10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2010

OR

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

For the transition period from ___________ to ___________

    Commission File Number Exact name of registrant as specified in its charter, state of incorporation, address of principal executive offices, zip code telephone number I.R.S. Employer Identification Number

1-16305 PUGET ENERGY, INC. A Washington Corporation 10885 NE 4th Street, Suite 1200 Bellevue, Washington 98004-5591 (425) 454-6363 91-1969407

1-4393 PUGET SOUND ENERGY, INC. A Washington Corporation 10885 NE 4th Street, Suite 1200 Bellevue, Washington 98004-5591 (425) 454-6363 91-0374630

Securities registered pursuant to Section 12(b) of the Act:  None

Securities registered pursuant to Section 12(g) of the Act:   None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

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

Indicate by check mark whether the registrants: (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.

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

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

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   /X/

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

Puget Energy, Inc.	Large accelerated filer	/  /	Accelerated filer	/  /	Non-accelerated filer	/X/	Smaller reporting company	/  /
Puget Sound Energy, Inc.	Large accelerated filer	/  /	Accelerated filer	/  /	Non-accelerated filer	/X/	Smaller reporting company	/  /

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

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

As of February 6, 2009, all of the outstanding shares of voting stock of Puget Energy, Inc. are held by Puget Equico LLC, an indirect wholly-owned subsidiary of Puget Holdings LLC.

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

This Report on Form 10-K is a combined report being filed separately by: Puget Energy, Inc. and Puget Sound Energy, Inc.  Puget Sound Energy, Inc. makes no representation as to the information contained in this report relating to Puget Energy, Inc. and the subsidiaries of Puget Energy, Inc. other than Puget Sound Energy, Inc. and its subsidiaries.

INDEX

DEFINITIONS

AFUDC	Allowance for Funds Used During Construction
aMW	Average Megawatt
ASC	Accounting Standards Codification
ASU	Accounting Standards Update
BPA	Bonneville Power Administration
Colstrip	Colstrip, Montana coal-fired steam electric generation facility
Dth	Dekatherm (one Dth is equal to one MMBtu)
EBITDA	Earnings Before Interest, Tax, Depreciation and Amortization
EPA	Environmental Protection Agency
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	Generally Accepted Accounting Principles
GHG	Greenhouse gases
Goldendale	Goldendale electric generating facility
IRP	Integrated Resource Plan
IRS	Internal Revenue Service
kWh	Kilowatt Hour (one kWh equals one thousand watt hours)
LIBOR	London Interbank Offered Rate
LNG	Liquefied Natural Gas
LTI Plan	Long-Term Incentive Plan
Mint Farm	Mint Farm Electric Generating Station
MMBtu	One Million British Thermal Units
MW	Megawatt (one MW equals one thousand kW)
MWh	Megawatt Hour (one MWh equals one thousand kWh)
NERC	North American Electric Reliability Corporation
Ninth Circuit	United States Court of Appeals for the Ninth Circuit
NOAA	National Oceanic and Atmospheric Administration
NPNS	Normal Purchase Normal Sale
NWP	Northwest Pipeline GP
NYSE	New York Stock Exchange
OCI	Other Comprehensive Income
PCA	Power Cost Adjustment
PCORC	Power Cost Only Rate Case
PGA	Purchased Gas Adjustment
PSE	Puget Sound Energy, Inc.
PTC	Production Tax Credit
PUDs	Washington Public Utility Districts
Puget Energy	Puget Energy, Inc.
Puget Equico	Puget Equico LLC
Puget Holdings	Puget Holdings LLC
PURPA	Public Utility Regulatory Policies Act
REC	Renewable Energy Credit
REP	Residential Exchange Program
SEC	United States Securities and Exchange Commission
Tenaska	Tenaska Power Fund, L.P.
VIE	Variable Interest Entity
Washington Commission	Washington Utilities and Transportation Commission
Wild Horse	Wild Horse wind project

FORWARD-LOOKING STATEMENTS

Puget Energy, Inc. (Puget Energy) and Puget Sound Energy, Inc. (PSE) include the following cautionary statements in this Form 10-K to make applicable and to take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by or on behalf of Puget Energy or PSE.  This report includes forward-looking statements, which are statements of expectations, beliefs, plans, objectives and assumptions of future events or performance.  Words or phrases such as “anticipates,” “believes,” “continues,” “could,” “estimates,” “expects,” “future,” “intends,” “may,” “might,” “plans,” “potential,” “predicts,” “projects,” “should,” “will likely result,” “will continue” or similar expressions are intended to identify certain of these forward-looking statements.

Forward-looking statements reflect current expectations and involve risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed.  Puget Energy’s and PSE’s expectations, beliefs and projections are expressed in good faith and are believed by Puget Energy and PSE, as applicable, to have a reasonable basis, including without limitation, management’s examination of historical operating trends, data contained in records and other data available from third parties.  However, there can be no assurance that Puget Energy’s and PSE’s expectations, beliefs or projections will be achieved or accomplished.  Puget Energy and PSE are collectively referred to herein as “the Company.”

In addition to other factors and matters discussed elsewhere in this report, some important factors that could cause actual results or outcomes for Puget Energy and PSE to differ materially from those discussed in forward-looking statements include:

· Governmental policies and regulatory actions, including those of the Federal Energy Regulatory Commission (FERC) and the Washington Utilities and Transportation Commission (Washington Commission), with respect to allowed rates of return, cost recovery, financing, industry and rate structures, transmission and generation business structures within PSE, acquisition and disposal of assets and facilities, operation, maintenance and construction of electric generating facilities, natural gas and electric distribution and transmission facilities, licensing of hydroelectric operations and natural gas storage facilities, recovery of other capital investments, recovery of power and natural gas costs, recovery of regulatory assets, implementation of energy efficiency programs and present or prospective wholesale and retail competition;

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

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

· Changes in, adoption of and compliance with laws and regulations, including decisions and policies concerning the environment, climate change, greenhouse gas or other emissions or byproducts of electric generation (including coal ash or other substances), natural resources, and fish and wildlife (including the Endangered Species Act) as well as the risk of litigation arising from such matters, whether involving public or private claimants or regulatory investigative or enforcement measures;

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

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

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

· Accidents or natural disasters, such as hurricanes, windstorms, earthquakes, floods, fires and landslides, which can interrupt service and lead to lost revenue, cause temporary supply disruptions and/or price spikes in the cost of fuel and raw materials and impose extraordinary costs;

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

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

· Financial difficulties of other energy companies and related events, which may affect the regulatory and legislative process in unpredictable ways, adversely affect the availability of and access to capital and credit markets and/or impact delivery of energy to PSE from its suppliers;

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

· Changes in Puget Energy’s or PSE’s credit ratings, which may have an adverse impact on the availability and cost of capital for Puget Energy or PSE generally, or the failure to comply with the covenants in Puget Energy’s or PSE’s credit facilities, which would limit the Companies’ ability to utilize such facilities for capital; and

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

Any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by law, Puget Energy and PSE undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events.  New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.  You are also advised to consult the reports on Form 10-Q and current reports on Form 8-K, as well as Item 1A - “Risk Factors” on this Form 10-K.

PART I

ITEM 1.  BUSINESS

GENERAL

Puget Energy is an energy services holding company incorporated in the state of Washington in 1999.  All of its operations are conducted through its subsidiary, PSE, a utility company.  Puget Energy has no significant assets other than the stock of PSE.

On February 6, 2009, Puget Holdings LLC (Puget Holdings) completed its merger with Puget Energy.  Puget Holdings is a consortium of long-term infrastructure investors including Macquarie Infrastructure Partners I, Macquarie Infrastructure Partners II, Macquarie Capital Group Limited, Macquarie-FSS Infrastructure Trust, the Canada Pension Plan Investment Board, the British Columbia Investment Management Corporation and the Alberta Investment Management Corporation.  As a result of the merger, Puget Energy is the direct wholly-owned subsidiary of Puget Equico LLC (Puget Equico), which is an indirect wholly-owned subsidiary of Puget Holdings.

Corporate Strategy

Puget Energy is the direct parent company of PSE, the oldest and largest electric and natural gas utility headquartered in the state of Washington, primarily engaged in the business of electric transmission, distribution, generation and natural gas distribution.  Puget Energy’s business strategy is to generate stable earnings and cash flow by offering reliable electric and natural gas service in a cost-effective manner through PSE.

Puget Sound Energy, Inc.

PSE is a public utility incorporated in the state of Washington in 1960.  PSE furnishes electric and natural gas service in a territory covering approximately 6,000 square miles, principally in the Puget Sound region.

The following table presents the number of PSE customers as of December 31, 2010 and 2009:

	Electric			Gas
	December 31		Percent	December 31		Percent
	2010	2009	Change	2010	2009	Change
Customers: 1
Residential	954,898	949,889	0.5%	696,988	691,850	0.7%
Commercial	118,706	118,422	0.2	53,981	54,320	(0.6)
Industrial	3,637	3,679	(1.1)	2,498	2,533	(1.4)
Other	3,451	3,430	0.6	169	150	12.7
Total	1,080,692	1,075,420	0.5%	753,636	748,853	0.6%

_______________

1 At December 31, 2010 approximately 376,300 customers purchased both electricity and natural gas from PSE.

During 2010, PSE’s billed retail and transportation revenue from electric utility operations were derived 52.9% from residential customers, 41.1% from commercial customers, 5.1% from industrial customers and 0.9% from other customers.  PSE’s retail revenue from natural gas utility operations were derived 65.1% from residential customers, 30.2% from commercial customers, 3.3% from industrial customers and 1.4% from transportation customers in 2010.  During this period, the largest customer accounted for approximately 1.7% of PSE’s operating revenue.

PSE is affected by various seasonal weather patterns and therefore, utility revenue and associated expenses are not generated evenly during the year.  Energy usage varies seasonally and monthly, primarily as a result of weather conditions.  PSE experiences its highest retail energy sales in the first and fourth quarters of the year.  Sales of electricity to wholesale customers also vary by quarter and year depending principally upon fundamental market factors and weather conditions.  PSE has a Purchased Gas Adjustment (PGA) mechanism in retail natural gas rates to recover variations in natural gas supply and transportation costs.  PSE also has a Power Cost Adjustment (PCA) mechanism in retail electric rates to recover variations in electricity costs on a shared basis with customers.

In the five-year period ended December 31, 2010, PSE’s gross electric utility plant additions were $3.3 billion and retirements were $362.7 million.  In the same five-year period, PSE’s gross natural gas utility plant additions were $880.6 million and retirements were $122.4 million and PSE’s gross common utility plant additions were $277.6 million and retirements were $292.6 million.  Gross electric utility plant at December 31, 2010 was approximately $7.6 billion, which consisted of 46.0% distribution, 34.0% generation, 6.1% transmission and 13.9% general plant and other.  Gross natural gas utility plant at December 31, 2010 was approximately $2.8 billion, which consisted of 93.2% distribution and 6.8% general plant and other.  Gross common utility general and intangible plant at December 31, 2010 was approximately $427.2 million.

Employees

At December 31, 2010, Puget Energy had no employees and PSE had approximately 2,800 full-time employees.  Approximately 1,230 PSE employees are represented by the United Association of Plumbers and Pipefitters (UA) and the International Brotherhood of Electrical Workers Union (IBEW).  The current contracts with the UA and the IBEW expire September 30, 2013 and March 31, 2014, respectively.

Corporate Location

Puget Energy’s and PSE’s principal executive offices are located at 10885 NE 4th Street, Suite 1200, Bellevue, Washington 98004 and the telephone number is (425) 454-6363.

REGULATION AND RATES

PSE is subject to the regulatory authority of:  (1) the FERC with respect to the transmission of electricity, the sale of electricity at wholesale, accounting and certain other matters; and (2) the Washington Commission as to retail rates, accounting, the issuance of securities and certain other matters.  PSE also must comply with mandatory electric system reliability standards developed by the NERC, the electric reliability organization certified by the FERC, which standards are enforced by the Western Electricity Coordinating Council in PSE’s operating territory.

Electric Regulation and Rates

Electric Rate Case.  On April 2, 2010, the Washington Commission issued its order in PSE’s consolidated electric rate case filed in May 2009 which approved a general rate increase for electric customers of 3.7% annually, or $74.1 million, effective April 8, 2010.  In its order, the Washington Commission approved a weighted cost of capital of 8.1% and a capital structure that included 46.0% common equity with an after-tax return on equity of 10.1%.  

The Washington Commission issued an order in 2010 relating to how Renewable Energy Credit (REC) proceeds should be handled for regulatory accounting and ratemaking purposes.  The order required REC proceeds to be recorded as regulatory liabilities and that amounts recorded would accrue interest.  In its petition, PSE had sought approval for $21.1 million of REC proceeds to be used as an offset against its California wholesale energy sales regulatory asset.  In response to the order, PSE adjusted the carrying value of its regulatory asset in the second quarter of 2010 by $17.8 million (from $21.1 million to $3.3 million), with the $3.3 million then offset against the Company’s RECs regulatory liability.  The Company’s California wholesale energy sales regulatory asset represented unpaid bills for power sold into the markets maintained by the California Independent System Operator during the 2000-2001 California Energy Crisis, the claims of which were settled along with all counterclaims against PSE in a settlement agreement approved by the FERC on July 1, 2009.

On May 20, 2010, PSE filed an accounting petition requesting that the Washington Commission approve:  (1) the creation of a regulatory asset account for the prepayments made to the Bonneville Power Administration (BPA) associated with network upgrades to the Central Ferry substation related to the Lower Snake River wind project; (2) the monthly accrual of carrying charges on that regulatory asset at PSE’s approved net of tax rate of return; and (3) the ability to provide customers the BPA interest received through a reduction to transmission expense.  The petition is still pending approval by the Washington Commission.

Effective July 1, 2010, the Washington Commission approved a change in PSE’s PTC tariff as PSE has not been able to utilize PTCs since 2007, due to insufficient taxable income caused primarily by bonus tax depreciation.  The Washington Commission approved PSE suspending its PTC tariff, effective July 1, 2010.  This resulted in an overall increase in PSE’s electric rates of 1.7%, with no impact to net income.  

On September 22, 2010, a joint proposal and accounting petition was filed with the Washington Commission by PSE, Washington Commission Staff and Industrial Customers of Northwest Utilities which addressed how to recover PTCs provided to customers that have not been utilized and addresses REC proceeds to be returned to customers.  On October 26, 2010, the Washington Commission issued an order granting the joint proposal and accounting petition.  The order allows the Company to credit customers for REC revenue received and deferred through November 2009.  This credit will reduce rates by $27.7 million, or 2.5%, over five months beginning November 2010 through March 2011.  RECs received after November 2009 will be retained by PSE and will be used to recapture the benefit of PTCs previously provided to customers.  Once these PTCs are utilized by PSE on its tax return, the customers will receive the benefit.  There is no impact to net income related to these items.

On December 30, 2010, the Washington Commission approved revisions to PSE’s PTC tariff, effective January 1, 2011, which changed the methodology by which PTCs are passed-through to customers.  Due to the uncertainty of realizing the benefit of PTCs, the PTCs will pass-through to customers following the year in which they are able to be utilized on PSE’s tax return, rather than in the same year in which they are generated by qualifying wind powered facilities.  The rate schedule will pass-through $5.5 million of the $28.7 million treasury grant in 2011.  The Washington Commission order authorized PSE to pass back one-tenth of the treasury grant on an annual basis and includes 23 months of treasury grant amortization to customers from February 2010 through December 2011, which represents the month the treasury grant funds were received through the end of the period over which the rates will be set.  This represents an overall average rate reduction of 0.3%, with no impact to net income.  Since the tariff now addresses additional federal incentives, it has been renamed the Federal Incentive Tracker.

Natural Gas Regulation and Rates

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

On October 1, 2010, PSE filed a natural gas tariff filing with the Washington Commission to implement changes to natural gas rates that would result in an overall increase in revenue of $24.4 million and a customer rate increase of 2.3%.  The parties agreed upon a settlement of $19.0 million with a recommended effective date of April 1, 2011.  A Washington Commission order is expected in March 2011.

The Washington Commission approved a PGA natural gas tariff filing to adjust the PGA rates, effective November 1, 2010 to recover expected natural gas costs from PSE’s sales to customers.  This filing reflected decreases in forward market prices.  On an average annual basis, the impact of these changes is a 3.1% decrease in natural gas rates.  The PGA filing also reflects a decrease in the PGA deferred natural gas cost credit, which will result in a 5.0% increase in overall natural gas revenue.  Collectively, the increase is $18.3 million, or 1.9%.  This rate adjustment will have no impact on PSE’s net income.

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

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

Type of Rate Adjustment	Effective Date	Average Percentage Increase (Decrease) in Rates	Annual Increase (Decrease)  in Revenue (Dollars in Millions)
Purchased Gas Adjustment	November 1, 2010	1.9%	$   18.3
Gas General Rate Case	April 8, 2010	0.8	10.1
Purchased Gas Adjustment	October 1, 2009 – October 31, 2010	(17.1)	(198.1)
Purchased Gas Adjustment	June 1, 2009 – May 31, 2010	(1.8)	(21.2)
Merger Rate Credit	February 13, 2009	(0.4)	(3.6)
Gas General Rate Case	November 1, 2008	4.6	49.2
Purchased Gas Adjustment	October 1, 2008 – September 30, 2009	11.1	108.8

ELECTRIC UTILITY OPERATING STATISTICS

	Year Ended December 31,
	2010			2009			2008
Generation and purchased power, MWh
Company-controlled resources		11,220,935			10,748,523			9,419,375
Contracted resources		8,188,156			8,285,761			8,711,075
Non-firm energy purchased		5,683,635			6,935,600			7,106,320
Total generation and purchased power		25,092,726			25,969,884			25,236,770
Less: losses and Company use		(1,685,890	)		(1,568,372	)		(1,549,277	)
Total energy sales, MWh		23,406,836			24,401,512			23,687,493
Electric energy sales, MWh
Residential		10,672,887			11,163,371			11,082,670
Commercial		9,100,518			9,488,763			9,453,940
Industrial		1,160,588			1,148,060			1,304,662
Other customers		99,679			103,537			100,948
Total energy billed to customers		21,033,672			21,903,731			21,942,220
Unbilled energy sales – net (decrease) increase		(125,288	)		(29,652	)		80,375
Total energy sales to customers		20,908,384			21,874,079			22,022,595
Sales to other utilities and marketers		2,498,452			2,527,433			1,664,898
Total energy sales, MWh		23,406,836			24,401,512			23,687,493
Transportation, including unbilled		1,954,913			2,030,110			2,045,161
Electric energy sales and transportation, MWh		25,361,749			26,431,622			25,732,654
Electric operating revenue by classes (dollars in thousands):
Residential	$	1,078,262		$	1,067,274		$	1,046,897
Commercial		836,957			838,275			800,878
Industrial		103,678			99,552			106,092
Other customers		18,694			18,392			16,818
Operating revenue billed to customers		2,037,591			2,023,493			1,970,685
Unbilled revenue – net (decrease) increase		(5,907	)		(1,968	)		10,789
Total operating revenue from customers		2,031,684			2,021,525			1,981,474
Transportation, including unbilled		11,000			10,623			7,840
Sales to other utilities and marketers		62,943			78,471			84,716
Miscellaneous operating revenue		1,842			(11,883	)		55,433
Total electric operating revenue	$	2,107,469		$	2,098,736		$	2,129,463
Number of customers served (average):
Residential		952,803			947,299			939,440
Commercial		118,595			118,423			117,521
Industrial		3,660			3,695			3,744
Other		3,426			3,403			3,231
Transportation		17			17			18
Total customers		1,078,501			1,072,837			1,063,954

	Year Ended December 31,
	2010			2009			2008
Average kWh used per customer:
Residential		11,202			11,784			11,797
Commercial		76,736			80,126			80,445
Industrial		317,100			310,706			348,467
Other		29,095			30,425			31,244
Average revenue billed per customer:
Residential	$	1,132		$	1,127		$	1,114
Commercial		7,057			7,079			6,815
Industrial		28,327			26,942			28,337
Other		5,457			5,405			5,205
Average retail revenue per kWh sold:
Residential	$	0.1010		$	0.0956		$	0.0944
Commercial		0.0920			0.0883			0.0847
Industrial		0.0893			0.0867			0.0813
Other		0.1875			0.1776			0.1666
Average retail revenue per kWh sold		0.0969			0.0924			0.0898
Heating degree days		4,549			4,897			5,062
Percent of normal - NOAA1 30-year average		94.8	%		102.1	%		105.1	%
Load factor 2		56.7	%		54.5	%		58.6	%

_______________

1	National Oceanic and Atmospheric Administration (NOAA).
2	Average usage by customers divided by their maximum usage.

ELECTRIC SUPPLY

At December 31, 2010, PSE’s electric power resources, which include company-owned or controlled resources as well as those under long-term contract, had a total capacity of approximately 5,318 megawatts (MW).  PSE’s historical peak load of approximately 4,912 MW occurred on December 10, 2009.  In order to meet an extreme winter peak load, PSE may supplement its electric power resources with winter-peaking call options and other instruments that may include, but are not limited to, weather-related hedges.  When it is more economical for PSE to purchase power than to operate its own generation facilities, PSE will purchase spot market energy.

The following table shows PSE’s electric energy supply resources and energy production for the years ended December 31, 2010 and 2009:

	Peak Power Resources At December 31						Energy Production At December 31
	2010			2009			2010			2009
	MW	%		MW	%		MWh	%		MWh	%
Purchased resources:
Columbia River PUD contracts 1	1,027	19.4	%	1,057	21.0	%	4,330,176	19.2	%	4,861,462	20.7	%
Other hydroelectric 2	145	2.7		145	2.8		635,996	2.8		606,534	2.6
Other producers 2	1,170	22.0		822	16.3		3,101,364	13.7		3,098,197	13.2
Wind	50	0.9		50	1.0		120,632	0.5		132,569	0.6
Short-term wholesale energy purchases 3	N/A	N/A		N/A	N/A		3,185,183	14.1		3,995,166	17.0
Total purchased	2,392	45.0	%	2,074	41.1	%	11,373,351	50.3	%	12,693,928	54.1	%
Company-controlled resources:
Hydroelectric	192	3.6	%	236	4.7	%	929,595	4.1	%	987,779	4.2	%
Coal	677	12.7		677	13.4		5,198,105	23.0		4,451,104	19.0
Natural gas/oil	1,627	30.6		1,627	32.3		4,102,298	18.2		4,363,146	18.6
Wind	430	8.1		430	8.5		990,925	4.4		946,494	4.1
Total company-controlled	2,926	55.0	%	2,970	58.9	%	11,220,923	49.7	%	10,748,523	45.9	%
Total	5,318	100.0	%	5,044	100.0	%	22,594,274	100.0	%	23,442,451	100.0	%

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1	Net of 59 MW of capacity delivered to Canada pursuant to the provisions of a treaty between Canada and the United States and Canadian Entitlement Allocation agreements.
2	Power received from other utilities and firm contracts are classified between hydroelectric and other producers based on the character of the utility system used to supply the power or, if the power is supplied from a particular resource, the character of that resource.
3	Short-term wholesale purchases, net of resale, of 2,498,452 megawatt hours (MWh) and 2,527,433 MWh account for 3.4% and 7.0% of energy production, for 2010 and 2009, respectively.

Company – Owned Electric Generation Resources

At December 31, 2010, PSE owns or controls the following plants with an aggregate net generating capacity of 2,926 MW:

Plant Name	Plant Type	Net Maximum Capacity (MW) 1	Year Installed
Colstrip Units 3 & 4 (25% interest)	Coal	370	1984 & 1986
Colstrip Units 1 & 2 (50% interest)	Coal	307	1975 & 1976
Mint Farm	Natural gas combined cycle	302	2007
Goldendale	Natural gas combined cycle	278	2004
Frederickson Unit 1 (49.85% interest)	Natural gas combined cycle	136	2002; added duct firing in 2005
Wild Horse	Wind	273	2006; added 22 turbines in 2009
Hopkins Ridge	Wind	157	2005; added 4 turbines in 2008
Fredonia Units 1 & 2	Dual-fuel combustion turbines	207	1984
Frederickson Units 1 & 2	Dual-fuel combustion turbines	149	1981
Whitehorn Units 2 & 3	Dual-fuel combustion turbines	149	1981
Fredonia Units 3 & 4	Dual-fuel combustion turbines	107	2001
Encogen	Natural gas cogeneration	167	1993
Sumas	Natural gas cogeneration	129	1993
Upper Baker River 2	Hydroelectric	91	1959
Lower Baker River 2	Hydroelectric	79	1925; reconstructed 1960; upgraded 2001
Snoqualmie Falls 3	Hydroelectric	--	1898 to 1911 & 1957; currently no output due to rebuild
Electron	Hydroelectric	22	1904 to 1929
Crystal Mountain	Internal combustion	3	1969
Total net capacity		2,926

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1	Net Maximum Capacity is the capacity a unit can sustain over a specified period of time when not restricted by ambient conditions or deratings, less the losses associated with auxiliary loads.
2	The FERC jurisdictional facility, operated pursuant to 50-year license granted by the FERC in October 2008, will require net present value funds between $305.0 million to $325.0 million for capital expenditures and operations and maintenance costs over 50 years in order to implement the license conditions.  The license provides protection and enhancements for fish and wildlife, water quality, recreation and cultural and historic resources.
3	The FERC jurisdictional facility, operated pursuant to 40-year license granted by the FERC in June 2004, will require net present value funds between $240.0 million to $260.0 million for capital expenditures and operations and maintenance costs over 40 years in order to implement the license conditions.

Columbia River Electric Energy Supply Contracts

During 2010, approximately 19.2% of PSE’s energy requirement was obtained through long-term contracts with three Washington Public Utility Districts (PUDs) that own and operate hydroelectric projects on the Columbia River.  PSE agrees to pay a share of the annual debt service, operating and maintenance costs and other expenses associated with each project in proportion to its share of projected output.  PSE’s payments are not contingent upon the projects being operable.

As of December 31, 2010, PSE was entitled to purchase portions of the power output of the PUDs’ projects as set forth below:

			Company’s Annual Purchasable Amount (Approximate)
Project	Contract Expiration Year	License Expiration Year	Percent of Output		Megawatt Capacity
Chelan County PUD: 1
Rock Island Project	2012	2029	50.0	%	312
Rocky Reach Project	2011	2052	38.9	%	498
Douglas County PUD: 2
Wells Project	2018	2012	29.9	%	251
Grant County PUD: 3
Priest Rapids Development	2052	2052	1.2	%	12
Wanapum Development	2052	2052	1.2	%	13
Total					1,086

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1	On February 3, 2006, PSE and Chelan entered into a new Power Sales Agreement and a related Transmission Agreement for 25.0% of the output of Chelan’s Rocky Reach and Rock Island hydroelectric generating facilities, located on the mid-Columbia River, in exchange for PSE paying 25.0% of the operating costs of the facilities.  The agreements terminate in 2031 and provide that PSE will begin to receive power upon expiration of PSE’s existing long-term contracts with Chelan for the Rocky Reach and Rock Island output (expiring in 2011 and 2012, respectively). PSE made a non-refundable capacity reservation payment of $89.0 million as required by the agreements.  The Washington Commission determined the prudence of PSE entering into the new Chelan contract and confirmed the treatment of the $89.0 million as a regulatory asset as part of its order in PSE’s general rate case on January 5, 2007.
2	Douglas County PUD began the FERC integrated licensing process in 2004 and is progressing on schedule for a new license upon the current license expiration in May 2012.
3	PSE’s share of power under the 2001 contract will decline over time as Grant County PUD’s load increases. PSE’s share of both the Priest Rapids and Wanapum developments was 1.2% at the end of 2010 and will not be less than 0.6% through 2052.

Other Electric Supply, Exchange and Transmission Contracts and Agreements

PSE purchases electric energy under long-term firm purchased power contracts with other utilities and marketers in the Western region.  With the exception of a contract with NorthWestern Energy, PSE is generally not obligated to make payments under these contracts unless power is delivered.  PSE has seasonal energy and capacity exchange agreements with the BPA (for 42 average megawatts (aMW)) and with Pacific Gas & Electric Company (for 300 MW of capacity) and an energy purchase contract with NorthWestern Energy (for 71 aMW) which terminated on December 29, 2010.

Pursuant to the provisions of the federal Public Utility Regulatory Policies Act (PURPA) and Washington state regulations, PSE also enters into long-term firm purchased power contracts with non-utility generators.  PSE purchases the net electrical output of these projects at fixed and annually escalating prices, intended to approximate PSE’s avoided cost of new generation projected at the time these agreements were made.

As of December 31, 2010, the Company purchased the following significant power output from the entities:

				Average
	Plant	Contract	Megawatt	Megawatts
Contract	Type	Expiration	Capacity	of Energy
March Point Cogeneration Company:
March Point Phase I	Natural gas cogeneration	December 2011	80	70
March Point Phase II	Natural gas cogeneration	December 2011	60	53
Tenaska Washington Partners, L.P.	Natural gas cogeneration	December 2011	245	216
Total			385	339

Further, PSE has entered into multiple various-term transmission contracts with other utilities to integrate electric generation and contracted resources into PSE’s system.  These transmission contracts require PSE to pay for transmission service based on the contracted MW level of demand, regardless of actual use.  These costs are recovered through the PCA mechanism.

Other transmission agreements provide actual capacity ownership or capacity ownership rights.  PSE’s annual charges under these agreements are also based on contracted MW volumes.  Capacity on these agreements that is not committed to serve PSE’s load is available for sale to third parties.  PSE also purchases short-term transmission services from a variety of providers, including the BPA.

In 2010, PSE had 4,020 MW and 619 MW of total transmission demand contracted with the BPA and other utilities, respectively.

Natural Gas Supply for Electric Customers

PSE purchases natural gas supplies for its power portfolio to meet demand for its combustion turbine generators. Supplies range from long-term to daily agreements, as the demand for the turbines varies depending on market heat rates.  Purchases are made from a diverse group of major and independent natural gas producers and marketers in the United States and Canada.  PSE also enters into physical and financial fixed price derivative instruments to hedge the cost of natural gas.  PSE utilizes natural gas storage capacity that is dedicated to and paid for by the power portfolio to facilitate increased natural gas supply reliability and intra-day dispatch of PSE’s gas-fired generation resources.  During 2010, approximately 77.5% of natural gas for power purchased by PSE for power customers originated in British Columbia and 22.5% originated in the United States.  Natural gas is either marketed outside PSE’s service territory (off-system sales) or injected into the power portfolio’s natural gas storage when the natural gas is not needed for the combustion turbines.

Integrated Resource Plans, Resource Acquisition and Development

PSE is required by Washington Commission regulations to file electric and natural gas Integrated Resource Plans (IRP) every two years with the next IRP scheduled to be filed by May 30, 2011.  PSE filed its most recent IRP with the Washington Commission on July 30, 2009 and an addendum to the 2009 IRP was filed on January 29, 2010.  The IRP demonstrated PSE’s continuing need to acquire significant amounts of new generating resources, driven primarily by the expiration of existing power purchase contracts and by the requirements of the state’s renewable portfolio standard.  The IRP, as amended, identifies the following capacity needs:

	2012	2013	2014	2015
Projected MW shortfall	934	1,036	1,128	1,245

To meet these expected shortfalls, the IRP identified a mix of energy efficiency programs, additional renewable resources (primarily wind) and base-load natural gas-fired generation to meet the growing needs of its customers.  The specific resources acquired will be determined through the Company’s resource acquisition program which examines specific acquisition and development opportunities.

PSE has enough renewable resources to meet statutory requirements through 2016.  However, the 2009 IRP determined the cost would be lower by taking advantage of expiring tax incentives rather than waiting until 2016 to develop more renewable energy.  In 2009, PSE purchased from RES America, Inc., all of the undivided interest in four development-stage wind projects, collectively known as the Lower Snake River wind project in Columbia and Garfield counties in Washington state.  PSE is currently constructing Phase 1 of the Lower Snake River wind project, which will total 343 MW of capacity when complete.  In 2010, PSE completed construction of the Phase 1 project roads and turbine foundations in preparation for wind turbine delivery and installation in 2011.  Phase 1 is expected to be in commercial operation by April 2012.

NATURAL GAS UTILITY OPERATING STATISTICS

	Year Ended December 31,
	2010			2009			2008
Gas operating revenue by classes (dollars in thousands):
Residential	$	648,649		$	795,756		$	766,799
Commercial firm		262,735			303,989			321,829
Industrial firm		28,939			36,141			42,529
Interruptible		42,413			56,511			53,317
Total retail gas sales		982,736			1,192,397			1,184,474
Transportation services		14,082			13,014			14,700
Other		14,713			19,334			17,694
Total gas operating revenue	$	1,011,531		$	1,224,745		$	1,216,868
Number of customers served (average):
Residential		694,086			689,438			681,267
Commercial firm		53,703			54,022			53,441
Industrial firm		2,489			2,534			2,596
Interruptible		381			398			419
Transportation		152			140			128
Total customers		750,811			746,532			737,851
Gas volumes, therms (thousands):
Residential		519,527			585,626			589,405
Commercial firm		239,693			248,321			275,631
Industrial firm		29,812			31,535			38,956
Interruptible		52,771			59,222			56,329
Total retail gas volumes, therms		841,803			924,704			960,321
Transportation volumes		205,516			210,243			217,774
Total volumes		1,047,319			1,134,947			1,178,095
Working gas volumes in storage at year end, therms (thousands):
Jackson Prairie		70,213			66,948			60,301
Clay Basin		86,891			93,023			92,203
Average therms used per customer:
Residential		749			849			865
Commercial firm		4,463			4,597			5,158
Industrial firm		11,978			12,445			15,006
Interruptible		138,507			148,799			134,436
Transportation		1,352,079			1,501,739			1,701,359
Average revenue per customer:
Residential	$	935		$	1,154		$	1,126
Commercial firm		4,892			5,627			6,022
Industrial firm		11,627			14,262			16,383
Interruptible		111,320			141,987			127,248
Transportation		92,645			92,957			114,844
Average revenue per therm sold:
Residential	$	1.249		$	1.359		$	1.302
Commercial firm		1.096			1.224			1.168
Industrial firm		0.971			1.146			1.092
Interruptible		0.804			0.954			0.947
Average retail revenue per therm sold		1.167			1.289			1.233
Transportation		0.069			0.062			0.068
Heating degree days		4,549			4,897			5,062
Percent of normal - NOAA 30-year average		94.8	%		102.1	%		105.1	%

NATURAL GAS SUPPLY FOR NATURAL GAS CUSTOMERS

PSE purchases a portfolio of natural gas supplies ranging from long-term firm to daily from a diverse group of major and independent natural gas producers and marketers in the United States and Canada.  PSE also enters into physical and financial fixed-price derivative instruments to hedge the cost of natural gas to serve its customers.  All of PSE’s natural gas supply is ultimately transported through the facilities of Northwest Pipeline GP (NWP), the sole interstate pipeline delivering directly into PSE’s service territory.  Accordingly, delivery of natural gas supply to PSE’s natural gas system is dependent upon the reliable operations of NWP.

	At December 31
	2010				2009
Peak Firm Natural Gas Supply  1	Dth per Day		%		Dth per Day		%
Purchased gas supply:
British Columbia	199,000		21.3		203,400		21.3
Alberta	70,000		7.5		78,400		8.2
United States	177,000		18.9		177,000		18.5
Total purchased natural gas supply	446,000		47.7	%	458,800		48.0	%
Purchased storage capacity:
Jackson Prairie	58,000		6.2		64,700		6.8
Plymouth liquefied natural gas	70,500		7.5		70,500		7.4
Total purchased storage capacity	128,500		13.7	%	135,200		14.2	%
Owned storage capacity:
Jackson Prairie	348,700		37.3		348,700		36.5
Propane-air and other	12,500		1.3		12,500		1.3
Total owned storage capacity	361,200		38.6	%	361,200		37.8	%
Total peak firm natural gas supply	935,700		100.0	%	955,200		100.0	%
Other and commitments with third parties	(15,500	)			(15,400	)
Total net peak firm natural gas supply	920,200				939,800

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1 All peak firm gas supplies and storage are connected to PSE’s market with firm transportation capacity.

For baseload, peak management and supply reliability purposes, PSE supplements its firm natural gas supply portfolio by purchasing natural gas in off-peak periods, injecting it into underground storage facilities and withdrawing it during the peak winter heating season.  Underground storage facilities at Jackson Prairie in western Washington and at Clay Basin in Utah are used for this purpose.  Clay Basin withdrawals are used to supplant purchases from the U.S. Rocky Mountain supply region, while Jackson Prairie provides incremental peak-day resources utilizing storage redelivery transportation capacity.  Jackson Prairie is also used for daily balancing of load requirements on PSE’s gas system.  Peaking needs are also met by; using PSE-owned natural gas held in NWP’s liquefied natural gas (LNG) storage facility in Plymouth, Washington; using PSE-owned natural gas held in PSE’s LNG peaking facility located within its distribution system in Gig Harbor, Washington; producing propane-air gas at a plant owned by PSE and located on its distribution system; and interrupting service to customers on interruptible service rates.

PSE expects to meet its firm peak-day requirements for residential, commercial and industrial markets through its firm natural gas purchase contracts, firm transportation capacity, firm storage capacity and other firm peaking resources.  PSE believes it will be able to acquire incremental firm natural gas supply and capacity to meet anticipated growth in the requirements of its firm customers for the foreseeable future.

During 2010, approximately 42.8% of natural gas supplies purchased by PSE for its gas customers originated in British Columbia, while 18.7% originated in Alberta and 38.5% originated in the United States.  PSE’s firm natural gas supply portfolio has adequate flexibility in its transportation arrangements to enable it to achieve savings when there are regional price differentials between natural gas supply basins.  The geographic mix of suppliers and daily, monthly and annual take requirements permit some degree of flexibility in managing natural gas supplies during off-peak periods to minimize costs.  Natural gas is marketed outside PSE’s service territory (off-system sales) whenever on-system customer demand requirements permit and the benefits or costs are reflected in PSE’s natural gas customer tariff rates through the PGA mechanism.

Natural Gas Storage Capacity

PSE holds storage capacity in the Jackson Prairie and Clay Basin underground natural gas storage facilities adjacent to NWP’s pipeline to serve PSE’s natural gas customers.  The Jackson Prairie facility is operated and one-third owned by PSE.  The facility is used primarily for intermediate peaking purposes since it is able to deliver a large volume of natural gas over a relatively short time period.  Combined with capacity contracted from NWP’s one-third stake in Jackson Prairie, PSE has peak firm withdrawal capacity in excess of 460,000 Dekatherm (Dth) per day, which, after reduction for a portion temporarily released to the power portfolio represents nearly 43.5% of PSE’s expected near-term peak-day requirement.  PSE’s total firm storage capacity of the facility is in excess of 9.8 million Dth.  The location of the Jackson Prairie facility in PSE’s market area increases supply reliability and provides significant pipeline demand cost savings by reducing the amount of annual pipeline capacity required to meet peak-day natural gas requirements.  PSE has been expanding the storage capacity at Jackson Prairie since March 2003.  The most recent withdrawal capacity expansion was placed in service in November 2008 and the reservoir expansion activities will continue through 2012.

Due to the recent expansion of Jackson Prairie storage withdrawal capacity and storage capacity, PSE’s natural gas storage resources are expected to exceed natural gas customer requirements for the next two or three years.  Therefore, beginning in 2009 and continuing in 2010, 50,000 Dth per day of natural gas storage withdrawal capacity and 500,000 Dth of natural gas storage capacity have been temporarily released at market sensitive rates to PSE’s power portfolio, increasing natural gas supply reliability and facilitating intra-day dispatch of PSE’s natural gas-fired generation resources.

 The Clay Basin storage facility is a supply area storage facility that is used primarily to reduce portfolio costs through supply management efforts that take advantage of market price volatility, and provides system reliability.  PSE holds over 12.8 million Dth of Clay Basin storage capacity and approximately 107,000 Dth per day of firm withdrawal capacity under two long-term contracts with remaining terms of two and nine years.  PSE’s maximum firm withdrawal capacity and total storage capacity at Clay Basin, net of releases, is over 90,000 Dth per day and exceeds 10.8 million Dth, respectively.

LNG and Propane-Air Resources

LNG and propane-air resources provide firm natural gas supply on short notice for short periods of time.  Due to their typically high cost and slow cycle times, these resources are normally utilized as a last resort supply source in extreme peak-demand periods, typically during the coldest hours or days.  PSE contracts for LNG storage services of 241,700 Dth of PSE-owned gas at NWP’s Plymouth facility, which is approximately three and one-half day’s supply at a maximum daily deliverability of 70,500 Dth.  PSE owns and operates the Swarr vaporized propane-air station located in Renton, Washington which includes storage capacity for approximately 1.5 million gallons of propane.  This propane-air injection facility is designed to deliver the equivalent of 10,000 Dth of natural gas per day for up to 12 days directly into PSE’s distribution system.  PSE owns and operates an LNG peaking facility in Gig Harbor, Washington, with total capacity of 10,600 Dth, which is capable of delivering the equivalent of 2,500 Dth of natural gas per day.

Natural Gas Transportation Capacity

PSE currently holds firm transportation capacity on pipelines owned by NWP, Gas Transmission Northwest (GTN), Nova Gas Transmission (NOVA), Foothills Pipe Lines (Foothills) and Westcoast Energy (Westcoast).  GTN, NOVA, and Foothills are all TransCanada companies.  PSE pays fixed monthly demand charges for the right, but not the obligation, to transport specified quantities of natural gas from receipt points to delivery points on such pipelines each day for the term or terms of the applicable agreements.

PSE holds approximately 520,000 Dth per day of capacity for its natural gas customers on NWP that provides firm year-round delivery to PSE’s service territory.  In addition, PSE holds approximately 524,000 Dth per day of seasonal firm capacity on NWP to provide for delivery of natural gas stored in Jackson Prairie and the Plymouth LNG facility during the heating season.  PSE has firm transportation capacity on NWP through various contracts that supply electric generating facilities with approximately 168,000 Dth per day.  PSE participates in the pipeline capacity release market to achieve savings for PSE’s customers and has released certain segments of temporarily surplus firm capacity to third parties.  PSE’s firm transportation capacity contracts with NWP have remaining terms ranging from one to 34 years.  However, PSE has either the unilateral right to extend the contracts under the contracts’ current terms or the right of first refusal to extend such contracts under current FERC rules.

PSE’s firm transportation capacity for its natural gas customers on Westcoast’s pipeline is approximately 130,000 Dth under various contracts, with remaining terms of two to eight years.  PSE has other firm transportation capacity on Westcoast’s pipeline, which supplies the electric generating facilities, totaling approximately 73,000 Dth per day, with remaining terms of four to eight years.  PSE has firm transportation capacity on NOVA and Foothills pipelines, totaling approximately 80,000 Dth per day, with remaining terms of one to 13 years.  PSE has annual renewal rights on this capacity.  PSE’s firm transportation capacity on the GTN pipeline, totaling approximately 90,000 Dth per day, has a remaining term of 13 years.

Capacity Release

The FERC regulates the release of firm pipeline and storage capacity for facilities which fall under its jurisdiction.  Capacity releases allow shippers to temporarily or permanently relinquish unutilized capacity to recover all or a portion of the cost of such capacity.  The FERC allows capacity to be released through several methods including open bidding and pre-arrangement.  PSE has acquired some firm pipeline and storage service through capacity release provisions to serve its growing service territory and electric generation portfolio.  PSE also mitigates a portion of the demand charges related to unutilized storage and pipeline capacity through capacity release.  Capacity release benefits derived from the natural gas customer portfolio are passed on to PSE’s natural gas customers through the PGA mechanism.

ENERGY EFFICIENCY

PSE is required under Washington state law to pursue cost-effective reductions in electric power consumption.  PSE offers programs designed to help new and existing residential, commercial and industrial customers use energy efficiently.  PSE uses a variety of mechanisms including cost-effective financial incentives, information and technical services to enable customers to make energy efficient choices with respect to building design, equipment and building systems, appliance purchases and operating practices.  As described below, PSE recovers the actual costs of electric and natural gas energy efficiency programs through a tracker mechanism (for natural gas) and a rider mechanism (for electric) so that these expenditures have no impact on earnings.  However, the rider mechanism does not provide for any cost recovery of lost sales margin associated with reduced energy sales.

PSE’s rates are designed to capture most of the approved revenue requirements for fixed costs through volumetric rates.  PSE fully recovers these costs only if its customers consume a certain level of natural gas and electricity.  This level of consumption is typically established in the utility’s most recently completed rate case based upon historical natural gas and electric volumes.  When customers use less natural gas or electricity, whether due to conservation, weather or economic conditions, PSE’s financial performance is negatively impacted because recovery of fixed costs is reduced in proportion to the reduction in natural gas or electric sales.

Since 1995, PSE has been authorized by the Washington Commission to defer natural gas energy efficiency (or conservation) expenditures and recover them through a tracker mechanism.  The tracker mechanism allows PSE to defer efficiency expenditures and recover them in rates over the subsequent year.  The tracker mechanism also allows PSE to recover an allowance for funds used to conserve energy on any outstanding balance that is not currently being recovered in rates.

Since May 1997, PSE has recovered direct electric energy efficiency (or conservation) expenditures through a rider mechanism.  The rider mechanism allows PSE to defer the efficiency expenditures and amortize them to expense as PSE concurrently collects the efficiency expenditures in rates over a one-year period.  As a result of the rider mechanism, direct electric energy efficiency expenditures are recovered.

ENVIRONMENT

PSE’s operations, including generation, transmission, distribution, service and storage facilities, are subject to environmental laws and regulations by federal, state and local authorities.  The primary areas of environmental law that have the potential to most significantly impact PSE’s operations and costs include:

Air and Climate Change Protection

PSE owns numerous thermal generation facilities, including seven natural gas plants and an ownership percentage of a coal plant in Colstrip, Montana (Colstrip).  All these facilities are governed by the Clean Air Act (CAA) and all have CAA Title V operation permits that must be renewed every five years.  These facilities also emit greenhouse gases (GHGs), and thus are also subject to any current or future GHG or climate change legislation or regulation.  Colstrip represents PSE’s most significant source of GHG emissions.

Species Protection

PSE owns three hydroelectric plants and three wind farms and numerous miles of above ground electric distribution and transmission lines which can be impacted by laws related to species protection.  A number of species of fish have been listed as threatened or endangered under the Endangered Species Act (ESA), which influences hydroelectric operations, and may affect PSE operations, potentially representing cost exposure and operational constraints.  Similarly, there are a number of avian and terrestrial species that have been listed as threatened or endangered under the ESA or are protected by the Migratory Bird Act.  Designations of protected species under these two laws have the potential to influence operation of our wind farms and above ground transmission and distribution systems.

Remediation of Contamination

PSE and its predecessors are responsible for environmental remediation at various contaminated sites.  These include properties currently and formerly owned by PSE, as well as third party owned properties in which hazardous substances were generated or released.  Cleanup laws PSE may be subject to primarily include the Comprehensive Environmental Response, Compensation and Liability Act (federal) and the Model Toxics Control Act (state).  These laws may hold liable any current or past owner, or operator of a contaminated site, as well as, any generator, arranger or disposer regulated substances.

Hazardous and Solid Waste and PCB Handling and Disposal

Related to certain operations, including power generation and transmission and distribution maintenance, PSE must handle and dispose of certain hazardous and solid wastes, as well as, PCB contaminated wastes.  These actions are regulated by the Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act (federal), the Toxic Substances Control Act (federal), and the dangerous waste regulations (state) that impose complex requirements on handling and disposing of regulated substances.

Water Protection  

PSE facilities that discharge wastewater or storm water, or store bulk petroleum products are governed by the Clean Water Act (federal and state) which includes the Oil Pollution Act amendments.  This includes most all generation facilities (all of which have water discharges and some of which have bulk fuel storage), and due to recent changes in state storm water regulations also includes many other facilities and construction projects depending on drainage, facility or construction activities, and chemical, petroleum and material storage.

Siting New Facilities

In siting new generation, transmission or distribution, PSE is subject to the State Environmental Policy Act, and may be subject to the federal National Environmental Policy Act, if there is a federal nexus, as well as, other local siting and zoning ordinances.  These requirements may potentially require mitigation of environmental impacts to the fullest extent possible as well as other measures that can add significant cost to new facilities.

RECENT AND FUTURE ENVIRONMENTAL LAW AND REGULATION

Recent and future environmental law and regulations may be imposed at a federal, state or local level and may have a significant impact on cost of PSE operations.  PSE monitors legislative and regulatory developments for environmental issues with the potential to alter the operation and cost of our generation plants, transmission and distribution system, and other assets.  Recent, pending and potential future environmental law and regulations with the most significant potential impacts to PSE’s operations and costs are described below.

Climate Change and Greenhouse Gas Emissions

PSE recognizes the growing concern that increased atmospheric concentrations of GHG contribute to climate change.  PSE believes that climate change is an important issue that requires careful analysis and considered responses.  A climate policy continues to evolve at the state and federal levels and PSE remains involved in state, regional and federal policymaking activities. PSE will continue to monitor the development of any climate change or climate change related air emission reduction initiative at the state and western regional level.  PSE will also consider the impact of any future legislation or new government regulation on the cost of generation in its IRP process.

Most recent definitive federal legislative activity on climate change occurred in June 2009; the United States House of Representatives passed H.R. 2454, the American Clean Energy and Security Act.  The bill implements a cap-and-trade system of allowances to reduce GHG emissions 17.0% below 2005 levels by 2020, reaching an eventual target of 83.0% below 2005 levels by 2050.  However, the 111th Congress ended without enacting any major law to limit or reduce GHG emissions.

Recent federal climate change regulation includes the Tailoring Rule, which became effective January 2, 2011, sets permit levels for GHG emissions in two phases for power plants and other large stationary sources.  The ruling limits the amount of GHG emissions a facility can emit by requiring installment of Best Available Control Technology (BACT).  Phase I requires existing facilities that emit more than 100,000 tons of emissions per year to comply with the new BACT rules when air permits are renewed or when major modifications are made after January 2011.  Phase II, which begins after July 2011, requires preconstruction permits using BACT for new projects that emit 100,000 tons of emissions per year or existing projects that make major modifications and that emit more than 75,000 tons per year.  Currently the EPA has only released BACT guidance for coal technology.  The EPA’s work to determine natural gas turbine BACT guidance is ongoing.  Potential impacts on Colstrip are being evaluated and impacts to our gas fleet cannot yet be determined.

Beginning on March 31, 2011, PSE will be required to submit, on an annual basis, a report of its GHG emissions to the EPA including a report of emissions from all individual power plants emitting over 25,000 tons per year of GHGs and from certain natural gas distribution operations.  Capital investments to monitor GHGs from the power plants and in the distribution system are not required at this time.  Since 2002, PSE has voluntarily undertaken an annual inventory of its GHG emissions associated with PSE’s total electric retail load, which was 20.9 million MWh in 2010, served from a supply portfolio of owned and purchased resources.  The most recent data indicate that PSE’s total GHG emissions (direct and indirect) from its electric supply portfolio in 2009 were 14.4 million tons of carbon dioxide equivalent.  Since 2009, new generation facilities have resulted in combined GHG emissions of 591,935 tons of carbon dioxide equivalent.  Approximately 36.4% of PSE’s total GHG emissions (approximately 5.3 million tons) are associated with PSE’s ownership and contractual interests in Colstrip.

In November 2010, the EPA released two more GHG reporting rules affecting PSE. The first rule, commonly referred to as Subpart DD, requires owners and operators of electric power system facilities with a total nameplate capacity exceeding 17,820 pounds of sulfur hexafluoride to report emissions from its use of electrical transmission and distribution equipment. The second rule, commonly referred to as Subpart W, requires certain oil and natural gas operations, including distribution and storage, to report GHG emissions from leaks and certain combustions activities.  PSE will submit the required information as part of its annual filing to the EPA beginning on March 31, 2012.

While Colstrip remains a significant portion of PSE’s GHG emissions, Colstrip is an essential part of the diversified portfolio PSE owns and/or operates for its customers.  Consequently, PSE’s overall emissions strategy demonstrates a concerted effort to manage customers’ needs with an appropriate balance of new renewable generation, existing generation owned and/or operated by PSE and significant energy efficiency efforts.

Mercury Emissions

The state of Montana issued regulations limiting mercury emissions from coal-fired plants on October 16, 2006 (with limits of 0.9 lbs/Trillion British thermal units for plants burning coal like that used at Colstrip) which took effect on January 1, 2010.  Mercury control equipment has been installed at Colstrip and is operating at a level that meets the current Montana limit.  Compliance based on a rolling 12-month average was confirmed in January 2011.  Colstrip continues to monitor whether additional controls, if any, are necessary depending on actual long-term performance.

Mercury regulation at a federal level is currently in litigation.  Under current court proceedings, the EPA is required to propose a standard that will limit the amount of toxic mercury a coal and oil-fired power plant is allowed to emit.  The proposal deadline is March 16, 2011 with a finalized rule by November 16, 2011.  The EPA will determine the maximum achievable control technology emission rate limitations for coal-fired units based on coal type.  PSE cannot predict with any certainty what the federal mercury limit will be, but Colstrip is currently meeting a relatively low state standard for mercury emissions.

Additional Colstrip Emission Controls

On June 15, 2005, the EPA issued the Clean Air Visibility rule to address regional haze or regionally-impaired visibility caused by multiple sources over a wide area.  The rule defines Best Available Retrofit Technology (BART) requirements for electric generating units, including presumptive limits for sulfur dioxide, particulate matter and nitrogen oxide controls for large units.  In February 2007, Colstrip was notified by the EPA that Colstrip Units 1 & 2 were determined to be subject to the EPA’s BART requirements.  A BART engineering analysis for Colstrip Units 1 & 2 was submitted in August 2007 and additional requested analyses were submitted in June 2008.  On November 5, 2010, the EPA issued a request for additional reasonable progress information for Colstrip Units 3 & 4 which is currently being prepared.  PSE cannot yet determine the outcome of these analyses or information requests.

Coal Combustion Residuals

On June 21, 2010, the EPA issued a proposed rulemaking for the “Identification and Listing of Special Wastes: Disposal of Coal Combustion Residuals from Electric Utilities” which proposes different regulatory mechanisms to regulate coal ash.  The EPA received numerous comments on the respective proposals in November 2010, including comments from PSE and other Colstrip owners.  The EPA has announced that a final rule will be issued in 2011.

To date, EPA has proposed three regulatory options.  Under the first two options, coal ash could be regulated as a solid waste under Subtitle D provisions of the Resource Conservation and Recovery Act (RCRA).  This would give authority to the states to oversee a set of performance standards for handling and disposal.  Coal ash would be listed as non-hazardous and would allow wet handling to continue, and it would allow continued use of surface impoundments provided they are equipped with protective liners.  One of these two options would require significantly less modifications to closed as well as in-use impoundments.

Under the third option, coal ash could be regulated as a hazardous waste under Subtitle C provisions of the RCRA, which would make coal ash subject to a comprehensive program of federally enforceable requirements for waste management and disposal.  Regulation under Subtitle C would essentially require the phase-out of wet handling and surface impoundments. The EPA estimates over 500 surface impoundments would be affected by this ruling.  The EPA is expected to issue a final ruling in 2011.

Impact to Colstrip operations and PSE, could range from minimal to significant.  Due to the wide range in the options proposed by EPA PSE cannot determine impacts with any more certainty at this time, but we are involved with monitoring development of the final rule and advocating for reasonable approach that would be protective of the environment and cost-effective.

PCBs

On April 7, 2010, the EPA issued a Advance Notice of Proposed Rule Making (ANPRM) soliciting information on a broad range of questions concerning inventory, management, use, and disposal of PCB-containing equipment.  EPA is using this ANPRM to seek data to better evaluate whether to initiate a rulemaking process geared toward a mandatory phase-out of all PCBs. This would likely remove all existing use authorizations for PCBs in electrical and gas pipeline equipment. As proposed, the ANPRM would mandate a phase out of in-service PCBs through a phased process with full removal achieved by 2025.

The end of the comment period for the ANPRM was initially July 6, 2010 but due to the volume of comments received, an extension was granted to August 20, 2010 with the suggested issuance of a Notice in May 2012.  PSE provided comments through both the Utilities Solid Waste Advocacy Group (USWAG) as well as the American Gas Association (AGA).  Upon receiving all comments, EPA has rescheduled the issuance to April 2013.  At this time, PSE cannot determine what the impacts of this NPRM will have on its operations but will continue to work closely with USWAG and AGA to monitor develops and advocate for a reasonable approach that would be protective of the environment and cost-effective.

EXECUTIVE OFFICERS OF THE REGISTRANTS

The executive officers of Puget Energy as of March 1, 2011 are listed below along with their business experience during the past five years.  Officers of Puget Energy are elected for one-year terms.

Name	Age	Offices
K. J. Harris	46	President and Chief Executive Officer since March 1, 2011; President July 2010 – February 2011; Executive Vice President and Chief Resource Officer 2007 – 2010; Senior Vice President Regulatory Policy and Energy Efficiency 2005 – 2007.
J. W. Eldredge	60	Vice President, Controller and Chief Accounting Officer since May 2007; Vice President, Corporate Secretary and Chief Accounting Officer 2005 – 2007.
D. E. Gaines	54	Vice President Finance and Treasurer since March 2002.
S. R. Secrist	49	Vice President, General Counsel and Chief Ethics and Compliance Officer since January 2011; Interim General Counsel October 2010 – January 2011; Deputy General Counsel 2006 – October 2010.
B. A. Valdman	48	Senior Vice President and Chief Financial Officer since February 2011; Executive Vice President and Chief Operating Officer May 2007 – January 2011; Senior Vice President Finance and Chief Financial Officer 2003 – 2007.

The executive officers of PSE as of March 1, 2011 are listed below along with their business experience during the past five years.  Officers of PSE are elected for one-year terms.

Name	Age	Offices
K. J. Harris	46	President and Chief Executive Officer since March 1, 2011; President July 2010 – February 2011; Executive Vice President and Chief Resource Officer 2007 – 2010; Senior Vice President Regulatory Policy and Energy Efficiency 2005 – 2007.
J. W. Eldredge	60	Vice President, Controller and Chief Accounting Officer since May 2007; Vice President, Corporate Secretary, Controller and Chief Accounting Officer 2001 – 2007.
D. E. Gaines	54	Vice President Finance and Treasurer since March 2002.
E. M. Markell	59	Senior Vice President and Chief Strategy Officer since February 2011; Executive Vice President and Chief Financial Officer May 2007 – January 2011; Senior Vice President Energy Resources 2003 – 2007.
S. McLain	54	Senior Vice President Delivery Operations since February 2011; Senior Vice President Operations 2003 – January 2011.
M. D. Mellies	50	Senior Vice President and Chief Administrative Officer since February 2011; Vice President Human Resources 2005 – January 2011.
S. R. Secrist	49	Vice President, General Counsel and Chief Ethics and Compliance Officer since January 2011; Interim General Counsel October 2010 – January 2011; Deputy General Counsel 2006 – October 2010.
B. A. Valdman	48	Senior Vice President and Chief Financial Officer since February 2011; Executive Vice President and Chief Operating Officer May 2007 – January 2011; Senior Vice President Finance and Chief Financial Officer 2003 – 2007.
P. M. Wiegand	58	Senior Vice President Energy Operations since February 2011; Senior Vice President Power Generation 2010 – January 2011; Vice President Power Generation 2007 – 2010; Vice President Project Development & Contract Management 2003 – 2007.

ITEM 1A.  RISK FACTORS

The following risk factors, in addition to other factors and matters discussed elsewhere in this report, should be carefully considered.  The risks and uncertainties described below are not the only risks and uncertainties that Puget Energy and PSE may face.  Additional risks and uncertainties not presently known or currently deemed immaterial also may impair PSE’s business operations.  If any of the following risks actually occur, Puget Energy’s and PSE’s business, results of operations and financial conditions would suffer.

RISKS RELATING TO PSE’s BUSINESS

The actions of regulators can significantly affect PSE’s earnings, liquidity and business activities.

The rates that PSE is allowed to charge for its services is the single most important item influencing its financial position, results of operations and liquidity.  PSE is highly regulated and the rates that it charges its wholesale and retail customers are determined by both the Washington Commission and the FERC.

PSE is also subject to the regulatory authority of the Washington Commission with respect to accounting, operations, the issuance of securities and certain other matters, and the regulatory authority of the FERC with respect to the transmission of electric energy, the sale of electric energy at wholesale, accounting and certain other matters.  Policies and regulatory actions by these regulators could have a material impact on PSE’s financial position, results of operations and liquidity.

PSE’s recovery of costs is subject to regulatory review and its operating income may be adversely affected if its costs are disallowed.

The Washington Commission determines the rates PSE may charge to its electric retail customers based in part on historic test year costs plus weather normalized assumptions about rate year hydrological conditions and power costs.  Non-energy costs for natural gas retail customers are based on historic test year costs.  If in a specific year PSE’s costs are higher than what is allowed to be recovered in rates, revenue may not be sufficient to permit PSE to earn its allowed return or to cover its costs.  In addition, the Washington Commission decides what level of expense and investment is reasonable and prudent in providing electric and natural gas service.  If the Washington Commission decides that part of PSE’s costs do not meet the standard, those costs may be disallowed partially or entirely and not recovered in rates.  For these reasons, the rates authorized by the Washington Commission may not be sufficient to earn the allowed return or recover the costs incurred by PSE in a given period.

The PCA mechanism, by which variations in PSE’s power costs are apportioned between PSE and its customers pursuant to a graduated scale, could result in significant increases in PSE’s expenses if power costs are significantly higher than the baseline rate.

PSE has a PCA mechanism that provides for recovery of power costs from customers or refunding of power cost savings to customers, as those costs vary from the “power cost baseline” level of power costs which are set, in part, based on normalized assumptions about weather and hydrological conditions.  Excess power costs or power cost savings will be apportioned between PSE and its customers pursuant to the graduated scale set forth in the PCA mechanism.  As a result, if power costs are significantly higher than the baseline rate, PSE’s expenses could significantly increase.

PSE may be unable to acquire energy supply resources to meet projected customer needs or may fail to successfully integrate such acquisitions.  

PSE projects that future energy needs will exceed current purchased and Company-controlled power resources.  As part of PSE’s business strategy, it plans to acquire additional electric generation and delivery infrastructure to meet customer needs.  If PSE cannot acquire additional energy supply resources at a reasonable cost, it may be required to purchase additional power in the open market at a cost that could significantly increase its expenses thus reducing earnings and cash flows.  Additionally, PSE may not be able to timely recover some or all of those increased expenses through ratemaking.  While PSE expects to identify the benefits of new energy supply resources prior to their acquisition and integration, it may not be able to achieve the expected benefits of such energy supply sources.

PSE’s cash flow and earnings could be adversely affected by potential high prices and volatile markets for purchased power, increased customer demand for energy, recurrence of low availability of hydroelectric resources, outages of its generating facilities or a failure to deliver on the part of its suppliers.

The utility business involves many operating risks.  If PSE’s operating expenses, including the cost of purchased power and natural gas, significantly exceed the levels recovered from retail customers, its cash flow and earnings would be negatively affected.  Factors which could cause purchased power and natural gas costs to be higher than anticipated include, but are not limited to, high prices in western wholesale markets during periods when PSE has insufficient energy resources to meet its load requirements and/or high volumes of energy purchased in wholesale markets at prices above the amount recovered in retail rates due to:

· Increases in demand due, for example, either to weather or customer growth;

· Below normal energy generated by PSE-owned hydroelectric resources due to low streamflow conditions or precipitation;

· Extended outages of any of PSE-owned generating facilities or the transmission lines that deliver energy to load centers;

· Failure to perform on the part of any party from which PSE purchases capacity or energy; and

· The effects of large-scale natural disasters on a substantial portion of distribution infrastructure.

PSE’s electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased power purchase costs.  

PSE owns and operates coal, natural gas-fired, hydroelectric, wind-powered and oil-fired generating facilities.  Operation of electric generating facilities involves risks that can adversely affect energy output and efficiency levels.  Included among these risks are:

· Increased prices for fuel and fuel transportation as existing contracts expire;

· Facility shutdowns due to a breakdown or failure of equipment or processes or interruptions in fuel supply;

· Disruptions in the delivery of fuel and lack of adequate inventories;

· Labor disputes;

· Inability to comply with regulatory or permit requirements;

· Disruptions in the delivery of electricity;

· Operator error or safety related stoppages;

· Terrorist attacks; and

· Catastrophic events such as fires, explosions, floods or other similar occurrences.

PSE is subject to the commodity price, delivery and credit risks associated with the energy markets.  

In connection with matching loads and resources, PSE engages in wholesale sales and purchases of electric capacity and energy, and, accordingly, is subject to commodity price risk, delivery risk, credit risk and other risks associated with these activities.  Credit risk includes the risk that counterparties owing PSE money or energy will breach their obligations.  Should the counterparties to these arrangements fail to perform, PSE may be forced to enter into alternative arrangements.  In that event, PSE’s financial results could be adversely affected.  Although PSE takes into account the expected probability of default by counterparties, the actual exposure to a default by a particular counterparty could be greater than predicted.

To lower its financial exposure related to commodity price fluctuations, PSE may use forward delivery agreements, swaps and option contracts to hedge commodity price risk with a diverse group of counterparties.  However, PSE does not always cover the entire exposure of its assets or positions to market price volatility and the coverage will vary over time.  To the extent PSE has unhedged positions or its hedging procedures do not work as planned, fluctuating commodity prices could adversely impact its results of operations.

Costs of compliance with environmental, climate change and endangered species laws are significant and the cost of compliance with new and emerging laws and regulations and the incurrence of associated liabilities could adversely affect PSE’s results of operations.

PSE’s operations are subject to extensive federal, state and local laws and regulations relating to environmental, including air and climate protection, endangered species protection, remediation of contamination, waste handling and disposal, water protection and siting new facilities.  To comply with these legal requirements, PSE must spend significant sums on measures including resource planning, remediation, monitoring, analysis, mitigation measures, pollution control equipment and emissions related abatement and fees.  New environmental laws and regulations affecting PSE’s operations may be adopted, and new interpretations of existing laws and regulations could be adopted or become applicable to PSE or its facilities which may substantially increase environmental expenditures incurred by PSE in the future.  Compliance with these or other future regulations could require significant capital expenditures by PSE and adversely affect PSE’s financial position, results of operations, cash flows and liquidity.  In addition, PSE may not be able to recover all of its costs for such expenditures through electric and natural gas rates at current levels in the future.

With respect to endangered species laws, the listing or proposed listing of several species of salmon in the Pacific Northwest is causing a number of changes to the operations of hydroelectric generating facilities on Pacific Northwest rivers, including the Columbia River.  These changes could reduce the amount, and increase the cost, of power generated by hydroelectric plants owned by PSE, or in which PSE has an interest, and increase the cost of the permitting process for these facilities.

