacted due to an increase in depreciation and amortization of $12.1 million and an increase of $8.4 million in utility operations and maintenance.  These increases were partially offset by a $5.3 million increase in unrecognized gain on derivatives.

Energy Margins

The following table displays the details of electric margin changes for the three months ended June 30, 2009 as compared to the same period in 2008.  Electric margin is electric sales to retail and transportation customers less pass-through tariff items, revenue-sensitive taxes, and the cost of generating and purchasing electric energy sold to customers, including transmission costs to bring electric energy to PSE’s service territory.

	Electric Margin
(Dollars in Millions) Three Months Ended June 30,	2009			2008			Change			Percent Change
Electric operating revenue1	$	456.8		$	478.0		$	(21.2	)		(4.4	) %
Less: Other electric operating revenue		(6.9	)		(20.3	)		13.4			66.0
Add: Other electric operating revenue-gas supply resale		(5.0	)		8.3			(13.3	)		*
Total electric revenue for margin		444.9			466.0			(21.1	)		(4.5	)
Adjustments for amounts included in revenue:
Pass-through tariff items		(14.9	)		(16.2	)		1.3			8.0
Pass-through revenue-sensitive taxes		(33.6	)		(32.9	)		(0.7	)		(2.1	)
Net electric revenue for margin		396.4			416.9			(20.5	)		(4.9	)
Minus power costs:
Purchased electricity1		(188.9	)		(198.9	)		10.0			5.0
Electric generation fuel1		(17.8	)		(32.7	)		14.9			45.6
Residential exchange1		20.9			20.3			0.6			3.0
Total electric power costs		(185.8	)		(211.3	)		25.5			12.0
Electric margin2	$	210.6		$	205.6		$	5.0			2.4	%

______________

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 $5.0 million for the three months ended June 30, 2009 as compared to the same period in 2008.  Electric margin increased $16.8 million due to a general rate case increase of 7.1% effective November 1, 2008.  This increase was partially offset by a $10.2 million decrease in margin due to a 4.8% decrease in retail kilowatt hour (kWh) sales as a result of decreased customer usage and a $1.6 million decrease in other items due primarily to an increase in purchase power costs related to the aforementioned outage at a Colstrip generating unit which is undergoing major repair and lower hydroelectric generation as compared to 2008.

The following table displays the details of electric margin changes for the six months ended June 30, 2009 as compared to the same period in 2008.  Electric margin is electric sales to retail and transportation customers less pass-through tariff items, revenue-sensitive taxes, and the cost of generating and purchasing electric energy sold to customers, including transmission costs to bring electric energy to PSE’s service territory.

	Electric Margin
(Dollars in Millions) Six Months Ended June 30,	2009			2008			Change			Percent Change
Electric operating revenue1	$	1,057.0		$	1,084.2		$	(27.2	)		(2.5	) %
Less: Other electric operating revenue		(7.8	)		(32.5	)		24.7			76.0
Add: Other electric operating revenue-gas supply resale		(13.8	)		11.0			(24.8	)		*
Total electric revenue for margin		1,035.4			1,062.7			(27.3	)		(2.6	)
Adjustments for amounts included in revenue:
Pass-through tariff items		(36.6	)		(29.1	)		(7.5	)		(25.8	)
Pass-through revenue-sensitive taxes		(77.9	)		(74.6	)		(3.3	)		(4.4	)
Net electric revenue for margin		920.9			959.0			(38.1	)		(4.0	)
Minus power costs:
Purchased electricity1		(449.2	)		(471.7	)		22.5			4.8
Electric generation fuel1		(66.0	)		(79.7	)		13.7			17.2
Residential exchange1		53.3			20.3			33.0			*
Total electric power costs		(461.9	)		(531.1	)		69.2			13.0
Electric margin2	$	459.0		$	427.9		$	31.1			7.3	%

______________

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 $31.1 million for the six months ended June 30, 2009 as compared to the same period in 2008.  The increase in electric margin was primarily due to a general tariff rate increase of 7.1% or $40.0 million.  This increase was partially offset by a decrease in margin due to a 2.4% decrease in retail kWh sales and increased costs due to the Colstrip outage and a 7.3% decline in hydroelectric generation for the six months ended June 30, 2009 as compared to the same period in 2008.

The following table displays the details of gas margin changes for the three months ended June 30, 2009 as compared to the same period in 2008.  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 June 30,	2009			2008			Change			Percent Change
Gas operating revenue1	$	226.9		$	233.8		$	(6.9	)		(3.0	) %
Less: Other gas operating revenue		(5.2	)		(4.2	)		(1.0	)		(23.8	)
Total gas revenue for margin		221.7			229.6			(7.9	)		(3.4	)
Adjustments for amounts included in revenue:
Pass-through tariff items		(2.5	)		(2.3	)		(0.2	)		(8.7	)
Pass-through revenue-sensitive taxes		(20.1	)		(20.3	)		0.2			0.1
Net gas revenue for margin		199.1			207.0			(7.9	)		(3.8	)
Minus purchased gas costs1		(132.1	)		(137.7	)		5.6			4.1
Gas margin2	$	67.0		$	69.3		$	(2.3	)		(3.3	)%

____________________

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 decreased $2.3 million for the three months ended June 30, 2009 compared to the same period in 2008.  There was a 16.0% decrease in gas therm sales related to warmer temperatures in 2009 as compared to the same period in 2008 which contributed to a $12.5 million decrease to margin. This decrease was partially offset by a general rate case increase of 4.6% effective November 1, 2008 which contributed to a $7.2 million increase in margin as well as customer mix and other pricing variances contributed to a $3.0 million increase.

