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, 2014

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 4^th Street, Suite 1200 Bellevue, Washington 98004-5591 (425) 454-6363 91-1969407

1-4393 PUGET SOUND ENERGY, INC. A Washington Corporation 10885 NE 4^th 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 / / No /X/

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

	Page
Definitions	4
Forward-Looking Statements	5
Part I
1.         Business	7
General	7
Regulation and Rates	8
Electric Utility Operating Statistics	11
Electric Supply	13
Natural Gas Utility Operating Statistics	17
Natural Gas Supply for Natural Gas Customers	18
Energy Efficiency	20
Environment	20
Recent and Future Environmental Law and Regulation	21
Executive Officers of the Registrants	23
1A.      Risk Factors	23
1B.      Unresolved Staff Comments	29
2.         Properties	29
3.         Legal Proceedings	29
4.         Mine Safety Disclosures	29
Part II
5.         Market for Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	30
6.         Selected Financial Data	31
7.         Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
7A.      Quantitative and Qualitative Disclosures about Market Risk	55
8.         Financial Statements and Supplementary Data	59
Report of Management and Statement of Responsibility	60
Report of Independent Registered Public Accounting Firm – Puget Energy	61
Report of Independent Registered Public Accounting Firm – Puget Sound Energy	62
9.         Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	123
9A.      Controls and Procedures	123
9B.      Other Information	124
Part III
10.       Directors, Executive Officers and Corporate Governance	124
11.       Executive Compensation	127
12.       Security Ownership of Certain Beneficial Owners and Management and Related	149
Shareholder Matters
13.       Certain Relationships and Related Transactions, and Director Independence	150
14.       Principal Accountant Fees and Services	151
Part IV
15.       Exhibits and Financial Statement Schedules	152
Signatures	153
Exhibit Index	155

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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
ISDA	International Swaps and Derivatives Association
JPUD	Jefferson County Public Utility District
kW	Kilowatt
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
MMBtus	One Million British Thermal Units
MW	Megawatt (one MW equals one thousand kW)
MWh	Megawatt Hour (one MWh equals one thousand kWh)
NAESB	North American Energy Standards Board
NERC	North American Electric Reliability Corporation
Ninth Circuit	United States Court of Appeals for the Ninth Circuit
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
SERP	Supplemental Executive Retirement Plan
Tenaska	Tenaska Power Fund, L.P.
Washington Commission	Washington Utilities and Transportation Commission
Wild Horse	Wild Horse Wind Project

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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 Company records and other data available from third parties.  However, there can be no assurance that Puget Energy’s and PSE’s expectations, beliefs or projections will be achieved or accomplished.  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;

• Inability to manage costs during the rate stay out period through March 31, 2016, due to unforeseen events which would cause increases in costs of operations;

• 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;

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• 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 as a result of municipalization or other government action or negotiated settlement, 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, asset-based or cyber-based attacks, 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, the availability of insurance for certain specific losses,  and the cost of such insurance;

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

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

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

Any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by law, the Company undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events.  New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.  You are also advised to consult 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.

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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.

In 2009, Puget Holdings LLC (Puget Holdings) completed its merger with Puget Energy.  Puget Holdings is owned by a consortium of long-term infrastructure investors including Macquarie Infrastructure Partners I, Macquarie Infrastructure Partners II, Macquarie Capital Group Limited, FSS Infrastructure Trust, the Canada Pension Plan Investment Board (CPPIB), the British Columbia Investment Management Corporation and the Alberta Investment Management Corporation.  As a result of the merger, all of Puget Energy’s common stock is indirectly owned by 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, 2014 and 2013:

	Electric				Gas
	December 31,		Percent		December 31,		Percent
	2014	2013	Change		2014	2013	Change
Customers: 1
Residential	966,144	957,897	0.9	%	733,135	722,680	1.4	%
Commercial	121,814	119,709	1.8	%	55,021	54,569	0.8	%
Industrial	3,457	3,442	0.4	%	2,392	2,409	(0.7	)%
Other	6,144	5,937	3.5	%	209	208	0.5	%
Total	1,097,559	1,086,985	1.0	%	790,757	779,866	1.4	%

_______________

¹  At December 31, 2014, approximately 381,500 customers purchased both electricity and natural gas from PSE as compared to 374,200 at December 31, 2013.

During 2014, PSE’s billed retail and transportation revenue from electric utility operations were derived 51.5% from residential customers, 41.7% from commercial customers, 5.4% from industrial customers and 1.4% from other customers.  PSE’s billed retail revenue from natural gas utility operations were derived 66.5% from residential customers, 29.1% from commercial customers, 2.6% from industrial customers and 1.8% from transportation customers in 2014.  During this period, the largest customer accounted for approximately 1.5% of PSE’s operating revenue.

PSE's revenues and associated expenses are not generated evenly throughout the year, primarily due to seasonal weather patterns and varying wholesale prices for electricity and the amount of hydroelectric energy supplies available to PSE, which makes quarter-to-quarter comparisons difficult. Weather conditions in PSE's service territory have an impact on customer energy usage, affecting PSE's billed revenue and energy supply expenses. PSE normally experiences its highest retail energy sales, and subsequently often higher power costs, during the winter heating season in the first and fourth quarters of the year and its lowest sales and subsequently lower power costs in the third quarter of the year. While fluctuations in weather conditions will continue to affect PSE's billed revenue and energy supply expenses from month to month, PSE's decoupling mechanisms which went into effect on July 1, 2013 for electric and gas operations, are expected to diminish the impact of weather on operating revenue and net income. Under the decoupling mechanism, the Washington Commission allows PSE to record a monthly adjustment to its electric and gas operating revenues related to electric transmission and distribution, gas operations and general administrative costs from residential, commercial and industrial customers to eliminate the effects of

7

abnormal weather, conservation impacts and changes in usage patterns per customer with the exception of the electric business where power costs are not part of the decoupling mechanism. As a result, these electric and gas revenues will be recovered on a per customer basis regardless of actual consumption levels. The energy supply costs, which are part of the Power Cost Adjustment (PCA) and Purchased Gas Adjustment (PGA) mechanisms, are not included in the decoupling mechanism.

In the five-year period ended December 31, 2014, PSE’s gross electric utility plant additions were $3.7 billion and retirements were $409.3 million.  In the same five-year period, PSE’s gross natural gas utility plant additions were $723.2 million and retirements were $96.6 million and PSE’s gross common utility plant additions were $390.7 million and retirements were $372.4 million.  Gross electric utility plant at December 31, 2014 was approximately $9.3 billion, which consisted of 36.0% distribution, 41.8% generation, 14.0% transmission and 8.2% general plant and other.  Gross natural gas utility plant at December 31, 2014 was approximately $3.3 billion, which consisted of 93.3% distribution and 6.7% general plant and other.  Gross common utility general and intangible plant at December 31, 2014 was approximately $512.8 million.

Employees

At December 31, 2014, Puget Energy had no employees and PSE had approximately 2,700 full-time employees.  Approximately 1,100 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 on September 30, 2017 and March 31, 2017, respectively.

Corporate Location

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

Available Information

The information required by Item 101(e) of Regulation S-K is incorporated herein by reference to the material under “Additional Information” in Item 10 Part III of this annual report.

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.

Expedited Rate Filing (ERF)

On February 4, 2013, PSE filed revised tariffs seeking to update its rates established in its base rate proceedings in May 2012. The ERF was limited in scope and rate impact. This filing was primarily intended to establish baseline rates on which the decoupling mechanisms, described below, are proposed to operate. The filing also provided for the collection of property taxes through a property tax tracker mechanism based on cash payments of property tax made by PSE during the year. Any difference between the cash payments and property tax valuation accruals will be deferred and recovered in a property tax tracker.

Decoupling

On October 25, 2012, PSE and the Northwest Energy Coalition (NWEC) filed a petition for an order seeking approval of an electric and a natural gas decoupling mechanism for the recovery of its delivery-system costs and authority to record accounting entries associated with the mechanisms. Included in the amended decoupling petition was a rate plan that allows PSE an opportunity to earn its authorized rate of return without the need for another general rate case process over the plan period. The rate plan includes predetermined annual increases (K factor) to PSE's allowed electric and gas delivery revenue (transmission and distribution), which are effective January of each year, currently 3.0% for electric and 2.2% for gas. Under this plan, PSE, with limited exceptions, would be allowed to file its next general rate case no sooner than April 1, 2015 and no later than April 1, 2016 unless agreed to otherwise by the parties. PSE would continue to be authorized to file for rate changes under existing rate mechanisms such as the PCA and PGA mechanism, and emergency rate relief during the rate plan period.

PSE's rates related to the cumulative deferred decoupling mechanism, accrued at each rate group through the calendar year and effective May 1 in the following year, will be subject to a 3.0% “soft cap” on rate increases. Any amount in excess of the soft cap will be added to the decoupling tracker in subsequent rate periods, subject to a 3.0% soft cap on rate increases in the subsequent year. In addition, PSE and its customers would have shared 50.0% each in any earnings in excess of the authorized rate of return

8

of 7.8%. The customers share of the over earnings will be returned to customers over the subsequent 12 month period beginning May 1 of each year.

On April 24, 2014, the Washington Commission approved PSE’s request to change rates under its electric and natural gas decoupling mechanism, effective May 1, 2014.  The rate change incorporated the effects of an increase to the allowed delivery revenue per customer as well as true-ups to the rate from the prior year.  This represents a rate increase for electric of $10.6 million, or 0.5% annually on total electric revenue, and a rate decrease for natural gas of $1.0 million, or 0.1% annually on total gas revenue.  

Washington Commission Decision

On July 24, 2013, the Public Counsel Division of the Washington State Attorney General's Office (Public Counsel) and the Industrial Customers of Northwest Utilities (ICNU) each filed a petition in Thurston County Superior Court (the Court) seeking judicial reviews of various aspects of the Washington Commission's ERF and decoupling mechanism final order. The parties' petition argues that the order violates various procedural and substantive requirements of the Washington Administrative Procedure Act, and so requests that it be vacated and that the matter be remanded to the Washington Commission. Oral arguments regarding this matter were held on May 9, 2014. On June 25, 2014, the court issued a letter decision in which it affirmed the attrition adjustment (escalating factors referred to as the K-Factor) and the Washington Commission's decision not to consider the case as a general rate case, but reversed and remanded the cost of equity for further adjudication consistent with the court's decision. As a result, there will be evidentiary proceedings regarding return on equity (ROE) in the first quarter of 2015 with an order anticipated in the first half of 2015.

Electric RateCase

On May 7, 2012, the Washington Commission issued its order in PSE's consolidated electric and natural gas general rate case, filed in June 2011, approving a general rate increase for electric customers of $63.3 million or 3.2% annually, and an increase in natural gas rates of $13.4 million or 1.3% annually. The rate increases for electric and natural gas customers became effective May 14, 2012. In its order, the Washington Commission approved a weighted cost of capital of 7.8% and a capital structure that included 48.0% common equity with a return on equity of 9.8%.

On January 31, 2013, the Washington Commission approved a rate change to PSE's Federal Incentive Tracker tariff, effective February 1, 2013. In its order, the Washington Commission incorporated the effects of the Treasury Grant related to the Lower Snake River wind generation project, keeping the ten year amortization period, and inclusion of interest on the unamortized balance of the grants. The rate change passed through 11 months of amortization for both grants to eligible customers over 11 months beginning February 1, 2013, including grant amortization pass-back of $34.6 million and interest pass-back of $23.8 million. This represents an overall average rate decrease of 2.8%.

On October 23, 2013, the Washington Commission approved an update on the Company's Power Cost Only Rate Case (PCORC), effective November 1, 2013, which reflected decreases in the overall normalized power supply costs. This resulted in an estimated revenue decrease of $10.5 million or 0.5% annually.

On December 27, 2013, the Washington Commission approved the annual true-up and rate filing to PSE's Federal Incentive Tracker tariff, effective January 1, 2014. The true-up filing resulted in a total credit of $58.5 million to be passed back to eligible customers over the twelve months, beginning January 1, 2014.  Of the total credit, $37.8 million represents the pass-back of grant amortization and $20.6 million represents the pass through of interest, in addition to a minor true-up associated with the 2013 rate period.  This filing represents an overall average rate increase of 0.3%. 

On April 24, 2014, the Washington Commission approved PSE’s request to change rates under its electric and natural gas property tax tracker mechanism, effective May 1, 2014.  The rate change incorporated the effects of an increase in the amount of property taxes paid as well as true-ups to the rate from the prior year.  This represents a rate increase for electric of $11.0 million, or 0.5% annually, and a rate increase for natural gas of $5.6 million, or 0.6% annually.  

On April 24, 2014, the Washington Commission approved PSE’s request to change rates under its electric and natural gas conservation riders, effective May 1, 2014.  The rate change incorporated the effects of changes in the annual conservation budgets as well as true-ups to the rate from the prior year.  The rate change represents a rate increase for electric of $12.2 million, or 0.5% annually, and a rate increase for natural gas of $0.3 million.

On April 24, 2014, the Washington Commission also approved PSE’s request to change rates under its electric and natural gas decoupling mechanism, effective May 1, 2014.  This represents a rate increase for electric of $10.6 million, or 0.5% annually.

On November 3, 2014, the Washington Commission issued an order on the settlement of the PCORC which PSE filed on May 23, 2014. The original filing proposed a decrease of $9.6 million (or an average of approximately 0.5%) in the Company's overall power supply costs. PSE filed joint testimony supporting a settlement stipulation. Customer rates decreased by approximately $19.4 million, or 0.93% annually, as a result of the settlement, effective December 1, 2014.

For additional information, see Note 3 to the consolidated financial statements included in Item 8 of this report.

9

Natural Gas Rate Case

On May 7, 2012, the Washington Commission issued its order in PSE's consolidated electric and natural gas general rate case filed in June 2011, approving a general rate increase for electric customers of $63.3 million, or 3.2% annually, and an increase in natural gas rates of $13.4 million, or 1.3% annually. The rate increases for electric and natural gas customers became effective May 14, 2012. In its order, the Washington Commission approved a weighted cost of capital of 7.8% and a capital structure that included 48.0% common equity with a return on equity of 9.8%.

On June 1, 2012, PSE filed with the Washington Commission a petition seeking an Accounting Order authorizing PSE to change the existing natural gas conservation tracker mechanism into a rider mechanism to be consistent with the electric conservation program recovery. The accounting petition requested the ability to recover the costs associated with the Company's current gas conservation programs via transfers from amounts deferred for the over recovery of commodity costs in the Company's PGA mechanism. The Washington Commission granted PSE's accounting petition on June 28, 2012. The approved accounting petition resulted in an increase to gas conservation revenues of $6.9 million and an increase to conservation amortization expense of $6.6 million, the difference being recognized as revenue sensitive taxes.

On October 31, 2012, the Washington Commission approved PSE's PGA natural gas tariff filing and allowed the rates to go into effect on November 1, 2012 on a temporary basis subject to revision. The rates resulted in a decrease to the rates charged to customers under the PGA. On May 1, 2013, the Washington Commission approved the proposed rates and allowed them to be made permanent. The estimated revenue impact of the approved change is a decrease of $77.0 million, or 7.7% annually. The rate adjustment has no impact on net operating income.

On October 30, 2013, the Washington Commission approved PSE's PGA natural gas tariff, effective on November 1, 2013, which reflected changes in wholesale gas and pipeline transportation costs and changes in deferral amortization rates. The estimated revenue impact of the approved change is an increase of $4.0 million, or 0.4% annually, with no impact on net operating income.

On April 24, 2014, the Washington Commission approved PSE’s request to change rates under its electric and natural gas decoupling mechanism, effective May 1, 2014.  This represents a rate decrease for natural gas of $1.0 million, or 0.1% annually.