Under current law, PSE is also generally responsible for any on-site liabilities associated with the environmental condition of the facilities that it currently owns or operates or has previously owned or operated.  The incurrence of a material environmental liability or the new regulations governing such liability could result in substantial future costs and have a material adverse effect on PSE’s results of operations and financial condition.

Specific to climate change, Washington state has adopted both a renewable portfolio standard and greenhouse gas legislation, including an emission performance standard provision.  PSE cannot yet determine the costs of compliance with the recently enacted legislation.  Recent decisions related to climate change by the United States Supreme Court and the EPA, together with efforts by Congress, have drawn greater attention to this issue at the federal, state and local level.  While PSE cannot yet determine costs associated with these or future decisions or potential future legislation, there may be a significant impact on the cost of carbon-intensive coal generation, in particular.

PSE’s business is dependent on its ability to successfully access capital.  

PSE relies on access to bank borrowings and short-term money markets as sources of liquidity and longer-term debt markets to fund its utility construction program and other capital expenditure requirements not satisfied by cash flow from its operations or equity investment from its parent, Puget Energy.  If PSE is unable to access capital on reasonable terms, its ability to pursue improvements or acquisitions, including generating capacity, which may be relied on for future growth and to otherwise implement its strategy, could be adversely affected.  Capital and credit market disruptions, a downgrade of PSE’s credit rating or the imposition of restrictions on borrowings under its credit facility in the event of a deterioration of financial ratios, may increase PSE’s cost of borrowing or adversely affect the ability to access one or more financial markets.

PSE’s operating results fluctuate on a seasonal and quarterly basis.  

PSE’s business is seasonal and weather patterns can have a material impact on its revenue, expenses and operating results.  Because natural gas is heavily used for residential and commercial heating, demand depends heavily on weather patterns in PSE’s service territory, and a significant amount of natural gas revenue is recognized in the first and fourth quarters related to the heating season.  However, conservation efforts may result in decreased customer demand, despite normal or lower than normal temperatures.  Demand for electricity is also greater in the winter months associated with heating.  Accordingly, PSE’s operations have historically generated less revenue and income when weather conditions are milder in the winter.  In the event that the Company experiences unusually mild winters, results of operations and financial condition could be adversely affected.

PSE may be adversely affected by extreme events in which PSE is not able to promptly respond and repair the electric and gas infrastructure system.

PSE must maintain an emergency planning and training program to allow PSE to quickly respond to extreme events.  Without emergency planning, PSE is subject to availability of outside contractors during an extreme event which may impact the quality of service provided to PSE’s customers.  In addition, a slow response to extreme events may have an adverse affect on earnings as customers may be without electricity and natural gas for an extended period of time.

PSE may be negatively affected by its inability to attract and retain professional and technical employees.

PSE’s ability to implement a workforce succession plan is dependent upon PSE’s ability to employ and retain skilled professional and technical workers.  Without a skilled workforce, PSE’s ability to provide quality service to PSE’s customers and to meet regulatory requirements could affect PSE’s earnings.

PSE depends on an aging work force and third party vendors to perform certain important services.

PSE continues to be concerned about the availability and aging of skilled workers for special complex utility functions.  PSE also hires third parties to perform a variety of normal business functions, such as power plant maintenance, data warehousing and management, electric transmission, electric and gas distribution construction and maintenance, certain billing and metering processes, call center overflow and credit and collections.  The unavailability of skilled workers or unavailability of such vendors could adversely affect the quality and cost of PSE’s gas and electric service and accordingly PSE’s results of operations.

Poor performance of pension and postretirement benefit plan investments and other factors impacting plan costs could unfavorably impact PSE’s cash flow and liquidity.

PSE provides a defined benefit pension plan to PSE employees and postretirement benefits to certain PSE employees and former employees.  Costs of providing these benefits are based in part on the value of the plan’s assets and therefore, continued adverse market performance could result in lower rates of return for the investments that fund PSE’s pension and postretirement benefits plans and could increase PSE’s funding requirements related to the pension plans.  Any contributions to PSE’s plans in 2011 and beyond as well as the timing of the recovery of such contributions in general rate cases could impact PSE’s cash flow and liquidity.

RISKS RELATING TO PUGET ENERGY AND PSE OPERATIONS

A downgrade in Puget Energy’s or PSE’s credit rating could negatively affect the ability to access capital and the ability to hedge in wholesale markets.

Although neither Puget Energy nor PSE has any rating downgrade provisions in its credit facilities that would accelerate the maturity dates of outstanding debt, a downgrade in the Companies’ credit ratings could adversely affect the ability to renew existing or obtain access to new credit facilities and could increase the cost of such facilities.  For example, under Puget Energy’s and PSE’s facilities, the borrowing spreads over the London Interbank Offered Rate (LIBOR) and commitment fees increase if their respective corporate credit ratings decline.  A downgrade in commercial paper ratings could increase the cost of commercial paper and limit or preclude PSE’s ability to issue commercial paper under its current programs.

Any downgrade below investment grade of PSE’s corporate credit rating could cause counterparties in the wholesale electric, wholesale natural gas and financial derivative markets to request PSE to post a letter of credit or other collateral, make cash prepayments, obtain a guarantee agreement or provide other mutually agreeable security, all of which would expose PSE to additional costs.

The Company may be negatively affected by unfavorable changes in the tax laws or their interpretation.

Changes in tax law, related regulations or differing interpretation or enforcement of applicable law by the IRS or other taxing jurisdiction could have a material adverse impact on the Company’s financial statements.  The tax law, related regulations and case law are inherently complex.  The Company must make judgments and interpretations about the application of the law when determining the provision for taxes.  Disputes over interpretations of tax laws may be settled with the taxing authority in examination, upon appeal or through litigation.  The Company’s tax obligations include income, real estate, public utility, municipal, sales and use, business and occupation and employment-related taxes and ongoing appeals issues related to these taxes.  These judgments may include reserves for potential adverse outcomes regarding tax positions that may be subject to challenge by the taxing authorities.

RISKS RELATING TO PUGET ENERGY’S CORPORATE STRUCTURE

As a holding company, Puget Energy depends on PSE’s ability to pay dividends. 

As a holding company with no significant operations of its own, the primary source of funds for the repayment of debt and other expenses, as well as payment of dividends to its shareholder, is cash dividends PSE pays to Puget Energy.  PSE is a separate and distinct legal entity and has no obligation to pay any amounts to Puget Energy, whether by dividends, loans or other payments.  The ability of PSE to pay dividends or make distributions to Puget Energy, and accordingly, Puget Energy’s ability to pay dividends or repay debt or other expenses, will depend on PSE’s earnings, capital requirements and general financial condition.  If Puget Energy does not receive adequate distributions from PSE, it may not be able to meet its obligations or pay dividends.

The payment of dividends by PSE to Puget Energy is restricted by provisions of certain covenants applicable to long-term debt contained in PSE’s electric and natural gas mortgage indentures.  Beginning February 6, 2009, pursuant to the terms of the Washington Commission merger order, PSE may not declare or pay dividends if PSE’s common equity ratio, calculated on a regulatory basis, is 44.0% or below except to the extent a lower equity ratio is ordered by the Washington Commission.  Also, pursuant to the merger order, PSE may not declare or make any distribution, unless on the date of distribution PSE’s corporate credit/issuer rating is investment grade, or if its credit ratings are below investment grade, PSE’s ratio of Earnings Before Interest, Tax, Depreciation and Amortization (EBITDA) to interest expense for the four most recently ended fiscal quarters prior to such date is equal to or greater than three to one.  The common equity ratio, calculated on a regulatory basis, was 46.5% at December 31, 2010 and the EBITDA to interest expense was 3.9 to one.

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

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

The principal electric generating plants and underground natural gas storage facilities owned by PSE are described under Item 1, Business – Electric Supply and Gas Supply.  PSE owns its transmission and distribution facilities and various other properties.  Substantially all properties of PSE are subject to the liens of PSE’s mortgage indentures.  The Company’s corporate headquarters is housed in a leased building located in Bellevue, Washington.

ITEM 3. LEGAL PROCEEDINGS

From time to time, the Company is involved in litigation relating to claims arising out of its operations in the normal course of business.  The following is a description of legal proceedings that are material to PSE’s operations:

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.

Pacific Northwest Refund Proceeding.  In October 2000, PSE filed a complaint with the FERC (Docket No. EL01-10) against “all jurisdictional sellers” in the Pacific Northwest seeking prospective price caps consistent with any result the FERC ordered for the California markets.  The FERC issued an order including price caps in July 2001, and PSE moved to dismiss the proceeding.  In response to PSE’s motion, various entities intervened and sought to convert PSE’s complaint into one seeking retroactive refunds in the Pacific Northwest.  The FERC rejected that effort, after holding what the FERC referred to as a “preliminary evidentiary hearing” before an administrative law judge.  In April 2009, the United States Court of Appeals for the Ninth Circuit (Ninth Circuit) rejected the requests for rehearing filed in this matter and remanded the proceeding to the FERC.  The FERC is now considering what response to take to the Ninth Circuit remand order, as petitions for review by the Supreme Court were denied on January 11, 2010.  PSE intends to vigorously defend its position but is unable to predict the outcome of this matter.

Proceedings Relating to Colstrip

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

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

Proceedings Related to the Bonneville Power Administration

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

On May 3, 2007, the Ninth Circuit issued an opinion in Portland Gen. Elec. v. BPA, Case No. 01-70003, in which proceeding the actions of the BPA in entering into settlement agreements regarding the REP with PSE and with other investor-owned utilities were challenged.  In this opinion, the Ninth Circuit granted petitions for review and held the settlement agreements entered into between the BPA and the investor-owned utilities being challenged in that proceeding to be inconsistent with statute.  On May 3, 2007, the Ninth Circuit also issued an opinion in Golden Northwest Aluminum v. BPA, Case No. 03-73426, in which proceeding the petitioners sought review of the BPA’s 2002-2006 power rates.  In this opinion, the Ninth Circuit granted petitions for review and held that BPA unlawfully shifted onto its preference customers the costs of its settlements with the investor-owned utilities.  On October 11, 2007, the Ninth Circuit remanded the May 2004 agreement to the BPA in light of the Portland Gen. Elec. v. BPA opinion and dismissed the remaining three pending cases regarding settlement agreements.

In March 2008, the BPA and PSE signed an agreement pursuant to which the BPA made a payment to PSE related to the REP benefits for the fiscal year ended September 30, 2008, which payment is subject to true-up depending upon the amount of any REP benefits ultimately determined to be payable to PSE.

In September 2008, the BPA issued its record of decision in its reopened WP-07 rate proceeding to respond to the various Ninth Circuit opinions.  In this record of decision, the BPA adjusted its fiscal year 2009 rates, determined the amounts of REP benefits it considered to have been improperly paid after fiscal year 2001 to PSE and the other regional investor-owned utilities, and determined that such amounts are to be recovered through reductions in REP benefit payments to be made over a number of years.  The amount determined by the BPA to be recovered through reductions commencing October 2007 in REP payments for PSE’s residential and small farm customers was approximately $207.2 million plus interest on unrecovered amounts to the extent that PSE receives any REP benefits for its customers in the future.  However, these BPA determinations are subject to subsequent administrative and judicial review, which may alter or reverse such determinations.  PSE and others, including a number of preference agency and investor-owned utility customers of the BPA, in December 2008 filed petitions for review in the Ninth Circuit of various of these BPA determinations.  Any change to the REP would be passed to customers.

In September 2008, the BPA and PSE signed a short-term Residential Purchase and Sale Agreement (RPSA) under which the BPA is to pay REP benefits to PSE for fiscal years ending September 30, 2009 through 2011.  In December 2008, the BPA and PSE signed another, long-term RPSA under which the BPA is to pay REP benefits to PSE for the period October 2011 through September 2028.  PSE and other customers of the BPA in December 2008 filed petitions for review in the Ninth Circuit of the short-term and long-term RPSAs signed by PSE (and similar RPSAs signed by other investor-owned utility customers of the BPA) and the BPA’s record of decision regarding such RPSAs.  Generally, REP benefit payments under a RPSA are based on the amount, if any, by which a utility’s average system cost exceeds the BPA’s Priority Firm (PF) Exchange rate for such utility.  The average system cost for a utility is determined using an average system cost methodology adopted by the BPA.  The average system cost methodology adopted by the BPA and the average system cost determinations, REP overpayment determinations, and the PF Exchange rate determinations by the BPA are all subject to the 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 the BPA to PSE.  As discussed above, the BPA has determined to reduce such payments based on its determination of REP benefit overpayments after fiscal year 2001.

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

Proceedings Relating to Snoqualmie Falls

On July 7, 2010, a lawsuit was filed in the U.S. District Court for the Western District of Washington by the Snoqualmie Valley Preservation Alliance, a group of downstream landowners, against the United States Army Corps of Engineers (Corps) challenging permits issued by the Corps in connection with the redevelopment of the Snoqualmie Falls Hydroelectric Project.  Plaintiffs requested an order to stop work at the project pending further review of downstream impacts.  PSE sought and was granted permission to intervene in the proceeding.  Motions for summary judgment have been filed by the plaintiff and the Corps.  PSE joined the Corps’ motion and filed a motion for summary judgment arguing the plaintiff’s claims are barred as untimely and improper.  The parties await a determination by the Court.  The ultimate impact of the suit, if any, on PSE or the work currently underway on the project cannot be determined at this time.  The construction schedule has not been impacted by the lawsuit.

ITEM 4. REMOVED AND RESERVED

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Upon the completion of the merger on February 6, 2009, Puget Energy’s common stock was delisted from trading on the New York Stock Exchange (NYSE).  As a result of the merger, all of the outstanding shares of Puget Energy’s common stock, the only class of common equity of Puget Energy, are held by its direct parent Puget Equico, which is an indirect wholly-owned subsidiary of Puget Holdings.  The outstanding shares of PSE’s common stock, the only class of common equity of PSE, are held by Puget Energy and are not publicly traded.

In the first quarter of 2009, prior to the merger, Puget Energy declared quarterly dividends in the amount of $0.25 per share on each share of common stock outstanding and, in connection with the February 6, 2009 merger, Puget Energy also declared a special pro rata dividend of $0.04448 per share.

The payment of dividends on PSE common stock to Puget Energy is restricted by provisions of certain covenants applicable to long-term debt contained in PSE’s mortgage indentures in addition to terms of the Washington Commission merger order.  Puget Energy’s ability to pay dividends is also limited by the merger order issued by the Washington Commission as well as by the terms of its credit facilities.  For further discussion, see Item 1A, Risk Factors, Risks relating to Puget Energy’s Corporate Structure and Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations included in this report.

ITEM 6.  SELECTED FINANCIAL DATA

The following tables show selected financial data.  This information should be read in conjunction with the Management Discussion and Analysis and the audited consolidated financial statements and the related notes, included in Items 7 and 8 of this report, respectively.

	Successor 1				Predecessor 1
Puget Energy Summary of Operations	Year Ended December 31,		February 6, 2009 - December 31,		January 1, 2009 - February 5,		Year Ended December 31,
(Dollars in Thousands)	2010		2009		2009		2008		2007		2006
Operating revenue	$	3,122,217	$	2,925,148	$	403,713	$	3,357,773	$	3,220,147	$	2,907,063
Operating income		308,234		474,863		35,410		382,748		441,034		420,851
Income from continuing operations		30,311		174,015		12,756		154,929		184,676		167,224
Net income		30,311		174,015		12,756		154,929		184,464		219,216
Basic earnings per common share from continuing operations		N/A		N/A		N/A		1.20		1.57		1.44
Basic earnings per common share		N/A		N/A		N/A		1.20		1.57		1.89
Diluted earnings per common share from continuing operations		N/A		N/A		N/A		1.19		1.56		1.44
Diluted earnings per common share		N/A		N/A		N/A		1.19		1.56		1.88
Dividends per common share		N/A		N/A		N/A	$	1.00	$	1.00	$	1.00
Book value per common share		N/A		N/A		N/A		17.53		19.45		18.15
Total assets at year end	$	11,929,336	$	11,900,140	$	8,594,836	$	8,434,102	$	7,598,736	$	7,066,039
Long-term debt		4,132,713		3,790,698		2,520,860		2,270,860		2,428,860		2,608,360
Preferred stock subject to mandatory redemption 2		--		--		--		1,889		1,889		1,889
Junior subordinated notes		250,000		250,000		250,000		250,000		250,000		--
Junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities		--		--		--		--		--		37,750
Capital lease obligations		42,603		134,229		68,293		68,586		22,910		23,043

Puget Sound Energy Summary of Operations	Year Ended December 31,
(Dollars in Thousands)	2010		2009		2008		2007		2006
Operating revenue	$	3,122,217	$	3,328,501	$	3,357,773	$	3,220,147	$	2,907,063
Operating income		207,591		383,135		392,386		450,384		422,682
Net income		26,095		159,252		162,736		191,127		176,740
Total assets at year end	$	9,310,784	$	8,816,571	$	8,435,855	$	7,592,210	$	7,061,413
Long-term debt		2,953,860		2,638,860		2,270,860		2,428,860		2,608,360
Preferred stock subject to mandatory redemption 2		--		--		1,889		1,889		1,889
Junior subordinated notes		250,000		250,000		250,000		250,000		--
Junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities		--		--		--		--		37,750
Capital lease obligations		--		54,196		68,586		22,910		23,043

        _______________

1

All of the operations of Puget Energy are conducted through its subsidiary PSE.  “Predecessor” refers to the operations of Puget Energy and PSE prior to the consummation of the merger.  “Successor” refers to the operations of Puget Energy and PSE subsequent to the merger.  The merger was accounted for in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 805.  For a description of this transaction, see Note 3 to the consolidated financial statements included in Item 8 of this report.

2

All outstanding shares of preferred stock of PSE were redeemed in March 2009.  In connection with the merger, Puget Energy and PSE amended in their entirety their respective Articles of Incorporation and preferred stock is no longer authorized.

ITEM 7.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

OVERVIEW

Puget Energy is an energy services holding company and all of its operations are conducted through its subsidiary PSE, a regulated electric and natural gas utility company.  PSE is the largest electric and natural gas utility in the state of Washington, primarily engaged in the business of electric transmission, distribution and generation and natural gas distribution.  Puget Energy’s business strategy is to generate stable cash flows by offering reliable electric and natural gas service in a cost-effective manner through PSE.  On February 6, 2009, Puget Holdings completed its merger with Puget Energy.  Puget Holdings is a consortium of long-term infrastructure investors including Macquarie Infrastructure Partners I, Macquarie Infrastructure Partners II, Macquarie Capital Group Limited, Macquarie-FSS Infrastructure Trust, the Canada Pension Plan Investment Board, the British Columbia Investment Management Corporation, and the Alberta Investment Management Corporation.  As a result of the merger, Puget Energy is a direct wholly-owned subsidiary of Puget Equico, which is an indirect wholly-owned subsidiary of Puget Holdings.  Puget Energy accounted for the merger as a business combination and all its assets and liabilities were recorded at fair value as of the merger date.  PSE’s basis of accounting continues to be on a historical basis and PSE’s financial statements do not include any purchase accounting adjustments.  Puget Energy and PSE are collectively referred to herein as “the Company.”

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

For the year ended December 31, 2010, PSE’s net income was adversely affected by the following five factors:  (1) the impact of falling wholesale forward prices of electricity and natural gas on mark-to-market unrealized gains/losses on energy derivative contracts; (2) a decline in electric and natural gas retail and transportation customer sales primarily due to unusually warm temperatures in the Pacific Northwest during the first quarter of 2010 and weak economic conditions; (3) the effect of higher power costs resulting from below average hydrological and wind conditions that negatively impacted PSE’s electric generation; (4) PSE’s general tariff increases approved in April 2010, which were based on historical costs for non-power related items, are insufficient to recover capital and operating costs incurred and are anticipated to incur in the future; and (5) an adjustment in the California wholesale energy sales regulatory asset carrying value of PSE.

NON-GAAP FINANCIAL MEASURES

The following discussion includes financial information prepared in accordance with generally accepted accounting principles (GAAP), as well as return on equity excluding unrealized loss on derivative instruments (net income plus unrealized loss on derivative instruments dividend by average common equity) that is considered a “non-GAAP financial measure.”  This measure is a supplemental financial measure that is not prepared in accordance with GAAP.  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 return on equity excluding unrealized loss on derivative instruments is intended to supplement readers’ understanding of the Company’s operating performance.  Return on equity excluding unrealized loss on derivative instrument is used by the Company to determine whether the Company is collecting the appropriate earnings from its customers to allow recovery of investor’s capital.  Furthermore, this measure is not intended to replace return on equity (net income dividend by average common equity) as determined in accordance with GAAP as an indicator of operating performance and may not be comparable to similarly titled measures used by other companies.

The Company faced certain challenges during 2010 which caused a significant reduction in the return on equity as compared to other years.  The following table presents PSE’s return on equity for 2010:

(Dollars in Thousands)	Return on Equity		Average Common Equity		Percent
Return on equity	$	26,095	$	3,028,990	0.8	%
Plus: Unrealized loss on derivative instruments, after-tax		108,519		3,028,990	3.6	%
Return on equity excluding derivative instruments	$	134,614	$	3,028,990	4.4	%
Authorized regulated return on equity 1					10.1	%

_______________

1 The authorized regulated return on equity was approved by the Washington Commission in its general rate case order which became effective April 8, 2010.

The Company's 2010 return on equity, excluding derivative instruments, was 4.4%, which is lower than the authorized return on equity due to the following:

·   Electric retail kilowatt sales and natural gas therm sales for the year ended December 31, 2010 declined 2.3% and 1.9%, respectively, as compared to historical averages due to warmer temperatures in the first quarter of 2010 which is one of its highest revenue quarters for the year and, to a lesser extent, the impact of PSE’s residential and commercial customer conservation programs, as well as continued effects of weak economic conditions in the Pacific Northwest.

·   The Pacific Northwest experienced below normal hydrological and wind conditions which adversely impacted PSE’s power costs in the first quarter of 2010.  Hydroelectric and wind generation for the year ended December 31, 2010 decreased by 700,511 MWhs, or 11.8%, as compared to historical averages.  As a result, PSE’s power costs in excess of the baseline rate was $29.2 million due to purchasing or generating higher cost electricity to replace the decrease in generation from hydroelectric and wind generating projects.

·   PSE had requested electric and natural gas rate increases of $110.3 million and $27.2 million, respectively in 2009.  The Washington Commission approved general rate case increases of $74.1 million and $18.3 million for electric and natural gas customers, respectively which were effective April 8, 2010.  The difference between the allowed and requested increases included a rate of return with a lower equity return and lower equity component then requested, in addition to stricter interpretation of proforma adjustments from what was previously allowed.

·   As a result of the Washington Commission order of May 20, 2010, PSE adjusted the carrying value of its California wholesale energy sales regulatory asset in the second quarter of 2010 by $17.8 million pre-tax (from $21.1 million to $3.3 million), which impacted wholesale energy sales.

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

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

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

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

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

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

·   PSE’s ability to supply electricity and natural gas, either through company-owned generation, power purchase contracts or by procuring natural gas or electricity in wholesale markets;

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

·   Regulatory compliance costs, including those related to new and developing federal regulations of electric system reliability, state regulations of natural gas pipelines and federal, state and local environmental laws and regulations;

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

·   Wholesale commodity prices of electricity and natural gas; and

·   Increasing depreciation and related property taxes

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

Electric Rates

On April 2, 2010, the Washington Commission issued its order in PSE’s consolidated electric rate case filed in May 2009 which approved a general rate increase for electric customers of 3.7% annually, or $74.1 million, effective April 8, 2010.  In its order, the Washington Commission approved a weighted cost of capital of 8.1% and a capital structure that included 46.0% common equity with an after-tax return on equity of 10.1%.  For additional information on electric rates, see Note 4 to the consolidated financial statements included in Item 8 of this report.

PSE has a PCA mechanism that provides for recovery of power costs from customers or refunding of power cost savings to customers, as those costs vary from the “power cost baseline” level of power costs which are set, in part, based on normalized assumptions about weather and hydrological conditions.  Excess power costs or power cost savings are apportioned between PSE and its customers pursuant to the graduated scale set forth in the PCA mechanism.  As a result, if power costs are significantly higher than the baseline rate, PSE’s expenses could significantly increase.

The graduated scale is as follows:

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

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

Type of Rate Adjustment	Effective Date	Average Percentage Increase (Decrease) in Rates		Annual Increase (Decrease) in Revenue (Dollars in Millions)
Electric General Rate Case	April 8, 2010	3.7	%	$	74.1
Merger Rate Credit	February 13, 2009	(0.4	)		(6.7	)
Electric General Rate Case	November 1, 2008	7.1			130.2

Natural Gas Rates

On April 2, 2010, the Washington Commission issued its order, effective April 8, 2010, in PSE’s natural gas general rate case filed in May 2009, approving a general rate increase of 0.8% annually or $10.1 million.  In its order, the Washington Commission approved a weighted cost of capital of 8.1% and a capital structure that included 46.0% common equity with an after-tax return on equity of 10.1%.  For additional information on gas rates, see Note 4 to the consolidated financial statements included in Item 8 of this report.

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

Type of Rate Adjustment	Effective Date	Average Percentage Increase (Decrease) in Rates		Annual Increase (Decrease)  in Revenue (Dollars in Millions)
Purchased Gas Adjustment	November 1, 2010	1.9	%	$	18.3
Gas General Rate Case	April 8, 2010	0.8			10.1
Purchased Gas Adjustment	October 1, 2009 – October 31, 2010	(17.1	)		(198.1	)
Purchased Gas Adjustment	June 1, 2009 – May 31, 2010	(1.8	)		(21.2	)
Merger Rate Credit	February 13, 2009	(0.4	)		(3.6	)
Gas General Rate Case	November 1, 2008	4.6			49.2
Purchased Gas Adjustment	October 1, 2008 – September 30, 2009	11.1			108.8

Weather Conditions.  Weather conditions in PSE’s service territory can have a significant impact on customer energy usage, affecting PSE’s revenue and energy supply expenses.  PSE’s operating revenue and associated energy supply expenses are not generated evenly throughout the year.  While both PSE’s electric and natural gas sales are generally greatest during winter months, variations in energy usage by 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.  PSE reported lower customer usage for the year ended December 31, 2010 primarily due to warmer temperatures in the Pacific Northwest during the first quarter of 2010 as compared to the same period in 2009.  The average temperature during the first quarter of 2010 was 46.8 degrees, or 6.2 degrees warmer than the same period in 2009.  As a result of the warmer first quarter of 2010, heating degree days (difference in average daily temperature compared to 65 degrees) for the year ended December 31, 2010 were 7.1% lower than the same period in 2009.

Customer Demand.  PSE expects the number of natural gas customers to grow at rates slightly above electric customers.  Both residential electric and natural gas customers are expected to continue a long-term trend of slow decline of energy usage based on continued energy efficiency improvements and the effect of higher retail rates.  The effects of the current recession on Washington’s economy have exacerbated a decline in customer usage throughout 2010.

Access to Debt Capital.  PSE relies on access to bank borrowings and short-term money markets as sources of liquidity and longer-term debt markets to fund its utility construction program, to meet maturing debt obligations and other capital expenditure requirements not satisfied by cash flow from its operations or equity investment from its parent, Puget Energy.  Neither Puget Energy nor PSE have any debt outstanding whose maturity would accelerate upon a credit rating downgrade.  However, a ratings downgrade could adversely affect the Company’s ability to renew existing, or obtain access to new credit facilities and could increase the cost of such facilities.  For example, under Puget Energy’s and PSE’s credit facilities, both of which expire in 2014, the borrowing costs and commitment fees increase as their respective credit ratings decline.  If PSE is unable to access debt capital on reasonable terms, its ability to pursue improvements or acquisitions, including generating capacity, which may be relied on for future growth and to otherwise implement its strategy, could be adversely affected.  PSE monitors the credit environment and expects to continue to be able to access the capital markets to meet its short-term and long-term borrowing needs.

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

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

Other Challenges and Strategies

Energy Supply.  As noted in PSE’s IRP filed with the Washington Commission, PSE projects future energy needs will exceed current resources from long-term power purchase agreements and Company-controlled power resources.  The IRP identifies reductions in contractual supplies of energy and capacity available under certain long-term power purchase agreements, requiring replacement of supplies to meet projected demands.  Therefore, PSE’s IRP sets forth a multi-part strategy of implementing energy efficiency programs and pursuing additional renewable resources (primarily wind) and additional base load natural gas-fired generation to meet the growing needs of its customers.  If PSE cannot acquire needed energy supply resources at a reasonable cost, it may be required to purchase additional power in the open market at a cost that could, in the absence of regulatory relief, significantly increase its expenses and reduce earnings and cash flows.

Infrastructure Investment. PSE is investing in its utility infrastructure and customer service functions in order to meet regulatory requirements, serve customers’ energy needs and replace aging infrastructure.  These investments and operating requirements give rise to significant growth in depreciation and operating expenses, which are not recovered through the ratemaking process in a timely manner.  This “regulatory lag” is expected to continue for the foreseeable future.

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

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

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

RESULTS OF OPERATIONS

The following discussion should be read in conjunction with the audited consolidated financial statements and the related notes included elsewhere in this document.  Set forth below is the consolidated financial results of PSE for the years ended December 31, 2010, 2009 and 2008:

Puget Sound Energy	Year Ended December 31,						Percent Change		Year Ended December 31,			Percent Change
(Dollars in Thousands)	2010			2009			2010-2009			2008		2009-2008
Operating revenue:
Electric
Residential sales	$	1,078,262		$	1,067,274		1.0	%	$	1,046,897		1.9	%
Commercial sales		836,957			838,275		(0.2	)		800,878		4.7
Industrial sales		103,678			99,552		4.1			106,092		(6.2	)
Other retail sales, including unbilled revenue		12,787			16,424		(22.1	)		27,607		(40.5	)
Total retail sales		2,031,684			2,021,525		0.5			1,981,474		2.0
Transportation sales		11,000			10,623		3.5			7,840		35.5
Sales to other utilities and marketers		62,943			78,471		(19.8	)		84,716		(7.4	)
Other		1,842			(11,883	)	115.5			55,433		*
Total electric operating revenue		2,107,469			2,098,736		0.4			2,129,463		(1.4	)
Gas
Residential sales		648,649			795,756		(18.5	)		766,799		3.8
Commercial sales		301,083			357,110		(15.7	)		373,701		(4.4	)
Industrial sales		33,004			39,531		(16.5	)		43,974		(10.1	)
Total retail sales		982,736			1,192,397		(17.6	)		1,184,474		0.7
Transportation sales		14,082			13,014		8.2			14,700		(11.5	)
Other		14,713			19,334		(23.9	)		17,694		9.3
Total gas operating revenue		1,011,531			1,224,745		(17.4	)		1,216,868		0.6
Non-utility operating revenue		3,217			5,020		(35.9	)		11,442		(56.1	)
Total operating revenue		3,122,217			3,328,501		(6.2	)		3,357,773		(0.9	)
Operating expenses:
Energy costs:
Purchased electricity		774,007			887,306		12.8			903,317		1.8
Electric generation fuel		268,147			208,444		(28.6	)		212,333		1.8
Residential exchange		(75,109	)		(96,504	)	22.2			(40,664	)	*
Purchased gas		535,933			718,860		25.4			737,851		2.6
Net unrealized (gain) loss on derivative instruments		166,953			(1,254	)	*			7,538		*
Utility operations and maintenance		486,701			487,396		(0.1	)		461,632		(5.6	)
Non-utility expense and other		11,159			14,532		23.2			12,399		(17.2	)
Merger and related costs		--			23,908		*			--		*
Depreciation		292,634			269,386		(8.6	)		255,706		(5.3	)
Amortization		71,572			63,466		(12.8	)		56,422		(12.5	)
Conservation amortization		90,109			66,466		(35.6	)		61,650		(7.8	)
Taxes other than income taxes		292,520			303,360		3.6			297,203		(2.1	)
Total operating expenses		2,914,626			2,945,366		1.0			2,965,387		0.7
Operating income		207,591			383,135		(45.8	)		392,386		(2.4	)
Other income		45,153			52,812		(14.5	)		33,239		58.9
Other expense		(5,673	)		(6,524	)	13.0			(7,215	)	9.6
Interest expense		(220,854	)		(202,527	)	(9.0	)		(194,792	)	(4.0	)
Income before income taxes		26,217			226,896		(88.4	)		223,618		1.5
Income tax expense		122			67,644		99.8			60,882		(11.1	)
Net income	$	26,095		$	159,252		(83.6	)%	$	162,736		(2.1	)%

_____________

* Not meaningful

Puget Sound Energy

2010 compared to 2009

Summary Results of Operations

PSE’s net income in 2010 was $26.1 million with operating revenue of $3.1 billion as compared to $159.3 million with operating revenue of $3.3 billion in 2009.

The following are significant factors that impacted PSE’s net income for the year ended December 31, 2010:

·   Increase in net unrealized loss on derivative instruments of $168.2 million primarily due to falling forward market prices of electricity and natural gas.  PSE’s discontinuation of cash flow hedge accounting on July 1, 2009 resulted in additional volatility in net income.

·   Increase in depreciation and amortization expense of $31.4 million primarily due to additional capital expenditures on utility plant placed in service.

·   Increase in interest expense of $18.3 million related to additional debt outstanding.

·   Decrease in sales to other utilities and marketers of $15.6 million primarily due to the carrying value adjustment of the California wholesale energy sales regulatory asset of $17.8 million.

·   Decrease in income tax expense of $67.5 million, primarily due to lower taxable income.

·   Decrease in purchased electricity and electric generation fuel of $53.6 million primarily due to lower wholesale costs, lower customer usage offset by higher generation from coal fired plants.

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

2009 compared to 2008

Summary Results of Operations

PSE’s net income in 2009 was $159.3 million with operating revenue of $3.3 billion as compared to $162.7 million with operating revenue of $3.4 billion in 2008.

The following are significant factors that impacted PSE’s net income for the year ended December 31, 2009:

·   Increase in utility operations and maintenance of $25.8 million mainly due to increases in customer service expense and bad debts expense.

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

·   Increase in depreciation and amortization of $20.7 million primarily due to additional capital expenditures that were placed into service.

·   Increase in residential exchange credits for power costs of $55.8 million from the BPA, which was a pass-through to PSE customers, reflected as a reduction in PSE electric operating revenue.

·   Increase in other income and expenses of $20.3 million primarily due to an increase in regulatory interest income from the Mint Farm deferral.

·   Decrease in purchased electricity and electric generation fuel of $19.9 million as a result of lower customer usage and lower wholesale market prices.

·   Decrease in purchased gas of $19.0 million due to lower customer usage and a decrease in PGA rates as a result of declining natural gas wholesale costs and a reduction of the credit for accumulated PGA payable balance.

Puget Sound Energy

The following discussion provides the significant items that impacted PSE’s results of operations for the years ended December 31, 2010 and 2009.

2010 compared to 2009

Regulated Utility Operating Revenue

Electric Operating Revenue.Electric retail sales increased $10.2 million, or 0.5%, to $2.03 billion from $2.02 billion for the year ended December 31, 2010 as compared to the same period in 2009.  The increase in electric retail sales was due to a $47.9 million electric rate increase effective April 8, 2010.  Partially offsetting the increase in electric retail sales was an $88.8 million decline in retail electricity usage of 965,695 MWhs, or 4.4%, primarily due to warmer than average temperatures in the Pacific Northwest during the first quarter of 2010 as compared to the same period in 2009.  The average temperature during the first quarter of 2010 was 46.8 degrees, or 6.2 degrees warmer than the same period in 2009.  As a result of the warmer first quarter of 2010, heating degree days for the year ended December 31, 2010 were 7.1% lower than the same period in 2009.  The decline in retail electricity usage was also due to an increase in PSE’s residential and commercial customer conservation programs and the continued effects of a weak Pacific Northwest economy.  Also contributing to the increase in retail sales are pass-through items with no impact to earnings including a $22.3 million increase attributable to a decrease in benefits (credits to customers) of the Residential and Small Farm Energy Exchange Benefit, a $20.2 million increase due to conservation rider program rate increases and a $17.0 million increase in retail sales related to the suspension of the PTC tariff effective July 1, 2010.  PTCs that are generated and provided to customers are recorded as a reduction in other electric operating revenue until PSE utilizes the tax credit on its tax return at which time the PTCs will be credited to customers in retail sales.  Additionally, PSE’s customers were credited $10.5 million for REC revenue effective November 1, 2010, resulting in a decrease in electric retail sales.  The $10.5 million credits to customers is offset in other electric operating revenue with no impact to earnings.  PSE’s customers will continue to receive credits through March 2011.

Sales to other utilities and marketers decreased $15.6 million, or 19.8%, to $62.9 million from $78.5 million for the year ended December 31, 2010 as compared to the same period in 2009.  This decrease was primarily due to a carrying value adjustment of $17.8 million related to PSE’s California wholesale energy sales regulatory asset.  Additionally, PSE’s average wholesale electric sales prices declined which decreased revenue $15.2 million.  Sales volumes decreased 28,981 MWhs, or 1.1% which decreased revenue $0.7 million.

Other operating revenue increased $13.7 million, or 115.5%, to $1.8 million from a loss of $(11.9) million for the year ended December 31, 2010, as compared to the same period in 2009.  The increase was primarily due to an increase in non-core gas sales of $9.9 million and REC revenue of $10.5 million.  As discussed above, REC revenue is an offset of the REC credit provided to PSE’s customers in electric retail sales with no impact to earnings.  Partially offsetting the increase to other operating revenue was $7.3 million of PTCs which are deferred until PSE utilizes tax credit on its tax return.

Gas Operating Revenue.  Natural gas retail sales decreased $209.7 million, or 17.6%, to $982.7 million from $1.19 billion during year ended December 31, 2010 as compared to the same period in 2009.  This decrease was primarily due to a $115.4 million decrease in gas operating revenue as a result of PGA rate decreases effective June 1, 2009 and October 1, 2009.  The PGA mechanism passes through to customer increases or decreases in the natural gas supply portion of the natural gas service rates based upon changes in the price of natural gas purchased from producers and wholesale marketers or changes in natural gas pipeline transportation costs.  PSE’s net income is not affected by changes under the PGA mechanism.  The decrease in natural gas retail sales was also due to a decrease of 87.6 million in natural gas therm sales, or 7.7%, which decreased revenue by $107.2 million.  The decrease was due primarily to warmer than average temperatures in the Pacific Northwest during the first quarter of 2010 as compared to 2009, an increase in PSE’s residential and commercial customer conservation programs and the continued effects of a weak Pacific Northwest economy.

Operating Expenses

Purchased electricity expenses decreased $113.3 million, or 12.8%, for the year ended December 31, 2010 as compared to the same period in 2009.  The decrease was primarily the result of a decrease in purchased power of 1,349,571 MWhs, or 8.9%, resulting in a decrease of $71.6 million and by lower wholesale market prices which contributed $44.5 million. The decrease in purchased power for the year ended December 31, 2010 was primarily the result of lower customer usage related to warmer than normal temperatures during 2010, a weak economy in the Pacific Northwest and 18.7% higher generation of electricity from PSE’s coal-fired generation facility, Colstrip, due to Colstrip Unit 4 having an extended outage in 2009.

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

Electric generation fuel expense increased $59.7 million, or 28.6%, for the year ended December 31, 2010 as compared to the same period in 2009.  The increase was primarily due to a $44.5 million increase in costs at PSE’s combustion turbine facilities and a $15.2 million increase related to increased generation at Colstrip in 2010 due to the Colstrip Unit 4 extended outage in 2009.  Also contributing to the increased electric generation fuel expense at company-owned natural gas facilities was an 8.0% decrease in hydroelectric generation by Company-owned facilities and under take-or-pay purchased electricity contracts partially offset by an increase in wind generation.

Residential exchange credits decreased $21.4 million, or 22.2%, for the year ended December 31, 2010 as compared to the same period in 2009 as a result of lower electric residential and farm customer sales volumes associated with the BPA REP.  The REP credit is a pass-through tariff item with a corresponding credit in electric operating revenue, with no impact on net income.

Purchased gas expense decreased $182.9 million, or 25.4%, for the year ended December 31, 2010 as compared to the same period in 2009.  The decrease was due to a 7.7% decrease in customer usage and natural gas costs reflected in PGA rates.  The decrease in customer usage was mainly due to a 7.1% decrease in heating degrees days during 2010 as compared to the same period in 2009, the impact of PSE’s residential and commercial customer conservation programs and the continued effects of a weak Pacific Northwest economy.  The PGA mechanism provides the rates used to determine natural gas costs based on customer usage.  The rate decrease was the result of declining costs of wholesale natural gas.  The PGA mechanism allows PSE to recover expected natural gas supply and transportation costs and defer, as a receivable or liability, any natural gas supply and transportation costs that exceed or fall short of this expected natural gas cost amount in PGA mechanism rates, including accrued interest.  The PGA mechanism receivable balance at December 31, 2010 was $6.0 million as compared to payable balance of $49.6 million at December 31, 2009.  PSE is authorized by the Washington Commission to accrue carrying costs on PGA receivable and payable balances.  A receivable balance in the PGA mechanism reflects an underrecovery of market natural gas cost through rates.  A payable balance reflects overrecovery of market natural gas cost through rates.

Net unrealized (gain) loss on derivative instruments changed by $168.2 million to a loss of $167.0 million in 2010, as compared to a gain of $(1.3) million in 2009.  The loss was primarily due to the decline in wholesale energy prices during 2010 which resulted in unrealized losses on contracts for future deliveries of energy commodities which we record as derivative instruments.  On July 1, 2009, PSE elected to de-designate its energy related derivative contracts previously designated as cash flow hedges.  The contracts that were de-designated were physical electric supply contracts and natural gas swap contracts used to fix the price of natural gas for electric generation.  For these contracts and for contracts initiated after such date, all mark-to-market accounting impacts are recognized through earnings.  The amount in accumulated other comprehensive income (OCI) is transferred to earnings when the contracts settle or sooner, if management determines that the forecasted transaction is probable of not occurring.  As a result, PSE will continue to experience the earnings impact of these reversals from OCI in future periods.  Over the tenor of PSE’s outstanding derivative contracts, the forward wholesale prices of electricity and natural gas declined 21.0% and 27.0%, respectively, from December 31, 2009 to December 31, 2010.

Merger and related costs associated with the merger with Puget Holdings incurred for the year ended December 31, 2010 decreased $23.9 million.  These costs were due to one-time PSE employee compensation costs, expenses related to the termination of credit agreements, legal fees and deferred compensation liability increases triggered by the merger in 2009.  Pursuant to the Washington Commission merger order commitments, PSE did not seek recovery of these costs in retail rates.

Depreciation expense increased $23.2 million, or 8.6%, for the year ended December 31, 2010 as compared to the same period in 2009.  This increase was primarily due to new additions of electric, natural gas and common plant which were placed into service in 2010 and the full year effect of plant placed in service throughout 2009.

Amortization expense increased $8.1 million, or 12.8%, for the year ended December 31, 2010 as compared to the same period in 2009 due to the inclusion of Mint Farm and Wild Horse expansion operating and ownership costs in general rates effective April 8, 2010.  PSE ceased deferral of these costs effective April 8, 2010.  These increases were partially offset by a decrease in software amortization.

Conservation amortization increased $23.6 million, or 35.6%, for the year ended December 31, 2010 as compared to the same period in 2009.  The increase was due to a higher authorized recovery of electric and natural gas conservation expenditures.  Conservation amortization is a pass-through tariff item with no impact on earnings.

Taxes other than income taxes decreased $10.8 million, or 3.6%, for the year ended December 31, 2010 as compared to the same period in 2009.  The decrease was primarily due to a decrease in revenue sensitive taxes due to lower retail sales which were partially offset by an increase in property taxes.

Other Income, Interest Expense and Income Tax Expense

Other income decreased $7.7 million, or 14.5%, for the year ended December 31, 2010 as compared to the same period in 2009.  The decrease was primarily due to the carrying costs associated with the Mint Farm regulatory asset being included in general rates effective April 8, 2010.  Prior to April 8, 2010, the Mint Farm regulatory asset was accruing interest income as authorized by the Washington Commission.  Also contributing to the decrease was a $7.0 million decrease due to the Washington Commission Allowance for Funds Used During Construction (AFUDC).  These decreases were partially offset by an $8.5 million increase in  AFUDC equity income.

Interest expense increased $18.3 million, or 9.0%, for the year ended December 31, 2010 as compared to the same period in 2009.  The increase was primarily due to a write off of a regulatory asset of deferred interest paid to the IRS of $6.9 million related to the Simplified Service Cost Method deduction from prior years which was disallowed in the Washington Commission general rate case order of April 2, 2010.  Also impacting the increase was higher long-term debt outstanding and interest on regulatory liability associated with RECs.

Income tax expense decreased $67.5 million or 99.8%, for the year ended December 31, 2010, as compared to the same period in 2009.  The decrease was primarily related to lower pre-tax income.

2009 compared to 2008

Regulated Utility Operating Revenue

Electric Operating Revenue.Electric retail sales increased $40.0 million, or 2.0%, to $2.02 billion from $1.98 billion for the year ended December 31, 2009 as compared to the same period in 2008.  The increase in electric retail sales was primarily due to an electric general rate increase of 7.1% effective November 1, 2008, that was partially offset by a merger rate credit, which contributed to an increase in electric retail sales of $109.3 million.  Partially offsetting the increase in electric retail sales was an increase in the benefits (credits to customers) of the Residential and Small Farm Energy Exchange Benefit which reduced electric operating revenue by $58.4 million.  The credits of the Residential and Small Farm Energy Exchange Benefit also reduced power costs by a corresponding amount resulting in no impact to earnings.  In addition, electric operating revenue decreased $13.7 million due to a decline in retail electricity usage of 148,516 MWhs, or 0.7%, related to lower customer usage.

Sales to other utilities and marketers decreased $6.2 million, or 7.4%, to $78.5 million from $84.7 million for the year ended December 31, 2009 as compared to the same period in 2008.  The decrease was primarily due to a decline in PSE’s average wholesale electric sales price of $33.3 million which was partially offset by $26.7 million due to an increase in sales volume of 862,535 MWh or 51.8%.

Other electric operating revenue decreased $67.3 million, to $(11.9) million from $55.4 million for the year ended December 31, 2009 as compared to the same period in 2008.  The decrease was primarily due to $54.7 million related losses from natural gas hedging contracts and $7.6 million decrease in non-core gas sales.  Such gains or losses on the sale of natural gas, which was intended to be used for electric generation, are included as a component of PSE’s PCA mechanism. In addition, other electric operating revenue decreased due to a reduction in transmission revenue and other miscellaneous operating revenue.

Gas Operating Revenue.  Natural gas retail sales increased $7.9 million, or 0.7%, to $1.192 billion from $1.184 billion for the year ended December 31, 2009 as compared to the same period in 2008.  This increase was primarily due to a $50.5 million increase in gas operating revenue as a result of a gas general rate increase of 4.6% effective November 1, 2008 and PGA rate increase effective October 1, 2008, partially offset by PGA rate decreases of June 1, 2009 and October 1, 2009.  The PGA mechanism passes through to customer increases or decreases in the natural gas supply portion of the natural gas service rates based upon changes in the price of natural gas purchased from producers and wholesale marketers or changes in natural gas pipeline transportation costs.  PSE’s net income is not affected by changes under the PGA mechanism.  Partially offsetting the increase in natural gas retail sales was a decrease of 35.6 million in natural gas therm sales, or 3.7%, which decreased revenue by $44.4 million.

Non-Utility Operating Revenue

Non-utility operating revenue decreased $6.4 million, or 56.1%, to $5.0 million from $11.4 million.  The decrease was due to lower property sales by PSE’s real estate subsidiary, which reduced revenue by $3.6 million, and lower revenue related to non-tariff customer support work performed by PSE, which reduced revenue by $3.0 million.

Operating Expenses

Purchased electricity expenses decreased $16.0 million, or 1.8%, for the year ended December 31, 2009 as compared to the same period in 2008.  This decrease was primarily due to lower customer usage related to weak economic conditions and higher generation from natural gas combustion turbines as a result of the Colstrip Unit 4 outage and lower hydroelectric and wind generation.

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

Electric generation fuel expense decreased $3.9 million, or 1.8%, for the year ended December 31, 2009 as compared to the same period in 2008.  This decrease was primarily due to an $8.6 million decrease in coal-burned fuel due to the outage of Colstrip Unit 4.  The unit was taken offline in March 2009 to conduct maintenance and repair and was returned to service in October 2009.  The decrease was partially offset by a $4.8 million increase in combustion turbine generation costs due to lower hydroelectric and wind generation.

Residential exchange credits increased $55.8 million, or 137.1%, for the year ended December 31, 2009 as compared to the same period in 2008.  The increase was a result of an agreement with the BPA to continue to pass on REP benefits to PSE’s customers.  The REP credit is a pass-through tariff item with a corresponding credit in electric operating revenue; thus, it has no impact on net income.

Purchased gas expenses decreased $19.0 million, or 2.6%, for the year ended December 31, 2009 as compared to the same period in 2008.  The decrease was primarily due to a 3.7% decrease in customer usage and changes to PGA rates.  The PGA mechanism provides the rates used to determine natural gas costs based on customer usage.  The rate decrease was the result of declining costs of wholesale natural gas.  The PGA mechanism allows PSE to recover expected natural gas supply and transportation costs and defer, as a receivable or liability, any natural gas supply and transportation costs that exceed or fall short of this expected gas cost amount in PGA mechanism rates, including accrued interest.  The PGA mechanism payable balance at December 31, 2009 was $49.6 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 underrecovery of market natural gas cost through rates.  A payable balance reflects overrecovery of market natural gas cost through rates.

Net unrealized (gain) loss on derivative instruments changed by $8.8 million, to a gain of $(1.3) million in 2009, as compared to a loss of $7.5 million in 2008.  The gain was primarily due to mark-to-market accounting for PSE’s energy derivative contracts.  On July 1, 2009, PSE elected to de-designate its energy related derivative contracts previously designated as cash flow hedges.  The contracts that were de-designated are physical electric supply contracts and natural gas swap contracts used to fix the price of natural gas for electric generation.  For these contracts and for contracts initiated after such date, all mark-to-market accounting impacts are recognized through earnings.  The amount in OCI is transferred to earnings when the contracts settle or sooner, if management determines that the forecasted transaction is probable of not occurring.  As a result, PSE will continue to experience earnings impact of these reversals from OCI in future periods.  For the year ended December 31, 2009, PSE recognized a $135.5 million gain from the transfer in OCI when contracts settled, which was offset by a $126.6 million loss from unfavorable mark-to-market adjustments.

Utility operations and maintenance expense increased $25.8 million, or 5.6%, to $487.4 million from $461.6 million.  The increase was driven by an $18.6 million increase in customer service expenses, which included a $4.9 million increase in bad debt expense, administrative costs and electric transmission and distribution costs.  Also contributing to the increase was a $2.1 million increase in gas operations costs.

Merger and related costs associated with the merger with Puget Holdings increased $23.9 million.  These costs were due to one-time PSE employee compensation costs, expenses related to the termination of credit agreements, legal fees and deferred compensation liability increases triggered by the merger in 2009.  Pursuant to the Washington Commission merger order commitments, PSE will not seek recovery of these costs in retail rates.

Depreciation expense increased $13.7 million, or 5.3%, for the year ended December 31, 2009 as compared to the same period in 2008.  This increase was primarily due to additional capital expenditures that were placed into service.

Amortization expense increased $7.0 million, or 12.5%, for the year ended December 31, 2009 as compared to the same period in 2008.  This increase was due to an increase in storm amortization costs as approved in PSE’s general rate case effective November 1, 2008.  Amortization expense included a benefit related to the deferral of Mint Farm fixed cost of $14.1 million which, had it not been included as a reduction to amortization expense would have increased by $34.9 million.

Conservation amortization increased $4.8 million, or 7.8%, for the year ended December 31, 2009 as compared to the same period in 2008. The increase was due to a higher authorized recovery of electric and natural gas conservation expenditures.  Conservation amortization is a pass-through tariff item with no impact on earnings.

Taxes other than income taxes increased $6.2 million, or 2.1%, for the year ended December 31, 2009 as compared to the same period in 2008.  The increase was primarily due to revenue sensitive taxes from increased revenue.

Other Income, Interest Expense and Income Tax Expense

Other income increased $19.6 million, or 58.9%, for the year ended December 31, 2009 as compared to the same period in 2008.  The increase was primarily due to an increase in regulatory interest income from the Mint Farm which contributed $14.7 million, AFUDC of $2.6 million and $2.2 million gain on PSE trust owned life insurance.

Interest expense increased $7.8 million, or 4.0%, for the year ended December 31, 2009 as compared to the same period in 2008.  The increase was primarily due to issuance of higher rate long-term debt and an increase in the amortization of costs of credit facilities.

Income tax expense increased $6.7 million, or 11.11%, for the year ended December 31, 2009 as compared to the same period in 2008.  The increase was primarily due to an increase in the effective tax rate to 29.8% from 27.2%.  The increase in effective tax rate was mainly due to lower wind generation in 2009 as compared to 2008, which resulted in lower PTCs.

Puget Energy

All the operations of Puget Energy are conducted through its subsidiary PSE.  “Predecessor” refers to the operations of Puget Energy and PSE prior to the consummation of the merger on February 6, 2009.  “Successor” refers to the operations of Puget Energy and PSE subsequent to the merger.  Puget Energy accounted for the merger as a business combination and all its assets and liabilities were recorded at fair value as of the merger date with the remaining consideration recorded as goodwill.  The fair values of assets are being amortized over their estimated useful lives in a manner that best reflects the economic benefits derived from such assets.  Goodwill is not amortized, but is subject to impairment testing on an annual basis.  Such adjustments to fair value and the allocation of purchase price between identifiable intangibles and goodwill will have an impact on Puget Energy’s expenses and profitability.

Puget Energy’s net income for the years ended December 31, 2010, 2009 and 2008 was as follows:

Puget Energy Consolidated Statements of Income
(Dollars in Thousands)				Successor			Predecessor
Benefit/(Expense)	Year Ended December 31, 2010			February 6, 2009 - December 31, 2009			January 1, 2009 – February 5, 2009			2009 Combined			2010-2009 Percent Change			Year Ended December 31, 2008			2009-2008 Percent Change
PSE net income	$	26,095		$	127,641		$	31,611		$	159,252			(83.6	)%	$	162,736			(2.1	)%
Other operating revenue		--			361			--			361			*			--			*
Purchased electricity		578			529			--			529			9.3			--			*
Net unrealized gain on derivative instruments		112,858			151,481			--			151,481			(25.5	)		--			*
Non-utility expense and other		(12,793	)		(2,249	)		(4	)		(2,253	)		*			(380	)		*
Merger and related costs		--			(2,731	)		(20,416	)		(23,147	)		*			(9,252	)		*
Depreciation and amortization		--			167			--			167			*			--			*
Charitable contribution expense		--			(5,000	)		--			(5,000	)		*			--			*
Other income		43			--			--			--			*			--			*
Unhedged interest rate derivative expense		(7,955	)		--			--			--			*			--			*
Interest expense 1		(86,156	)		(71,250	)		25			(71,225	)		21.0			851			*
Income tax benefit (expense)		(2,359	)		(24,934	)		1,540			(23,394	)		(89.9	)		974			*
Puget Energy net income	$	30,311		$	174,015		$	12,756		$	186,771			(83.8	)%	$	154,929			20.6	%

_____________

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

2010 compared to 2009

Summary Results of Operations

Puget Energy’s net income for 2010 was $30.3 million with operating revenue of $3.1 billion as compared to net income of $186.8 million with operating revenue of $3.3 billion for 2009.  The following are significant factors that impacted Puget Energy’s net income which are not included in PSE’s discussion:

Net unrealized gain on derivative instruments decreased $38.6 million for the year ended December 31, 2010, as compared to the same period in 2009, as a result of the required recognition of all contracts at fair value as part of purchase accounting, including derivative contracts previously designated as Normal Purchase Normal Sale (NPNS).  Certain of these contracts were subsequently redesignated as NPNS.  The unrealized gain represents the change in fair value of derivative contracts.

Non-utility expense and other costs increased $10.5 million for the year ended December 31, 2010, as compared to the same period in 2009, due primarily to the write down of SO2 emissions allowance inventory of $7.9 million.

Merger and related costs decreased $23.1 million for the year ended December 31, 2010, as compared to the same period in 2009, due to one-time merger related costs of compensation triggered by Puget Energy’s change of control, excise taxes and financial advisor fees.

Unhedged interest rate derivative expense increased $8.0 million for the year ended December 31, 2010, as compared to the same period in 2009, due to the de-designation of interest rate swaps associated with the portion of the term-loan that was paid off on December 6, 2010.

Charitable contribution expense decreased $5.0 million for the year ended December 31, 2010, as compared to the same period in 2009, due to a charitable contribution to the PSE Foundation in 2009.

Interest expense increased $14.9 million for the year ended December 31, 2010, as compared to the same period in 2009.  The increase was primarily due to the write-down of unamortized loan issuance costs associated with the portion of the term-loan paid off on December 6, 2010, business combination fair value amortization adjustments related to PSE’s long-term debt and deferred debt costs.

Income tax expense decreased $21.0 million for the year ended December 31, 2010, as compared to the same period in 2009, primarily due to a decrease in pre-tax income combined with a decrease in the effective tax rate.

2009 compared to 2008

Summary Results of Operations

Puget Energy’s net income for 2009 was $186.8 million with operating revenue of $3.3 billion as compared to net income of $154.9 million with operating revenue of $3.4 billion for the same period in 2008.  The following are significant factors that impacted Puget Energy’s net income which are not included in PSE’s discussion:

Net unrealized gain on derivative instruments increased $151.5 million for the year ended December 31, 2009, as compared to the same period in 2008, as a result of the required recognition of all contracts at fair value as part of purchase accounting, including derivative contracts previously designated as NPNS.  Certain of these contracts were subsequently redesignated as NPNS.  The unrealized gain represents the change in fair value of derivative contracts.

Merger and related costs increased $13.8 million for the year ended December 31, 2009, as compared to the same period in 2008, due to the merger of Puget Energy with Puget Holdings.  These costs were primarily related to real estate, excise taxes, legal fees, transaction advisory services and stock options.

Non-utility expense and other costs increased $2.6 million for the year ended December 31, 2009, as compared to the same period in 2008, due to pension and postretirement plan costs as a result of purchase accounting related to the merger.

Charitable contribution expense increased $5.0 million for the year ended December 31, 2009, as compared to the same period in 2008, due to a charitable contribution to the PSE Foundation.

Interest expense increased $72.1 million for the year ended December 31, 2009, as compared to the same period in 2008, primarily due to the term-loan and credit facility fees related to the merger on February 6, 2009, which contributed $80.2 million.  Offsetting this increase were the business combination fair value amortization of PSE’s fair value debt, PSE’s deferred debt costs, and PSE treasury locks, which contributed $8.6 million.

Income tax expense increased $24.3 million for the year ended December 31, 2009, as compared to the same period in 2008 due to an increase in pre-tax income combined with an increase in the effective tax rate.  The effective tax rate increase was attributable primarily to non-deductible merger transaction costs.

CAPITAL RESOURCES AND LIQUIDITY

Capital Requirements

Contractual Obligations and Commercial Commitments

The following are PSE’s and Puget Energy’s aggregate contractual obligations as of December 31:

	Payments Due Per Period
Contractual Obligations (Dollars in Thousands)	Total			2011				2012- 2013		2014- 2015	Thereafter
Energy purchase obligations 1	$	5,003,929		$	1,052,381		$	1,419,935	$	997,065	$	1,534,548
Long-term debt including interest 2		8,174,031			461,579			412,512		557,738		6,742,202
Short-term debt including interest 7,8		269,598			269,598			--		--		--
Service contract obligations 3		417,794			85,210			147,761		124,699		60,124
Non-cancelable operating leases 4		134,938			11,870			26,847		24,891		71,330
Pension and other benefits funding and payments 5		18,096			6,457			2,798		2,522		6,319
Total PSE contractual cash obligations	$	14,018,386		$	1,887,095		$	2,009,853	$	1,706,915	$	8,414,523
Long-term debt, including interest 6		1,937,073			79,485			159,108		1,103,592		594,888
Puget Energy capital leases 4		42,603			42,603			--		--		--
Less: Inter-company short-term debt and interest elimination 7		(22,598	)		(22,598	)		--		--		--
Total Puget Energy contractual cash obligations	$	15,975,464		$	1,986,585		$	2,168,961	$	2,810,507	$	9,009,411

_____________

1	Energy purchase contracts were entered into as part of PSE’s obligation to serve retail electric and natural gas customers’ energy requirements.  As a result, costs are generally recovered either through base retail rates or adjustments to retail rates as part of the power and natural gas cost adjustment mechanisms.
2	For individual long-term debt maturities, see Note 8 to the consolidated financial statements included in Item 8 of this report.  For Puget Energy the amount above excludes the fair value adjustments related to the merger.
3	Represents operational agreements, settlements and other contractual obligations with respect to generation, transmission and distribution facilities.  These costs are generally recovered through base retail rates.
4	For additional information, see Note 12 to the consolidated financial statements included in Item 8 of this report.
5	Pension and other benefit expected contributions represent PSE’s estimated cash contributions to the pension plan through 2015.
6	As of December 31, 2010, Puget Energy had fully drawn on a five-year term-loan with a balance of $782.0 million and incurred a $258.0 million draw under its $1.0 billion Puget Energy capital expenditure facility.
7	As of December 31, 2010, PSE has a revolving credit facility with Puget Energy in the form of a promissory note to borrow up to $30.0 million of which $22.6 million was drawn.
8	As of December 31, 2010, PSE had credit facilities totaling $1.15 billion of which $259.6 million had been drawn.  These facilities consisted of $400.0 million to fund operating expenses, $400.0 million to fund capital expenditures and $350.0 million to support energy and natural gas hedging.  In addition, a $12.6 million letter of credit was outstanding under the $400.0 million hedging facility.

The following are PSE’s and Puget Energy’s aggregate availability under commercial commitments as of December 31:

	Amount of Available Commitments Expiration Per Period
Commercial Commitments (Dollars in Thousands)	Total			2011				2012- 2013		2014- 2015	Thereafter
PSE working capital facility 1	$	387,352		$	--		$	--	$	387,352	$	--
PSE capital expenditures facility 1		153,000			--			--		153,000		--
PSE energy hedging facility 1		350,000			--			--		350,000		--
Inter-company short-term interest and debt 2		7,402			7,402			--		--		--
Total PSE commercial commitments	$	897,754		$	7,402		$	--	$	890,352	$	--
Puget Energy capital expenditures facility 3		742,000			--			--		742,000		--
Less: Inter-company short-term interest and debt elimination 2		(7,402	)		(7,402	)		--		--		--
Total Puget Energy commercial commitments	$	1,632,352		$	--		$	--	$	1,632,352	$	--

_____________

1	As of December 31, 2010, PSE had credit facilities totaling $1.15 billion of which $259.6 million had been drawn.  These facilities consisted of $400.0 million to fund operating expenses, $400.0 million to fund capital expenditures and $350.0 million to support energy and natural gas hedging.  In addition, a $12.6 million letter of credit was outstanding under the $400.0 million hedging facility.
2	As of December 31, 2010, PSE has a revolving credit facility with Puget Energy in the form of a promissory note to borrow up to $30.0 million of which $22.6 million was drawn.
3	As of December 31, 2010, Puget Energy had fully drawn on a five-year term-loan with a balance of $782.0 million and incurred a $258.0 million draw under its $1.0 billion Puget Energy capital expenditure facility.

Utility Construction Program

PSE’s construction programs for generating facilities, the electric transmission system and the natural gas and electric distribution systems are designed to meet regulatory requirements, customer growth and to support reliable energy delivery.  Construction expenditures, excluding equity AFUDC, totaled $859.1 million in 2010.  As a result of a general slowing in the economy and changes to the Company’s proposed resources, PSE’s projected construction expenditures have been reduced.  Presently planned utility construction expenditures, excluding AFUDC, for 2011, 2012 and 2013 are:

Capital Expenditure Projections (Dollars in Thousands)	2011		2012		2013
Energy delivery, technology and facilities	$	636,728	$	672,417	$	621,310
New generating resources		386,446		45,877		119,622
Total expenditures	$	1,023,174	$	718,294	$	740,932

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

Capital Resources

Cash From Operations

Puget Sound Energy

Cash generated from operations for the year ended December 31, 2010 was $575.8 million, a decrease of $144.9 million from the $720.7 million generated during the year ended December 31, 2009.  The decrease was primarily the result of the following:

·   PSE’s deferred taxes decreased by $16.3 million in 2010 as compared to tax savings in 2009 of $194.5 million due to bonus depreciation and repair allowance deductions, which decreased cash flow from operating activities by $210.8 million.

·   PSE’s PGA mechanism provided $55.6 million payment to customers related to overcollection of prior year plan related rates during the year ended 2010 as compared to an overrecovery from customers of $40.7 million during the same period in 2009, which decreased cash flow from operating activities by $96.3 million.

·   Accounts receivable and unbilled revenue decreased $7.6 million during the year ended 2010 as compared to a decrease of $64.3 million during the same period in 2009, causing an operating cash flow decrease of $56.7 million.

·   PSE received tax net refunds of $20.6 million during the year ended 2010 as compared to net tax refunds of $44.4 million during the same period in 2009, causing a decrease of $23.8 million.

·   PSE incurred $14.0 million of storm damage deferred costs during the year ended December 31, 2010.

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

·   A decrease in prepaid income taxes of $37.8 million during the year ended 2010 as compared to an increase of $82.6 million during the same period in 2009, causing an increase in cash from operations of $120.4 million.

·   Cash received from the sale of RECs of $44.6 million during the year ended 2010 as compared to payments received of $26.7 million during the same period in 2009, causing an increase in cash from operations of $17.9 million.

·   Pension funding of $12.0 million during the year ended 2010 as compared to funding of $18.4 million during the same period in 2009, causing an increase in cash from operations of $6.4 million.

Puget Energy

Cash generated from operations for the year ended December 31, 2010 was $865.9 billion, a decrease of $202.4 million from the $1.1 billion generated in 2009.  The decrease included $144.9 million from the cash provided by the operating activities of PSE as previously discussed.  Other factors contributing to the decrease included the following:

·   As a result of the merger, $371.6 million in derivative settlement payments were reclassified to financing activities during the year ended 2010 as compared to $524.4 million during the same period in 2009, resulting in a decrease in operating cash flows of $152.8 million.  These contracts represent proceeds received from derivative instruments that included financing elements at the merger date.

·   Puget Energy made $89.5 million less net payments on accounts payable during the year ended 2010 as compared to the year ended 2009, causing an increase in cash from operations.