The following table displays the details of gas margin changes for the six months ended June 30, 2009 as compared to the same period in 2008.  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) Six Months Ended June 30,	2009			2008			Change			Percent Change
Gas operating revenue1	$	733.4		$	677.1		$	56.3			8.3	%
Less: Other gas operating revenue		(10.2	)		(8.9	)		(1.3	)		(14.6	)
Total gas revenue for margin		723.2			668.2			55.0			8.2
Adjustments for amounts included in revenue:
Pass-through tariff items		(7.2	)		(6.7	)		(0.5	)		(7.5	)
Pass-through revenue-sensitive taxes		(61.7	)		(55.4	)		(6.3	)		(11.4	)
Net gas revenue for margin		654.3			606.1			48.2			8.0
Minus purchased gas costs1		(452.2	)		(413.9	)		(38.3	)		(9.3	)
Gas margin2	$	202.1		$	192.2		$	9.9			5.2	%

____________________

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 $9.9 million for the six months ended June 30, 2009 as compared to the same period in 2008 primarily due to a $27.7 million increase in margin primarily due to the general tariff rate increase of 4.6% effective November 1, 2008.  This increase was partially offset by a $12.8 million decrease in margin due to a 6.7% decrease in gas therm volume due to warmer weather in 2009 as compared to 2008 and a $5.0 million decrease due to customer mix and other pricing variances.

Electric Operating Revenues

The table below sets forth changes in electric operating revenues for PSE for the three months ended June 30, 2009 as compared to the same period in 2008.

(Dollars in Millions) Three Months Ended June 30,	2009			2008			Change			Percent Change
Electric operating revenues:
Residential sales	$	240.4		$	237.1		$	3.3			1.4	%
Commercial sales		198.0			189.4			8.6			4.5
Industrial sales		23.9			26.1			(2.2	)		(8.4	)
Other retail sales, including unbilled revenue		(25.7	)		(20.7	)		(5.0	)		(24.2	)
Total retail sales		436.6			431.9			4.7			1.1
Transportation sales		2.3			1.4			0.9			64.3
Sales to other utilities and marketers		10.9			24.4			(13.5	)		(55.3	)
Other		7.0			20.3			(13.3	)		(65.5	)
Total electric operating revenues	$	456.8		$	478.0		$	(21.2	)		(4.4	)%

Electric retail sales increased $4.7 million for the three months ended June 30, 2009 as compared to the same period in 2008.  The increase was due in part to the electric general rate increase of November 1, 2008 partially offset by a merger rate credit effective February 13, 2009, which combined, contributed to an increase in electric retail sales of $29.5 million for 2009 as compared to 2008.  This increase was partially offset by a $2.2 million decrease in the conservation rider charged to customers for PSE’s energy efficiency programs, which has no impact on net income as the amount is offset in conservation amortization.  Also partially offsetting these increases was a decrease in retail electricity usage of 243,899 megawatt hours (MWhs) or 4.8% related to decreased customer usage for 2009 as compared to the same period in 2008, which resulted in a decrease of approximately $22.2 million to electric operating revenue.  The benefits of the Residential and Farm Energy Exchange Benefit credited to customers reduced electric operating revenues by $0.7 million.  This credit also reduced power costs and revenue sensitive taxes by a corresponding amount with no impact on earnings.

Sales to other utilities and marketers decreased $13.5 million for the three months ended June 30, 2009 as compared to the same period in 2008 primarily due to a decrease in wholesale electric energy prices and a 7.5% decline in kWh volumes.

Other electric operating revenues decreased $13.3 million for the three months ended June 30, 2009 as compared to the same period in 2008 primarily due to a decrease of $13.7 million in non-core gas sales and related losses from hedging contracts entered into to manage electric generation fuel costs.

The table below sets forth changes in electric operating revenues for PSE for the six months ended June 30, 2009 as compared to the same period in 2008.

(Dollars in Millions) Six Months Ended June 30,	2009			2008			Change			Percent Change
Electric operating revenues:
Residential sales	$	599.2		$	583.7		$	15.5			2.7	%
Commercial sales		429.5			401.5			28.0			7.0
Industrial sales		50.5			53.5			(3.0	)		(5.6	)
Other retail sales, including unbilled revenue		(55.1	)		(32.3	)		(22.8	)		(70.6	)
Total retail sales		1,024.1			1,006.4			17.7			1.8
Transportation sales		4.8			2.9			1.9			65.5
Sales to other utilities and marketers		20.3			42.4			(22.1	)		(52.1	)
Other		7.8			32.5			(24.7	)		(76.0	)
Total electric operating revenues	$	1,057.0		$	1,084.2		$	(27.2	)		(2.5	)%

Electric retail sales increased $17.7 million for the six months ended June 30, 2009 as compared to the same period in 2008.  The increase was due in part to the electric general rate increase of November 1, 2008 partially offset by a merger rate credit effective February 13, 2009, which combined, contributed to an increase in electric retail sales of $70.6 million for 2009 as compared to 2008.  Also positively impacting retail sales is $5.3 million related to an increase in the conservation rider charged to customers due to an increase in PSE’s energy efficiency programs, which has no impact on net income as the amount is offset in conservation amortization.

This increase was partially offset by the benefits of the Residential and Farm Energy Exchange Benefit credited to customers which reduced electric operating revenues by $34.6 million.  This credit also reduced power costs and revenue sensitive taxes by a corresponding amount with no impact on earnings.  Also partially offsetting these increases was a decrease in retail electricity usage of 274,245 MWhs or 2.4% related to decreased customer usage for 2009 as compared to the same period in 2008, which resulted in a decrease of approximately $25.2 million to electric operating revenue.

Sales to other utilities and marketers decreased $22.1 million for the six months ended June 30, 2009 as compared to the same period in 2008 primarily due to a decrease in wholesale electric energy prices and a 4.2% decline in kWh volumes.

Other electric operating revenues decreased $24.7 million for the six months ended June 30, 2009 as compared to the same period in 2008 primarily due to $24.9 million decrease in non-core gas sales and related losses from hedging contracts entered into to manage electric generation fuel costs.