On October 30, 2014, the Washington Commission approved PSE's PGA natural gas tariff, effective on November 1, 2014, which reflected changes in wholesale gas and pipeline transportation costs and changes in deferral amortization rates. The estimated revenue impact of the approved change is a decrease of $23.3 million, or 2.5% annually, with no impact on net operating income.

For additional information, see Note 3 to the consolidated financial statements included in Item 8 of this report.

10

ELECTRIC UTILITY OPERATING STATISTICS

	Year Ended December 31,
	2014			2013			2012
Generation and purchased power, MWh
Company-controlled resources	11,640,504			12,421,626			8,999,259
Contracted resources	4,050,062			4,498,204			6,058,460
Non-firm energy purchased	8,001,425			7,565,140			9,117,094
Total generation and purchased power	23,691,991			24,484,970			24,174,813
Less: losses and Company use	(1,724,501		)	(1,581,108		)	(1,638,649		)
Total energy sales, MWh	21,967,490			22,903,862			22,536,164
Electric energy sales, MWh
Residential	10,412,460			10,718,566			10,744,641
Commercial	8,955,593			8,995,023			9,098,946
Industrial	1,216,903			1,215,442			1,208,801
Other customers	94,932			98,318			101,070
Total energy billed to customers	20,679,888			21,027,349			21,153,458
Unbilled energy sales – net (decrease) increase	(104,010		)	188,606			(7,228		)
Total energy sales to customers	20,575,878			21,215,955			21,146,230
Sales to other utilities and marketers	1,391,612			1,687,907			1,389,934
Total energy sales, MWh	21,967,490			22,903,862			22,536,164
Transportation, including unbilled	2,099,219			2,089,435			1,980,878
Electric energy sales and transportation, MWh	24,066,709			24,993,297			24,517,042
Electric operating revenue by classes (dollars in thousands):
Residential	$	1,035,523		$	1,112,374		$	1,112,727
Commercial	838,606			840,056			853,096
Industrial	108,115			107,602			109,083
Other customers	19,151			19,163			19,210
Operating revenue billed to customers	2,001,395			2,079,195			2,094,116
Unbilled revenue – net (decrease) increase	(45,955		)	11,828			6,309
Total operating revenue from customers	1,955,440			2,091,023			2,100,425
Transportation, including unbilled	9,502			8,738			9,790
Sales to other utilities and marketers	41,680			54,444			23,709
Decoupling Revenue	31,344			(14,989		)	—
Miscellaneous operating revenue	45,831			17,704			(5,694		)
Total electric operating revenue	$	2,083,797		$	2,156,920		$	2,128,230
Number of customers served (average):
Residential	960,708			956,783			961,914
Commercial	121,332			119,833			120,261
Industrial	3,437			3,474			3,600
Other	6,023			5,274			3,504
Transportation	17			17			17
Total customers	1,091,517			1,085,381			1,089,296

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	Year Ended December 31,
	2014			2013			2012
Average kWh used per customer:
Residential	10,838			11,203			11,170
Commercial	73,811			75,063			75,660
Industrial	354,060			349,868			335,778
Other	15,762			18,642			28,844
Average revenue billed per customer:
Residential	$	1,078		$	1,163		$	1,157
Commercial	6,912			7,010			7,094
Industrial	31,456			30,973			30,301
Other	3,180			3,634			5,482
Average retail revenue per kWh sold:
Residential	$	0.0995		$	0.1038		$	0.1036
Commercial	0.0936			0.0934			0.0938
Industrial	0.0888			0.0885			0.0902
Other	0.2017			0.1949			0.1901
Average retail revenue per kWh sold	0.0968			0.0989			0.0990
Heating degree days	3,829			4,734			4,741
Percent of normal - NOAA1 30-year average	81.1		%	100.3		%	100.5		%
Load factor 2	52.3		%	51.2		%	59.9		%

_______________

¹  National Oceanic and Atmospheric Administration (NOAA).

²  Average Megawatt (MW) usage by customers divided by their maximum usage.

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ELECTRIC SUPPLY

At December 31, 2014, 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 4,889 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, 2014 and 2013:

	Peak Power Resources At December 31,						Energy Production At December 31,
	2014			2013			2014			2013
	MW	%		MW	%		MWh	%		MWh	%
Purchased resources:
Columbia River PUD contracts 1	709	14.5	%	712	14.7	%	3,318,746	14.9	%	3,445,954	15.1	%
Other hydroelectric 2	85	1.7		58	1.2		185,943	0.8		165,305	0.7
Other producers 2	464	9.5		408	8.4		815,640	3.7		741,992	3.3
Wind	56	1.2		56	1.2		140,716	0.6		144,952	0.6
Short-term wholesale energy purchases 3	N/A	—		N/A	—		6,198,830	27.8		5,877,234	25.7
Total purchased	1,314	26.9	%	1,234	25.5	%	10,659,875	47.8	%	10,375,437	45.4	%
Company-controlled resources:
Hydroelectric	254	5.2	%	276	5.7	%	1,000,201	4.5	%	837,569	3.7	%
Coal	677	13.8		677	14.0		4,509,567	20.2		4,346,208	19.1
Natural gas/oil	1,871	38.3		1,871	38.8		4,154,983	18.6		5,355,248	23.5
Wind	773	15.8		773	16.0		1,975,754	8.9		1,882,600	8.3
Total company-controlled	3,575	73.1	%	3,597	74.5	%	11,640,505	52.2	%	12,421,625	54.6	%
Total	4,889	100.0	%	4,831	100.0	%	22,300,380	100.0	%	22,797,062	100.0	%

_______________

¹  Net of 36 MW in 2014 and 37 MW in 2013 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 1,391,612 Megawatt Hours (MWh) and 1,687,907 MWh, account for 27.3% and 25.6% of energy production, for 2014 and 2013, respectively.

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Company–Owned Electric Generation Resources

At December 31, 2014, PSE owns the following plants with an aggregate net generating capacity of 3,575 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	297	2007; acquired 2008
Goldendale	Natural gas combined cycle	278	2004; acquired 2007
Frederickson Unit 1 (49.85% interest)	Natural gas combined cycle	136	2002; added duct firing in 2005
Lower Snake River	Wind	343	2012
Wild Horse	Wind	273	2006 & 2009
Hopkins Ridge	Wind	157	2005 & 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
Ferndale	Natural gas co-generation	253	1994; acquired 2012
Encogen	Natural gas co-generation	165	1993; acquired 1999
Sumas	Natural gas co-generation	127	1993; acquired 2008
Upper Baker River 2	Hydroelectric	91	1959
Lower Baker River 2	Hydroelectric	109	1925; reconstructed 1960; upgraded 2001 and 2013
Snoqualmie Falls 3	Hydroelectric	54	1898 to 1911 & 1957; rebuilt 2013
Crystal Mountain	Internal combustion	3	1969
Total net capacity		3,575

_______________

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 was operated pursuant to 50-year license granted by the FERC in October 2008. The license provides protection and enhancements for fish and wildlife, water quality, recreation and cultural and historic resources.

³  The FERC jurisdictional facility was operated pursuant to 40-year license granted by the FERC in June 2004.   

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Columbia River Electric Energy Supply Contracts

During 2014, approximately 14.9% 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, 2014, 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		MW Capacity
Chelan County PUD:
Rock Island Project	2031	2029	25.0	%	156
Rocky Reach Project	2031	2052	25.0	%	325
Douglas County PUD:
Wells Project	2018	2052	29.9	%	251
Grant County PUD:
Priest Rapids Development	2052	2052	0.6	%	8
Wanapum Development	2052	2052	0.6	%	9
Total					749

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.  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 Bonneville Power Administration (BPA) (for 44 aMW of capacity) and with Pacific Gas & Electric Company (for 300 MW of capacity).

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.

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 2014, PSE had 4,646 MW and 695 MW of total transmission demand contracted with the BPA and other utilities, respectively.  PSE’s remaining transmission capacity needs are met via PSE owned transmission assets.

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 2014, approximately 91.2% of natural gas for power purchased by PSE for power customers originated in British Columbia and 8.8% originated in the United States.  

Integrated Resource Plans, Resource Acquisition and Development

PSE is required by Washington Commission regulations to file an electric and natural gas Integrated Resource Plan (IRP) every two years with the next IRP scheduled to be filed by May 30, 2015.  As part of the resource planning process, PSE filed an IRP in 2013.  The 2013 IRP identified the following capacity needs:

	2015	2016	2017	2018	2019
Projected MW shortfall/(surplus)	(140)	(102)	12	61	105

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The expected capacity needs reflect the mix of energy efficiency programs deemed cost effective in the 2013 IRP. In 2013, PSE renewed all the Mid-Columbia (Mid-C) transmission available for renewal during the year to meet peak capacity needs.

As part of the 2013 PCORC, PSE sought approval for the Mid-C transmission renewals executed in 2013. As the Washington Commission approved all the Mid-C transmission renewals requested in the 2013 PCORC, PSE expects to have sufficient resources to meet its capacity needs over the next few years. On February 6, 2014, the Washington Commission formally accepted PSE's 2013 IRP filing.

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NATURAL GAS UTILITY OPERATING STATISTICS

	Year Ended December 31,
	2014			2013			2012
Gas operating revenue by classes (dollars in thousands):
Residential	$	644,055		$	682,636		$	712,805
Commercial firm	252,235			259,315			277,232
Industrial firm	23,887			25,830			29,302
Interruptible	30,770			35,545			37,861
Total retail gas sales	950,947			1,003,326			1,057,200
Transportation services	17,069			16,531			15,434
Decoupling Revenue	31,324			(5,165		)	—
Other	13,520			13,665			13,461
Total gas operating revenue	$	1,012,860		$	1,028,357		$	1,086,095
Number of customers served (average):
Residential	727,244			716,518			706,965
Commercial firm	54,328			53,840			53,728
Industrial firm	2,383			2,394			2,431
Interruptible	449			429			337
Transportation	208			204			194
Total customers	784,612			773,385			763,655
Gas volumes, therms (thousands):
Residential	527,423			572,668			569,308
Commercial firm	242,095			255,543			253,743
Industrial firm	26,481			28,469			29,371
Interruptible	46,113			54,554			51,112
Total retail gas volumes, therms	842,112			911,234			903,534
Transportation volumes	211,429			219,696			225,810
Total volumes	1,053,541			1,130,930			1,129,344
Working gas volumes in storage at year end, therms (thousands):
Jackson Prairie	81,889			76,772			77,968
Clay Basin	29,719			31,594			85,356
Average therms used per customer:
Residential	725			799			805
Commercial firm	4,456			4,746			4,723
Industrial firm	11,112			11,892			12,082
Interruptible	102,701			127,164			151,668
Transportation	1,016,486			1,076,943			1,163,968
Average revenue per customer:
Residential	$	886		$	953		$	1,008
Commercial firm	4,643			4,816			5,160
Industrial firm	10,024			10,789			12,053
Interruptible	68,530			82,855			112,348
Transportation	82,063			81,033			79,559
Average revenue per therm sold:
Residential	$	1.221		$	1.192		$	1.252
Commercial firm	1.042			1.015			1.093
Industrial firm	0.902			0.907			0.998
Interruptible	0.667			0.652			0.741
Average retail revenue per therm sold	1.129			1.101			1.170
Transportation	0.081			0.075			0.068
Heating degree days	3,829			4,734			4,741
Percent of normal - NOAA 30-year average	81.2		%	100.3		%	100.5		%

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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 LLC (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,
	2014				2013
Peak Firm Natural Gas Supply 1	Dth per Day		%		Dth per Day		%
Purchased gas supply:
British Columbia	243,000		28.0	%	185,000		23.9	%
Alberta	99,000		11.4	%	69,000		8.9	%
United States	127,000		14.6	%	120,000		15.5	%
Total purchased natural gas supply	469,000		54.0	%	374,000		48.3	%
Purchased storage capacity:
Jackson Prairie	48,400		5.6	%	48,400		6.3	%
Plymouth liquefied natural gas	—		—	%	—		—	%
Total purchased storage capacity	48,400		5.6	%	48,400		6.3	%
Owned storage capacity:
Jackson Prairie	348,700		40.1	%	348,700		45.1	%
Propane and LNG	2,500		0.3	%	2,500		0.3	%
Total owned storage capacity	351,200		40.4	%	351,200		45.4	%
Total peak firm natural gas supply	868,600		100.0	%	773,600		100.0	%
Other and commitments with third parties	(7,500	)			(5,200	)
Total net peak firm natural gas supply	861,100				768,400

_______________

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

For base load, 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 supplement purchases from the U.S. Rocky Mountain supply region, while Jackson Prairie provides incremental peak-day resources utilizing firm 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 PSE’s Liquefied Natural Gas (LNG) peaking facility located within its distribution system in Gig Harbor, Washington; and interrupting service to customers on interruptible service rates, if necessary.

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 2014, approximately 57.1% of natural gas purchased by PSE for its natural gas customers originated in British Columbia, 18.1% originated in Alberta and 24.8% 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 resulting economics of these transactions 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 solely operated and one-third owned by PSE and is used primarily for intermediate peaking purposes due to its ability to deliver a large volume of natural gas over a relatively short

18

time period.  Combined with capacity contracted from NWP’s one-third stake in Jackson Prairie, PSE holds firm withdrawal capacity in excess of 453,800 Dekatherm (Dth) per day, and over 9.8 million Dth of storage capacity at the Jackson Prairie facility. Of this total, PSE holds 397,000 Dth per day of the firm withdrawal capacity and over 9.2 million Dth of storage capacity designated to serve natural gas customers, which represents nearly 45.7% of PSE's expected near-term peak-day requirement. 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.   

Of the remaining Jackson Prairie storage capacity, 56,700 Dth per day of firm withdrawal capacity and 600,000 Dth of the storage capacity is currently designated to PSE's power portfolio, increasing natural gas supply reliability and facilitating intra-day dispatch of PSE's natural gas-fired generation resources. In addition, PSE has temporarily released approximately 6,000 Dth per day of firm withdrawal capacity and 200,0000 of Dth of storage capacity to a third party, in exchange for temporary firm pipeline capacity on a constrained portion of NWP's system.

The Clay Basin storage facility is a supply area storage facility that provides operational flexibility and price protection.  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 three and five years and has rights to extend such agreements.  PSE’s total storage capacity and maximum firm withdrawal capacity at Clay Basin, net of temporarily releases, exceeds 8.9 million Dth and is over 74,000 Dth per day, 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, at a maximum daily deliverability of 70,500 Dth.  During 2014, PSE, working with NWP, determined that the pipeline redelivery to PSE from the Plymouth LNG facility can no longer be considered firm and reliable during peak conditions. Therefore, PSE has removed the Plymouth service from its firm portfolio and given notice to NWP of its intent to terminate the Plymouth service agreement effective October 31, 2015. PSE is negotiating with NWP and other market participants to replace the Plymouth service with an alternate firm resource to accommodate expected future load growth. 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 vaporized propane-air injection facility is designed to deliver the thermal equivalent of 10,000 Dth of natural gas per day for up to 12 days directly into PSE’s distribution system, however, it is temporarily not in-service pending planned environmental, safety, efficiency and reliability upgrades.  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 Spectra's 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 523,000 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 450,000 Dth per day of seasonal firm capacity on NWP to provide for delivery of natural gas stored in Jackson Prairie.  PSE holds approximately 168,000 Dth per day firm transportation capacity on NWP to supply natural gas to its electric generating facilities.  PSE’s firm transportation capacity contracts with NWP have remaining terms ranging from four to 30 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 per day under various contracts, with remaining terms of two to five years.  PSE has other firm transportation capacity on Westcoast’s pipeline, which supplies the electric generating facilities, totaling approximately 85,000 Dth per day, with remaining terms of two to four years.  PSE has firm transportation capacity on NOVA and Foothills pipelines, totaling approximately 85,000 Dth per day, with remaining terms of one to nine years.  PSE has annual renewal rights on the capacity on NOVA and Foothills pipelines.  PSE’s firm transportation capacity on the GTN pipeline, totaling approximately 90,000 Dth per day, has a remaining term of nine years and the first right-of-refusal to extend such contracts under current FERC rules.