Financing Program

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

Credit Facilities and Commercial Paper

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

As of December 31, 2010 and 2009, PSE had $247.0 million and $105.0 million in short-term debt outstanding, respectively, exclusive of the demand promissory note with Puget Energy.  Outside of the consolidation of PSE’s short-term debt, Puget Energy had no short-term debt outstanding in either year as borrowing under its credit facilities are classified as long-term.  PSE’s weighted-average interest rate on short-term debt, including borrowing rate, commitment fees and the amortization of debt issuance costs, during 2010 and 2009 was 5.11%, and 3.59%, respectively.  As of December 31, 2010, PSE and Puget Energy had several committed credit facilities that are described below.

Puget Sound Energy Credit Facilities

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

PSE’s credit agreements contain usual and customary affirmative and negative covenants that, among other things, place limitations on PSE’s ability to incur additional indebtedness and liens, issue equity, pay dividends, transact with affiliates and make asset dispositions and investments.  The credit agreements also contain financial covenants which include a cash flow interest coverage ratio and, in addition, if PSE has a below investment grade credit rating, a cash flow to net debt outstanding ratio (each as specified in the facilities).  PSE certifies its compliance with these covenants to participating banks each quarter.  As of December 31, 2010, PSE was in compliance with all applicable covenants.

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

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

As of December 31, 2010, $247.0 million was drawn and outstanding under PSE’s $400.0 million capital expenditure facility in addition to a $12.6 million letter of credit supporting the BPA contracts.  No loans were outstanding under PSE’s working capital facility and no loans or letters of credit were outstanding under PSE’s $350.0 million facility supporting energy hedging activities. Outside of the credit agreements, PSE had a $5.7 million letter of credit in support of a long-term transmission contract.

Demand Promissory Note.  On June 1, 2006, PSE entered into a revolving credit facility with Puget Energy, in the form of a credit agreement and a Demand Promissory Note (Note) pursuant to which PSE may borrow up to $30.0 million from Puget Energy subject to approval by Puget Energy.  Under the terms of the Note, PSE pays interest on the outstanding borrowings based on the lowest of the weighted-average interest rate of PSE’s outstanding commercial paper interest rate or PSE’s senior unsecured revolving credit facility.  Absent such borrowings, interest is charged at one-month LIBOR plus 0.25%. At December 31, 2010, the outstanding balance of the Note was $22.6 million.  The outstanding balance and the related interest under the Note are eliminated by Puget Energy upon consolidation of PSE’s financial statements.

Puget Energy Credit Facilities

Effective with the close of the merger on February 6, 2009, Puget Energy entered into a $1.225 billion five-year term-loan and a $1.0 billion credit facility for funding capital expenditures.  On December 6, 2010, Puget Energy issued $450.0 million of senior secured notes.  The net proceeds of $443.0 million from these notes were used to repay a portion of the $1.225 billion five-year term-loan.  Concurrent with the repayment of the term-loan, Puget Energy expensed $7.2 million of the loan’s unamortized discount and issuance costs.  As of December 31, 2010, Puget Energy had fully drawn the five-year term-loan which had a remaining outstanding balance of $782.0 million and had drawn $258.0 million under the $1.0 billion facility.  The term-loan and facility mature in February 2014.  These credit agreements contain usual and customary affirmative and negative covenants which are similar to PSE’s credit facilities.  Puget Energy’s credit agreements contain financial covenants based on the following three ratios:  cash flow interest coverage, cash flow to net debt outstanding and debt service coverage (cash available for debt service to borrower interest), each as specified in the facilities.  Puget Energy certifies its compliance with these covenants each quarter.  As of December 31, 2010, Puget Energy was in compliance with all applicable covenants.

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

These facilities contain similar terms and conditions and are syndicated among numerous committed lenders.  The agreements provide Puget Energy with the ability to borrow at different interest rate options and include variable fee levels.  Borrowings may be at the banks’ prime rate or at floating rates based on LIBOR plus a spread based upon Puget Energy’s credit rating.  Puget Energy must also pay a commitment fee on the unused portion of the $1.0 billion facility.  The spreads and the commitment fee depend on Puget Energy’s credit ratings.  As of the date of this report, the spread over prime rate is 1.25%, the spread to the LIBOR is 2.25% and the commitment fee is 0.84%.  In February 2011, Puget Energy borrowed an additional $175.0 million under the $1.0 billion credit facility.

New Legislation on Derivative Contracts

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

Dividend Payment Restrictions

The payment of dividends by PSE to Puget Energy is restricted by provisions of certain covenants applicable to long-term debt contained in PSE’s electric and natural gas mortgage indentures.  At December 31, 2010, approximately $416.7 million of unrestricted retained earnings was available for the payment of dividends under the most restrictive mortgage indenture covenant.

Beginning February 6, 2009, pursuant to the terms of the Washington Commission merger order, PSE may not declare or pay dividends if PSE’s common equity ratio, calculated on a regulatory basis, is 44.0% or below except to the extent a lower equity ratio is ordered by the Washington Commission.  Also, pursuant to the merger order, PSE may not declare or make any distribution unless on the date of distribution PSE’s corporate credit/issuer rating is investment grade, or, if its credit ratings are below investment grade, PSE’s ratio of EBITDA to interest expense for the most recently ended four fiscal quarter periods prior to such date is equal to or greater than three to one.  The common equity ratio, calculated on a regulatory basis, was 46.5% at December 31, 2010 and the EBITDA to interest expense was 3.9 to one.

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

Puget Energy’s ability to pay dividends is also limited by the merger order issued by the Washington Commission as well as by the terms of its credit facilities.  Pursuant to the merger order, Puget Energy may not declare or make a distribution unless on such date Puget Energy’s ratio of consolidated EBITDA to consolidated interest expense for the four most recently ended fiscal quarters prior to such date is equal to or greater than two to one.  At December 31, 2010,  the EBITDA to interest expense was 2.7 to one.  In accordance with terms of the Puget Energy credit facilities, Puget Energy is limited to paying a dividend within an eight business-day period that begins seven business days following the delivery of quarterly or annual financial statements to the facility agent.  Puget Energy is not permitted to pay dividends during any Event of Default, or if the payment of dividends would result in an Event of Default (as defined in the facilities), such as failure to comply with certain financial covenants.  In addition, in order to declare or pay unrestricted dividends, Puget Energy’s interest coverage ratio may not be less than 1.5 to one and its cash flow to net debt outstanding ratio may not be less than 8.25% for the 12 months ending each quarter-end.  Puget Energy is also subject to other restrictions such as a “lock up” provision that, in certain circumstances, such as failure to meet certain cash flow tests, may further restrict Puget Energy's ability to pay dividends.

At December 31, 2010, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.

Debt Restrictive Covenants

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

PSE’s ability to issue additional secured debt may be limited by certain restrictions contained in its electric and natural gas mortgage indentures.  Under the most restrictive tests, at December 31, 2010, PSE could issue:

· approximately $1.4 billion of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately $2.3 billion of electric bondable property available for issuance, subject to an interest coverage ratio limitation of 2.0 times net earnings available for interest (as defined in the electric utility mortgage), which PSE exceeded at December 31, 2010; and

· approximately $168.0 million of additional first mortgage bonds under PSE’s natural gas mortgage indenture based on approximately $280.0 million of gas bondable property available for issuance, subject to a combined gas and electric interest coverage test of 1.75 times net earnings available for interest and a gas interest coverage test of 2.0 times net earnings available for interest (as defined in the natural gas utility mortgage), both of which PSE exceeded at December 31, 2010.

At December 31, 2010, PSE had approximately $5.7 billion in electric and natural gas ratebase to support the interest coverage ratio limitation test for net earnings available for interest.

Shelf Registrations and Long-Term Debt Activity

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

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

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

Puget Energy.  On December 6, 2010, Puget Energy issued $450.0 million of senior secured notes.  The notes have a term of ten years and an interest rate of 6.5%.  The notes are secured by an interest in substantially all of Puget Energy’s assets, which consists mainly of all the issued and outstanding stock of PSE and the stock of Puget Energy held by Puget Equico.  The notes contain a change of control provision pursuant to which holders of the notes may have the right to require Puget Energy to repurchase all or any part of the notes at a purchase price in cash equal to 101.0% of the principal amount of the notes, plus accrued and unpaid interest.  Net proceeds from the issue of the notes were used to repay a portion of the $1.225 billion Puget Energy five-year term-loan.

Other

Potential for Flooding in the Green River Valley

The Howard Hanson Dam (Dam), located on the upper reach of the Green-Duwamish River, provides flood risk reduction for the benefit of the Green River Valley of south King County.  Formerly an agricultural area, the Green River Valley now is home to substantial residential, commercial and industrial development in such communities as Auburn, Kent, Renton, South Seattle and Tukwila, all of which are within PSE’s natural gas and electric service territories.  In addition to many natural gas and electric customers, the area is home to critical PSE infrastructure, including transmission substations, distribution systems, and key operational facilities housing.  In January 2009, heavy rains damaged a section of the Dam and resulted in the Corps deciding in July 2009 to reduce the Dam’s flood storage capacity, pending the completion of improvements.  Due to this reduced capacity, there is an increased risk to downstream communities for higher flood levels during storm seasons, according to the Corps.  PSE is working closely with the Corps, King County, the many affected jurisdictions, and other agencies in preparing for the possibility of flooding, potentially multiple times, that could disrupt service to tens of thousands of electric and natural gas customers and damage substantial PSE infrastructure.Should a flood or floods in the Green River Valley occur, PSE could incur both significant costs responding to the event and repairing any damage it creates, as well as the loss of revenue from affected customers.

On January 28, 2010, the Washington Commission approved PSE’s request for authorization to defer the costs associated with restoring the Company’s infrastructure, facilitating public safety, and repairing the Company’s electric and natural gas system in the Green River Valley flood plain in the event evacuation is required or flooding occurs due to operations associated with the Dam.  This authorization is conditioned on PSE incurring incremental operation and maintenance costs in excess of $5.0 million per year associated with repair or restoration of the Company’s systems around the Green River.  The Washington Commission’s order will be effective until the date the Corps confirms that the Dam has been permanently repaired and that Corps’ operations will return to normal.

Critical Accounting Policies And Estimates

The preparation of financial statements in conformity with GAAP requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the reported amounts of assets and liabilities in the financial statements.  The following accounting policies represent those that management believes are particularly important to the financial statements and that require the use of estimates, assumptions and judgment to describe matters that are inherently uncertain.

Revenue Recognition.Operating utility revenue is recognized when the basis of service is rendered, which include estimated unbilled revenue.  Unbilled revenue is determined by taking MWh generated and purchased less estimated system losses and billed MWh plus unbilled MWh balance at the last true-up date.  The estimated system loss percentage for electricity is determined by reviewing historical billed MWh to generated and purchased MWh.  The estimated unbilled MWh balance is then multiplied by the estimated average revenue per MWh.  Unbilled natural gas revenue is determined by taking therms delivered to PSE less estimated system losses, prior month unbilled therms and billed therms.  The estimated system loss percentage for natural gas is determined by reviewing historical billed therms to therms delivered to customers, which vary little from year to year.  The estimated current month unbilled therms is then multiplied by estimated average rate schedule revenue per therm.

Regulatory Accounting.  As a regulated entity of the Washington Commission and the FERC, PSE prepares its financial statements in accordance with the provisions of Accounting Standards Codification (ASC) 980, “Regulated Operations” (ASC 980).  The application of ASC 980 results in differences in the timing and recognition of certain revenue and expenses in comparison with businesses in other industries.  The rates that are charged by PSE to its customers are based on cost base regulation reviewed and approved by the Washington Commission and the FERC.  Under the authority of these commissions, PSE has recorded certain regulatory assets and liabilities at December 31, 2010 in the amount of $887.6 million and $296.9 million, respectively, and regulatory assets and liabilities at December 31, 2009 of $867.7 million and $300.2 million, respectively.  In conjunction with the merger, Puget Energy recognized additional regulatory assets of $297.1 million and liabilities of $1.05 billion, reflecting the regulatory treatment of certain assets and liabilities subject to purchase accounting.  Such amounts are amortized through a corresponding liability or asset account, respectively, with no impact to earnings.  PSE expects to fully recover its regulatory assets and liabilities through its rates.  If future recovery of costs ceases to be probable, PSE would be required to write off these regulatory assets and liabilities.  In addition, if PSE determines that it no longer meets the criteria for continued application of ASC 980, Puget Energy could be required to write off its regulatory assets and liabilities related to those operations not meeting ASC 980 requirements.

Also encompassed by regulatory accounting and subject to ASC 980 are the PCA and PGA mechanisms.  The PCA and PGA mechanisms mitigate the impact of commodity price volatility upon the Company and are approved by the Washington Commission.  The PCA mechanism provides for a sharing of costs that vary from baseline rates over a graduated scale.  For further discussion regarding the PCA mechanism, see Item 1 – Business – Regulation and Rates – Electric Regulation and Rates of this report.  The PGA mechanism passes through to customers increases and decreases in the cost of natural gas supply.  PSE expects to fully recover these regulatory assets through its rates.  However, both mechanisms are subject to regulatory review and approval by the Washington Commission on a periodic basis.

Goodwill.  On February 6, 2009, Puget Holdings completed its merger with Puget Energy.  Puget Energy remeasured the carrying amount of all its assets and liabilities to fair value, which resulted in recognition of approximately $1.7 billion in goodwill.  ASC 350, “Intangibles - Goodwill and Other,” (ASC 350) requires that goodwill be tested for impairment at the reporting unit level on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value.  These events or circumstances could include a significant change in the Company’s business or regulatory outlook, legal factors, a sale or disposition of a significant portion of a reporting unit or significant changes in the financial markets which could influence the Company’s access to capital and interest rates.  Application of the goodwill impairment test requires judgment, including the identification of reporting units, assignment of assets and liabilities to reporting units, assignment of goodwill to reporting units and the determination of the fair value of the reporting units.  Management has determined Puget Energy has only one reporting unit.

The goodwill recorded by Puget Energy represents the potential long-term return to the Company’s investors.  Goodwill is tested for impairment annually using a two-step process.  The first step compares the carrying amount of the reporting unit with its fair value, with a carrying value higher than fair value indicating potential impairment.  If the first step test fails, the second step is performed.  This would entail a full valuation of Puget Energy’s assets and liabilities and comparing the valuation to its carrying amounts, with the aggregate difference indicating the amount of impairment.  Goodwill of a reporting unit is required to be tested for impairment on an interim basis if an event occurs or circumstances change that would cause the fair value of a reporting unit to fall below its carrying amount.

Puget Energy conducted its most recent annual impairment test as of October 1, 2010.  The fair value of Puget Energy’s reporting unit was estimated using the weighted-averages from an income valuation method, or discounted cash flow method, and a market valuation approach. These valuations required significant judgments, including: (1) estimation of future cash flows, which is dependent on internal forecasts, (2) estimation of the long-term rate of growth for Puget Energy’s business, (3) estimation of the useful life over which cash flows will occur, (4) the selection of utility holding companies determined to be comparable to Puget Energy, and (5) the determination of an appropriate weighted-average cost of capital or discount rate.

Management estimated the fair value of Puget Energy’s equity to be approximately $3.7 billion at the October 1, 2010 measurement date for the annual test of goodwill impairment.  The carrying value of Puget Energy’s equity was approximately $3.2 billion with the excess of the fair value over the carrying value representing 14.0%.

The income approach and the market approach valuations resulted in Puget Energy equity values of $3.9 billion and $3.5 billion, respectively.  The result of the income approach was very sensitive to long-term cash flow growth rates applicable to periods beyond management’s five-year business plan and financial forecast period and the weighted-average cost of capital assumptions of 3.0% and 7.1% respectively.

The following table summarizes the results of the income valuation method:

Equity Value Sensitivity Table
(Dollars in Billions)	Long-Term Growth Rate
Weighted-Average Cost of Capital	2.7%	3.0%	3.3%
7.2%	$    3.0	$    3.6	$    4.2
7.1	3.2	3.9	4.5
7.0	3.5	4.1	4.8

Derivatives.  ASC 815, “Derivatives and Hedging” (ASC 815), requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair value.  The Company enters into derivative contracts to manage its energy resource portfolio and interest rate exposure including forward physical and financial contracts and swaps.  The majority of PSE’s physical contracts qualify for the NPNS exception to derivative accounting rules.  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 to determine 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 economically hedge the variability of certain index-based contracts.  Those contracts that do not meet the NPNS exception are marked-to-market to current earnings in the statements of income, subject to deferral under ASC 980, for energy related derivatives due to the PCA mechanism and PGA mechanism.

Energy and financial contracts that are considered derivatives may be eligible for designation as cash flow hedges.  If a contract is designated as a cash flow hedge, the change in its market value of the effective portion of the hedge is generally deferred as a component of OCI until the transaction it is hedging is completed.  Conversely, the change in the market value of derivatives not designated as cash flow hedges is recorded in current period earnings.

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

PSE values derivative instruments based on daily quoted prices from an independent external pricing service.  The Company regularly confirms the validity of pricing service quoted prices (e.g. Level 2 in the fair value hierarchy) used to value commodity contracts to the actual prices of commodity contracts entered into during the most recent quarter. When external quoted market prices are not available for derivative contracts, PSE uses a valuation model that uses volatility assumptions relating to future energy prices based on specific energy markets and utilizes externally available forward market price curves.  All derivative instruments are sensitive to market price fluctuations that can occur on a daily basis.  The Company is focused on commodity price exposure and risks associated with volumetric variability in the natural gas and electric portfolios.  It is not engaged in the business of assuming risk for the purpose of speculative trading.  The Company economically hedges open natural gas and electric positions to reduce both the portfolio risk and the volatility risk in prices.  The exposure position is determined by using a probabilistic risk system that models 250 simulations of how the Company’s natural gas and power portfolios will perform under various weather, hydrological and unit performance conditions.

The Company may enter into swap instruments or other financial derivative instruments to manage the interest rate risk associated with its long-term debt financing and debt instruments.  As of December 31, 2010, Puget Energy had interest rate swap contracts outstanding related to its long-term debt.  Using net proceeds from a ten-year debt issuance settling on December 6, 2010, Puget Energy repaid a portion of its outstanding variable rate loans within its existing interest rate cash flow hedge, essentially refinancing a portion of these loans.  Since the terms of the December 6, 2010 debt issuance were different than the existing variable rate debt issued February 6, 2009 (fixed versus variable) Puget Energy was unable to replace the original hedged item with additional variable rate debt within the context of the cash flow hedge.  For additional information, see Item 7A and  Note 10 to the consolidated financial statements included in Item 8 of this report.

Fair Value.  ASC 820, “Fair Value Measurements and Disclosures” (ASC 820), defined fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).  However, as permitted under ASC 820, the Company utilizes a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical expedient for valuing the majority of its assets and liabilities measured and reported at fair value.  The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique.  These inputs can be readily observable, market corroborated or generally unobservable.  The Company primarily applies the market approach for recurring fair value measurements as it believes that this approach is used by market participants for these types of assets and liabilities.  Accordingly, the Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.  For further discussion on market risk, see Item 7A of this report.

On February 6, 2009, Puget Holdings completed its merger with Puget Energy.  Puget Energy remeasured the carrying amount of all its assets and liabilities to fair value, which resulted in a recognition of approximately $1.7 billion in goodwill.  For the discussion of purchase accounting adjustments, see Note 3 to the consolidated financial statements included in Item 8 of this report.

Pension and Other Postretirement Benefits.  PSE has a qualified defined benefit pension plan covering substantially all employees of PSE.  PSE recognized qualified pension expense of $8.0 million, expense of $3.3 million and income of $0.4 million for the years ended December 31, 2010, 2009 and 2008, respectively.  Of these amounts, approximately 61.1%, 61.2% and 60.0% were included in utility operations and maintenance expense in 2010, 2009 and 2008, respectively, and the remaining amounts were capitalized.  Due to the merger, the pension plan was remeasured in accordance with ASC 805.  For further information on the business combination, see Note 3 to the consolidated financial statements included in Item 8 of this report.  For the year ending December 31, 2010, Puget Energy recognized incremental qualified pension expense of $3.0 million.  In 2011, it is expected that PSE and Puget Energy will recognize pension expense of $7.7 million and $2.4 million of pension income, respectively.

PSE has a Supplemental Retirement Plan (SERP).  PSE recognized pension and other postretirement benefit expenses of $4.5 million, $4.9 million and $4.5 million for the years ended December 31, 2010, 2009 and 2008, respectively.  Due to the merger, the SERP plan was remeasured in accordance with ASC 805.  For further information on the business combination, see Note 3 to the consolidated financial statements included in Item 8 of this report.  For the year ended December 31, 2010 and 2009, Puget Energy recognized incremental income of $1.3 million and $1.8 million, respectively.  In 2011, it is expected PSE and Puget Energy will recognize $5.2 million of pension expense and $1.4 million of pension income, respectively.

PSE has other limited postretirement benefit plans.  PSE recognized expense of $0.1 million, expense of $0.3 million and income of $0.2 million for the years ended December 31, 2010, 2009 and 2008, respectively.  Due to the merger, the other postretirement benefit plans were remeasured in accordance with ASC 805.  For the year ended December 31, 2010, Puget Energy recognized incremental expense of $0.3 million.  For further information on the business combination, see Note 3 to the consolidated financial statements included in Item 8 of this report.  In 2011, it is expected that PSE and Puget Energy will recognize expense of $0.1 million and $0.3 million, respectively.

The Company’s pension and other postretirement benefits income or costs depend on several factors and assumptions, including plan design, timing and amount of cash contributions to the plan, earnings on plan assets, discount rate, expected long-term rate of return, mortality and health care cost trends.  Changes in any of these factors or assumptions will affect the amount of income or expense that the Company records in its financial statements in future years and its projected benefit obligation.  The Company has selected an expected return on plan assets based on a historical analysis of rates of return and the Company’s investment mix, market conditions, inflation and other factors.  The Company’s accounting policy for calculating the market-related value of assets is based on a five-year smoothing of asset gains or losses measured from the expected return on market-related assets.  This is a calculated value that recognizes changes in fair value in a systematic and rational manner over five years.  The same manner of calculating market-related value is used for all classes of assets, and is applied consistently from year to year.  The Company has selected an expected return on plan assets based on a historical analysis of rates of return and the Company’s investment mix, market conditions, inflation and other factors.  As required by merger accounting rules, market-related value was reset to market value effective with the merger.  During 2010, the Company made a cash contribution of $12.0 million to the qualified defined benefit plan.  Management is closely monitoring the funding status of its qualified pension plan given the recent volatility of the financial markets.  The aggregate expected contributions and payments by the Company to fund the retirement plan, SERP and other postretirement plans for the year ending December 31, 2011 are expected to be at least $5.0 million, $3.5 million and $0.5 million, respectively.

The following tables reflect the estimated sensitivity associated with a change in certain significant actuarial assumptions (each assumption change is presented mutually exclusive of other assumption changes):

Puget Energy and Puget Sound Energy	Change in Assumption	Impact on Projected Benefit Obligation Increase /(Decrease)
(Dollars in Thousands)		Pension Benefits			SERP			Other Benefits
Increase in discount rate	50 basis points	$	(26,471	)	$	(1,961	)	$	(716	)
Decrease in discount rate	50 basis points		29,016			2,116			775

Puget Energy	Change in Assumption	Impact on 2010 Pension Expense Increase /(Decrease)
(Dollars in Thousands)		Pension Benefits			SERP		Other Benefits
Increase in discount rate	50 basis points	$	(320	)	$	36	$	(44	)
Decrease in discount rate	50 basis points		2,046			95		47
Increase in return on plan assets	50 basis points		(2,042	)		*		(41	)
Decrease in return on plan assets	50 basis points		2,042			*		41

Puget Sound Energy	Change in Assumption	Impact on Projected Benefit Obligation Increase /(Decrease)
(Dollars in Thousands)		Pension Benefits			SERP			Other Benefits
Increase in discount rate	50 basis points	$	(26,471	)	$	(1,961	)	$	(716	)
Decrease in discount rate	50 basis points		29,016			2,116			775

__________

* Calculation not applicable.

Recently Adopted Accounting Pronouncements

For the discussion of recently adopted accounting pronouncements, see Note 2 to the consolidated financial statements included in Item 8 of this report.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Energy Portfolio Management

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

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

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

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

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

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

ASC 815 requires a significant amount of disclosure regarding PSE’s derivative activities and the nature of such derivatives impact on PSE’s financial position, financial performance and cash flows.  The information in this Item 7A should serve as an accompaniment to Management’s Discussion and Analysis and Note 13 to the consolidated financial statements included in Items 7 and 8 of this report, respectively.

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

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

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

	Energy Derivatives
Puget Energy Derivative Portfolio (Dollars in Thousands)	December 31, 2010				December 31, 2009
	Assets		Liabilities		Assets		Liabilities
Electric portfolio:
Current	$	4,716	$	142,780	$	4,137	$	79,732
Long-term		5,046		99,801		1,003		70,367
Total electric derivatives	$	9,762	$	242,581	$	5,140	$	150,099
Gas portfolio:
Current	$	2,784	$	100,273	$	10,811	$	62,207
Long-term		3,187		55,378		3,602		19,350
Total gas derivatives	$	5,971	$	155,651	$	14,413	$	81,557
Total derivatives	$	15,733	$	398,232	$	19,553	$	231,656

	Energy Derivatives
Puget Sound Energy Derivative Portfolio (Dollars in Thousands)	December 31, 2010				December 31, 2009
	Assets		Liabilities		Assets		Liabilities
Electric portfolio:
Current	$	4,716	$	142,780	$	4,137	$	75,323
Long-term		5,046		99,801		1,003		70,367
Total electric derivatives	$	9,762	$	242,581	$	5,140	$	145,690
Gas portfolio:
Current	$	2,784	$	100,273	$	10,811	$	62,207
Long-term		3,187		55,378		3,602		19,350
Total gas derivatives	$	5,971	$	155,651	$	14,413	$	81,557
Total derivatives	$	15,733	$	398,232	$	19,553	$	227,247

For further details regarding both the fair value of derivative instruments and the impacts such instruments have on current period earnings and OCI (for cash flow hedges), see Notes 13 and 14 to the consolidated financial statements included in Item 8 of this report.

At December 31, 2010, the Company had total assets of $6.0 million and total liabilities of $155.7 million related to financial contracts used to economically hedge the cost of physical natural gas purchased to serve natural gas customers.  All fair value adjustments of derivatives relating to the natural gas business have been reclassified to a deferred account in accordance with ASC 980 due to the PGA mechanism.  All increases and decreases in the cost of natural gas supply are passed on to customers with the PGA mechanism.  As the gains and losses on the hedges are realized in future periods, they will be recorded as natural gas costs under the PGA mechanism.

A hypothetical 10.0% increase or decrease in market prices of natural gas and electricity would change the fair value of the Company’s derivative contracts by $112.2 million, with an after-tax impact of $72.9 million.

The change in fair value of the Company’s outstanding energy derivative instruments from December 31, 2009 through December 31, 2010 is summarized in the table below:

Energy Derivative Contracts Gain (Loss) (Dollars in Thousands )	Puget Energy			Puget Sound Energy
Fair value of contracts outstanding at December 31, 2009	$	(212,105	)	$	(207,694	)
Contracts realized or otherwise settled during 2010		268,358			263,052
Change in fair value of derivatives		(438,752	)		(437,857	)
Fair value of contracts outstanding at December 31, 2010	$	(382,499	)	$	(382,499	)

The fair value of the Company’s outstanding derivative instruments at December 31, 2010, based on price source and the period during which the instrument will mature, is summarized below:

Puget Energy and Puget Sound Energy	Fair Value of Contracts By Settlement Year
Source of Fair Value (Dollars in Thousands)	2011				2012-2013			2014-2015		Thereafter			Total
Prices provided by external sources 1	$	(198,963	)	$	(92,243	)	$	--		$	--		$	(291,206	)
Prices based on internal models and valuation methods 2		(36,590	)		(46,401	)		(8,112	)		(190	)		(91,293	)
Total fair value	$	(235,553	)	$	(138,644	)	$	(8,112	)	$	(190	)	$	(382,499	)

______________

1	Prices provided by external pricing service, which utilizes broker quotes and pricing models.  Pricing inputs are based on observable market data.
2	Pricing derived from inputs with internally developed methodologies. Pricing inputs are generally less observable than objective sources.

Contingent Features and Counterparty Credit Risk

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

Where deemed appropriate, PSE may request collateral or other security from its counterparties to mitigate the potential credit default losses.  Criteria employed in this decision include, among other things, the perceived creditworthiness of the counterparty and the expected credit exposure.  As of December 31, 2010, PSE held approximately $11.1 million worth of standby letters of credit in support of various electricity and REC transactions.

It is possible that volatility in energy commodity prices could cause PSE to have material credit risk exposures with one or more counterparties.  If such counterparties fail to perform their obligations under one or more agreements, PSE could suffer a material financial loss.  However, as of December 31, 2010, approximately 92.2% of PSE’s energy and natural gas portfolio exposure, including NPNS transactions, is with counterparties that are rated at least investment grade by the major rating agencies and 7.8% of PSE’s portfolio are either rated below investment grade or are not rated by rating agencies.  PSE assesses credit risk internally for counterparties that are not rated.

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

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

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

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

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

The Company applies the counterparty’s default factor to compute credit reserves for counterparties that are in a net asset position.  Moreover, the Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate.  The fair value of derivatives includes the impact of taking into account credit and non-performance reserves.  As of December 31, 2010, the Company was in a net liability position with the majority of their counterparties, therefore the default factors of counterparties did not have a significant impact on reserves for the year.  Despite its net liability position, PSE was not required to post additional collateral with any of its counterparties. Additionally, PSE did not trigger any collateral requirements with any of its counterparties, nor were any of PSE’s counterparties required to post additional collateral resulting from credit rating downgrades.

Interest Rate Risk

The Company believes its interest rate risk primarily relates to the use of short-term debt instruments, leases and anticipated long-term debt financing needed to fund capital requirements.  The Company manages its interest rate risk through the issuance of mostly fixed-rate debt of various maturities.  The Company utilizes internal cash from operations, commercial paper and credit facilities to meet short-term funding needs.  Short-term obligations are commonly refinanced with fixed-rate bonds or notes when needed and when interest rates are considered favorable.  The Company may enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with its debt.  As of December 31, 2010, Puget Energy had seven interest rate swap contracts outstanding with a total notional amount of $1.483 billion.  The interest rate swaps hedge the exposure of the five-year variable rate debt which Puget Energy was holding in 2010.  PSE did not have any outstanding interest rate swap instruments as of December 31, 2010.

Using net proceeds from a ten-year debt issuance settling on December 6, 2010, Puget Energy repaid $443.0 million of the $1.483 billion of its outstanding variable rate loans within its existing interest rate cash flow hedge, essentially refinancing a portion of these loans. Since the terms of the December 6, 2010 debt issuance were different than the existing variable rate debt issued February 6, 2009 (fixed rate versus variable rate), Puget Energy was unable to replace the original hedged item with the additional variable rate debt within the context of the cash flow hedge.

The purpose of refinancing Puget Energy’s variable rate loans is to stagger the maturity dates of the original $1.483 billion of borrowings which mature on February 6, 2014. The Company intends to refinance a portion of the remaining $1.040 billion of outstanding variable rate debt ($1.483 billion less $443.0 million) over the next few years in order to further stagger debt maturity dates. This refinancing approach is supported in the Company’s five-year financial plan and was implemented to satisfy a commitment the Company made to the Washington Commission and to mitigate refinancing risk.

The Company’s current intent is to continue to refinance the remaining portion of the $1.040 billion in variable rate debt within the cash flow hedging relationship, as evidenced by the five-year financial plan, which establishes a pattern of determining that the forecasted transactions (forecasted future interest payments on the underlying debt) are probable of not occurring.

Because management concluded the forecasted future interest payments were no longer probable of occurring in all future periods, Puget Energy de-designated the cash flow hedging relationship on the entire $1.483 billion of interest rate swaps, effective December 6, 2010. The outstanding interest rate derivative loss on December 6, 2010, of $61.8 million, was recorded in OCI and will be amortized as the future interest payments on the debt occur. In addition, the forecasted transactions related to the $443.0 million repayment were determined to be remote of occurring and as a result, management reclassified a $7.3 million loss to other deductions in December 2010.

Going forward, all gains or losses associated with the interest rate swaps will be marked-to-market and recorded in earnings. Puget Energy recorded a $10.9 million gain related to the swaps to interest expense during 2010.  As of December 31, 2010, Puget Energy had not unwound or terminated any of the swaps corresponding to the de-designated cash flow hedge. A portion of those swaps mayremain un-hedged (not linked to any debt) until December 6, 2011 or the Company may unwind or follow other strategies to mitigate the risk of these open positions. During the period which these swaps remain un-hedged, the Company will be subject to additional interest rate risk.

A hypothetical 10% increase or decrease in the one-month LIBOR would change the fair value of the interest rate swaps remaining in a cash flow hedge relationship by $5.6 million, or $3.6 million after tax, recorded in accumulated OCI.

As a result of the cash flow hedge de-designation related to its interest rate swaps, the Company is exposed to additional interest rate risk on the portion of swaps that remain unhedged. A hypothetical 10% increase or decrease in the three-month LIBOR would change the fair value of these specific unhedged swaps by $0.7 million. This hypothetical change in fair value would directly impact earnings.

The following table presents Puget Energy’s interest rate swaps at December 31, 2010 and 2009:
 

Puget Energy Derivative Portfolio (Dollars in Thousands)	December 31, 2010				December 31, 2009
	Assets		Liabilities		Assets		Liabilities
Interest rate swaps:
Current	$	--	$	30,047	$	--	$	26,844
Long-term		--		27,956		20,854		--
Total	$	--	$	58,003	$	20,854	$	26,844

The change in fair value of Puget Energy’s outstanding interest rate swaps from December 31, 2009 through December 31, 2010 is summarized in the table below:

Interest Rate Swap Contracts Gain (Loss) (Dollars in Thousands )	Puget Energy
Fair value of contracts outstanding at December 31, 2009	$	(5,990	)
Contracts realized or otherwise settled during 2010		33,887
Change in fair value of derivatives		(85,900	)
Fair value of contracts outstanding at December 31, 2010	$	(58,003	)

The fair value of Puget Energy’s outstanding interest rate swaps at December 31, 2010, based on price source and the period during which the instrument will mature, is summarized below:

Source of Fair Value	Fair Value of Contracts By Settlement Year
(Dollars in Thousands)	2011				2012-2013			2014-2015	Total
Prices provided by external sources 1	$	(30,047	)	$	(28,236	)	$	280	$	(58,003	)

______________

1 Prices provided by external pricing service, which utilizes broker quotes and pricing models.  Pricing inputs are based on observable market data.

From time to time PSE may enter into treasury locks or forward starting swap contracts to hedge interest rate exposure related to an anticipated debt issuance.  The ending balance in OCI related to the forward starting swaps and previously settled treasury lock contracts at December 31, 2010 is a net loss of $7.3 million after tax and accumulated amortization.  This compares to an after-tax loss of $7.6 million in OCI as of December 31, 2009.  All financial hedge contracts of this type are reviewed by an officer, presented to the Asset Management Committee or the Board of Directors, as applicable and are approved prior to execution.  PSE had no treasury locks or forward starting swap contracts outstanding at December 31, 2010.

The following table presents the carrying amounts and the fair value of the Company’s debt instruments at December 31, 2010 and 2009:

	December 31, 2010				December 31, 2009
(Dollars in Thousands)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Financial liabilities:
Short-term debt	$	247,000	$	247,000	$	105,000	$	105,000
Short-term debt owed by PSE to Puget Energy 1		22,598		22,598		22,898		22,898
Long-term debt - fixed-rate		3,629,660		4,226,639		2,834,179		3,282,364
Long-term debt – variable rate		1,013,053		1,083,117		1,438,519		1,478,632

______________

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

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORTS:

CONSOLIDATED FINANCIAL STATEMENTS:

PUGET ENERGY:

PUGET SOUND ENERGY:

NOTES  To The Consolidated Financial Statements of Puget Energy and Puget Sound Energy:
Note 1.	Summary of Significant Accounting Policies
Note 2.	New Accounting Pronouncements
Note 3.	Business Combinations (Puget Energy Only)
Note 4.	Regulation and Rates
Note 5.	Preferred Share Purchase Right
Note 6.	Dividend Payment Restrictions
Note 7.	Utility Plant
Note 8.	Long-Term Debt
Note 9.	Redeemable Securities
Note 10.	Estimated Fair Value of Financial Instruments
Note 11	Liquidity Facilities and Other Financing Arrangements
Note 12.	Leases
Note 13.	Accounting for Derivative Instruments and Hedging Activities
Note 14.	Fair Value Measurements
Note 15.	Employee Investment Plans
Note 16.	Retirement Benefits
Note 17.	Stock-based Compensation Plans
Note 18.	Income Taxes
Note 19.	Litigation
Note 20.	Variable Interest Entities
Note 21.	Commitments and Contingencies
Note 22.	Related Party Transactions
Note 23.	Other
Note 24.	Segment Information

SUPPLEMENTAL QUARTERLY FINANCIAL DATA

SCHEDULE:

All other schedules have been omitted because of the absence of the conditions under which they are required, or because the information required is included in the consolidated financial statements or the notes thereto.

Financial statements of PSE’s subsidiaries are not filed herewith inasmuch as the assets, revenue, earnings and earnings reinvested in the business of the subsidiaries are not material in relation to those of the Company.

REPORT OF MANAGEMENT AND STATEMENT OF RESPONSIBILITY

Puget Energy, Inc.

and

Puget Sound Energy, Inc.

Puget Energy, Inc. and Puget Sound Energy, Inc. (the Company) management assumes accountability for maintaining compliance with our established financial accounting policies and for reporting our results with objectivity and integrity.  The Company believes it is essential for investors and other users of the consolidated financial statements to have confidence that the financial information we provide is timely, complete, relevant and accurate.  Management is also responsible to present fairly Puget Energy’s and Puget Sound Energy’s consolidated financial statements, prepared in accordance with GAAP.

Management, with oversight of the Board of Directors, established and maintains a strong ethical climate under the guidance of our Corporate Ethics and Compliance Program so that our affairs are conducted to high standards of proper personal and corporate conduct.  Management also established an internal control system that provides reasonable assurance as to the integrity and accuracy of the consolidated financial statements.  These policies and practices reflect corporate governance initiatives that are compliant with the corporate governance requirements of the Sarbanes-Oxley Act of 2002, including:

· Our Board has adopted clear corporate governance guidelines.

· With the exception of the President and Chief Executive Officer, the Board members are independent of management.

· All members of our key Board committees – the Audit Committee, the Compensation and Leadership Development Committee and the Governance and Public Affairs Committee – are independent of management.

· The non-management members of our Board meet regularly without the presence of Puget Energy and Puget Sound Energy management.

· The Charters of our Board committees clearly establish their respective roles and responsibilities.

· The Company has adopted a Corporate Ethics and Compliance Code with a hotline (through an independent third party) available to all employees, and our Audit Committee has procedures in place for the anonymous submission of employee complaints on accounting, internal accounting controls or auditing matters.  The Compliance Program is led by the Chief Ethics and Compliance Officer of the Company.

· Our internal audit control function maintains critical oversight over the key areas of our business and financial processes and controls, and reports directly to our Board Audit Committee.

Management is confident that the internal control structure is operating effectively and will allow the Company to meet the requirements under Section 404 of the Sarbanes-Oxley Act of 2002.

PricewaterhouseCoopers LLP, our independent registered public accounting firm, reports directly to the Audit Committee of the Board of Directors.  PricewaterhouseCoopers LLP’s accompanying report on our consolidated financial statements is based on its audit conducted in accordance with auditing standards prescribed by the Public Company Accounting Oversight Board, including a review of our internal control structure for purposes of designing their audit procedures.  Our independent registered accounting firm has reported on the effectiveness of our internal control over financial reporting as required under Section 404 of the Sarbanes-Oxley Act of 2002.

We are committed to improving shareholder value and accept our fiduciary oversight responsibilities.  We are dedicated to ensuring that our high standards of financial accounting and reporting as well as our underlying system of internal controls are maintained.  Our culture demands integrity and we have confidence in our processes, our internal controls and our people, who are objective in their responsibilities and who operate under a high level of ethical standards.

/s/ Kimberly J. Harris	/s/ Bertrand A. Valdman	/s/  James W. Eldredge
Kimberly J. Harris	Bertrand A. Valdman	James W. Eldredge
President and Chief Executive Officer	Senior Vice President and Chief Financial Officer	Vice President, Controller and Chief Accounting Officer

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Puget Energy, Inc.:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, common shareholder's equity, comprehensive income and cash flows present fairly, in all material respects, the financial position of Puget Energy, Inc. and its subsidiaries (Successor Company) at December 31, 2010 and 2009, and the results of their operations and their cash flows for the year ended December 31, 2010 and for the period from February 6, 2009 through December 31, 2009 in conformity with accounting principles generally accepted in the United States of America.  In addition, in our opinion, the schedule of Condensed Financial Information of Puget Energy and the schedule of Valuation and Qualifying Accounts and Reserves for the year ended December 31, 2010 and for the period from February 6, 2009 through December 31, 2009, present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.  Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  The Company's management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting appearing under Item 9A.  Our responsibility is to express opinions on these financial statements, on the financial statement schedules and on the Company's internal control over financial reporting based on our integrated audits.  We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects.  Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk.  Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Seattle, Washington

March 4, 2011

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Puget Energy, Inc.:

In our opinion, the accompanying consolidated statements of income, common shareholder's equity, comprehensive income and cash flows of Puget Energy, Inc. and its subsidiaries (Predecessor Company) present fairly, in all material respects, the results of their operations and their cash flows for the period from January 1, 2009 to February 5, 2009 and for the year ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America.  In addition, in our opinion, the schedule of Condensed Financial Information of Puget Energy and the schedule of Valuation and Qualifying Accounts and Reserves for the period from January 1, 2009 to February 5, 2009 and for the year ended December 31, 2008 present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.  These financial statements and financial statement schedules are the responsibility of the Company's management.  Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 2 to the consolidated financial statements, the Company changed the manner in which it accounts for business combinations in 2009.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Seattle, Washington

February 25, 2010

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of Puget Sound Energy, Inc.:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, common shareholder's equity, comprehensive income and cash flows present fairly, in all material respects, the financial position of Puget Sound Energy, Inc. and its subsidiaries at December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America.  In addition, in our opinion, the financial statement schedule of Valuation and Qualifying Accounts and Reserves  presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.  Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  The Company's management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in Management's Report on Internal Control over Financial Reporting appearing under Item 9A.  Our responsibility is to express opinions on these financial statements, on the financial statement schedule and on the Company's internal control over financial reporting based on our integrated audits.  We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects.  Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk.  Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Seattle, WA

March 4, 2011

 

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands)

				Successor			Predecessor
	Year Ended December 31, 2010			February 6, 2009 – December 31, 2009			January 1, 2009 – February 5, 2009			Year Ended December 31, 2008
Operating revenue:
Electric	$	2,107,469		$	1,885,118		$	213,618		$	2,129,463
Gas		1,011,531			1,034,744			190,001			1,216,868
Other		3,217			5,286			94			11,442
Total operating revenue		3,122,217			2,925,148			403,713			3,357,773
Operating expenses:
Energy costs:
Purchased electricity		773,429			796,040			90,737			903,317
Electric generation fuel		268,147			196,483			11,961			212,333
Residential exchange		(75,109	)		(83,962	)		(12,542	)		(40,664	)
Purchased gas		535,933			597,935			120,925			737,851
Net unrealized (gain) loss on derivative instruments		54,095			(156,601	)		3,867			7,538
Utility operations and maintenance		486,701			449,745			37,650			461,632
Non-utility expense and other		23,952			16,672			112			12,785
Merger and related costs		--			2,731			44,324			9,252
Depreciation		292,634			242,477			21,773			255,706
Amortization		71,572			63,466			4,969			56,422
Conservation amortization		90,109			58,875			7,592			61,650
Taxes other than income taxes		292,520			266,424			36,935			297,203
Total operating expenses		2,813,983			2,450,285			368,303			2,975,025
Operating income		308,234			474,863			35,410			382,748
Other income (deductions):
Other income		45,196			49,158			3,653			33,274
Other expense		(5,673	)		(6,154	)		(369	)		(7,215	)
Unhedged interest rate derivative expense		(7,955	)		--			--			--
Charitable contributions		--			(5,000	)		--			--
Interest charges:
AFUDC		14,157			8,864			350			8,610
Interest expense		(321,167	)		(265,675	)		(17,291	)		(202,582	)
Income before income taxes		32,792			256,056			21,753			214,835
Income tax expense		2,481			82,041			8,997			59,906
Net income	$	30,311		$	174,015		$	12,756		$	154,929

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

PUGET ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

ASSETS

	December 31,
	2010			2009
Utility plant:
Electric plant	$	5,253,786		$	4,705,900
Gas plant		2,129,200			1,995,219
Common plant		318,615			284,758
Less:  Accumulated depreciation and amortization		(429,038	)		(185,474	)
Net utility plant		7,272,563			6,800,403
Other property and investments:
Goodwill		1,656,513			1,656,513
Investment in Bonneville Exchange Power contract		22,923			26,450
Other property and investments		125,918			127,073
Total other property and investments		1,805,354			1,810,036
Current assets:
Cash and cash equivalents		36,557			78,527
Restricted cash		5,470			19,844
Accounts receivable, net of allowance for doubtful accounts		327,615			320,016
Unbilled revenue		194,088			208,948
Purchased gas adjustment receivable		5,992			--
Materials and supplies, at average cost		85,413			75,035
Fuel and gas inventory, at average cost		96,633			96,483
Unrealized gain on derivative instruments		7,500			14,948
Income taxes		76,183			134,617
Prepaid expense and other		14,835			13,117
Power contract acquisition adjustment gain		134,553			169,171
Deferred income taxes		83,086			39,977
Total current assets		1,067,925			1,170,683
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes		73,337			89,303
Regulatory asset for PURPA buyout costs		40,629			78,162
Power cost adjustment mechanism		15,618			8,529
Regulatory assets related to power contracts		116,116			210,340
Other regulatory assets		773,974			751,999
Unrealized gain on derivative instruments		8,233			25,459
Power contract acquisition adjustment gain		624,667			865,020
Other		130,920			90,206
Total other long-term and regulatory assets		1,783,494			2,119,018
Total assets	$	11,929,336		$	11,900,140

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

PUGET ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

CAPITALIZATION AND LIABILITIES

	December 31,
	2010			2009
Capitalization:
Common shareholder’s equity:
Common stock $0.01 par value, 1,000 share authorized, 200 shares outstanding	$	--		$	--
Additional paid-in capital		3,308,957			3,308,957
Earnings reinvested in the business		17,024			91,024
Accumulated other comprehensive income (loss) - net of tax		(3,069	)		23,487
Total common shareholder’s equity		3,322,912			3,423,468
Long-term debt:
PSE first mortgage bonds and senior notes		3,052,000			2,709,000
PSE pollution control revenue bonds:
Revenue refunding 2003 series, due 2031		161,860			161,860
PSE junior subordinated notes		250,000			250,000
Puget Energy long-term debt		1,490,000			1,483,000
PSE long-term debt due within one year		(260,000	)		(232,000	)
Debt discount and other		(311,147	)		(331,162	)
Total long-term debt		4,382,713			4,040,698
Total capitalization		7,705,625			7,464,166
Current liabilities:
Accounts payable		291,148			321,287
Short-term debt		247,000			105,000
Current maturities of long-term debt		260,000			232,000
Accrued expenses:
Purchased gas adjustment liability		--			49,587
Taxes		81,505			77,302
Salaries and wages		34,453			30,654
Interest		59,182			52,540
Unrealized loss on derivative instruments		273,100			168,783
Power contract acquisition adjustment loss		69,915			94,223
Other		114,409			194,786
Total current liabilities		1,430,712			1,326,162
Long-term and regulatory liabilities:
Deferred income taxes		1,127,611			1,147,667
Unrealized loss on derivative instruments		183,135			89,717
Regulatory liabilities		305,936			261,990
Regulatory liabilities related to power contracts		759,220			1,034,192
Power contract acquisition adjustment loss		46,779			117,272
Other deferred credits		370,318			458,974
Total long-term and regulatory liabilities		2,792,999			3,109,812
Commitments and contingencies (Note 21)
Total capitalization and liabilities	$	11,929,336		$	11,900,140

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

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY

(Dollars in Thousands)

	Common Stock
	Shares	Amount		Additional Paid-in Capital			Earnings Reinvested in the Business			Accumulated Other Comprehensive Income (Loss)			Total Equity
Predecessor
Balance at December 31, 2007	129,678,489	$	1,297	$	2,278,500		$	240,079		$	2,078		$	2,521,954
Net income	--		--		--			154,929			--			154,929
Common stock dividend declared	--		--		--			(129,677	)		--			(129,677	)
Adjustment to initially apply ASC 820, Fair Value Measurements	--		--		--			(5,848	)		--			(5,848	)
Common stock issued:
Employee plans	--		--		(3,275	)		--			--			(3,275	)
Other comprehensive loss	--		--		--			--			(264,882	)		(264,882	)
Balance at December 31, 2008	129,678,489	$	1,297	$	2,275,225		$	259,483		$	(262,804	)	$	2,273,201
Net income	--		--		--			12,756			--			12,756
Common stock dividend declared	--		--		--			(38,188	)		--			(38,188	)
Common stock expense	--		--		(455	)		--			--			(455	)
Vesting of employee common stock	--		--		1,531			--			--			1,531
Other comprehensive loss	--		--		--			--			(19,312	)		(19,312	)
Balance at February 5, 2009	129,678,489	$	1,297	$	2,276,301		$	234,051		$	(282,116	)	$	2,229,533
Successor
Capitalization at merger	200	$	--	$	3,308,529		$	--		$	--		$	3,308,529
Net income	--		--		--			174,015			--			174,015
Common stock dividend declared	--		--		--			(82,991	)		--			(82,991	)
Employee stock plan tax windfall	--		--		428			--			--			428
Other comprehensive income	--		--		--			--			23,487			23,487
Balance at December 31, 2009	200	$	--	$	3,308,957		$	91,024		$	23,487		$	3,423,468
Net income	--		--		--			30,311			--			30,311
Common stock dividend declared	--		--		--			(104,311	)		--			(104,311	)
Other comprehensive income	--		--		--			--			(26,556	)		(26,556	)
Balance at December 31, 2010	200	$	--	$	3,308,957		$	17,024		$	(3,069	)	$	3,322,912

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

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands)

				Successor			Predecessor
	Year Ended December 31, 2010			February 6, 2009 – December 31, 2009			January 1, 2009 – February 5, 2009			Year Ended December 31, 2008
Net income	$	30,311		$	174,015		$	12,756		$	154,929
Other comprehensive income (loss):
Net unrealized loss on interest rate swaps during the period, net of tax of $(31,325), $(12,264), $0 and $0, respectively		(58,175	)		(22,777	)		--			--
Reclassification of net unrealized loss on interest rate swaps during the period, net of tax of $11,860, $10,168, $0 and $0, respectively		22,027			18,884			--			--
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $2,842, $18,554, $ 170 and $(80,769), respectively		5,172			34,458			315			(149,999	)
Net unrealized loss on energy derivative instruments during the period, net of tax of $0, $(14,120), $(13,010) and $(73,621), respectively		--			(26,222	)		(24,162	)		(136,725	)
Reclassification of net unrealized loss on energy derivative instruments settled during the period, net of tax of $2,380, $10,309, $2,428 and $11,590, respectively		4,420			19,144			4,509			21,525
Amortization of financing cash flow hedge contracts to earnings, net of tax of $0, $0, $15 and $171, respectively		--			--			26			317
Other comprehensive income (loss)		(26,556	)		23,487			(19,312	)		(264,882	)
Comprehensive income (loss)	$	3,755		$	197,502		$	(6,556	)	$	(109,953	)

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

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

				Successor			Predecessor
	Year Ended December 31, 2010			February 6, 2009 – December 31, 2009			January 1, 2009 – February 5, 2009			Year Ended December 31, 2008
Operating activities:
Net income	$	30,311		$	174,015		$	12,756		$	154,929
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		292,634			242,477			21,773			255,706
Amortization		71,572			63,466			4,969			56,422
Conservation amortization		90,109			58,875			7,592			61,650
Deferred income taxes and tax credits, net		(32,955	)		243,381			(512	)		80,596
Amortization of gas pipeline capacity assignment		(8,644	)		(8,620	)		(791	)		(9,346	)
Carrying value related to California wholesale energy sale regulatory asset		17,763			--			--			--
Non cash return on regulatory assets		(17,864	)		(25,342	)		(2,185	)		(11,018	)
Net unrealized loss (gain) on derivative instruments		50,495			(156,601	)		3,867			7,538
Renewable energy credit payments received		44,633			25,748			942			3,008
Pension funding		(12,000	)		(18,400	)		--			(24,900	)
Change in residential exchange program		(55	)		(2,667	)		1,927			37,811
Derivative contracts classified as financing activities due to merger		371,621			524,397			--			--
Storm damage deferred costs		(13,952	)		--			--			--
Other		(2,774	)		(943	)		2,230			1,849
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue		7,261			91,515			(31,332	)		(29,405	)
Materials and supplies		(19,378	)		4,077			(3,388	)		89
Fuel and gas inventory		3,591			(11,444	)		7,605			(20,433	)
Income taxes		58,434			(133,773	)		18,277			25,182
Prepayments and other		(2,345	)		5,744			(3,295	)		(3,055	)
Purchased gas adjustment		(55,579	)		38,984			1,711			(68,972	)
Accounts payable		(26,396	)		(85,073	)		(40,203	)		21,420
Taxes payable		4,203			12,227			(3,340	)		313
Accrued expenses and other		15,264			(31,473	)		59,172			(2,802	)
Net cash provided by operating activities		865,949			1,010,570			57,775			536,582
Investing activities:
Construction expenditures - excluding  equity AFUDC		(859,091	)		(726,157	)		(49,531	)		(846,001	)
Energy efficiency expenditures		(95,726	)		(82,258	)		(4,918	)		(66,126	)
Treasury grant payment received		28,675			--			--			--
Restricted cash		14,374			(945	)		(10	)		(14,096	)
Cash proceeds from property sales		5,145			28,152			--			2,248
Other		856			(1,868	)		959			(7,880	)
Net cash used in investing activities		(905,767	)		(783,076	)		(53,500	)		(931,855	)
Financing activities:
Change in short-term debt and leases, net		141,941			38,807			(151,800	)		704,214
Dividends paid		(104,311	)		(121,179	)		--			(129,677	)
Long-term notes and bonds issued		1,025,000			400,211			250,000			--
Redemption of preferred stock		--			--			(1,889	)		--
Redemption of bonds and notes		(675,000	)		(158,000	)		--			(179,500	)
Derivative contracts classified as financing activities due to merger		(371,621	)		(524,397	)		--			--
Issuance cost of bonds and other		(18,161	)		(16,372	)		7,133			(2,035	)
Net cash provided by (used in) financing activities		(2,152	)		(380,930	)		103,444			393,002
Net increase (decrease) in cash and cash equivalents		(41,970	)		(153,436	)		107,719			(2,271	)
Cash and cash equivalents at beginning of period		78,527			231,963			38,526			40,797
Cash and cash equivalents at end of period	$	36,557		$	78,527		$	146,245		$	38,526
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	278,926		$	247,247		$	1,239		$	204,837
Cash payments (refunds) for income taxes		(22,243	)		(47,740	)		--			(42,338	)

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands)

	Year Ended December 31,
	2010			2009			2008
Operating revenue:
Electric	$	2,107,469		$	2,098,736		$	2,129,463
Gas		1,011,531			1,224,745			1,216,868
Other		3,217			5,020			11,442
Total operating revenue		3,122,217			3,328,501			3,357,773
Operating expenses:
Energy costs:
Purchased electricity		774,007			887,306			903,317
Electric generation fuel		268,147			208,444			212,333
Residential exchange		(75,109	)		(96,504	)		(40,664	)
Purchased gas		535,933			718,860			737,851
Net unrealized (gain) loss on derivative instruments		166,953			(1,254	)		7,538
Utility operations and maintenance		486,701			487,396			461,632
Non-utility expense and other		11,159			14,532			12,399
Merger and related costs		--			23,908			--
Depreciation		292,634			269,386			255,706
Amortization		71,572			63,466			56,422
Conservation amortization		90,109			66,466			61,650
Taxes other than income taxes		292,520			303,360			297,203
Total operating expenses		2,914,626			2,945,366			2,965,387
Operating income		207,591			383,135			392,386
Other income (deductions):
Other income		45,153			52,812			33,239
Other expense		(5,673	)		(6,524	)		(7,215	)
Interest charges:
AFUDC		14,157			9,215			8,610
Interest expense		(234,793	)		(211,478	)		(202,588	)
Interest expense on Puget Energy note		(218	)		(264	)		(814	)
Income before income taxes		26,217			226,896			223,618
Income tax expense		122			67,644			60,882
Net income	$	26,095		$	159,252		$	162,736

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

ASSETS

	December 31,
	2010			2009
Utility plant:
Electric plant	$	7,586,208		$	7,046,379
Gas plant		2,752,962			2,637,003
Common plant		427,227			539,296
Less: Accumulated depreciation and amortization		(3,509,277	)		(3,453,165	)
Net utility plant		7,257,120			6,769,513
Other property and investments:
Investment in Bonneville Exchange Power contract		22,923			26,450
Other property and investments		115,056			116,267
Total other property and investments		137,979			142,717
Current assets:
Cash and cash equivalents		36,320			78,407
Restricted cash		5,470			19,844
Accounts receivable, net of allowance for doubtful accounts		327,341			320,065
Unbilled revenue		194,088			208,948
Purchased gas adjustment receivable		5,992			--
Materials and supplies, at average cost		84,222			64,604
Fuel and gas inventory, at average cost		92,222			95,813
Unrealized gain on derivative instruments		7,500			14,948
Income taxes		62,114			99,948
Prepaid expenses and other		14,412			12,067
Deferred income taxes		80,215			38,781
Total current assets		909,896			953,425
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes		73,337			89,303
Regulatory asset for PURPA buyout costs		40,629			78,162
Power cost adjustment mechanism		15,618			8,529
Other regulatory assets		729,115			665,272
Unrealized gain on derivative instruments		8,233			4,605
Other		138,857			105,045
Total other long-term and regulatory assets		1,005,789			950,916
Total assets	$	9,310,784		$	8,816,571

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

CAPITALIZATION AND LIABILITIES

	December 31,
	2010			2009
Capitalization:
Common shareholder’s equity:
Common stock $0.01 par value – 150,000,000 shares authorized, 85,903,791 shares outstanding	$	859		$	859
Additional paid-in capital		2,959,205			2,959,205
Earnings reinvested in the business		172,490			333,128
Accumulated other comprehensive income (loss) – net of tax		(157,647	)		(210,120	)
Total common shareholder’s equity		2,974,907			3,083,072
Long-term debt:
First mortgage bonds and senior notes		3,052,000			2,709,000
Pollution control revenue bonds:
Revenue refunding 2003 series, due 2031		161,860			161,860
Junior subordinated notes		250,000			250,000
Long-term debt due within one year		(260,000	)		(232,000	)
Total long-term debt		3,203,860			2,888,860
Total capitalization		6,178,767			5,971,932
Current liabilities:
Accounts payable		291,765			321,287
Short-term debt		247,000			105,000
Short-term note owed to Puget Energy		22,598			22,898
Current maturities of long-term debt		260,000			232,000
Accrued expenses:
Purchased gas adjustment liability		--			49,587
Taxes		81,505			77,302
Salaries and wages		34,453			30,654
Interest		54,723			47,154
Unrealized loss on derivative instruments		243,053			137,530
Other		49,661			104,148
Total current liabilities		1,284,758			1,127,560
Long-term and regulatory liabilities:
Deferred income taxes		1,034,517			996,576
Unrealized loss on derivative instruments		155,179			89,717
Regulatory liabilities		296,884			250,586
Other deferred credits		360,679			380,200
Total long-term and regulatory liabilities		1,847,259			1,717,079
Commitments and contingencies (Note 21)
Total capitalization and liabilities	$	9,310,784		$	8,816,571

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY

(Dollars in Thousands)

	Common Stock
	Shares	Amount			Additional Paid-in Capital			Earnings Reinvested in the business			Accumulated Other Comprehensive Income (loss)			Total Equity
Balance at December 31, 2007	85,903,791	$	859,038		$	1,297,076		$	345,899		$	2,078		$	2,504,091
Net income	--		--			--			162,736			--			162,736
Common stock dividend declared	--		--			--			(145,840	)		--			(145,840	)
Adjustment to initially apply ASC 820, Fair Value Measurements	--		--			--			(5,848	)		--			(5,848	)
Investment returned to parent	--		--			(1,071	)		--			--			(1,071	)
Other comprehensive loss	--		--			--			--			(264,882	)		(264,882	)
Balance at December 31, 2008	85,903,791	$	859,038		$	1,296,005		$	356,947		$	(262,804	)	$	2,249,186
Change in par value	--		(858,179	)		858,179			--			--			--
Net income	--		--			--			159,252			--			159,252
Common stock dividend declared	--		--			--			(183,071	)		--			(183,071	)
Investment from parent	--		--			805,283			--			--			805,283
Employee common stock award transferred to liability award	--		--			(690	)		--			--			(690	)
Employee stock plan tax windfall	--		--			428			--			--			428
Other comprehensive income	--		--			--			--			52,684			52,684
Balance at December 31, 2009	85,903,791	$	859		$	2,959,205		$	333,128		$	(210,120	)	$	3,083,072
Net income	--		--			--			26,095			--			26,095
Common stock dividend declared	--		--			--			(186,733	)		--			(186,733	)
Other comprehensive income	--		--			--			--			52,473			52,473
Balance at December 31, 2010	85,903,791	$	859		$	2,959,205		$	172,490		$	(157,647	)	$	2,974,907

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands)

	Year Ended December 31,
	2010		2009			2008
Net income	$	26,095	$	159,252		$	162,736
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $2,446, $12,819 and $(80,769), respectively		3,610		23,807			(149,999	)
Net unrealized gain (loss) on energy derivative instruments during the period, net of tax of $309, $(32,996) and $(73,621), respectively		575		(61,277	)		(136,725	)
Reclassification of net unrealized loss on energy derivative instruments settled during the period, net of tax of $25,831, $48,373 and $11,590, respectively		47,971		89,837			21,525
Amortization of financing cash flow hedge contracts to earnings, net of tax of $171, $171 and $171, respectively		317		317			317
Other comprehensive income (loss)		52,473		52,684			(264,882	)
Comprehensive income (loss)	$	78,568	$	211,936		$	(102,146	)

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

	Year Ended December 31,
	2010			2009			2008
Operating activities:
Net income	$	26,095		$	159,252		$	162,736
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		292,634			269,386			255,706
Amortization		71,572			63,466			56,422
Conservation amortization		90,109			66,466			61,650
Deferred income taxes and tax credits, net		(16,284	)		194,494			78,050
Amortization of gas pipeline capacity assignment		(8,644	)		(9,410	)		(9,346	)
Carrying value adjustment related to California wholesale energy sale regulatory asset		17,763			--			--
Non cash return on regulatory assets		(17,864	)		(27,527	)		(11,018	)
Net unrealized loss (gain) on derivative instruments		166,953			(1,254	)		7,538
Renewable energy credit payments received		44,633			26,690			3,008
Pension funding		(12,000	)		(18,400	)		(24,900	)
Change in residential exchange program		(55	)		(740	)		37,811
Storm damage deferred costs		(13,952	)		--			--
Other		(26,096	)		(13,444	)		11,484
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue		7,584			64,349			(33,055	)
Materials and supplies		(19,618	)		(2,580	)		89
Fuel and gas inventory		3,591			24,391			(20,433	)
Income taxes		37,834			(82,630	)		24,497
Prepayments and other		(2,345	)		2,353			(3,055	)
Purchased gas adjustment		(55,579	)		40,695			(68,972	)
Accounts payable		(25,780	)		(35,205	)		20,735
Taxes payable		4,203			(7,339	)		313
Accrued expenses and other		11,021			7,678			(2,840	)
Net cash provided by operating activities		575,775			720,691			546,420
Investing activities:
Construction expenditures - excluding equity AFUDC		(859,091	)		(775,688	)		(846,001	)
Energy efficiency expenditures		(95,726	)		(87,176	)		(66,126	)
Treasury grant payment received		28,675			--			--
Restricted cash		14,374			(955	)		(18,090	)
Cash received from property sales		5,145			28,175			2,248
Other		856			(926	)		(7,880	)
Net cash used in investing activities		(905,767	)		(836,570	)		(935,849	)
Financing activities:
Change in short-term debt and leases, net		141,941			(113,286	)		704,214
Dividends paid		(186,733	)		(183,071	)		(145,840	)
Long-term notes and bonds issued		575,000			600,000			--
Loan from (payment to) Puget Energy		(300	)		(3,156	)		10,287
Redemption of preferred stock		--			(1,889	)		--
Redemption of bonds and notes		(232,000	)		(158,000	)		(179,500	)
Investment from parent		--			25,960			--
Issuance cost of bonds and other		(10,003	)		(10,742	)		(2,035	)
Net cash provided by financing activities		287,905			155,816			387,126
Net increase (decrease) in cash and cash equivalents		(42,087	)		39,937			(2,303	)
Cash and cash equivalents at beginning of period		78,407			38,470			40,773
Cash and cash equivalents at end of period	$	36,320		$	78,407		$	38,470
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	198,496		$	183,652		$	204,837
Cash refunds for income taxes		(20,632	)		(44,365	)		(40,034	)

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1)  Summary of Significant Accounting Policies

Basis of Presentation

Puget Energy, Inc. (Puget Energy) is an energy services holding company that owns Puget Sound Energy, Inc. (PSE).  PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering 6,000 square miles, primarily in the Puget Sound region.  On February 6, 2009, Puget Holdings LLC (Puget Holdings), a consortium of long-term infrastructure investors, completed its merger with Puget Energy.  As a result of the merger, Puget Energy is a direct wholly-owned subsidiary of Puget Equico LLC (Puget Equico), which is an indirect wholly-owned subsidiary of Puget Holdings.  The acquisition of Puget Energy was accounted for in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 805, “Business Combinations” (ASC 805), as of the date of the merger.  ASC 805 requires the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the merger date.  Puget Energy’s consolidated financial statements and accompanying footnotes have been segregated to present pre-merger activity as the “Predecessor” Company and post-merger activity as the “Successor” Company.