The following electric rate changes were approved by the Washington Commission in 2008 and 2009:

Type of Rate Adjustment	Effective Date	Average Percentage Increase (Decrease) in Rates			Annual Increase (Decrease)  in Revenues (Dollars in Millions)
Electric General Rate Case	November 1, 2008		7.1	%	$	130.2
Merger Rate Credit	February 13, 2009		(0.4	)%		(6.7	)

Gas Operating Revenues

The table below sets forth changes in gas operating revenues for PSE for the three months ended June 30, 2009 as compared to the same period in 2008.

(Dollars in Millions) Three Months Ended June 30,	2009		2008		Change			Percent Change
Gas operating revenues:
Residential sales	$	142.1	$	144.3	$	(2.2	)		(1.5	) %
Commercial sales		68.1		72.1		(4.0	)		(5.5	)
Industrial sales		8.3		9.7		(1.4	)		(14.4	)
Total retail sales		218.5		226.1		(7.6	)		(3.4	)
Transportation sales		3.1		3.4		(0.3	)		(8.8	)
Other		5.3		4.3		1.0			23.3
Total gas operating revenues	$	226.9	$	233.8	$	(6.9	)		(3.0	) %

Gas retail sales decreased $7.6 million for the three months ended June 30, 2009 as compared to the same period in 2008 primarily due to a 35.4 million decrease in gas therm sales related to warmer temperatures for the three months ended June 30, 2009 as compared to the same period in 2008, which decreased revenue by $50.4 million.  Partially offsetting the decrease is a $43.0 million increase in gas operating revenues as a result of a 11.1% Purchased Gas Adjustment (PGA) mechanism rate increase for retail customers effective October 1, 2008, a general rate increase effective November 1, 2008 and a 1.7% PGA mechanism rate decrease effective June 1, 2009.  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.

The table below sets forth changes in gas operating revenues for PSE for the six months ended June 30, 2009 as compared to the same period in 2008.

(Dollars in Millions) Six Months Ended June 30,	2009		2008		Change			Percent Change
Gas operating revenues:
Residential sales	$	486.3	$	438.5	$	47.8			10.9	%
Commercial sales		207.6		200.0		7.6			3.8
Industrial sales		23.0		22.5		0.5			2.2
Total retail sales		716.9		661.0		55.9			8.5
Transportation sales		6.3		7.2		(0.9	)		(12.5	)
Other		10.2		8.9		1.3			14.6
Total gas operating revenues	$	733.4	$	677.1	$	56.3			8.3	%

Gas retail sales increased $55.9 million for the six months ended June 30, 2009 as compared to the same period in 2008 due to a $105.1 million increase in gas operating revenues as a result of a 11.1% PGA mechanism rate increase for retail customers effective October 1, 2008, a general rate increase effective November 1, 2008 and a 1.7% PGA mechanism rate decrease effective June 1, 2009.  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.  Partially offsetting the increase is 36.4 million decrease in gas therm sales which decreased revenue by $49.9 million.

The following natural gas rate adjustments were approved by the Washington Commission in 2008 and 2009:

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
General Rate Case	November 1, 2008		4.3	%		49.2
Merger Rate Credit	February 13, 2009		(0.4	)%		(3.6	)
Purchased Gas Adjustment	June 1, 2009		(1.7	)%		(21.2	)

Non-Utility Operating Revenues

The table below sets forth changes in non-utility operating revenues for PSE for the three and six months ended June 30, 2009 as compared to the same period in 2008.

(Dollars in Millions) Three Months Ended June 30,	2009		2008		Change		Percent Change
Non-utility operating revenue	$	2.6	$	0.5	$	2.1	*

___________

* Percent change not applicable or meaningful.

(Dollars in Millions) Six Months Ended June 30,	2009		2008		Change		Percent Change
Non-utility operating revenue	$	3.5	$	2.1	$	1.4		66.7	%

Non-utility operating revenues increased $2.1 million and $1.4 million for the three and six months ended June 30, 2009, respectively, as compared to the same period in 2008 due to higher property sales during 2009 as compared to the same period in 2008 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 June 30, 2009 as compared to the same period in 2008.

(Dollars in Millions) Three Months Ended June 30,	2009			2008			Change			Percent Change
Purchased electricity	$	188.9		$	198.9		$	(10.0	)		(5.0	) %
Electric generation fuel		17.8			32.7			(14.9	)		(45.6	)
Purchased gas		132.1			137.7			(5.6	)		(4.1	)
Unrealized gain on derivative instruments		(9.9	)		(2.4	)		(7.5	)		*
Utility operations and maintenance		122.1			116.5			5.6			4.8
Merger and related costs		(3.7	)		--			(3.7	)		*
Depreciation and amortization		82.4			76.3			6.1			8.0
Taxes other than income taxes		66.7			63.7			3.0			4.7

___________

* Percent change not applicable or meaningful.

The table below sets forth significant changes in operating expenses for PSE and its subsidiaries for the six months ended June 30, 2009 as compared to the same period in 2008.

(Dollars in Millions) Six Months Ended June 30,	2009			2008			Change			Percent Change
Purchased electricity	$	449.2		$	471.7		$	(22.5	)		(4.8	) %
Electric generation fuel		66.0			79.7			(13.7	)		(17.2	)
Residential exchange		(53.3	)		(20.3	)		(33.0	)		*
Purchased gas		452.2			413.9			38.3			9.3
Unrealized gain on derivative instruments		(7.6	)		(2.3	)		(5.3	)		*
Utility operations and maintenance		237.0			228.6			8.4			3.7
Merger and related costs		23.9			--			23.9			*
Depreciation and amortization		163.7			151.7			12.0			7.9
Conservation amortization		34.6			28.9			5.7			19.7
Taxes other than income taxes		168.0			158.0			10.0			6.3

___________

* Percent change not applicable or meaningful.

Purchased electricity expenses decreased $10.0 million and $22.5 million for the three and six months ended June 30, 2009 as compared to the same period in 2008.  The decrease for the three months ended June 30, 2009 was primarily the result of lower wholesale market prices and a decrease of 1.1% in energy purchased reflecting lower customer energy demands.  The decrease for the six months ended June 30, 2009 was also the result of lower wholesale market prices and a 3.4% decrease in the volume of energy purchased.