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

19

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 all available conservation that is cost-effective, reliable and feasible. 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.  PSE recovers the actual costs of its electric and natural gas energy efficiency programs through rider mechanisms.  However, the rider mechanisms do not provide for any cost recovery of lost sales margin associated with reduced energy sales.  To address this issue, PSE received approval in 2013 from the Washington Commission for electric and gas decoupling mechanisms.

Since 1997, PSE has recovered direct electric energy efficiency (or conservation) expenditures through an electric rider mechanism. To recover gas expenditures, from 1997 to 2011, PSE used a tracker mechanism, which recovered actual gas expenditures in the year following the year in which the expenditures were incurred. In 2012, the Washington Commission directed PSE to convert gas expenditure recovery to a rider mechanism, consistent with the electric expenditure recovery methodology.  The rider mechanism allows PSE to defer the efficiency expenditures and amortize them to expense as PSE collects them in rates over a one-year period.

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 natural gas plants and an ownership percentage of a coal plant in Colstrip, Montana.  All these facilities are governed by the Clean Air Act (CAA) and all have CAA Title V operation permits which must be renewed every five years.  This renewal process could result in additional costs to the plants. PSE continues to monitor these developments to determine the corresponding potential impact to the plants. These facilities also emit greenhouse gases (GHG), and thus are also subject to any current or future GHG or climate change legislation or regulation.  The Colstrip plant represents PSE’s most significant source of GHG emissions.

Species Protection

PSE owns hydroelectric plants, 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 sites.  These include properties currently and formerly owned by PSE (or its predecessors), as well as third party owned properties where hazardous substances were allegedly generated, transported or released.  The primary cleanup laws that PSE is subject to 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, transporter, arranger, or disposer of regulated substances.

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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.  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 generation facilities (and all those with water discharges and some with bulk fuel storage), and 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, distribution or other related facilities, 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, in addition to other possible local siting and zoning ordinances.  These requirements may potentially require mitigation of environmental impacts as well as other measures that can add significant cost to new facilities.

RECENT AND FUTURE ENVIRONMENTAL LAW AND REGULATION

Recent and future environmental laws and regulations may be imposed at a federal, state or local level and may have a significant impact on the 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.  Described below are the recent, pending and potential future environmental law and regulations with the most significant potential impacts to PSE’s operations and costs.

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.  As climate policy continues to evolve at the state and federal levels, 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 known impact of any future legislation or new government regulation on the cost of generation in its IRP process.

On January 8, 2014, the Environmental Protection Agency (EPA) issued a proposed New Source Performance Standard (NSPS) for the control of carbon dioxide (CO2) from new power plants that burn fossil fuels under section 111(b) of the Clean Air Act. The EPA first proposed a NSPS for emissions for CO2 from new power plants in April 2012. However, after more than 2.5 million comments on the original proposal, the EPA decided that a new approach was warranted and rescinded the April 2012 proposal. The EPA is currently proposing an emissions limit for coal-fired sources of 1,100 lb. CO2/MWh, and proposes standards for natural gas combined cycle sources from 1,000 to 1,100 lb. CO2/MWh depending on the size and type of unit. Under the January 8, 2014 NSPS proposal, the Agency concluded that Carbon Capture and Storage (CCS) has been adequately demonstrated as a technology for controlling CO2 emissions in full-scale commercial applications at coal-fired electrical generating units (EGUs), while reaching the opposite conclusion, that CCS is not adequately demonstrated, in the case of gas-fired generators. PSE submitted comments by the end of the comment period on May 9, 2014. The EPA is expected to issue the final rule within the next 12 months. States have one year after the effective date of the standard to adopt the final rule.

On June 2, 2014, the EPA proposed guidelines under section 111(d) of the Clean Air Act for the control of CO2 emissions from existing fossil fuel-fired power plants. The proposed guidelines are estimated by the EPA to reduce total power sector carbon emissions 30% from 2005 levels by 2030 through the setting of individual emissions targets for each state. The EPA is applying its “best system of emission reductions” (BSER) approach for reducing CO2 emissions from the electric power sector, consisting of increasing the efficiency of power generation and substituting higher emitting plants with lower emitting technologies. The EPA is using the following four step approach to establish its reduction targets: (1) improving the heat rate of individual generating units, thereby reducing the amount of CO2 produced per unit of electricity generated, (2) prioritizing dispatch of existing (and new) natural gas combined cycle (NGCC) generation over coal-fired generation, (3) accounting for increasing renewable generation and nuclear generation that is under construction or will have extended life and (4) improving demand-side energy efficiency to reduce the amount of electricity generation required.

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States will be given the flexibility to choose the emissions reduction strategies best suited to their reduction requirements, and they can select technologies and techniques beyond what is defined in BSER, provided the emission reductions are verifiable and approved by the EPA. States must achieve their state-specific interim goal by 2025 and their state-specific final goal by 2030. PSE filed comments on this rule on December 1, 2014, which was the end of the comment period. The EPA initially stated that it will issue a final rule in June 2015 and that states must submit a plan for implementing CO2 reductions to the EPA one to three years following issuance of the final rule. Recently the EPA extended this timeframe and stated that it plans to issue the final 111(d) and 111(b) rules simultaneously in August 2015.

Each year, PSE is required to submit, on an annual basis, a report of its GHG emissions to the State of Washington including a report of emissions from all individual power plants emitting over 10,000 tons per year of GHGs and from certain natural gas distribution operations.  Emissions exceeding 25,000 tons per year of GHGs from these sources must also be reported to the EPA. 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 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 2013 were 9.9 million tons of carbon dioxide equivalents.  Approximately 41.4% of PSE’s total GHG emissions (approximately 4.1 million tons) are associated with PSE’s ownership and contractual interests in Colstrip.

While Colstrip remains a significant portion of PSE’s GHG emissions, Colstrip is an essential part of the existing 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

Mercury control equipment has been installed at Colstrip and has operated at a level that meets the current Montana requirement.  Compliance based on a rolling 12-month average was first confirmed in January 2011 and has continued to meet the requirement.

The EPA published the final Mercury and Air Toxics Standard (MATS) in February 2012. Generating units have 3 years, until April 2015, to comply with MATS and could receive up to a 1-year extension from state permitting authorities if necessary for the installation of controls. Testing confirms that Colstrip currently meets the MATS limits for mercury and acid gases. Units 3 & 4 meet the particulate surrogate for other metals. Modifications to the Unit 1 & 2 scrubbers are required to meet the particulate limit in the MATS rule. PSE has installed sieve trays in three of the six scrubbers and will install them in the remaining scrubbers by 2016. Testing of the scrubbers subsequent to modification shows that it can meet the MATS particulate limit.

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.  The final Federal Implementation Plan for Montana (FIP) for Regional Haze was issued in September 2012. There are no immediate requirements for Units 3&4, but Units 1&2 will need to upgrade pollution controls to meet new sulfur dioxide and nitrogen oxide limits. The Sierra Club filed an appeal of the FIP with the United States Court of Appeals for the Ninth Circuit (Ninth Circuit) on November 15, 2012 and PPL Montana also filed an appeal as the Colstrip operator. The case was heard on May 15, 2014 in Seattle, Washington and a final decision by the Ninth Circuit is still pending. PSE cannot at this time predict the impact of the matter on the Company.

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 (CCR) from Electric Utilities” which proposes different regulatory mechanisms to regulate coal ash. On December 19, 2014, the EPA signed and made public a final rule, although this rule has not yet been published in the Federal Register. The new rule proposes a non-hazardous approach to regulating CCRs. The rule is intended to regulate the disposal of CCR as solid waste under Subtitle D of the Resource Conservation and Recovery Act (RCRA). Subtitle D establishes nationally applicable minimum criteria for the safe, environmentally-sound waste management practices for the disposal of non-hazardous solid waste in landfills and surface impoundments (often referred to as ponds). The actual planning and direct implementation of the solid waste program under Subtitle D remains with the state and local regulators. Included in the rule’s minimum criteria are requirements for location restrictions, design criteria, surface and groundwater monitoring and enhanced record keeping. PSE is currently evaluating the final rule and cannot at this time predict the impact of the matter on the Company.

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PCB Handling and Disposal

On April 7, 2010, the EPA issued an Advance Notice of Proposed Rule Making (ANPRM) soliciting information on a broad range of questions concerning inventory, management, use, and disposal of polychlorinated biphenyl (PCB) containing equipment.  The 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.

The rule is currently scheduled to be published in July 2015. Because the EPA received extensive comments, the rule has undergone multiple extensions and revisions. At this point, PSE cannot determine what impacts this ANPRM will have on its operations, if any, but will continue to work closely with the Utility Solid Waste Activities Group (USWAG) and the American Gas Association (AGA) to monitor developments.

EXECUTIVE OFFICERS OF THE REGISTRANTS

The executive officers of Puget Energy as of February 27, 2015 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	50	President and Chief Executive Officer since March 1, 2011; President July 2010 – February 2011; Executive Vice President and Chief Resource Officer 2007 – 2010.
D. A. Doyle	56	Senior Vice President and Chief Financial Officer since November 2011.  Prior to PSE, he was President of Wisconsin Sports Development Corporation 2010 – November 2011.
S. R. Secrist	53	Senior Vice President, General Counsel and Chief Ethics and Compliance Officer since January 2014; Vice President, General Counsel and Chief Ethics and Compliance Officer January 2011-January 2014; Interim General Counsel October 2010 – January 2011; Deputy General Counsel 2006 – October 2010.
M. J. Stranik	51	Controller and Principal Accounting Officer since June 2012; Assistant Controller - Financial Reporting March 2011 – June 2012; Assistant Controller November 2002 – March 2011.

The executive officers of PSE as of February 27, 2015 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	50	President and Chief Executive Officer since March 1, 2011; President July 2010 – February 2011; Executive Vice President and Chief Resource Officer 2007 – 2010.
D. A. Doyle	56	Senior Vice President and Chief Financial Officer since November 2011.  Prior to PSE, he was President of Wisconsin Sports Development Corporation 2010 – November 2011.
P. K. Bussey	58	Senior Vice President and Chief Customer Officer since March 2012. Prior to PSE, he was President and Chief Executive Officer of Seattle Metropolitan Chamber May 2009 - March 2012.
M. D. Mellies	54	Senior Vice President and Chief Administrative Officer since February 2011; Vice President Human Resources 2005 – January 2011.
S. R. Secrist	53	Senior Vice President, General Counsel and Chief Ethics and Compliance Officer since January 2014; Vice President, General Counsel and Chief Ethics and Compliance Officer January 2011-January 2014; Interim General Counsel October 2010 – January 2011; Deputy General Counsel 2006 – October 2010.
M. J. Stranik	51	Controller and Principal Accounting Officer since June 2012; Assistant Controller - Financial Reporting March 2011 – June 2012; Assistant Controller November 2002 – March 2011.

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.

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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 the wholesale level, 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 normalized assumptions about rate year power costs, weather and hydrological conditions.  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 the aforementioned 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.

PSE has additional risks associated with the Washington Commission approved stay out period, which doesn't allow for any general rate case filings to be filed earlier than April 1, 2015 without extraordinary circumstances.

PSE will have additional risks if PSE's costs are not within the pre-approved annual increases in allowed revenue per customer (3.3% for electric customers; 2.2% natural gas customers), as earnings will be below the authorized rate of return and due to the stay out period, PSE cannot file for general rate increases unless it is for emergency rate relief. If PSE earns above its authorized rate of return, PSE will need to share the excess earnings above the threshold of 7.8% with customers.  The earnings test is done for each service (electric/natural gas) separately, so the risk would be if PSE over earns on one and under earns on the other service, PSE would still be obligated to share the earnings for that service exceeding the threshold (there is no offset for the service under earning).

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 owned and controlled power resources in the near future.  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.

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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:

• 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;

• 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;

• New laws or regulations that necessitate significant investments in our plants;

• Future costs such as remediation that could necessitate significant expenditures but are presently unknown, not required by existing laws or regulations, or are such that they are not estimable at this time;

• Terrorist or other attacks (both cyber-based and/or asset-based); and

• Catastrophic events such as fires, explosions or acts of nature.

If PSE is unable to protect its physical assets from terrorist attacks or its information technology infrastructure and network against data corruption, cyber-based attacks or network security breaches, its operations could be disrupted.

Despite PSE's implementation of security measures, its physical assets and technology systems may be vulnerable to disability, failures or unauthorized access due to hacking, viruses, acts of war or terrorism and other causes.  If our technology systems were to fail or be breached and we were unable to recover in a timely manner, we may be unable to fulfill critical business functions and sensitive, confidential and other data could be compromised, which could have a material adverse effect on our results of operations, financial condition and cash flows.  In addition, these physical asset or cyber-based attacks could disrupt our ability to produce or distribute some portion of our energy products and could affect the reliability or operability of the electric and natural gas systems. As a result, PSE endeavors to maintain unceasing vigilance against the continuous threat of physical asset and cyber-based attacks.

PSE is subject to the commodity price, delivery and credit risks associated with the energy markets as well as to supply and price risks affecting PSE’s construction and maintenance programs.  

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.

Further, as a consequence of its electric generation construction and reconstruction programs and investments in its electric and gas distribution systems, PSE contracts to purchase substantial quantities of steel, cable, and similar materials, and thus is

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subject to supply and price risks affecting these items.  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 costs 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 issues, including air emissions and climate change, endangered species protection, remediation of contamination, avian protection, waste handling and disposal, decommissioning, water protection and siting new facilities.  To comply with these legal requirements, PSE must spend significant sums of money 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.  Compliance with these or other future regulations could require significant 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.

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 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 renewable portfolio standards and greenhouse gas legislation, including an emission performance standard provision.   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 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. Demand for electricity is 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 winter. In the event that the Company experiences unusually mild winters, its 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, repair and restart 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 or ineffective response to extreme events may have an adverse effect 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.

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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 the current interest rate environment and therefore, adverse market performance or low interest rates 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 2015 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.

Potential municipalization or technological developments may adversely affect PSE's financial condition.

PSE may be adversely affected if we experience a loss in the number of our customers due to municipalization or other related government action.  When a town or city in our service territory establishes its own municipal-owned utility, it acquires our assets and takes over the delivery of energy services that we provide.  Any such loss of customers and related revenue could negatively affect PSE's financial condition.  In addition, there is also the risk that advances in power generation, energy efficiency and other alternative energy technologies, such as solar generation, could lead to more wide-spread use of these technologies, thereby reducing customer demand for the energy supplied by PSE which could negatively impact PSE's revenue and financial condition. 

RISKS RELATING TO PUGET ENERGY AND PSE OPERATIONS

The Company's business is dependent on its ability to successfully access capital.

The Company relies on access to internally generated funds, bank borrowings through multi-year committed credit facilities and short-term money markets as sources of liquidity and longer-term debt markets to fund PSE's utility construction program and other capital expenditure requirements of PSE.  If Puget Energy or PSE are unable to access capital on reasonable terms, their 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 Puget Energy's or PSE's credit rating or the imposition of restrictions on borrowings under their credit facilities in the event of a deterioration of financial ratios, may increase Puget Energy's and PSE’s cost of borrowing or adversely affect the ability to access one or more financial markets.

The amount of the Company's debt could adversely affect its liquidity and results of operations.