The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiary, PSE.  PSE’s consolidated financial statements include the accounts of PSE and its subsidiaries.  Puget Energy and PSE are collectively referred to herein as “the Company.”  The consolidated financial statements are presented after elimination of all significant intercompany items and transactions.  PSE’s accounting continues to be on a historical basis and PSE’s financial statements do not include any ASC 805 purchase accounting adjustments.

The preparation of financial statements in conformity with Generally Accepted Accounting Principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period.  Actual results could differ from those estimates.

Certain prior year amounts have been reclassified to conform to the current year presentation.

Utility Plant

PSE capitalizes, at original cost, additions to utility plant, including renewals and betterments.  Costs include indirect costs such as engineering, supervision, certain taxes, pension and other employee benefits and an Allowance For Funds Used During Construction (AFUDC).  Replacements of minor items of property and major maintenance are included in maintenance expense.  The original cost of utility plant is charged to accumulated depreciation and costs associated with removal of property, less salvage, are charged to the cost of removal regulatory liability when the property is retired and removed from service.

Puget Energy remeasured the carrying amount of utility plant to fair value on February 6, 2009, as a result of purchase accounting adjustments.  After February 6, 2009, utility plant additions are capitalized at original cost.

Non-Utility Property, Plant and Equipment

For PSE, the costs of other property, plant and equipment are stated at historical cost.  Expenditures for refurbishment and improvements that significantly add to productive capacity or extend useful life of an asset are capitalized.  Replacement of minor items is expensed on a current basis.  Gains and losses on assets sold or retired are reflected in earnings.

For Puget Energy, the carrying amount of non-utility property, plant and equipment was remeasured to fair value on February 6, 2009, as a result of purchase accounting adjustments.  After February 6, 2009, non-utility property, plant and equipment are capitalized at original costs.

Depreciation and Amortization

For financial statement purposes, the Company provides for depreciation and amortization on a straight-line basis.  Amortization is comprised of intangibles such as computer software and franchises.  The depreciation of automobiles, trucks, power-operated equipment, tools and office equipment is allocated to asset and expense accounts based on usage.  The annual depreciation provision stated as a percent of a depreciable electric utility plant was 2.7%, 2.6% and 2.8% in 2010, 2009 and 2008, respectively; depreciable gas utility plant was 3.6%, 3.6% and 3.4% in 2010, 2009 and 2008, respectively; and depreciable common utility plant was 11.8%, 9.6% and 5.8% in 2010, 2009 and 2008, respectively.  Depreciation on other property, plant and equipment is calculated primarily on a straight-line basis over the useful lives of the assets.  The cost of removal is collected from PSE’s customers through depreciation expense and any excess is recorded as a regulatory liability.

Goodwill

On February 6, 2009, Puget Holdings completed its merger with Puget Energy.  Puget Energy remeasured the carrying amount of all its assets and liabilities to fair value, which resulted in recognition of approximately $1.7 billion in goodwill.  ASC 350, “Intangibles - Goodwill and Other” (ASC 350), requires that goodwill be tested for impairment at the reporting unit level on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value.  These events or circumstances could include a significant change in the Company’s business or regulatory outlook, legal factors, a sale or disposition of a significant portion of a reporting unit or significant changes in the financial markets which could influence the Company’s access to capital and interest rates.  Application of the goodwill impairment test requires judgment, including the identification of reporting units, assignment of assets and liabilities to reporting units, assignment of goodwill to reporting units and the determination of the fair value of the reporting units.  Management has determined Puget Energy has only one reporting unit.

The goodwill recorded by Puget Energy represents the potential long-term return to the Company’s investors.  Goodwill is tested for impairment annually using a two-step process.  The first step compares the carrying amount of the reporting unit with its fair value, with a carrying value higher than fair value indicating potential impairment.  If the first step test fails, the second step is performed.  This would entail a full valuation of Puget Energy’s assets and liabilities and comparing the valuation to its carrying amounts, with the aggregate difference indicating the amount of impairment.  Goodwill of a reporting unit is required to be tested for impairment on an interim basis if an event occurs or circumstances change that would cause the fair value of a reporting unit to fall below its carrying amount.

Puget Energy conducted its annual impairment test in 2010 using an October 1, 2010 measurement date.  The fair value of Puget Energy’s reporting unit was estimated using both discounted cash flow and market approach.  Such approaches are considered methodologies that market participants would use.  This analysis requires significant judgments, including estimation of future cash flows, which is dependent on internal forecasts, estimation of long-term rate of growth for Puget Energy business, estimation of the useful life over which cash flows will occur, the selection of utility holding companies determined to be comparable to Puget Energy and determination of an appropriate weighted-average cost of capital or discount rate.  The market approach estimates the fair value of the business based on market prices of stocks of comparable companies engaged in the same or similar lines of business.  In addition, indications of market value are estimated by deriving multiples of equity or invested capital to various measures of revenue, earnings or cash flow.  Changes in these estimates and or assumptions could materially affect the determination of fair value and goodwill impairment of the reporting unit.  Based on the test performed, management has determined that there was no indication of impairment of Puget Energy’s goodwill as of October 1, 2010.  There were no events or circumstances from the date of the assessment through December 31, 2010 that would impact management’s conclusion.

Cash and Cash Equivalents

Cash and cash equivalents consist of demand bank deposits and short-term highly liquid investments with original maturities of three months or less at the time of purchase.  Cash equivalents are reported at cost, which approximates fair value, and were $20.6 and $44.3 million as of December 31, 2010 and 2009, respectively.

Restricted Cash

Restricted cash represents cash to be used for specific purposes.  The restricted cash balance was $5.5 million and $19.8 million at December 31, 2010 and 2009, respectively.  The restricted cash balance in both 2010 and 2009 includes $0.7 million, and $0.8 million which represents funds held by Puget Western, Inc., a PSE subsidiary, for a real estate development project.  As of December 31, 2010, other restricted cash includes $3.2 in a Benefit Protection Trust, and $1.6 million in other restricted cash accounts.

Materials and Supplies

Materials and supplies are used primarily in the operation and maintenance of electric and natural gas distribution and transmission systems as well as spare parts for combustion turbines used for the generation of electricity.  PSE records these items at weighted-average cost.

Puget Energy remeasured the carrying amount of materials and supplies to fair value on February 6, 2009, as a result of purchase accounting adjustments.  Additionally, materials and supplies include emission allowances, Renewable Energy Credits (RECs) and carbon financials instruments recorded at fair value as of the merger date.  After February 6, 2009, items are recorded at weighted-average cost.

Fuel and Gas Inventory

Fuel and gas inventory is used in the generation of electricity and for future sales to the Company’s natural gas customers.  Fuel inventory consists of coal, diesel and natural gas used for generation.  Gas inventory consists of natural gas and liquefied natural gas (LNG) held in storage for future sales.  PSE records these items at the lower of cost or market value using the weighted-average cost method.

For Puget Energy, the carrying amount of fuel and gas inventory was remeasured to fair value on February 6, 2009, as a result of purchase accounting adjustments.  After February 6, 2009, additional inventory are recorded at the lower of cost or market value using the weighted-average cost method.

Regulatory Assets and Liabilities

PSE accounts for its regulated operations in accordance with ASC 980 “Regulated Operations” (ASC 980).  ASC 980 requires PSE to defer certain costs that would otherwise be charged to expense, if it were probable that future rates will permit recovery of such costs.  It similarly requires deferral requires deferral of revenues or gains and losses that are expected to be returned to customers in the future.  Accounting under ASC 980 is appropriate as long as rates are established by or subject to approval by independent third-party regulators; rates are designed to recover the specific enterprise’s cost of service; and in view of demand for service, it is reasonable to assume that rates set at levels that will recover costs can be charged to and collected from customers.  In most cases, PSE classifies regulatory assets and liabilities as long-term assets or liabilities.  The exception is the Purchased Gas Adjustment (PGA) which is a current asset.

Below is a chart with the allowed return on the net regulatory assets and liabilities and times periods associated.

Period	Rate of Return		After-Tax Return
April 8, 2010 - present	8.10	%	6.90	%
November 1, 2008 - April 7, 2010	8.25		7.00
January 13, 2007 - October 31, 2008	8.40		7.06

The net regulatory assets and liabilities at December 31, 2010 and 2009 included the following:

Puget Sound Energy	Remaining Amortization		December 31,
(Dollars in Thousands)	Period		2010			2009
PGA deferral of unrealized losses on derivative instruments	(a)		$	149,681		$	67,144
Chelan PUD contract initiation	(b)			133,888			124,406
Storm damage costs electric	3 to 8 years (a)			103,630			105,676
Deferred income taxes	(a)			73,337			89,303
Baker Dam licensing operating and maintenance costs	48 years			63,459			69,988
Environmental remediation	(a)			62,240			59,006
Deferred Washington Commission AFUDC	30 years			53,378			51,734
Energy conservation costs	1 to 2 years			48,367			41,695
PURPA electric energy supply contract buyout costs	1 year			40,629			78,162
White River relicensing and other costs	(a)			32,260			34,273
Mint Farm ownership and operating costs	14.3 years			29,364			20,805
Investment in Bonneville Exchange power contract	6.5 years			22,923			26,450
California ISO/PX Receivable		N/A		--			21,063
Unamortized loss on reacquired debt	1 to 25.5 years			18,304			19,539
PCA mechanism	(a)			15,618			8,529
PGA receivable	1 year			5,992			--
Various other regulatory assets	Varies			34,544			49,943
Total PSE regulatory assets			$	887,614		$	867,716
Cost of removal	(c)		$	(193,765	)	$	(173,370	)
PGA payable		N/A		--			(49,587	)
Renewable energy credits	(a)			(48,493	)		(35,481	)
Production tax credits	(d)			(20,186	)		--
Summit purchase option buy-out	10 years			(15,488	)		(17,062	)
Deferred credit on gas pipeline capacity	7.8 years			(13,310	)		(14,671	)
Various other regulatory liabilities	Up to 6.6 years			(5,642	)		(10,002	)
Total PSE regulatory liabilities			$	(296,884	)	$	(300,173	)
PSE net regulatory assets and liabilities			$	590,730		$	567,543

_______________

(a)	Amortization periods vary depending on timing of underlying transactions or awaiting regulatory approval in a future Washington Utilities and Transportation Commission (Washington Commission) rate proceeding.
(b)	Amortization will begin in November 2011 for a 20-year period.
(c)	The balance is dependent upon the cost of removal of underlying assets and the life of utility plant.
(d)	Amortization will begin once PTCs are utilized by PSE on its tax return.

Puget Energy	Remaining Amortization	December 31,
(Dollars in Thousands)	Period	2010			2009
Total PSE regulatory assets	(a)	$	887,614		$	867,716
Puget Energy acquisition adjustments:
Regulatory assets related to power contracts	1 year to 27 years		116,116			210,340
Service provider contracts	1 to 3 years		15,933			29,638
Various other regulatory assets	Varies		28,926			57,089
Total Puget Energy regulatory assets		$	1,048,589		$	1,164,783
Total PSE regulatory liabilities	(a)	$	(296,884	)	$	(300,173	)
Puget Energy acquisition adjustments:
Regulatory liabilities related to power contracts	1 to 42 years		(759,220	)		(1,034,192	)
Various other regulatory liabilities	Varies		(9,052	)		(11,404	)
Total Puget Energy regulatory liabilities		$	(1,065,156	)	$	(1,345,769	)
Puget Energy net regulatory asset and liabilities		$	(16,567	)	$	(180,986	)

_______________

(a) Puget Energy’s regulatory assets and liabilities include purchase accounting adjustments as a result of the merger.  For additional information, see Note 3.

If the Company determines that it no longer meets the criteria for continued application of ASC 980, the Company would be required to write off its regulatory assets and liabilities related to those operations not meeting ASC 980 requirements.  Discontinuation of ASC 980 could have a material impact on the Company’s financial statements.

In accordance with guidance provided by ASC 410, “Asset Retirement and Environmental Obligations,” PSE reclassified from accumulated depreciation to a regulatory liability $193.8 million and $173.4 million in 2010 and 2009, respectively, for the cost of removal of utility plant.  These amounts are collected from PSE’s customers through depreciation rates.

Allowance for Funds Used During Construction

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

The authorized AFUDC rates authorized by the Washington Utilities and Transportation Commission (Washington Commission) for natural gas and electric utility plant additions based on the effective dates is as follows:

Effective Date	Washington Commission AFUDC Rates
April 8, 2010 - present	8.10	%
November 1, 2008 - April 7, 2010	8.25
January 13, 2007 - October 31, 2008	8.40

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

The following table presents the AFUDC amounts:

	Year Ended December 31,
(Dollars in Thousands)	2010		2009		2008
Equity AFUDC	$	12,677	$	4,177	$	2,627
Washington Commission AFUDC		3,715		10,693		8,080
Total in other income		16,392		14,870		10,707
Debt AFUDC		14,157		9,214		8,610
Total AFUDC		30,549		24,084		19,317

Revenue Recognition

Operating utility revenue is recognized when the basis of services is rendered which include estimated unbilled revenue.  Sales to other utilities are recognized in accordance with ASC 605 “Revenue Recognition” (ASC 605).  Non-utility subsidiaries recognize revenue when services are performed or upon the sale of assets.  Revenue from retail sales is billed based on tariff rates approved by the Washington Commission.  Sales of RECs are deferred as a regulatory liability.

PSE collected Washington state excise taxes (which are a component of general retail rates) and municipal taxes totaling $231.1 million, $247.8 million and $240.5 million for 2010, 2009 and 2008, respectively.  The Company’s policy is to report such taxes on a gross basis in operating revenue and taxes other than income taxes in the accompanying consolidated statements of income.

Allowance for Doubtful Accounts

Allowance for doubtful accounts are provided for electric and natural gas customer accounts based upon a historical experience rate of write-offs of energy accounts receivable as compared to operating revenue.  The allowance account is adjusted monthly for this experience rate.  Other non-energy receivable balances are reserved in the allowance account based on facts and circumstances surrounding the receivable including, among other things, collection trends, prevailing and anticipated economic conditions and specific customer credit risk, indicating some or all of the balance is uncollectible.  The allowance account is maintained until either receipt of payment or the likelihood of collection is considered remote at which time the allowance account and corresponding receivable balance are written off.

The Company’s allowance for doubtful accounts at December 31, 2010 and 2009 was $9.8 million and $8.1 million, respectively.

Self-Insurance

PSE currently has no insurance coverage for storm damage and recent environmental contamination occurring on PSE-owned property.  PSE is self-insured for a portion of the risk associated with comprehensive liability, workers’ compensation claims and catastrophic property losses other than those which are storm related.  The Washington Commission has approved the deferral of certain uninsured storm damage costs that exceed $7.0 million for the years ending 2006 through 2008 and $8.0 million for subsequent years of qualifying storm damage costs for collection in future rates if the outage meets the Institute of Electrical and Electronics Engineers (IEEE) outage criteria for system average interruption duration index.

Federal Income Taxes

For Puget Energy and PSE’s separate financial statement purposes, income taxes are allocated to the subsidiaries on the basis of separate company computations of tax, modified by allocating certain consolidated group limitations which are attributed to the separate company level.  Taxes payable or receivable are settled with Puget Holdings.

Puget Energy and PSE provide for deferred taxes on certain assets and liabilities that are reported differently for income tax purposes than for financial reporting purposes, as required by ASC 740 “Income Taxes” (ASC 740).  Uncertain tax positions are also accounted for under ASC 740.  The Company reports interest in interest expense and penalties in other expense in the accompanying consolidated statements of income.

Rate Adjustment Mechanisms

PSE has a PCA mechanism that provides for a rate adjustment process if PSE’s costs to provide customers’ electricity varies from a baseline power cost rate established in a rate proceeding.  All significant variable power supply cost drivers are included in the PCA mechanism (hydroelectric generation variability, market price variability for purchased power and surplus power sales, natural gas and coal fuel price variability, generation unit forced outage risk and wheeling cost variability).  The PCA mechanism apportions increases or decreases in power costs, on a graduated scale, between PSE and its customers.  Any unrealized gains and losses from derivative instruments accounted for under ASC 815, “Derivatives and Hedging” (ASC 815), are deferred in proportion to the cost-sharing arrangement under the PCA mechanism.  On January 10, 2007, the Washington Commission approved the PCA mechanism with the same annual graduated scale but without a cap on excess power costs.

The graduated scale is as follows:

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

For the year ended December 31, 2010, the annual power costs variability was between $20.0 million and $40.0 million.  Accordingly, PSE and the customer share the costs in excess of $20.0 million in equal proportion.

The differences between the actual cost of PSE’s natural gas supplies and natural gas transportation contracts and costs currently allowed by the Washington Commission are deferred and recovered or repaid through the PGA mechanism.  The PGA mechanism allows PSE to recover expected gas costs, and defer, as a receivable or liability, any gas costs that exceed or fall short of this expected gas cost amount in the PGA mechanism rates, including interest.

Natural Gas Off-System Sales and Capacity Release

PSE contracts for firm natural gas supplies and holds firm transportation and storage capacity sufficient to meet the expected peak winter demand for natural gas by its firm customers.  Due to the variability in weather, winter peaking consumption of natural gas by most of its customers and other factors, PSE holds contractual rights to natural gas supplies and transportation and storage capacity in excess of its average annual requirements to serve firm customers on its distribution system.  For much of the year, there is excess capacity available for third-party natural gas sales, exchanges and capacity releases.  PSE sells excess natural gas supplies, enters into natural gas supply exchanges with third parties outside of its distribution area and releases to third parties excess interstate natural gas pipeline capacity and natural gas storage rights on a short-term basis to mitigate the costs of firm transportation and storage capacity for its core natural gas customers.  The proceeds from such activities, net of transactional costs, are accounted for as reductions in the cost of purchased natural gas and passed on to customers through the PGA mechanism, with no direct impact on net income.  As a result, PSE nets the sales revenue and associated cost of sales for these transactions in purchased natural gas.

Non-Core Gas Sales

As part of the Company’s electric operations, PSE provides natural gas to an electric supplier and to its gas-fired generation facilities.  The projected volume of natural gas for power is relative to the price of natural gas.  Based on the market prices for natural gas, PSE may use the gas it has already purchased to generate power or PSE may sell the already purchased natural gas.  The net proceeds from such activities are accounted for in other electric operating revenue and are included in the PCA mechanism.

Production Tax Credit

Production Tax Credits (PTCs) represent federal income tax incentives available to companies that generate energy from qualifying renewable sources.  Prior to July 1, 2010, PTCs that were generated were passed-through to customers in retail sales.  After July 1, 2010, PTCs which are generated and owed to customers are recorded as a regulatory liability with a corresponding reduction in electric operating revenue until PSE utilizes the tax credit on its tax return, at which time the PTCs will be credited to customers in retail sales.

Accounting for Derivatives

ASC 815 requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair value unless the contracts qualify for an exception.  PSE enters into derivative contracts to manage its energy resource portfolio and interest rate exposure including forward physical and financial contracts and swaps.  The majority of PSE’s physical contracts qualify for the Normal Purchase Normal Sale (NPNS) exception to derivative accounting rules.  PSE may enter into financial fixed contracts to economically hedge the variability of certain index-based contracts.  Those contracts that do not meet the NPNS exception are marked-to-market to current earnings in the statements of income, subject to deferral under ASC 980, for energy related derivatives due to the PCA mechanism and PGA mechanism.

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

The Company may enter into swap instruments or other financial derivative instruments to manage the interest rate risk associated with its long-term debt financing and debt instruments.  As of December 31, 2010, Puget Energy has interest rate swap contracts outstanding related to its long-term debt.  For additional information, see Note 10.

Fair Value Measurements of Derivatives

ASC 820, “Fair Value Measurements and Disclosures” (ASC 820), defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).  However, as permitted under ASC 820, the Company utilizes a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical expedient for valuing the majority of its assets and liabilities measured and reported at fair value.  The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique.  These inputs can be readily observable, market corroborated or generally unobservable.  The Company primarily applies the market approach for recurring fair value measurements as it believes that the approach is used by market participants for these types of assets and liabilities.  Accordingly, the Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.

The Company values derivative instruments based on daily quoted prices from an independent external pricing service.  When external quoted market prices are not available for derivative contracts, the Company uses a valuation model that uses volatility assumptions relating to future energy prices based on specific energy markets and utilizes externally available forward market price curves.  All derivative instruments are sensitive to market price fluctuations that can occur on a daily basis.

Stock-Based Compensation

The Company applies the fair value approach to stock compensation and estimates fair value in accordance with provisions of ASC 718, “Compensation – Stock Compensation.”  Effective February 6, 2009, as a result of the merger, all outstanding shares of the Company were accelerated and vested, the stock compensation plan was terminated and there was no stock-based compensation.  The Company recognized $14.5 million of stock compensation expense which was recorded in merger and related costs.

Debt Related Costs

Debt premiums, discounts, expenses and amounts received or incurred to settle hedges are amortized over the life of the related debt for the Company.  The premiums and costs associated with reacquired debt are deferred and amortized over the life of the related new issuance, in accordance with ratemaking treatment for PSE.

Statements of Cash Flows

PSE funds cash dividends paid to the shareholders of Puget Energy.  These funds are reflected in the statement of cash flows of Puget Energy as if Puget Energy received the cash from PSE and paid the dividends directly to the shareholders.

The following non-cash investing and financing activities have occurred at the Company:

·   PSE did not incur any capital lease obligations for the year ended December 31, 2010.  PSE incurred capital lease obligations of $15.9 million for vehicles for the year ended December 31, 2009.  PSE incurred $45.8 million for energy generation turbines for the year ended December 31, 2008.

·   In connection with the February 6, 2009 merger, Puget Energy assumed $779.3 million of long-term debt in order to pay down PSE short-term debt and assumed $587.8 million of long-term debt to pay off the previous shareholders.  This amount was included as part of the purchase price consideration.

Accumulated Other Comprehensive Income (Loss)

The following tables set forth the components of the Company’s accumulated other comprehensive income (loss) at December 31:

Puget Energy	At December 31,
(Dollars in Thousands)	2010			2009
Net unrealized loss on energy derivatives	$	(2,658	)	$	(7,078	)
Net unrealized loss on interest rate swaps		(40,041	)		(3,893	)
Net unrealized gain and prior service cost on pension plans		39,630			34,458
Total Puget Energy, net of tax	$	(3,069	)	$	23,487

Puget Sound Energy	At December 31,
(Dollars in Thousands)	2010			2009
Net unrealized loss on energy derivatives	$	(34,612	)	$	(83,158	)
Settlement of cash flow hedge contracts		(7,257	)		(7,574	)
Net unrealized loss and prior service cost on pension plans		(115,778	)		(119,388	)
Total PSE, net of tax	$	(157,647	)	$	(210,120	)

(2)  New Accounting Pronouncements

Recently Adopted Accounting Pronouncements

Business Combinations.  On January 1, 2009, Puget Energy adopted ASC 805, “Business Combinations.”  The objective of the standard is to improve the relevance, representational faithfulness and comparability of the information that a reporting entity provides in its financial reports about a business combination and its effects. To accomplish that, the standard establishes principles and requirements for how the acquirer: (1) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree; (2) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and (3) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination.  For additional information, see Note 3.

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

On February 6, 2009, Puget Holdings completed its merger with Puget Energy.  Puget Energy remeasured the carrying amount of all its assets and liabilities to fair value, which resulted in the recognition of approximately $1.7 billion in goodwill.  For additional information, see Note 3.

In September 2009, the FASB issued ASU 2009-12, “Fair Value Measurements and Disclosures: Investments in Certain Entities that Calculate Net Asset Value per Share (or its equivalent).”  The standard allows the reporting entity, as a practical expedient, to measure the fair value of investments that do not have readily determinable fair values on the basis of the net asset value per share of the investment if the net asset value of the investment is calculated in a matter consistent with Topic 946, “Financial Services – Investment Companies.”  The standard requires disclosures about the nature and risk of the investments and whether the investments are probable of being sold at amounts different from the net asset value per share.  The Company adopted the standard as of December 31, 2009, and such adoption did not have an impact on the consolidated financial statements.  For additional information, see Note 16.

On January 1, 2008, the Company adopted  ASC 820 for all financial assets and liabilities and nonfinancial assets and liabilities that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually).  The standard defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements.  This standard does not require any new fair value measurements, but provides guidance on how to measure fair value by providing a fair value hierarchy used to classify the source of the information.

The Company adopted ASC 820 on January 1, 2008, prospectively, for financial and nonfinancial instruments measured on a recurring basis, with certain exceptions, including the initial impact of changes in fair value measurements of existing derivative financial instruments measured initially using the transaction price under ASC 815.  The difference between the carrying amounts and the fair values of those instruments originally recorded under guidance in ASC 815 was recognized as a cumulative-effect adjustment to the opening balance of retained earnings of $9.0 million before tax as a result of recording a deferred loss on net derivative assets and liabilities.

In January 2009, the Company adopted ASC 820 for all nonfinancial assets and nonfinancial liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis.  The application of the fair value measurement guidance to nonrecurring nonfinancial assets and nonrecurring nonfinancial liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis did not impact the Company’s consolidated financial statements.

Accounting Standards Codification.  In June 2009, FASB issued ASU 2009-01, Topic 105, “GAAP amendments based on the Statement of Financial Standards No. 168 – The FASB Accounting Standards Codification and the Hierarchy of GAAP.”  With this ASU, the FASB Codification became the authoritative source of GAAP.  The FASB Codification was effective for interim and annual reporting periods ending after September 15, 2009, which was September 30, 2009 for the Company.  The FASB Codification did not have a material impact on the financial reporting of the Company.

Derivative Instruments Disclosures.  In January 2009, FASB issued a new standard, which required additional disclosures about the Company’s objectives in using derivative instruments and hedging activities, and tabular disclosures of the effects of such instruments and related hedged items on the Company’s financial position, financial performance, and cash flows. For additional information, see Note 13.

Retirement Benefits Disclosures.  Effective December 31, 2009, ASC 715 “Compensation – Retirement Benefits” (ASC 715) 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.  For additional information, see Note 16.

Subsequent Events.  In May 2009, FASB issued ASC 855, “Subsequent Events,” a new standard on subsequent events.  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 for the Company.  The implementation of this standard did not have a significant impact on the financial statements of the Company.

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

(3)  Business Combinations (Puget Energy Only)

On February 6, 2009, Puget Holdings completed its merger with Puget Energy.  As a result of the merger, Puget Energy is the direct wholly-owned subsidiary of Puget Equico, which is an indirect wholly-owned subsidiary of Puget Holdings.  After the merger, Puget Energy has 1,000 shares authorized, of which 200 shares have been issued at a par value of $0.01 per share.

At the time of the merger, each issued and outstanding share of common stock of Puget Energy was cancelled and converted automatically into the right to receive $30.00 in cash, without interest.  The fair value of consideration transferred was $3.9 billion, including funding by Puget Holdings of $3.0 billion, debt of $0.6 billion issued by Puget Energy and $0.3 billion that was the result of the stepped-up basis of the investors’ previously owned shares.

The table below is the statement of fair value of assets acquired and accrued liabilities assumed as of February 6, 2009 measured in accordance with ASC 805.  There were no adjustments subsequent to the merger transaction date.

(Dollars in Thousands)	Amount
Net utility plant	$	6,346,032
Other property and investments		151,913
Goodwill		1,656,513
Current assets		1,259,505
Long-term and regulatory assets		2,497,355
Long-term debt		2,490,544
Current liabilities		2,173,079
Long-term liabilities		3,358,000

The following tables present the fair value adjustments to Puget Energy’s balance sheet and recognition of goodwill in accordance with ASC 805:

ASSETS

(Dollars in Thousands)	February 6, 2009 Increase (Decrease)
Utility plant:
Electric plant	$	(2,367,756	)
Gas plant		(666,278	)
Common plant		(302,015	)
Less:  Accumulated depreciation and amortization		3,381,095
Net utility plant		45,046
Other property and investments:
Goodwill		1,656,513
Non-utility property		4,250
Total other property and investments		1,660,763
Current assets:
Materials and supplies		13,700
Fuel and gas inventory		(27,561	)
Unrealized gain on derivative instruments		3,765
Power contract acquisition adjustment gain		123,975
Deferred income taxes		32,772
Total current assets		146,651
Other long-term and regulatory assets:
Other regulatory assets		145,711
Unrealized gain on derivative instruments		1,359
Regulatory asset related to power contracts		317,800
Power contract acquisition adjustment gain		1,016,225
Other		(17,072	)
Total other long-term and regulatory assets		1,464,023
Total assets	$	3,316,483

CAPITALIZATION AND LIABILITIES

(Dollars in Thousands)	February 6, 2009 Increase (Decrease)
Capitalization:
Common shareholders’ equity	$	1,660,160
Long-term debt		(280,315	)
Total capitalization		1,379,845
Current liabilities:
Unrealized loss on derivative instruments		84,603
Current portion of deferred income taxes		171
Power contract acquisition adjustment loss		118,167
Other		42,679
Total current liabilities		245,620
Long-term liabilities and regulatory liabilities:
Deferred income taxes		161,094
Unrealized loss on derivative instruments		50,979
Regulatory liabilities		17,417
Regulatory liabilities related to power contracts		1,140,200
Power contract acquisition adjustment loss		199,633
Other deferred credits		121,695
Total long-term liabilities and regulatory liabilities		1,691,018
Total capitalization and liabilities	$	3,316,483

The carrying values of net utility plant and the majority of regulatory assets and liabilities were determined to be stated at fair value at the acquisition date based on a conclusion that individual assets are subject to regulation by the Washington Commission and the FERC.  As a result, the future cash flows associated with the assets are limited to the carrying value plus a return, and management believes that a market participant would not expect to recover any more or less than the carrying value.  Furthermore, management believes that the current rate of return on plant assets is consistent with an amount that market participants would expect.  ASC 805 requires that the beginning balance of fixed depreciable assets be shown net, with no accumulated amortization recorded, at the date of acquisition, consistent with fresh start accounting.

Other property and investments includes the carrying value of the investments in PSE subsidiaries and other non-utility assets adjusted to fair value based on a combination of the income approach, the market based approach and the cost approach.

The fair values of materials and supplies, which included emission allowances, RECs and carbon financial instruments, were established using a variety of approaches to estimate the market price.  The carrying value of fuel inventory was adjusted to its fair value by applying market cost at the date of acquisition.

Energy derivative contracts were reassessed and revalued at the merger date based on forward market prices and forecasted energy requirements.

The fair value assigned to the power contracts was determined using an income approach comparing the contract rate to the market rate for power over the remaining period of the contracts incorporating nonperformance risk.  Management also incorporated certain assumptions related to quantities and market presentation that it believes market participants would make in the valuation.  The fair value of the power contracts will be amortized as the contracts settle.

Other regulatory assets include service contracts which were valued using the income approach comparing the contract rate to the market rate over the remaining period of the contract.

The fair value of leases was determined using the income approach which calculated the favorable/unfavorable leasehold interests as the net present value of the difference between the contract lease rent and market lease rent over the remaining terms of the contracted lease obligation.

The fair value assigned to long-term debt was determined using two different methodologies.  For those securities which were quoted by a third party pricing service based on observable market data, the best indication of fair value was assumed to be the third party’s quoted price.  For those securities for which the third party did not provide regular pricing, the fair value of the debt was estimated by forecasting out all coupon and principal payments and discounting them to the present value at an approximated discount rate based on PSE’s risk of nonperformance as of the merger date.

The merger also triggered a new basis of accounting for Puget Energy’s postretirement benefit plans sponsored by PSE under ASC 805 which required remeasuring plan liabilities without the five year smoothing of market-related asset gains and losses.

For the year ended December 31, 2009, Puget Energy incurred pre-tax merger expenses of $47.1 million primarily related to legal fees, transaction advisory services, new credit facility fees, change of control provisions and real estate excise tax.  Puget Energy’s merger costs in 2009 are not indicative for periods following the acquisition.

One day prior to the merger, PSE defeased its preferred stock in the amount of $1.9 million.  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 closing of the merger.  An additional $26.0 million of the capital contribution was used to pay change in control costs associated with the merger.

(4)  Regulation and Rates

Electric Regulation and Rates

Storm Damage Deferral Accounting

The Washington Commission issued a general rate case order that defined deferrable catastrophic/extraordinary losses and provided that costs in excess of $8.0 million annually may be deferred for qualifying storm damage costs that meet the IEEE outage criteria for system average interruption duration index.PSE’s storm accounting, which allows deferral of certain storm damage costs.  In 2010 and 2009, PSE incurred $23.5 million and $4.7 million, respectively, in storm-related electric transmission and distribution system restoration costs, of which $14.0 million was deferred in 2010 and none in 2009.  

Electric General Rate Case

On April 2, 2010, the Washington Commission issued its order in PSE’s consolidated electric rate case filed in May 2009 which approved a general rate increase for electric customers of 3.7% annually, or $74.1 million, effective April 8, 2010.  In its order, the Washington Commission approved a weighted cost of capital of 8.1% and a capital structure that included 46.0% common equity with an after-tax return on equity of 10.1%.

On October 8, 2008, the Washington Commission issued its order in PSE’s electric general rate case filed in December 2007, approving a general rate increase for electric customers of $130.2 million or 7.1% annually.  The rate increase for electric customers was effective November 1, 2008.  In its order, the Washington Commission approved a weighted cost of capital of 8.25%, or 7.00% after-tax, and a capital structure that included 46.0% common equity with a return on equity of 10.15%.

Power Cost Only Rate Case

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

Accounting Ordersand Petitions

On May 21, 2008, PSE filed an accounting petition for a Washington Commission order that authorizes the deferral of a settlement payment of $10.7 million incurred as a result of the recent settlement of a lawsuit in the state of Montana over alleged damages caused by the operation of the Colstrip Montana coal-fired steam electric generation facility (Colstrip).  The payment was expensed pending resolution of the accounting petition.  In the April 2, 2010 general rate case order, the Washington Commission allowed recovery of $8.4 million in PSE’s operating costs, which represents the amount of the settlement, net of insurance proceeds.

On November 5, 2008, PSE filed an accounting petition for a Washington Commission order authorizing the deferral and recovery of interest due the Internal Revenue Service (IRS) for tax years 2001 to 2006 along with carrying costs incurred in connection with the interest due.  In October 2005, the Washington Commission issued an order authorizing the deferral and recovery of costs associated with increased borrowings necessary to remit deferred taxes to the IRS.  In the April 2, 2010 general rate case order, the Washington Commission denied recovery of the interest due to the IRS.  PSE expensed the interest deferral of $6.9 million in April 2010.

On November 6, 2008, PSE filed an accounting petition for a Washington Commission order authorizing accounting treatment and amortization related to payments received for taking assignment of Westcoast Pipeline Capacity.  The accounting petition seeks deferred accounting treatment and amortization of the regulatory liability to power costs beginning in November 2009 and extending over the remaining primary term of the pipeline capacity contract through October 31, 2018.  In the April 2, 2010 general rate case order, the Washington Commission approved the deferral of $7.5 million and amortization as proposed.

On December 30, 2008, the Washington Commission approved an order authorizing the sale of Puget Energy and PSE to Puget Holdings subject to a Settlement Stipulation which included 78 conditions.  Items included in the conditions that may affect the financial statements are dividend restrictions for Puget Energy and PSE which are discussed in Note 6.  In addition, the conditions provided for rate credits of $10.0 million per year (less certain merger savings) over a ten-year period beginning at the closing of the transaction.

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 Electric Generating Station (Mint Farm) that were 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 gas (GHG) emissions performance standard until the plant is included in rates or for two years from the date of purchase, whichever occurs sooner.  In the April 2, 2010 general rate case order, the Washington Commission approved the prudence of the Mint Farm acquisition and recovery of the deferred costs from the plant’s in-service date to the date of the order.  The deferred costs are to be amortized over 15 years.  As of December 31, 2010, the balance of the regulatory asset, net of amortization was $28.3 million.

On March 13, 2009, PSE filed with the Washington Commission an application for authority to sell and transfer certain assets related to the Company’s White River Hydroelectric Project (the Project) to the Cascade Water Alliance (CWA).  PSE also requested in its application that the Washington Commission waive applicable provisions of the Revised Code of Washington and Washington Administrative Code with regard to certain surplus property related to the Project, which PSE expects to sell in the near future but which is not part of the CWA transaction.  On May 14, 2009, the application for authority to transfer certain assets to CWA was approved by the Washington Commission and the application for waiver with regard to the Surplus Property was denied and requires PSE to seek approval prior to the sale of any property.

On September 30, 2009, PSE filed an accounting petition requesting that the Washington Commission authorize PSE to normalize over 10 years a Treasury grant of $28.7 million received under Section 1603 of the American Recovery and Reinvestment Act of 2009 associated with the Wild Horse expansion project.  Treasury grants are tax free grants related to certain renewable energy infrastructure that are available in lieu of the PTC allowed under the Internal Revenue Code.  The Washington Commission issued an order approving the accounting petition on December 10, 2009.

On October 16, 2009, PSE filed an accounting petition requesting that the Washington Commission authorize the deferral and recovery of incremental costs associated with protecting the Company’s infrastructure, facilitating public safety, and preparing PSE’s electric and natural gas system in the Green River Valley flood plain in anticipation of release of water from the United States Army Corps of Engineers’ (Corps) Howard Hanson Dam (Dam).  In the event of actual flooding, PSE also petitioned the Washington Commission to allow the deferral of costs associated with the repair and restoration of any electric and gas system infrastructure affected by a flood.

On January 28, 2010, the Washington Commission approved PSE’s request for authorization to defer the costs associated with restoring the Company’s infrastructure, facilitating public safety, and repairing the Company’s electric and natural gas system in the Green River Valley flood plain in the event evacuation is required or flooding occurs due to operations associated with the Dam.  This authorization is conditioned on PSE incurring incremental operation and maintenance costs in excess of $5.0 million per year associated with repair or restoration of the Company’s systems around the Green River.  The Washington Commission’s order will be effective until the date the Corps confirms that the Dam has been permanently repaired and that Corps’ operations will return to normal.

The Washington Commission issued an order in 2010 relating to how REC proceeds should be handled for regulatory accounting and ratemaking purposes.  The order required REC proceeds to be recorded as regulatory liabilities and that amounts recorded would accrue interest at a rate to be determined in a later filing.  In its petition, PSE had sought approval for the use of $21.1 million of REC proceeds to be used as an offset against its California wholesale energy sales regulatory asset.  In response to the order, PSE adjusted the carrying value of its regulatory asset in the second quarter of 2010 by $17.8 million (from $21.1 million to $3.3 million), with the $3.3 million then offset against the Company’s RECs regulatory liability.  The Company’s California wholesale energy sales regulatory asset represented unpaid bills for power sold into the markets maintained by the California Independent System Operator during the 2000-2001 California Energy Crisis, the claims of which were settled along with all counterclaims against PSE in a settlement agreement approved by the FERC on July 1, 2009.

On May 20, 2010, PSE filed an accounting petition requesting that the Washington Commission approve:  (1) the creation of a regulatory asset account for the prepayments made to the Bonneville Power Administration (BPA) associated with network upgrades to the Central Ferry substation related to the Lower Snake River wind project; (2) the monthly accrual of carrying charges on that regulatory asset at PSE’s approved net of tax rate of return; and (3) the ability to provide customers the BPA interest received through a reduction to transmission expense.  The petition is still pending approval by the Washington Commission.

Production Tax Credit / Renewable Energy Credit

PSE has a tariff which passes the benefits of the PTCs to customers.  The tariff is not subject to the sharing bands in the PCA.  Prior to July 1, 2010, PSE could adjust the PTC tariff annually based on differences between the PTC credits provided to the customers and the PTC credits actually earned, plus estimated PTC credits for the following year, less interest associated with the deferred tax balance for the PTC credits.  Since customers received the benefit of the tax credits as they were generated and the Company did not receive a credit from the IRS until the tax credits were utilized, the Company will be reimbursed for its carrying costs.  PSE will continue to be reimbursed for carrying costs through December 31, 2011 when the credits that were provided and not used will be received from customers.

Effective July 1, 2010, the Washington Commission approved a change in PSE’s PTC tariff as PSE has not been able to utilize PTCs since 2007, due to insufficient taxable income caused primarily by bonus tax depreciation.  The Washington Commission approved PSE suspending its PTC tariff, effective July 1, 2010.  This resulted in an overall increase in PSE’s electric rates of 1.7%, however, this will not result in an increase in earnings.  

On September 22, 2010, a joint proposal and accounting petition was filed with the Washington Commission by PSE, Washington Commission Staff and Industrial Customers of Northwest Utilities which addressed how to recover PTCs provided to customers that have not been utilized and addresses REC proceeds to be returned to customers.  On October 26, 2010, the Washington Commission issued an order granting the joint proposal and accounting petition.  The order allows the Company to credit customers for REC revenue received and deferred through November 2009.  This credit will reduce rates by $27.7 million, or 2.5%, over five months beginning November 2010 through March 2011.  RECs received after November 2009 will be retained by PSE and will be used to recapture the benefit of PTCs previously provided to customers.  Once these PTCs are utilized by PSE on its tax return, the customers will receive the benefit.  

Treasury Grant

Section 1603 of the American Recovery and Reinvestment Tax Act of 2009 (Section 1603) authorizes the United States Department of the Treasury (U.S. Treasury) to make grants to corporations who place specified energy property in service provided certain conditions are met.  The Wild Horse expansion facility was placed into service on November 9, 2009.  The Wild Horse facility was expanded from 229 megawatts (MW) to 273 MW through the addition of wind turbines.  On December 22, 2009, PSE filed an application with the U.S. Treasury to request a grant on the expansion in the amount of $28.7 million.  Section 1603 precludes a recipient from claiming PTCs on property for which a grant is claimed.  On February 19, 2010, the U.S. Treasury approved the grant and payment was received in February 2010.

On December 30, 2010, the Washington Commission approved revisions to PSE’s PTC tariff, effective January 1, 2011, which changed the methodology by which PTCs are passed-through to customers.  Due to the uncertainty of realizing the benefit of PTCs, the PTCs will pass-through to customers following the year in which they are able to be utilized on PSE’s tax return, rather than in the same year in which they are generated by qualifying wind powered facilities.  The rate schedule will pass-through $5.5 million of the $28.7 million treasury grant in 2011.  The order authorized PSE to pass back one-tenth of the treasury grant on an annual basis and includes 23 months of treasury grant amortization to customers from February 2010 through December 2011, which represents the month the treasury grant funds were received through the end of the period over which the rates will be set.  This represents an overall average rate reduction of 0.3%, with no impact to net income.  Since the tariff now addresses additional federal incentives, it has been renamed the Federal Incentive Tracker.

PCA Mechanism

In 2002, the Washington Commission approved a PCA mechanism that provides for a rate adjustment process if PSE’s costs to provide customers’ electricity varies from a baseline power cost rate established in a rate proceeding. On January 10, 2007, the Washington Commission approved the continuation of the PCA mechanism under the same annual graduated scale but without a cap on excess power costs.  All significant variable power supply cost variables (hydroelectric and wind generation, market price for purchased power and surplus power, natural gas and coal fuel price, generation unit forced outage risk and transmission cost) are included in the PCA mechanism.

The PCA mechanism apportions increases or decreases in power costs, on a calendar year basis, between PSE and its customers on a graduated scale.  For a discussion of the accounting policy and PCA graduated scale, see Note 1.

Gas Regulation and Rates

Gas General Rate Case

On October 1, 2010, PSE filed a natural gas tariff filing with the Washington Commission to implement changes to natural gas rates that would result in an overall increase in revenue of $24.4 million and a customer rate increase of 2.3%.  The parties to the proceedings have agreed upon a settlement of $19.0 million with a recommended effective date of April 1, 2011.  A Washington Commission order is expected in March 2011.

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

On October 8, 2008, the Washington Commission issued its order in PSE’s natural gas general rate case filed in December 2007, approving a general rate increase for natural gas rates of $49.2 million, or 4.6% annually.  The rate increases for natural gas customers were effective November 1, 2008.  In its order, the Washington Commission approved a weighted cost of capital of 8.25%, or 7.00% after tax, and a capital structure that included 46.0% common equity with a return on equity of 10.15%.

Purchased Gas Adjustment

PSE has a PGA mechanism in retail natural gas rates to recover variations in natural gas supply and transportation costs.  Variations in natural gas rates are passed through to customers; therefore, PSE’s net income is not affected by such variations.

The following table sets for PGA rate adjustments that were approved by the Washington Commission and the corresponding impact to PSE’s annual revenue based on the effective dates:

Effective Date	Percentage Increase (Decrease) in Rates		Annual Increase (Decrease) in Revenue (Dollars in Millions)
November 1, 2010	1.9	%	$	18.3
October 1, 2009 – October 31, 2010	(17.1	)		(198.1	)
June 1, 2009 – May 31, 2010	(1.8	)		(21.2	)
October 1, 2008 – September 30, 2009	11.1			108.8

(5)  Preferred Share Purchase Right

On October 23, 2000, the Board of Directors declared a dividend of one preferred share purchase right (a Right) for each outstanding common share of Puget Energy.  The dividend was paid on December 29, 2000 to shareholders of record on that date.  The Rights were to become exercisable only if a person or group acquired 10.0% or more of Puget Energy’s outstanding common stock or announced a tender offer which, if consummated, would have resulted in ownership by a person or group of 10.0% or more of the outstanding common stock.  Each Right entitled the holder to purchase from Puget Energy one one-hundredth of a share of preferred stock with economic terms similar to that of one share of Puget Energy’s common stock at a purchase price of $65.00, subject to adjustments.  The Rights were terminated on February 6, 2009 in connection with the merger transaction.

(6)  Dividend Payment Restrictions

The payment of dividends by PSE to Puget Energy is restricted by provisions of certain covenants applicable to long-term debt contained in PSE’s electric and natural gas mortgage indentures.  At December 31, 2010, approximately $416.7 million of unrestricted retained earnings was available for the payment of dividends under the most restrictive mortgage indenture covenant.

Beginning February 6, 2009, pursuant to the terms of the Washington Commission merger order, PSE may not declare or pay dividends if PSE’s common equity ratio, calculated on a regulatory basis, is 44.0% or below except to the extent a lower equity ratio is ordered by the Washington Commission.  Also, pursuant to the merger order, PSE may not declare or make any distribution unless on the date of distribution PSE’s corporate credit/issuer rating is investment grade, or, if its credit ratings are below investment grade, PSE’s ratio of Earnings Before Interest, Tax, Depreciation and Amortization (EBITDA) to interest expense for the most recently ended four fiscal quarter periods prior to such date is equal to or greater than three to one.  The common equity ratio, calculated on a regulatory basis, was 46.5% at December 31, 2010 and the EBITDA to interest expense was 3.9 to one.

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

Puget Energy’s ability to pay dividends is also limited by the merger order issued by the Washington Commission as well as by the terms of its credit facilities.  Pursuant to the merger order, Puget Energy may not declare or make a distribution unless on such date Puget Energy’s ratio of consolidated EBITDA to consolidated interest expense for the four most recently ended fiscal quarters prior to such date is equal to or greater than two to one.  At December 31, 2010, the EBITDA to interest expense was 2.7 to one.  In accordance with terms of the Puget Energy credit facilities, Puget Energy is limited to paying a dividend within an eight business-day period that begins seven business days following the delivery of quarterly or annual financial statements to the facility agent.  Puget Energy is not permitted to pay dividends during any Event of Default, or if the payment of dividends would result in an Event of Default (as defined in the facilities), such as failure to comply with certain financial covenants.  In addition, in order to declare or pay unrestricted dividends, Puget Energy’s interest coverage ratio may not be less than 1.5 to one and its cash flow to net debt outstanding ratio may not be less than 8.25% for the 12 months ending each quarter-end.  Puget Energy is also subject to other restrictions such as a “lock up” provision that, in certain circumstances, such as failure to meet certain cash flow tests, may further restrict Puget Energy’s ability to pay dividends.

At December 31, 2010, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.

(7)  Utility Plant

		Puget Energy						Puget Sound Energy
Utility Plant	Estimated Useful Life	At December 31						At December 31
(Dollars In Thousands)	(Years)	2010			2009			2010			2009
Electric, gas and common utility plant classified by prescribed accounts at original cost:
Distribution plant	10-50	$	4,313,447		$	3,986,453		$	6,054,961		$	5,759,617
Production plant	25-125		1,575,694			1,365,601			2,585,864			2,385,228
Transmission plant	45-65		337,163			277,038			463,546			403,657
General plant	5-35		390,732			308,065			449,980			363,739
Intangible plant (including capitalized software)	3-50		97,458			106,277			184,706			343,180
Plant acquisition adjustment	NA		183,142			211,728			223,108			251,693
Underground storage	25-60		26,869			26,338			40,558			40,052
Liquefied natural gas storage	25-45		12,440			12,440			14,310			14,310
Plant held for future use	NA		53,945			38,378			54,098			38,532
Other	NA		8,058			7,529			8,057			7,529
Plant not classified	NA		58,822			201,013			58,822			201,013
Capital leases	1-2		15,444			86,285			--			55,396
Less: accumulated provision for depreciation			(429,038	)		(185,474	)		(3,509,277	)		(3,453,165	)
Subtotal		$	6,644,176		$	6,441,671		$	6,628,733		$	6,410,781
Construction work in progress	NA		628,387			358,732			628,387			358,732
Net utility plant		$	7,272,563		$	6,800,403		$	7,257,120		$	6,769,513

Jointly owned generating plant service costs are included in utility plant service cost.  The following table indicates the Company’s percentage ownership and the extent of the Company’s investment in jointly owned generating plants in service at December 31, 2010.  These amounts are also included in the Utility Plant table above.

				Puget Energy’s Share					Puget Sound Energy’s Share
Jointly Owned Generating Plants (Dollars in Thousands)	Energy Source (Fuel)	Company’s Ownership Share		Plant in Service at Cost		Accumulated Depreciation			Plant in Service at Cost		Accumulated Depreciation
Colstrip Units 1 & 2	Coal	50	%	$	116,712	$	(3,008	)	$	263,467	$	(149,764	)
Colstrip Units 3 & 4	Coal	25	%		209,772		(11,463	)		496,485		(298,176	)
Colstrip Units 1 – 4 Common Facilities 1	Coal	various			83		(7	)		252		(175	)
Frederickson 1	Gas	49.85	%		61,745		2,582			70,701		(6,374	)

_______________

1 The Company’s ownership is 50% for Colstrip Units 1 & 2 and 25% for Colstrip Units 3 & 4.

There were no valuation adjustments to asset retirement obligations (ARO) in conjunction with the merger in 2009.  The Company did not recognize any new AROs in 2010 or in 2009.

The following table describes all changes to the Company’s ARO liability:

	At December 31
(Dollars in Thousands)	2010			2009
Asset retirement obligation at beginning of period	$	24,095		$	29,661
New asset retirement obligation recognized in the period		--			--
Liability settled in the period		(2,341	)		(3,621	)
Revisions in estimated cash flows		2,413			(3,483	)
Accretion expense		1,249			1,538
Asset retirement obligation at end of period	$	25,416		$	24,095

The Company has identified the following obligations which were not recognized at December 31, 2010:

· a legal obligation under Federal Dangerous Waste Regulations to dispose of asbestos-containing material in facilities that are not scheduled for remodeling, demolition or sales. The disposal cost related to these facilities could not be measured since the retirement date is indeterminable; therefore, the liability cannot be reasonably estimated currently;  

· an obligation under Washington state law to decommission the wells at the Jackson Prairie natural gas storage facility upon termination of the project.  Since the project is expected to continue as long as the Northwest pipeline continues to operate, the liability cannot be reasonably estimated currently;  

· an obligation to pay its share of decommissioning costs at the end of the functional life of the major transmission lines.  The major transmission lines are expected to be used indefinitely; therefore, the liability cannot be reasonably estimated currently;  

· a legal obligation under Washington state environmental laws to remove and properly dispose of certain under and above ground fuel storage tanks.  The disposal costs related to under and above ground storage tanks could not be measured since the retirement date is indeterminable; therefore, the liability cannot be reasonably estimated currently;

(8)  Long-Term Debt

Puget Sound Energy (Dollars in Thousands)
First Mortgage Bonds, Pollution Control Bonds , Senior Notes and Junior Subordinated Notes
			At December 31							At December 31
Series		Due	2010		2009		Series		Due	2010		2009
7.120	%	2010	$	--	$	7,000	7.200	%	2025	$	2,000	$	2,000
7.960	%	2010		--		225,000	7.020	%	2027		300,000		300,000
7.690	%	2011		260,000		260,000	7.000	%	2029		100,000		100,000
6.830	%	2013		3,000		3,000	5.000	%1	2031		138,460		138,460
6.900	%	2013		10,000		10,000	5.100	%1	2031		23,400		23,400
5.197	%	2015		150,000		150,000	5.483	%	2035		250,000		250,000
7.350	%	2015		10,000		10,000	6.724	%	2036		250,000		250,000
7.360	%	2015		2,000		2,000	6.274	%	2037		300,000		300,000
6.750	%	2016		250,000		250,000	5.757	%	2039		350,000		350,000
6.740	%	2018		200,000		200,000	5.764	%	2040		250,000		--
9.570	%	2020		25,000		25,000	5.795	%	2040		325,000		--
7.150	%	2025		15,000		15,000	6.974	%2	2067		250,000		250,000
Total PSE long-term debt										$	3,463,860	$	3,120,860

_______________

1	Pollution Control Bonds
2	Junior Subordinated Notes

Puget Energy		At December 31
(Dollars in Thousands)	Due	2010			2009
PSE long-term debt	Various	$	3,463,860		$	3,120,860
Fair value adjustment of PSE long-term debt 1			(284,187	)		(286,681	)
Term-loan	2014		782,000			1,225,000
Capital expenditures facility	2014		258,000			258,000
6.500% senior secured note	2020		450,000			--
Original discount on Puget Energy term-loan and capital expenditures facility	N/A		(26,947	)		(44,481	)
Unamortized discount on senior secured note	N/A		(13	)		--
Total Puget Energy long-term debt		$	4,642,713		$	4,272,698

_______________

1 For additional information regarding fair value adjustments, see Note 3

Puget Sound Energy Long-Term Debt

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

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

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

Substantially all utility properties owned by PSE are subject to the lien of the Company’s electric and natural gas mortgage indentures.  To issue additional first mortgage bonds under these indentures, PSE’s earnings available for interest must exceed certain minimums as defined in the indentures.  At December 31, 2010, the earnings available for interest exceeded the required amount.

Puget Sound Energy Pollution Control Bonds

PSE has two series of Pollution Control Bonds outstanding.  Amounts outstanding were borrowed from the City of Forsyth, Montana who obtained the funds from the sale of Customized Pollution Control Refunding Bonds issued to finance pollution control facilities at Colstrip Units 3 & 4.

Each series of bonds is collateralized by a pledge of PSE’s first mortgage bonds, the terms of which match those of the Pollution Control Bonds.  No payment is due with respect to the related series of first mortgage bonds so long as payment is made on the Pollution Control Bonds.

Puget Energy Long-Term Debt

On December 6, 2010, Puget Energy issued $450.0 million of senior secured notes.  The notes have a term of ten years and an interest rate of 6.5%.  The notes are secured by an interest in substantially all of Puget Energy’s assets, which consists mainly of all the issued and outstanding stock of PSE and the stock of Puget Energy held by Puget Equico.  The notes contain a change of control provision pursuant to which holders of the notes may have the right to require Puget Energy to repurchase all or any part of the notes at a purchase price in cash equal to 101.0% of the principal amount of the notes, plus accrued and unpaid interest.  

Effective with the close of the merger on February 6, 2009, Puget Energy entered into a $1.225 billion five-year term-loan and a $1.0 billion credit facility for funding capital expenditures.  Net proceeds from Puget Energy’s $450.0 million senior secured notes issue were used to repay $443.0 million of the $1.225 billion five-year term.  Concurrent with repayment on the term-loan, Puget Energy expensed $7.2 million of the loan’s unamortized discount and issuance costs.  As of December 31, 2010, Puget Energy had fully drawn the five-year term-loan which had a remaining outstanding balance of $782.0 million, and had drawn $258.0 million under the $1.0 billion credit facility.  The term-loan and facility mature in February 2014.  These credit agreements contain usual and customary affirmative and negative covenants, which are similar to PSE’s credit facilities.  In May 2010, Puget Energy’s credit facilities were amended, in part, to include a provision for the sharing of collateral with future note holders when notes are issued to repay and reduce the size of the credit facilities.  Concurrent with the borrowings under these credit agreements, Puget Energy entered into several interest rate swaps with a group of banks to fix the interest rates at 4.76% for the initial term-loan and credit facility borrowings totaling $1.483 billion.  For additional information, see Note 13.

Long-Term Debt Maturities

The principal amounts of long-term debt maturities for the next five years and thereafter are as follows:

(Dollars in Thousands)	2011		2012		2013		2014		2015		Thereafter		Total
Maturities of:
PSE long-term debt	$	260,000	$	--	$	13,000	$	--	$	162,000	$	3,028,860	$	3,463,860
Puget Energy long-term debt		--		--		--		1,040,000		--		450,000		1,490,000
Puget Energy long-term debt	$	260,000	$	--	$	13,000	$	1,040,000	$	162,000	$	3,478,860	$	4,953,860

Financial Covenants

The Company’s credit facilities contain financial covenants related to cash flow interest coverage, cash flow to net debt outstanding and debt service coverage, each as specified in the facilities.  As of December 31, 2010, the Company is in compliance with its long-term debt financial covenants.

(9)  Redeemable Securities

On February 5, 2009, PSE deposited with its Redemption and Paying Agent approximately $1.9 million to defease the preferred stock and issued an irrevocable notice that the shares were to be redeemed on March 13, 2009.  The Redemption and Paying Agent paid shareholders their redemption price plus accrued dividends through March 13, 2009.  As of December 31, 2010, there were no outstanding shares of preferred stock or other redeemable securities.

(10)  Estimated Fair Value of Financial Instruments

Puget Energy

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

	December 31, 2010				December 31, 2009
(Dollars in Thousands)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Financial assets:
Cash and cash equivalents	$	36,557	$	36,557	$	78,527	$	78,527
Restricted cash		5,470		5,470		19,844		19,844
Notes receivable and other		72,419		72,419		74,063		74,063
Electric derivatives		9,762		9,762		5,140		5,140
Gas derivatives		5,971		5,971		14,413		14,413
Interest rate derivatives		--		--		20,854		20,854
Financial liabilities:
Short-term debt	$	247,000	$	247,000	$	105,000	$	105,000
Junior subordinated notes		250,000		246,864		250,000		232,684
Current maturities of long-term debt (fixed-rate)		260,000		261,472		232,000		234,632
Long-term debt (fixed-rate), net of discount		3,119,660		3,718,303		2,352,179		2,815,048
Long-term debt (variable-rate), net of discount		1,013,053		1,083,117		1,438,519		1,478,632
Electric derivatives		242,581		242,581		150,099		150,099
Gas derivatives		155,651		155,651		81,557		81,557
Interest rate derivatives		58,003		58,003		26,844		26,844

Puget Sound Energy

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

	December 31, 2010				December 31, 2009
(Dollars in Thousands)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Financial assets:
Cash and cash equivalents	$	36,320	$	36,320	$	78,407	$	78,407
Restricted cash		5,470		5,470		19,844		19,844
Notes receivable and other		72,419		72,419		74,063		74,063
Electric derivatives		9,762		9,762		5,140		5,140
Gas derivatives		5,971		5,971		14,413		14,413
Financial liabilities:
Short-term debt	$	247,000	$	247,000	$	105,000	$	105,000
Short-term debt owed by PSE to Puget Energy 1		22,598		22,598		22,898		22,898
Junior subordinated notes		250,000		246,864		250,000		232,684
Current maturities of long-term debt (fixed-rate)		260,000		261,472		232,000		234,632
Non-current maturities of long-term debt (fixed-rate)		2,953,860		3,267,994		2,638,860		2,815,048
Electric derivatives		242,581		242,581		145,690		145,690
Gas derivatives		155,651		155,651		81,557		81,557

________________

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

The fair value of long-term notes and variable rate notes were estimated using U.S. Treasury yields and related current market credit spreads, interpolating to the maturity date of each issue.

The carrying values of short-term debt and notes receivable are considered to be a reasonable estimate of fair value.  The carrying amount of cash, which includes temporary investments with original maturities of three months or less, is also considered to be a reasonable estimate of fair value.

(11)  Liquidity Facilities and Other Financing Arrangements

As of December 31, 2010 and 2009, PSE had $247.0 million and $105.0 million in short-term debt outstanding, respectively, exclusive of the demand promissory note with Puget Energy.  Outside of the consolidation of PSE’s short-term debt, Puget Energy had no short-term debt outstanding in either year as borrowings under its credit facilities are classified as long-term.  PSE’s weighted-average interest rate on short-term debt, including borrowing rate, commitment fees and the amortization of debt issuance costs, during 2010 and 2009 was 5.11% and 3.59%, respectively.  As of December 31, 2010, PSE and Puget Energy had several committed credit facilities that are described below

Puget Sound Energy Credit Facilities

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

PSE’s credit agreements contain usual and customary affirmative and negative covenants that, among other things, place limitations on PSE’s ability to incur additional indebtedness and liens, issue equity, pay dividends, transact with affiliates and make asset dispositions and investments.  The credit agreements also contain financial covenants which include a cash flow interest coverage ratio and, in addition, if PSE has a below investment grade credit rating, a cash flow to net debt outstanding ratio (each as specified in the facilities).  PSE certifies its compliance with these covenants to participating banks each quarter.  As of December 31, 2010, PSE was in compliance with all applicable covenants.

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

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

As of December 31, 2010, $247.0 million was drawn and outstanding under PSE’s $400.0 million capital expenditure facility in addition to a $12.6 million letter of credit supporting the BPA contracts.  No loans were outstanding under PSE’s working capital facility and no loans or letters of credit were outstanding under PSE’s $350.0 million facility supporting energy hedging activities. Outside of the credit agreements, PSE had a $5.7 million letter of credit in support of a long-term transmission contract.

Demand Promissory Note.  On June 1, 2006, PSE entered into a revolving credit facility with Puget Energy in the form of a Demand Promissory Note (Note) pursuant to which PSE may borrow up to $30.0 million from Puget Energy subject to approval by Puget Energy.  Under the terms of the Note, PSE pays interest on the outstanding borrowings based on the lowest of the weighted-average interest rate of PSE’s outstanding commercial paper interest rate or PSE’s senior unsecured revolving credit facility.  Absent such borrowings, interest is charged at one-month LIBOR plus 0.25%. At December 31, 2010 and 2009, the outstanding balance of the Note was $22.6 million and $22.9 million, respectively, and the interest rate was 1.1% and 1.2%, respectively.  The outstanding balance and the related interest under the Note are eliminated by Puget Energy upon consolidation of PSE’s financial statements.  The $30.0 million credit facility with Puget Energy was not affected by the merger.

Puget Energy Credit Facilities

Effective with the close of the merger on February 6, 2009, Puget Energy entered into a $1.225 billion five-year term-loan and a $1.0 billion credit facility for funding capital expenditures.  On December 6, 2010, Puget Energy issued $450.0 million of senior secured notes.  The net proceeds of $443.0 million from these notes were used to repay a portion of the $1.225 billion five-year term-loan.  Concurrent with the repayment on the term-loan, Puget Energy expensed $7.2 million of the loan’s unamortized discount and issuance costs.  As of December 31, 2010, Puget Energy had fully drawn the five-year term-loan  which had a remaining outstanding balance of $782.0 million, and had drawn $258.0 million under the $1.0 billion facility. The term-loan and facility mature in February 2014.  These credit agreements contain usual and customary affirmative and negative covenants which are similar to PSE’s credit facilities.  Puget Energy’s credit agreements contain financial covenants based on the following three ratios:  cash flow interest coverage, cash flow to net debt outstanding and debt service coverage (cash available for debt service to borrower interest), each as specified in the facilities.  Puget Energy certifies its compliance with these covenants each quarter.  As of December 31, 2010, Puget Energy was in compliance with all applicable covenants.

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

These facilities contain similar terms and conditions and are syndicated among numerous committed lenders.  The agreements provide Puget Energy with the ability to borrow at different interest rate options and include variable fee levels.  Borrowings may be at the banks’ prime rate or at floating rates based on LIBOR plus a spread based upon Puget Energy’s credit rating.  Puget Energy must also pay a commitment fee on the unused portion of the $1.0 billion facility.  The spreads and the commitment fee depend on Puget Energy’s credit ratings.  As of the date of this report, the spread over prime rate is 1.25%, the spread to the LIBOR is 2.25% and the commitment fee is 0.84%.

(12)  Leases

PSE leases buildings and assets under operating leases.  In January 2009, PSE entered into an agreement to purchase the Fredonia combustion turbines for $42.4 million and its fleet vehicles for $11.8 million, which purchase was completed in January 2010.  These were previously leased under an operating lease.  Entering into the purchase agreement resulted in the reclassification of the Fredonia and fleet leases as capital leases.  Certain leases contain purchase options and renewal and escalation provisions.  Rent expense net of sublease receipts were:

(Dollars in Thousands)
At December 31
2010	$	22,493
2009		31,747
2008		29,087

Payments received for the subleases of properties was approximately $0.1 million for each of the years ended 2010, 2009 and 2008.

Future minimum lease payments for non-cancelable leases net of sublease receipts are:

(Dollars in Thousands) At December 31	Operating		Capital
2011	$	11,870	$	42,603
2012		13,288		--
2013		13,559		--
2014		12,412		--
2015		12,479		--
Thereafter		71,330		--
Total minimum lease payments	$	134,938	$	42,603

PSE leased a portion of its owned natural gas transmission pipeline infrastructure under a non-cancelable operating lease to a third party which expired in 2009.

The capital lease schedule above represents Puget Energy’s estimate for leased Tenaska Power Fund, L.P. (Tenaska) turbines in the amount of $42.6 million for the year ended 2011.  As a result of the merger, the Tenaska turbine lease was reclassified from a power purchase agreement to a capital lease for Puget Energy.

(13)  Accounting for Derivative Instruments and Hedging Activities

PSE employs various portfolio optimization strategies, but is not in the business of assuming risk for the purpose of realizing speculative trading revenue.  The nature of serving regulated electric customers with its portfolio of owned and contracted electric generation resources exposes PSE and its customers to 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 costs and margins in the portfolio.  PSE’s energy risk portfolio management function monitors and manages these risks using analytical models and tools.  In order to manage risks effectively, PSE enters into physical and financial transactions which are appropriate for the service territory of PSE and are relevant to its regulated electric and natural gas portfolios.

On the date of the merger, Puget Energy de-designated its derivative contracts that were designated on PSE’s books as NPNS or cash flow hedges and recorded such contracts at fair value as either assets or liabilities.  Certain contracts meeting the criteria defined in ASC 815 were subsequently re-designated as NPNS or cash flow hedges.