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 fuelexpense decreased $14.9 million and $13.7 million for the three and six months ended June 30, 2009, respectively, as compared to the same period in 2008.  The decrease for the three months ended June 30, 2009 was due in part to decreased generation from Goldendale and Frederickson combustion turbines which contributed $6.1 million and $4.0 million, respectively.  There was a decrease in fuel expense of $4.0 million primarily due to the outage of Colstrip Unit 4 during the second quarter.  The unit was taken offline in March 2009 to conduct maintenance and repair and is expected to return to service in November 2009.  The decrease for the six months ended June 30, 2009 was primarily due to lower cost of natural gas in 2009 as compared to 2008.

Residential exchange credits associated with the Bonneville Power Administration (BPA) Residential Exchange Program (REP) increased $33.0 million for the six months ended June 30, 2009 as a result of an agreement with BPA to continue to pass on REP benefits to PSE’s customers.  REP does not have an impact on net income.

Purchased gas expenses decreased $5.6 million and increased $38.3 million for the three and six months ended June 30, 2009, respectively, as compared to the same period in 2008 primarily due to an increase of 11.1% in PGA rates effective October 1, 2008 offset by a 1.7% PGA rate decrease effective June 1, 2009 which provides the rates used to determine gas costs based on customer usage.  The rate increase was the result of declining costs of natural gas wholesale costs and a reduction of the credit for accumulated PGA payable balance.  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 June 30, 2009 was $62.9 million as compared to $8.9 million at December 31, 2008.  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.

Unrealized gain on derivative instruments increased $7.5 million and $5.3 million forthe three and six months ended June 30, 2009, respectively, as compared to the same period in 2008.  For the three months ended June 30, 2009, the increase was primarily related to a reversal of unrealized losses on gas for power financial contracts.  The reversal of losses was primarily related to increases in the forward market price of natural gas from March 31, 2009.  The increase for the six months ended June 30, 2009 was primarily due to increasing forward market prices of natural gas on gas for power financial contracts, which resulted in the reversal of losses previously recorded.

Utility operations and maintenance expense increased $5.6 million and $8.4 million for the three and six months ended June 30, 2009, respectively, as compared to the same period in 2008.  The increase for the three months ended June 30, 2009 was primarily due to an increase in customer service costs of $3.5 million, including increases in bad debt expense, electric generation operations and maintenance costs and gas operations and distribution expenses.  These increases were partially offset by a $1.5 million decrease in electric transmission and distribution costs.  The increase for the six months ended June 30, 2009 was driven by a $5.7 million increase in customer service expenses, which included increases in bad debt expense, salaries and benefits rent expense, and electric plant maintenance and a $2.4 million increase in gas operations costs offset by a $5.2 million decrease in production costs related to a reduction in operations at Colstrip and maintenance costs.

Merger and related costs associated with the merger with Puget Holdings incurred for the three and six months ended June 30, 2009 was $(3.7) million and $23.9 million, respectively.  For the three months ended June 30, 2009, the decrease relates to a revision to compensation costs as a result of the change in control.  For the six months ended June 30, 2009, the costs include compensation costs as a result of the change in control, write-off of deferred debt costs associated with the termination of the pre-merger credit facilities, expenses associated with new credit facilities and the impact of deferred compensation liabilities as a result of the merger.  Pursuant to the Washington Commission merger order commitments, PSE will not seek recovery of these costs.

Depreciation and amortization expense increased $6.1 million and $12.0 million for the three and six months ended June 30, 2009, respectively, as compared to the same period in 2008.  Excluding the regulatory credit for the deferral of Mint Farm fixed costs of $3.2 million and $7.0 million, depreciation and amortization expense increased $9.3 million and $19.0 million, respectively, for the three and six months ended June 30, 2009 as compared to the same period in 2008. This increase is due to additional depreciable property placed into service and an increase in storm amortization costs as approved in PSE’s general rate case effective November 1, 2008.

Conservation amortization increased $5.7 million for the six months ended June 30, 2009 as compared to the same period in 2008 due to lower recovery of conservation expenditures.  Conservation amortization is a pass-through tariff item with no impact on earnings.

Taxes other than income taxes increased $3.0 million and $10.0 million for the three and six months ended June 30, 2009, respectively, as compared to the same period in 2008 due to revenue sensitive taxes.

Other Income, Other Expenses and Interest Expense

The tables below set forth significant changes in other income, other expenses, interest expense and income tax expense for PSE and its subsidiaries for the three months and six months ended June 30, 2009 as compared to the same period in 2008.

(Dollars in Millions) Three Months Ended June 30,	2009		2008		Change		Percent Change
Other income / expense (net)	$	10.7	$	7.2	$	3.5		48.6	%

(Dollars in Millions) Six Months Ended June 30,	2009		2008		Change		Percent Change
Other income / expense (net)	$	18.2	$	13.1	$	5.1		38.9	%
Interest expense		99.2		95.8		3.4		3.5

Other income increased $3.5 million for the three months ended June 30, 2009 as compared to the same period in 2008 primarily due to an increase in regulatory interest income from Mint Farm of $4.5 million offset by penalties of $0.4 million in 2009 and a benefit in a penalty true-up in 2008 of $0.8 million.  The increase of $5.1 million for six months ended June 30, 2009 as compared to the same period in 2008 is primarily due to an increase in regulatory interest income from Mint Farm.

Interest expense increased $3.4 million for six months ended June 30, 2009 as compared to the same period in 2008 is primarily due to higher long-term debt rates and increased debt issuance amortization costs on the post–merger credit facilities.

Capital Requirements

Contractual Obligations and Commercial Commitments

The information provided in the contractual obligations table is incorporated herein by reference to the material under “Capital Requirements” in Item 7 “Management’s Discussion and Analysis of Financial Conditions and Results of Operations” in the combined Puget Energy and PSE annual report on Form 10-K.