Puget Energy and PSE have short-term and long-term debt, and may incur additional debt (including secured debt) in the future.  Puget Energy has access to a multi-year $800.0 million revolving credit facility, secured by substantially all of its assets, which has a maturity date of April 15, 2018. No amount was outstanding under the facility as of December 31, 2014.  Puget Energy's credit facility includes an accordion feature that could, upon the banks' approval, increase the size of the facility to $1.3 billion. Puget Energy is party to three separate term loan agreements totaling $299.0 million, which it entered into on June 26, 2014. The term loans mature in 2016 and 2017.  PSE also has two credit facilities, which provide PSE with access to $1.0 billion in short-term borrowing capability, and include an accordion feature that could, upon the banks' approval, increase the size of the facilities to $1.450 billion. The two PSE credit facilities mature on April 15, 2019. As of December 31, 2014, no amounts were drawn and outstanding under the PSE credit facilities. In addition, Puget Energy has issued $1.4 billion in senior secured notes, whereas PSE, as of December 31, 2014 had approximately $3.8 billion outstanding under first mortgage bonds, pollution control bonds, senior notes and junior subordinated notes.  The Company's debt level could have important effects on the business, including but not limited to:

• Making it difficult to satisfy obligations under the debt agreements and increasing the risk of default on the debt obligations;

• Making it difficult to fund non-debt service related operations of the business; and

• Limiting the Company's financial flexibility, including its ability to borrow additional funds on favorable terms or at all.

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.

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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.

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.  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.  These judgments may include reserves for potential adverse outcomes regarding tax positions that may be subject to challenge by the taxing authorities.

Potential legislation and regulatory actions could increase the Company’s costs, reduce the Company’s revenue and cash flow, or otherwise alter the way the Company conducts business.

In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank) was signed into law.  Title VII of the Dodd-Frank law gave regulators including the Commodities Futures Trading Commission (CFTC) and the Securities and Exchange Commission the authority to create new oversight structures for derivative financial instruments, which were widely thought to have contributed to the 2008 financial crisis. The new regulation of certain over-the-counter swaps could expand collateral requirements of swaps, which may make it more costly for companies and/or limit the Company’s ability to enter into such transactions. The Dodd-Frank law amended section 2(h) (7) of the Commodities Exchange Act to provide an elective exemption from the clearing requirements of Title VII of the Dodd-Frank law for any entity that is not a financial entity, is using swaps to hedge or mitigate commercial risk, and notifies the CFTC, in a manner set forth by the CFTC, how it generally meets its financial obligations associated with entering into non-cleared swaps. The Company has elected to employ the "End-User Exception" to clearing on its applicable treasury department transactions, and will likely employ the End-User Exception to clearing on commodities transactions after applicable final regulations for those transactions are adopted. The Company continues to evaluate the legislation and the CFTC’s implementation of it to determine its impact, if any, on the Company’s hedging program, results of operations and liquidity. The Company is aware that the Dodd-Frank law will increase recordkeeping and certain administrative costs for applicable transactions, but will not know the full impact of the new legislation until the regulations are finalized and the Company's compliance systems are fully implemented.

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.  In addition, 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 Adjusted 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 47.7% at December 31, 2014 and the EBITDA to interest expense was 4.3 to 1.0 for the 12 months then ended.

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 (as defined in the facilities), or if the payment of dividends would result in an Event of Default, such as failure to comply with certain financial covenants.

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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 or legislative/rule-making proceedings relating to its operations in the normal course of business.  The following is a description of proceedings that are material to PSE’s operations:

Colstrip

PSE has a 50% ownership interest in Colstrip Units 1 and 2, and a 25% interest in Colstrip Units 3 and 4.  On March 6, 2013, Sierra Club and Montana Environmental Information Center (MEIC) filed a Clean Air Act citizen suit against all Colstrip owners (including PSE) in the U.S. District Court, District of Montana.  Based on a second amended complaint filed in August 2014, Plaintiffs’ lawsuit currently alleges violations of permitting requirements under the New Source Review program of the Clean Air Act and the Montana State Implementation Plan arising from seven projects undertaken at Colstrip from 2001-2012.  Plaintiffs have since indicated that they do not intend to pursue two of the seven projects, leaving a total of five projects remaining.  The lawsuit claims that, for each project, Colstrip should have obtained a permit and installed pollution control equipment at Colstrip.  The Plaintiffs’ complaint also seeks civil penalties and other appropriate relief.  The case has been bifurcated into separate liability and remedy trials. Discovery in the case is ongoing.  The liability trial is currently set for November 2015, and a date for the remedy trial has yet to be determined.  PSE is litigating the allegations set forth in the complaint and as such, it is not reasonably possible to estimate the outcome of this matter.

EPA Draft Rule 111(d)

In June 2014, the EPA issued a proposed rule under Section 111(d) of the Clean Air Act designed to regulate greenhouse gas emissions from existing power plants.  The proposed rule includes state-specific goals and guidelines for states to develop plans for meeting these goals. PSE filed comments on this rule in December 2014. The EPA initially stated that it will issue a final rule in June 2015 and that states must submit a plan for implementing CO2 reductions to the EPA one to three years following issuance of the final rule. Recently the EPA extended the time to issue the final rule to August 2015. PSE is continuing to review of the proposed rule and work with key stakeholders to monitor it as the rule moves forward towards possible final implementation.  PSE cannot yet provide a determination of how the final rule, may impact PSE or its existing generation facilities, if at all.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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PART II

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

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 LLC (Puget Equico), which is an indirect wholly-owned subsidiary of Puget Holdings, and are not publicly traded.  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.

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.

From time to time, when deemed advisable and permitted, each of PSE and Puget Energy pay dividends on its common stock. During 2014, 2013 and 2012, PSE paid dividends to its parent, Puget Energy, and Puget Energy paid dividends to its parent, Puget Equico, in the amounts shown in Puget Energy's and PSE's Consolidated Statements of Common Shareholder's Equity, included in this report.

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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.

Puget Energy Summary of Operations	Year Ended December 31,
(Dollars in Thousands)	2014		2013		2012		2011		2010
Operating revenue	$	3,113,171	$	3,187,297	$	3,215,156	$	3,318,765	$	3,122,217
Operating income	577,851		755,160		715,535		474,940		308,234
Net income	171,835		285,728		273,821		123,290		30,311
Total assets at year end	$	12,835,048	$	12,906,575	$	12,835,275	$	12,407,306	$	11,929,336
Long-term debt	4,831,608		4,982,476		5,083,200		5,027,367		4,132,713
Junior subordinated notes	250,000		250,000		250,000		250,000		250,000
Capital lease obligations	9,473		17,051		24,629		32,207		42,603

Puget Sound Energy Summary of Operations	Year Ended December 31,
(Dollars in Thousands)	2014		2013		2012		2011		2010
Operating revenue	$	3,116,123	$	3,187,335	$	3,216,259	$	3,319,803	$	3,122,217
Operating income	568,693		735,574		692,989		431,043		207,591
Net income	236,614		356,129		356,170		204,120		26,095
Total assets at year end	$	10,789,862	$	10,808,888	$	10,627,971	$	10,108,143	$	9,310,784
Long-term debt	3,351,259		3,513,258		3,513,258		3,523,845		2,953,860
Junior subordinated notes	250,000		250,000		250,000		250,000		250,000
Capital lease obligations	9,473		17,051		24,629		32,207		—

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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. In 2009, Puget Holdings completed its merger with Puget Energy. Puget Holdings is owned by a consortium of long-term infrastructure investors including Macquarie Infrastructure Partners I, Macquarie Infrastructure Partners II, Macquarie Capital Group Limited, 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, all of Puget Energy's common stock is indirectly owned by 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.”

The Company's mission is to be a safe, dependable and efficient utility. The Company's objectives are to focus on safety, employees, operational excellence, customer service and financial strength. The Company's strategies are aligned to achieve these objectives and ultimately the Company's mission.

These strategies involve numerous commitments and investments related to utility infrastructure and customer service, which may give rise to expenditures that may not be recovered timely through the ratemaking process.  PSE has undertaken several initiatives to reduce the volatility and regulatory lag in the business. During 2013, PSE completed an ERF, which is a limited scope rate proceeding, and established a decoupling mechanism for gas operations and electric transmission, distribution and administrative costs. The ERF proceeding established baseline rates on which the decoupling mechanism will operate going forward. The ERF also established a property tax tracker mechanism in which any difference between amounts in rates and property tax payments will be deferred and recovered in an annual filing based on the annual cash payments for the year.

The decoupling mechanism allows PSE to recover costs on a per customer basis rather than on a consumption basis. Included in the decoupling petition was a rate plan that allows PSE an opportunity to earn its authorized rate of return without the need for another general rate case process during the rate plan period. The rate plan included predetermined annual increases to PSE’s allowed electric and natural gas revenue. This plan, with limited exceptions (PCORC or emergency rate relief), requires PSE to file a general rate case no sooner than April 1, 2015 and no later than April 1, 2016. The decoupling mechanism also allows for decoupling revenue on a per customer basis to subsequently increase by 3.0% for electric customers and 2.2% for natural gas customers on January 1 of each year, until the effective date of PSE’s next general rate case. In addition, the decoupling mechanism reduces earnings volatility, but does not materially affect the timing of cash flow due to the timing difference between the recognition of decoupling revenue and resulting impacts on rates.

Washington state law also requires PSE to pursue conservation initiatives that promote efficient use of energy. PSE’s mandate to pursue conservation initiatives may have a negative impact on the electric business financial performance due to lost margins

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from lower sales volumes as power costs are not part of the decoupling mechanism. This mandate, however, will only have a slight negative impact on natural gas business financial performance due to the natural gas business being almost fully decoupled. 

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. PSE expects to be in balance between its load requirements and generation resources for the next two or three years. 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, 2014 as compared to the prior year, PSE’s net income was affected by the following four factors:  (1) changes in unrealized gain and loss in derivative instruments for energy contracts; (2) increase in utility operations and maintenance expense due to bad debt expense and transmission and distribution expenses; (3) increased gas and electric margins driven by decoupling, which went into effect July 1, 2013 and (4) a reduction in interest income related to regulatory assets.

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

NON-GAAP FINANCIAL MEASURES

The following discussion includes financial information prepared in accordance with U.S. 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 divided by average common equity) that is considered a “non-GAAP financial measure.”  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 investors' capital. The return on average of monthly averages (AMA) equity is not intended to represent the regulated return on equity. PSE's return on equity may not be comparable to other companies return on equity measures.  Furthermore, this measure is not intended to replace return on equity (net income divided by average common equity) as determined in accordance with GAAP as an indicator of operating performance.

The following table presents PSE’s authorized regulated return on equity for 2014 and 2013:

	2014							2013
(Dollars in Thousands)	Earnings		Average Common Equity			Return On Equity		Earnings			Average Common Equity		Return On Equity
Return on equity  - GAAP	$	236,614	$	3,359,743		7.0	%	$	356,129		3,422,251		10.4	%
Less/Plus: Unrealized gains and losses on derivative instruments, after-tax	55,663		—			*		(64,272		)	—		*
Less: Equity adjustments 1	—		251,467			*		—			113,985		*
Plus: Impact of average of monthly average (AMA)	—		(64,487		)	*		—			111,598		*
Return on AMA equity	$	292,277	$	3,546,723		8.2	%	$	291,857		$	3,647,834	8.0	%
Authorized regulated return on equity						9.8	%						9.8	%

_______________

¹  Equity adjustments are related to removing the impacts of accumulated Other Comprehensive Income (OCI), subsidiary retained earnings and retained earnings of derivative instruments.

^*  Not meaningful.

The Company’s 2014 return on AMA equity, excluding unrealized gains and loss on derivative instruments and any impacts of OCI, subsidiary retained earnings and retained earnings of derivative instruments, was 8.2%, which is lower than the authorized regulated return on equity primarily due to the following:

• Utility operations and maintenance expense was $22.1 million higher than the amount allowed in rates for the year ended December 31, 2014.  The increase was driven by higher costs in electric production, general and administration, bad debt and customer service expenses.

• Depreciation expense was $5.3 million higher than the amount allowed in rates for the year ended December 31, 2014.  The increase was primarily due to additional electric expenditures placed into service.

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The Company’s 2013 return on equity, excluding derivative instruments, was 8.0%, which is lower than the authorized return on equity primarily due to the following:

• Utility operations and maintenance expense was $15.6 million higher than the amount allowed in rates for the year ended December 31, 2013.  The increase was driven by an increase in costs in electric production, administration and general expenses and customer service expense.

• Depreciation expense was $36.4 million higher than the amount allowed in rates for the year ended December 31, 2013.  The increase was primarily due to additional electric expenditures placed into service.

Factors and Trends Affecting PSE’s Performance  

PSE’s regulatory requirements and operational needs require the investment of substantial capital in 2014 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 reduces 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 power costs that are included in rates which are based on volume;

• PSE’s ability to manage costs during the rate stay out period through March 31, 2016;

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

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

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

• Equal sharing between PSE and its customers of earnings which exceed PSE's authorized rate of return;

• 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;

• Wholesale commodity prices of electricity and natural gas;

• Increasing depreciation; and

• Federal, state, and local taxes.

Regulation of PSE Rates and Recovery of PSE Costs

The rates that PSE is allowed to charge for its services influence its financial condition, results of operations and liquidity. PSE is highly regulated and the rates that it charges its retail customers are approved by the Washington Commission. The Washington Commission has traditionally required these rates be determined based, to a large extent, on historic test year costs plus weather normalized assumptions about hydroelectric conditions and power costs in the relevant rate year. Incremental customer growth and sales typically have not provided sufficient revenue to cover year-to-year cost growth, thus rate increases are required. If, in a particular year, PSE's costs are higher than what is currently 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 some of PSE's costs do not meet the standard applied, those costs may be disallowed partially or entirely and not recovered in rates.

Expedited Rate Filing

On February 4, 2013, PSE filed revised tariffs seeking to update its rates established in its base rate proceedings in May 2012 known as an Expedited Rate Filing (ERF). The ERF was limited in scope and rate impact. This filing was primarily intended to establish baseline rates on which the decoupling mechanisms, described below, are proposed to operate. The filing also provided for the collection of property taxes through a property tax tracker mechanism based on cash payments of property tax made by PSE during the year. Any difference between the cash payments and property tax valuation accruals will be deferred and recovered in a property tax tracker.

Decoupling

On October 25, 2012, PSE and the Northwest Energy Coalition (NWEC) filed a petition for an order seeking approval of an electric and a natural gas decoupling mechanism for the recovery of PSE's delivery-system costs and authority to record accounting

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entries associated with the mechanisms. Included in the amended decoupling petition was a rate plan that allows PSE an opportunity to earn its authorized rate of return without the need for another general rate case process over the plan period. The rate plan includes predetermined annual increases (K factor) to PSE's allowed electric and gas delivery revenue (transmission and delivery), which are effective January of each year, currently 3.0% for electric and 2.2% for gas. Under this plan, PSE, with limited exceptions, would be allowed to file its next general rate case no sooner than April 1, 2015 and no later than April 1, 2016 unless agreed to otherwise by the parties. PSE would continue to be authorized to file for rate changes under existing rate mechanisms such as the PCA and PGA mechanism, and emergency rate relief during the rate plan period.

PSE's rates related to the cumulative deferred decoupling mechanism accrued by each rate group through the calendar year and effective May 1 in the following year, will be subject to a 3.0% “soft cap” on rate increases. Any amount in excess of the soft cap will be added to the decoupling tracker in subsequent rate periods, subject to a 3.0% soft cap on rate increases in the subsequent year. In addition, PSE and its customers would have shared 50.0% each in any earnings in excess of the authorized rate of return of 7.8%. The customers' share of the over earnings will be returned to customers over the subsequent 12 month period beginning May 1 of each year.