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

The Company manages its interest rate risk through the issuance of mostly fixed-rate debt of various maturities.  The Company utilizes internal cash from operations, commercial paper, and credit facilities to meet short-term funding needs.  Short-term obligations are commonly refinanced with fixed-rate bonds or notes when needed and when interest rates are considered favorable.  The Company may enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts.  In February 2009, Puget Energy entered into interest rate swap transactions to hedge the risk associated with its one-month LIBOR floating debt rate.  As of December 31, 2010, Puget Energy had seven interest rate swap contracts outstanding and PSE did not have any outstanding interest rate swap instruments.

Effective December 6, 2010, Puget Energy elected to de-designate its interest rate derivatives previously recorded as cash flow hedges based on its intent to refinance the underlying debt over the next few years.  The outstanding interest rate derivative loss on December 6, 2010 of $61.8 million was recorded in OCI and will be amortized as the future interest payments on the debt occur.  In addition, a portion of the related forecasted transactions was determined to be remote of occurring and as a result, management reclassified a $7.3 million loss to other deductions in December 2010.  

Going forward, all gains or losses associated with the interest rate swaps will be marked-to-market and recorded in earnings.  Puget Energy recorded a $10.9 million gain related to the swaps to interest expense during 2010.  As of December 31, 2010, Puget Energy had not unwound or terminated any of the swaps corresponding to the de-designated cash flow hedge.  A portion of those swaps may remain un-hedged (not linked to any debt) until December 6, 2011 or the Company may unwind or follow other strategies to mitigate the risk of these open positions.  During the period for which these swaps remain un-hedged, the Company will be subject to additional interest rate risk.

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

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

Derivatives Not Designated as Hedging Instruments
Puget Energy	December 31, 2010				December 31, 2009
(Dollars in Thousands)	Assets 1		Liabilities 1		Assets 1		Liabilities 1
Interest rate swaps:
Current	$	--	$	30,047	$	--	$	--
Long-term		--		27,956		--		--
Electric portfolio:
Current		4,716		142,780		4,137		79,732
Long-term		5,046		99,801		1,003		70,367
Gas portfolio: 2
Current		2,784		100,273		10,811		62,207
Long-term		3,187		55,378		3,602		19,350
Total derivatives	$	15,733	$	456,235	$	19,553	$	231,656

___________

1

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

2

Puget Energy had a derivative liability and an offsetting regulatory asset of $149.7 million at December 31, 2010 and $67.1 million at December 31, 2009 related to financial contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers.  All fair value adjustments on derivatives relating to the natural gas business have been reclassified to a deferred account in accordance with ASC 980 due to the PGA mechanism.  All increases and decreases in the cost of natural gas supply are passed on to customers with the PGA mechanism and the gains and losses on the hedges in future periods will be recorded as gas costs.

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

Derivatives Not Designated as Hedging Instruments
Puget Sound Energy	December 31, 2010				December 31, 2009
(Dollars in Thousands)	Assets 1		Liabilities 1		Assets 1		Liabilities 1
Electric portfolio:
Current	$	4,716	$	142,780	$	4,137	$	75,323
Long-term		5,046		99,801		1,003		70,367
Gas portfolio: 2
Current		2,784		100,273		10,811		62,207
Long-term		3,187		55,378		3,602		19,350
Total derivatives	$	15,733	$	398,232	$	19,553	$	227,247

___________

1

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

2

PSE had a derivative liability and an offsetting regulatory asset of $149.7 million at December 31, 2010 and $67.1 million at December 31, 2009 related to financial contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers.  All fair value adjustments on derivatives relating to the natural gas business have been reclassified to a deferred account in accordance with ASC 980 due to the PGA mechanism.  All increases and decreases in the cost of natural gas supply are passed on to customers with the PGA mechanism and the gains and losses on the hedges in future periods will be recorded as gas costs.

For further details regarding the fair value of derivative instruments and their Level categorization, see Note 14.

The following table presents the net unrealized (gain) loss of Puget Energy’s derivative instruments recorded on the statements of income for the years ended December 31, 2010 and 2009:

	Successor						Predecessor
Puget Energy (Dollars in Thousands)	Year Ended December 31, 2010			February 6, 2009 – December 31, 2009			January 1, 2009 – February 5, 2009			Year Ended December 31, 2008
Gas / Power NPNS 1	$	(40,564	)	$	(42,328	)	$	--		$	--
Gas for power generation		37,535			(71,921	)		3,696			4,521
Power exchange		(2,619	)		(2,247	)		(588	)		(3,232	)
Power		59,743			(51,698	)		759			6,331
Credit reserve 2		--			11,593			--			(82	)
Total net unrealized (gain) loss on derivative instruments	$	54,095		$	(156,601	)	$	3,867		$	7,538
Interest expense – interest rate swaps	$	(10,918	)	$	--		$	--		$	--
Other deductions – interest rate swaps	$	7,319		$	--		$	--		$	--

___________

1	Amount represents amortization expense related to contracts that were recorded at fair value at the time of the merger order.
2	Beginning in the second quarter 2009, the credit reserve was incorporated as a component of the individual derivative value and not recorded separately.

The following table presents the net unrealized (gain) loss of PSE’s derivative instruments recorded on the statements of income for the years ended December 31, 2010 and 2009:

Puget Sound Energy	Year Ended December 31,
(Dollars in Thousands)	2010			2009			2008
Gas for power generation	$	91,666		$	(2,835	)	$	4,521
Power exchange		(2,620	)		(2,822	)		(3,232	)
Power		77,907			4,321			6,331
Credit reserve 1		--			82			(82	)
Total net unrealized (gain) loss on derivative instruments	$	166,953		$	(1,254	)	$	7,538

___________

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

The following tables present the effect of hedging instruments on Puget Energy’s OCI and statements of income for the years ended December 31, 2010 and 2009:

Puget Energy (Dollars in Thousands)	Year Ended December 31, 2010
Derivatives in Cash Flow Hedging Relationships	Gain (Loss) Recognized in OCI on Derivatives 1 (Effective Portion 2)			Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion 3)				Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion and Amount Excluded from Effectiveness Testing 3)
				Location				Location
Interest rate contracts:	$	(58,175	)	Interest expense	$	(33,887	)		$	--
Commodity contracts: Electric derivatives		--		Electric generation fuel		(3,347	)	Net unrealized gain on derivative instruments		--
Electric derivatives		--		Purchased electricity		(3,453	)	Net unrealized loss on derivative instruments		--
Total	$	(58,175	)		$	(40,687	)		$	--

Puget Energy (Dollars in Thousands)	SuccessorFebruary 6, 2009 – December 31, 2009
Derivatives in Cash Flow Hedging Relationships	Gain (Loss) Recognized in OCI on Derivatives1  (Effective Portion 2)			Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion 3)				Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion and Amount Excluded from Effectiveness Testing 3)
				Location				Location
Interest rate contracts:	$	(22,777	)	Interest expense	$	(29,052	)		$	--
Commodity contracts: Electric derivatives		(19,933	)	Electric generation fuel		(25,296	)	Net unrealized gain on derivative instruments		325
Electric derivatives		(6,289	)	Purchased electricity		(4,157	)	Net unrealized loss on derivative instruments		(2,897	)
Total	$	(48,999	)		$	(58,505	)		$	(2,572	)

___________

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

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

____________

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

The following table presents the effect of hedging instruments on PSE’s OCI and statements of income for the years ended December 31, 2010 and 2009:

Puget Sound Energy (Dollars in Thousands)	Year Ended December 31,
Derivatives in Cash Flow Hedging Relationships	Gain (Loss) Recognized in OCI on Derivatives 1 (Effective Portion 2)					Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion 3)							Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion and Amount Excluded from Effectiveness Testing 3)
	2010		2009			Location	2010			2009			Location	2010		2009
Interest rate contracts:	$	--	$	--		Interest expense	$	(488	)	$	(488	)		$	--	$	--
Commodity contracts: Electric derivatives:		575		(49,848	)	Electric generation fuel		(56,594	)		(117,524	)	Net unrealized gain on derivative instruments		--		--
Electric derivatives		--		(11,429	)	Purchased electricity		(17,207	)		(20,686	)	Net unrealized loss on derivative instruments		--		(2,749	)
Total	$	575	$	(61,277	)		$	(74,289	)	$	(138,698	)		$	--	$	(2,749	)

___________

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

For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings.  Gains and losses on the derivatives representing hedge ineffectiveness are recognized in current earnings.  Puget Energy expects that $28.6 million of losses in OCI will be reclassified into earnings within the next twelve months.  PSE expects that $33.4 million of losses in OCI will be reclassified into earnings within the next twelve months.  The maximum length of time over which Puget Energy and PSE are hedging their exposure to the variability in future cash flows extends to February 2015 for purchased electricity contracts and to October 2015 for gas for power generation contracts.  For Puget Energy interest rate swaps, the maximum length of forecasted transactions deferred in OCI extends to February 2014.

The following table presents the effect of Puget Energy’s derivatives not designated as hedging instruments on income during the years ended December 31, 2010 and 2009:

Puget Energy		Year Ended December 31,			Successor February 6, 2009 – December 31,			Predecessor January 1, 2009 – February 5,
(Dollars in Thousands)	Location	2010			2009			2009
Interest rate contracts:
	Other deductions	$	(7,955	)	$	--		$	--
	Interest expense		9,423			--			--
Commodity contracts:
Electric derivatives	Net unrealized gain (loss) on derivative instruments		(94,659	) 1		117,515	2		(2,881	) 3
	Electric generation fuel		(100,514	)		(88,185	)		(863	)
	Purchased electricity		(36,886	)		(56,498	)		(243	)
Total gain (loss) recognized in income on derivatives		$	(230,591	)	$	(27,168	)	$	(3,987	)

___________

1	Differs from the amount stated in the statements of income as it does not include $40.6 million of amortization expense related to contracts that were recorded at fair value at the time of the merger and subsequently designated as NPNS.
2	Differs from the amount stated in the statements of income as it does not include $41.7 million of amortization expense related to contracts that were recorded at fair value at the time of the merger and subsequently designated as NPNS and $(2.6) million related to hedge ineffectiveness.
3	Differs from the amount stated in the statements of income as it does not include $(1.0) million related to hedge ineffectiveness.

The following table presents the effect of PSE’s derivatives not designated as hedging instruments on income during the years ended December 31, 2010 and 2009:

Puget Sound Energy		Year Ended December 31,
(Dollars in Thousands)	Location	2010			2009
Commodity contracts:
Electric derivatives	Net unrealized gain (loss) on derivative instruments	$	(166,953	)	$	4,003	1
	Electric generation fuel		(100,514	)		(89,255	)
	Purchased electricity		(36,886	)		(40,770	)
Total gain (loss) recognized in income on derivatives		$	(304,353	)	$	(126,022	)

___________

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

The Company had the following outstanding contracts as of December 31, 2010:

Puget Energy at December 31, 2010	Number of Units
Derivatives not designated as hedging instruments:
Interest rate swaps	$1.483 billion
Gas derivatives 1	372,984,645 MMBtus
Electric generation fuel	104,055,000 MMBtus
Purchased electricity	9,630,725 MWhs

Puget Sound Energy at December 31, 2010	Number of Units
Derivatives not designated as hedging instruments:
Gas derivatives 1	372,984,645 MMBtus
Electric generation fuel	104,055,000 MMBtus
Purchased electricity	9,630,725 MWhs

__________

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

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

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

It is possible that volatility in energy commodity prices could cause the Company to have material credit risk exposure with one or more counterparties.  If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss.  However, as of December 31, 2010, approximately 99.9% of the Company’s energy portfolio exposure, excluding NPNS transactions, is with counterparties that are rated at least investment grade by the major rating agencies and 0.1% are either rated below investment grade or not rated by rating agencies.  The Company assesses credit risk internally for counterparties that are not rated.

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

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

The Company applies the counterparty’s default factor to compute credit reserves for counterparties that are in a net asset position.  Moreover, the Company applies its own default factor to compute credit reserves for counterparties that are in a net liability position.  Credit reserves are booked as contra accounts to unrealized gain (loss) positions.  As of December 31, 2010, the Company was in a net liability position with the majority of counterparties, so the default factors of counterparties did not have a significant impact on reserves for the year.  The majority of the Company’s derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council.  Despite its net liability position, PSE was not required to post any additional collateral with any of its counterparties.  Additionally, PSE did not trigger any collateral requirements with any of its counterparties nor were any of PSE’s counterparties required to post additional collateral resulting from credit rating downgrades.

As of December 31, 2010, the Company did not have any outstanding energy supply contracts with counterparties that contained credit risk related contingent features, which could result in a counterparty requesting immediate payment or demanding immediate and ongoing full overnight collateralization on derivative instruments in a net liability position.

The table below presents the fair value of the overall contractual contingent liability positions for the Company’s derivative activity at December 31, 2010:

Puget Energy and Puget Sound Energy Contingent Feature (Dollars in Thousands)	Fair Value 1 Liability			Posted Collateral		Contingent Collateral
Credit rating 2	$	(45,422	)	$	--	$	45,422
Requested credit for adequate assurance		(125,759	)		--		--
Forward value of contract 3		(17,585	)		--		--
Total	$	(188,766	)	$	--	$	45,422

__________

1	Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions at December 31, 2010.  Excludes NPNS, accounts payable and accounts receivable liability.
2	Failure by PSE to maintain an investment grade credit rating from each of the major credit rating’s agencies provides counterparties a contractual right to demand collateral.
3	Collateral requirements may vary, based on changes in forward value of underlying transactions relative to contractually defined collateral thresholds.

(14)  Fair Value Measurements

ASC 820 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 ASC 820 are as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date.  Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.  Level 1 primarily consists of financial instruments such as exchange-traded derivatives and listed equities.  Equity securities that are also classified as cash equivalents are considered Level 1 if there are unadjusted quoted prices in active markets for identical assets or liabilities.

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date.  Level 2 includes those financial instruments that are valued using models or other valuation methodologies.  These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures.  Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.  Instruments in this category include non-exchange-traded derivatives such as over-the-counter forwards and options.

Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources.  These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.  Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs.  At each balance sheet date, the Company performs an analysis of all instruments subject to ASC 820 and includes in Level 3 all of those instruments whose fair value is based on significant unobservable inputs.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  If a fair value measurement relies on inputs from different levels of the hierarchy, the entire measurement must be placed based on the lowest level input that is significant to the fair value measurement.  The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.  On a daily basis, the Company obtains quoted forward prices for the electric and natural gas market from an independent external pricing service.  Those forward price quotes are then used in addition to other various inputs to determine the reported fair value.  Some of the inputs include the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), assumptions for time value and also the impact of the Company’s  nonperformance risk on its liabilities.

As of December 31, 2010, the Company considered the markets for its electric and natural gas Level 2 derivative instruments to be actively traded.  Management’s assessment is based on the trading activity volume in real-time and forward electric and natural gas markets.  The Company regularly confirms the validity of pricing service quoted prices (e.g. Level 2 in the fair value hierarchy) used to value commodity contracts to the actual prices of commodity contracts entered into during the most recent quarter.

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

Puget Energy	Fair Value Measurement At December 31, 2010								Fair Value Measurement At December 31, 2009
(Dollars in Thousands)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	--	$	1,874	$	7,888	$	9,762	$	--	$	2,469	$	2,671	$	5,140
Gas derivative instruments		--		1,487		4,484		5,971		--		14,298		115		14,413
Cash equivalents		15,184		5,450		--		20,634		38,835		5,465		--		44,300
Restricted cash		3,246		--		--		3,246		3,305		--		--		3,305
Interest rate derivative instruments		--		--		--		--		--		20,854		--		20,854
Total assets	$	18,430	$	8,811	$	12,372	$	39,613	$	42,140	$	43,086	$	2,786	$	88,012
Liabilities:
Electric derivative instruments	$	--	$	147,257	$	95,324	$	242,581	$	--	$	51,099	$	99,000	$	150,099
Gas derivative instruments		--		147,308		8,343		155,651		--		77,438		4,119		81,557
Interest rate derivative instruments		--		58,003		--		58,003		--		26,844		--		26,844
Total liabilities	$	--	$	352,568	$	103,667	$	456,235	$	--	$	155,381	$	103,119	$	258,500

				Successor			Predecessor
Puget Energy Level 3 Roll-Forward Net (Liability) (Dollars in Thousands)	Year Ended December 31, 2010			February 6, 2009 - December 31, 2009			January 1, 2009 - February 5, 2009			Year Ended December 31, 2008
Balance at beginning of period	$	(100,333	)	$	(185,813	) 1	$	(132,256	)	$	(6,156	)
Changes during period:
Realized and unrealized energy derivatives
- included in earnings		(112,180	)		(14,832	)		(627	)		(2,935	)
- included in other comprehensive income		--			(17,429	)		(14,821	)		(110,439	)
- included in regulatory assets/liabilities		(2,665	)		(4,345	)		(1,410	)		(17,311	)
Purchases, issuances, and settlements		29,832			26,374			2,154			6,677
Transferred into Level 3		225			(8,611	)		--			--
Transferred out of Level 3 2		93,826			104,323			8,560			(2,092	)
Balance at end of period	$	(91,295	)	$	(100,333	)	$	(138,400	)	$	(132,256	)

_________________

1	The beginning balance for the Successor period was adjusted to reflect the impact of certain fair value adjustments from the merger transaction.
2	Transferred in/out of Level 3 for the Successor includes the cash equivalents of $1.4 million.  The cash equivalents became Level 2 during the second quarter 2009.

Puget Sound Energy	Fair Value measurement At December 31, 2010								Fair Value Measurement At December 31, 2009
(Dollars in Thousands)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	--	$	1,874	$	7,888	$	9,762	$	--	$	2,469	$	2,671	$	5,140
Gas derivative instruments		--		1,487		4,484		5,971		--		14,298		115		14,413
Cash equivalents		15,184		5,450		--		20,634		38,835		5,465		--		44,300
Restricted cash		3,246		--		--		3,246		3,305		--		--		3,305
Total assets	$	18,430	$	8,811	$	12,372	$	39,613	$	42,140	$	22,232	$	2,786	$	67,158
Liabilities:
Electric derivative instruments	$	--	$	147,257	$	95,324	$	242,581	$	--	$	46,690	$	99,000	$	145,690
Gas derivative instruments		--		147,308		8,343		155,651		--		77,438		4,119		81,557
Total liabilities	$	--	$	294,565	$	103,667	$	398,232	$	--	$	124,128	$	103,119	$	227,247

Puget Sound Energy  Level 3 Roll-Forward Net (Liability)	Year Ended December 31,
(Dollars in Thousands)	2010			2009			2008
Balance at beginning of period	$	(100,333	)	$	(132,256	)	$	(6,156	)
Changes during period:
Realized and unrealized energy derivatives
- included in earnings		(112,180	)		(776	)		(2,935	)
- included in other comprehensive income		--			(38,047	)		(110,439	)
- included in regulatory assets/liabilities		(2,665	)		(7,824	)		(17,311	)
Purchases, issuances, and settlements		29,832			28,779			6,677
Transferred into Level 3 1		225			(6,778	)		--
Transferred out of Level 3 1		93,826			56,569			(2,092	)
Balance at end of period	$	(91,295	)	$	(100,333	)	$	(132,256	)

_________________

1 The energy derivatives transferred in/out of Level 3 in 2009 includes the cash equivalents of $1.4 million. These cash equivalents became Level 2 during the second quarter 2009.

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

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

Certain energy derivative instruments are classified as Level 3 in the fair value hierarchy because Level 3 inputs are significant to their fair value measurement.  Energy derivatives transferred out of Level 3 represent existing assets or liabilities that were classified as Level 3 at the start of the reporting period for which the lowest significant input became observable during the current reporting period and were transferred into Level 2.  Conversely, energy derivatives transferred into Level 3 from Level 2 represent scenarios in which the lowest significant input became unobservable during the current reporting period.  The Company had no transfers between Level 2 and Level 1 during the year ended December 31, 2010 or 2009.

(15)  Employee Investment Plans

The Company has a qualified Employee Investment Plan under which employee salary deferrals and after-tax contributions are used to purchase several different investment fund options.  PSE’s contributions to the Employee Investment Plan were $11.8 million, $11.4 million and $10.0 million for the years 2010, 2009 and 2008, respectively.  The Employee Investment Plan eligibility requirements are set forth in the plan documents.

(16)  Retirement Benefits

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

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

The following tables summarize Puget Energy’s change in benefit obligation, change in plan assets, net periodic benefit cost and other changes in OCI for the years ended December 31, 2010 and 2009:

	Qualified Pension Benefits
Puget Energy	Successor						Predecessor
(Dollars in Thousands)	Year Ended December 31, 2010			February 6, 2009 – December 31, 2009			January 1, 2009 – February 5, 2009
Change in benefit obligation:
Benefit obligation at beginning of period	$	504,786		$	453,731		$	460,586
Service cost		16,089			12,469			1,090
Interest cost		27,975			25,912			2,302
Amendment		(21,866	)		--			--
Actuarial loss		32,163			33,458			--
Benefits paid		(26,532	)		(20,784	)		(2,517	)
Benefit obligation at end of period	$	532,615		$	504,786		$	461,461
Change in plan assets:
Fair value of plan assets at beginning of period	$	485,689		$	373,767		$	392,900
Actual return on plan assets		55,312			114,306			3,585
Employer contribution		12,000			18,400			--
Benefits paid		(26,532	)		(20,784	)		(2,517	)
Fair value of plan assets at end of period	$	526,469		$	485,689		$	393,968
Funded status at end of period	$	(6,146	)	$	(19,097	)	$	(67,493	)

	SERP Pension Benefits
Puget Energy	Successor						Predecessor
(Dollars in Thousands)	Year Ended December 31, 2010			February 6, 2009 – December 31, 2009			January 1, 2009 – February 5, 2009
Change in benefit obligation:
Benefit obligation at beginning of period	$	39,152		$	38,750		$	39,348
Service cost		1,024			951			89
Interest cost		2,165			2,178			193
Actuarial loss		3,663			1,433			--
Benefits paid		(1,682	)		(4,160	)		(532	)
Benefit obligation at end of period	$	44,322		$	39,152		$	39,098
Change in plan assets:
Fair value of plan assets at beginning of period	$	--		$	--		$	--
Employer contribution		1,682			4,160			532
Benefits paid		(1,682	)		(4,160	)		(532	)
Fair value of plan assets at end of period	$	--		$	--		$	--
Funded status at end of period	$	(44,322	)	$	(39,152	)	$	(39,098	)

	Other Benefits
Puget Energy	Successor						Predecessor
(Dollars in Thousands)	Year Ended December 31, 2010			February 6, 2009 – December 31, 2009			January 1, 2009 – February 5, 2009
Change in benefit obligation:
Benefit obligation at beginning of period	$	15,953		$	15,807		$	18,089
Service cost		106			114			11
Interest cost		880			894			89
Actuarial loss		867			770			--
Benefits paid		(2,030	)		(2,050	)		(147	)
Medicare part D subsidy received		803			418			139
Benefit obligation at end of period	$	16,579		$	15,953		$	18,181
Change in plan assets:
Fair value of plan assets at beginning of period	$	8,790		$	7,829		$	8,435
Actual return on plan assets		1,140			2,272			37
Employer contribution		388			739			82
Benefits paid		(2,030	)		(2,050	)		(147	)
Fair value of plan assets at end of period	$	8,288		$	8,790		$	8,407
Funded status at end of period	$	(8,291	)	$	(7,163	)	$	(9,774	)

Puget Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2010			2009			2010			2009			2010			2009
Amounts recognized in Statement of Financial Position consist of:
Current liabilities	$	--		$	--		$	(3,506	)	$	(2,978	)	$	(44	)	$	(39	)
Noncurrent liabilities		(6,146	)		(19,097	)		(40,816	)		(36,174	)		(8,247	)		(7,124	)
Total	$	(6,146	)	$	(19,097	)	$	(44,322	)	$	(39,152	)	$	(8,291	)	$	(7,163	)
Amounts recognized in Accumulated Other Comprehensive Income consist of:
Net loss (gain)	$	(43,544	)	$	(53,265	)	$	5,095		$	1,434		$	(820	)	$	(1,124	)
Prior service cost		(21,701	)		--			--			--			--			--
Total	$	(65,245	)	$	(53,265	)	$	5,095		$	1,434		$	(820	)	$	(1,124	)

	Qualified Pension Benefits
Puget Energy	Successor						Predecessor
(Dollars in Thousands)	Year Ended December 31, 2010			February 6, 2009 – December 31, 2009			January 1, 2009 – February 5, 2009
Components of net periodic benefit cost:
Service cost	$	16,089		$	12,469		$	1,090
Interest cost		27,975			25,912			2,302
Expected return on plan assets		(32,941	)		(27,583	)		(3,585	)
Amortization of prior service cost (credit)		(165	)		--			95
Amortization of net loss		70			--			269
Net periodic benefit cost	$	11,028		$	10,798		$	171

	SERP Pension Benefits
Puget Energy	Successor				Predecessor
(Dollars in Thousands)	Year Ended December 31, 2010		February 6, 2009 – December 31, 2009		January 1, 2009 – February 5, 2009
Components of net periodic benefit cost:
Service cost	$	1,024	$	951	$	89
Interest cost		2,165		2,178		193
Amortization of prior service cost		--		--		51
Amortization of net loss (gain)		--		--		74
Net periodic benefit cost	$	3,189	$	3,129	$	407

	Other Benefits
Puget Energy	Successor						Predecessor
(Dollars in Thousands)	Year Ended December 31, 2010			February 6, 2009 – December 31, 2009			January 1, 2009 – February 5, 2009
Components of net periodic benefit cost:
Service cost	$	106		$	114		$	11
Interest cost		880			894			89
Expected return on plan assets		(510	)		(379	)		(37	)
Amortization of prior service cost		--			--			7
Amortization of net loss (gain)		(67	)		--			(15	)
Amortization of transition obligation		--			--			4
Net periodic benefit cost	$	409		$	629		$	59

Puget Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
(Dollars in Thousands)	2010			2009			2010		2009		2010		2009
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)	$	9,791		$	(53,265	)	$	3,663	$	1,434	$	236	$	(1,124	)
Amortization of net loss (gain)		(70	)		--			--		--		67		--
Prior service credit		(21,866	)		--			--		--		--		--
Amortization of prior service credit		165			--			--		--		--		--
Total change in other comprehensive income for year	$	(11,980	)	$	(53,265	)	$	3,663	$	1,434	$	303	$	(1,124	)

The estimated net loss (gain) and prior service cost (credit) for the pension plans that will be amortized from accumulated OCI into net periodic benefit cost in 2011 are zero and $(2.0) million, respectively.  The estimated net loss (gain) and prior service cost (credit) for the SERP that will be amortized from accumulated OCI into net periodic benefit cost in 2011 are $0.4 million and zero, respectively.  The estimated net loss (gain), prior service cost (credit) and transition obligation (asset) for the other postretirement plans that will be amortized from accumulated OCI into net periodic benefit cost in 2011 are immaterial.

The following tables summarize PSE’s change in benefit obligation, change in plan assets, net periodic benefit cost and other changes in OCI for the years ended December 31, 2010 and 2009:

Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2010			2009			2010			2009			2010			2009
Change in benefit obligation:
Benefit obligation at beginning of period	$	504,786		$	460,586		$	39,152		$	39,348		$	15,953		$	18,088
Service cost		16,089			14,141			1,024			1,068			106			125
Interest cost		27,975			27,734			2,165			2,315			880			960
Amendment		(21,866	)		--			--			--			--			--
Actuarial loss (gain)		32,163			25,094			3,663			707			867			(1,296	)
Benefits paid		(26,532	)		(22,769	)		(1,682	)		(4,286	)		(2,030	)		(2,342	)
Medicare part D subsidiary received		--			--			--			--			803			418
Benefit obligation at end of period	$	532,615		$	504,786		$	44,322		$	39,152		$	16,579		$	15,953
Change in plan assets:
Fair value of plan assets at beginning of period	$	485,689		$	392,900		$	--		$	--		$	8,790		$	8,435
Actual return on plan assets		55,312			97,158			--			--			1,140			1,952
Employer contribution		12,000			18,400			1,682			4,286			388			745
Benefits paid		(26,532	)		(22,769	)		(1,682	)		(4,286	)		(2,030	)		(2,342	)
Fair value of plan assets at end of period	$	526,469		$	485,689		$	--		$	--		$	8,288		$	8,790
Funded status at end of period	$	(6,146	)	$	(19,097	)	$	(44,322	)	$	(39,152	)	$	(8,291	)	$	(7,163	)

Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2010			2009			2010			2009			2010			2009
Amounts recognized in Statement of Financial Position consist of:
Current liabilities	$	--		$	--		$	(3,506	)	$	(2,978	)	$	(44	)	$	(39	)
Noncurrent liabilities		(6,146	)		(19,097	)		(40,816	)		(36,174	)		(8,247	)		(7,124	)
Total	$	(6,146	)	$	(19,907	)	$	(44,322	)	$	(39,152	)	$	(8,291	)	$	(7,163	)
Amounts recognized in Accumulated Other Comprehensive Income consist of:
Net loss (gain)	$	187,240		$	173,822		$	11,770		$	8,876		$	(4,492	)	$	(5,281	)
Prior service cost		(17,245	)		5,170			867			1,430			134			267
Transition obligations		--			--			--			--			100			150
Total	$	169,995		$	178,992		$	12,637		$	10,306		$	(4,258	)	$	(4,864	)

Puget Sound Energy	Qualified Pension Benefits									SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2010			2009			2008			2010		2009		2008		2010			2009			2008
Components of net periodic benefit cost:
Service cost	$	16,089		$	14,141		$	12,750		$	1,024	$	1,068	$	935	$	106		$	125		$	128
Interest cost		27,975			27,734			26,685			2,165		2,315		2,211		880			960			1,130
Expected return on plan assets		(43,892	)		(43,453	)		(41,555	)		--		--		--		(509	)		(455	)		(789	)
Amortization of prior service cost		548			1,134			768			562		616		616		132			83			84
Amortization of net loss (gain)		7,325			3,702			945			769		886		732		(553	)		(460	)		(799	)
Amortization of transition obligation		--			--			--			--		--		--		50			50			50
Net periodic benefit cost (income)	$	8,045		$	3,258		$	(407	)	$	4,520	$	4,885	$	4,494	$	106		$	303		$	(196	)

Puget Sound Energy	Qualified Pension Benefit						SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2010			2009			2010			2009			2010			2009
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)	$	20,743		$	(28,610	)	$	3,663		$	707		$	236		$	(2,794	)
Amortization of net loss (gain)		(7,325	)		(3,702	)		(769	)		(886	)		553			461
Prior service cost (credit)		(21,867	)		--			--			--			--			--
Amortization of prior service cost		(546	)		(1,134	)		(562	)		(616	)		(132	)		(83	)
Amortization of transition (asset) obligation		--			--			--			--			(50	)		(50	)
Total change in other comprehensive income for year	$	(8,995	)	$	(33,446	)	$	2,332		$	(795	)	$	607		$	(2,466	)

The estimated net loss (gain) and prior service cost (credit) for the pension plans that will be amortized from accumulated OCI into net periodic benefit cost in 2011 are $10.8 million and $(1.6) million, respectively.  The estimated net loss (gain) and prior service cost (credit) for the SERP that will be amortized from accumulated OCI into net periodic benefit cost in 2011 are $1.2 million and $0.6 million, respectively.  The estimated net loss (gain), prior service cost (credit) and transition obligation (asset) for the other postretirement plans that will be amortized from accumulated OCI into net periodic benefit cost in 2011 total $(0.3) million.

The aggregate expected contributions by the Company to fund the retirement plan, SERP and the other postretirement plans for the year ending December 31, 2011 are expected to be at least $5.0 million, $3.5 million and $0.5 million, respectively.

As a result of the Patient Protection and Affordable Care Act of 2010, PSE recorded a one-time tax expense of $0.8 million during the three months ended March 31, 2010, related to a Medicare D subsidy that PSE receives.  These subsidies have been non-taxable in the past and will be subject to federal income taxes after 2012 as a result of the legislation.

As part of PSE’s new contract with the International Brotherhood of Electrical Workers (IBEW) Local 77 union, which took effect September 1, 2010, the benefit calculation formula has changed for Company employees covered by the contract.  IBEW represented employees hired after August 31, 2010 and employees not vested in a plan benefit as of July 31, 2010 participate in the cash balance formula of the retirement program, with any accrued benefit converted to a beginning cash balance account.  Employees who were vested in a plan benefit as of July 31, 2010 had a choice to convert to the cash balance formula or remain on a final average earnings formula based on qualified pay and years of service.  All employees accruing benefits under the cash balance formula receive the same investment plan match and Company contribution.  Effective December 1, 2010, the IBEW represented employees who accrue benefits under the cash balance formula receive a higher matching contribution and an additional Company contribution as compared to IBEW represented employees who are covered by the final average earnings formula.  These are the same formulas applied to non-union represented employees.  IBEW represented employees who were rehired after August 31, 2010, will accrue future benefits under the cash balance formula and will be able to elect to convert their prior benefits to the cash balance formula.  As a result of these changes to the IBEW contract, approximately 88.0% of the employees are in the cash balance formula and approximately 12.0% of the employees are in the final average earnings formula.

Assumptions

In accounting for pension and other benefit obligations and costs under the plans, the following weighted-average actuarial assumptions were used by the Company:

	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
Benefit Obligation Assumptions	2010		2009		2008		2010		2009		2008		2010		2009		2008
Discount rate 1	5.15	%	5.75	%	6.20	%	5.15	%	5.75	%	6.20	%	5.15	%	5.75	%	6.20	%
Rate of compensation increase	4.50	%	4.50	%	4.50	%	4.50	%	4.50	%	4.50	%	4.50	%	4.50	%	4.50	%
Medical trend rate	--		--		--		--		--		--		8.00	%	7.50	%	8.00	%
Benefit Cost Assumptions
Discount rate	5.75	%	6.50	% 2	6.30	%	5.75	%	6.50	% 2	6.30	%	5.75	%	6.50	% 2	6.30	%
Rate of plan assets	8.00	%	8.25	%	8.25	%	--		--		--		7.80	%	7.60	%	--
Rate of compensation increase	4.50	%	4.50	%	4.50	%	4.50	%	4.50	%	4.50	%	4.50	%	4.50	%	4.50	%
Medical trend rate	--		--		--		--		--		--		8.50	%	9.00	%	9.00	%

_______________

1	The Company calculates the present value of the pension liability using a discount rate of 5.15% which represents the single-rate equivalent of the AA rated corporate bond yield curve.
2	6.50% is the benefit cost discount rate used by Puget Energy.  6.20% is the benefit cost discount rate use by PSE.  The discount rates for the net periodic costs for Puget Energy and PSE were different because of the discount rates in effect as of February 5, 2009, and December 31, 2008, respectively.

The assumed medical inflation rate used to determine benefit obligations is 8.0% in 2011 grading down to 4.90% in 2012.  A 1.0% change in the assumed medical inflation rate would have the following effects:

	2010		2009
(Dollars in Thousands)	1% Increase	1% Decrease	1% Increase	1% Decrease
Effect on post-retirement benefit obligation	$ 97	$ 85	$ 131	$ 119
Effect on service and interest cost components	6	5	7	6

The Company has selected the expected return on plan assets based on a historical analysis of rates of return and the Company’s investment mix, market conditions, inflation and other factors.  The expected rate of return is reviewed annually based on these factors.  The Company’s accounting policy for calculating the market-related value of assets for the Company’s retirement plan is as follows.  PSE market-related value of assets is based on a five-year smoothing of asset gains/losses measured from the expected return on market-related assets.  This is a calculated value that recognizes changes in fair value in a systematic and rational manner over five years.  The same manner of calculating market-related value is used for all classes of assets, and is applied consistently from year to year.

Puget Energy’s pension and other postretirement benefits income or costs depend on several factors and assumptions, including plan design, timing and amount of cash contributions to the plan, earnings on plan assets, discount rate, expected long-term rate of return, mortality and health care costs trends.  Changes in any of these factors or assumptions will affect the amount of income or expense that Puget Energy records in its financial statements in future years and its projected benefit obligation.  Puget Energy has selected an expected return on plan assets based on a historical analysis of rates of return and Puget Energy’s investment mix, market conditions, inflation and other factors.  As required by merger accounting rules, market-related value was reset to market value effective with the merger.

The discount rates were determined by using market interest rate data and the weighted-average discount rate from Citigroup Pension Liability Index Curve.  The Company also takes into account in determining the discount rate the expected changes in market interest rates and anticipated changes in the duration of the plan liabilities.

The aggregate expected contributions and payments by the Company to fund the retirement plan, SERP and the other postretirement plans for the year ending December 31, 2011 are expected to be at least $5.0 million, $3.5 million and $0.5 million, respectively.

Plan Benefits

The expected total benefits to be paid under the qualified pension plans for the next five years and the aggregate total to be paid for the five years thereafter are as follows:

(Dollars in Thousands)	2011	2012	2013	2014	2015	2016-2020
Total benefits	$ 35,400	$ 37,500	$ 38,100	$ 37,900	$ 38,700	$ 204,700

The expected total benefits to be paid under the SERP for the next five years and the aggregate total to be paid for the five years thereafter are as follows:

(Dollars in Thousands)	2011	2012	2013	2014	2015	2016-2020
Total benefits	$  3,506	$  2,971	$  3,857	$  3,238	$ 3,159	$   17,916

The expected total benefits to be paid under the other benefits for the next five years and the aggregate total to be paid for the five years thereafter are as follows:

(Dollars in Thousands)	2011	2012	2013	2014	2015	2016-2020
Total benefits	$ 1,457	$ 1,432	$ 1,366	$ 1,299	$ 1,223	$ 6,319
Total benefits without Medicare Part D subsidy	$ 1,861	$ 1,861	$ 1,823	$ 1,782	$ 1,727	$ 7,735

Plan Assets

Plan contributions and the actuarial present value of accumulated plan benefits are prepared based on certain assumptions pertaining to interest rates, inflation rates and employee demographics, all of which are subject to change.  Due to uncertainties inherent in the estimations and assumptions process, changes in these estimates and assumptions in the near term may be material to the financial statements.

The Company has a Retirement Plan Committee that establishes investment policies, objectives and strategies designed to balance expected return with a prudent level of risk.  All changes to the investment policies are reviewed and approved by the Retirement Plan Committee prior to being implemented.

The Retirement Plan Committee invests trust assets with investment managers who have historically achieved above-median long-term investment performance within the risk and asset allocation limits that have been established.  Interim evaluations are routinely performed with the assistance of an outside investment consultant.  To obtain the desired return needed to fund the pension benefit plans, the Retirement Plan Committee has established investment allocation percentages by asset classes as follows:

	Allocation
Asset Class	Minimum	Target	Maximum
Domestic large cap equity	25%	32%	40%
Domestic small cap equity	0%	10%	15%
Non-U.S. equity	10%	20%	30%
Tactical asset allocation	0%	5%	10%
Fixed income	15%	23%	30%
Real estate	0%	0%	10%
Absolute return	5%	10%	15%
Cash	0%	0%	5%

Plan Fair Value Measurements

Effective December 31, 2009, ASC 715 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.

In September 2009, the FASB issued ASU 2009-12, “Fair Value Measurements and Disclosures: Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent).”  The standard allows the reporting entity, as a practical expedient, to measure the fair value of investments that do not have readily determinable fair values on the basis of the net asset value per share of the investment if the net asset value of the investment is calculated in a matter consistent with ASC 946, “Financial Services – Investment Companies.”  The standard requires disclosures about the nature and risk of the investments and whether the investments are probable of being sold at amounts different from the net asset value per share.

The following table sets forth by level, within the fair value hierarchy, the qualified pension plan assets at fair value that were accounted for at fair value on a recurring basis as of December 31, 2010 and 2009:

	Recurring Fair Value Measures As of December 31, 2010								Recurring Fair Value Measures As of December 31, 2009
(Dollars in Thousands)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets:
Equities:
Non-US equity 1	$	54,298	$	52,418	$	--	$	106,716	$	50,890	$	48,062	$	--	$	98,952
Domestic large cap equity 2		144,431		28,376		--		172,807		134,754		24,641		--		159,395
Domestic small cap equity 3		55,750		--		--		55,750		49,513		--		--		49,513
Total equities		254,479		80,794		--		335,273		235,157		72,703		--		307,860
Tactical asset allocation 4		--		29,566		--		29,566		--		25,469		--		25,469
Fixed income securities 5		102,314		1,982		--		104,296		43,244		51,244		--		94,488
Absolute return 6		--		--		48,100		48,100		--		--		46,226		46,226
Cash and cash equivalents 7		--		6,737		--		6,737		--		9,588		--		9,588
Subtotal	$	356,793	$	119,079	$	48,100	$	523,972	$	278,401	$	159,004	$	46,226	$	483,631
Net receivables								2,272								1,629
Accrued income								225								429
Total assets							$	526,469							$	485,689

_________________

1	Non – US Equity investments are comprised of a (1) mutual fund; and (2) commingled fund.  The investment in the mutual fund is valued using quoted market prices multiplied by the number of shares owned as of December 31, 2010.  The investment in the commingled fund is valued at the net asset value per share multiplied by the number of shares held as of December 31, 2010.
2	Domestic large cap equity investments are comprised of (1) common stock, and (2) commingled fund.  Investments in common stock are valued using quoted market prices multiplied by the number of shares owned as of December 31, 2010.  The investment in the commingled fund is valued at the net asset value per share multiplied by the number of shares held as of December 31, 2010.
3	Domestic small cap equity investments are comprised of common stock and are valued using quoted market prices multiplied by the number of shares owned as of December 31, 2010.
4	The tactical asset allocation investment are compromised of a commingled fund, which is valued at the net asset value per share multiplied by the number of shares held as of the measurement date.
5	Fixed income securities consist of a mutual fund, convertible securities, corporate bonds, and mortgage backed mortgage pools guaranteed by GNMA, FNMA and FHLMC.  The investment in the mutual fund is valued using quoted market prices multiplied by the number of shares owned as of December 31, 2010.  The other investments are valued using various valuation techniques and sources such as value generation models, broker quotes, benchmark yields and/or other applicable data.
6	Absolute return investments consist of a mutual fund and two partnerships.  The mutual fund is valued using the net asset value per share multiplied by the number of shares held as of December 31, 2010.  The partnership is valued using the financial reports as of December 31, 2010.  These investments are a Level 3 under ASC 820 because the plan does not have the ability to redeem the investment in the near-term at the net asset value per share.
7	The investment consists of a money market fund, which is valued at the net asset value per share of $1.00 per unit as of December 31, 2010.  The money market fund invests primarily in commercial paper, notes, repurchase agreements, and other evidences of indebtedness which are payable on demand or which have a maturity date not exceeding thirteen months from the date or purchase.

Level 3 Roll-Forward

The following table sets forth a reconciliation of changes in the fair value of the plan’s Level 3 assets for the years ended December, 31, 2010 and 2009:

	As of December 31, 2010								As of December 31, 2009
(Dollars in Thousands)	Partnership		Mutual Funds			total			Partnership		Mutual Funds		Total
Balance at beginning of year	$	23,214	$	23,012		$	46,226		$	20,514	$	19,137	$	39,651
Additional investments		10,473		--			10,473			--		--		--
Distributions		--		(11,716	)		(11,716	)		--		--		--
Realized losses on distributions		--		(1,370	)		(1,370	)		--		--		--
Unrealized gains relating to instruments still held at the reporting date		1,794		2,693			4,487			2,700		3,875		6,575
Balance at end of year	$	35,481	$	12,619		$	48,100		$	23,214	$	23,012	$	46,226

The following table sets forth by level, within the fair value hierarchy, the Other Benefits plan assets at fair value as of December 31, 2010 and 2009:

	Recurring Fair Value Measures as of December 31, 2010						Recurring Fair Value Measures as of December 31, 2009
(Dollars in Thousands)	Level 1		Level 2		Total		Level 1		Level 2		Total
Assets:
Mutual fund 1	$	8,115	$	--	$	8,115	$	8,321	$	--	$	8,321
Cash equivalents 2		--		173		173		--		469		469
Total assets	$	8,115	$	173	$	8,288	$	8,321	$	469	$	8,790

_______________

1

This is a publicly traded balanced mutual fund.  The fund seeks regular income, conservation of principal, and an opportunity for long-term growth of principal and income.  The fair value is determined by taking the number of shares owned by the plan, and multiplying by the market price as of December 31, 2010.

2

This consists of a deposit fund and a money market fund.  The fair value of the deposit fund is calculated by using the financial reports available as of December 31, 2010.  The money market fund investments are valued at the net asset value per share of $1.00 per unit as of December 31, 2010.  The money market fund invests primarily in commercial paper, notes, repurchase agreements, and other evidences of indebtedness which are payable on demand or which have a maturity date not exceeding thirteen months from the date or purchase.

(17)  Stock-based Compensation Plans

Prior to the merger on February 6, 2009, the Company granted equity awards, including stock awards, performance awards, stock options and restricted stock to officers and key employees of the Company under the Company’s Long-Term Incentive Plan (LTI Plan), approved by the shareholders in 2005.  Any shares awarded were either purchased on the open market or were a new issuance.  With the completion of the merger, all shares outstanding under the LTI Plan were fully vested and settled in cash to plan participants.  Puget Energy paid and recognized $14.5 million of merger expense in connection to the vesting of the LTI Plan shares.

Performance Share Grants

The Company generally awarded performance share grants annually under the LTI Plan to key employees which vested at the end of three years.  The number of shares awarded and the amount of expense recorded depended on Puget Energy’s performance as compared to other companies and service quality indices for customer service.  Compensation expense related to performance share grants was $9.6 million and $3.7 million for 2009 and 2008, respectively.  The weighted-average fair value per performance share granted for the year ended 2008 was $26.72.

Performance shares activity from December 31, 2008 to February 5, 2009 was as follows:

Predecessor	Number of Shares		Weighted-Average Fair Value Per Share
Total at December 31, 2008:	244,390		$	25.65
Granted	--			--
Vested	(244,390	)		25.65
Forfeited	--			--
Performance Shares Outstanding at February 5, 2009:	--		$	--

Plan participants meeting the Company’s stock ownership guidelines could elect to be paid up to 50.0% of the share award in cash.  The portion of the performance share grants that could be paid in cash was classified and accounted for as a liability.  As a result, the compensation expense of these liability awards was recognized over the performance period based on the fair value (i.e., cash value) of the award, and was periodically updated based on expected ultimate cash payout.  Compensation cost recognized during the performance period for the liability portion of the performance grants was based on the closing price of the Company’s common stock on the date of measurement and the number of months of service rendered during the period.  The equity portion was valued based on the closing price of the Company’s common stock on the grant date.  In connection with the completion of the merger in 2009, all performance shares vested and the Company paid and recognized $9.6 million recorded in merger and related costs for such shares.

Stock Options

In 2002, Puget Energy’s Board of Directors granted 40,000 stock options under the LTI Plan and an additional 260,000 options outside the LTI Plan (for a total of 300,000 non-qualified stock options) to the former President and Chief Executive Officer.  These options could be exercised at the grant date market price of $22.51 per share and vested annually over four and five years, respectively.  The fair value of the stock option award was estimated at $3.33 per share on the date of grant using the Black-Scholes option valuation model.  The options were cancelled at the time of the merger and $2.3 million was paid in cash to the former President and Chief Executive Officer based on the terms of the merger agreement.

Restricted Stock

Restricted stock activity for the year ended December 31, 2009 was as follows:

Predecessor	Number of Shares		Weighted-Average Fair Value Per Share
Restricted Stock Outstanding at December 31, 2008:	227,643		$	24.64
Granted	--			--
Vested	(227,643	)		24.64
Forfeited	--			--
Restricted Stock Outstanding at February 5, 2009:	--		$	--

Compensation expense related to the restricted shares was $2.2 million and $2.4 million for 2009 and 2008, respectively.

Retirement Equivalent Stock

Prior to the merger on February 6, 2009, the Company had a retirement equivalent stock agreement under which in lieu of participating in the Company’s SERP, the former President and Chief Executive Officer was granted performance-based stock equivalents in January of each year, which were deferred under the Company’s deferred compensation plan.  Retirement equivalent stock activity was as follows:

	Number of Shares	Weighted -Average Fair Value Per Share
Retirement Equivalent Stock Awarded:
2008	7,574	$	27.43

All shares vested in May 2008.  Compensation expense related to the retirement equivalent stock agreement was $0.3 million in 2008.  All equivalent stock units vested prior to the merger.

Non-Employee Director Stock Plan

Prior to February 6, 2009,  the Company had a non-employee director stock plan for all non-employee directors of Puget Energy and PSE.  An amended and restated plan was approved by shareholders in 2005.  Under the plan, non-employee directors received a portion of their quarterly retainer fees in Puget Energy stock except that 100.0% of quarterly retainers were paid in Puget Energy stock until the director held a number of shares equal in value to two years of their retainer fees.  Directors could choose to continue to receive their entire retainer in Puget Energy stock.  The compensation expense related to the director stock plan was $0.4 million and $0.7 million in 2009 and 2008, respectively.  As of December 31, 2008, the number of shares that had been purchased for the director stock plan was 62,362 and the number of shares deferred was 121,253, for a total of 183,615 shares.  The director stock plan was terminated on February 6, 2009 by action of the Board of Directors upon completion of the merger and outstanding shares thereunder were settled.

(18)  Income Taxes

The details of income tax (benefit) expense are as follows:

				Successor			Predecessor
Puget Energy (Dollars in Thousands)	Year Ended December 31, 2010			February 6, 2009 – December 31, 2009			January 1, 2009 – February 5, 2009			Year Ended December 31, 2008
Charged to operating expenses:
Current:
Federal	$	42,061		$	(161,087	)	$	10,185		$	(16,625	)
State		385			(988	)		87			(85	)
Deferred:
Federal		(38,717	)		244,116			(1,275	)		76,616
State		(1,248	)		--			--			--
Total income tax expense	$	2,481		$	82,041		$	8,997		$	59,906

Puget Sound Energy	Year Ended December 31,
(Dollars in Thousands)	2010			2009			2008
Charged to operating expenses:
Current:
Federal	$	32,331		$	(126,156	)	$	(13,103	)
State		385			(901	)		(85	)
Deferred:
Federal		(31,346	)		194,701			74,070
State		(1,248	)		--			--
Total income tax expense	$	122		$	67,644		$	60,882

The following reconciliation compares pre-tax book income at the federal statutory rate of 35.0% to the actual income tax expense in the Statements of Income:

				Successor			Predecessor
Puget Energy (Dollars in Thousands)	Year Ended December 31, 2010			February 6, 2009 – December 31, 2009			January 1, 2009 – February 5, 2009			Year Ended December 31, 2008
Income taxes at the statutory rate	$	11,477		$	89,620		$	7,613		$	75,069
Increase (decrease):
Production tax credit		(19,972	)		(13,871	)		(5,870	)		(23,112	)
AFUDC excluded from taxable income		(9,970	)		(5,326	)		(1,771	)		(4,670	)
Capitalized interest		8,244			5,028			914			3,653
Utility plant differences		6,162			4,323			1,472			5,882
Tenaska gas contract		5,889			3,049			1,429			3,198
Transaction costs		--			201			5,544			2,266
Other - net		651			(983	)		(334	)		(2,380	)
Total income tax expense	$	2,481		$	82,041		$	8,997		$	59,906
Effective tax rate		7.6	%		32.0	%		41.4	%		27.9	%

Puget Sound Energy	Year Ended December 31,
(Dollars in Thousands)	2010			2009			2008
Income taxes at the statutory rate	$	9,176		$	79,414		$	78,266
Increase (decrease):
Production tax credit		(19,972	)		(19,741	)		(23,112	)
AFUDC excluded from taxable income		(9,970	)		(7,097	)		(4,670	)
Capitalized interest		8,244			5,942			3,653
Utility plant differences		6,162			5,795			5,882
Tenaska gas contract		5,889			4,478			3,198
Other - net		593			(1,147	)		(2,335	)
Total income tax expense	$	122		$	67,644		$	60,882
Effective tax rate		0.5	%		29.8	%		27.2	%

The Company’s deferred tax liability at December 31, 2010 and 2009 is composed of amounts related to the following types of temporary differences:

Puget Energy	At December 31
(Dollars in Thousands)	2010			2009
Utility plant and equipment	$	1,099,857		$	930,946
Regulatory asset for income taxes		73,337			89,303
Fair value of debt instruments		92,661			86,047
Pensions and other compensation		46,084			42,395
Storm damage		36,286			37,002
Other deferred tax liabilities		106,714			85,797
Subtotal deferred tax liabilities		1,454,939			1,271,490
Net operating loss carryfoward		(168,463	)		--
Fair value of derivative instruments		(116,320	)		(75,964	)
Production tax credit		(60,613	)		(45,730	)
Other deferred tax assets		(65,018	)		(42,106	)
Subtotal deferred tax assets		(410,414	)		(163,800	)
Total	$	1,044,525		$	1,107,690

Puget Sound Energy	At December 31
(Dollars In Thousands)	2010			2009
Utility plant and equipment	$	1,099,857		$	930,946
Regulatory asset for income taxes		73,337			89,303
Storm damage		36,286			37,002
Other deferred tax liabilities		85,206			77,917
Subtotal deferred tax liabilities		1,294,686			1,135,168
Net operating loss carryforward		(105,140	)		--
Fair value of derivative instruments		(85,394	)		(53,271	)
Production tax credit		(60,613	)		(45,730	)
Pensions and other compensation		(31,312	)		(35,290	)
Other deferred tax assets		(57,925	)		(43,082	)
Subtotal deferred tax assets		(340,384	)		(177,373	)
Total	$	954,302		$	957,795

The above amounts have been classified in the Balance Sheets as follows:

Puget Energy	At December 31
(Dollars in Thousands)	2010			2009
Current deferred taxes	$	(83,086	)	$	(39,977	)
Non-current deferred taxes		1,127,611			1,147,667
Total	$	1,044,525		$	1,107,690

Puget Sound Energy	At December 31
(Dollars in Thousands)	2010			2009
Current deferred taxes	$	(80,215	)	$	(38,781	)
Non-current deferred taxes		1,034,517			996,576
Total	$	954,302		$	957,795

The Company calculates its deferred tax assets and liabilities under ASC 740.  ASC 740 requires recording deferred tax balances, at the currently enacted tax rate, on assets and liabilities that are reported differently for income tax purposes than for financial reporting purposes.  The utilization of deferred tax assets requires sufficient taxable income in the future years.  ASC 740 requires a valuation allowance on deferred tax assets when it is more likely than not that the deferred tax asset will not be realized.  The Company’s PTC carryforwards expire from 2027 through 2030.  The Company’s net operating loss carryforwards expire from 2029 through 2030.

For ratemaking purposes, deferred taxes are not provided for certain temporary differences.  PSE has established a regulatory asset for income taxes recoverable through future rates related to those temporary differences for which no deferred taxes have been provided, based on prior and expected future ratemaking treatment.

The Company accounts for uncertain tax position under ASC 740, which clarifies the accounting for uncertainty in income taxes recognized in the financial statements.  ASC 740 requires the use of a two-step approach for recognizing and measuring tax positions taken or expected to be taken in a tax return.  First, a tax position should only be recognized when it is more likely than not, based on technical merits, that the position will be sustained upon examination by the taxing authority.  Second, a tax position that meets the recognition threshold should be measured at the largest amount that has a greater than 50.0% likelihood of being sustained.

As of December 31, 2010 and 2009, the Company had no material unrecognized tax benefits.  As a result, no interest or penalties were accrued for unrecognized tax benefits during the year.

For ASC 740 purposes, the Company has open tax years from 2006 through 2010.  The Company is under audit by the IRS for tax years 2006 and 2008.  The Company classifies interest as interest expense and penalties as other expense in the financial statements.

(19)  Litigation

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.

Pacific Northwest Refund Proceeding.In October 2000, PSE filed a complaint with the FERC (Docket No. EL01-10) against “all jurisdictional sellers” in the Pacific Northwest seeking prospective price caps consistent with any result the FERC ordered for the California markets.  The FERC issued an order including price caps in July 2001, and PSE moved to dismiss the proceeding.  In response to PSE’s motion, various entities intervened and sought to convert PSE’s complaint into one seeking retroactive refunds in the Pacific Northwest.  The FERC rejected that effort, after holding what the FERC referred to as a “preliminary evidentiary hearing” before an administrative law judge.In April 2009, the Ninth Circuit rejected the requests for rehearing filed in this matter and remanded the proceeding to the FERC.  The FERC is now considering what response to take to the Court remand order, as petitions for review by the Supreme Court were denied on January 11, 2010.  PSE intends to vigorously defend its position but is unable to predict the outcome of this matter.

Proceedings Relating to Colstrip

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

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

Proceedings Related to Bonneville Power Administration

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

On May 3, 2007, the Ninth Circuit issued an opinion in Portland Gen. Elec. v. BPA, Case No. 01-70003, in which proceeding the actions of the BPA in entering into settlement agreements regarding the REP with PSE and with other investor-owned utilities were challenged.  In this opinion, the Ninth Circuit granted petitions for review and held the settlement agreements entered into between the BPA and the investor-owned utilities being challenged in that proceeding to be inconsistent with statute.  On May 3, 2007, the Ninth Circuit also issued an opinion in Golden Northwest Aluminum v. BPA, Case No. 03-73426, in which proceeding the petitioners sought review of BPA’s 2002-2006 power rates.  In this opinion, the Ninth Circuit granted petitions for review and held that the BPA unlawfully shifted onto its preference customers the costs of its settlements with the investor-owned utilities.  On October 11, 2007, the Ninth Circuit remanded the May 2004 agreement to the BPA in light of the Portland Gen. Elec. v. BPA opinion and dismissed the remaining three pending cases regarding settlement agreements.

In March 2008, the BPA and PSE signed an agreement pursuant to which BPA made a payment to PSE related to the REP benefits for the fiscal year ended September 30, 2008, which payment is subject to true-up depending upon the amount of any REP benefits ultimately determined to be payable to PSE.

In September 2008, the BPA issued its record of decision in its reopened WP-07 rate proceeding to respond to the various Ninth Circuit opinions.  In this record of decision, the BPA adjusted its fiscal year 2009 rates, determined the amounts of REP benefits it considered to have been improperly paid after fiscal year 2001 to PSE and the other regional investor-owned utilities, and determined that such amounts are to be recovered through reductions in REP benefit payments to be made over a number of years.  The amount determined by the BPA to be recovered through reductions commencing October 2007 in REP payments for PSE’s residential and small farm customers was approximately $207.2 million plus interest on unrecovered amounts to the extent that PSE receives any REP benefits for its customers in the future.  However, these BPA determinations are subject to subsequent administrative and judicial review, which may alter or reverse such determinations.  PSE and others, including a number of preference agency and investor-owned utility customers of the BPA, in December 2008 filed petitions for review in the Ninth Circuit of various of these BPA determinations.  Any change to the REP would be passed to customers.

In September 2008, the BPA and PSE signed a short-term Residential Purchase and Sale Agreement (RPSA) under which the BPA is to pay REP benefits to PSE for fiscal years ending September 30, 2009–2011.  In December 2008, the BPA and PSE signed another, long-term RPSA under which the BPA is to pay REP benefits to PSE for the period October 2011 through September 2028.  PSE and other customers of BPA in December 2008 filed petitions for review in the Ninth Circuit of the short-term and long-term RPSAs signed by PSE (and similar RPSAs signed by other investor-owned utility customers of the BPA) and the BPA’s record of decision regarding such RPSAs.  Generally, REP benefit payments under a RPSA are based on the amount, if any, by which a utility's average system cost exceeds the BPA’s Priority Firm (PF) Exchange rate for such utility.  The average system cost for a utility is determined using an average system cost methodology adopted by the BPA.  The average system cost methodology adopted by the BPA and the average system cost determinations, REP overpayment determinations, and the PF Exchange rate determinations by the BPA are all subject to FERC review or judicial review or both and are subject to adjustment, which may affect the amount of REP benefits paid or to be paid by the BPA to PSE.  As discussed above, the BPA has determined to reduce such payments based on its determination of REP benefit overpayments after fiscal year 2001.

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

Snoqualmie Falls

On July 7, 2010, a lawsuit was filed in the U.S. District Court for the Western District of Washington by the Snoqualmie Valley Preservation Alliance, a group of downstream landowners, against the United States Army Corps of Engineers (Corps) challenging permits issued by the Corps in connection with the redevelopment of the Snoqualmie Falls Hydroelectric Project.  Plaintiffs request an order to stop work at the project pending further review of downstream impacts.  PSE sought and was granted permission to intervene in the proceeding.  Motions for summary judgment have been filed by the plaintiff and the Corps.  PSE joined the Corps’ motion and filed a motion for summary judgment arguing the plaintiff’s claims are barred as untimely and improper.  The parties await a determination by the Court.  The ultimate impact of the suit, if any, on PSE or the work currently underway on the project cannot be determined at this time.  The construction schedule has not been impacted by the lawsuit.

(20)Variable Interest Entities

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

The Company evaluated its power purchase agreements and determined it was not the primary beneficiary of any VIEs.  The Company had previously disclosed two potentially significant variable interests in prior periods; both entities are qualifying facilities contracts that expire at the end of 2011.  The Company requested information from the relevant entities; however, they have refused to provide the necessary information to the Company, as they are not required to do so under their contracts.  However, if the variable interests were determined to be VIEs, the Company has concluded it is not the primary beneficiary of these entities based on available information and it has no exposure to losses on these contracts.  For the years ended December 31, 2010, 2009 and 2008, the Company’s purchased power expense for these entities was $190.3  million, $181.2  million and $196.8 million, respectively.

(21)  Commitments and Contingencies

For the year ended December 31, 2010, approximately 19.2% of the Company’s energy output was obtained at an average cost of approximately $0.018 per kilowatt hour (kWh) through long-term contracts with three of the Washington Public Utility Districts (PUDs) that own hydroelectric projects on the Columbia River.  The purchase of power from the Columbia River projects is on a pro rata share basis under which the Company pays a proportionate share of the annual debt service, operating and maintenance costs and other expenses associated with each project in proportion to the contractual shares that PSE obtains from that project.  In these instances, PSE’s payments are not contingent upon the projects being operable; therefore, PSE is required to make the payments even if power is not delivered.  These projects are financed through substantially level debt service payments and their annual costs should not vary significantly over the term of the contracts unless additional financing is required to meet the costs of major maintenance, repairs or replacements, or license requirements.  The Company’s share of the costs and the output of the projects is subject to reduction due to various withdrawal rights of the PUDs and others over the contract lives.

The following table summarizes the Company’s estimated payment obligations for power purchases from the Columbia River projects, contracts with other utilities and contracts under non-utility generators under the Public Utility Regulatory Policies Act.  These contracts have varying terms and may include escalation and termination provisions.

(Dollars in Thousands)	2011		2012		2013		2014		2015		Thereafter		Total
Columbia River projects	$	110,054	$	73,390	$	70,364	$	72,543	$	72,895	$	820,167	$	1,219,413
Other utilities		140,830		131,783		71,984		53,042		45,331		297,649		740,619
Non-utility generators		149,195		--		--		--		--		--		149,195
Total	$	400,079	$	205,173	$	142,348	$	125,585	$	118,226	$	1,117,816	$	2,109,227

Total purchased power contracts provided the Company with approximately 8.2 million, 8.3 million and 8.7 million megawatt hours (MWh) of firm energy at a cost of approximately $420.6 million, $363.3 million and $384.0 million for the years 2010, 2009 and 2008, respectively.

As part of its electric operations and in connection with the 1997 restructuring of the Tenaska Power Purchase Agreement, PSE is obligated to deliver to Tenaska up to 50,000 MMBtu (one million British thermal units, equal to one Dekatherm (Dth)) per day of natural gas for operation of Tenaska’s natural gas-fired cogeneration facility. This obligation continues for the remaining term of the agreement, through December 31, 2011, provided that no deliveries are required during the month of May. The price paid by Tenaska for this natural gas is reflective of the daily price of natural gas at the United States/Canada border near Sumas, Washington.

The Company has natural gas-fired generation facility obligations for natural gas supply amounting to an estimated $65.5 million in 2011.  Longer term agreements for natural gas supply amount to an estimated $137.2 million for 2012 through 2029.

PSE enters into short-term energy supply contracts to meet its core customer needs.  These contracts are generally classified as NPNS or in some cases recorded at fair value in accordance with ASC 815.  Commitments under these contracts are $86.0 million, $51.4 million and $9.3 million in 2011, 2012 and 2013, respectively.

Natural Gas Supply Obligations

The Company has also entered into various firm supply, transportation and storage service contracts in order to ensure adequate availability of natural gas supply for its firm customers.  Many of these contracts, which have remaining terms from less than one year to 34 years, provide that the Company must pay a fixed demand charge each month, regardless of actual usage.  The Company contracts for its long-term natural gas supply on a firm basis, which means the Company has a 100% daily take obligation and the supplier has a 100% daily delivery obligation to ensure service to PSE’s customers and generation requirements.  The Company incurred demand charges in 2010 for firm natural gas supply, firm transportation service and firm storage and peaking service of $0.4 million, $136.5 million and $7.1 million, respectively.  The Company incurred demand charges in 2010 for firm transportation and firm storage service for the natural gas supply for its combustion turbines in the amount of $27.7 million, which is included in the total Company demand charges.

The following table summarizes the Company’s obligations for future demand charges through the primary terms of its existing contracts.  The quantified obligations are based on current contract prices and the FERC authorized rates, which are subject to change.

Demand Charge Obligations (Dollars in Thousands)	2011		2012		2013		2014		2015		Thereafter		Total
Firm transportation service	$	144,529	$	137,305	$	128,759	$	104,790	$	62,667	$	328,864	$	906,914
Firm storage service		9,241		8,638		2,997		1,507		1,507		7,077		30,967
Firm natural gas supply		553		525		262		--		--		--		1,340
Total	$	154,323	$	146,468	$	132,018	$	106,297	$	64,174	$	335,941	$	939,221

Service Contracts

The following table summarizes the Company’s estimated obligations for service contracts through the terms of its existing contracts.

Service Contract Obligations (Dollars in Thousands)	2011		2012		2013		2014		2015		Thereafter		Total
Automated meter reading system	$	35,261	$	36,166	$	37,234	$	38,344	$	39,501	$	10,176	$	196,682
Energy production service contracts 1		23,477		18,994		19,360		20,124		26,730		49,948		158,633
Information technology service contracts		26,473		22,100		13,907		--		--		--		62,480
Total	$	85,211	$	77,260	$	70,501	$	58,468	$	66,231	$	60,124	$	417,795

_______________

1 Energy production service contracts include operations and maintenance contracts on Mint Farm, Wild Horse, Goldendale electric generating facility (Goldendale), Hopkins Ridge and Sumas facilities.