The following are PSE’s aggregate consolidated commercial commitments as of June 30, 2009:

			Amount of Commitment Expiration Per Period
Commercial commitments (Dollars in Millions)	Total		2009			2010- 2011		2012- 2013	2014 & Thereafter
Working capital facility	$	275.0	$	--	$	--	$	--	$	275.0
Capital expenditure facility		400.0		--		--		--		400.0
Energy hedging facility		330.0		--		--		--		330.0
Energy hedging letter of credit		6.1		--		6.1		--		--
Total commercial commitments	$	1,011.1	$	--	$	6.1	$	--	$	1,005.0

Off-Balance Sheet Arrangements

Fredonia 3 and 4 Operating Lease.  PSE leases two gas-fired turbines for its Fredonia 3 and 4 generating facility pursuant to a master operating lease that was amended for this purpose in April 2001.  On November 14, 2008, GE Capital Commercial Inc. notified PSE of its intentions to cancel the lease effective January 14, 2009.  PSE has up to one year to complete the termination of the lease.  PSE expects to purchase the gas-fired turbines by January 2010.  Payments under the lease vary with changes in the London Interbank Offered Rate (LIBOR).  At June 30, 2009, PSE’s outstanding balance under the lease was $44.0 million.  The expected residual value under the lease is the lesser of $42.3 million or 60.0% of the cost 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 Allowance for Funds Used During Construction (AFUDC) and customer refundable contributions, was $358.6 million for the six months ended June 30, 2009.  The anticipated utility construction expenditures, excluding AFUDC, for 2009, 2010 and 2011 are:

Capital Expenditure Estimates (Dollars in Millions)	2009		2010		2011
Energy delivery, technology and facilities	$	687	$	840	$	786
New supply resources		234		621		346
Total expenditures	$	921	$	1,461	$	1,132

The proposed utility construction expenditures and any new generation resource expenditures that may be incurred are anticipated to be funded with a combination of sources that could include cash from operations, short-term debt, long-term debt and/or 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 six months ended June 30, 2009 was $511.0 million, a decrease of $7.6 million from the $518.6 million generated during the six months ended June 30, 2008.  The decrease was primarily the result of an increase of $104.3 million in natural gas payments and payment of gas financial hedge contracts, power cost and other payable balances as compared to the same period in 2008.  Further, PSE received a refund of $42.4 million in income taxes during the first six months of 2008 compared to a net payment of $0.1 million in 2009 which resulted in a decrease of $42.3 million.  Also contributing to the decrease in operating activities was a Colstrip legal settlement accrual of $10.5 million in 2008 and an increase in REP net payments made of $30.8 million over the same period in 2008.  PSE increased prepaid income taxes for the first six months of 2009 by $63.2 million compared to the same period in 2008.

The decrease in cash generated from operating activities for the first six months of 2009 as compared to the same period in 2008 was partially offset by overrecovery of natural gas costs through the PGA mechanism during the first six months of 2009 of $54.0 million compared to providing a refund of $51.1 million during the same period in 2008 which increased operating activities by $105.1 million.  In addition, PSE collected $83.2 million more in accounts receivable in 2009 over 2008 and recognized $29.7 million greater net deferred income taxes and tax credits during the six months ended June 30, 2009 as compared to the same period in 2008.

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 capital markets.  PSE anticipates refinancing the redemption of bonds with its liquidity facilities and/or the issuance of new bonds.  Access to funds depends upon factors such as general economic conditions, regulatory climate and policies, PSE’s credit ratings and investor receptivity to investing in the utility industry and PSE.

On January 23, 2009, PSE issued $250.0 million of first mortgage bonds.  The bonds were placed with approximately 35 institutional investors, have a term of seven years and carry a 6.75% interest rate.

Liquidity Facilities and Commercial Paper

PSE’s short-term borrowings and sales of commercial paper are used to provide working capital and funding of utility construction programs.  PSE has not been significantly impacted by the recent disruption in the credit environment.

PSE Credit Facilities

Credit Agreements.  Effective with the close of the merger, PSE has three committed unsecured revolving credit facilities that provide, in aggregate, $1.15 billion in short-term borrowing capability.  These new facilities include a $400.0 million credit agreement for working capital needs, a $400.0 million credit facility for funding capital expenditures and a $350.0 million facility to support energy hedging activities.

These facilities mature in February 2014 and each contain similar terms and conditions and are syndicated among numerous committed banks.  The agreements provide PSE with the ability to borrow at either a base rate (which is based on the Prime Rate) or the Eurodollar rate (which is based on the LIBOR), plus a spread.  PSE must also pay a commitment fee on the unused portion of the facilities.  The spread and the commitment fee depend on PSE’s credit ratings as determined by S&P and Moody’s credit ratings.  For PSE’s current credit ratings as of the date of this report the spread is 85 basis points and the commitment fee is 26 basis points.  The $400.0 million working capital facility and $350.0 million credit agreement to support energy hedging allow for the issuing of standby letters of credit up to the entire amount of the credit agreements.  The $400.0 million working capital facility also serves as a backstop for PSE’s commercial paper program.

As of June 30, 2009, PSE had borrowed $125.0 million on the $400.0 million working capital facility and had a $20.0 million letter of credit outstanding under the $350.0 million facility.  There were no borrowings under the $400.0 million capital expenditure facility as of June 30, 2009.  Outside of the credit agreements, PSE had a $6.6 million letter of credit through a bank in support of a long-term transmission contract.

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 or (b) PSE’s senior unsecured revolving credit facility.  At June 30, 2009, the outstanding balance of the Note was $22.9 million.  This Note was unaffected by the February 6, 2009 merger.

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 June 30, 2009, PSE could issue:

·   approximately $1.0 billion of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately $1.7 billion of electric bondable property available for issuance, subject to an interest coverage ratio limitation of 2.0 times net earnings available for interest (as defined in the electric utility mortgage), which PSE exceeded at June 30, 2009;

·   approximately $652.0 million of additional first mortgage bonds under PSE’s natural gas mortgage indenture based on approximately $1.1 billion 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 June 30, 2009;

At June 30, 2009, PSE had approximately $3.7 billion in electric and natural gas ratebase to support the interest coverage ratio limitation test for net earnings available for interest.