On April 24, 2014, the Washington Commission approved PSE’s request to change rates under its electric and natural gas decoupling mechanism, effective May 1, 2014.  The rate change incorporated the effects of an increase to the allowed delivery revenue per customer as well as true-ups to the rate from the prior year.  This represents a rate increase for electric of $10.6 million, or 0.5% annually on total electric revenue, and a rate decrease for natural gas of $1.0 million, or 0.1% annually on total gas revenue.  

Washington Commission Decision

On July 24, 2013, the Public Counsel Division of the Washington State Attorney General's Office (Public Counsel) and the Industrial Customers of Northwest Utilities (ICNU) each filed a petition in Thurston County Superior Court (the Court) seeking judicial review of various aspects of the Washington Commission's ERF and decoupling mechanism final order. The parties' petition argues that the order violates various procedural and substantive requirements of the Washington Administrative Procedure Act, and so requests that it be vacated and that the matter be remanded to the Washington Commission. Oral arguments regarding this matter were held on May 9, 2014. On June 25, 2014, the court issued a letter decision in which it affirmed the attrition adjustment K-Factor and the Washington Commission's decision not to consider the case as a general rate case, but reversed and remanded the cost of equity for further adjudication consistent with the court's decision. As a result, there will be evidentiary proceedings regarding return on equity (ROE) in the first quarter of 2015 with an order anticipated in the first half of 2015.

Electric Rates

PSE has a PCA mechanism that provides for the recovery of power costs from customers or refunding of power cost savings to customers in the event those costs vary from the “power cost baseline” level of power costs. The “power cost baseline” levels are set, in part, based on normalized assumptions about weather and hydroelectric conditions.  Excess power costs or power cost savings are apportioned between PSE and its customers pursuant to the graduated scale set forth in the PCA mechanism.

The graduated scale is as follows:

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

PSE under recovered during the year ended December 31, 2014, due to $40.1 million below the “power cost baseline” level of which $10.1 million was apportioned to customers.  This compares to an over recovery of $37.8 million for the year ended December 31, 2013 of which $8.9 million was apportioned to customers.

On May 7, 2012, the Washington Commission issued its order in PSE's consolidated electric and natural gas general rate case filed in June 2011, approving a general rate increase for electric customers of $63.3 million, or 3.2% annually, and an increase in natural gas rates of $13.4 million, or 1.3% annually. The rate increases for electric and natural gas customers became effective May 14, 2012. In its order, the Washington Commission approved a weighted cost of capital of 7.8% and a capital structure that included 48.0% common equity with a return on equity of 9.8%.

On January 31, 2013, the Washington Commission approved a rate change to PSE's Federal Incentive Tracker tariff, effective February 1, 2013, which incorporated the effects of the Treasury Grant related to the Lower Snake River wind generation project and keeping the ten year amortization period and inclusion of interest on the unamortized balance of the grants. The rate change passed through eleven months of amortization for both grants to eligible customers over eleven months beginning February 1, 2013, including grant amortization pass-back of $34.6 million and interest pass-back of $23.8 million. This represents an overall average rate decrease of 2.8%.

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On October 23, 2013, the Washington Commission approved an update on the Company's PCORC, effective November 1, 2013, which reflected decreases in the overall normalized power supply costs. This resulted in an estimated revenue decrease of $10.5 million, or 0.5% annually.

On December 27, 2013, the Washington Commission approved the annual true-up and rate filing to PSE's Federal Incentive Tracker tariff, effective January 1, 2014. The true-up filing resulted in a total credit of $58.5 million to be passed back to eligible customers over the twelve months beginning January 1, 2014.  Of the total credit, $37.8 million represents the pass-back of grant amortization and $20.6 million represents the pass through of interest, in addition to a minor true-up associated with the 2013 rate period.  This filing represents an overall average rate increase of 0.3%. 

On April 24, 2014, the Washington Commission approved PSE’s request to change rates under its electric and natural gas decoupling mechanism, effective May 1, 2014.  This represents a rate increase for electric of $10.6 million, or 0.5% annually.

On November 3, 2014, the Washington Commission issued an order on the settlement of the PCORC, which PSE filed on May 23, 2014. The original filing proposed a decrease of $9.6 million (or an average of approximately 0.5%) in the Company's overall power supply costs. PSE filed joint testimony supporting a settlement stipulation. Customer rates decreased by approximately $19.4 million, or 0.9% annually, as a result of the settlement, effective December 1, 2014.

For additional information, see Note 3 to the consolidated financial statements included in Item 8 of this report.

Natural Gas Rates

PSE has a PGA mechanism that 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. 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 natural gas cost through rates.

On May 7, 2012, the Washington Commission issued its order in PSE's consolidated electric and natural gas general rate case filed in June 2011, approving a general rate increase for electric customers of $63.3 million, or 3.2% annually, and an increase in natural gas rates of $13.4 million, or 1.3% annually. The rate increases for electric and natural gas customers became effective May 14, 2012. In its order, the Washington Commission approved a weighted cost of capital of 7.8% and a capital structure that included 48.0% common equity with a return on equity of 9.8%.

On June 1, 2012, PSE filed with the Washington Commission a petition seeking an Accounting Order authorizing PSE to change the existing natural gas conservation tracker mechanism into a rider mechanism to be consistent with the electric conservation program recovery. The accounting petition requested the ability to recover the costs associated with the Company's current gas conservation programs via transfers from amounts deferred for the over-recovery of commodity costs in the Company's PGA mechanism. The Washington Commission granted PSE's accounting petition on June 28, 2012. The approved accounting petition resulted in an increase to gas conservation revenues of $6.9 million and an increase to conservation amortization expense of $6.6 million, the difference being recognized as revenue sensitive taxes.

On October 31, 2012, the Washington Commission approved PSE's PGA natural gas tariff filing and allowed the rates to go into effect on November 1, 2012 on a temporary basis subject to revision. The rates resulted in a decrease to the rates charged to customers under the PGA. On May 1, 2013, the Washington Commission approved the proposed rates and allowed them to be made permanent. The estimated revenue impact of the approved change is a decrease of $77.0 million, or 7.7% annually. The rate adjustment has no impact on net operating income.

On October 30, 2013, the Washington Commission approved PSE's PGA natural gas tariff, effective on November 1, 2013, which reflected changes in wholesale gas and pipeline transportation costs and changes in deferral amortization rates. The estimated revenue impact of the approved change is an increase of $4.0 million, or 0.4% annually, with no impact on net operating income.

On October 30, 2013, the Washington Commission approved PSE's Pipeline Replacement Program Plan (PRPP) that would accelerate and enhance the safety of the natural gas system and ultimately reduce costs. Under the PRPP plan, PSE would be allowed to file a tariff revision to recover its costs associated with the acceleration of the replacement of natural gas pipelines with the Washington Commission.

On April 24, 2014, the Washington Commission approved PSE’s request to change rates under its electric and natural gas decoupling mechanism, effective May 1, 2014.  This represents a rate decrease for natural gas of $1.0 million, or 0.1% annually.

On October 30, 2014, the Washington Commission approved PSE's PGA natural gas tariff filing with an effective date of November 1, 2014, which reflected changes in wholesale gas and pipeline transportation costs and changes in deferral amortization rates. The impact to the PGA rates is an annual revenue decrease of $23.3 million, or 2.5% annually, with no impact on net operating income.

For additional information, see Note 3 to the consolidated financial statements included in Item 8 of this report.

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Weather Conditions

Weather conditions in PSE's service territory have an impact on customer energy usage, affecting PSE's billed revenue and energy supply expenses. PSE's operating revenue and associated energy supply expenses are not generated evenly throughout the year. While both PSE's electric and natural gas sales are generally greatest during winter months, variations in energy usage by customers occur from season to season and month to month within a season, primarily as a result of weather conditions. PSE normally experiences its highest retail energy sales, and subsequently higher power costs, during the winter heating season in the first and fourth quarters of the year and its lowest sales in the third quarter of the year. Varying wholesale electric prices and the amount of hydroelectric energy supplies available to PSE also make quarter-to-quarter comparisons difficult. PSE reported lower usage by its residential electric customers in the twelve months ended December 31, 2014, primarily due to Pacific Northwest temperatures being warmer on average as compared to the same period in the prior year. The actual average temperature during the twelve months ended December 31, 2014 was 55.34 degrees, or 1.01 degrees warmer than the same period in the prior year, and 2.70 degrees warmer when compared to the historical average.

Revenue Decoupling

While fluctuations in weather conditions will continue to affect PSE's billed revenue and energy supply expenses from month to month, PSE's decoupling mechanisms which went into effect on July 1, 2013 for electric and gas operations, are expected to diminish the impact of weather on operating revenue and net income. The Washington Commission has allowed PSE to record a monthly adjustment to its electric and gas operating revenues related to electric transmission and distribution, gas operations and general administrative costs from residential, commercial and industrial customers to eliminate the effects of abnormal weather, conservation impacts and changes in usage patterns per customer with the exception of the electric business where power costs are not part of the decoupling mechanism. As a result, these electric and gas revenues will be recovered on a per customer basis regardless of actual consumption levels. The energy supply costs, which are part of the PCA and PGA mechanisms, are not included in the decoupling mechanism. The revenue recorded under the decoupling mechanisms will be affected by customer growth and not actual consumption. Following each calendar year, PSE will bill or refund the difference between allowed decoupling revenue and the corresponding actual revenue to affected customers during the following May to April time period.

Effective January 1, 2014, certain high volume natural gas industrial customers' rate schedules were excluded from the decoupling mechanism. As a result, PSE will be subject to certain effects of abnormal weather, conservation impacts and changes in customer usage patterns for these customers.

Customer Demand

PSE expects the number of natural gas customers to grow at rates slightly above that of electric customers. PSE also expects energy usage by both residential electric and natural gas customers to continue a long-term trend of slow decline primarily due to continued energy efficiency improvements.

Access to Debt Capital

PSE relies on access to bank borrowings and short-term money markets as sources of liquidity and longer-term capital 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, the borrowing costs increase as their respective credit ratings decline due to increases in credit spreads and commitment fees. 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. PSE's credit facilities expire in 2019 and Puget Energy's senior secured credit facility expires in 2018. (See discussion on credit facilities in the section entitled “Financing Program - Credit Facilities and Commercial Paper”).

Regulatory Compliance Costs and Expenditures

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

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

Other Challenges and Strategies

Competition. PSE’s electric and natural gas utility retail customers currently do not have the ability to choose their electric or natural gas supplier and therefore, PSE’s business has historically been recognized as a natural monopoly. However, PSE faces increasing competition for sales to its retail customers.  Alternative methods of electric energy generation, including solar and other self-generation methods, compete with PSE for sales to existing electric retail customers.  In addition, PSE’s natural gas customers may elect to use heating oil, propane or other fuels instead of using and purchasing natural gas from PSE.  Further, PSE faces competition from public utility districts and municipalities that want to establish their own municipal-owned utility, as a result of which PSE may lose a number of customers in its service territory.

Energy Supply.  As noted in PSE's IRP filed with the Washington Commission, PSE projects that beginning in 2017, its future energy needs will exceed current resources in its supply portfolio.  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, amortization and operating expenses, which are not recovered through the ratemaking process in a timely manner. 

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

Grant County PUD Purchase Power Contract. On February 27, 2014, Grant County PUD discovered a sixty-five foot long, two inch wide crack in a spillway pier at its Wanapum Development Project. PSE is party to a purchased power contract with Grant County PUD, pursuant to which PSE takes 0.64% of the output from the project and pays a proportional share of the operating cost of the project. Grant County PUD has lowered the reservoir level 26 feet below normal to begin repairs. Interim repairs were completed in November 2014 and the reservoir was raised 16 feet on December 1, 2014, still 10 feet below normal. This condition will remain into the second quarter of 2015. The Chelan County PUD Rock Island Project, which is upstream from the Wanapum Development Project, is still impacted, but is expected to run on a more regular basis. The engineering assessment of the crack repairs, required to restore the project to normal operations, has been developed and is expected to be completed near the end of April 2015. The impact to power costs is estimated to be $2.6 million over the next 30 years, our proportionate share of the estimated $60.0 million cost to mitigate this condition. All additional power cost increases are subject to the Company’s PCA mechanism sharing bands.

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

IBEW Contract. The contract between PSE and the International Brotherhood of Electrical Workers Local Union 77 (IBEW) expired on March 31, 2014.  There are approximately 850 PSE employees represented by the IBEW who perform work in customer service, electric operations and energy production.  After more than a year of negotiations, a new contract was ratified by the IBEW on December 11, 2014.  It is effective through March 31, 2017. 

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RESULTS OF OPERATIONS

Puget Sound Energy

The following discussion should be read in conjunction with the audited consolidated financial statements and the related notes included elsewhere in this document.  The following discussion provides the significant items that impacted PSE’s results of operations for the years ended December 31, 2014 and 2013.  Set forth below are the consolidated financial results of PSE for the years ended December 31, 2014, 2013 and 2012:

Puget Sound Energy	Year Ended December 31,						Favorable/(Unfavorable)		Year Ended December 31,			Favorable/(Unfavorable)
(Dollars in Thousands)	2014			2013					2012
Operating revenue:
Electric
Residential sales	$	1,035,523		$	1,112,374		(6.9	)%	$	1,112,727		*
Commercial sales	838,606			840,056			(0.2	)	853,096			(1.5	)
Industrial sales	108,115			107,602			0.5		109,083			(1.4	)
Other retail sales, including unbilled revenue	(26,804		)	30,991			*		25,519			21.4
Total retail sales	1,955,440			2,091,023			(6.5	)	2,100,425			(0.4	)
Transportation sales	9,502			8,738			8.7		9,790			(10.7	)
Sales to other utilities and marketers	41,680			54,444			(23.4	)	23,709			129.6
Decoupling revenue	31,344			(14,989		)	*		—			*
Other	45,831			17,704			*		(5,694		)	*
Total electric operating revenue	2,083,797			2,156,920			(3.4	)	2,128,230			1.3
Gas
Residential sales	644,054			682,636			(5.7	)	712,805			(4.2	)
Commercial sales	281,526			293,102			(3.9	)	313,051			(6.4	)
Industrial sales	25,366			27,588			(8.1	)	31,344			(12.0	)
Total retail sales	950,946			1,003,326			(5.2	)	1,057,200			(5.1	)
Transportation sales	17,069			16,531			3.3		15,434			7.1
Decoupling revenue	31,324			(5,165		)	*		—			*
Other	13,520			13,665			(1.1	)	13,461			1.5
Total gas operating revenue	1,012,859			1,028,357			(1.5	)	1,086,095			(5.3	)
Non-utility operating revenue	19,467			2,058			*		1,934			6.4
Total operating revenue	3,116,123			3,187,335			(2.2	)	3,216,259			(0.9	)
Operating expenses:
Energy costs:
Purchased electricity	514,087			541,905			5.1		622,288			12.9
Electric generation fuel	263,493			261,332			(0.8	)	204,956			(27.5	)
Residential exchange	(129,036		)	(81,053		)	59.2		(73,555		)	10.2
Purchased gas	458,691			488,201			6.0		538,612			9.4
Net unrealized (gain) loss on derivative instruments	85,636			(98,880		)	*		(119,120		)	(17.0	)
Utility operations and maintenance	550,146			529,939			(3.8	)	512,765			(3.3	)
Non-utility expense and other	23,729			12,205			(94.4	)	9,977			(22.3	)
Depreciation	370,962			364,324			(1.8	)	337,952			(7.8	)
Amortization	(5,356		)	24,631			121.7		55,819			55.9
Conservation amortization	104,096			105,897			1.7		114,177			7.3
Taxes other than income taxes	310,982			303,260			(2.5	)	319,399			5.1
Total operating expenses	2,547,430			2,451,761			(3.9	)	2,523,270			2.8
Operating income	568,693			735,574			(22.7	)	692,989			6.1
Other income	24,036			38,690			(37.9	)	49,056			(21.1	)
Other expense	(7,457		)	(7,134		)	(4.5	)	(11,770		)	39.4
Interest expense	(259,316		)	(250,115		)	(3.7	)	(224,797		)	(11.3	)
Income before income taxes	325,956			517,015			(37.0	)	505,478			2.3
Income tax expense	89,342			160,886			44.5		149,308			(7.8	)
Net income	$	236,614		$	356,129		(33.6	)%	$	356,170		*

_____________

^*  Not meaningful.