Surety Bond

The Company has a self-insurance surety bond in the amount of $4.3 million, which expires on July 1, 2011 and is renewed annually, guaranteeing compliance with the Industrial Insurance Act (workers’ compensation) and nine self-insurer’s pension bonds totaling $1.5 million.

Environmental Remediation

The Company is subject to environmental laws and regulations by the federal, state and local authorities and is required to undertake certain environmental investigative and remedial efforts as a result of these laws and regulations.  The Company has been named by the Environmental Protection Agency (EPA), the Washington State Department of Ecology and/or other third parties as potentially responsible at several contaminated sites and manufactured gas plant sites.  PSE has implemented an ongoing program to test, replace and remediate certain underground storage tanks (UST) as required by federal and state laws.  The UST replacement component of this effort is finished, but PSE continues its work remediating and/or monitoring relevant sites.  During 1992, the Washington Commission issued orders regarding the treatment of costs incurred by the Company for certain sites under its environmental remediation program.  The orders authorize the Company to accumulate and defer prudently incurred cleanup costs paid to third parties for recovery in rates established in future rate proceedings, subject to Washington Commission review.  The Washington Commission consolidated the gas and electric methodological approaches to remediation and deferred accounting in an order issued October 8, 2008.  Per the guidance of ASC 450, “Contingencies”, the Company reviews its estimated future obligations and adjusts loss reserves quarterly.  Management believes it is probable and reasonably estimable that the impact of the potential outcomes of disputes with certain property owners and other potentially responsible parties will result in environmental remediation costs ranging from $38.8 million to $55.8 million for gas and from $8.2 million to $27.8 million for electric.  The Company does not consider any amounts within those ranges as being a better estimate and has therefore accrued $38.8 million and $8.2 million for gas and electric, respectively.  The Company believes a significant portion of its past and future environmental remediation costs are recoverable from insurance companies, from third parties or from customers under a Washington Commission order.  For the year ended December 31, 2010, the Company incurred deferred electric and natural gas environmental costs of $7.6 million and $54.7 million, net of insurance proceeds, respectively.

(22)  Related Party Transactions

On June 1, 2006, PSE entered into a revolving credit facility with Puget Energy in the form of a Demand Promissory Note (Note).  Through the Note, PSE may borrow up to $30.0 million from Puget Energy, subject to approval by Puget Energy.  Under the terms of the Note, PSE pays interest on the outstanding borrowings based on the lowest of the weighted-average interest rate of PSE’s outstanding commercial paper interest rate or PSE’s senior unsecured revolving credit facility.  Absent such borrowings, interest is charged at one-month LIBOR plus 0.25%.  At December 31, 2010 and December 31, 2009, the outstanding balance of the Note was $22.6 million and $22.9 million, respectively, and the interest rate was 1.1% and 1.2%, respectively.  The outstanding balance and the related interest under the Note are eliminated by Puget Energy upon consolidation of PSE’s financial statements.  The $30.0 million credit facility with Puget Energy was unaffected by the merger.

On December 6, 2010, Puget Energy issued $450.0 million of senior secured notes.  Net proceeds of $443.0 million from these notes were used to repay a portion of the $1.225 billion term-loan.  Puget Energy’s term-loan and facility for funding capital expenditures mature in 2014, contain similar terms and conditions and are syndicated among numerous committed banks and other financial institutions.  One of these banks is Macquarie Bank Limited, which has commitments of $48.0 million under the term-loan and $20.6 million under the capital expenditure credit facility.  Concurrent with the borrowings under these credit agreements, Puget Energy entered into several interest rate swap instruments to hedge volatility associated with these two loans.  Two of the swap instruments were entered into with Macquarie Bank Limited with a total notional amount of $444.9 million.  These swap instruments remained outstanding at December 31, 2010.

(23)  Other

Fair Value of Intangible Assets.At the time of merger, Puget Energy recorded the fair value of its intangible assets in accordance with ASC 360.  The fair value assigned to the power contracts was determined using an income approach comparing the contract rate to the market rate for power over the remaining period of the contracts incorporating nonperformance risk.  Management also incorporated certain assumptions related to quantities and market presentation that it believes market participants would make in the valuation.  The fair value of the power contracts is amortized as the contracts settle.  ASC 360 requires long-live assets to be tested for impairment on an on-going basis, whenever events or circumstances would more likely than not reduce the fair value of the long-lived assets below its carrying value.  One such triggering event is a significant decrease in market price.

Puget Energy completed a valuation and impairment test as of December 31, 2010 for long-term power purchase contracts and SO2 emission allowances that were assets.  The carrying value of Puget Energy’s power contracts and SO2 emission allowances as of December 31, 2010 was approximately $864.7 million and $7.9 million, respectively.  The excess of the carrying value over the fair value of the power contracts was $105.8 million which was written-off against regulatory liabilities at December 31, 2010.  The excess of the carrying value over the fair value of the SO2 emissions was $7.9 million which was expensed at December 31, 2010.

2010 Out-of-period disclosure.  During the fourth quarter of 2010, management discovered errors in Puget Energy’s SO2 emission allowances for 2009 and 2010 interim periods.  Management did not perform the required impairment tests until the fourth quarter of 2010.  As a result, an impairment charge of $7.6 million was recognized within non-utility and other expenses as of December 31, 2010.

During the second quarter of 2010, management corrected accounting errors in the Companies’ financial statements that resulted in an increase to depreciation expense of $2.2 million, a net decrease to electric revenue and purchased electricity of $1.8 million and a decrease to income tax expense of $1.5 million.

The impact of correcting these errors in prior periods would have reduced Puget Energy’s net income by $3.5 million and $1.3 million in 2009 and 2008, respectively, and PSE’s net income by $1.1 million in 2009.  Management determined these errors were not material to the prior annual or interim periods or to the current annual or interim periods in which they are being corrected and, therefore, the Company recorded a reduction to Puget Energy’s net income of $4.8 million and PSE’s net income of $2.4 million for the year ended December 31, 2010.

(24)  Segment Information

Puget Energy operates one business segment referred to as the regulated utility segment.  The regulated utility segment includes the account receivables securitization program which was terminated during the merger.  Puget Energy’s regulated utility operation generates, purchases and sells electricity and purchases, transports and sells natural gas.  The service territory of PSE covers approximately 6,000 square miles in the state of Washington.

Non-utility business segment includes two PSE subsidiaries, and Puget Energy, is described as Other.  The PSE subsidiaries are a real estate investment and development company and a holding company for a small non-utility wholesale generator which was sold in 2010.  Reconciling items between segments are not significant.

Effective February 6, 2009, all merger related fair value adjustments were retained in Puget Energy.  Accordingly, only the financial statements of Puget Energy were adjusted to reflect the purchase accounting.  Prior to the merger, the business segment financial statements for Puget Energy and PSE were the same.

	Year Ended December 31, 2010
Puget Energy (Dollars in Thousands)	Regulated Utility		Other			Total
Revenue	$	3,121,934	$	283		$	3,122,217
Depreciation and amortization		364,205		1			364,206
Income tax (benefit) expense		35,905		(33,424	)		2,481
Operating income		310,130		(1,896	)		308,234
Interest charges, net of AFUDC		220,922		86,088			307,010
Net income		92,927		(62,616	)		30,311
Total assets		10,180,532		1,748,804			11,929,336
Construction expenditures - excluding equity AFUDC		859,091		--			859,091

	Year Ended December 31, 2010
Puget Sound Energy (Dollars in Thousands)	Regulated Utility		Other			Total
Revenue	$	3,121,935	$	282		$	3,122,217
Depreciation and amortization		364,204		2			364,206
Income tax (benefit) expense		60		62			122
Operating income		207,647		(56	)		207,591
Interest charges, net of AFUDC		220,854		--			220,854
Net income		26,358		(263	)		26,095
Total assets		9,260,675		50,109			9,310,784
Construction expenditures - excluding equity AFUDC		859,091		--			859,091

	Successor February 6, 2009 - December 31, 2009					Predecessor January 1, 2009 - February 5, 2009					Year Ended December 31, 2009
Puget Energy (Dollars in Thousands)	Regulated Utility		Other			Regulated Utility		Other			Total
Revenue	$	2,921,550	$	3,598		$	403,713	$	--		$	3,328,861
Depreciation and amortization		305,904		39			26,742		--			332,685
Income tax (benefit) expense		113,241		(31,200	)		10,537		(1,540	)		91,038
Operating income		477,082		(2,219	)		55,830		(20,420	)		510,273
Interest charges, net of AFUDC		176,858		79,953			16,966		(25	)		273,752
Net income		229,973		(55,958	)		31,611		(18,855	)		186,771
Total assets		10,117,563		1,782,577			8,507,548		87,288			11,900,140
Construction expenditures - excluding equity AFUDC		726,157		--			49,531		--			775,688

	Year Ended December 31, 2009
Puget Sound Energy (Dollars in Thousands)	Regulated Utility		Other			Total
Revenue	$	3,325,263	$	3,238		$	3,328,501
Depreciation and amortization		332,646		206			332,852
Income tax (benefit) expense		69,890		(2,246	)		67,644
Operating income		387,652		(4,517	)		383,135
Interest charges, net of AFUDC		202,527		--			202,527
Net income		161,508		(2,256	)		159,252
Total assets		8,765,189		51,382			8,816,571
Construction expenditures - excluding equity AFUDC		775,688		--			775,688

	Year Ended December 31, 2008
Puget Energy (Dollars in Thousands)	Regulated Utility		Other			Total
Revenue	$	3,351,108	$	6,665		$	3,357,773
Depreciation and amortization		311,920		208			312,128
Income tax expense		59,071		835			59,906
Operating income		386,912		(4,164	)		382,748
Interest charges, net of AFUDC		193,978		(6	)		193,972
Net income		159,373		(4,444	)		154,929
Total assets		8,347,974		86,128			8,434,102
Construction expenditures - excluding equity AFUDC		846,001		--			846,001

	Year Ended December 31, 2008
Puget Sound Energy (Dollars in Thousands)	Regulated Utility		Other			Total
Revenue	$	3,351,108	$	6,665		$	3,357,773
Depreciation and amortization		311,920		208			312,128
Income tax (benefit) expense		60,969		(87	)		60,882
Operating income		387,849		4,537			392,386
Interest charges, net of AFUDC		190,307		4,485			194,792
Net income		162,899		(163	)		162,736
Total assets		7,830,963		604,892			8,435,855
Construction expenditures - excluding equity AFUDC		846,001		--			846,001

SUPPLEMENTAL QUARTERLY FINANCIAL DATA

The following unaudited amounts, in the opinion of the Company, include all adjustments (consisting of normal recurring adjustments) necessary for a fair statement of the results of operations for the interim periods.  Quarterly amounts vary during the year due to the seasonal nature of the utility business.

Puget Energy	2010 Quarter
(Unaudited; Dollars in Thousands)	First			Second		Third			Fourth
Operating revenue	$	878,206		$	673,287	$	622,829		$	947,895
Operating income		45,403			71,726		(2,184	)		193,289
Net income (loss)		(19,191	)		3,663		(37,899	)		83,738

	2009 Quarter
(Unaudited; Dollars in Thousands)	First				Second		Third		Fourth
	Successor February 6, 2009 - March 31, 2009		Predecessor January 1, 2009 - February 5, 2009
Operating revenue	$	703,842	$	403,713	$	686,637	$	592,626	$	942,043
Operating income		116,646		35,410		117,625		101,632		138,960
Net income		52,060		12,756		43,570		24,507		53,878

Puget Sound Energy	2010 Quarter
(Unaudited; Dollars in Thousands)	First			Second		Third			Fourth
Operating revenue	$	878,206		$	673,287	$	622,829		$	947,895
Operating income		(4,984	)		48,794		(16,593	)		180,374
Net income (loss)		(38,274	)		507		(29,559	)		93,421

	2009 Quarter
(Unaudited; Dollars in Thousands)	First		Second		Third		Fourth
Operating revenue	$	1,107,555	$	686,280	$	592,626	$	942,040
Operating income		161,894		94,887		56,015		70,339
Net income		84,977		43,777		7,842		22,656

SCHEDULE I:  CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY

Puget Energy

Condensed Statements of Income

(Dollars in Thousands)

	Year Ended December 31, 2010			Successor February 6, 2009 - December 31, 2009			Predecessor January 1, 2009 - February 5, 2009			Year Ended December 31, 2008
Equity in earnings of subsidiary 1	$	92,700		$	231,978		$	31,611		$	162,736
Non-utility expense and other		(1,895	)		(1,526	)		(4	)		(386	)
Merger and related costs		--			(2,731	)		(20,416	)		(9,252	)
Other income (deductions):
Charitable foundation contributions		--			(5,000	)		--			--
Unhedged interest rate derivative expense		(7,955	)		--			--			--
Interest income		260			240			25			863
Interest expense		(86,304	)		(80,193	)		--			(8	)
Income taxes		33,505			31,247			1,540			976
Net income	$	30,311		$	174,015		$	12,756		$	154,929

_______________

1 Equity earnings of subsidiary included earnings from PSE of $26.1 million and $127.6 million for the years ended December 31, 2010 and 2009, respectively, and purchase accounting adjustments recorded at Puget Energy for PSE of $66.6 million and $104.3 million for the years ended December 31, 2010 and 2009, respectively.

See accompanying notes to the consolidated financial statements.

Puget Energy

Condensed Balance Sheets

(Dollars in Thousands)

	December 31,
	2010		2009
Assets:
Investment in subsidiaries 1	$	3,063,356	$	3,147,625
Other property and investments:
Goodwill		1,656,513		1,656,513
Current assets:
Cash		237		119
Receivables from affiliates 2		23,509		22,918
Income taxes		14,069		34,670
Deferred income taxes		10,516		9,395
Total current assets		48,331		67,102
Long-term assets:
Unrealized gain on derivative instruments		--		20,854
Deferred income taxes		71,967		1,261
Other		8,267		930
Total long-term assets		80,234		23,045
Total assets	$	4,848,434	$	4,894,285
Capitalization and liabilities:
Common equity	$	3,322,912	$	3,423,468
Long-term debt		1,463,039		1,438,519
Total capitalization		4,785,951		4,861,987
Current liabilities:
Accounts payable		--		48
Interest		4,480		5,406
Unrealized loss on derivative instruments		30,047		26,844
Total current liabilities		34,527		32,298
Long-term liabilities:
Unrealized loss on derivative instruments		27,956		--
Total long-term liabilities		27,956		--
Total capitalization and liabilities	$	4,848,434	$	4,894,285

_______________

1	Investment in subsidiaries for successor include Puget Energy business combination accounting adjustments under ASC 805 that are recorded at Puget Energy.
2	Eliminated in consolidation.

See accompanying notes to the consolidated financial statements.

Puget Energy

Condensed Statements of Cash Flows

(Dollars in Thousands)

	Year Ended December 31, 2010			Successor February 6, 2009 - December 31, 2009			Predecessor January 1, 2009 - February 5, 2009			Year Ended December 31,  2008
Operating activities:
Net income	$	30,311		$	174,015		$	12,756		$	154,929
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Unrealized gain on derivative instruments		(3,599	)		--			--			--
Deferred income taxes and tax credits - net		(52,364	)		(7,886	)		--			2,548
Equity in earnings of subsidiary 1		(92,700	)		(231,978	)		(31,611	)		(162,736	)
Other		18,169			3,153			(14	)		(7,332	)
Dividends received from subsidiaries		186,733			183,071			--			145,840
Accounts receivable		(891	)		--			--			38
Income taxes		20,601			(21,951	)		(1,539	)		810
Accounts payable		(48	)		(88,912	)		--			1,946
Affiliated payables		--			--			20,015			--
Accrued interest		(926	)		5,406			--			--
Net cash provided by (used in) operating activities		105,286			14,918			(393	)		136,043
Investing activities:
Restricted cash		--			--			--			3,994
Investment in subsidiaries		--			(25,960	)		--			--
(Increase) decrease in loan to subsidiaries		300			2,828			346			(10,287	)
Net cash provided by (used in) investing activities		300			(23,132	)		346			(6,293	)
Financing activities:
Dividends paid		(104,311	)		(121,178	)		--			(129,677	)
Issuance of bond		450,000			50,211			--			--
Redemption of term-loan		(443,000	)
Issue costs		(8,157	)		(6,428	)		--			(40	)
Net cash provided by (used in) by financing activities		(105,468	)		(77,395	)		--			(129,717	)
Increase (decrease) in cash		118			(85,609	)		(47	)		33
Cash at beginning of year		119			85,728			57			24
Cash at end of year	$	237		$	119		$	10		$	57

_______________

1 Equity earnings of subsidiary included earnings from PSE of $26.1 million and $127.6 million for the years ended December 31, 2010 and 2009, respectively, and purchase accounting adjustments recorded at Puget Energy for PSE of $66.6 million and $104.3 million for the years ended December 31, 2010 and 2009, respectively.

See accompanying notes to the consolidated financial statements.

SCHEDULE II:VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

Puget Energy (Dollars in Thousands)	Balance At Beginning of Period		Additions Charged to Costs and Expenses		Deductions		Balance At End Of Period
Year Ended December 31, 2010
Accounts deducted from assets on balance sheet:
Allowance for doubtful accounts receivable	$	8,094	$	23,875	$	22,185	$	9,784
Successor Period from February 6, 2009 to December 31, 2009
Accounts deducted from assets on balance sheet:
Allowance for doubtful accounts receivable	$	--	$	25,378	$	17,284	$	8,094
Predecessor Period from January 1, 2009 to February 5, 2009
Accounts deducted from assets on balance sheet:
Allowance for doubtful accounts receivable	$	6,392	$	1,285	$	7,677	$	--
Year Ended December 31, 2008
Accounts deducted from assets on balance sheet:
Allowance for doubtful accounts receivable	$	5,465	$	13,126	$	12,199	$	6,392

Puget Sound Energy (Dollars in Thousands)	Balance At Beginning of Period		Additions Charged to Costs and Expenses		Deductions		Balance At End Of Period
Year Ended December 31, 2010
Accounts deducted from assets on balance sheet:
Allowance for doubtful accounts receivable	$	8,094	$	23,875	$	22,185	$	9,784
Year Ended December 31, 2009
Accounts deducted from assets on balance sheet:
Allowance for doubtful accounts receivable	$	6,392	$	20,220	$	18,518	$	8,094
Year Ended December 31, 2008
Accounts deducted from assets on balance sheet:
Allowance for doubtful accounts receivable	$	5,465	$	13,126	$	12,199	$	6,392

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Puget Energy

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of Puget Energy’s management, including the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, Puget Energy has evaluated the effectiveness of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of December 31, 2010, the end of the period covered by this report.  Based upon that evaluation, the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer of Puget Energy concluded that these disclosure controls and procedures are effective.

Changes in Internal Control Over Financial Reporting

There have been no changes in Puget Energy’s internal control over financial reporting during the quarter ended December 31, 2010 that have materially affected, or are reasonably likely to materially affect, Puget Energy’s internal control over financial reporting.

Management’s Report on Internal Control Over Financial Reporting

Puget Energy’s management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934).  Under the supervision and with the participation of Puget Energy’s President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, Puget Energy’s management assessed the effectiveness of internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Based on the assessment, Puget Energy’s management concluded that its internal control over financial reporting was effective as of December 31, 2010.

Puget Energy’s effectiveness of internal control over financial reporting as of December 31, 2010 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.

Puget Sound Energy

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of PSE’s management, including the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, PSE has evaluated the effectiveness of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of December 31, 2010, the end of the period covered by this report.  Based upon that evaluation, the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer of PSE concluded that these disclosure controls and procedures are effective.

Changes in Internal Control Over Financial Reporting

There have been no changes in PSE’s internal control over financial reporting during the quarter ended December 31, 2010 that have materially affected, or are reasonably likely to materially affect, PSE’s internal control over financial reporting.

Management’s Report on Internal Control Over Financial Reporting

PSE’s management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934).  Under the supervision and with the participation of PSE’s President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, Puget Sound Energy’s management assessed the effectiveness of internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Based on the assessment, PSE’s management concluded that its internal control over financial reporting was effective as of December 31, 2010.

PSE’s effectiveness of internal control over financial reporting as of December 31, 2010 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.

ITEM 9B.    OTHER INFORMATION

Appointment of Director

Effective March 1, 2011, the sole shareholders of Puget Energy and PSE each appointed and elected Mary McWilliams to the Boards of Directors of Puget Energy and PSE, respectively.  The Boards of Puget Energy and PSE have not yet determined the board committee or committees, if any, on which Ms. McWilliams will serve.

Ms. McWilliams is currently the Executive Director at Puget Sound Health Alliance, which position she has held since 2008. She also served as President at Regence BlueShield from 2004 to 2008.  Ms. McWilliams will be entitled to receive the standard compensation for a nonemployee director and will also be reimbursed for out-of-pocket expenses incurred in connection with attendance or participation at meetings.  The nonemployee director compensation program is described in further detail in Item 11 of this report.

PART III

ITEM 10.     DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Board of Directors

As of March 1, 2011, nine directors constitute Puget Energy’s Board of Directors and ten directors currently constitute PSE’s Board of Directors, as set forth below.  The directors are selected in accordance with the Amended and Restated Bylaws of each of Puget Energy and PSE, pursuant to which, the investor-owners of Puget Holdings (the indirect parent company of both Puget Energy and PSE) are entitled to select individuals to serve on the boards of Puget Energy and PSE.

William Ayer, age 56, is a director on the boards of both Puget Energy and PSE and has extensive experience as the Chief Executive Officer of a locally-based public company with sophisticated operational requirements.  Mr. Ayer has been Chairman, President and Chief Executive Officer of Alaska Air Group (air transportation) since 2003.  He is also Chairman and Chief Executive Officer of Alaska Airlines, Inc. since 2008.  He served as Alaska Airlines’ Chairman, President and Chief Executive Officer from 2003 to 2008.  Mr. Ayer has been a director of Puget Energy and PSE since 2005.

Andrew Chapman, age 55, is a director on the boards of both Puget Energy and PSE.  Mr. Chapman is currently a director on the Board of Duquesne Light Holdings, Inc. and Duquesne Light Company, which position he has held since February 1, 2010.  Mr. Chapman is currently a Managing Director in the Macquarie Capital Funds division of the Macquarie Group, which position he has held since 2006.  Prior to joining the Macquarie Group, Mr. Chapman was Vice President – Strategy & Regulation for American Water from 2005 to 2006 and Regional Managing Director from 2003 to 2004.  Mr. Chapman has been a director of Puget Energy and PSE since February 2009.

Kimberly Harris, age 46, is a director on the boards of both Puget Energy and PSE, which positions she has held since March 1, 2011.  Ms. Harris has also been President and Chief Executive Officer since March 1, 2011.  Prior to that time, Ms. Harris served as President from July 2010 until February 2011.  Ms. Harris also served as Executive Vice President and Chief Resource Officer from May 2007 until July 2010, and was Senior Vice President Regulatory Policy and Energy Efficiency from 2005 until May 2007.

Benjamin Hawkins, age 36, became a director on the boards of both Puget Energy and PSE on May 21, 2010.  Mr. Haskins is currently a Principal of Infrastructure Investments for Alberta Investment Management Corporation, which position he has held since November 2008.  Prior to that time, Mr. Hawkins served as a Portfolio Manager, Infrastructure Investments of Alberta Investment Management Corporation from May 2007 until November 2008.  Prior to joining Alberta Investment Management Corporation, Mr. Hawkins held various positions with EPCOR Utilities, a Canadian power and water utility company.

Alan James, age 57, is a director on the boards of both Puget Energy and PSE.  Mr. James is currently the Senior Managing Director of Macquarie Capital (USA) Inc., which position he has held since 2005.  Prior to that time, Mr. James was Managing Director and Head, Investment Banking Australia and New Zealand at Citigroup from 2002 to 2005.  Mr. James has been a director of Puget Energy and PSE since February 2009.

Alan Kadic, age 39, is a director on the boards of both Puget Energy and PSE.  Mr. Kadic is currently a Senior Principal in the Infrastructure Group of the Private Investments department at the Canada Pension Plan (CPP) Investment Board, which position he has held since 2007.  Prior to joining CPP Investment Board, Mr. Kadic served as Vice President at Macquarie Bank Limited in Toronto, Canada from 2001 to 2007.  Mr. Kadic is currently a director on the board of Wales and West Utilities, a United Kingdom natural gas distribution company, as well as MGN Gas Networks, the holding company for Wales and West Utilities.  Mr. Kadic has been a director of Puget Energy and PSE since February 2009.

Christopher Leslie, age 46, is a director on the boards of both Puget Energy and PSE.  Mr. Leslie is currently the Executive Director in the Macquarie Capital Funds division of the Macquarie Group, which position he has held since 2005 and has also served as the Chief Executive Officer of Macquarie Infrastructure Partners I and II since 2006.  Mr. Leslie served as Executive Director of Macquarie Bank Limited from 2004 to 2005.  Mr. Leslie is currently a director on the boards of Duquesne Light Holdings, Inc. and Duquesne Light Company.  Mr. Leslie has been a director of Puget Energy and PSE since February 2009.

Mary McWilliams, age 62, became a director on the boards of both Puget Energy and PSE on March 1, 2011.  Ms. McWilliams is currently the Executive Director at Puget Sound Health Alliance, which position she has held since 2008.  She also served as President at Regence BlueShield from 2004 to 2008.  She also served as President and Chief Executive Officer at Regence BlueShield from 2000 to 2008.  In addition, Ms. McWilliams serves as Chairman of the board of the Seattle Branch of the Federal Reserve Bank of San Francisco.

Herbert Simon, age 67, is a director on the board of PSE and has a deep involvement in commercial and community activities in the Company’s service territory.  Mr. Simon has been a member of Simon Johnson, L.L.C. (real estate and venture capital projects investment company located in Tacoma, Washington) and its predecessor company since 1985.  In addition, Mr. Simon serves as a Regent and is on Tacoma Advisory Board of the Institute of Technology at the University of Washington.  Mr. Simon has served as a director of PSE since March 2006.

Christopher Trumpy, age 56, became a director on the boards of both Puget Energy and PSE on January 12, 2010.  Mr. Trumpy is currently the Chairman of the Pacific Carbon Trust, which position he has held since 2008.  He also served as Chairman of the British Columbia Investment Management Corporation (or bcIMC) from 2000 to 2008.  In addition, Mr. Trumpy served as Deputy Minister at Ministries of Finance, Environment and Provincial Revenue from 1998 to 2009.

Mark Wiseman, age 40, is a director on the boards of both Puget Energy and PSE.  Mr. Wiseman is currently Executive Vice President Investments at the Canada Pension Plan (CPP) Investment Board, which position he has held since April 2010.  He served as Senior Vice President Private Investments of CPP from 2005 to April 2010.  Mr. Wiseman has served as a director of Puget Energy and PSE since October 2009.

Executive Officers

The information required by this item with respect to Puget Energy and PSE is incorporated herein by reference to the material under “Executive Officers of the Registrants” in Part I of this report.

Audit Committee

The Puget Energy and PSE Boards of Directors have both established an Audit Committee.  Directors Andrew Chapman, Benjamin Hawkins, Alan Kadic and William S. Ayer are the members of the Audit Committee.  The Board has determined that Andrew Chapman meets the definition of “Audit Committee Financial Expert” under SEC rules.  Puget Energy and PSE currently do not have any outstanding stock listed on a national securities exchange and, therefore, there are no independence standards applicable to either company in connection with the independence of its Audit Committee members.

Changes to the Procedures by which Shareholders may recommend Nominees to the Board of Directors

Following the closing of the merger, members of the Boards of Directors of Puget Energy and PSE are nominated and elected in accordance with the provisions of their respective Amended and Restated Bylaws.

Code of Ethics

Puget Energy and PSE have adopted a Corporate Ethics and Compliance Code applicable to all directors, officers and employees and a Code of Ethics applicable to the Chief Executive Officer and senior financial officers, which are available on the website www.pugetenergy.com. If any material provisions of the Corporate Ethics and Compliance Code or the Code of Ethics are waived for the Chief Executive Officer or senior financial officers, or if any substantive changes are made to either code as they relate to any director or executive officer, we will disclose that fact on our website within four business days.  In addition, any other material amendments of these codes will be disclosed.

Communications with the Board

Interested parties may communicate with an individual director or the Board of Directors as a group via U.S. Postal mail directed to: Chairman of the Board of Directors, c/o Corporate Secretary, Puget Energy, Inc., P.O. Box 97034, PSE-12, Bellevue, Washington 98009-9734.  Please clearly specify in each communication the applicable addressee or addressees you wish to contact.  All such communications will be forwarded to the intended director or Board as a whole, as applicable.

ITEM 11.    EXECUTIVE COMPENSATION

Puget Energy

Puget Sound Energy

Executive Compensation

Compensation and Leadership Development Committee Interlocks and Insider Participation

The members of the Compensation and Leadership Development Committees (referred to as the Committee) of the Boards of Directors (referred to as the Board) of Puget Energy and PSE (referred to as the Company) are named in the Compensation and Leadership Development Committee Report.  No members of the Committee were officers or employees of the Company or any of its subsidiaries during 2010, were formerly Company officers or had any relationship otherwise requiring disclosure.  Each member meets the independence requirements of the SEC and the NYSE.

Compensation Discussion and Analysis

This section provides information about the compensation program for the Company’s Named Executive Officers who are included in the Summary Compensation Table.  For 2010, the Company’s Named Executive Officers and titles as of 2010 year end were:

·   Stephen P. Reynolds, Chief Executive Officer (CEO);

·   Kimberly J. Harris, President;

·   Bertrand A. Valdman, Executive Vice President and Chief Operating Officer;

·   Eric M. Markell, Executive Vice President and Chief Financial Officer;

·   James W. Eldredge, Vice President, Controller and Chief Accounting Officer;

·   Donald E. Gaines, Vice President Finance and Treasurer; and

·   Jennifer L. O’Connor, Former Senior Vice President General Counsel, Corporate Secretary, and Chief Ethics and Compliance Officer.

This section includes a discussion and analysis of the overall objectives of our compensation program and each element of compensation the Company provides.  It also discusses changes in executive roles made in connection with Mr. Reynolds’ retirement as CEO of the Company in March 2011.

Compensation Program Objectives

The Company’s executive compensation program has two main objectives:

·   Support sustained Company performance by attracting, retaining and motivating talented people to run the business.

·   Align compensation payment levels with achievement of Company goals.

The Committee is responsible for developing and monitoring an executive compensation program and philosophy that achieves the foregoing objectives.  In performing its duties, the Committee receives information and advice on various aspects of executive compensation from its outside compensation consultant, Towers Watson (formerly Towers Perrin).  The Committee recommends the pay level for our CEO, based on recommendations from Towers Watson to the Committee, and recommends the pay levels for the other executives, based on recommendations from our CEO, to the full Board for approval.  The Committee also recommends to the Board for its approval the establishment of annual and long-term incentive compensation plans for the executives, the setting of performance goals and the determination of awards under those plans.

In 2010, the Committee used the following strategies to achieve the objectives of our executive compensation program:

·   Design and deliver a competitive total pay opportunity.  To attract, retain and motivate a talented executive team, the Committee believes that total pay opportunity should be competitive with similar companies so that new executives will want to join the Company and current executives will be retained.  As described below in the discussion of Compensation Program Elements (Review of Pay Element Competitiveness), the Committee annually compares executive pay to external market data from similar companies in our industry and targets base pay and total direct compensation (which is base salary plus annual and long-term incentive pay) to the 50th percentile of this comparator group.  The Committee also recognizes the importance of providing retirement income.  Executives choose to work for the Company from a variety of other alternative organizations, and one financial goal of employees is to provide a secure future for themselves and their families.  The Committee reviews the design of retirement programs provided by our comparator group and provides benefits that are commensurate with this group.

·   Place a significant portion of each executive’s total compensation at risk to align executive compensation with Company financial and operating performance.   Under its “pay for performance” philosophy, the Committee works to design and deliver an incentive compensation program that supports the Company’s business direction as approved by the Board and aligns executive interests with those of investors and customers.  The Committee believes that a significant portion of each executive’s compensation should be “at risk” and rewarded solely for meeting and exceeding target levels of annual and long-term performance goals.  By establishing goals, monitoring results, and rewarding achievement of goals, the Company focuses executives on actions that will improve the Company and enhance investor value, while also retaining key talent.  The Committee annually evaluates the performance factors and targets for its annual and long-term incentive programs and considers adjustments as appropriate to meet the objectives of our executive compensation program.  As described below, the Company’s policies and practices surrounding incentive pay reduce the risk that employees would seek to take untoward risks in an attempt to increase incentive results.

·   Execute the Company’s succession planning process to ensure that executive leadership continues uninterrupted by executive retirements or other personnel changes.  The CEO leads the talent reviews for leadership succession planning through meetings with his executive team.  Each executive conducts talent reviews of senior employees who have high potential for assuming greater responsibility in the Company.  The talent reviews include evaluations prepared within the Company and by external organizational development consultants.  The Committee and the Board annually review these assessments of executive readiness, the plans for development of the Company’s key executives, and progress made on these succession plans.  The Committee and the Board directly participate in discussion of succession plans for the position of CEO.

During 2010, the Board worked with Mr. Reynolds on a succession plan to ensure a smooth transition in connection with his retirement as CEO in March 2011.  In July 2010, Mr. Reynolds voluntarily resigned as President of the Company and the Board appointed Ms. Harris, then the Company’s Executive Vice President and Chief Resource Officer, to that position.  In November 2010, Mr. Reynolds announced that he would retire as CEO, and effective with Mr. Reynolds’ retirement on March 1, 2011, Ms. Harris became CEO of the Company.

Risk Assessment

A portion of each executive’s total direct compensation is variable, at risk and tied to the Company’s financial and operational performance to motivate and reward executives for achievement of Company goals.  The Company’s variable pay program helps focus executives and creates a record of their results.  In structuring its incentive programs, the Company also strives to balance and moderate risk to the Company from such programs:  individual award opportunities are defined and subject to limits, goal funding is based on collective company performance, annual incentive awards are balanced by long-term incentive awards that measure performance over three years, performance targets are based on management’s operating plan (which includes providing good customer service), and all incentive awards to individual executives are subject to discretionary review by management and/or the Board.  As a result, the Committee and the Board believe that the programs’ design do not provide an incentive to executives to take unreasonable risks that could have a material adverse effect relating to the Company’s business and also provide appropriate incentive opportunities for executives to achieve Company goals that support the interests of our investors and customers.

Compensation Program Elements

The Company’s compensation program encompasses a mix of base salary, annual and long-term incentive compensation, retirement programs, health and welfare benefits and a small number of perquisites.  The Company also provides certain post-termination and change in control benefits to executives.  Since the Company is no longer publicly listed following its merger in February 2009, it relies on a mix of non-equity compensation elements to achieve its compensation objectives.

The total compensation package is designed to provide participants with appropriate incentives that are competitive with the comparator group and achieve current operational performance and customer service goals as well as the long-term objective of enhancing investor value.  The Company does not have a specific policy regarding the mix of compensation elements, though long-term incentive programs are designed to comprise the largest portion of each executive’s incentive pay.  The Company arrives at a mix of pay by setting each compensation element relative to market comparators.  The Company delivered cash compensation to the Named Executive Officers in 2010 through base salary to provide liquidity for the executives and through incentive programs to focus performance on important Company goals and to increase the connection to investors.  The Committee annually reviews total compensation opportunity and actual total compensation received over the prior years by each executive officer in the form of a tally sheet.  This review helps inform the Committee’s decisions on program designs by allowing the Committee to review overall pay received in relation to Company results.

Review of Pay Element Competitiveness

In making compensation decisions on base salary and annual and long-term incentive programs, management prepares comprehensive pay surveys for review by the Committee and the Committee’s outside executive pay consultant, Towers Watson.  The Committee also received advice from Towers Watson in making 2010 compensation decisions.  The surveys summarize data provided by the Towers Perrin 2009 Energy Services survey for a selection of utility and other companies that are most similar in scope and size to PSE.  For the review of compensation pay levels and practices in 2010, we included the following utility companies in our comparator group that were all of similar scope (generally $1.5 billion — $6.0 billion revenue and $4.0 billion — $11.0 billion asset size) and also participated in the Towers Perrin 2009 Energy Services survey:

1.	AGL Resources	8.	Nicor	15.	Portland General Electric
2.	Allegheny Energy	9.	Northeast Utilities	16.	SCANA
3.	Alliant Energy	10.	NSTAR/MA	17.	Southern Union Company
4.	Avista	11.	NV Energy	18.	TECO Energy
5.	CMS Energy	12.	OGE Energy	19.	Westar Energy
6.	MDU Resources	13.	Pinnacle West Capital	20.	Wisconsin Energy
7.	New York Power Authority	14.	PNM Resources

Base pay and total direct compensation (which is base salary plus annual and long-term incentive pay) are targeted to the 50th percentile of the industry comparator group if the Company’s performance goals are achieved at target.  If results are below expectations, total direct compensation is lower than this targeted level.  If achievement of performance goals significantly exceeds target, total cash compensation can approach the 75th percentile.

Individual pay adjustments are reviewed to see how they position the executive in relation to the median of market pay, while also considering the executive’s recent performance and experience level.  The Company may choose to pay an executive above or below the median level of market pay when that individual has a role with greater or lesser responsibility than the best comparison job or when our executive’s experience and performance exceed those typically found in the market.

Base Salary

We recognize that it is necessary to provide executives with a fixed portion of total compensation that is delivered each month and provides a balance to other pay elements that are at risk.  Base salaries are generally targeted at the 50th percentile for the comparator group and are reviewed annually by the Committee on an individual basis using as a guideline, median salary levels of our comparator group, as well as internal pay equity among executives.  Actual salaries vary by individual and depend on additional factors, such as an individual’s expertise, level of performance achievement, level of experience and level of contribution relative to others in the organization.

Base Salary Adjustments

The Committee reviewed the base salaries of the Named Executive Officers in early 2010 and recommended to the Board that base salaries not be changed from 2009 levels for 2010, in light of the continued difficult economic environment faced by many of our customers.  The Board approved the Committee’s recommendation, and base salaries for 2010 generally remained at the median of market among the comparator group.  Effective July 1, 2010, the Board appointed Ms. Harris as President of the Company and increased her base salary from $360,000 to $680,000.  In establishing the level of pay for Ms. Harris, the Committee recommended and the Board approved base pay that was below the median of market among the comparator group, reflecting Ms. Harris’s new tenure in 2010 as President.

Incentive Compensation (Annual and Long-Term)

Our annual and long-term incentives help executives focus on the priorities of our investors and customers and reward performance that meets or exceeds goals.  Both the Company’s annual incentive plan and the long-term incentive plan measure and reward the Company’s performance on Service Quality Indices (SQIs).  These reporting measures were developed in collaboration with the Company’s regulator, the Washington Commission, and provide customers with a report card on the Company’s customer service and reliability.  In fact, we provide an annual accounting on these measures to the Washington Commission and our customers each year.  Additional key performance measures used in 2010 for determining incentives were EBITDA in the annual incentive plan and Total Return in the long-term incentive plan.  EBITDA and Total Return are important performance measures of economic return to our investors, and their accomplishment indicates to our customers that the Company has the financial strength needed for long-term sustainability.

Annual Incentive Compensation

All PSE employees, including executive officers, participate in an annual incentive program referred to as the “Goals and Incentive Plan.”  The plan is designed to provide financial incentives to executives for achieving desired annual operating results while also meeting the Company’s service quality commitment to customers.  For 2010, the Company’s service quality commitment was measured by performance against 9 SQIs covering three broad categories, set forth below.  These are the same SQIs for which the Company is accountable to the Washington Commission.  The Company's annual report to the Washington Commission and our customers describes each SQI, how it is measured, the Company’s required level of achievement, and performance results.  For 2010, the Washington Commission agreed to remove one SQI that had been applicable for 2009 relating to limiting disconnects for non-payment, and during a future Company general rate case, the Washington Commission will determine if that measure should be reinstated for future years.

The report for 2010 and prior years is available at http://www.PSE.com/PerformanceReportCards.

The SQIs for 2010 were as follows:

·	Customer Satisfaction (3 SQIs)
	¾	Customer satisfaction with the telephone access center, gas field services and Washington Commission complaints
·	Customer Service (2 SQIs)
	¾	Calls answered “live” and on-time appointments
·	Safety and Reliability (4 SQIs)
	¾	Gas emergency response, electric emergency response, non-storm outage frequency and non-storm outage duration

The annual incentive plan for 2010 had a funding level based on customer service, as measured by SQI achievement, and EBITDA as shown in the table below.  EBITDA was selected as a performance goal because it provides a financial measure of cash flows generated from the Company’s annual operating performance.

The annual incentive plan had a funding level based on EBITDA and attainment of SQIs as shown in the table below.

Annual Incentive Performance Payout Scale
Performance	2010 EBITDA (In Millions)		SQI*	Funding Level
Maximum	$	1,274.3	9/9	200	%
Target		943.9	9/9	100	%
Trigger Payout Funding		849.5	6/9	30	%
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* SQI results of 6/9 or better and minimum EBITDA of $849.5 million are required for any incentive payout funding. SQI results below 9/9 reduce funding (e.g., 8/9 = 90%, 7/9 = 80%, 6/9 = 70%).

2010 Actual Performance $ 907.8 9/9 80.9 %

The Committee can adjust EBITDA used in the annual incentive calculation to exclude nonrecurring items that are outside the normal course of business for the year, but did not do so for 2010. Individual awards may be adjusted upward or downward based on a subjective evaluation of an executive officer’s performance against team and individual goals.  Individual goals were developed from the overall corporate goals for 2010:

2010 Corporate Goals

·   Enhance Customer Service — Respond to our customers by listening, leveraging new systems, updating processes and providing innovative and improved services, products and programs.

·   Optimize Generation and Delivery — Secure and maintain reliable resources, build or replace infrastructure in a way that meets our customers’ needs, promotes environmental stewardship and provides a fair return to investors.

·   Be a Good Neighbor — Embrace our role as a leader to protect and improve our natural gas and electric service, promote energy efficiency initiatives, encourage corporate giving and instill community involvement.

·   Value Employees — Safety is key; work safely.  Value diversity, teamwork and open communication.  Support employees through technology, process improvement, recognition, training and development.  Strive to make PSE a great place to work.

·   Own it — Conduct ourselves and our business in a manner that is ethical, responsible and meets or exceeds any internal or external compliance obligation.  Take personal responsibility for meeting customer needs while using company resources and facilities wisely.

·   Continue to Learn and Grow — Strive to get better at what we do every day.  Continuously examine past practices, challenge our assumptions and apply lessons learned to improve our efforts on behalf of customers and the community.

Actual performance of the corporate goals for 2010 was below target but above the threshold level for EBITDA, and at target for SQI achievement.  PSE EBITDA was $907.8 million, and SQI achievement was 9 out of 9, leading to a funding level of 80.9%.

For 2010, the target incentive levels for this plan varied by executive officer as a percentage of base salary as shown in the table below, based on the individual executive’s level of responsibility within the Company.  The Board increased the target incentive for Ms. Harris from 60% to 85% of her base salary of $680,000 when it appointed her President of the Company.  For 2010, Ms. Harris’s target annual incentive was pro-rated to reflect her two roles during the year (six months as Executive Vice President and Chief Resource Officer and six months as President).  With the exception of Ms. Harris, target annual incentive opportunities for the executives remained unchanged from 2009 levels.  The maximum incentive for exceptional performance in this plan is twice the target incentive.  An individual executive’s formula amount can be increased or decreased based on a subjective assessment by the CEO (or the Board in the case of the CEO) of the executive’s individual and team performance results.  After considering performance on individual and team goals, which were met by each executive, the CEO did not make adjustments for individual performance of the Named Executive Officers below CEO in 2010 and the amounts shown below were approved by the Board and paid in March 2011.  For Mr. Reynolds, the Board reviewed his individual and Company performance during 2010 and his contributions to the Company during his tenure and approved an award 5.2% above the formula amount, or 84.6% of funding level.

Name	Target Incentive (% of Base Salary)	2010 Actual Incentive Paid	2010 Actual Incentive (% of Base Salary)
Stephen P. Reynolds	85.0%	$ 596,982	72%
Kimberly J. Harris *	72.5%	321,173	47%
Bertrand A. Valdman	60.0%	191,733	49%
Eric M. Markell	60.0%	174,744	49%
James W. Eldredge	40.0%	71,004	32%
Donald E. Gaines	40.0%	68,660	32%
Jennifer L. O’Connor	50.0%	0	0%

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* As described above Ms. Harris’s incentive amount was based on six months at a salary of $360,000 and target of 60% and six months at a salary of $680,000 and target of 85%.

In addition to the annual incentive program, the Named Executive Officers, other than Mr. Reynolds, are eligible to receive merger performance bonuses under the terms of their Executive Employment Agreements.  (See the section Post-Termination Benefits below.)  Ms. O’Connor received a merger performance bonus at the first anniversary of the merger in February 2010, but voluntarily resigned in October 2010 and forfeited eligibility for a merger performance bonus at the second anniversary.  Ms. O’Connor also forfeited eligibility for a 2010 annual incentive.

Long-Term Incentive Compensation

Long-term incentive compensation opportunities are designed to be competitive with market practices, reward long-term performance and promote retention. Prior to the merger completed in February 2009, executives received equity awards under the Puget Energy 2005 LTI Plan in the form of performance shares and performance-based restricted stock.  Awards vested based on the Company achieving a targeted level of performance during a three-year performance cycle.  Upon the merger, all unvested LTI Plan awards accelerated in vesting and became payable in cash in 2009 pursuant to the terms of the LTI Plan.  As a result of this acceleration, the 2008-2010 performance cycle was terminated, and no LTI Plan awards were paid during 2010.

Since 2009, the Company has continued the basic design of the pre-merger LTI Plan program, including retention of three-year performance cycles that begin each year.  Since the Company no longer has publicly listed stock, LTI Plan awards for the 2009-2011 and 2010-2012 performance cycles are denominated in units and are settled in cash if threshold performance measures are met.

The Committee determines the number of LTI Plan units granted to each executive by evaluating the actual payment and forecast target payment of long-term incentive awards of our market comparator group for comparable levels of responsibility.  The Committee generally does not consider previously granted awards or the level of accrued value from prior or other programs when granting annual incentive awards or making new LTI Plan grants.  Each year’s grant is primarily viewed in the context of the compensation opportunity needed to maintain the Company’s competitive position relative to the comparator group.  Target LTI Plan awards are calculated based on a percentage of annual salary, taking into account the executive’s level of responsibility within the Company.  Target LTI Plan awards for the 2010-2012 performance cycle were 170% of base salary for Mr. Reynolds; 110% for Mr. Valdman and Mr. Markell; 50% for Mr. Eldredge and Mr. Gaines; and 95% for Ms. O’Connor.  In connection with her appointment as President, Ms. Harris’s target LTI Plan award increased from 110% to 170% of her base salary of $680,000, and her 2010 grant was pro-rated to reflect her two roles during the year (six months as Executive Vice President and Chief Resource Officer and six months as President). With the exception of Ms. Harris, target LTI Plan award opportunities as a percentage of base salary remained unchanged from 2009 levels for the Named Executive Officers.

Except for the CEO, 50% of each grant of LTI Plan units is allocated to achievement of SQIs only (SQI component) and 50% is allocated to achievement of a combination of SQIs and Total Return (Total Return component).  The CEO’s LTI Plan units are allocated 30% to the SQI component and 70% to the Total Return component to place additional weight on financial measures, consistent with other peer companies.  The total number of LTI Plan units granted to a Named Executive Officer is equal to the applicable percentage of salary divided by the per unit value at the beginning of the performance cycle.  For the 2010-2012 performance cycle, the initial per unit value was $31.56.

The total amount payable for a performance cycle is calculated at the end of the performance cycle based on the performance measures of SQIs and Total Return as well as the per unit dollar value at the end of the performance cycle.  Unit value is measured at the Puget Holdings LLC level and is re-calculated each year based on the change in Total Return for the prior year as measured by an independent auditing firm.  Total Return reflects the annual change in the value of the Company plus any distributions made to investors.  For any award to be earned in a performance cycle, average SQI results must meet or exceed 80% accomplishment of the available SQIs set forth above under Annual Incentive Compensation.  Executives must be employed on the payment date to receive a cash payment under the LTI Plan, except in the event of retirement at normal retirement age or approved early retirement, disability or death.

The tables and points below summarize the performance measures and design of the LTI Plan grants for the current performance cycles.

Grant Cycle	SQI Component	Total Return Component**
2009-2011*	50%	50%
2010-2012*	50%	50%

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*	CEO grants are split 30% SQI component and 70% Total Return Component.
**	Total Return Component is determined based on a combination of Total Return and 3-year average SQI results.

Service Quality Indices (SQIs) Component Table
SQI Result, 3 year average	Percentage of LTI Plan Target Award
80% achievement or above *	100%
Below 80%	0%

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* For 2009 in the 2009-2011 performance cycle, SQIs results were measured against 10 SQIs.  9 SQIs currently apply for the remaining years in the 2009-2011 performance cycle and for the 2010-2011 performance cycle.

The table below shows the percentage of LTI Plan target awards under the Total Return Component that will be earned based on three-year performance.  Percentages will be interpolated if performance falls between the values shown below.

Total Return Component Table
Percentage of LTI Plan Target Award
Annualized 3 Year Return	100% SQI (3 year average)	90% SQI (3 year average)	80% SQI (3 year average)	<80% SQI (3 year average)
15% or more	210%	175%	155%	0%
14%	180%	150%	130%	0%
13%	150%	125%	105%	0%
12%	120%	100%	80%	0%
11%	80%	65%	50%	0%
10%	40%	30%	20%	0%
<10%	0%	0%	0%	0%

 SQI Component:

·   A target number of units are granted at the beginning of a three-year performance cycle that will be paid in cash to the participant if the Company achieves the targeted level of 80% of SQIs during the performance cycle.  The actual award is paid at target level if an average of at least 80% of SQIs are satisfied during the performance cycle, but is not paid if the average is below 80%.  If threshold SQI performance is met, the amount payable is equal to the product of the target number of units granted and the per unit value at the end of the performance cycle.

·   If 80% SQIs are met during the performance cycle, but the Total Return threshold of 10% is not met, the SQI component will still be paid at target.

Total Return Component:

·   A target number of units are granted at the beginning of a three-year performance cycle that will be paid in cash to the participant if the Company achieves the targeted level of Total Return and SQI performance during the three-year performance cycle. The actual award paid is based on Company performance relative to target, subject to a minimum threshold level of performance of 10% for Total Return (based on average Total Return over the performance cycle) and average SQI achievement of 80%.

·   The LTI Plan unit value is determined annually by applying the Total Return for each year to the prior year’s unit price.

·   At the completion of the performance cycle, if the Total Return component is paid, the participant receives a cash payment equal to the number of units earned based on performance during the performance cycle multiplied by the unit price at the end of the performance cycle.

·   If the Total Return component exceeds 10% annualized 3-year return, but the SQI threshold is not met, the Total Return component will not be paid.

LTI Plan Performance of Outstanding Awards

  The Company’s 2010-2012 outstanding LTI Plan grants had the following performance during 2010:

·   Award calculation is based on the full three-year performance cycle, so no award payment calculations will be made until after 2012.

·   Performance on the SQI component of the grant was at 9 out of 9, which if continued for the remaining two years of the performance cycle would mean that the SQI component would pay based on the target number of units granted to a Named Executive Officer.

·   Performance on the Total Return component during 2010 was 7.1%, below the three-year average threshold needed for payment.

  The Company’s 2009-2011 outstanding LTI Plan grants had the following performance during 2009 and 2010:

·   Award calculation is based on the full three-year performance cycle, so no award payment calculations will be made until after 2011.

·   Performance on the SQI component of the grant was at 9 out of 10 in 2009, or 90%, and 9 out of 9 in 2010, or 100%, for a combined two-year result of 95%, which if continued for the remaining year of the performance cycle would mean that the SQI component would pay based on the target number of units granted to a Named Executive Officer.

·   Performance on the Total Return component during 2009 was 5.2% and during 2010 was 7.1%, or a combined two-year result of 6.15%, below the three-year average threshold needed for payment.

Retirement Plans — SERP and Retirement Plan

The Company maintains the Supplemental Executive Retirement Plan (SERP) for executives to provide a benefit that is coordinated with the tax-qualified Retirement Plan for Employees of Puget Sound Energy, Inc. (Retirement Plan).  Without the addition of the SERP, these executives would receive lower percentages of replacement income during retirement than other employees.  All the Named Executive Officers except Mr. Reynolds participate in the SERP.  When Mr. Reynolds was hired, he elected to receive an annual contribution to his account in the Deferred Compensation Plan for Key Employees in lieu of participating in the SERP, as described in the following paragraph.  He participates in the Retirement Plan.  Additional information regarding the SERP and the Retirement Plan is shown in the “2010 Pension Benefits” table.

Deferred Compensation Plan

The Named Executive Officers are eligible to participate in the Deferred Compensation Plan for Key Employees (Deferred Compensation Plan).  The Deferred Compensation Plan provides executives an opportunity to defer up to 100% of base salary, annual incentive bonus and LTI Plan awards, plus receive additional Company contributions made by PSE into an account that has three investment tracking fund choices.  The funds mirror performance in major asset classes of bonds, stocks, and an interest crediting fund that changes rates quarterly based on corporate bond rates.  The Deferred Compensation Plan is intended to allow the executives to defer current income, without being limited by the Internal Revenue Code contribution limitations for 401(k) plans and therefore have a deferral opportunity similar to other employees as a percentage of eligible compensation.  The Company contributions are also intended to restore benefits not available to executives under PSE’s tax-qualified plans due to Internal Revenue Code limitations on compensation and benefits applicable to those plans.  Under the terms of Mr. Reynolds’ employment agreement, he additionally receives an annual Company contribution to his Deferred Compensation Plan account equal to 15% of the base salary and annual incentive payment he received during the prior year.  Additional information regarding the Deferred Compensation Plan and Mr. Reynolds’ employment agreement arrangement, as well as his year-end balance, is shown in the “2010 Nonqualified Deferred Compensation” table.

Post-Termination Benefits

The Company has entered into agreements with its executive officers, including the Named Executive Officers, that provide for certain payments and benefits if an executive’s employment is terminated or terminates for certain reasons, such as following a change in control.  Benefits provided under these agreements are important for two primary reasons.  First, many executives when joining a new company require a level of assurance that they will receive pay in the event of a termination of employment following a change in control after they join the company.  Second, the Company provides these agreements so that the executives are focused on the Company’s ongoing operations and are not distracted by the employment uncertainty that can arise in the event of a change in control.  The Committee periodically reviews existing change in control arrangements for the comparator group considering benchmarking information provided by Towers Watson.  Based on this information, the Committee believes that the arrangements generally provide benefits that are similar to those of the comparator group.

Effective March 30, 2009, the Company entered into Executive Employment Agreements with the Named Executive Officers, except Mr. Reynolds, which amended and restated existing Amended and Restated Change of Control Agreements between the Company and each of the executives.  The Executive Employment Agreements provide for an employment period of two years following the February 6, 2009 completion of the merger and generally provide benefits similar to those under the previous Change of Control Agreements.  In addition, the agreements provide for a merger performance bonus equal to 100% of the executives’ annual base salary, payable on or shortly following each of the first and second anniversaries of the completion of the merger if the Company achieves specified minimum SQI performance goals established by the Committee (for 2010, 80% of SQIs or better) and the executive remains employed at the Company until the anniversary of the merger for which payment is made.  Ms. O’Connor received a merger performance bonus at the first anniversary of the merger, but voluntarily resigned in October 2010 and forfeited eligibility for payment at the second anniversary.

Following the merger, Mr. Reynolds’ employment agreement, as amended, continued, except that effective as of December 31, 2009, Mr. Reynolds agreed to waive any change in control benefits and payments that might otherwise be payable to him under the agreement on or after December 31, 2009, including upon a subsequent change in control.   Mr. Reynolds’ employment agreement terminated effective February 28, 2011 in connection with his retirement as CEO.

The “Potential Payments Upon Termination or Change in Control” section describes the current post-termination arrangements with the Named Executive Officers as well as other plans and arrangements that would provide benefits on termination of employment or a change in control, and the estimated potential incremental payments upon a termination of employment or change in control based on an assumed termination or change in control date of December 31, 2010.

Other Compensation

In addition to base salary and annual and long-term incentive award opportunities, the Company also provides the Named Executive Officers with benefits and perquisites targeted to competitive practices.  The executives participate in the same group health and welfare plans as other employees.  Company vice presidents and above, including the Named Executive Officers, are eligible for additional disability and life insurance benefits.  The executives are also eligible to receive reimbursement for financial planning, tax preparation, legal services, business club memberships and executive physicals up to an annual limit.  The reimbursement for financial planning, tax preparation and legal services is provided to allow executives to concentrate on their business responsibilities.  Business club memberships are provided to allow access for business meetings and business events at club facilities and executives are required to reimburse the Company for individual use of club facilities.  These perquisites do not make up a significant portion of executive compensation, amounting to less than $10,000 in total for each Named Executive Officer in 2010.

Relationship among Compensation Elements

A number of compensation elements increase in absolute dollar value as a result of increases to other elements.  Base salary increases translate into higher dollar value incentive opportunity for annual and long-term incentives, because each plan operates with a target level award set as a percentage of base salary.  Base salary increases also increase the level of retirement benefits, as do actual annual incentive plan payments.  Some key compensation elements are excluded from consideration when determining other elements of pay.  Retirement benefits exclude LTI Plan payments in the calculation of qualified retirement (pension and 401(k)) and SERP benefits.

Impact of Accounting Treatment of Compensation

The accounting treatment of compensation generally has not been a factor in determining the amounts of compensation for our executive officers.  However, the Company considers the accounting impact of various program designs to balance the potential cost to the Company with the benefit/value to the executive.

Compensation and Leadership Development Committee Report

The Board delegates responsibility to the Compensation and Leadership Development Committee to establish and oversee the Company’s executive compensation program.  Except as noted below, each member of the Committee served during all of 2010.

The Committee members listed below have reviewed and discussed the “Compensation Discussion and Analysis” with the Company’s management.  Based on this review and discussion, the Committee recommended to the Board, and the Board has approved, that the “Compensation Discussion and Analysis” be included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2010 for filing with the SEC.

Compensation and Leadership

Development Committee of

Puget Energy, Inc.

Puget Sound Energy, Inc.

Mark Wiseman, Chair (joined Committee July 27, 2010)

Christopher Leslie

Herbert B. Simon (PSE Only)

Chris Trumpy

SUMMARY COMPENSATION TABLE

The following information is furnished for the year ended December 31, 2010 (and for prior years where applicable) with respect to the Named Executive Officers during 2010.  The positions listed below are at Puget Energy and PSE, except that Mr. Valdman is an executive of PSE only. Positions listed are those held by the Named Executive Officers as of December 31, 2010.  Salary and incentive compensation includes amounts deferred at the executive’s election.

Name and Principal Position	Year	Salary		Bonus		Stock Awards 1		Option Awards		Non-Equity Incentive Plan Compensation 2		Change in Pension Value and Nonqualified Deferred Compensation Earnings 3		All Other Compensation 4		Total
Stephen P. Reynolds	2010	$	825,000	$	29,671	$	--	$	--	$	567,311	$	69,423	$	341,758	$	1,833,163
Chief Executive Officer 5	2009		825,000		--		--		--		507,705		69,885		6,595,041		7,997,631
	2008		819,792		--		1,341,221		--		788,906		29,910		316,124		3,295,953
Kimberly J. Harris	2010	$	506,667	$	--	$	--	$	--	$	681,173	$	445,997	$	25,935	$	1,659,772
President 6	2009		360,000		15,638		--		--		156,384		222,948		270,937		1,025,907
	2008		347,499		--		379,422		--		243,000		183,238		22,372		1,175,531
Bertrand A. Valdman	2010	$	395,000	$	--	$	--	$	--	$	586,733	$	247,187	$	47,163	$	1,276,083
Executive Vice President	2009		395,000		--		--		--		154,429		158,380		373,521		1,081,330
And Chief Operating Officer	2008		390,836		--		416,284		--		266,625		136,157		47,660		1,257,562
Eric M. Markell	2010	$	360,000	$	--	$	--	$	--	$	534,744	$	423,394	$	42,871	$	1,361,009
Executive Vice President	2009		360,000		15,638		--		--		156,384		309,648		289,672		1,131,342
And Chief Financial Officer	2008		347,500		--		379,422		--		243,000		281,473		39,767		1,291,162
James W. Eldredge	2010	$	219,420	$	--	$	--	$	--	$	290,424	$	191,743	$	26,985	$	728,572
Vice President, Controller
and Chief Accounting Officer
Donald E. Gaines	2010	$	212,175	$	--	$	--	$	--	$	280,835	$	156,474	$	22,570	$	672,054
Vice President Finance and
Treasurer
Jennifer L. O’Connor	2010	$	252,870	$	--	$	--	$	--	$	310,500	$	204,897	$	28,729	$	796,996
Former Senior Vice President	2009		310,500		--		--		--		101,161		162,103		255,244		829,008
General Counsel, Corporate	2008		308,313		--		282,641		--		174,656		172,627		31,684		969,921
Secretary, and Chief Ethics and
Compliance Officer 7

    ___________________

1	Reflects the grant date fair value of 2008 LTI Plan grants which were settled in cash in 2009 in connection with the merger.  Assumptions used in the calculation of these amounts are included in note 18 to the Company’s audited financial statements included in the Company’s Form 10-K for the fiscal year ended December 31, 2009.
2	For 2010, reflects annual cash incentive compensation paid under the 2010 Goals and Incentive Plan and the first year of merger performance bonuses payable to each of the executives, except Mr. Reynolds who was not eligible for a merger performance bonus.  Cash incentive amounts are based on 2010 performance and were paid in early 2011 or deferred at the executive’s election.  The 2010 Goals and Incentive Plan is described in further detail under “Compensation Discussion and Analysis,” including the amounts actually paid to each Named Executive Officer for 2010.  The threshold, target and maximum amounts that could have been paid under the 2010 Goals and Incentive Plan are set forth in the “2010 Grants of Plan-Based Awards” table. Merger performance bonus amounts were: Ms. Harris, $360,000; Mr. Valdman, $395,000; Mr. Markell, $360,000; Mr. Eldredge, $219,420; Mr. Gaines, $212,175; and Ms. O’Connor, $310,500.
3	Reflects the aggregate increase in the actuarial present value of the executive’s accumulated benefit under all pension plans during the year.  The amounts are determined using interest rate and mortality rate assumptions consistent with those used in the Company’s financial statements and include amounts which the executive may not currently be entitled to receive because such amounts are not vested.  Information regarding these pension plans is set forth in further detail under “2010 Pension Benefits.”  Mr. Reynolds does not participate in the SERP, and his accumulated benefit shown is only from the qualified pension plan.  The change in pension value amounts for 2010 are: Mr. Reynolds, $39,619; Ms. Harris, $444,018; Mr. Valdman, $246,097; Mr. Markell, $420,555; Mr. Eldredge, $184,114; Mr. Gaines, $153,976; and Ms. O’Connor $202,497.  Also included in this column are the portion of Deferred Compensation Plan earnings that are considered above market.  These amounts for 2010 are: Mr. Reynolds, $29,804; Ms. Harris, $1,979; Mr. Valdman, $1,090; Mr. Markell, $2,839; Mr. Eldredge, $7,629; Mr. Gaines, $2,498; and Ms. O’Connor, $2,400.  See the “2010 Nonqualified Deferred Compensation” table for all Deferred Compensation Plan earnings.
4	All Other Compensation is shown in detail in the table below.
5	Mr. Reynolds voluntarily resigned as President in July 2010.
6	Ms. Harris was promoted to President from Executive Vice President and Chief Resource Officer in July 2010.
7	Ms. O’Connor voluntarily resigned in October 2010.

Detail of All Other Compensation

Name	Perquisites and Other Personal Benefits 1		Tax Reimbursements		Payments/ Accruals on Termination Plans		Registrant Contributions to Defined Contribution Plans 2		Other 3
Stephen P. Reynolds	$	8,739	$	--	$	--	$	324,498	$	8,521
Kimberly J. Harris		5,084		--		--		16,630		4,221
Bertrand A. Valdman		7,553		--		--		35,416		4,194
Eric M. Markell		3,411		--		--		34,371		5,089
James W. Eldredge		827		--		--		19,768		6,390
Donald E. Gaines		2,718		--		--		18,171		1,681
Jennifer L. O’Connor		3,349		--		--		23,007		2,373

_______________

1	Annual reimbursement for financial planning, tax planning, and/or legal planning, up to a maximum of $2,500 for Mr. Eldredge, Mr. Gaines, and Ms. O’Connor and $5,000 for the other Named Executive Officers.  Club use is primarily for business purposes, but Company club expense is included when the executive is also able to use the club for personal use.  Expenses for personal club use are directly paid by the executive, not PSE.
2	Includes Company contributions during 2010 to PSE’s Investment Plan (a tax qualified 401(k) plan) and the Deferred Compensation Plan.  For Mr. Reynolds, this includes the Company contribution to the Deferred Compensation Plan equal to 15% of Mr. Reynolds’ base salary and annual incentive for the prior year, $242,086,  which is described in more detail in the “2010 Nonqualified Deferred Compensation” section. Includes Company 401k contributions: Mr. Reynolds $16,200; Ms. Harris $16,630; Mr. Valdman $15,666; Mr. Markell $16,371; Mr. Eldredge $14,665; Mr. Gaines $14,687; and Ms. O’Connor $17,150.
3	Reflects the value of imputed income for life insurance and Company paid premiums on supplemental disability insurance.