Credit Ratings

PSE has no 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-2/P-3 ratings by S&P and Moody’s.  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.

On January 16, 2009, S&P raised its corporate credit rating on PSE and removed it from its watch list for negative implications citing a stable outlook.  The rating actions reflected the anticipated completion of the acquisition of Puget Energy and PSE by Puget Holdings, which occurred on February 6, 2009.

On February 2, 2009, Moody’s affirmed the long-term ratings of PSE.  The ratings outlook for PSE is stable.

The ratings of PSE, as of July 24, 2009, were as follows:

	Ratings
	S&P1	Moody’s2
Puget Sound Energy, Inc.
Corporate credit/issuer rating	BBB	Baa3
Senior secured debt	A-	Baa2
Junior subordinated notes	BB+	Ba1
Preferred stock	BB+	Ba2
Commercial paper	A-2	P-3
Bank facilities	BBB	Baa3
Ratings outlook	Stable	Stable

_______________

1	On January 16, 2009, S&P upgraded PSE’s corporate and other credit ratings.  It also removed all the ratings from negative watch, citing a stable outlook.
2	On February 2, 2009, Moody’s affirmed the long-term ratings of PSE.

Other

Regulation and Rates

On May 8, 2009, PSE filed a general rate case requesting recovery of increased electric and natural gas revenue requirements.  PSE is requesting an electric general rate increase of approximately $148.1 million or 7.4% annually, and an increase in natural gas rates of $27.2 million or 2.2% annually.  This rate request includes an equity component of 48.0% and a requested return on equity of 10.8%.  A final order from the Washington Commission is expected by April 2010.

On May 28, 2009, the Washington Commission approved a PGA rate decrease of $21.2 million or 1.7% annually effective June 1, 2009.  PGA rate changes do not impact net income.

On April 17, 2009, the Washington Commission issued an order approving and adopting a settlement agreement that authorized PSE to defer certain ownership and operating costs related to its purchase of the Mint Farm that will be incurred prior to PSE recovering such costs in electric customer rates.  Under Washington state law, a jurisdictional electric utility may defer the costs associated with purchasing and operating a gas plant that complies with the greenhouse gases (GHG) emissions performance standard until the plant is included in rates or for two years from the date of purchase, whichever is earlier.  As of June 30, 2009, PSE had established a regulatory asset of $16.4 million per the Washington Commission order.  The prudence of the Mint Farm acquisition, recovery of costs of Mint Farm and compliance with the GHG emissions performance standard will be addressed in PSE’s general rate proceeding.

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 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 issued a separate order on January 15, 2009, that authorized the continuation of the Power Cost Only Rate Case (PCORC) with certain modifications to which the Washington Commission staff and PSE had agreed.  The five procedural modifications to the PCORC include extending the expected procedural schedule from five to six months, limiting the power cost updates to one per PCORC unless an additional update is allowed by the Washington Commission as part of the compliance filing, prohibiting the overlap of PCORC and general rate cases (except for requests for interim rate relief), shortening data request time from ten to five business days and requiring PSE to provide its future energy resource model projections at the outset of a case.

On September 25, 2008, the Washington Commission approved PSE’s requested revisions to its 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 impacted PSE’s revenue but will not impact its net income as the increased revenue will be offset by increased purchased gas costs.

Snoqualmie Falls Project

PSE received a new 40 year operating license for its Snoqualmie Falls hydroelectric project from the Federal Energy Regulatory Commission (FERC) in 2004.  The license contained an array of FERC-approved plans to upgrade the facility.  Due to changed circumstances, on December 6, 2007, PSE filed an application for a non-capacity amendment to the license to account for technology improvements and hydrologic and other changes.  On June 1, 2009, FERC issued an order amending the license that incorporates the changes requested by PSE.  This order is final and no party sought rehearing or review.

Proceedings Relating to the Western Power Market

The following discussion summarizes the status as of the date of this report of ongoing proceedings relating to the western power markets to which PSE is a party. PSE is vigorously defending the remaining claims. 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 will not materially and adversely affect PSE’s financial condition, results of operations or liquidity.

PSE Settlement of California Matters. On May 8, 2009, PSE and certain California parties filed a proposed settlement with FERC, that resolved all the matters and disputes pending between PSE and California parties relating to the Western Energy Crisis.  On July 1, 2009, FERC approved the settlement.

Under the settlement, PSE releases all claims to amounts held in, or presumed payable into, certain escrow accounts.  In particular, the California Power Exchange and Pacific Gas & Electric (PG&E) will deliver $59.9 million, plus up to $36.8 million in interest, from escrows they maintain to the California parties.  The release of those funds fully satisfies all claims by the California parties against PSE, and the California parties assume the risk of any shortfalls or adjustments that occur in those accounts.

The settlement resolves all claims by the California parties against PSE in all proceedings, and resolves all claims by PSE against California energy purchasers in all proceedings, except that PSE retains any claims or defenses that pertain to the Pacific Northwest Refund Proceedings at FERC.

In addition to the FERC approval obtained on July 1, 2009, PSE’s settlement with the California parties was expressly conditioned upon two other actions: (1) the California Energy Commission’s  approval as qualifying facilities under California renewable energy rules of PSE’s Wild Horse and Hopkins Ridge wind farms; and (2) the approval by the California Public Utility Commission (CPUC) of a renewable power agreement between PSE and Southern California Edison (SCE), under which PSE will sell qualifying renewable power to SCE in 2009 and 2010.  PSE entered into the SCE contract in January 2009, and all required approvals for that contract were obtained by June 18, 2009.

Use of the proceeds from the renewable power transaction, for ratemaking and accounting purposes, will be determined by the Washington Commission.  PSE anticipates that it will receive full recovery of the net California receivable through this proceeding.The settlement means that PSE’s exposure to Western Energy Crisis claims is now limited to the Pacific Northwest Refund Proceeding, described previously and updated below.