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Non-GAAP Financial Measures – Electric and Gas Margins

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

Electric Margin

The following table displays the details of PSE’s electric margin changes from periods 2014 to 2013 and periods 2013 to 2012.  Electric margin represents electric sales to retail and transportation customers less the cost of generating and purchasing electric energy sold to customers, including transmission costs to bring electric energy to PSE’s service territory.

Electric Margin	Year Ended December 31,						Percent Change		Year Ended December 31,			Percent Change
(Dollars in Thousands)	2014			2013					2012
Electric operating revenue:
Residential sales	$	1,035,523		$	1,112,374		(6.9	)%	$	1,112,727		*
Commercial sales	838,606			840,056			(0.2	)%	853,096			(1.5	)%
Industrial sales	108,115			107,602			0.5	%	109,083			(1.4	)%
Other retail sales, including unbilled revenues	(26,804		)	30,991			*		25,519			21.4	%
Total retail sales	1,955,440			2,091,023			(6.5	)%	2,100,425			(0.4	)%
Transportation sales	9,502			8,738			8.7	%	9,790			(10.7	)%
Sales to other utilities and marketers	41,680			54,444			(23.4	)%	23,709			129.6	%
Decoupling revenue	31,344			(14,989		)	*		—			*
Other	45,831			17,704			*		(5,694		)	*
Total electric operating revenues1	2,083,797			2,156,920			(3.4	)%	2,128,230			1.3	%
Minus power costs:
Purchased electricity1	(514,087		)	(541,905		)	(5.1	)%	(622,288		)	(12.9	)%
Electric generation fuel1	(263,493		)	(261,332		)	0.8	%	(204,956		)	27.5	%
Residential exchange1	129,036			81,053			59.2	%	73,555			10.2	%
Total electric power costs	(648,544		)	(722,184		)	(10.2	)%	(753,689		)	(4.2	)%
Electric margin2	$	1,435,253		$	1,434,736		0.0	%	$	1,374,541		4.4	%

______________

¹  As reported on PSE’s Consolidated Statement of Income.

²  Electric margin does not include any allocation for amortization/depreciation expense or electric generation operation and maintenance expense.

^*  Percent change not applicable or meaningful.

Electric margin increased$0.5 million and $60.2 million for the years ended December 31, 2014 and December 31, 2013, respectively.  Following is a discussion of significant items that impact electric operating revenue and electric energy costs which are included in electric margin:

2014 compared to 2013

Electric Operating Revenue

Electric operating revenuesdecreased$73.1 million, or 3.4%, to $2,083.8 million from $2,156.9 million for the year ended December 31, 2014 as compared to the same period in 2013.   Operating revenue decreased$73.1 million primarily due to lower residential sales of $76.9 million, lower other retail sales of $57.8 million and lower sales to other utilities and marketers of $12.8 million, partially offset by increased decoupling revenue and other operating revenue of $46.3 million and $28.1 million, respectively.  These items are discussed in detail below.

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Electric retail salesdecreased$135.6 million, or 6.5%, to $1,955.4 million from $2,091.0 million for the year ended December 31, 2014 as compared to the same period in 2013.  Electric retail sales decreased due to a net revenue decrease of $72.5 million, primarily due to the Jefferson County Public Utility District (JPUD) gain of $51.8 million, which was refunded to customers in December 2014, PCORC rate decreases effective December 1, 2014 of $19.4 million annually, or 0.9%, and effective November 1, 2013 of $10.5 million annually, or 0.5%. In addition, retail revenue decreased $63.1 million due to lower retail electricity usage of 640,076 MWhs, or 3.0%, for the year ended December 31, 2014 as compared to the same period in 2013.

Sales to other utilities and marketers decreased$12.8 million for the year ended December 31, 2014 as compared to the same period in 2013.  The decrease was primarily due to lower wholesale electricity prices which decreased revenue by $3.2 million and a decrease in sales volume of 296,295 MWhs, or 17.6%, which decreased revenue $9.6 million.  

Decoupling revenue resulted in an additional $31.3 million of revenue as a result of decoupling for the year ended December 31, 2014 due to lower volumetric revenues compared to the allowed decoupled revenues per customer. This is compared to a decrease of $15.0 million in decoupling revenue in the same period in 2013. The decoupling receivable will be recovered from customers through a future rate filing beginning May 1, 2015.

Other electric operating revenueincreased$28.1 million for the year ended December 31, 2014 as compared to the same period in 2013.  For the year ended December 31, 2014, other electric operating revenues increased primarily due to non-core gas sales of $13.5 million and biogas revenues of $10.5 million.

Electric Energy Costs

Purchased electricity expense decreased$27.8 million, or 5.1%, for the year ended December 31, 2014 as compared to the same period in 2013.  The decrease in purchased electricity expense for the year ended December 31, 2014 was primarily the result of a decrease of $17.8 million due to a market price offset and a $6.6 million decrease in long-term firm purchases and market purchases for the year ended December 31, 2014 as compared to the same period in 2013.

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.

Residential exchange creditsincreased$48.0 million, or 59.2%, for the year ended December 31, 2014 as compared to the same period in 2013 resulting from higher Residential Exchange Program (REP) credits associated with the BPA REP settlement.  The REP credit is a pass-through tariff item with a corresponding credit in electric operating revenue, with no impact on net income.

2013 compared to 2012

Electric Operating Revenue

Electric operating revenues increased $28.7 million, or 1.3%, to $2,156.9 million from $2,128.2 million for the year ended December 31, 2013 as compared to the same period in 2012.   Operating revenue increased $28.7 million primarily due to higher sales to other utilities and marketers of $30.7 million and higher miscellaneous other operating revenue of $23.4 million offset by decoupling revenue over-collection of $15.0 million and lower electric retail sales of $9.4 million.   These items are discussed in detail below.

Electric retail sales decreased $9.4 million, or 0.4%, to $2,091.0 million from $2,100.4 million for the year ended December 31, 2013 as compared to the same period in 2012. Electric retail sales decreased due to a net revenue decrease of $16.4 million, primarily due to PSE's Federal Incentive Tracker tariff which passes through to customers the benefits of federal income tax incentives with no impact on earnings. The offset is recorded in amortization expense and federal tax expense. The decrease was offset by the electric rate increase of 3.2% effective May 14, 2012, the expedited rate filing and the decoupling rate increase of 2.5% which became effective July 1, 2013 and various other pass-through tariff items that have no impact on earnings. The decrease was offset by a net revenue increase of $6.9 million due to higher retail electricity usage of 69,719 MWhs, or 0.3%, primarily due to higher usage by its commercial and industrial electric customers for the year ended December 31, 2013 as compared to the same period in 2012.

Sales to other utilities and marketers increased $30.7 million for the year ended December 31, 2013 as compared to the same period in 2012.  The increase was primarily due to an increase in wholesale electricity prices which increased revenue by $25.7 million and an increase in sales volume of 297,973 MWhs, or 21.4%, which increased revenue $5.1 million.  

Decoupling revenue resulted in a decrease of $15.0 million for the year ended December 31, 2013 due to higher volumetric revenues over the decoupled revenues per customer under the decoupling mechanism effective July1, 2013. The offset is recorded in regulatory liability which will be passed back to customers through a rate filing beginning May 1, 2014 over a 12-month period.

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Other electric operating revenue increased $23.4 million for the year ended December 31, 2013 as compared to the same period in 2012.  For the year ended December 31, 2013, other electric operating revenues increased primarily due to lower losses on non-core gas sales of $16.0 million and higher transmission revenue of $7.1 million.

Electric Energy Costs

Purchased electricity expense decreased $80.4 million, or 12.9%, for the year ended December 31, 2013 as compared to the same period in 2012.  The decrease in purchased electricity expense for the year ended December 31, 2013 was primarily the result of a $102.4 million decrease in long-term firm purchases and market purchases. This decrease was partially offset by an increase of $9.4 million due to a market price offset and increase of $7.7 million in transmission expense for the year ended December 31, 2013 as compared to the same period in 2012.

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 $56.4 million, or 27.5%, for the year ended December 31, 2013 as compared to the same period in 2012.  The increase was primarily due to a $48.3 million increase in fuel expense at PSE's combustion turbine facilities primarily resulting from an increase in electric generation at combustion turbine facilities of 2,735,066 MWhs, or 104.4%, as compared to the same period in 2012. Also contributing to the increase was a $9.8 million increase in fuel expense at PSE's Colstrip Unit 1 & 2 primarily due to the two plants which were taken offline in 2012 for maintenance for an extended period and reintroduced into production when it was more economical to generate energy at a later point in time. The increase was offset by a decrease of $1.7 million in fuel expense at Colstrip Unit 3 & 4 primarily due to Unit 4, which was shut down for repair and maintenance starting July 2013. Unit 4 returned to service in February 2014.

Residential exchange credits increased $7.5 million, or 10.2%, for the year ended December 31, 2013 as compared to the same period in 2012 as a result of higher REP tariff prices 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.0

Natural Gas Margin

The following table displays the details of PSE’s natural gas margin changes from 2014 to 2013 and 2013 to 2012.  Gas margin is natural gas sales to retail and transportation customers less the cost of natural gas purchased, including transportation costs to bring natural gas to PSE’s service territory.

Natural Gas Margin	Year Ended December 31,						Percent Change		Year Ended December 31,			Percent Change
(Dollars in Thousands)	2014			2013					2012
Gas operating revenue:
Residential sales	$	644,054		$	682,636		(5.7	)%	$	712,805		(4.2	)%
Commercial sales	281,526			293,102			(3.9	)	313,051			(6.4	)
Industrial sales	25,366			27,588			(8.1	)	31,344			(12.0	)
Total retail sales	$	950,946		$	1,003,326		(5.2	)	$	1,057,200		(5.1	)
Transportation sales	17,069			16,531			3.3		15,434			7.1
Decoupling revenue	31,324			(5,165		)	*		—			*
Other	13,520			13,665			(1.1	)	13,461			1.5
Total gas operating revenues1	$	1,012,859		$	1,028,357		(1.5	)	$	1,086,095		(5.3	)
Minus purchased gas costs1	$	(458,691	)	$	(488,201	)	(6.0	)	$	(538,612	)	(9.4	)
Natural gas margin2	$	554,168		$	540,156		2.6	%	$	547,483		(1.3	)%

___________________

¹  As reported on PSE’s Consolidated Statement of Income.

²  Gas margin does not include any allocation for amortization/depreciation expense or electric generation operations and maintenance expense.

^*  Percent change not applicable or meaningful.

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Natural gas margin increased$14.0 million for the year ended December 31, 2014 and decreased$7.3 million for the year ended December 31, 2013.  Following is a discussion of significant items that impact gas operating revenue and gas energy costs which are included in natural gas margin:

2014 compared to 2013

Gas Operating Revenue

Gas operating revenue decreased$15.5 million, or 1.5%, to $1,012.9 million from $1,028.4 million for the year ended December 31, 2014 as compared to the same period in 2013.  The decrease in gas operating revenue of $15.5 million was due primarily to lower natural gas retail sales revenue of $52.4 million as a result of lower natural gas costs. These items are discussed in detail below.

Natural gas retail sales revenuedecreased$52.4 million, or 5.2%, to $950.9 million from $1,003.3 million for the year ended December 31, 2014 as compared to the same period in 2013. The decrease in natural gas retail sales for the year ended December 31, 2014 as compared to the same period in 2013 was primarily due to a decrease of $76.1 million, or 7.6%, in natural gas therm sales. In addition, decreases in PSE's decoupling rate of $1.0 million, or 0.1% annually, effective May1, 2014, and PGA rate reduction of $19.9 million, or 2.1% annually, effective November 1, 2014.

Decoupling revenue resulted in an additional $31.3 million of revenue as a result of decoupling for the year ended December 31, 2014 due to lower volumetric revenues compared to the allowed decoupled revenue per customer. This is compared to a decrease of $5.2 million of revenue in the same period in 2013. The decoupling receivable will be recovered from customers through a future filing beginning May 1, 2015.

Gas Energy Costs

Purchased gas expense decreased$29.5 million, or 6.0%, for the year ended December 31, 2014 as compared to the same period in 2013.   The decrease was primarily due to lower natural gas costs reflected in PGA rates, which were effective November 1, 2013 and December 1, 2014. In addition, customer usage decreased 7.6% for the year ended December 31, 2014 as compared to the same period in 2013.

The PGA mechanism provides the rates used to determine natural gas costs based on customer usage. The rate decrease was the result of decreasing 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. 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 natural gas cost through rates. A payable balance reflects an over-recovery of natural gas cost through rates. The PGA mechanism receivable balance at December 31, 2014 was $21.1 million, which will be recovered from customers through a future PGA rate filing.

2013 compared to 2012

Gas operating revenue decreased $57.7 million, or 5.3%, to $1,028.4 million from $1,086.1 million for the year ended December 31, 2013 as compared to the same period in 2012.  The decrease in gas operating revenue of $57.7 million was due primarily to lower natural gas retail sales revenue of $53.9 million as a result of lower natural gas costs. These items are discussed in detail below.

Natural gas retail sales revenue decreased $53.9 million, or 5.1%, to $1,003.3 million from $1,057.2 million for the year ended December 31, 2013 as compared to the same period in 2012. The decrease in natural gas retail sales for the year ended December 31, 2013 as compared to the same period in 2012 was primarily due to a net $56.0 million decrease mostly related to the PGA rate decrease effective November 1, 2012. The PGA mechanism passes through to customers increases or decreases in the natural gas supply portion of the natural gas service rates based upon changes in the price of natural gas purchased from producers and wholesale marketers or changes in natural gas pipeline transportation costs. PSE's net income is not affected by changes under the PGA mechanism. Also contributing was a decrease of $6.9 million related to gas conservation revenues as a result of an approved accounting petition authorizing PSE to recover the costs associated with the Company's 2012 gas conservation programs via transfers from amounts deferred for the over-recovery of commodity costs in the Company's PGA commodity account. This had no impact on earnings as conservation expense increased by the same amount. Partially offsetting these decreases was an increase of 7.7 million in therm sales, or 0.9%, that resulted in a $9.0 million revenue increase.

Decoupling revenue resulted in an over-collection of $5.2 million for the year ended December 31, 2013 due to higher volumetric revenues over the decoupled revenues per customer under the decoupling mechanism effective July 1, 2013. The offset is recorded in regulatory liability which will be passed back to customers through a rate filing beginning May 1, 2014 over a 12 month period.

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Gas Energy Costs

Purchased gas expense decreased $50.4 million, or 9.4%, for the year ended December 31, 2013 as compared to the same period in 2012.   The decrease was primarily due to lower natural gas costs reflected in PGA rates which were effective November 1, 2012. Partially offsetting the decrease was an increase in customer usage of 0.9% for the year ended December 31, 2013 as compared to the same period in 2012. The PGA mechanism payable balance at December 31, 2013 was $5.9 million.

2014 compared to 2013

Other Operating Expenses

Net unrealized gain on derivative instrumentsdecreased$184.5 million for the year ended December 31, 2014 as compared to the same period in 2013.  The net loss was comprised of a $66.1 million loss related to PSE's natural gas derivative instruments for power and a loss of $118.4 million related to electricity derivative instruments.  This compares to a loss of $29.4 million related to PSE's natural gas for power derivative instruments and a gain of $9.1 million related to electricity derivative instruments, respectively, during the same period in 2013.  The decrease was primarily due to decreases in natural gas and wholesale electricity forward prices over the three-year tenor of PSE's energy supply hedging program. 