2010 Grants of Plan-Based Awards

The following table presents information regarding 2010 grants of non-equity annual incentive awards and LTI Plan awards, including, as applicable, the range of potential payouts for the awards:

		Estimated Future Payouts under Non-Equity Incentive Plan Awards
Name	Grant Date	Number Of Units Granted		Threshold		Target		Maximum
Stephen P. Reynolds
Annual Incentive 1	1/1/2010			$	245,438	$	701,250	$	1,402,500
LTI Plan 2010-2012 2	2/24/2010		44,439		420,750		1,970,412		3,775,458
Kimberly J. Harris
Annual Incentive 1	1/1/2010			$	138,950	$	397,000	$	794,000
LTI Plan 2010-2012 2	2/24/2010		24,588		387,999		1,090,232		1,829,302
Bertrand A. Valdman
Annual Incentive 1	1/1/2010			$	82,950	$	237,000	$	474,000
LTI Plan 2010-2012 2	2/24/2010		13,768		217,252		610,445		1,024,278
Eric M. Markell
Annual Incentive 1	1/1/2010			$	75,600	$	216,000	$	432,000
LTI Plan 2010-2012 2	2/24/2010		12,548		198,000		556,351		933,513
James W. Eldredge
Annual Incentive 1	1/1/2010			$	30,719	$	87,768	$	175,536
LTI Plan 2010-2012 2	2/24/2010		3,467		54,854		154,133		258,623
Donald E. Gaines
Annual Incentive 1	1/1/2010			$	29,705	$	84,870	$	169,740
LTI Plan 2010-2012 2	2/24/2010		3,362		53,043		149,043		250,082
Jennifer L. O’Connor 3
Annual Incentive 1,3	1/1/2010			$	54,338	$	155,250	$	310,500
LTI Plan 2009-2011 2,3	2/24/2010		9,347		147,486		414,415		695,355

_______________

1	Annual Goals and Incentive Plan. As described in the “Compensation Discussion and Analysis,” the 2010 Goals and Incentive Plan had dual funding triggers in 2010 of $849.5 million EBITDA and SQI performance of 6/9.  Payment would be $0 if either trigger is not met.  The threshold estimate assumes $849.5 million EBITDA and SQI performance at 6/9. The target estimate assumes $943.9 million EBITDA and SQI performance at 9/9.  The maximum estimate assumes $1,274.3 million EBITDA or higher and SQI performance at 9/9.
2	As described in the “Compensation Discussion and Analysis,” LTI Plan grants are allocated between an SQI component and a Total Return component.  Payments are calculated based on the average three-year performance of SQIs and Total Return at Puget Holdings LLC and the unit value at the end of the performance cycle.  Threshold estimate assumes that SQI results average 80% achievement, Total Return is below 10%, and ending unit value is $31.56.  Target estimate assumes that SQI results average 90%, Total Return averages 12%, and ending unit value is $44.34.  Maximum estimate assumes that SQI results average 100%, Total Return averages 15%, and ending unit value is $48.00.
3	Ms. O’Connor forfeited eligibility to the annual incentive, receiving $0 for 2010 performance, and forfeited eligibility in all outstanding LTI Plan grants, including the LTI Plan 2010-2012 grant, when she voluntarily resigned.

2010 Pension Benefits

The Company and its affiliates maintain two pension plans:  the Retirement Plan and the SERP. The following table provides information for each of the Named Executive Officers regarding the actuarial present value of the executive’s accumulated benefit and years of credited service under the Retirement Plan and the SERP.  The present value of accumulated benefits was determined using interest rate and mortality rate assumptions consistent with those used in the Company’s financial statements. Except as described below in footnote 1, relating to Mr. Reynolds, each of the Named Executive Officers participates in both plans.

Name	Plan Name	Number of Years Credited Service	Present Value of Accumulated Benefit 2,3	Payments During Last Fiscal Year
Stephen P. Reynolds 1	PSE Retirement Plan	9.0	$ 208,855	$    --
	PSE SERP	n/a	n/a	n/a
Kimberly J. Harris	PSE Retirement Plan	11.7	185,600	--
	PSE SERP	11.7	1,074,166	--
Bertrand A. Valdman	PSE Retirement Plan	7.1	118,561	--
	PSE SERP	7.1	755,755	--
Eric M. Markell	PSE Retirement Plan	8.4	179,911	--
	PSE SERP	8.4	1,413,019	--
James W. Eldredge	PSE Retirement Plan	37.2	621,431	--
	PSE SERP	37.2	1,109,571	--
Donald E. Gaines	PSE Retirement Plan	29.9	424,102	--
	PSE SERP	29.9	696,455	--
Jennifer L. O’Connor	PSE Retirement Plan	7.7	139,272	--
	PSE SERP	7.7	785,745	--

_______________

1	Mr. Reynolds participates in the Retirement Plan, but does not participate in the SERP. In lieu of participating in the SERP, each year Mr. Reynolds’ account under the Deferred Compensation Plan is credited with an amount equal to 15% of his base salary and annual incentive for the preceding year.  The value of this deferred compensation account at December 31, 2010 of $3,991,754 is also shown in the “2010 Nonqualified Deferred Compensation Plan” table.
2	The amounts reported in this column for each executive were calculated assuming no future service or pay increases. Present values were calculated assuming no pre-retirement mortality or termination.  The values under the Retirement Plan and the SERP are the actuarial present values as of December 31, 2010 of the benefits earned as of that date and payable at normal retirement age (age 65 for the Retirement Plan and age 62 for the SERP).  Future cash balance interest credits are 4.0% for 2011 and are assumed to average 5.5% annually thereafter.  The discount assumption is 5.15%, and the post-retirement mortality assumption is based on the 2011 417(e) unisex mortality table. Annuity benefits are converted to lump sum amounts at retirement based on assumed future 417(e) segment rates of 3.78%, 6.31% and 6.57% (the 24 month average of the underlying rates as of September 2010).  These assumptions are consistent with the ones used for the Retirement Plan and the SERP for financial reporting purposes for 2010.  In order to determine the change in pension values for the “Summary Compensation” table, the values of the Retirement Plan and the SERP benefits were also calculated as of December 31, 2009 for the benefits earned as of that date using the assumptions used for financial reporting purposes for 2009.  These assumptions included assumed average cash balance interest credits of 4% for 2010 and 5.5% for all future years, a discount assumption of 5.75% and post-retirement mortality assumption based on the 2010 417(e) unisex mortality table.  Annuity benefits were converted to lump sum amounts at retirement based on assumed future 417(e) segment rates of 5.03%, 6.73% and 6.82% (the 24 month average of the underlying rates as of September 2009).   Other assumptions used to determine the value as of December 31, 2009 were the same as those used for December 31, 2010.
3	As described in footnote 2 above, the amounts reported for the SERP in this column are actuarial present values, calculated using the actuarial assumptions used for financial reporting purposes.  These assumptions are different from those used to calculate the actual amount of benefit payments under the SERP (see text below for a discussion of the actuarial assumptions used to calculate actual payment amounts).  The following table shows the estimated lump sum amount that would be paid under the SERP to each SERP-eligible Named Executive Officer at age 62 (without discounting to the present), calculated as if such Named Executive Officer had terminated employment on December 31, 2010.  Each SERP-eligible Named Executive Officer was vested in his or her SERP benefits as of December 31, 2010.

Name	Lump Sum
Kimberly J. Harris	$	2,319,959
Bertrand A. Valdman		1,532,950
Eric M. Markell		1,602,032
James W. Eldredge		1,221,677
Donald E. Gaines		1,049,549
Jennifer L. O’Connor		1,164,450

Retirement Plan

Under the Retirement Plan, Puget Energy’s and PSE’s eligible salaried employees, including the Named Executive Officers, accrue benefits in accordance with a cash balance formula, beginning on the later of their date of hire or March 1, 1997.  Under this formula, for each calendar year after 1996, age-weighted pay credits are allocated to a bookkeeping account (a Cash Balance Account) for each participant.  The pay credits range from 3% to 8% of eligible compensation. Eligible compensation generally includes base salary and bonuses (other than bonuses paid under the LTI Plan, signing, retention and similar bonuses), up to the limit imposed by the Internal Revenue Code. For 2009 through 2011, the Internal Revenue Code compensation limit was $245,000.  In addition, as of March 1, 1997, the Cash Balance Account of each participant who was participating in the Retirement Plan on March 1, 1997 was credited with an amount based on the actuarial present value of that participant’s accrued benefit, as of February 28, 1997, under the Retirement Plan’s previous formula.

Amounts in the Cash Balance Accounts are also credited with interest.  The interest crediting rate is 4% per year or such higher amount as PSE may determine. For 2010 and 2011 the annual interest crediting rate was 4%.

A participant’s Retirement Plan benefit generally vests upon the earlier of the participant’s completion of three years of active service with Puget Energy, PSE or their affiliates or attainment of age 65 (the Retirement Plan’s normal retirement age) while employed by the Company or one of its affiliates.  Normal retirement benefit payments begin to a vested participant as of the first day of the month following the later of the participant’s termination of employment or attainment of age 65.  However, a vested participant may elect to have his or her benefit under the Retirement Plan paid, or commence to be paid, as of the first day of any month commencing after the date on which his or her employment with Puget Energy, PSE and their affiliates terminates.  If benefit payments commence prior to the participant’s attainment of age 65, then the amount of the monthly payments will be reduced for early commencement to reflect the fact that payments will be made over a longer period of time.  This reduction is subsidized — that is, it is less than a pure actuarial reduction.  The amount of this reduction is, on average, 0.30% for each of the first 60 months, 0.33% for each of the second 60 months, 0.23% for each of the third 60 months and 0.17% for each of the fourth 60 months that the payment commencement date precedes the participant’s 65th birthday.  Further reductions apply for each additional month that the payment commencement date precedes the participant’s 65th birthday.  As of December 31, 2010, all the Named Executive Officers were vested in their benefits under the Retirement Plan and, hence, would be eligible to commence benefit payments upon termination.

The normal form of benefit payment for unmarried participants is a straight life annuity providing monthly payments for the remainder of the participant’s life, with no death benefits.  The straight life annuity payable on or after the participant's normal retirement age is actuarially equivalent to the balance in the participant’s Cash Balance Account as of the date of distribution.  For married participants, the normal form of benefit payment is an actuarially equivalent joint and 50% survivor annuity with a “pop-up” feature providing reduced monthly payments (as compared to the straight life annuity) for the remainder of the participant’s life and, upon the participant’s death, monthly payments to the participant’s surviving spouse for the remainder of the spouse’s life in an amount equal to 50% of the amount being paid to the participant.  Under the pop-up feature, if the participant’s spouse predeceases the participant, the participant’s monthly payments increase to the level that would have been provided under the straight life annuity.  In addition, the Retirement Plan provides several other annuity payment options and a lump sum payment option that can be elected by participants. All payment options are actuarially equivalent to the straight life annuity.  However, in no event will the amount of the lump sum payment be less than the balance in the participant’s Cash Balance Account as of the date of distribution (in some instances the amount of the lump sum distribution may be greater than the balance in the Cash Balance Account due to differences in the mortality table and interest rates used to calculate actuarial equivalency).

If a participant in the cash balance portion of the Retirement Plan dies while employed by the Company or any of its affiliates, then his or her Retirement Plan benefit will be immediately vested.  If a vested participant dies before his or her Retirement Plan benefit is paid, or commences to be paid, then the participant’s Retirement Plan benefit will be paid to his or her beneficiary(ies).  If a participant dies after his or her Retirement Plan benefit has commenced to be paid, then any death benefit will be governed by the form of payment elected by the participant.

Supplemental Executive Retirement Plan

The SERP provides a benefit to participating Named Executive Officers that supplements the retirement income provided to the executives by the Retirement Plan.  Ms. Harris, Mr. Valdman, Mr. Markell, Mr. Eldredge, Mr. Gaines and Ms. O’Connor participate in the SERP.

A participating Named Executive Officer’s SERP benefit generally vests upon the executive’s completion of five years of participation in the SERP while employed by the Company or any of its affiliates. All the participating Named Executive Officers are vested in their SERP benefits.  Ms. O’Connor voluntarily resigned in October 2010 and will be entitled to receive her SERP benefit beginning at age 62.  The monthly benefit payable under the SERP to a vested executive (calculated in the form of a straight life annuity payable for the executive’s lifetime commencing at the later of the executive’s date of termination or attainment of age 62) is equal to (1) below minus the sum of (2) and (3) below:

(1)   One-twelfth (1/12) of the executive’s highest average earnings times the executive’s years of credited service (not in excess of 15) times 3-1/3%.  For purposes of the SERP, “highest average earnings” means the average of the executive’s highest three calendar years of earnings.  The three calendar years do not have to be consecutive, but they must be among the last ten calendar years completed by the executive prior to his or her termination. “Earnings” for this purpose include base salary and annual bonus, but do not include long-term incentive compensation. An executive will receive one “year of credited service” for each consecutive 12-month period he or she is employed by the Company or its affiliates.  If an executive becomes entitled to disability benefits under PSE’s long-term disability plan, then the executive’s highest average earnings will be determined as of the date the executive became disabled, but the executive will continue to accrue years of credited service until he or she begins to receive SERP benefits.

(2)   The monthly amount payable (or that would be payable) under the Retirement Plan to the executive in the form of a straight life annuity commencing as of the first day of the month following the later of the executive’s date of termination or attainment of age 62, and includes amounts previously paid or segregated pursuant to a qualified domestic relations order.

(3)   The actuarially equivalent monthly amount payable (or that would be payable) to the executive as of the first day of the month following the later of the executive’s date of termination or attainment of age 62 from any pension-type rollover accounts within the Deferred Compensation Plan (including the Annual Cash Balance Restoration Account). These accounts are described in more detail in the “2010 Nonqualified Deferred Compensation” section.

Normal retirement benefits under the SERP generally are paid or commence to be paid within 90 days following the later of the Named Executive Officer’s termination of employment or attainment of age 62.  Except as provided below, SERP benefits are normally paid in a lump sum that is equal to the actuarial present value of the monthly straight life annuity benefit.  In lieu of the normal form of payment, an executive may elect to receive his or her SERP benefit in the form of monthly installment payments over a period of two to 20 years, in a straight life annuity or in a joint and survivor annuity with a 100%, 75%, 50% or 25% survivor benefit.  All payment options are actuarially equivalent to the straight life annuity. Mr. Markell and Mr. Eldredge are the only Named Executive Officers eligible for early retirement benefit payments under the SERP.

If a participating Named Executive Officer dies while employed by Puget Energy, PSE or any of their affiliates or after becoming vested in his or her SERP benefit, but before his or her SERP benefit has commenced to be paid, then the executive’s surviving spouse will receive a lump sum benefit equal to the actuarial equivalent of the survivor benefit such spouse would have received under the joint and 50% survivor annuity option.  This amount will be calculated assuming the executive would have commenced benefit payments in that form on the first day of the month following the later of his or her death or attainment of age 62.  If the executive is eligible for early retirement, the death benefit will be calculated based on the survivor benefit the spouse would have received as of the earliest commencement date.  Distribution will be made to the executive’s surviving spouse as soon as administratively practicable after the executive’s death.  If the executive is not married, then no death benefit will be paid.  If an executive dies after his or her SERP benefit has commenced to be paid, then any death benefit will be governed by the form of payment elected by the executive.

2010 Nonqualified Deferred Compensation

The following table provides information for each of the Named Executive Officers regarding aggregate executive and Company contributions and aggregate earnings for 2010 and year-end account balances under the Deferred Compensation Plan.

Name	Executive Contributions in 2010 1		Registrant Contributions in 2010 2		Aggregate Earnings in 2010 3		Aggregate Withdrawals/ Distributions			Aggregate Balance at December 31, 2010 5
Stephen P. Reynolds	$	90,116	$	308,298	$	224,250	$	--		$	3,991,754
Kimberly J. Harris		--		--		12,850		--			240,521
Bertrand A. Valdman		27,455		19,750		21,949		--			352,237
Eric M. Markell		26,062		18,000		19,802		--			381,739
James W. Eldredge		6,932		5,103		49,542		--			937,308
Donald E. Gaines		4,898		3,484		16,218		--			310,966
Jennifer L. O’Connor 4		4,742		5,857		15,920		363,099	4		--

_______________

1	The amount in this column reflects elective deferrals by the executive of salary, annual incentive compensation or LTI Plan awards paid in 2010.  Deferred salary amounts are: Mr. Reynolds, $55,000; Ms. Harris, $0; Mr. Valdman, $26,333; Mr. Markell, $24,000; Mr. Eldredge, $6,932; Mr. Gaines, $4,898; and Ms. O’Connor, $4,742. Deferred incentive compensation amounts are: Mr. Reynolds, $35,116; Ms. Harris, $0; Mr. Valdman, $1,121; Mr. Markell, $2,062; Mr. Eldredge, $0; Mr. Gaines, $0; and Ms. O’Connor, $0.  The amounts are also included in the applicable column of the “Summary Compensation” table for 2010.
2	The amount reported in this column reflects contributions by PSE consisting of the Annual Investment Plan Restoration Amount and Annual Cash Balance Restoration Amount described below. For Mr. Reynolds, the amount also includes $242,086 in additional contributions by PSE to the Deferred Compensation Plan in lieu of Mr. Reynolds’ participation in the SERP.  These amounts are also included in the total amounts shown in the All Other Compensation column of the “Summary Compensation” table for 2010.
3	The amount in this column for each executive reflects the change in value of investment tracking funds.  Above market earnings on these amounts are included in the Change in Pension Value and Nonqualified Deferred Compensation Earnings column of the “Summary Compensation” table for 2010.
4	Ms. O’Connor voluntarily resigned in October 2010 and per the terms of the plan for a participant not eligible for retirement, received a distribution of the entire account balance.
5	Of the amounts in this column, the following amounts have also been reported in the “Summary Compensation” table for 2010, 2009, and 2008.

Name	Reported for 2010		Reported for 2009		Reported for 2008
Stephen P. Reynolds	$	428,218	$	512,237	$	397,801
Kimberly J. Harris		1,979		3,671		--
Bertrand A. Valdman		48,295		63,211		58,870
Eric M. Markell		46,901		58,122		45,541
James W. Eldredge		19,664		--		--
Donald E. Gaines		10,880		--		--
Jennifer L. O’Connor		12,999		31,339		26,791

Deferred Compensation Plan

The Named Executive Officers are eligible to participate in the Deferred Compensation Plan and may defer up to 100% of base salary, annual incentive compensation and LTI Plan grants.  In addition, each year, executives are eligible to receive Company contributions to restore benefits not available to them under the Company's tax-qualified plans due to limitations imposed by the Internal Revenue Code.  The Annual Investment Plan Restoration Amount equals the additional matching and any other employer contribution under the 401(k) plan that would have been credited to an electing executive’s 401(k) plan account if the Internal Revenue Code limitations were not in place and if deferrals under the Deferred Compensation Plan were instead made to the 401(k) plan.  The Annual Cash Balance Restoration Amount equals the actuarial equivalent of any reductions in an executive’s accrued benefit under the Retirement Plan due to Internal Revenue Code limitations or as a result of deferrals under the Deferred Compensation Plan.  An executive must generally be employed on the last day of the year to receive these Company contributions, unless he or she retires or dies during the year in which case the Company will contribute a prorated amount.

Mr. Reynolds does not participate in the SERP.  In lieu of such participation, each year Mr. Reynolds’ account under the Deferred Compensation Plan is credited with an amount equal to 15% of Mr. Reynolds’ base salary and annual bonus for the preceding year.

The Named Executive Officers choose how to credit deferred amounts among three investment tracking funds.  The tracking funds mirror performance in major asset classes of bonds, stocks, and interest crediting.  The tracking funds differ from the investment funds offered in the 401(k) plan.  The 2010 calendar year returns of these tracking funds were:

Vanguard Total Bond Market Index	6.58%
Vanguard 500 Index	14.91%
Interest Crediting Fund	5.68%

The Named Executive Officers may change how deferrals are allocated to the tracking funds at any time.  Changes generally become effective as of the first trading day of the following calendar quarter.

The Named Executive Officers generally may choose how and when to receive payments under the Deferred Compensation Plan.  There are three types of in-service withdrawals.  First, an executive may choose an interim payment of deferred amounts by designating a plan year for payment at the time of his or her deferral election.  The interim payment is made in a lump sum within 60 days after the last day of the designated plan year, which must be at least two years following the plan year of the deferral.  Second, an in-service withdrawal may also be made to an executive upon a qualifying hardship event and demonstrated need.  Third, only with respect to amounts deferred and vested prior to 2005, the executive may elect an in-service withdrawal for any reason by paying a 10% penalty.  Payments upon termination of employment depend on whether the executive is then eligible for retirement.  If the executive's termination occurs prior to his or her retirement date (generally the earlier of attaining age 62 or age 55 with five years of credited service), the executive will receive a lump sum payment of his or her account balance.  If the executive’s termination occurs after his or her retirement date, the executive may choose to receive payments in a lump sum or via one of several installment options (fixed amount, specified amount, annual or monthly installments, of up to 20 years).  Mr. Reynolds, Mr. Markell and Mr. Eldredge are the only Named Executive Officers currently retirement eligible under the Deferred Compensation Plan.

Potential Payments Upon Termination or Change in Control

The “Estimated Potential Incremental Payments Upon Termination or Change in Control” table reflects the estimated amount of incremental compensation payable to each of the Named Executive Officers in the event of (i) an involuntary termination without cause or by the executive for good reason not in connection with a change in control; (ii) a change in control, (iii) an involuntary termination without cause or for good reason in connection with a change in control, including the merger; (iv) retirement; (v) disability; or (vi) death.  Ms. O’Connor voluntarily resigned in October 2010 and was not entitled to termination or change in control benefits at December 31, 2010.

Certain Company benefit plans provide incremental benefits or payments in the event of certain terminations of employment.  In addition, each Named Executive Officer, other than Mr. Reynolds, entered into an Amended and Restated Executive Employment Agreement with the Company in March 2009, which provides for benefits or payments upon certain terminations of employment from the Company following the merger or a subsequent change in control.  Mr. Reynolds’ employment agreement provides for certain benefits and payments following a termination of employment by the Company without cause or by Mr. Reynolds with good reason.  The only benefit payable to the Named Executive Officers solely upon a change in control is accelerated vesting of LTI Plan awards, described below.

Disability and Life Insurance Plans

If a Named Executive Officer’s employment terminates due to disability or death, the executive or his or her estate will receive benefits under the PSE disability plan or life insurance plan available generally to all salaried employees.  These disability and life insurance amounts are not reflected in the table below.  The Named Executive Officer is also eligible to receive supplemental disability and life insurance.  The supplemental monthly disability coverage is 65% of monthly base salary and target incentive pay, reduced by (i) amounts receivable under the PSE disability plan generally available to salaried employees and (ii) certain other income benefits.  The supplemental life insurance benefit is provided at two times base salary and target annual incentive bonus if the executive dies while employed by PSE with a reduction for amounts payable under the applicable group life insurance policy.

LTI Plan Awards

If a Named Executive Officer’s employment terminates due to disability or death, the executive or his or her estate will be paid a pro-rata portion of LTI Plan awards that were granted in a prior year.  In the case of retirement at normal retirement age or approved early retirement, pro-rata LTI Plan awards will be paid in the first quarter following the year of retirement, based on performance through the prior year.  In the event of a change in control, outstanding LTI Plan awards will be paid at the higher of (i) target performance or (ii) actual performance achieved during the performance cycle ending with the fiscal quarter that precedes the change of control.

Employment Agreement with Mr. Reynolds

Puget Energy and Puget Sound Energy (together, the “Company”) entered into an employment agreement with Mr. Reynolds as of January 1, 2002 to secure his services as Chief Executive Officer and President.  The agreement had an initial term of three years after which time it automatically renewed for one-year terms unless notice of termination was given by either party at least 180 days prior to the expiration of the then current term, which notice Mr. Reynolds provided in June 2010.  In connection with Mr. Reynolds’ retirement as CEO, his employment agreement terminated effective as of February 28, 2011.  During the term of the employment agreement, and effective as of December 31, 2009, Mr. Reynolds agreed to waive all change in control payments and benefits that may otherwise be payable to him on or after December 31, 2009 and for which he was previously eligible under his employment agreement.  During the term of the employment agreement, if the Company had terminated Mr. Reynolds’ employment without cause, or Mr. Reynolds had terminated his employment with good reason, Mr. Reynolds would have received an amount equal to two times his then current annual base salary and target annual incentive bonus.

In the event of termination by death or disability, Mr. Reynolds would have been eligible to receive his annual incentive bonus at the target level pro-rated through the date of termination (which amount is not disclosed in the table below since it was earned for 2010) and continued group medical, dental, disability and life insurance benefits as are provided to the other Named Executive Officers under the terms of their employment agreements.  Mr. Reynolds also would have received a cash payment equal to any excise taxes imposed by Section 4999 of the Internal Revenue Code due to payments received under the employment agreement or any other payment or benefit from the Company, plus the income taxes payable by him resulting from this cash payment.

The employment agreement contains a noncompetition covenant pursuant to which Mr. Reynolds commits that during his employment with the Company and for a period of two years following his voluntary termination without good reason, he will not perform services for any person or entity selling or distributing electric power or natural gas in Washington, Oregon or Idaho, unless the Company consents in writing.  The Company may enforce this covenant through injunctive relief or other appropriate remedies. The employment agreement also contains an indemnification clause in favor of Mr. Reynolds.  The Company commits to defend, indemnify and hold harmless Mr. Reynolds from all liabilities in connection with his service.  As part of that commitment, the Company will cover him under the Company’s directors’ and officers’ liability insurance for six years following his termination of employment.

Under Mr. Reynolds’ employment agreement, “cause” and “good reason” were defined as follows:

Cause generally means the Board’s finding that Mr. Reynolds willfully engaged in illegal or grossly wrongful misconduct that results in financial detriment materially and demonstrably injurious to the Company. Cause does not include any act or omission believed to be in good faith and in the best interests of the Company.

Good Reason generally includes the following actions by the Company: (i) assigning duties inconsistent with, or taking actions in diminution of, Mr. Reynolds’ position (including status, offices, titles and reporting requirements), authority, duties or responsibility under the employment agreement; (ii) failing to comply with the provisions of the employment agreement; (iii) requiring that Mr. Reynolds be based at any location other than the Company’s corporate headquarters or relocating the corporate headquarters more than 25 miles from Bellevue, Washington; and (iv) failing to assign the employment agreement to a successor or the successor failing to assume and be bound by it explicitly. Good Reason is triggered on a reasonable determination by Mr. Reynolds that any of the above events has occurred.

Employment Agreements with Other Named Executive Officers

In March 2009, PSE entered into Amended and Restated Executive Employment Agreements (Employment Agreements) with each of Ms. Harris, Mr. Valdman, Mr. Markell, Mr. Eldredge, Mr. Gaines, and Ms. O’Connor (Executives), the terms of which are the same for all six Executives and which amended and restated existing Amended and Restated Change of Control Agreements between the Company and each of the Executives.  The Employment Agreements provide for an employment period of two years after the completion of the February 2009 merger (Employment Period) and generally provide benefits similar to those provided under the previous Change of Control Agreements.  In the event of termination of employment prior to the second anniversary of the merger or termination of employment within two years of a change in control that follows the Employment Period, an Executive is eligible to receive the payments described below, except for Ms. O’Connor who voluntarily resigned.  A change in control generally means a person (or group of persons) (with certain exceptions set forth in the Employment Agreements) acquires (i) beneficial ownership of more than 55% of the total combined voting power of the Company’s securities outstanding immediately after such acquisition (other than through a registered public offering) or (ii) all or substantially all of the Company’s assets.

Payments upon Involuntary Termination without Cause or for Good Reason

If an Executive’s employment is terminated without cause by the Company or is terminated by the Executive for good reason during the Employment Period, the Executive is eligible to receive the following compensation and benefits:

·   Three times the sum of annual base salary and annual incentive bonus for the year in which termination occurs;

·   Pro-rated annual incentive bonus for the year in which termination occurs (Annual Bonus).  Since this amount was earned for 2010, no amount is show in the table below;

·   Supplemental retirement benefit equal to the difference between (x) the actuarial equivalent of the amount the Executive would have received under the Retirement Plan and the SERP had his or her employment continued until the end of the Employment Period, and (y) the actuarial equivalent of the amount the Executive actually receives or is entitled to receive under the Retirement Plan and SERP;

·   Merger performance bonus equal to the amount the Executive would have received had his or her employment continued until each of the first and second anniversaries of the merger.  In the event of termination after the first anniversary of the merger but on or prior to the second anniversary of the merger, the Executive is eligible to receive the merger performance bonus that would have been payable as of the second anniversary; and

·   Continued group medical, dental, disability and life insurance benefits to the Executive and his or her family.  Benefits will be paid by the Company while the Executive is eligible for COBRA and thereafter by reimbursement of payments made by the Executive for such coverage (including related tax amounts), except that if the Executive becomes re-employed with another employer and is eligible to receive medical or other welfare benefits under another employer-provided plan, the medical and other welfare benefits under the Employment Agreement will become secondary to those provided by the other employer (the foregoing benefit is referred to as Health and Welfare Benefit Continuation).

Under the Employment Agreements, “cause” and “good reason” have the following meanings:

Cause generally means (i) the willful and continued failure by the Executive to substantially perform the Executive’s duties with the Company (other than any such failure resulting from incapacity due to physical or mental illness) for a period of 30 days after written notice of demand for substantial performance has been delivered to the Executive or (ii) the Executive’s willfully engaging in gross misconduct materially and demonstrably injurious to the Company, as determined by the Board after notice to the executive and opportunity for a hearing.  No act or failure to act on the Executive’s part is considered “willful” unless the Executive has acted or failed to act with an absence of good faith and without a reasonable belief that the Executive’s action or failure to act was in the best interests of the Company.

Good Reason generally means (i) the assignment of the Executive to a non-officer position with the Company, which the parties agree would constitute a material reduction in the Executive’s authority, duties or responsibilities; (ii) a material diminution in the Executive’s total compensation opportunities under the Employment Agreement; (iii) the Company’s requiring the Executive to be based at any location that represents a material change from the Executive’s location in the Seattle/Bellevue metropolitan area, unless the Executive consents to the relocation; or (iv) a material breach of the Employment Agreement by the Company, provided that, in any of the foregoing, the Company has not remedied the alleged violation(s) within 60 days of notice from the Executive.

Payments upon Retirement, Disability or Death

If an Executive’s employment terminates due to voluntary retirement after having attained age 55 with a minimum of five years of service to the Company, a pro-rated Annual Bonus is payable.  The bonus is payable at the time the Executive otherwise would have received the payment had employment continued, based on the Company’s actual achievement of performance goals.

If an Executive’s employment terminates due to disability or death, the Executive is eligible to receive the following compensation and benefits:

·   Pro-rated Annual Bonus; and

·   Health and Welfare Benefit Continuation.

In addition, upon termination for any of the foregoing reasons during the Employment Period, other than by reason of retirement, the Executive is eligible to receive the perquisite of financial planning.

Except as otherwise described above, payments of salary and bonus will be paid after the date of termination, subject to the Executive’s timely execution of a general waiver and release of claims.

The Employment Agreements also contain noncompetition and anti-solicitation provisions that restrict the Executive during the Employment Period and for twelve months thereafter from, respectively, engaging in activities related to selling or distributing electric power or natural gas in Washington or soliciting others to leave the Company or causing them to be hired from the Company by another entity.  The Employment Agreements contain a non-disparagement clause and a confidentiality clause pursuant to which the Executives must keep confidential all secret or confidential information, knowledge or data relating to the Company and its affiliates obtained during their employment.  The Executives may not disclose any such information, knowledge or data after their respective terminations of employment unless PSE consents in writing or as required by law.

If any payments paid or payable in connection with the February 2009 merger, whether paid or payable pursuant to the Employment Agreements or otherwise, are characterized as “excess parachute payments” within the meaning of Section 280G of the Internal Revenue Code, then the Company will make a cash payment to or on behalf of the Executive equal to any excise taxes imposed by Section 4999 of the Internal Revenue Code on such payments, plus the income taxes payable by him or her resulting from this cash payment.  If a change in control occurs subsequent to the merger while the Company’s stock is not traded on an established securities market or otherwise immediately before such change in control, then the Executive will agree to execute a waiver of any “excess parachute payments” that would result from such payments, provided that the Company agrees to seek, but is not required to obtain, shareholder approval of the amount payable in connection with termination of employment, in which case the waived amounts will be restored to the Executive.

Estimated Potential Incremental Payments Upon Termination or Change in Control

The amounts shown in the table below assume that the termination of employment or change in control was effective as of December 31, 2010.  The amounts below are estimates of the incremental amounts that would be paid out to the Named Executive Officer upon a termination of employment or change in control.  Actual amounts payable can only be determined at the time of a termination of employment or change in control.

	Involuntary Termination w/o Cause or for Good Reason		Upon Change in Control		After Change in Control Involuntary Termination w/o Cause or for Good Reason 1		Retirement		Disability		Death
Stephen P. Reynolds
Cash Severance (salary and/or annual incentive)	$	3,052,500	$	--	$	--	$	--	$	--	$	--
Long Term Incentive Plan		--		2,877,930		2,877,930		295,086		295,086		295,086
Benefits  (continuation)3		--		--		49,171		--		49,171		49,171
Supplemental Life Insurance		--		--		--		--		--		2,452,500
Excise Tax Gross-Up		--		--		--		--		--		--
Total Estimated Incremental Value	$	3,052,500	$	2,877,930	$	2,927,101	$	295,086	$	344,257	$	2,796,757
Kimberly J. Harris
Cash Severance (salary and/or annual incentive)	$	n/a	$	--	$	3,774,000	$	--	$	--	$	--
Long Term Incentive Plan		--		812,592		812,592		--		138,864		138,864
Merger Performance Bonus		--		--		680,000		--		--		--
SERP (additional years of credited service) 2		--		--		881,921		--		--		--
Benefits (continuation) 3		n/a		--		31,533		--		31,533		31,533
Supplemental Life Insurance		n/a		--		--		--		--		1,916,000
Excise Tax Gross-Up		n/a		--		1,857,949		--		--		--
Total Estimated Incremental Value	$	n/a	$	812,592	$	8,037,995	$	--	$	170,397	$	2,086,397
Bertrand A. Valdman
Cash Severance (salary and/or annual incentive)	$	n/a	$	--	$	1,896,014	$	--	$	--	$	--
Long Term Incentive Plan		--		891,618		891,618		--		152,372		152,372
Merger Performance Bonus		--		--		395,000		--		--		--
SERP (additional years of credited service)2		--		--		504,079		--		--		--
Benefits (continuation) 3		n/a		--		45,824		--		45,824		45,824
Supplemental Life Insurance		n/a		--		--		--		--		869,000
Excise Tax Gross-Up		n/a		--		--		--		--		--
Total Estimated Incremental Value	$	n/a	$	891,618	$	3,732,535	$	--	$	198,196	$	1,067,196
Eric M. Markell
Cash Severance (salary and/or annual incentive)	$	n/a	$	--	$	1,728,000	$	--	$	--	$	--
Long Term Incentive Plan		--		812,592		812,592		138,864		138,864		138,864
Merger Performance Bonus		--		--		360,000		--		--		--
SERP (additional years of credited service) 2		--		--		431,583		-		--		--
Benefits (continuation) 3		n/a		--		47,818		--		47,818		47,818
Supplemental Life Insurance		n/a		--		--		--		--		792,000
Excise Tax Gross-Up		n/a		--		845,406		--		--		--
Total Estimated Incremental Value	$	n/a	$	812,592	$	4,225,399	$	138,864	$	186,682	$	978,682
James W. Eldredge
Cash Severance (salary and/or annual incentive)	$	n/a	$	--	$	921,564	$	--	$	--	$	--
Long Term Incentive Plan		--		225,156		225,156		38,482		38,482		38,482
Merger Performance Bonus		--		--		219,420		--		--		--
SERP (additional years of credited service) 2		n/a		--		--		-		--		--
Benefits (continuation) 3		n/a		--		38,981		--		38,981		38,981
Supplemental Life Insurance		n/a		--		--		--		--		394,956
Excise Tax Gross-Up		n/a		--		--		--		--		--
Total Estimated Incremental Value	$	n/a	$	225,156	$	1,405,121	$	38,482	$	77,463	$	472,419
Donald E. Gaines
Cash Severance (salary and/or annual incentive)	$	n/a	$	--	$	891,135	$	--	$	--	$	--
Long Term Incentive Plan		--		217,747		217,747		--		37,220		37,220
Merger Performance Bonus		--		--		212,175		--		--		--
SERP (additional years of credited service) 2		n/a		--		--		--		--		--
Benefits (continuation) 3		n/a		--		24,265		--		24,265		24,265
Supplemental Life Insurance		n/a		--		--		--		--		381,915
Excise Tax Gross-Up		n/a		--		--		--		--		--
Total Estimated Incremental Value	$	n/a	$	217,747	$	1,345,322	$	--	$	61,485	$	443,400

_______________

1	If the termination of employment had been in connection with the merger, the Excise Tax Gross-Up amounts reported above would have been payable.  If the termination of employment had followed a change in control other than the merger, the Named Executive Officers (other than Mr. Reynolds) would not have received an Excise Tax Gross-Up.
2	SERP values are shown as the estimated incremental value that the Named Executive Officer would receive at age 62 as a result of the termination event shown in the column, relative to the vested benefit as of December 31, 2010. These values are based on interest rate and mortality rate assumptions consistent with those used in the Company’s financial statements.
3	Benefits (continuation) reflects the value of continued medical, dental, disability and life insurance benefits as well as financial planning benefit in the amount of $5,000 for each Named Executive Officer, except $2,500 for Mr. Eldredge and Mr. Gaines.

Director Compensation for Fiscal Year 2010

The following table sets forth information regarding compensation for each of the Company’s nonemployee directors for 2010.  The directors named in the table are those persons who received compensation from the Company in 2010 for service as a nonemployee director.  Directors who are employed by the Company or by the Company’s investor-owners are not paid separately for their service and thus are not named in the table below.  The directors who served in 2010 and were employed by the Company’s investor-owners are: Graeme Bevans, Andrew Chapman, Alan James, Alan Kadic, Christopher Leslie, William McKenzie, Benjamin Hawkins, Lincoln Webb, Mark Wiseman and Mark Wong who is no longer a director.  Stephen Reynolds was employed by the Company and also served as a director during 2010.

As described in further detail below, the Company’s nonemployee director compensation program in 2010 consisted of quarterly retainer cash fees of $20,000.  Additional quarterly retainer amounts associated with serving as Chair of the Board, chairing Board committees and serving on the Audit Committee and meeting fees were also paid in cash.

Name	Fees Earned or Paid In Cash 1		Nonqualified Deferred Compensation Earnings 2		Total
William Ayer	$	156,800	$	3,417	$	160,217
Herbert Simon		112,400		2,401		114,801
Christopher Trumpy		112,400		--		112,400

_______________

1	Represents director compensation earned and paid in cash including amounts deferred under our deferred compensation plan for non-employee directors.
2	Represents earnings accrued to deferred compensation considered to be above market.

Nonemployee Independent Director Compensation Program.  The 2010 nonemployee independent director compensation program is based on the principles that the level of nonemployee director compensation should be based on Board and committee responsibilities and should be competitive with comparable companies.

The 2010 compensation program for independent nonemployee directors was as follows:

· A base cash quarterly retainer fee of $20,000

· $1,600 for attendance at each in-person Board and committee meeting, and $800 for each telephonic meeting lasting 60 minutes or less,

In 2010, nonemployee independent directors were paid the following additional cash quarterly retainer fees:

· Independent Board Chairman, $10,000

· Chair of the Audit Committee, $2,500

· Chair of the Compensation and Leadership Development Committee, $2,000

· Chair of the Governance and Public Affairs Committees, $1,500

· Each member of the Audit Committee other than the chair, $1,000

All quarterly retainer and meeting attendance fees were paid on the last business day of March, June, September and December. Nonemployee directors were reimbursed for actual travel and out-of-pocket expenses incurred in connection with their services.

Nonemployee independent directors are eligible to participate in the Company’s matching gift program on the same terms as all Puget Energy employees.  Under this program, the Company matches up to a total of $300 a year in contributions by a director to non-profit organizations that have IRS 501(c)(3) tax exempt status and are located in and served the people of PSE’s service territory in Washington State.

Deferral of Compensation.  Nonemployee independent directors may choose to elect to defer all or a part of their cash fees under the Company’s Deferred Compensation Plan for Nonemployee Directors.  Nonemployee directors may allocate these deferrals into one or more “measurement funds,” which include an interest crediting fund, an equity index fund and a bond index fund.  Nonemployee independent directors are permitted to make changes in measurement fund allocations quarterly.  None of the independent board members deferred any director fees during 2010.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SHAREHOLDER MATTERS

Security Ownership of Directors, Executive Officers and Certain Beneficial Owners

The following tables show the number of shares of common stock beneficially owned as of December 31, 2010 by each person or group that we know owns more than 5.0% of Puget Energy’s and PSE’s common stock.  No director, executive officer or executive officer named in the Summary Compensation Table in Item 11 of Part III of this report owns any of the outstanding shares of common stock of Puget Energy or PSE.  Puget Equico LLC and its affiliates beneficially own 100.0% of the outstanding common stock of Puget Energy.  Puget Energy holds 100.0% of the outstanding common stock of PSE.  Percentage of beneficial ownership is based on 200 shares of Puget Energy common stock and 85,903,791 shares of Puget Sound Energy common stock outstanding as of December 31, 2010.

Beneficial Ownership Table of Puget Energy and PSE

	Number of Beneficially Owned Shares
Name	Puget Energy	PSE
Puget Equico LLC and affiliates	200 1, 2	--
Puget Energy	--	85,903,791 3

_______________

1	Information presented above and in this footnote is based on Amendment No. 2 to Schedule 13D/A filed on February 13, 2009 (the Schedule 13D) by Puget Equico LLC (Puget Equico), Puget Intermediate Holdings Inc. (Puget Intermediate), Puget Holdings LLC (Puget Holdings and together with Puget Intermediate, the Parent Entities), Macquarie Infrastructure Partners I (formerly MIP Padua Holdings GP) (MIP), Macquarie Infrastructure Partners II (formerly MIP Washington Holdings, L.P.) (MIP II), Macquarie FSS Infrastructure Trust (MFIT), Padua MG Holdings LLC (PMGH) CPP Investment Board (USRE II) Inc. (CPP), 6860141 Canada Inc. as trustee for British Columbia Investment Management Corporation (bcIMC), PIP2PX (Pad) Ltd. (PIP2PX) and PIP2GV (Pad) Ltd. (PIP2GV and together with MIP, MIP II, MFIT, PMGH, CPP, bcIMC and PIP2PX, the Investors). Puget Equico is a wholly-owned subsidiary of Puget Intermediate, Puget Intermediate is a wholly-owned subsidiary of Puget Holdings and the Investors are the direct or indirect owners of Puget Holdings.  The Parent Entities and the Investors are the direct or indirect owners of Puget Equico. Although the Parent Entities and the Investors do not own any shares of Puget Energy directly, Puget Equico, the Parent Entities and the Investors may be deemed to be members of a “group,” within the meaning of Section 13(d)(3) of the Securities Exchange Act of 1934, as amended. Accordingly, each such entity may be deemed to beneficially own the 200 shares of Puget Energy common stock owned by Puget Equico.  Such shares of common stock constitute 100.0% of the issued and outstanding shares of common stock of Puget Energy.  Under Section 13(d)(3) of the Exchange Act and based on the number of shares outstanding, Puget Equico, the Parent Entities and the Investors may be deemed to have shared power to vote and shared power to dispose of such shares of Puget Energy common stock that may be beneficially owned by Puget Equico.  However, each of Puget Equico, the Parent Entities and the Investors expressly disclaims beneficial ownership of such shares of common stock other than those shares held directly by such entity.  According to the Schedule 13D, as of February 13, 2009:
	·The address of the principal office of Puget Holdings, Puget Intermediate and Puget Equico is the PSE Building, 10885 NE 4th Street, Bellevue, WA 98009.
	·The address of the principal office of MIP and MIP II is 125 West 55th Street, Level 22, New York, NY 10019.
	·The address of the principal office of MFIT is Level 11, 1 Martin Place, Sydney, Australia NSW 2000.
	·The address of the principal office of PMGH is 125 West 55th Street, Level 22, New York, NY 10019.
	·The address of the principal office of CPP is One Queen Street East, Suite 2600, P.O. Box 101, Toronto, Ontario, Canada M5C 2W5.
	·The address of the principal office of bcIMC is Sawmill Point, Suite 301-2940 Jutland Road, Victoria, British Columbia, Canada V8T 5K6.
	·The address of the principal office of PIP2PX and PIP2GV is 340 Terrace Building, 9515-107 Street, Edmonton, Alberta, Canada T5K 2C3.
2	Pursuant to that certain Pledge Agreement dated as of February 6, 2009, made by Puget Equico LLC to Barclays Bank PLC, as collateral agent and that certain Joinder Agreement dated December 6, 2010 by and among Barclays Bank PLC, as collateral agent, Barclays Bank PLC, as facility agent, Puget Energy, Puget Equico and Wells Fargo Bank, National Association as trustee, the outstanding stock of Puget Energy held by Puget Equico was pledged by Puget Equico to secure the obligations of Puget Energy under (a) the Credit Agreement dated as of May 16, 2008 among Puget Merger Sub Inc., as Borrower, Barclays Bank PLC, as Facility Agent, the other agents party thereto, and the lender party thereto (which agreement was subsequently assumed by Puget Energy) and (b) the senior secured notes issued on December 6, 2010.
3	Pursuant to that certain Borrower’s Security Agreement dated as of February 6, 2009, and that certain Joinder Agreement dated December 6, 2010 by and among Barclays Bank PLC, as collateral agent, Barclays Bank PLC, as facility agent, Puget Energy, Puget Equico and Wells Fargo Bank, National Association as trustee, the outstanding stock of PSE held by Puget Energy was pledged by Puget Energy to secure its obligations under (a) the Credit Agreement dated as of May 16, 2008, as amended, among Puget Merger Sub Inc,. as Borrower, Barclays Bank PLC, as Facility Agent, the other agents party thereto, and the lender party thereto (which agreement was subsequently assumed by Puget Energy) and (b) the senior secured notes issued on December 6, 2010.

Equity Compensation Plan Information

In connection with the merger of Puget Energy with Puget Holdings, which was completed on February 6, 2009, all compensation plans under which equity securities were authorized for issuance have been terminated, except the LTI Plan.  Following the merger, only non-equity awards that can be settled solely in cash are made under the LTI Plan.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Transactions with Related Persons

Our Boards of Directors have adopted a written policy for the review and approval or ratification of related person transactions.  Under the policy, our directors and executive officers are expected to disclose to our Chief Compliance Officer the material facts of any transaction that could be considered a related person transaction promptly upon gaining knowledge of the transaction.  A related person transaction is generally defined as any transaction required to be disclosed under Item 404(a) of Regulation S-K, the SEC’s related person transaction disclosure rule.

Any transaction reported to the Chief Compliance Officer will be reviewed according to the following procedures:

· If the Chief Compliance Officer determines that disclosure of the transaction is not required under the SEC’s related person transaction disclosure rule, the transaction will be deemed approved and will be reported to the Audit Committee.

· If disclosure is required, the Chief Compliance Officer will submit the transaction to the Chair of the Audit Committee who will review and, if authorized, will determine whether to approve or ratify the transaction.  The Chair is authorized to approve or ratify any related person transaction involving an aggregate amount of less than $1.0 million or when it would be impracticable to wait for the next Audit Committee meeting to review the transaction.

· If the transaction is outside the Chair’s authority, the Chair will submit the transaction to the Audit Committee for review and approval or ratification.

When determining whether to approve or ratify a related person transaction, the Chair of the Audit Committee or the Audit Committee, as applicable, will review relevant facts regarding the related person transaction, including:

· The extent of the related person’s interest in the transaction;

· Whether the terms are comparable to those generally available in arms’ length transactions; and

· Whether the related person transaction is consistent with the best interests of the Company.

If any related person transaction is not approved or ratified, the Committee may take such action as it may deem necessary or desirable in the best interests of the Company and its shareholders.

Kimberly Harris, who serves as the President and Chief Executive Officer, as well as a director of Puget Energy and PSE, is married to Kyle Branum, a principal at the law firm Riddell Williams P.S. since 2008.  Riddell Williams or its predecessor firms have been one of PSE’s primary law firms for nearly 50 years.  In 2010, Riddell Williams was paid $1.41 million for legal services provided to PSE.  Mr. Branum is among the lawyers at Riddell Williams who provide legal services to PSE.  This work was performed under the direct supervision of the office of the general counsel and the compensation arrangements were comparable to other regional law firms providing legal services to PSE.

Board of Directors and Corporate Governance

Independence of the Board

The Boards of Puget Energy and PSE have reviewed the relationships between Puget Energy and PSE (and their respective subsidiaries) and each of their respective directors.  Based on this review, the Boards have determined that of the members constituting the Boards, William Ayer (member of the Boards of both Puget Energy and PSE) and Herbert Simon (member of the Board of PSE) are independent under the New York Stock Exchange (NYSE) corporate governance listing standards and also meet the definition of an “Independent Director” under the Company’s Amended and Restated Bylaws.  Under the Amended and Restated Bylaws of Puget Energy and PSE, an Independent Director is a director who: (a) shall not be a member of Puget Holdings (referred to as a Holdings Member) or an affiliate of any Holdings Member (including by way of being a member, stockholder, director, manager, partner, officer or employee of any such member), (b) shall not be an officer or employee of PSE, (c) shall be a resident of the state of Washington, and (d) if and to the extent required with respect to any specific director, shall meet such other qualifications as may be required by any applicable regulatory authority for an independent director or manager.  The Company’s definition of “Independent Director” is available in the Corporate Governance Guidelines at www.pugetenergy.com.

In making these independence determinations, the Boards have established a categorical standard that a director’s independence is not impaired solely as a result of the director, or a company for which the director or an immediate family member of the director serves as an executive officer, making payments to PSE for power or natural gas provided by PSE at rates fixed in conformity with law or governmental authority, unless such payments would automatically disqualify the director under the NYSE’s corporate governance listing standards.  The Board has also established a categorical standard that a director’s independence is not impaired if a director is a director, employee or executive officer of another company that makes payments to or receives payments from Puget Energy, PSE or any of their affiliates, for property or services in an amount which is less than the greater of $1.0 million or one percent of such other company’s consolidated gross revenue, determined for the most recent fiscal year.  These categorical standards will not apply, however, to the extent that Puget Energy or PSE would be required to disclose an arrangement as a related person transaction pursuant to Item 404 of Regulation S-K.

The Boards considered all relationships between its directors and Puget Energy and PSE (and there respective subsidiaries), including some that are not required to be disclosed in this report as related-person transactions.  Messrs. Ayer and Simon serve as directors or officers of, or otherwise have a financial interest in, entities that make payments to PSE for energy services provided to those entities at tariff rates established by the Washington Utilities and Transportation Commission.  These transactions fall within the first categorical independence standard described above.  In addition, PSE has entered into transactions with entities for whom Mr. Simon serves as a director or officer, or in which he otherwise has a financial interest, that involve amounts that are less than the greater of $1.0 million or 1% of those entities’ consolidated gross revenue.  These transactions fall within the second categorical standard described above.  Because these relationships either fall within the Board’s categorical independence standards or involve an amount that is not material to Puget Energy or the other entity, the Board has concluded that none of these relationships impair the independence of the applicable directors.

Executive Sessions

Non-management directors meet in executive session on a regular basis, generally on the same date as each scheduled Board meeting.  Mr. Ayer, who is not a member of management, presides over the executive sessions. Interested parties may communicate with the non-management directors of the Board through the procedures described in Item 10 of Part III of this annual report under the section “Communications with the Board.”

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The aggregate fees billed by PricewaterhouseCoopers LLP, the Company’s independent registered public accounting firm, for the years ended December 31 were as follows:

	2010				2009
(Dollars in Thousands)	Puget Energy		PSE		Puget Energy		PSE
Audit fees 1	$	1,558	$	1,453	$	1,638	$	1,518
Audit related fees 2		332		264		297		289
Tax fees 3		50		50		61		61
Total	$	1,940	$	1,767	$	1,996	$	1,868

_______________

1	For professional services rendered for the audit of Puget Energy’s and PSE’s annual financial statements and reviews of financial statements included in the Company’s Forms 10-Q.  The 2010 fees are estimated and include an aggregate amount of $0.8 million billed to Puget Energy and PSE through December 2010.
2	Consists of employee benefit plan audits, work performed in connection with registration statements and other regulatory audits.
3	Consists of tax consulting and tax return reviews.

The Audit Committee of the Company has adopted policies for the pre-approval of all audit and non-audit services provided by the Company’s independent registered public accounting firm.  The policies are designed to ensure that the provision of these services does not impair the firm’s independence.  Under the policies, unless a type of service to be provided by the independent registered public accounting firm has received general pre-approval, it will require specific pre-approval by an Audit Committee.  In addition, any proposed services exceeding pre-approved cost levels will require specific pre-approval by an Audit Committee.

The annual audit services engagement terms and fees, as well as any changes in terms, conditions and fees relating to the engagement, are subject to specific pre-approval by the Audit Committee.  In addition, on an annual basis, the Audit Committee grants general pre-approval for specific categories of audit, audit-related, tax and other services, within specified fee levels, that may be provided by the independent registered public accounting firm.  With respect to each proposed pre-approved service, the independent registered public accounting firm is required to provide detailed back-up documentation to the Audit Committee regarding the specific services to be provided.  Under the policies, the Audit Committee may delegate pre-approval authority to one or more of their members.  The member or members to whom such authority is delegated shall report any pre-approval decision to the Audit Committee at its next scheduled meeting.  The Audit Committee does not delegate responsibilities to pre-approve services performed by the independent registered public accounting firm to management.

For 2010 and 2009, all audit and non-audit services were pre-approved.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

a) Documents filed as part of this report:

1) Financial Statements.

2) Financial Statement Schedules.  Financial Statement Schedules of the Company consist of the following:

I. Condensed Financial Information of Puget

II. Valuation of Qualifying Accounts

3) Exhibits

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

PUGET ENERGY, INC.	PUGET SOUND ENERGY, INC.
/s/ Kimberly J. Harris	/s/ Kimberly J. Harris
Kimberly J. Harris	Kimberly J. Harris
President and Chief Executive Officer	President and Chief Executive Officer
Date:  March 4, 2011	Date:  March 4, 2011

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of each registrant and in the capacities and on the dates indicated.

Signature	Title	Date
	(Puget Energy and PSE unless otherwise noted)
/s/ Kimberly J. Harris	President and	March 4, 2011
(Kimberly J. Harris)	Chief Executive Officer
/s/ Bertrand A. Valdman	Senior Vice President and
(Bertrand A. Valdman)	Chief Financial Officer
/s/ James W. Eldredge	Vice President, Controller
(James W. Eldredge)	and Chief Accounting Officer
/s/ William S. Ayer	Chairman and Director
(William S. Ayer)
	Director
(Andrew Chapman)
/s/ Benjamin Hawkins	Director
(Benjamin Hawkins)
/s/ Alan W. James	Director
(Alan W. James)
/s/Alan Kadic	Director
(Alan Kadic)
/s/ Christopher J. Leslie	Director
(Christopher J. Leslie)
/s/ Mary O. McWilliams	Director
(Mary O. McWilliams)
/s/ Christopher Trumpy	Director
(Christopher Trumpy)

/s/ Mark Wiseman	Director
(Mark Wiseman)

/s/ Herbert B. Simon	Director of PSE only
(Herbert B. Simon)

EXHIBIT INDEX

Certain of the following exhibits are filed herewith.  Certain other of the following exhibits have heretofore been filed with the Securities and Exchange Commission and are incorporated herein by reference.