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.   In April, 2009, the Ninth Circuit rejected the requests for rehearing filed in this matter and remanded the proceeding to FERC.  FERC is now considering what response to take to the Court remand order.  PSE intends to vigorously defend its position but is unable to predict the outcome of this matter.

Proceedings Relating to the Bonneville Power Administration

Like other investor-owned utilities in the region, PSE has been a party to certain agreements with the BPA that provide payments to PSE which PSE passes through to its residential and small farm electric customers.  Several actions in the Ninth Circuit against BPA assert that BPA acted contrary to law in connection with this REP, including with respect to benefits received or to be received by PSE from BPA and the Ninth Circuit has directed BPA to revisit certain REP calculations relating to payments made in the 2001 to 2006 period.  PSE and BPA, separately, also have agreed to certain go-forward REP payment amounts through 2011 and have sought Ninth Circuit review of the agreements related thereto.  The amounts of such payments and the methods utilized in setting them are subject to FERC review or judicial review, or both, and are subject to adjustment, which may affect the amount of REP benefits paid or to be paid by BPA to PSE.  Although it is not clear what impact, if any, these reviews or other REP-related litigation may ultimately have on PSE, any changes to the REP payments pass through to customers with no impact to PSE’s net income.

New Accounting Pronouncements

In June 2009, FASB issued, “Accounting Standards Update No. 2009-1, Topic 105 – Generally Accepted Accounting Principles amendments based on the Statement of Financial Standards No. 168 – The FASB Accounting Standard Codifications and the Hierarchy of Generally Accepted Accounting Principles and Statement of Financial Accounting Standard No. 168, The FASB Accounting Standards Codification and the Hierarchy of GAAP, a replacement of FASB Statement No. 62.”  The Accounting Standards Update and SFAS No. 168 make the FASB Codification the authoritative source of GAAP.  The FASB Codification is effective for interim and annual reporting periods ending after September 15, 2009, which will be September 30, 2009 for PSE.  PSE will update GAAP referencing for the third quarter 2009 Form 10-Q.  The FASB Codification is not expected to have a material impact on financial reporting of PSE.

In June 2009, FASB issued Statement of Financial Accounting Standard No. 167, “Amendments to FASB Interpretation No. 46 (R).”  This Statement replaces a quantitative approach with a qualitative approach to determine whether the company’s variable interest or interests give it a controlling financial interest in a variable interest entity (VIE).  In addition, the Statement requires enhanced disclosures which will provide users of the financial statements with more transparent information about an enterprises involvement in a VIE.  The Statement is effective for the first annual reporting period beginning after November 15, 2009 and for interim periods within that first annual reporting period, which will be the period ending March 31, 2010 for PSE.  PSE is assessing the impact of this Statement.

In May 2009, FASB issued SFAS No. 165, “Subsequent Events” (SFAS No. 165).  The standard does not require significant changes regarding recognition or disclosure of subsequent events but does require disclosure of the date through which subsequent events have been evaluated for disclosure and recognition.  The standard is effective for financial statements issued after June 15, 2009 which was the quarter ended June 30, 2009.  The implementation of this standard did not have a significant impact on the financial statements of PSE.  PSE has performed an evaluation of subsequent events through July 28, 2009, which is the date the financial statements were issued.

On April 9, 2009, FASB issued Staff Position (FSP) 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (FSP No. 157-4).  FSP No. 157-4 became effective for PSE as of June 30, 2009.  FSP No. 157-4 provides additional guidance for estimating fair value in accordance with SFAS No. 157, when the volume and level of activity for the asset or liability have significantly decreased. FSP No. 157-4 also includes guidance on identifying circumstances that indicate a transaction is not orderly.  As of June 30, 2009, PSE has determined that FSP No. 157-4 has no impact to its consolidated financial position or results of operations. 

On December 30, 2008, FASB issued FSP No. 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets” (FSP No. 132(R)-1).  FSP No. 132(R)-1 directs companies to provide additional disclosures about plan assets of a defined benefit pension or other postretirement plan.  The objectives of the disclosures are to disclose the following: (1) how investment allocation decisions are made, including the factors that are pertinent to an understanding of investment policies and strategies, (2) major categories of plan assets, (3) inputs and valuation techniques used to measure the fair value of plan assets, (4) effect of fair value measurements using significant unobservable inputs (Level 3) on changes in plan assets for the period and (5) significant concentrations of risk within plan assets.  FSP No. 132(R)-1 is effective for the fiscal year December 15, 2009, which will be effective for PSE for the fiscal year end December 31, 2009.  PSE is currently assessing the impact of FSP No. 132(R)-1.

Item 3.            Quantitative and Qualitative Disclosure About Market Risk

Energy Portfolio Management

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

PSE is focused on commodity price exposure and risks associated with volumetric variability in the gas and electric portfolios and the related effects noted above.  It is not engaged in the business of assuming risk for the purpose of speculative trading.  PSE hedges open gas and electric positions to reduce both the portfolio risk and the volatility risk in prices.  The exposure position is determined by using a probabilistic risk system that models 250 simulations of how PSE’s 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 the energy portfolio prudently to serve retail load at overall least cost and limit undesired impacts on PSE’s customers and shareholders;

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

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

SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – An Amendment of Financial Accounting Standards Board (FASB) Statement No. 133” (SFAS No. 161), requires a significant amount of disclosure regarding PSE’s derivative activities and the nature of how such derivatives impact the company’s financial position, financial performance and cash flows.  Such detail should serve as an accompaniment to Management’s Discussion and Analysis (MD&A), which is located under Item 2 of this report.  Further, and as a result of the SFAS No. 161 disclosures, summary metrics that may be included in this MD&A discussion may be further expanded upon in the footnotes preceding the MD&A.