Utility operations and maintenance expense increased$20.2 million, or 3.8%, for the year ended December 31, 2014 as compared to the same period in 2013.  The increase was primarily driven by an increase of $10.4 million in bad debts expense and $10.1 million in electric transmission and distribution expenses for year ended December 31, 2014.

Non-utility operations and maintenance expense increased$11.5 million, or 94.4%, for the year ended December 31, 2014 as compared to the same period in 2013. Biogas expense increased by $10.7 million during 2014 due to a full year of purchases in 2014 as compared to only two months during 2013.

Depreciation expense increased$6.6 million, or 1.8%, for the year ended December 31, 2014 as compared to the same period in 2013. The increase was primarily due to $9.5 million of electric depreciation expense from additional capital expenditures placed into service, net of retirements, such as the Snoqualmie and Baker hydroelectric generating facility additions, which went into service in 2013. Gas depreciation also increased in the amount of $3.6 million, mainly due to new additions. The increase was offset by a decrease of $6.3 million in common utility plant, mainly due to the retirement of computer equipment.

Amortization expense decreased$30.0 million, or 121.7%, for the year ended December 31, 2014 as compared to the same period in 2013. The decrease was primarily due to the gain for the sale of assets in Jefferson County that was refunded to customers in the amount of $51.8 million. Partially offsetting the decrease was a reduction of $15.5 million in regulatory credits and an increase of $5.6 million of regulatory debits.

Conservation amortizationdecreased$1.8 million, or 1.7%, for the year ended December 31, 2014 as compared to the same period in 2013.  The decrease was primarily due to a reduction of $8.1 million in gas conservation amortization offset by an increase of $6.3 million in electric conservation amortization for the year ended December 31, 2014.

Taxes other than income taxesincreased$7.7 million, or 2.5%, for the year ended December 31, 2014 as compared to the same period in 2013.  The increase was primarily due to an increase in property taxes of $15.4 million due to an increase in the property tax tracker tariff rate. The increase was partially offset by a decrease of $8.8 million in state excise and municipal taxes for electric utilities due to lower revenues for the year ended December 31, 2014.

Other Income, Interest Expense and Income Tax Expense

Other incomedecreased$14.7 million, or 37.9%, for the year ended December 31, 2014 as compared to the same period in 2013.  The decrease for the year ended December 31, 2014, was primarily due to decreases of $11.0 million in interest and dividend income, primarily related to regulatory interest income, and $8.9 million of AFUDC equity income, which was partially offset by PSE's share of the JPUD gain in the amount of $7.5 million.

Interest expenseincreased$9.2 million, or 3.7%, for the year ended December 31, 2014 as compared to the same period in 2013.  The increase was primarily due to an increase of $8.2 million in regulatory liability interest expense and a reduction of $5.6 million related to the debt component of AFUDC from lower average construction work in process. This was partially offset by a $2.2 million decrease in interest on long term debt.

Income tax expensedecreased$71.5 million, or 44.5%, for the year ended December 31, 2014 as compared to the same period in 2013.  The decrease was primarily driven by a lower pre-tax income, and to a lesser extent, by increases in PTC and treasury grant amortization. The Company calculates its deferred tax assets and liabilities under ASC 740, "Income Taxes" (ASC 740). The utilization of NOL and PTC requires sufficient taxable income in future years. See Note 13, Income Taxes, for further details.

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2013 compared to 2012

Other Operating Expenses

Net unrealized gain on derivative instruments decreased $20.2 million, or 17.0%, for the year ended December 31, 2013 as compared to the same period in 2012.  The decrease was due to a decline in the settlement of contracts with unrealized losses from previous periods totaling $128.1 million, partially offset by an increase in gains due to changes in price totaling $107.9 million. Average 3-year forward prices of wholesale electricity and natural gas increased by 9.4% and 1.1%, respectively, for the year ended December 31, 2013.

Utility operations and maintenance expense increased $17.2 million, or 3.3%, for the year ended December 31, 2013 as compared to the same period in 2012.  The increase was primarily driven by increases of $7.3 million in administration and general expenses, $4.3 million in electric transmission and distribution expenses, and $4.1 million in low income assistance program expenses for year ended December 31, 2013.

Depreciation expense increased $26.4 million, or 7.8%, for the year ended December 31, 2013 as compared to the same period in 2012. The increase was primarily due to additional capital expenditures placed into service, net of retirements, such as the Lower Snake River (LSR) wind generation facility which began commercial operations on February 29, 2012, Snoqualmie Falls Plant and the Baker hydroelectric generating facility additions which went into service in 2013.

Amortization expense decreased $31.2 million, or 55.9%, for the year ended December 31, 2013 as compared to the same period in 2012. The decrease was primarily due to an increase in regulatory credit related to amortization of Treasury Grants of $39.8 million. Partially offsetting the decrease was an $8.2 million increase in computer software system amortization for the year ended December 31, 2013 related to a new Customer Information System.

Conservation amortization decreased $8.3 million, or 7.3%, for the year ended December 31, 2013 as compared to the same period in 2012.  The decrease was primarily due to a reduction of $11.1 million in gas conservation amortization for the year ended December 31, 2013. During the second quarter of 2012, an approved accounting petition authorized PSE to recover the costs associated with the Company's 2012 gas conservation programs via transfers from amounts deferred for the over-recovery commodity costs in the Company's PGA commodity account. Conservation amortization is a pass-through tariff item with no impact on earnings. The decrease was offset by an increase of $2.8 million in electric conservation amortization for the year ended December 31, 2013.

Taxes other than income taxes decreased $16.1 million, or 5.1%, for the year ended December 31, 2013 as compared to the same period in 2012.  The decrease was primarily due to a reduction of $22.1 million in property taxes associated with the tracker mechanism approved in June 2013, and $4.7 million related to Montana property tax refund for the year ended December 31, 2013 as compared to the same period in 2012.

Other Income, Interest Expense and Income Tax Expense

Other income decreased $10.4 million, or 21.1%, for the year ended December 31, 2013 as compared to the same period in 2012.  The decrease for the year ended December 31, 2013, was primarily due to decreases of $9.5 million in AFUDC equity income and $1.1 million in interest and dividend income.

Interest expense increased $25.3 million, or 11.3%, for the year ended December 31, 2013 as compared to the same period in 2012.  The increase was primarily due to an increase of $19.6 million in interest expense associated with LSR Treasury Grant regulatory liability and a decrease of $11.0 million related to the debt component of AFUDC primarily due to the decrease in average construction work in process. The increase was partially offset by a decrease of $3.5 million in debt issuance cost amortization for the increase primarily because PSE adjusted its revolving credit facilities in February 2013.

Income tax expense increased $11.6 million, or 7.8%, for the year ended December 31, 2013 as compared to the same period in 2012.  The increase was primarily driven by higher pre-tax income and lower AFUDC. The Company calculates its deferred tax assets and liabilities under ASC 740, "Income Taxes" (ASC 740). The utilization of NOL and PTC requires sufficient taxable income in future years. See Note 13, Income Taxes, for further details.

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Puget Energy

All the operations of Puget Energy are conducted through its subsidiary PSE.  Puget Energy’s net income for the years ended December 31, 2014, 2013 and 2012 was as follows:

Benefit/(Expense)	Year Ended December 31,						Percent Change		Year Ended December 31,			Percent Change
(Dollars in Thousands)	2014			2013					2012
PSE net income	$	236,614		$	356,129		(33.6	)%	$	356,170		*
Other operating revenue	(2,952		)	(38		)	*		(1,103		)	96.6	%
Net unrealized gain on derivative instruments	1,491			3,865			(61.4	)%	14,486			(73.3	)%
Non-utility expense and other	10,620			15,759			(32.6	)%	9,165			71.9	%
Other income	3			1			*		12			(91.7	)%
Unhedged interest rate swap expense	(3,915		)	2,420			*		(4,288		)	*
Interest expense 1	(102,382		)	(130,887		)	21.8	%	(145,204		)	9.9	%
Income tax benefit (expense)	32,356			38,479			(15.9	)%	44,583			(13.7	)%
Puget Energy net income	$	171,835		$	285,728		(39.9	)%	$	273,821		4.3	%

_____________

¹  Puget Energy’s interest expense includes elimination adjustments of intercompany interest on short-term debt.

^*  Percent change not applicable or meaningful.

2014 compared to 2013

Summary Results of Operations

Puget Energy’s net income for the year ended December 31, 2014 was $171.8 million with operating revenue of $3,113.2 million as compared to net income of $285.7 million with operating revenue of $3,187.3 million for 2013.  The following are significant factors that impacted Puget Energy’s net income which are not included in PSE’s discussion:

Non-utility expense and other decreased$5.1 million for the year ended December 31, 2014 as compared to the same period in 2013, due primarily to lower pension expense related to the qualified pension plan which resulted in a gain in 2014.

Unhedged interest rate swap decreased$6.3 million to an expense of $3.9 million for the year ended December 31, 2014 from income of $2.4 million in 2013, primarily due to market value increases of $4.7 million.

Interest expensedecreased$28.5 million for the year ended December 31, 2014 as compared to the same period in 2013. The decrease was primarily due to net write off of fair value amortization and debt cost of $18.0 million in 2013, an increase of $4.9 million in mark-to-market gains on hedged interest rate swap contracts, a decrease of $3.8 million in interest expense related to Puget Energy's revolving senior secured credit facility and the fact that the commitment fees and spreads were reduced due to a rating upgrade in 2014.

Income tax benefit decreased $6.1 million for the year ended December 31, 2014, as compared to the same period in 2013, due primarily to a lower pre-tax loss.

2013 compared to 2012

Summary Results of Operations

Puget Energy’s net income for 2013 was $285.7 million with operating revenue of $3,187.3 million as compared to net income of $273.8 million with operating revenue of $3,215.2 million for 2012.  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 $10.6 million for the year ended December 31, 2013 as compared to the same period in 2012, due to the effects of purchase accounting on derivative contracts in other comprehensive income of $8.4 million and the fair value amortization of Normal Purchase Normal Sale (NPNS) derivative contracts of $2.2 million.

Income related to non-utility expense and other increased $6.6 million for the year ended December 31, 2013 as compared to the same period in 2012, due primarily to higher pension expense related to the qualified pension plan.

Income related to unhedged interest rate swap increased $6.7 million to an income of $2.4 million for the year ended December 31, 2013 from an expense of $4.3 million, as compared to the same period in 2012. Due to swap balance reductions in February and May, 2012, the interest rate swap expense decreased by $19.0 million for the year ended December 31, 2013 as compared to the same period in 2012. Additionally, mark-to-market gains on non-hedging interest rate derivative decreased by $12.3 million.

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Interest expense decreased $14.3 million for the year ended December 31, 2013 as compared to the same period in 2012. The decrease was primarily due to a decrease of $20.8 million in interest expense related to hedged interest rate swap contracts, a write-off of the unamortized issuance costs of $13.2 million for the three months ended March 31, 2012, related to the retirement of a five-year term loan, a decrease of $5.8 million in interest expense related to Puget Energy's revolving senior secured credit facility as its balance was reduced by $135.0 million in 2013, and an increase of $3.0 million in mark-to-market gains on hedged interest rate swap contracts. The decrease was partially offset by a write off of the unamortized fair value adjustment and debt issuance cost of $18.0 million related to PSE's Pollution Control Bonds and an increase of $11.5 million in interest expense related to the senior secured notes of $450.0 million issued on June 15, 2012.

Income tax benefit decreased $6.1 million for the year ended December 31, 2013, as compared to the same period in 2012, due primarily to a lower pre-tax loss.

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, 2014:

	Payments Due Per Period
Contractual Obligations (Dollars in Thousands)	Total			2015			2016- 2017		2018- 2019		Thereafter
Energy purchase obligations 1	$	6,836,102		$	856,932		$	1,602,473	$	1,425,628	$	2,951,069
Long-term debt including interest 2	8,450,392			384,693			649,395		577,882		6,838,422
Short-term debt including interest 3,4	113,950			113,950			—		—		—
Service contract obligations 5	219,495			58,381			50,651		35,034		75,429
Non-cancelable operating leases 6	217,704			17,677			43,633		35,603		120,791
PSE capital leases 6	10,338			8,160			2,178		—		—
Pension and other benefits funding and payments 7	72,040			24,154			7,855		14,423		25,608
Total PSE contractual cash obligations	$	15,920,021		$	1,463,947		$	2,356,185	$	2,088,570	$	10,011,319
Long-term debt, including interest 8	2,272,176			88,303			472,659		169,125		1,542,089
Less: Inter-company short-term debt and interest elimination 3	(28,950		)	(28,950		)	—		—		—
Total Puget Energy contractual cash obligations	$	18,163,247		$	1,523,300		$	2,828,844	$	2,257,695	$	11,553,408

_____________

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 6 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  As of December 31, 2014, 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 $29.0 million was drawn.

⁴  As of December 31, 2014, PSE had credit facilities totaling $1.0 billion under which $25.0 million had been drawn.  These facilities consisted of a $650.0 million liquidity facility to fund operating expenses and serve as a backstop to the Company's commercial paper program, and a $350.0 million hedging facility to support electric and natural gas hedging.  The $650.0 million liquidity facility includes a swingline feature allowing same day availability on borrowings up to $75.0 million. The credit facilities also have an accordion feature that, upon the banks' approval, would increase the total size of these facilities to $1.450 billion. As of December 31, 2014, no loans or letters of credit were outstanding under the PSE energy hedging facility, and $25.0 million was outstanding under the PSE liquidity facility and no amount was outstanding under the commercial paper program. Outside of the credit agreements, PSE had a $4.2 million letter of credit in support of a long-term transmission contract and a $1.0 million letter of credit in support of natural gas purchases in Canada. The credit agreements are syndicated among numerous lenders. All other terms and conditions of that facility remain unchanged from when it was committed in 2013.

⁵  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.

⁶  For additional information, see Note 8 to the consolidated financial statements included in Item 8 of this report.

⁷  Pension and other benefit expected contributions represent PSE’s estimated cash contributions to the pension plan through 2024.

⁸  As of December 31, 2014, Puget Energy had a revolving credit facility totaling $800.0 million, which matures in April 2018. The revolving credit facility is syndicated among numerous lenders. The revolving credit facility also has an accordion feature that, upon the banks' approval, would increase the size of the facility to $1.3 billion.

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The following are PSE’s and Puget Energy’s aggregate availability under commercial commitments as of December 31, 2014:

	Amount of Available Commitments Expiration Per Period
Commercial Commitments (Dollars in Thousands)	Total			2015		2016- 2017		2018- 2019		Thereafter
PSE working capital facility 1	$	650,000		$	—	$	—	$	650,000	$	—
PSE energy hedging facility 1	350,000			—		—		350,000		—
Inter-company short-term debt 2	1,067			—		—		—		1,067
Total PSE commercial commitments	$	1,001,067		$	—	$	—	$	1,000,000	$	1,067
Puget Energy revolving credit facility 3	800,000			—		—		800,000		—
Less: Inter-company short-term debt elimination 2	(1,067		)	—		—		—		(1,067		)
Total Puget Energy commercial commitments	$	1,800,000		$	—	$	—	$	1,800,000	$	—

_____________

¹  As of December 31, 2014, PSE had credit facilities totaling $1.0 billion which will expire in April 2019.  These facilities consisted of a $650.0 million liquidity facility to fund operating expenses and serve as a backstop to the Company's commercial paper program, and a $350.0 million hedging facility to support electric and natural gas hedging.  The $650.0 million liquidity facility includes a swingline feature allowing same day availability on borrowings up to $75.0 million. The credit facilities also have an accordion feature that, upon the banks' approval, would increase the total size of these facilities to $1.450 billion. As of December 31, 2014, no loans or letters of credit were outstanding under the PSE energy hedging facility, and no amounts were outstanding under the PSE liquidity facility and $85.0 million was outstanding under the commercial paper program. Outside of the credit agreements, PSE had a $4.2 million letter of credit in support of a long-term transmission contract and a $1.0 million letter of credit in support of natural gas purchases in Canada. The credit agreements are syndicated among numerous lenders.