	2.1	Agreement and Plan of Merger, dated October 25, 2007, by and among Puget Energy, Inc., Padua Holdings LLC, Padua Intermediate Holdings Inc. and Padua Merger Sub Inc. (incorporated herein by reference to Exhibit 2.1 to Puget Energy’s Current Report on Form 8-K, dated October 25, 2007, Commission File No. 1-16305).
	3(i).1	Amended Articles of Incorporation of Puget Energy (incorporated herein by reference to Exhibit 3.1 to Puget Energy’s Current Report on Form 8-K, dated February 6, 2009, Commission File No. 1-16305).
	3(i).2	Amended and Restated Articles of Incorporation of Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit 3.2 to Puget Sound Energy’s Current Report on Form 8-K, dated February 6, 2009, Commission File No. 1-4393).
	3(ii).1	Amended and Restated Bylaws of Puget Energy dated February 6, 2009 (incorporated herein by reference to Exhibit 3.3 to Puget Energy’s Current Report on Form 8-K, Commission File No. 1-16305).
	3(ii).2	Amended and Restated Bylaws of Puget Sound Energy, Inc. dated February 6, 2009 (incorporated herein by reference to Exhibit 3.4 to Puget Sound Energy’s Current Report on Form 8-K, Commission File No. 1-4393).
	4.1	Indenture between Puget Sound Energy, Inc. and U.S. Bank National Association (as successor to State Street Bank and Trust Company) defining the rights of the holders of Puget Sound Energy’s senior notes (incorporated herein by reference to Exhibit 4-a to Puget Sound Energy’s Report on Form 10-Q for the quarter ended June 30, 1998, Commission File No. 1-4393).
	4.2	First, Second, Third and Fourth Supplemental Indentures defining the rights of the holders of Puget Sound Energy’s senior notes (incorporated herein by reference to Exhibit 4-b to Puget Sound Energy’s Report on Form 10-Q for the quarter ended June 30, 1998, Commission File No. 1-4393; Exhibit 4.26 to Puget Sound Energy’s Current Report on Form 8-K, dated March 4, 1999, Commission File No. 1-4393; Exhibit 4.1 to Puget Sound Energy’s Current Report on Form 8-K, dated November 2, 2000, Commission File No. 1-4393; and Exhibit 4.1 to Puget Sound Energy’s Current Report on Form 8-K, dated May 28, 2003, Commission File No. 1-4393).
	4.3	Fortieth through Sixtieth Supplemental Indentures defining the rights of the holders of Puget Sound Energy’s Electric Utility First Mortgage Bond (incorporated herein by reference to Exhibits 4.3 through and including 4.23 to Puget Sound Energy’s Registration Statement on Form S-3ASR, filed March 13, 2009, Registration No. 333-157960).
	4.4	Sixty-first through Eighty-seventh Supplemental Indentures defining the rights of the holders of Puget Sound Energy’s Electric Utility First Mortgage Bonds (incorporated herein by reference to Exhibit (4)-j-1 to Registration No. 2-72061; Exhibit (4)-a to Registration No. 2-91516; Exhibit (4)-b to Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 1985, Commission File No. 1-4393; Exhibits (4)(a) and (4)(b) to Puget Sound Energy’s Current Report on Form 8-K, dated April 22, 1986, Commission File No. 1-4393; Exhibit (4)(b) to Puget Sound Energy’s Current Report on Form 8-K, dated September 5, 1986, Commission File No. 1-4393; Exhibit (4)-b to Puget Sound Energy’s Report on Form 10-Q for the quarter ended September 30, 1986, Commission File No. 1-4393; Exhibit (4)-c to Registration No. 33-18506; Exhibit (4)-b to Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 1989, Commission File No. 1-4393; Exhibit (4)-b to Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 1990, Commission File No. 1-4393; Exhibits (4)-d and (4)-e to Registration No. 33-45916; Exhibit (4)-c to Registration No. 33-50788; Exhibit (4)-a to Registration No. 33-53056; Exhibit 4.3 to Registration No. 33-63278; Exhibit 4-c to Puget Sound Energy’s Report on Form 10-Q for the quarter ended June 20, 1998, Commission File No. 1-4393; Exhibit 4.27 to Puget Sound Energy’s Current Report on Form 8-K, dated March 4, 1999, Commission File No. 1-4393; Exhibit 4.2 to Puget Sound Energy’s Current Report on Form 8-K, dated November 2, 2000, Commission File No. 1-4393; Exhibit 4.2 to Puget Sound Energy’s Current Report on Form 8-K, dated May 28, 2003, Commission File No. 1-4393; Exhibit 4.28 to Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2004, Commission File No. 1-4393; Exhibit 4.1 to Puget Sound Energy’s Current Report on Form 8-K, dated May 23, 2005, Commission File No. 1-4393; Exhibit 4.30 to Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2005, Commission File No. 1-4393); Exhibit 4.4 to Post-Effective Amendment No. 2 to Puget Sound Energy’s Registration Statement on Form S-3, filed February 9, 2009, Registration No. 333-132497-01; Exhibit 4.1 to Puget Sound Energy’s Current Report on Form 8-K, dated September 13, 2006, Commission File No. 1-4393; Exhibit 4.1 to Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2007, Commission File No. 1-4393; and Exhibit 4.5 to Post-Effective Amendment No. 2 to Puget Sound Energy’s Registration Statement on Form S-3, filed February 9, 2009, Registration No. 333-132497-01); Exhibit 4.1 to Puget Sound Energy’s Current Report on Form 8-K, dated September 8, 2009, Commission File No. 1-4393.
	4.5	Indenture of First Mortgage, dated as of April 1, 1957, defining the rights of the holders of Puget Sound Energy’s Gas Utility First Mortgage Bonds (incorporated herein by reference to Puget Sound Energy’s Registration Statement on Form S-3ASR, filed March 13, 2009, Registration No. 333-157960).
	4.6	First, Sixth, Seventh and Seventeenth Supplemental Indenture to the Gas Utility First Mortgage, dated as of October 1, 1959, August 1, 1966, February 1, 1967, June 1, 1977 and August 9, 1978, respectively (incorporated herein by reference to Exhibits 4.26 through and including 4.30 to Puget Sound Energy's Registration Statement on Form S-3ASR, filed March 13, 2009, Registration No. 333-157960).
	4.7	Twenty-second Supplemental Indenture to the Gas Utility First Mortgage, dated as of July 15, 1986 (incorporated herein by reference to Exhibit 4-B.20 to Washington Natural Gas Company’s Report on Form 10-K for the fiscal year ended September 30, 1986, Commission File No. 0-951).
	4.8	Twenty-seventh Supplemental Indenture to the Gas Utility First Mortgage, dated as of September 1, 1990 (incorporated herein by reference to Exhibit 4.12 to Post-Effective Amendment No. 2 to Puget Sound Energy’s Registration Statement on Form S-3, filed February 9, 2009, Registration No. 333-132497-01).
	4.9	Twenty-eighth through Thirty-sixth Supplemental Indentures to the Gas Utility First Mortgage (incorporated herein by reference to Exhibit 4-A to Washington Natural Gas Company’s Report on Form 10-Q for the quarter ended March 31, 1993, Commission File No. 0-951; Exhibit 4-A to Washington Natural Gas Company’s Registration Statement on Form S-3, Registration No. 33-49599; Exhibit 4-A to Washington Natural Gas Company’s Registration Statement on Form S-3, Registration No. 33-61859; Exhibit 4.30 to Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2002, Commission File No. 1-4393; Exhibits 4.22 and 4.23 to Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2005, Commission File No. 1-4393; Exhibits 4.22 and 4.23 to Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2007, Commission File No. 1-4393; and Exhibit 4.14 to Post-Effective Amendment No. 2 to Puget Sound Energy’s Registration Statement on Form S-3, filed February 9, 2009, Registration No. 333-132497-01).
	4.10	Unsecured Debt Indenture, dated as of May 18, 2001, between Puget Sound Energy, Inc. and The Bank of New York Trust Company, N.A. (as successor to Bank One Trust Company, N.A.) defining the rights of the holders of Puget Sound Energy’s unsecured debentures (incorporated herein by reference to Exhibit 4.3 to Puget Sound Energy’s Current Report on Form 8-K, dated May 18, 2001, Commission File No. 1-4393).
	4.11	Second Supplemental Indenture to the Unsecured Debt Indenture, dated June 1, 2007, between Puget Sound Energy, Inc. and The Bank of New York Trust Company, N.A. defining the rights of Puget Sound Energy’s Series A Enhanced Junior Subordinated Notes due June 1, 2067 (incorporated herein by reference to Exhibit 4.1 to Puget Sound Energy’s Current Report on Form 8-K, dated May 30, 2007, Commission File No. 1-4393).
	4.12	Form of Replacement Capital Covenant of Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit 4.2 to Puget Sound Energy’s Current Report on Form 8-K, dated May 30, 2007, Commission File No. 1-4393).
	4.13	Pledge Agreement dated March 11, 2003 between Puget Sound Energy, Inc. and Wells Fargo Bank Northwest, National Association, as Trustee (incorporated herein by reference to Exhibit 4.24 to Post-Effective Amendment No. 1 to Puget Sound Energy’s Registration Statement on Form S-3, filed July 11, 2003, Registration No. 333-82940-02).
	4.14	Loan Agreement dated as of March 1, 2003, between the City of Forsyth, Rosebud County, Montana and Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit 4.25 to Post-Effective Amendment No. 1 to Puget Sound Energy’s Registration Statement on Form S-3, filed July 11, 2003, Registration No. 333-82490).
	4.15	Indenture and First Supplemental Indenture between Wells Fargo Bank, National Association and Puget Energy, Inc. dated as of December 6, 2010 (incorporated by reference to Exhibits 4.1 and 4.2 to Puget Energy's Current Report on Form 8-K, filed December 7, 2010, Commission File No. 1-16305).
	4.16	Registration Rights Agreement dated as of December 6, 2010 among Puget Energy, Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated, Barclays Capital Inc. and J.P. Morgan Securities LLC and the other initial purchasers party thereto (incorporated herein by reference to Exhibit 4.3 to Puget Energy's Current Report on Form 8-K, filed December 7, 2010, Commission File No. 1-16305).
	10.1	First Amendment dated as of October 4, 1961 to Power Sales Contract between Public Utility District No. 1 of Chelan County, Washington and Puget Sound Energy, Inc., relating to the Rocky Reach Project (incorporated herein by reference to Exhibit 10.1 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
	10.2	First Amendment dated February 9, 1965 to Power Sales Contract between Public Utility District No. 1 of Douglas County, Washington and Puget Sound Energy, Inc., relating to the Wells Development (incorporated herein by reference to Exhibit 10.2 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
	10.3	Contract dated November 14, 1957 between Public Utility District No. 1 of Chelan County, Washington and Puget Sound Energy, Inc., relating to the Rocky Reach Project (incorporated herein by reference to Exhibit 10.3 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
	10.4	Power Sales Contract dated as of November 14, 1957 between Public Utility District No. 1 of Chelan County, Washington and Puget Sound Energy, Inc., relating to the Rocky Reach Project (incorporated herein by reference to Exhibit 10.4 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
	10.5	Power Sales Contract dated May 21, 1956 between Public Utility District No. 2 of Grant County, Washington and Puget Sound Energy, Inc., relating to the Priest Rapids Project (incorporated herein by reference to Exhibit 10.5 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
	10.6	First Amendment to Power Sales Contract dated as of August 5, 1958 between Puget Sound Energy, Inc. and Public Utility District No. 2 of Grant County, Washington, relating to the Priest Rapids Development (incorporated herein by reference to Exhibit 10.6 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
	10.7	Power Sales Contract dated June 22, 1959 between Public Utility District No. 2 of Grant County, Washington and Puget Sound Energy, Inc., relating to the Wanapum Development (incorporated herein by reference to Exhibit 10.7 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
	10.8	Agreement to Amend Power Sales Contracts dated July 30, 1963 between Public Utility District No. 2 of Grant County, Washington and Puget Sound Energy, Inc., relating to the Wanapum Development (incorporated herein by reference to Exhibit 10.8 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
	10.9	Power Sales Contract executed as of September 18, 1963 between Public Utility District No. 1 of Douglas County, Washington and Puget Sound Energy, Inc., relating to the Wells Development (incorporated herein by reference to Exhibit 10.9 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
	10.10	Construction and Ownership Agreement dated as of July 30, 1971 between The Montana Power Company and Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit 10.10 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
	10.11	Operation and Maintenance Agreement dated as of July 30, 1971 between The Montana Power Company and Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit 10.11 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
	10.12	Contract dated June 19, 1974 between Puget Sound Energy, Inc. and P.U.D. No. 1 of Chelan County (incorporated herein by reference to Exhibit 10.12 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
	10.13	Transmission Agreement dated April 17, 1981 between the Bonneville Power Administration and Puget Sound Energy, Inc. (Colstrip Project) (incorporated herein by reference to Exhibit (10)-55 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).
	10.14	Transmission Agreement dated April 17, 1981 between the Bonneville Power Administration and Montana Intertie Users (Colstrip Project) (incorporated herein by reference to Exhibit (10)-56 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).
	10.15	Ownership and Operation Agreement dated as of May 6, 1981 between Puget Sound Energy, Inc. and other Owners of the Colstrip Project (Colstrip 3 and 4) (incorporated herein by reference to Exhibit (10)-57 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).
	10.16	Colstrip Project Transmission Agreement dated as of May 6, 1981 between Puget Sound Energy, Inc. and Owners of the Colstrip Project (incorporated herein by reference to Exhibit (10)-58 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).
	10.17	Common Facilities Agreement dated as of May 6, 1981 between Puget Sound Energy, Inc. and Owners of Colstrip 1 and 2, and 3 and 4 (incorporated herein by reference to Exhibit (10)-59 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).
	10.18	Amendment dated as of June 1, 1968, to Power Sales Contract between Public Utility District No. 1 of Chelan County, Washington and Puget Sound Energy, Inc. (Rocky Reach Project) (incorporated herein by reference to Exhibit (10)-66 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).
	10.19	Transmission Agreement dated as of December 30, 1987 between the Bonneville Power Administration and Puget Sound Energy, Inc. (Rock Island Project) (incorporated herein by reference to Exhibit (10)-74 to Report on Form 10-K for the fiscal year ended December 31, 1988, Commission File No. 1-4393).
	10.20	Power Sales Agreement between Northwestern Resources (formerly The Montana Power Company) and Puget Sound Energy, Inc. dated as of October 1, 1989 (incorporated herein by reference to Exhibit (10)-4 to Report on Form 10-Q for the quarter ended September 30, 1989, Commission File No. 1-4393).
	10.21	Amendment No. 1 to the Colstrip Project Transmission Agreement dated as of February 14, 1990 among The Montana Power Company, The Washington Water Power Company (Avista), Portland General Electric Company, PacifiCorp and Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit (10)-91 to Report on Form 10-K for the fiscal year ended December 31, 1990, Commission File No. 1-4393).
	10.22	Agreement for Firm Power Purchase (Thermal Project) dated December 27, 1990 among March Point Cogeneration Company, a California general partnership comprising San Juan Energy Company, a California corporation; Texas-Anacortes Cogeneration Company, a Delaware corporation; and Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit (10)-4 to Report on Form 10-Q for the quarter ended March 31, 1991, Commission File No. 1-4393).
	10.23	Agreement for Firm Power Purchase dated March 20, 1991 between Tenaska Washington, Inc., a Delaware corporation, and Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit (10)-1 to Report on Form 10-Q for the quarter ended June 30, 1991, Commission File No. 1-4393).
	10.24	Amendment of Seasonal Exchange Agreement, dated December 4, 1991 between Pacific Gas and Electric Company and Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit (10)-107 to Report on Form 10-K for the fiscal year ended December 31, 1991, Commission File No. 1-4393).
	10.25	Capacity and Energy Exchange Agreement, dated as of October 4, 1991 between Pacific Gas and Electric Company and Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit (10)-108 to Report on Form 10-K for the fiscal year ended December 31, 1991, Commission File No. 1-4393).
	10.26	General Transmission Agreement dated as of December 1, 1994 between the Bonneville Power Administration and Puget Sound Energy, Inc. (BPA Contract No. DE-MS79-94BP93947) (incorporated herein by reference to Exhibit 10.115 to Report on Form 10-K for the fiscal year ended December 31, 1994, Commission File No. 1-4393).
	10.27	PNW AC Intertie Capacity Ownership Agreement dated as of October 11, 1994 between the Bonneville Power Administration and Puget Sound Energy, Inc. (BPA Contract No. DE-MS79-94BP94521) (incorporated herein by reference to Exhibit 10.116 to Report on Form 10-K for the fiscal year ended December 31, 1994, Commission File No. 1-4393).
	10.28	Amendment to Gas Transportation Service Contract dated July 31, 1991 between Washington Natural Gas Company and Northwest Pipeline Corporation (incorporated herein by reference to Exhibit 10-E.2 to Washington Natural Gas Company’s Form 10-K for the fiscal year ended September 30, 1995, Commission File No. 1-11271).
	10.29	Firm Transportation Service Agreement dated January 12, 1994 between Northwest Pipeline Corporation and Washington Natural Gas Company for firm transportation service from Jackson Prairie (incorporated herein by reference to Exhibit 10-P to Washington Natural Gas Company’s Form 10-K for the fiscal year ended September 30, 1994, Commission File No. 1-11271).
	10.30	Product Sales Contract dated December 13, 2001 and Amendment No. 1 thereto, between Public Utility District No. 2 of Grant County, Washington, and Puget Sound Energy, Inc., relating to the Priest Rapids Project (incorporated herein by reference to Exhibit 10-1 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended June 30, 2002, File No. 1-4393).
	10.31	Reasonable Portion Power Sales Contract dated December 13, 2001 and Amendment No. 1 thereto, between Public Utility District No. 2 of Grant County, Washington, and Puget Sound Energy, Inc., relating to the Priest Rapids Project (incorporated herein by reference to Exhibit 10-2 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended June 30, 2002, Commission File No. 1-4393).
	10.32	Additional Products Sales Agreement dated December 13, 2001, and Amendment No. 1 thereto, between Public Utility District No. 2 of Grant County, Washington, and Puget Sound Energy, Inc., relating to the Priest Rapids Project (incorporated herein by reference to Exhibit 10.3 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended June 30, 2002, Commission File No. 1-4393).
	10.33	Credit Agreement dated as of May 16, 2008 among Puget Merger Sub Inc., as Borrower, Barclays Bank PLC, as Facility Agent, the other agents party thereto, and the lenders party thereto (incorporated herein by reference to Exhibit 10.1 to Puget Energy’s and Puget Sound Energy’s Report on Form 10-Q for the quarter ended September 30, 2009, Commission File Nos. 1-16305 and 1-4393).
	10.34	Credit Agreement dated as of February 6, 2009 among Puget Sound Energy, Inc., as Borrower, Barclays Bank PLC, as Facility Agent, the other agents party thereto, and the lenders party thereto (incorporated herein by reference to Exhibit 10.2 to Puget Energy’s and Puget Sound Energy’s Report on Form 10-Q for the quarter ended September 30, 2009, Commission File Nos. 1-16305 and 1-4393).
	10.35	Amendment dated May 10, 2010 to Credit Agreement (dated February 6, 2009) among Puget Sound Energy, Inc. as Borrower, Barclays Bank PLC, as Facility Agent, and the lenders party thereto (incorporated herein by reference to Exhibit 10.1 to Puget Energy’s and Puget Sound Energy’s Report on Form 10-Q for the quarter ended June 30, 2010, Commission File Nos. 1-16305 and 1-4393).
	10.36	First Amendment dated May 10, 2010 to Credit Agreement (dated May 16, 2008) among Puget Energy, Inc., as Borrower, Barclays Bank PLC, as Facility Agent, and Collateral Agent, and the lenders party thereto (incorporated herein by reference to Exhibit 10.2 to Puget Energy’s and Puget Sound Energy’s Report on Form 10-Q for the quarter ended June 30, 2010, Commission File Nos. 1-16305 and 1-4393).
**	10.37	Employment agreement with S. P. Reynolds, Chief Executive Officer and President, dated January 1, 2002 (incorporated herein by reference to Exhibit 10.104 to the Report on Form 10-K for the fiscal year ended December 31, 2001, Commission File Nos. 1-16305 and 1-4393).
**	10.38	First Amendment effective May 12, 2005 to employment agreement with S.P. Reynolds, Chief Executive Officer and President, dated as of January 1, 2002 (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K, dated May 12, 2005, Commission File Nos. 1-16305 and 1-4393).
**	10.39	Second Amendment dated February 9, 2006 to employment agreement with S. P. Reynolds, Chief Executive Officer and President, dated as of January 1, 2002 and amended as of May 10, 2005 (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K, dated February 14, 2006, Commission File Nos. 1-16305 and 1-4393).
**	10.40	Third Amendment dated February 28, 2008 to employment agreement with S.P. Reynolds, Chief Executive Officer and President, dated as of January 1, 2002 and amended as of February 9, 2006  (incorporated herein by reference to Exhibit 10.44 to Puget Energy’s Report on Form 10-K for the fiscal year ended December 31, 2007, Commission File No. 1-16305 and 1-4393).
**	10.41	Form of Executive Employment Agreement with Executive Officers (incorporated herein by reference to Exhibit 10.1 to Puget Sound Energy’s Current Report on Form 8-K, dated April 3, 2009, Commission File No. 1-4393).
**	10.42	Waiver of rights to certain payments and other benefits, executed by Stephen P. Reynolds, Chief Executive Officer and President, dated February 25, 2010.
**	10.43	Puget Sound Energy, Inc. Amended and Restated Supplemental Executive Retirement Plan effective January 1, 2009 (incorporated herein by reference to Exhibit 10.39 to Puget Energy’s and Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2008, Commission File No. 1-16305 and 1-4393).
**	10.44	Puget Sound Energy, Inc. Amended and Restated Deferred Compensation Plan for Key Employees effective January 1, 2009 (incorporated herein by reference to Exhibit 10.40 to Puget Energy’s and Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2008, Commission File No. 1-16305 and 1-4393).
**	10.45	Puget Sound Energy, Inc. Amended and Restated Deferred Compensation Plan for Nonemployee Directors effective January 1, 2009 (incorporated herein by reference to Exhibit 10.41 to Puget Energy’s and Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2008, Commission File No. 1-16305 and 1-4393).
**	10.46	Summary of Director Compensation (incorporated herein by reference to Exhibit 10.51 to Puget Energy’s and Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2006, Commission File No. 1-16305 and 1-4393).
**	10.47	Form of Amended and Restated Change of Control Agreement between Puget Sound Energy, Inc. and Executive Officers (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K, dated February 14, 2006, Commission File Nos. 1-4393).
**	10.48	Puget Sound Energy, Inc. Supplemental Death Benefit Plan for Executive Employees, effective October 1, 2000, as amended (incorporated herein by reference to Exhibit 10.45 to Puget Energy’s and Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2008, Commission File No. 1-16305 and 1-4393).
**	10.49	Puget Sound Energy, Inc. Supplemental Death Benefit Plan for Executive Employees, effective January 1, 2002, as amended (incorporated herein by reference to Exhibit 10.46 to Puget Energy’s and Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2008, Commission File No. 1-16305 and 1-4393).
**	10.50	Puget Sound Energy, Inc. Supplemental Disability Plan for Executive Employees, effective October 1, 2000, as amended (incorporated herein by reference to Exhibit 10.47 to Puget Energy’s and Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2008, Commission File No. 1-16305 and 1-4393).
**	10.51	Puget Sound Energy, Inc. Supplemental Death Benefit Plan for Executive Employees, effective November 1, 2007, as amended (incorporated herein by reference to Exhibit 10.48 to Puget Energy’s and Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2008, Commission File No. 1-16305 and 1-4393).
***	10.52	Puget Energy, Inc. Amended and Restated 2005 Long-Term Incentive Plan, effective March 4, 2011.
*	12.1	Statement setting forth computation of ratios of earnings to fixed charges of Puget Energy, Inc. (2006 through 2010).
*	12.2	Statement setting forth computation of ratios of earnings to fixed charges of Puget Sound Energy, Inc. (2006 through 2010).
*	21.1	Subsidiaries of Puget Energy, Inc.
*	21.2	Subsidiaries of Puget Sound Energy, Inc.
*	23.1	Consent of PricewaterhouseCoopers LLP.
*	31.1	Certification of Puget Energy, Inc. - Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 – Kimberly J. Harris.
*	31.2	Certification of Puget Energy, Inc. - Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 – Bertrand A. Valdman.
*	31.3	Certification of Puget Sound Energy, Inc. - Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 – Kimberly J. Harris.
*	31.4	Certification of Puget Sound Energy, Inc. – Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 – Bertrand A. Valdman.
*	32.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 – Kimberly J. Harris.
*	32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 – Bertrand A. Valdman.

*	Filed herewith.
**	Management contract, compensating plan or arrangement.
***	Management contract, compensating plan or arrangement filed herewith.

EX-10.52

Exhibit 10.52

PUGET ENERGY, INC.

2005 LONG-TERM INCENTIVE PLAN

(The 1995 Long-Term Incentive Compensation Plan as amended and

restated and renamed effective May 10, 2005 and as further amended and restated effective February 9, 2006 and March 4, 2011)

SECTION 1.   PURPOSE

The purpose of the Puget Energy, Inc. 2005 Long-Term Incentive Plan is to attract, retain and motivate employees, officers, directors, consultants, agents, advisors and independent contractors of the Company and its Related Companies by providing them the opportunity to acquire a proprietary interest in the Company and to align their interests and efforts to the long-term interests of the Company's shareholders.

SECTION 2.   DEFINITIONS

Certain capitalized terms used in the Plan have the meanings set forth in Appendix A to the Plan.

SECTION 3.   ADMINISTRATION

3.1 Administration of the Plan

The Plan shall be administered by the Board or the Compensation and Leadership Development Committee, which shall be composed of two or more directors, each of whom is a "non-employee director" within the meaning of Rule 16b-3(b)(3) promulgated under the Exchange Act, or any successor definition adopted by the Securities and Exchange Commission, and an "outside director" within the meaning of Section 162(m) of the Code, or any successor provision thereto.  Notwithstanding the foregoing, the Board may delegate responsibility for administering the Plan with respect to designated classes of Eligible Persons to different committees consisting of two or more members of the Board, subject to such limitations as the Board deems appropriate, except with respect to Awards to Participants who are subject to Section 16 of the Exchange Act or Awards granted pursuant to Section 16 of the Plan.  Members of any committee shall serve for such terms as the Board may determine, subject to removal by the Board at any time.  To the extent consistent with applicable law, the Board may authorize one or more senior executive officers of the Company to grant Awards to designated classes of Eligible Persons, within limits specifically prescribed by the Board; provided, however, that no such officer shall have or obtain authority to grant Awards to himself or herself or to any person subject to Section 16 of the Exchange Act.  All references in the Plan to the "Committee" shall be, as applicable, to the Board, the Compensation and Leadership Development Committee or any other committee or any officer to whom the Board has delegated authority to administer the Plan.

3.2 Administration and Interpretation by Committee

(a)           Except for the terms and conditions explicitly set forth in the Plan and to the extent permitted by applicable law, the Committee shall have full power and exclusive authority, subject to such orders or resolutions not inconsistent with the provisions of the Plan as may from time to time be adopted by the Board or a Committee composed of members of the Board, to (i) select the Eligible Persons to whom Awards may from time to time be granted under the Plan; (ii) determine the type or types of Award to be granted to each Participant under the Plan; (iii) determine the number of shares of Common Stock to be covered by each Award granted under the Plan; (iv) determine the terms and conditions of any Award granted under the Plan; (v) approve the forms of notice or agreement for use under the Plan; (vi) determine whether, to what extent and under what circumstances Awards may be settled in cash, shares of Common Stock or other property or canceled or suspended; (vii) determine whether, to what extent and under what circumstances cash, shares of Common Stock, other property and other amounts payable with respect to an Award shall be deferred either automatically or at the election of the Participant, subject to Section 409A of the Code; (viii) interpret and administer the Plan and any instrument evidencing an Award, notice or agreement executed or entered into under the Plan; (ix) establish such rules and regulations as it shall deem appropriate for the proper administration of the Plan; (x) delegate ministerial duties to such of the Company's employees as it so determines; and (xi) make any other determination and take any other action that the Committee deems necessary or desirable for administration of the Plan.

(b)           In no event, however, shall the Committee have the right, without shareholder approval, to (i) cancel or amend outstanding Options or SARs for the purpose of repricing, replacing or regranting such Options or SARs with Options or SARs that have a purchase or grant price that is less than the purchase or grant price for the original Options or SARs except in connection with adjustments provided in Section 15, or (ii) issue an Option or SAR or amend an outstanding Option or SAR to provide for the grant or issuance of a new Option or SAR on exercise of the original Option or SAR.

(c)           The effect on the vesting of an Award of a Company-approved leave of absence or a Participant's working less than full-time shall be determined by the Company's chief human resources officer or other person performing that function or, with respect to directors or executive officers, by the Committee, whose determination shall be final.

(d)           Decisions of the Committee shall be final, conclusive and binding on all persons, including the Company, any Participant, any shareholder and any Eligible Person.  A majority of the members of the Committee may determine its actions.

SECTION 4.   SHARES SUBJECT TO THE PLAN

4.1 Authorized Number of Shares

Subject to adjustment from time to time as provided in Section 15.1, a maximum of 4,200,000 shares of Common Stock shall be available for issuance under the Plan.  Shares issued under the Plan shall be drawn from authorized and unissued shares.

4.2 Share Usage

(a)           Shares of Common Stock covered by an Award shall not be counted as used unless and until they are actually issued and delivered to a Participant.  If any Award lapses, expires, terminates or is canceled prior to the issuance of shares thereunder or if shares of Common Stock are issued under the Plan to a Participant and thereafter are forfeited to or otherwise reacquired by the Company, the shares subject to such Awards and the forfeited or reacquired shares shall again be available for issuance under the Plan.  Any shares of Common Stock (i) tendered by a Participant or retained by the Company as full or partial payment to the Company for the purchase price of an Award or to satisfy tax withholding obligations in connection with an Award, or (ii) covered by an Award that is settled in cash, or in a manner such that some or all of the shares of Common Stock covered by the Award are not issued, shall be available for Awards under the Plan.  The number of shares of Common Stock available for issuance under the Plan shall not be reduced to reflect any dividends or dividend equivalents that are reinvested into additional shares of Common Stock or credited as additional shares of Common Stock subject or paid with respect to an Award.

(b)           The Committee shall also, without limitation, have the authority to grant Awards as an alternative to or as the form of payment for grants or rights earned or due under other compensation plans or arrangements of the Company.

(c)           Notwithstanding anything in the Plan to the contrary, the Committee may grant Substitute Awards under the Plan.  Substitute Awards shall not reduce the number of shares authorized for issuance under the Plan.  In the event that an Acquired Entity has shares available for awards or grants under one or more preexisting plans not adopted in contemplation of such acquisition or combination, then, to the extent determined by the Board or the Committee, the shares available for grant pursuant to the terms of such preexisting plan (as adjusted, to the extent appropriate, using the exchange ratio or other adjustment or valuation ratio or formula used in such acquisition or combination to determine the consideration payable to holders of common stock of the entities that are parties to such acquisition or combination) may be used for Awards under the Plan and shall not reduce the number of shares of Common Stock authorized for issuance under the Plan; provided, however, that Awards using such available shares shall not be made after the date awards or grants could have been made under the terms of such preexisting plans, absent the acquisition or combination, and shall only be made to individuals who were not employees or directors of the Company or a Related Company prior to such acquisition or combination.  In the event that a written agreement between the Company and an Acquired Entity pursuant to which a merger, consolidation or statutory share exchange is completed is approved by the Board and said agreement sets forth the terms and conditions of the substitution for or assumption of outstanding awards of the Acquired Entity, said terms and conditions shall be deemed to be the action of the Committee without any further action by the Committee, except as may be required for compliance with Rule 16b-3 promulgated under the Exchange Act, and the persons holding such awards shall be deemed to be Participants.

(d)           Notwithstanding the other provisions in this Section 4.2, the maximum number of shares that may be issued upon the exercise of Incentive Stock Options shall equal the aggregate number of shares stated in Section 4.1, subject to adjustment as provided in Section 15.1.

4.3 Limitations

Subject to adjustment as provided in Section 15.1, the aggregate number of shares that may be issued pursuant to Awards granted under the Plan that contain no restrictions or restrictions based solely on continuous employment or services for less than three years (except where Termination of Service occurs by reason of death, Retirement or Disability) shall not exceed 1,050,000 of the aggregate number of shares specified in Section 4.1.

SECTION 5.   ELIGIBILITY

An Award may be granted to any employee, officer or director of the Company or a Related Company whom the Committee from time to time selects.  An Award may also be granted to any consultant, agent, advisor or independent contractor for bona fide services rendered to the Company or any Related Company.

SECTION 6.   AWARDS

6.1 Form, Grant and Settlement of Awards

The Committee shall have the authority, in its sole discretion, to determine the type or types of Awards to be granted under the Plan.  Such Awards may be granted either alone or in addition to or in tandem with any other type of Award.  Any Award settlement may be subject to such conditions, restrictions and contingencies as the Committee shall determine.

6.2 Evidence of Awards

Awards granted under the Plan shall be evidenced by a written, including an electronic, notice or agreement that shall contain such terms, conditions, limitations and restrictions as the Committee shall deem advisable and that are not inconsistent with the Plan.

6.3 Deferrals

 The Committee may permit or require a Participant to defer receipt of the payment of any Award.  If any such deferral election is permitted or required, the Committee, in its sole discretion, shall establish rules and procedures for such payment deferrals, which may include the grant of additional Awards or provisions for the payment or crediting of interest or dividend equivalents, including converting such credits to deferred stock unit equivalents; provided, however, that the terms of any deferrals under this Section 6.3 shall comply with all applicable law, rules and regulations, including, without limitation, Section 409A of the Code.

.

6.4 Dividends and Distributions

Participants may, if the Committee so determines, be credited with dividends paid with respect to shares of Common Stock underlying an Award in a manner determined by the Committee in its sole discretion.  The Committee may apply any restrictions to the dividends or dividend equivalents that the Committee deems appropriate.  The Committee, in its sole discretion, may determine the form of payment of dividends or dividend equivalents, including cash, shares of Common Stock, Restricted Stock or Stock Units.

SECTION 7.   PERFORMANCE AWARDS

7.1 Performance Shares

The Committee may grant Awards of Performance Shares, designate the Participants to whom Performance Shares are to be awarded and determine the number of Performance Shares and the terms and conditions of each such Award.  Performance Shares shall consist of a unit valued by reference to a designated number of shares of Common Stock, the value of which may be paid to the Participant by delivery of shares of Common Stock or, if set forth in the instrument evidencing the Award, of such property as the Committee shall determine, including, without limitation, cash, shares of Common Stock, other property, or any combination thereof, upon the attainment of performance goals, as established by the Committee, and other terms and conditions specified by the Committee.  Notwithstanding the foregoing, the amount to be paid under an Award of Performance Shares may be adjusted on the basis of such further consideration as the Committee shall determine in its sole discretion.

7.2 Performance Units

The Committee may grant Awards of Performance Units, designate the Participants to whom Performance Units are to be awarded and determine the number of Performance Units and the terms and conditions of each such Award.  Performance Units shall consist of a unit valued by reference to a designated amount of property other than shares of Common Stock, which value may be paid to the Participant by delivery of such property as the Committee shall determine, including, without limitation, cash, shares of Common Stock, other property, or any combination thereof, upon the attainment of performance goals, as established by the Committee, and other terms and conditions specified by the Committee.  Notwithstanding the foregoing, the amount to be paid under an Award of Performance Units may be adjusted on the basis of such further consideration as the Committee shall determine in its sole discretion.

SECTION 8.   OPTIONS

8.1 Grant of Options

The Committee may grant Options designated as Incentive Stock Options or Nonqualified Stock Options.

8.2 Option Exercise Price

The exercise price for shares purchased under an Option shall be as determined by the Committee, but shall not be less than 100% of the Fair Market Value on the Grant Date, except in the case of Substitute Awards.  Notwithstanding the foregoing, the Committee, in its sole discretion, may establish an exercise price that is equal to the average of 100% of the Fair Market Value over a period of trading days not to exceed 30 days from the Grant Date.

8.3 Term of Options

Subject to earlier termination in accordance with the terms of the Plan and the instrument evidencing the Option, the maximum term of a Nonqualified Stock Option shall be as established for that Option by the Committee or, if not so established, shall be ten years from the Grant Date.

8.4 Exercise of Options

The Committee shall establish and set forth in each instrument that evidences an Option the time at which, or the installments in which, the Option shall vest and become exercisable, any of which provisions may be waived or modified by the Committee at any time.

To the extent an Option has vested and become exercisable, the Option may be exercised in whole or from time to time in part by delivery to or as directed or approved by the Company of a properly executed stock option exercise agreement or notice, in a form and in accordance with procedures established by the Committee, setting forth the number of shares with respect to which the Option is being exercised, the restrictions imposed on the shares purchased under such exercise agreement, if any, and such representations and agreements as may be required by the Committee, accompanied by payment in full as described in Sections 8.5 and 13.  An Option may be exercised only for whole shares and may not be exercised for less than a reasonable number of shares at any one time, as determined by the Committee.

8.5 Payment of Exercise Price

The exercise price for shares purchased under an Option shall be paid in full to the Company by delivery of consideration equal to the product of the Option exercise price and the number of shares purchased.  Such consideration must be paid before the Company will issue the shares being purchased and must be in a form or a combination of forms acceptable to the Committee for that purchase, which forms may include:

(a)           cash, check or wire transfer;

(b)           tendering (either actually or by attestation) shares of Common Stock that on the day prior to the exercise date have an aggregate Fair Market Value equal to the aggregate exercise price of the shares being purchased under the Option;

(c)           having the Company withhold a number of shares of Common Stock that would otherwise be issued to the Participant upon exercise of the Option having a Fair Market Value on the day prior to the exercise date equal to the aggregate exercise price of the shares being purchased under the Option;

(d)           to the extent permitted by law, delivery of a properly executed exercise notice, together with irrevocable instructions to a brokerage firm designated or approved by the Company to deliver promptly to the Company the aggregate amount of proceeds to pay the Option exercise price and any tax withholding obligations that may arise in connection with the exercise, all in accordance with the regulations of the Federal Reserve Board; or

(e)           such other consideration as the Committee may permit.

8.6 Effect of Termination of Service

The Committee shall establish and set forth in each instrument that evidences an Option whether the Option shall continue to be exercisable, and the terms and conditions of such exercise, after a Termination of Service, any of which provisions may be waived or modified by the Committee at any time.  If not so established in the instrument evidencing the Option, the Option shall be exercisable according to the following terms and conditions, which may be waived or modified by the Committee at any time:

(a)           Any portion of an Option that is not vested and exercisable on the date of a Participant's Termination of Service shall expire on such date.

(b)           Any portion of an Option that is vested and exercisable on the date of a Participant's Termination of Service shall expire on the earliest to occur of

(i)           if the Participant's Termination of Service occurs for reasons other than Cause, Retirement, Disability or death, the date that is three months after such Termination of Service;

(ii)           if the Participant's Termination of Service occurs by reason of Retirement, Disability or death, the one-year anniversary of such Termination of Service; and

(iii)           the last day of the maximum term of the Option (the "Option Expiration Date").

Notwithstanding the foregoing, if a Participant dies after his or her Termination of Service but while an Option is otherwise exercisable, the portion of the Option that is vested and exercisable on the date of such Termination of Service shall expire upon the earlier to occur of (y) the Option Expiration Date and (z) the one-year anniversary of the date of death, unless the Committee determines otherwise.

Also notwithstanding the foregoing, in case a Participant's Termination of Service occurs for Cause, all Options granted to the Participant shall automatically expire upon first notification to the Participant of such termination, unless the Committee determines otherwise.  If a Participant's employment or service relationship with the Company is suspended pending an investigation of whether the Participant shall be terminated for Cause, all the Participant's rights under any Option shall likewise be suspended during the period of investigation.  If any facts that would constitute termination for Cause are discovered after a Participant's Termination of Service, any Option then held by the Participant may be immediately terminated by the Committee, in its sole discretion.

(c)           A Participant's change in status from an employee to a consultant, advisor or independent contractor or a change in status from a consultant, advisor or independent contractor to an employee shall not be considered a Termination of Service for purposes of this Section 8.6.

SECTION 9.   INCENTIVE STOCK OPTIONS

Notwithstanding any other provisions of the Plan, the terms and conditions of any Incentive Stock Options shall in addition comply in all respects with Section 422 of the Code, or any successor provision, and any applicable regulations thereunder.

SECTION 10.   STOCK APPRECIATION RIGHTS

10.1 Grant of Stock Appreciation Rights

The Committee may grant Stock Appreciation Rights to Participants at any time on such terms and conditions as the Committee shall determine in its sole discretion.  An SAR may be granted in tandem with an Option or alone ("freestanding").  The grant price of a tandem SAR shall be equal to the exercise price of the related Option.  The grant price of a freestanding SAR shall be established in accordance with procedures for Options set forth in Section 8.2.  An SAR may be exercised upon such terms and conditions and for such term as the Committee determines in its sole discretion; provided, however, that, subject to earlier termination in accordance with the terms of the Plan and the instrument evidencing the SAR, the term of a freestanding SAR shall be as established for that SAR by the Committee or, if not so established, shall be ten years, and in the case of a tandem SAR, (a) the term shall not exceed the term of the related Option and (b) the tandem SAR may be exercised for all or part of the shares subject to the related Option upon the surrender of the right to exercise the equivalent portion of the related Option, except that the tandem SAR may be exercised only with respect to the shares for which its related Option is then exercisable.  The Committee shall establish and set forth in each instrument that evidences an SAR whether the SAR shall continue to be exercisable, and the terms and conditions of such exercise, after a Termination of Service, any of which provisions may be waived or modified by the Committee at any time.  If not so established in the instrument evidencing the SAR, the SAR shall be exercisable according to the terms and conditions set forth in Section 8.6 (a)-(c) for Options, which may be waived or modified by the Committee at any time.

10.2 Payment of SAR Amount

Upon the exercise of an SAR, a Participant shall be entitled to receive payment in an amount determined by multiplying:  (a) the difference between the Fair Market Value of the Common Stock on the date of exercise over the grant price of the SAR by (b) the number of shares with respect to which the SAR is exercised.  At the discretion of the Committee as set forth in the instrument evidencing the Award, the payment upon exercise of an SAR may be in cash, in shares, in some combination thereof or in any other manner approved by the Committee in its sole discretion.

SECTION 11.   STOCK AWARDS, RESTRICTED STOCK AND STOCK UNITS

11.1 Grant of Stock Awards, Restricted Stock and Stock Units

The Committee may grant Stock Awards, Restricted Stock and Stock Units on such terms and conditions and subject to such repurchase or forfeiture restrictions, if any, that may be based on continuous service with the Company or a Related Company or the achievement of any performance goals, as the Committee shall determine in its sole discretion, which terms, conditions and restrictions shall be set forth in the instrument evidencing the Award.

11.2 Vesting of Restricted Stock and Stock Units

Upon the satisfaction of any terms, conditions and restrictions prescribed with respect to Restricted Stock or Stock Units, or upon a Participant's release from any terms, conditions and restrictions of Restricted Stock or Stock Units, as determined by the Committee, and subject to the provisions of Section 13, (a) the shares of Restricted Stock covered by each Award of Restricted Stock shall become freely transferable by the Participant, and (b) Stock Units shall be paid in shares of Common Stock or, if set forth in the instrument evidencing the Awards, in cash or a combination of cash and shares of Common Stock.  Any fractional shares subject to such Awards shall be paid to the Participant in cash.

11.3 Waiver of Restrictions

Notwithstanding any other provisions of the Plan, the Committee, in its sole discretion, may waive the repurchase or forfeiture period and any other terms, conditions or restrictions on any Restricted Stock or Stock Unit under such circumstances and subject to such terms and conditions as the Committee shall deem appropriate.

SECTION 12.   OTHER STOCK OR CASH-BASED AWARDS

Subject to the terms of the Plan and such other terms and conditions as the Committee deems appropriate, the Committee may grant other incentives payable in cash or in shares of Common Stock under the Plan.

SECTION 13.   WITHHOLDING

The Company may require the Participant to pay to the Company the amount of (a) any taxes that the Company is required by applicable federal, state, local or foreign law to withhold with respect to the grant, vesting or exercise of an Award ("tax withholding obligations") and (b) any amounts due from the Participant to the Company or any Related Company ("other obligations").  The Company shall not be required to issue any shares of Common Stock or otherwise settle an Award under the Plan until such tax withholding obligations and other obligations are satisfied.

The Committee may permit or require a Participant to satisfy all or part of the Participant's tax withholding obligations and other obligations by (a) paying cash to the Company, (b) having the Company withhold an amount from any cash amounts otherwise due or to become due from the Company to the Participant, (c) having the Company withhold a number of shares of Common Stock that would otherwise be issued to the Participant (or become vested, in the case of Restricted Stock) having a Fair Market Value equal to the tax withholding obligations and other obligations, or (d) surrendering a number of shares of Common Stock the Participant already owns having a value equal to the tax withholding obligations and other obligations.  The value of the shares so withheld may not exceed the employer's minimum required tax withholding rate, and the value of the shares so tendered may not exceed such rate to the extent the Participant has owned the tendered shares for less than six months, if such limitations are necessary to avoid adverse accounting consequences to the Company.

SECTION 14.   ASSIGNABILITY

No Award or interest in an Award may be sold, assigned, pledged (as collateral for a loan or as security for the performance of an obligation or for any other purpose) or transferred by a Participant or made subject to attachment or similar proceedings otherwise than by will or by the applicable laws of descent and distribution, except to the extent the Participant designates one or more beneficiaries on a Company-approved form who may exercise the Award or receive payment under the Award after the Participant's death.  During a Participant's lifetime, an Award may be exercised only by the Participant.  Notwithstanding the foregoing and to the extent permitted by Section 422 of the Code, the Committee, in its sole discretion, may permit a Participant to assign or transfer an Award subject to such terms and conditions as the Committee shall specify.

SECTION 15.   ADJUSTMENTS

15.1 Adjustment of Shares

In the event, at any time or from time to time, a stock dividend, stock split, spin-off, combination or exchange of shares, recapitalization, merger, consolidation, distribution to shareholders other than a normal cash dividend, or other change in the Company's corporate or capital structure results in (a) the outstanding shares of Common Stock, or any securities exchanged therefor or received in their place, being exchanged for a different number or kind of securities of the Company or (b) new, different or additional securities of the Company or any other company being received by the holders of shares of Common Stock, then the Committee shall make proportional adjustments in (i) the maximum number and kind of securities available for issuance under the Plan and the maximum number and kind of securities that may be made subject to Awards to any Participant as set forth in Section 16.3; (ii) the maximum number and kind of securities issuable as Incentive Stock Options as set forth in Section 4.2; (iii) the maximum number and kind of securities that may be issued pursuant to Awards granted under the Plan that contain no restrictions or restrictions based solely on continuous employment or services for less than three years (except where Termination of Service occurs by reason of death, Retirement or Disability) as set forth in Section 4.3; and (iv) the number and kind of securities that are subject to any outstanding Award and the per share price of such securities, without any change in the aggregate price to be paid therefore.  The determination by the Committee as to the terms of any of the foregoing adjustments shall be conclusive and binding.

Notwithstanding the foregoing, the issuance by the Company of shares of stock of any class, or securities convertible into shares of stock of any class, for cash or property, or for labor or services rendered, either upon direct sale or upon the exercise of rights or warrants to subscribe therefor, or upon conversion of shares or obligations of the Company convertible into such shares or other securities, shall not affect, and no adjustment by reason thereof shall be made with respect to, outstanding Awards.  Also notwithstanding the foregoing, a dissolution or liquidation of the Company or a Change of Control shall not be governed by this Section 15.1 but shall be governed by Sections 15.2 and 15.3, respectively.

15.2 Dissolution or Liquidation

To the extent not previously exercised or settled, and unless otherwise determined by the Committee in its sole discretion, Awards shall terminate immediately prior to the dissolution or liquidation of the Company.  To the extent a vesting condition, forfeiture provision or repurchase right applicable to an Award has not been waived by the Committee, the Award shall be forfeited immediately prior to the consummation of the dissolution or liquidation.

15.3 Change of Control

Except as otherwise provided in the instrument that evidences a specific Award or in a written employment, services or other agreement between the Participant and the Company or a Related Company, in the event of a Change of Control:

(a)           If and to the extent that a Successor Company converts, assumes, substitutes or replaces an Award with a comparable award of equivalent value or an Award is otherwise continued following a Change of Control, the applicable vesting restrictions (including restrictions based on performance criteria), forfeiture provisions and payout provisions for such Award shall not be accelerated or lapse, and all such applicable vesting restrictions, forfeiture provisions and payout provisions shall continue with respect to such Award; provided, however, that if, in connection with or within one year after the effective date of the Change of Control (the "COC Effective Date"), a Participant's employment is terminated by the Company or a Successor Company without Cause or the Participant terminates his or her employment for Good Reason (each, a "COC Termination Event"), such Award shall be cancelled and deemed earned and payable as provided in Section 15.3(b).

(b)           If and to the extent that (i) a Successor Company does not convert, assume, substitute or replace an Award or an Award is not otherwise continued following a Change of Control or (ii) a Participant experiences a COC Termination Event, the payout opportunities attainable under an Award with restrictions based on performance criteria shall be pro-rated for the number of full months completed in an outstanding performance cycle, up to and including the COC Effective Date or COC Termination Event, as applicable, and, on such pro-rated basis, shall be deemed to be earned in an amount equal to the product of (x) the most recent per-unit independent valuation for the units subject to such Award and (y) that number of units equal to the greater of (A) the total number of units based on targeted performance for the performance cycle being attained as of the COC Effective Date or COC Termination Event, as applicable, and (B) the number of units based on actual performance attained for the performance cycle, based on the most recent independent evaluation of performance preceding the COC Effective Date or COC Termination Date, as applicable.  Any such Award shall be payable in cash within 30 days after the COC Effective Date or COC Termination Event, as applicable.

(c)           The determination of whether an Award shall be considered converted, assumed, substituted, replaced or otherwise continued shall be determined by the Board or Compensation Committee, and its determination shall be conclusive and binding on the Company and Participants.  For the avoidance of doubt, nothing in this Section 15.3 requires all outstanding Awards to be treated similarly.

15.4 Further Adjustment of Awards

Subject to Sections 15.2 and 15.3, the Committee shall have the discretion, exercisable at any time before a sale, merger, consolidation, reorganization, liquidation, dissolution or change of control of the Company, as defined by the Committee, to take such further action as it determines to be necessary or advisable with respect to Awards.  Such authorized action may include (but shall not be limited to) establishing, amending or waiving the type, terms, conditions or duration of, or restrictions on, Awards so as to provide for earlier, later, extended or additional time for exercise, lifting restrictions and other modifications, and the Committee may take such actions with respect to all Participants, to certain categories of Participants or only to individual Participants.  The Committee may take such action before or after granting Awards to which the action relates and before or after any public announcement with respect to such sale, merger, consolidation, reorganization, liquidation, dissolution or change of control that is the reason for such action.

15.5 No Limitations

The grant of Awards shall in no way affect the Company's right to adjust, reclassify, reorganize or otherwise change its capital or business structure or to merge, consolidate, dissolve, liquidate or sell or transfer all or any part of its business or assets.

15.6 Fractional Shares

In the event of any adjustment in the number of shares covered by any Award, each such Award shall cover only the number of full shares resulting from such adjustment.

15.7 Section 409A

 Notwithstanding any other provision of the Plan to the contrary, (a) any adjustments made pursuant to this Section 15 to Awards that are considered "deferred compensation" within the meaning of Section 409A of the Code shall be made in compliance with the requirements of Section 409A and (b) any adjustments made pursuant to this Section 15 to Awards that are not considered "deferred compensation" subject to Section 409A of the Code shall be made in such a manner as to ensure that after such adjustment the Awards either (i) continue not to be subject to Section 409A of the Code or (ii) comply with the requirements of Section 409A of the Code.

SECTION 16.   CODE SECTION 162(m) PROVISIONS

Notwithstanding any other provision of the Plan, if the Committee determines, at the time Awards are granted to a Participant who is, or is likely to be as of the end of the tax year in which the Company would claim a tax deduction in connection with such Award, a Covered Employee, then the Committee may provide that this Section 16 is applicable to such Award.

16.1 Performance Criteria

If an Award is subject to this Section 16, then the lapsing of restrictions thereon and the distribution of cash, shares of Common Stock or other property pursuant thereto, as applicable, shall be subject to the achievement of one or more objective performance goals established by the Committee, which shall be based on the attainment of specified levels of one or any combination of the following "performance criteria" for the Company as a whole or any business unit of the Company, as reported or calculated by the Company:  cash flows (including, but not limited to, operating cash flow, free cash flow or cash flow return on capital); working capital; earnings per share; book value per share; operating income (including or excluding depreciation, amortization, extraordinary items, restructuring charges or other expenses); revenues; operating margins; return on assets; return on equity; debt; debt plus equity; market or economic value added; stock price appreciation; total shareholder return; cost control; strategic initiatives; market share; net income; return on invested capital; improvements in capital structure; cash management or asset management metrics; customer satisfaction, employee satisfaction, services performance, subscriber, safety or reliability metrics; or Service Quality Indices (together, the "Performance Criteria").  Such performance goals also may be based on the achievement of specified levels of Company performance (or performance of an applicable affiliate or business unit of the Company) under one or more of the Performance Criteria described above relative to the performance of other corporations.  Such performance goals shall be set by the Committee within the time period prescribed by, and shall otherwise comply with the requirements of, Section 162(m) of the Code, or any successor provision thereto, and the regulations thereunder.

16.2 Adjustment of Awards

Notwithstanding any provision of the Plan other than Section 15, with respect to any Award that is subject to this Section 16, the Committee may adjust downwards, but not upwards, the amount payable pursuant to such Award, and the Committee may not waive the achievement of the applicable performance goals except in the case of the death or Disability of the Covered Employee.

16.3 Limitations

Subject to adjustment from time to time as provided in Section 15.1, no Covered Employee may be granted (i) Options and SARs subject to this Section 16 in any calendar-year period with respect to more than an aggregate of 600,000 shares of Common Stock for such Awards or (ii) Awards other than Options and SARs or Performance Units subject to this Section 16 in any calendar-year period with respect to more than an aggregate of 400,000 shares of Common Stock for such Awards.  The maximum dollar value payable with respect to Performance Units subject to this Section 16 granted to any Covered Employee in any one calendar year is $3,000,000.

The Committee shall have the power to impose such other restrictions on Awards subject to this Section 16 as it may deem necessary or appropriate to ensure that such Awards satisfy all requirements for "performance-based compensation" within the meaning of Section 162(m)(4)(C) of the Code, or any successor provision thereto.

SECTION 17.   AMENDMENT AND TERMINATION

17.1 Amendment, Suspension or Termination

The Board or the Committee may amend, suspend or terminate the Plan or any portion of the Plan at any time and in such respects as it shall deem advisable; provided, however, that, to the extent required by applicable law, regulation or stock exchange rule, shareholder approval shall be required for any amendment to the Plan; and provided, further, that any amendment that requires shareholder approval may be made only by the Board.  Subject to Section 17.3, the Committee may amend the terms of any outstanding Award, prospectively or retroactively.

17.2 Term of the Plan

Unless sooner terminated as provided herein, the Plan shall terminate ten years from the Effective Date.  After the Plan is terminated, no future Awards may be granted, but Awards previously granted shall remain outstanding in accordance with their applicable terms and conditions and the Plan's terms and conditions.  Notwithstanding the foregoing, no Incentive Stock Options may be granted more than ten years after the later of (a) the Effective Date and (b) the approval by the shareholders of any amendment to the Plan that constitutes the adoption of a new plan for purposes of Section 422 of the Code.

17.3 Consent of Participant

The amendment, suspension or termination of the Plan or a portion thereof or the amendment of an outstanding Award shall not, without the Participant's consent, materially adversely affect any rights under any Award theretofore granted to the Participant under the Plan.  Any change or adjustment to an outstanding Incentive Stock Option shall not, without the consent of the Participant, be made in a manner so as to constitute a "modification" that would cause such Incentive Stock Option to fail to continue to qualify as an Incentive Stock Option.  Notwithstanding the foregoing, any adjustments made pursuant to Section 15 shall not be subject to these restrictions.

SECTION 18.   GENERAL

18.1 No Individual Rights

No individual or Participant shall have any claim to be granted any Award under the Plan, and the Company has no obligation for uniformity of treatment of Participants under the Plan.

Furthermore, nothing in the Plan or any Award granted under the Plan shall be deemed to constitute an employment contract or confer or be deemed to confer on any Participant any right to continue in the employ of, or to continue any other relationship with, the Company or any Related Company or limit in any way the right of the Company or any Related Company to terminate a Participant's employment or other relationship at any time, with or without cause.

18.2 Issuance of Shares

Notwithstanding any other provision of the Plan, the Company shall have no obligation to issue or deliver any shares of Common Stock under the Plan or make any other distribution of benefits under the Plan unless, in the opinion of the Company's counsel, such issuance, delivery or distribution would comply with all applicable laws (including, without limitation, the requirements of the Securities Act or the laws of any state or foreign jurisdiction) and the applicable requirements of any securities exchange or similar entity.

The Company shall be under no obligation to any Participant to register for offering or resale or to qualify for exemption under the Securities Act, or to register or qualify under the laws of any state or foreign jurisdiction, any shares of Common Stock, security or interest in a security paid or issued under, or created by, the Plan, or to continue in effect any such registrations or qualifications if made.  The Company may issue certificates for shares with such legends and subject to such restrictions on transfer and stop-transfer instructions as counsel for the Company deems necessary or desirable for compliance by the Company with federal, state and foreign securities laws.  The Company may also require such other action or agreement by the Participants as may from time to time be necessary to comply with applicable securities laws.

To the extent the Plan or any instrument evidencing an Award provides for issuance of stock certificates to reflect the issuance of shares of Common Stock, the issuance may be effected on a noncertificated basis, to the extent not prohibited by applicable law or the applicable rules of any stock exchange.

18.3 Indemnification

Each person who is or shall have been a member of the Board, or a committee appointed by the Board, or an officer of the Company to whom authority was delegated in accordance with Section 3, shall be indemnified and held harmless by the Company against and from any loss, cost, liability or expense that may be imposed upon or reasonably incurred by such person in connection with or resulting from any claim, action, suit or proceeding to which such person may be a party or in which such person may be involved by reason of any action taken or failure to act under the Plan and against and from any and all amounts paid by such person in settlement thereof, with the Company's approval, or paid by such person in satisfaction of any judgment in any such claim, action, suit or proceeding against such person; provided, however, that such person shall give the Company an opportunity, at its own expense, to handle and defend the same before such person undertakes to handle and defend it on such person's own behalf, unless such loss, cost, liability or expense is a result of such person's own willful misconduct or except as expressly provided by statute.

The foregoing right of indemnification shall not be exclusive of any other rights of indemnification to which such person may be entitled under the Company's certificate of incorporation or bylaws, as a matter of law or otherwise, or of any power that the Company may have to indemnify or hold harmless.

18.4 No Rights as a Shareholder

Unless otherwise provided by the Committee or in the instrument evidencing the Award or in a written employment, services or other agreement, no Award, other than a Stock Award, shall entitle the Participant to any cash dividend, voting or other right of a shareholder unless and until the date of issuance under the Plan of the shares that are the subject of such Award.

18.5 Compliance With Laws and Regulations

(a)           In interpreting and applying the provisions of the Plan, any Option granted as an Incentive Stock Option pursuant to the Plan shall, to the extent permitted by law, be construed as an "incentive stock option" within the meaning of Section 422 of the Code.

(b)           The Plan and Awards granted under the Plan are intended to be exempt from the requirements of Section 409A of the Code, including the final regulations and other guidance issued thereunder by the Department of the Treasury and the Internal Revenue Service, to the maximum extent possible, whether pursuant to the short-term deferral exception described in Treasury Regulation Section 1.409A-1(b)(4), the exclusion applicable to stock options, stock appreciation rights and certain other equity-based compensation under Treasury Regulation Section 1.409A-1(b)(5), or otherwise.  To the extent Section 409A of the Code is applicable to the Plan or any Award granted under the Plan, it is intended that the Plan and any Awards granted under the Plan comply with the deferral, payout, plan termination and other limitations and restrictions imposed under Section 409A of the Code.  Notwithstanding any other provision of the Plan or any Award granted under the Plan to the contrary, the Plan and any Award granted under the Plan shall be interpreted, operated and administered in a manner consistent with such intentions; provided, however, that the Company makes no representations that Awards granted under the Plan shall be exempt from or comply with Section 409A of the Code and makes no undertaking to preclude Section 409A of the Code from applying to Awards granted under the Plan.  Without limiting the generality of the foregoing, and notwithstanding any other provision of the Plan or any Award granted under the Plan to the contrary, with respect to any payments and benefits under the Plan or any Award granted under the Plan to which Section 409A of the Code applies, all references in the Plan or any Award granted under the Plan to the termination of the Participant's employment or service are intended to mean the Participant's "separation from service," within the meaning of Section 409A(a)(2)(A)(i) of the Code to the extent necessary to avoid subjecting the Participant to the imposition of any additional tax under Section 409A of the Code.  In addition, if the Participant is a "specified employee," within the meaning of Section 409A of the Code, then to the extent necessary to avoid subjecting the Participant to the imposition of any additional tax under Section 409A of the Code, amounts that would otherwise be payable under the Plan or any Award granted under the Plan during the six-month period immediately following the Participant's "separation from service," within the meaning of Section 409A(a)(2)(A)(i) of the Code, shall not be paid to the Participant during such period, but shall instead be accumulated and paid to the Participant (or, in the event of the Participant's death, the Participant's estate) in a lump sum on the first business day after the earlier of the date that is six months following the Participant's separation from service or the Participant's death.Notwithstanding any other provision of the Plan to the contrary, the Board or the Committee, to the extent it deems necessary or advisable in its sole discretion, reserves the right, but shall not be required, to unilaterally amend or modify the Plan and any Award granted under the Plan so that the Award qualifies for exemption from or complies with Section 409A of the Code.

18.6 Participants in Other Countries or Jurisdictions

Without amending the Plan, the Committee may grant Awards to Eligible Persons who are foreign nationals on such terms and conditions different from those specified in the Plan as may, in the judgment of the Committee, be necessary or desirable to foster and promote achievement of the purposes of the Plan and shall have the authority to adopt such modifications, procedures, subplans and the like as may be necessary or desirable to comply with provisions of the laws or regulations of other countries or jurisdictions in which the Company or any Related Company may operate or have employees to ensure the viability of the benefits from Awards granted to Participants employed in such countries or jurisdictions, meet the requirements that permit the Plan to operate in a qualified or tax-efficient manner, comply with applicable foreign laws or regulations and meet the objectives of the Plan.

18.7 No Trust or Fund

The Plan is intended to constitute an "unfunded" plan.  Nothing contained herein shall require the Company to segregate any monies or other property, or shares of Common Stock, or to create any trusts, or to make any special deposits for any immediate or deferred amounts payable to any Participant, and no Participant shall have any rights that are greater than those of a general unsecured creditor of the Company.

18.8 Successors

All obligations of the Company under the Plan with respect to Awards shall be binding on any successor to the Company, whether the existence of such successor is the result of a direct or indirect purchase, merger, consolidation, or otherwise, of all or substantially all the business and/or assets of the Company.

18.9 Severability

If any provision of the Plan or any Award is determined to be invalid, illegal or unenforceable in any jurisdiction, or as to any person, or would disqualify the Plan or any Award under any law deemed applicable by the Committee, such provision shall be construed or deemed amended to conform to applicable laws, or, if it cannot be so construed or deemed amended without, in the Committee's determination, materially altering the intent of the Plan or the Award, such provision shall be stricken as to such jurisdiction, person or Award, and the remainder of the Plan and any such Award shall remain in full force and effect.

18.10 Choice of Law

The Plan, all Awards granted thereunder and all determinations made and actions taken pursuant hereto, to the extent not otherwise governed by the laws of the United States, shall be governed by the laws of the State of Washington without giving effect to principles of conflicts of law.

18.11 Legal Requirements

The granting of Awards and the issuance of shares of Common Stock under the Plan are subject to all applicable laws, rules and regulations and to such approvals by any governmental agencies or national securities exchanges as may be required.

SECTION 19.   EFFECTIVE DATE

The effective date (the "Effective Date") is the date on which the Plan is approved by the shareholders of the Company.

APPENDIX A (to the 2005 Long-Term Incentive Plan)

DEFINITIONS

As used for purposes of the Plan,

"Acquired Entity" means any entity acquired by the Company or a Related Company or with which the Company or a Related Company merges or combines.

"Award" means any Option, Stock Appreciation Right, Stock Award, Restricted Stock, Stock Unit, Performance Share, Performance Unit, cash-based award or other incentive payable in cash or in shares of Common Stock as may be designated by the Committee from time to time.

"Board" means the Board of Directors of the Company.

"Cause," unless otherwise defined in the instrument evidencing an Award or in a written employment, services or other agreement between the Participant and the Company or a Related Company with respect to an Award, means (a) willful and continued failure by the Participant to substantially perform the Participant's duties with the Company (other than any such failure resulting from incapacity due to physical or mental illness), for a period of 30 days after written notice of demand for substantial performance has been delivered to the Participant, which specifically identifies the manner in which the Company believes that the Participant has not substantially performed the Participant's duties, or (b) the willful engaging by the Participant in gross misconduct materially and demonstrably injurious to the Company, after notice to the Participant and an opportunity for a hearing, in each case as determined by the Company's chief human resources officer or other person performing that function or, in the case of directors and executive officers, the Board, whose determination shall be conclusive and binding.  No act or failure to act on the Participant's behalf shall be considered "willful" unless the Participant has acted or failed to act with an absence of good faith and without a reasonable belief that the Participant's action or failure to act was in the best interests of the Company.

"Change of Control," unless the Committee determines otherwise with respect to an Award at the time the Award is granted or unless otherwise defined for purposes of an Award in a written employment, services or other agreement between the Participant and the Company or a Related Company, means a change in beneficial ownership or control of the Company effected through a transaction or series of transactions (other than an offering of Common Stock to the general public through a registration statement filed with the Securities and Exchange Commission) whereby any "person" or related "group" of "persons" (as such terms are used in Sections 13(d) and 14(d)(2) of the Exchange Act) (other than the Company, any of its subsidiaries, an employee benefit plan maintained by the Company or any of its subsidiaries, any Member (as defined in that certain Amended and Restated Limited Liability Company Agreement of Puget Holdings LLC, dated as of February 6, 2009) or a "person" that, prior to such transaction, directly or indirectly controls, is controlled by, or is under common control with, the Company or a Member) directly or indirectly acquires (a) beneficial ownership (within the meaning of Rule 13d-3 under the Exchange Act) of securities of the Company possessing more than 55% of the total combined voting power of the Company's securities outstanding immediately after such acquisition or (b) all or substantially all of the assets of the Company.

"COC Effective Date" has the meaning set forth in Section 15.3.

"COC Termination Date" has the meaning set forth in Section 15.3.

"Code" means the Internal Revenue Code of 1986, as amended from time to time.

"Committee" has the meaning set forth in Section 3.1.

"Common Stock" means the common stock, par value $.01 per share, of the Company.

"Company" means Puget Energy, Inc., a Washington corporation.

"Compensation Committee" means the Compensation and Leadership Development Committee of the Board.

"Covered Employee" means a "covered employee" as that term is defined for purposes of Section 162(m)(3) of the Code or any successor provision.

"Disability," unless otherwise defined by the Committee or in the instrument evidencing the Award or in a written employment, services or other agreement between the Participant and the Company or a Related Company, means "disability" as defined in the Company's Investment Plan for Employees or other similar successor plan applicable to salaried employees.

"Effective Date" has the meaning set forth in Section 19.

"Eligible Person" means any person eligible to receive an Award as set forth in Section 5.

"Entity" means any individual, entity or group (within the meaning of Section 13(d)(3) of the Exchange Act).

"Exchange Act" means the Securities Exchange Act of 1934, as amended from time to time.

"Fair Market Value" means the average of the high and low trading prices for the Common Stock on any given date during regular trading or, if not trading on that date, such price on the last preceding date on which the Common Stock was traded, unless determined otherwise by the Committee using such methods or procedures as it may establish.

"Good Reason" means the occurrence of any of the following events or conditions without the Participant's consent:

(a)           a change in the Participant's position that represents a material reduction of authority or level of responsibilities as in effect immediately prior thereto;

(b)           a material reduction in the Participant's annual base salary;

(c)           the Company's requiring the Participant (without the Participant's consent) to be based at any place outside a 35-mile radius of his or her place of employment prior to a Change of Control, except for reasonably required travel on the Company's business that is not materially greater than such travel requirements prior to the Change of Control;

(d)           the Company's failure to (i) continue in effect any material compensation or benefit plan (or the substantial equivalent thereof) in which the Participant was participating at the time of a Change of Control, including, but not limited to, the Plan, or (ii) provide the Participant with compensation and benefits at least equal (in terms of benefit levels and/or reward opportunities) to those provided for under each employee benefit plan, program and practice as in effect immediately prior to the Change of Control (or as in effect following the Change of Control, if greater);

(e)           any material breach by the Company of any provision of the Plan; or

(f)           any purported termination of the Participant's employment for Cause by the Company that does not comply with the terms of the Plan.

In order for a termination by a Participant to constitute a termination for Good Reason, (i) the Participant must notify the Company or a Successor Company of the existence of the condition which the Participant believes constitutes Good Reason within thirty (30) days of the initial existence of such condition, (ii) the Company or a Successor Company must fail to remedy such condition within thirty (30) days after the date on which it receives such notice (the "Remedial Period"), and (iii) the Participant must actually terminate employment within ten (10) days after expiration of the Remedial Period.

"Grant Date" means the later of (a) the date on which the Committee completes the corporate action authorizing the grant of an Award or such later date specified by the Committee or (b) the date on which all conditions precedent to an Award have been satisfied, provided that conditions to the exercisability or vesting of Awards shall not defer the Grant Date.

"Incentive Stock Option" means an Option granted with the intention that it qualify as an "incentive stock option" as that term is defined for purposes of Section 422 of the Code or any successor provision.

"Nonqualified Stock Option" means an Option other than an Incentive Stock Option.

"Option" means a right to purchase Common Stock granted under Section 8.

"Parent Company" means a company or other entity that as a result of a Change of Control owns the Company or all or substantially all the Company's assets either directly or through one or more subsidiaries.

"Participant" means any Eligible Person to whom an Award is granted.

"Performance Award" means an Award of Performance Shares or Performance Units granted under Section 7.

"Performance Criteria" has the meaning set forth in Section 16.1.

"Performance Share" means an Award of units denominated in shares of Common Stock granted under Section 7.1.

"Performance Unit" means an Award of units denominated in cash or property other than shares of Common Stock granted under Section 7.2.

"Plan" means the Puget Energy, Inc. 2005 Long-Term Incentive Plan, as the same may be amended from time to time.

"Related Company" means any entity that is directly or indirectly controlled by, in control of or under common control with the Company.

"Restricted Stock" means an Award of shares of Common Stock granted under Section 11, the rights of ownership of which are subject to restrictions prescribed by the Committee.

"Retirement," unless otherwise defined in the instrument evidencing the Award or in a written employment, services or other agreement between the Participant and the Company or a Related Company, means "Retirement" as defined for purposes of the Plan by the Committee or the Company's chief human resources officer or other person performing that function or, if not so defined, means Termination of Service on or after the date the Participant reaches "normal retirement age," as that term is defined in Section 411(a)(8) of the Code.

"Securities Act" means the Securities Act of 1933, as amended from time to time.

"Stock Appreciation Right" or "SAR" means a right granted under Section 10.1 to receive the excess of the Fair Market Value of a specified number of shares of Common Stock over the grant price.

"Stock Award" means an Award of shares of Common Stock granted under Section 11, the rights of ownership of which are not subject to restrictions prescribed by the Committee.

"Stock Unit" means an Award denominated in units of Common Stock granted under Section 11.

"Substitute Awards" means Awards granted or shares of Common Stock issued by the Company in substitution or exchange for awards previously granted by an Acquired Entity.

"Successor Company" means the surviving company, the continuing company, the successor company or Parent Company, as applicable, in connection with a Change of Control.

"Termination of Service" means a termination of employment or service relationship with the Company or a Related Company for any reason, whether voluntary or involuntary, including by reason of death, Disability or Retirement.  Any question as to whether and when there has been a Termination of Service for the purposes of an Award and the cause of such Termination of Service shall be determined by the Company's chief human resources officer or other person performing that function or, with respect to directors and executive officers, by the Committee, whose determination shall be conclusive and binding.  Transfer of a Participant's employment or service relationship between the Company and any Related Company shall not be considered a Termination of Service for purposes of an Award.  Unless the Committee determines otherwise, a Termination of Service shall be deemed to occur if the Participant's employment or service relationship is with an entity that has ceased to be a Related Company.

EX-12.1

Exhibit 12.1

PUGET ENERGY STATEMENT SETTING FORTH COMPUTATIONS OF RATIOS OF EARNINGS TO FIXED CHARGES (Dollars in Thousands)
	Successor						Predecessor
	Year Ended December 31,			Period from February 6, 2009 through December 31,			Period from January 1, 2009 through			Years Ended December 31,
	2010			2009			February 5, 2009			2008			2007			2006
Earnings Available For Fixed Charges:
Pre-tax income:
Income from continuing operations before income taxes	$	32,792		$	256,056		$	21,753		$	214,835		$	257,258		$	259,710
AFUDC - equity		(12,677	)		(4,108	)		(69	)		(2,627	)		(1,351	)		(7,978	)
AFUDC - debt		(14,157	)		(8,864	)		(350	)		(8,610	)		(12,614	)		(15,874	)
Total	$	5,958		$	243,084		$	21,334		$	203,598		$	243,293		$	235,858
Fixed charges:
Interest expense	$	321,167		$	265,675		$	17,291		$	202,582		$	217,823		$	184,013
Other interest		12,677			4,108			69			2,627			1,351			7,978
Portion of rentals representative of the interest factor		5,391			9,131			1,081			11,775			9,199			9,151
Total	$	339,235		$	278,914		$	18,441		$	216,984		$	228,373		$	201,142
Earnings available for combined fixed charges	$	345,193		$	521,998		$	39,775		$	420,582		$	471,666		$	437,000
Ratio of Earnings to Fixed Charges		1.02	x		1.87	x		2.16	x		1.94	x		2.07	x		2.17	x

EX-12.2

Exhibit 12.2

PUGET SOUND ENERGY
STATEMENT SETTING FORTH COMPUTATIONS OF RATIOS OF
EARNINGS TO FIXED CHARGES
(Dollars in Thousands)
	Years Ended December 31,
	2010			2009			2008			2007			2006
Earnings Available For Fixed Charges:
Pre-tax income:
Income from continuing operations before income taxes	$	26,217		$	226,896		$	223,618		$	265,308		$	275,339
AFUDC - equity		(12,677	)		(4,177	)		(2,627	)		(1,351	)		(7,978	)
AFUDC - debt		(14,157	)		(9,215	)		(8,610	)		(12,614	)		(15,874	)
Total	$	(617	)	$	213,504		$	212,381		$	251,342		$	251,487
Fixed charges:
Interest expense	$	235,011		$	211,742		$	203,402		$	219,120		$	184,859
Other interest		12,677			4,177			2,627			1,351			7,978
Portion of rentals representative of the interest factor		5,391			10,212			11,775			9,199			9,151
Total	$	253,079		$	226,131		$	217,804		$	229,670		$	201,988
Earnings available for combined fixed charges	$	252,462		$	439,635		$	430,185		$	481,012		$	453,475
Ratio of Earnings to Fixed Charges		1.00	x		1.94	x		1.98	x		2.09	x		2.25	x

EX-21.1

Exhibit 21.1

Puget Energy, Inc.

SUBSIDIARIES

1.   Puget Sound Energy, Inc.

10885 N.E. Fourth Street, Suite 1200

Bellevue, Washington 98004

EX-21.2

Exhibit 21.2

Puget Sound Energy, Inc.

SUBSIDIARIES

1.   Puget Western, Inc.

19515 North Creek Parkway

Suite 310

Bothell, Washington 98011

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (No. 333-171851) of Puget Sound Energy, Inc. of our report dated March 4, 2011 relating to the financial statements, financial statement schedule and the effectiveness of internal control over financial reporting of Puget Sound Energy, Inc., which appears in this Form 10-K.

/s/PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Seattle, Washington

March 4, 2011

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Kimberly J. Harris, certify that:

I have reviewed this report on Form 10-K of Puget Energy, Inc.;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)      Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)      Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)      Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)      Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s Board of Directors (or persons performing the equivalent functions):

a)      All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)      Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 4, 2011

/s/ Kimberly J. Harris

Kimberly J. Harris

President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Bertrand A. Valdman, certify that:

I have reviewed this report on Form 10-K of Puget Energy, Inc.;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)      Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)      Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)      Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)      Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s Board of Directors (or persons performing the equivalent functions):

a)      All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)      Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 4, 2011

/s/ Bertrand A. Valdman

Bertrand A. Valdman

Senior Vice President and

Chief Financial Officer

EX-31.3

Exhibit 31.3

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Kimberly J. Harris, certify that:

I have reviewed this report on Form 10-K of Puget Sound Energy, Inc.;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)      Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)      Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)      Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)      Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s Board of Directors (or persons performing the equivalent functions):

a)      All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)      Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  March 4, 2011

/s/ Kimberly J. Harris

Kimberly J. Harris

President and Chief Executive Officer

EX-31.4

Exhibit 31.4

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Bertrand A. Valdman, certify that:

I have reviewed this report on Form 10-K of Puget Sound Energy, Inc.;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)      Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)      Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)      Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)      Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s Board of Directors (or persons performing the equivalent functions):

a)      All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)      Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  March 4, 2011

/s/ Bertrand A. Valdman

Bertrand A. Valdman

Senior Vice President and

Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Puget Energy, Inc. and Puget Sound Energy, Inc. (the “Companies”) on Form 10-K for the year ended December 31, 2010 as filed with the Securities and Exchange Commission on the date hereof (the “Form 10-K”), I, Kimberly J. Harris, the President and Chief Executive Officer of the Companies, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Companies.

Date:  March 4, 2011

/s/Kimberly J. Harris

Kimberly J. Harris

President and Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Puget Energy, Inc. and Puget Sound Energy, Inc. (the “Companies”) on Form 10-K for the year ended December 31, 2010 as filed with the Securities and Exchange Commission on the date hereof (the “Form 10-K”), I, Bertrand A. Valdman, Senior Vice President and Chief Financial Officer of the Companies, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Companies.

Date:  March 4, 2011

/s/Bertrand A. Valdman

Bertrand A. Valdman

Senior Vice President and Chief Financial Officer