The following table presents a summary of the fair value of both electric and natural gas (used in both electric generation and in core gas sales) derivative instruments that do not meet the Normal Purchase Normal Sale (NPNS) exception at June 30, 2009 and December 31, 2008, including contracts designated as cash flow hedges:

Derivative Portfolio (Dollars in Millions)	June 30, 2009		December 31, 2008
Current asset	$	13.7	$	15.6
Long-term asset		10.5		6.7
Total assets	$	24.2	$	22.3
Current liability	$	275.4	$	236.9
Long-term liability		123.2		158.4
Total liabilities	$	398.6	$	395.3

If it is determined that it is uneconomical to operate PSE’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 recognition of future changes in value in the income statements.  As these contracts are settled, amounts previously deferred in other comprehensive income (OCI) are recognized as energy costs and are included as part of the Power Cost Adjustment (PCA) mechanism.  For further details regarding both the fair value of derivative instruments and the impacts such instruments have on current period earnings and OCI (for cash flow hedges), please see Note 3, “Accounting for Derivative Instruments and Hedging Activities.”

At June 30, 2009, PSE had total assets of $20.0 million and total liabilities of $154.0 million related to financial contracts used to economically hedge the cost of physical natural gas purchased to serve natural gas customers.  All fair value adjustments on derivatives 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 gas costs under the PGA mechanism.

A hypothetical 10.0% decrease in market prices of natural gas and electricity would decrease the fair value of derivative contracts by $102.2 million, with a corresponding after-tax decrease in other comprehensive income and earnings of $33.6 million and $0.7 million respectively related to derivatives designated as hedges, and would decrease the fair value of those contracts marked-to-market in earnings by $4.0 million after-tax related to derivatives not designated as hedges.  A discussion of the Level 3 valuation is included in Note 4, “Fair Value Measurements.”

Contingent Features and Counterparty Credit Risk

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

Where deemed appropriate, PSE may request collateral or other security from its counterparties to mitigate the potential credit default losses.  Criterion employed in this decision includes, among other things, the perceived creditworthiness of the counterparty and the expected credit exposure.  As of June 30, 2009, PSE held approximately $0.6 million worth of standby letters of credit in support of various electricity and renewable energy credit transactions.

It is possible that volatility in energy commodity prices could cause PSE to have material credit risk exposures with one or more counterparties.  If such counterparties fail to perform their obligations under one or more agreements, PSE could suffer a material financial loss.  However, as of June 30, 2009, approximately 96.7% of PSE’s energy portfolio exposure, including NPNS transactions, is with counterparties that are rated at least investment grade by the major rating agencies and 3.3% are either rated below investment grade or are not rated by rating agencies.  PSE assesses credit risk internally for counterparties that are not rated.

PSE has entered into commodity master arrangements with its counterparties to mitigate credit exposure to those counterparties.  PSE generally enters into the following master arrangements:  (1) Western Systems Power Pool agreements (WSPP) - standardized power sales contracts 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.  PSE believes that entering into such agreements reduces the risk of default by allowing a counterparty the ability to make only one net payment.

PSE monitors counterparties that are experiencing financial problems, have significant swings in credit default swap rates, have credit rating changes by external rating agencies, or have changes in ownership.  Counterparty credit risk impacts PSE’s decisions on derivative accounting treatment.  A counterparty may have a deterioration of credit below investment grade, potentially indicating that it is no longer probable that it will fulfill its obligations under a contract (e.g., make a physical delivery upon the contract’s maturity).  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 counterparty’s credit, PSE records the fair value of the contract on the balance sheet, with the corresponding amount 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, PSE would discontinue hedge accounting, record in earnings subsequent changes in the derivative’s fair value and freeze amounts previously accounted for in Accumulated OCI.  If the transaction is remote of occurring, any amounts previously accounted for in Accumulated OCI would be reclassified into earnings.

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

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

PSE applies the counterparty’s default factor to compute credit reserves for counterparties that are in a net asset position.  Moreover, PSE calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate.  The fair value of derivatives includes the impact of taking into account credit and non-performance reserves.  As of June 30, 2009, PSE was in a net liability position with the majority of counterparties,  so the default factors of counterparties did not have a significant impact on reserves for the year.

Interest Rate Risk

PSE believes its interest rate risk primarily relates to the use of short-term debt instruments, variable-rate notes and leases and anticipated long-term debt financing needed to fund capital requirements.  PSE manages its interest rate risk through the issuance of mostly fixed-rate debt of various maturities.  PSE utilizes bank borrowings, commercial paper and line of credit facilities 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.  PSE may enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts.  PSE did not have any swap instruments outstanding as of June 30, 2009; however from time to time PSE may enter into treasury lock or forward starting swap contracts to hedge interest rate exposure related to an anticipated debt issuance.  The ending balance in other comprehensive income related to the forward starting swaps and previously settled treasury lock contracts at June 30, 2009 is a net loss of $7.7 million after tax and accumulated amortization.  This compares to a loss of $7.9 million in other comprehensive income after-tax and accumulated amortization at December 31, 2008.  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 Sound Energy

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of PSE’s management, including the President and Chief Executive Officer and the 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 June 30, 2009, the end of the period covered by this report.  Based upon that evaluation, the 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 June 30, 2009, 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 “Other” of 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 PSE’s business exist at June 30, 2009.  Litigation is subject to numerous uncertainties and PSE is unable to predict the ultimate outcome of these matters.

Item 1A.           Risk Factors

There have been no material changes from the risk factors set forth in Part I, Item 1A in PSE’s Annual Report on Form 10-K for the year ended December 31, 2008.

Item 6.              Exhibits

See Exhibit Index for list of exhibits.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	PUGET SOUND ENERGY, INC.
	/s/ James W. Eldredge
	James W. Eldredge
	Vice President, Controller and Chief Accounting Officer
Date:  July 28, 2009
	Chief accounting officer and officer duly authorized to sign this report on behalf of registrant

EXHIBIT INDEX

The following exhibits are filed herewith:

12.1	Statement setting forth computation of ratios of earnings to fixed charges (2004 through 2008 and 12 months ended June 30, 2009) for PSE.
31.1	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.
31.2	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.