²  As of December 31, 2014, PSE had a revolving credit facility with Puget Energy in the form of a promissory note to borrow up to $30.0 million of which $29.0 million was drawn.

³  As of December 31, 2014, Puget Energy had a revolving credit facility totaling $800.0 million, which expires in April 2018. The revolving credit facility is syndicated among numerous lenders. The revolving credit facility also has an accordion feature that, upon the banks' approval, would increase the size of the facility to $1.3 billion. As of December 31, 2014, no amount was outstanding under the Puget Energy credit 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 and customer growth and to support reliable energy delivery.  Construction expenditures, excluding equity AFUDC, totaled $493.1 million in 2014.  Presently planned utility construction expenditures, excluding equity AFUDC, are as follows:

Capital Expenditure Projections (Dollars in Thousands)	2015		2016		2017
Total energy delivery, technology and facilities expenditures	$	593,606	$	671,060	$	674,555

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

Capital Resources

Cash From Operations

Puget Sound Energy

Cash generated from operations for the year ended December 31, 2014 decreased by $68.1 million from $835.7 million generated during the same period in 2013. The decrease was primarily the result of a decrease in regulatory assets and liabilities of $155.8 million and a $142.8 million decrease related to other long term liabilities. Offsetting this decrease in cash flow was a $190.3 million cash inflow related to accounts receivable.

Net income decreased by $119.5 and non-cash items increased by $164.1 million, primarily related to the fair value adjustment of derivative instruments of 184.5 million.

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Puget Energy

Cash generated from operations for the year ended December 31, 2014 was $686.6 million, a decrease of $79.5 million from the $766.1 million generated during the year ended December 31, 2013.  The net decrease was negatively impacted by $68.1 million from cash provided by the operating activities of PSE, as previously discussed. The above decrease was negatively impacted by Puget Energy's $15.4 million cash outflow related to interest.

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, 2014 and 2013, PSE had $85.0 million and $162.0 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 2014 and 2013 was 4.05%, and 3.93%, respectively.  As of December 31, 2014, PSE and Puget Energy had several committed credit facilities that are described below.

Puget Sound Energy Credit Facilities

PSE has two unsecured revolving credit facilities which provide, in aggregate, $1.0 billion of short-term liquidity needs. These facilities consist of a $650.0 million revolving liquidity facility (which includes a liquidity letter of credit facility and a swingline facility) to be used for general corporate purposes, including a backstop to the Company's commercial paper program and a $350.0 million revolving energy hedging facility (which includes an energy hedging letter of credit facility). The $650.0 million liquidity facility includes a swingline feature allowing same day availability on borrowings up to $75.0 million. The credit facilities also have an accordion feature which, upon the banks' approval, would increase the total size of these facilities to $1.450 billion.

In April 2014, the Company completed a one-year extension on both of the liquidity and hedging facilities, extending the maturity from February 2018 to April 2019, and updating or clarifying the definitions of other terms and conditions of the facilities from when they were committed in 2013. The credit agreements are syndicated among numerous lenders and contain usual and customary affirmative and negative covenants that, among other things, place limitations on PSE's ability to transact with affiliates, make asset dispositions and investments or permit liens to exist. The credit agreements also contain a financial covenant of total debt to total capitalization of 65% or less. PSE certifies its compliance with such covenants to participating banks each quarter. As of December 31, 2014, PSE was in compliance with all applicable covenant ratios.

The credit agreements provide PSE with the ability to borrow at different interest rate options. 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. PSE must pay a commitment fee on the unused portion of the credit facilities. The spreads and the commitment fee depend on PSE's credit ratings. As of the date of this report, the spread to the LIBOR is 1.25% and the commitment fee is 0.175%.

As of December 31, 2014, no amounts were drawn and outstanding under PSE's $650.0 million liquidity facility. No amounts were drawn and outstanding under the $350.0 million energy hedging facility. No letters of credit were outstanding under either facility, and $85.0 million was outstanding under the commercial paper program. Outside of the credit agreements, PSE had a $4.2 million letter of credit in support of a long-term transmission contract and a $1.0 million letter of credit in support of natural gas purchases in Canada.

Demand Promissory Note

On June 1, 2006, PSE entered into a revolving credit facility with Puget Energy, in the form of a credit agreement and a Demand Promissory Note (Note) pursuant to which PSE may borrow up to $30.0 million from Puget Energy subject to approval by Puget Energy.  Under the terms of the Note, PSE pays interest on the outstanding borrowings based on the lower of the weighted-average interest rates of PSE’s outstanding commercial paper interest rate or PSE’s senior unsecured revolving credit

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facility.  Absent such borrowings, interest is charged at one-month LIBOR plus 0.25%.  At December 31, 2014, the outstanding balance of the Note was $28.9 million.  The outstanding balance and the related interest under the Note are eliminated by Puget Energy upon consolidation of PSE’s financial statements.

Puget Energy Credit Facility

At December 31, 2014, Puget Energy maintained an $800.0 million revolving senior secured credit facility. In April 2014, the Company completed an amendment to the senior secured credit facility, extending the maturity from February 2017 to April 2018, updating the fee structure, eliminating a financial covenant and updating or clarifying the definitions of other terms and conditions of the facility. The Puget Energy revolving senior secured credit facility also has an accordion feature which, upon the banks' approval, would increase the size of the facility to $1.3 billion.

The revolving senior secured credit facility provides Puget Energy the ability to borrow at different interest rate options and includes variable fee levels. Interest rates may be based on the bank's prime rate or LIBOR, plus a spread based on Puget Energy's credit ratings. Puget Energy must pay a commitment fee on the unused portion of the facility. As of December 31, 2014, there was no amount drawn and outstanding under the facility. As a result of Puget Energy's credit rating upgrade in 2014, the spread over LIBOR was 1.75% and the commitment fee was 0.275% as of the date of this report. Puget Energy entered into interest rate swap contracts to manage the interest rate risk associated with the credit facility or similar variable rate debt (see Part II Item 7A "Interest Rate Risk" section).

The revolving senior secured credit facility contains usual and customary affirmative and negative covenants. The agreement also contains a Maximum Leverage Ratio financial covenant as defined in the agreement governing the senior secured credit facility. As of December 31, 2014, Puget Energy was in compliance with all applicable covenants.

Term Loans

In June 2014, Puget Energy entered into three bilateral term loans, with two and three year maturities, which in total, equal $299.0 million. The proceeds of the term loans were used to pay off the outstanding Puget Energy revolving credit facility balance, which subsequently allows the Company to carry the debt with lower interest expense. All other terms, conditions and covenants are consistent with each other and the credit facility agreements, with the exception of maturity and price.

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, 2014, approximately $438.4 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 3 to one.  The common equity ratio, calculated on a regulatory basis, was 47.7% at December 31, 2014 and the EBITDA to interest expense was 4.3 to one for the 12 months then ended.

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 (as defined in the facilities), or if the payment of dividends would result in an Event of Default, 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 facility.  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 2 to one.  At December 31, 2014, the EBITDA to interest expense was 3.1 to one for the 12 months then ended.

At December 31, 2014, 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 financings for PSE may be limited by provisions in PSE's electric and natural gas mortgage indentures.  

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PSE’s ability to issue additional secured debt may also be limited by certain restrictions contained in its electric and natural gas mortgage indentures.  Under the most restrictive tests, at December 31, 2014, PSE could issue:

• Approximately $2.10 billion of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately $3.5 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, 2014; and

• Approximately $367.0 million of additional first mortgage bonds under PSE’s natural gas mortgage indenture based on approximately $611.7 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, 2014.

At December 31, 2014, PSE had approximately $6.9 billion in electric and natural gas rate base to support the interest coverage ratio limitation test for net earnings available for interest.

Upon approval of the merger in 2009, the Company was required to refinance its debt in place at the time of the merger. The Company has met this refinancing requirement as of December 31, 2014.

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, up to $800 million aggregate principal amount of senior notes secured by pledged 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.    

Other

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 includes estimated unbilled revenue.  PSE's estimate of unbilled revenue is based on a calculation using meter readings from its automated meter reading (AMR) system. The estimate calculates unbilled usage at the end of each month as the difference between the customer meter readings on the last day of the month and the last customer meter readings billed. The unbilled usage is then priced at published rates for each schedule to estimate the unbilled revenues by customer.

Beginning July 1, 2013, PSE's electric and gas operations contain a revenue decoupling mechanism under which PSE's actual energy delivery revenues related to electric transmission and distribution, gas operations and general administrative costs are compared with authorized revenues allowed under the mechanism. Any differences are deferred to a regulatory asset for under recovery or regulatory liability for over recovery. Revenues associated with power costs under the PCA mechanism and PGA rates are excluded from the decoupling mechanism.

As defined by ASC 980, “Regulated Operations” (ASC 980), the decoupling mechanism is an alternative revenue program that allows billings to be adjusted for the effects of weather abnormalities, conservation efforts or other various external factors. PSE adjusts these billings in the future in response to these effects to collect additional revenues provided under the decoupling mechanism.  Once billing of additional revenues under the decoupling mechanism is permitted, the additional revenue can be recognized when the following criteria specified by ASC 980 are met: (i) the program is established by an order from the WUTC that allows for automatic adjustment of future rates, (ii) the amount of additional revenues for the period is objectively determinable and is probable of recovery and (iii) the additional revenues will be collected within 24 months following the end of the annual period in which they are recognized. PSE meets the criteria to recognize revenue under the decoupling mechanism.

Regulatory Accounting.  As a regulated entity of the Washington Commission and the FERC, PSE prepares its financial statements in accordance with the provisions of ASC 980 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, 2014 in the amount of $987.4 million and $635.4 million, respectively, and regulatory assets and liabilities at December 31, 2013 of $895.7 million and $697.5 million, respectively.  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

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determines that it no longer meets the criteria for continued application of ASC 980, PSE 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 Electric Regulation and Rates within Item 1. Business – Regulation and Rates of this report.  The increases and decreases in the cost of natural gas supply are reflected in customers' bills through the PGA mechanism.  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.  In 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, 2014.  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 $4.4 billion at the October 1, 2014 measurement date for the annual test of goodwill impairment.  The carrying value of Puget Energy’s equity was approximately $3.6 billion with the excess of the fair value over the carrying value representing 22.0% or $801.0 million.

The income approach and the market approach valuations resulted in Puget Energy equity values of $4.4 billion and $4.5 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 2.9% and 7.0%, respectively.

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

Equity Value Sensitivity Table
(Dollars in Billions)
Weighted-Average Cost of Capital		Long-Term Growth Rate
		2.5		%	2.6		%	2.7		%	2.8		%	2.9		%	3.0		%
7.1	%	$	3.3		$	3.5		$	3.7		$	3.9		$	4.1		$	4.4
7.0		3.5			3.7			3.9			4.2			4.4			4.7
6.9		3.8			4.0			4.2			4.5			4.7			5.0

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 unless the contracts qualify for an exception.  The Company enters into derivative contracts to manage its energy resource portfolio and interest rate exposure including forward physical and financial contracts and swaps.  Some of PSE’s physical electric supply 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

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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. Natural gas derivative contracts qualify for deferral under ASC 980 due to the PGA mechanism.

On 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 their 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 affects 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, 2014, Puget Energy had interest rate swap contracts outstanding related to its long-term debt.  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), 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 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.

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 $13.8 million, $22.4 million and $14.8 million for the years ended December 31, 2014, 2013 and 2012, respectively.  Of these amounts, approximately 61.5%, 60.8% and 57.2% were included in utility operations and maintenance expense in 2014, 2013 and 2012, respectively, and the remaining amounts were capitalized.  For the years ended December 31, 2014 and 2013, Puget Energy recognized incremental qualified pension income of $12.8 million and $16.5 million, respectively.  In 2015, it is expected that PSE and Puget Energy will recognize pension expense of $23.3 million and incremental qualified pension income of $16.6 million, respectively.

PSE has a Supplemental Executive Retirement Plan (SERP).  PSE recognized pension and other postretirement benefit expenses of $4.9 million, $5.7 million and $5.0 million for the years ended December 31, 2014, 2013 and 2012, respectively.  For the years ended December 31, 2014 and 2013, Puget Energy recognized incremental income of $0.6 million and $0.7 million, respectively.  In 2015, it is expected that PSE and Puget Energy will recognize pension expense of $5.6 million and incremental pension income of $0.5 million, respectively.

PSE has other limited postretirement benefit plans.  PSE recognized income of $0.4 million and expense of $0.1 million and $0.1 million for the years ended December 31, 2014, 2013 and 2012, respectively.  For the years ended December 31, 2014 and 2013, Puget Energy recognized incremental expense of $0.3 million and $0.3 million, respectively.  In 2015, it is expected that PSE and Puget Energy will recognize income of $0.1 million and incremental expense of $0.3 million, respectively.

The Company’s pension and other postretirement benefits income or expense 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

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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.  As required by merger accounting rules, market-related value was reset to market value effective with the merger.  During 2014, the Company made a cash contribution of $18.0 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.  At December 31, 2014 and 2013, the Company’s qualified pension plan was $64.0 million underfunded and $42.4 million over-funded as measured under GAAP, or 90.7% and 107.4% funded, respectively. As of January 1, 2015, the plan's estimated funded ratio, as calculated under guidelines from The Pension Protection Act of 2006 and considering temporary interest rate relief measures approved by Congress, was more than 100%. 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, 2015 are expected to be at least $18.0 million, $4.4 million and $0.5 million, respectively.

The discount rate used in accounting for pension and other benefit obligations decreased from 5.10% in 2013 to 4.25% in 2014. The discount rate used in accounting for pension and other benefit expense increased from 4.15% in 2013 to 5.10% in 2014. The rate of return on plan assets for qualified pension benefits in 2014 remained unchanged at 2013 level, or 7.75%. The rate of return on plan assets for other benefits increased from 6.90% in 2013 to 7.00% in 2014. 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	$	(37,910	)	$	(2,392	)	$	(743	)
Decrease in discount rate	50 basis points	42,110			2,572			810

Puget Energy	Change in Assumption	Impact on 2014 Pension Expense Increase /(Decrease)
(Dollars in Thousands)		Pension Benefits			SERP			Other Benefits
Increase in discount rate	50 basis points	$	(3,054	)	$	(169	)	$	(63	)
Decrease in discount rate	50 basis points	3,380			175			56
Increase in return on plan assets	50 basis points	(2,945		)	*			(39		)
Decrease in return on plan assets	50 basis points	2,944			*			39

Puget Sound Energy	Change in Assumption	Impact on 2014 Pension Expense Increase /(Decrease)
(Dollars in Thousands)		Pension Benefits			SERP			Other Benefits
Increase in discount rate	50 basis points	$	(3,054	)	$	(169	)	$	(67	)
Decrease in discount rate	50 basis points	3,380			175			72
Increase in return on plan assets	50 basis points	(2,972		)	*			(39		)
Decrease in return on plan assets	50 basis points	2,972			*			39

_________________

^*  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.

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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's objective is to minimize commodity price exposure and risks associated with volumetric variability in the natural gas and electric portfolios and related effects. It is not engaged in the business of assuming risk for the purpose of speculative trading.  PSE 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 PSE’s natural gas and power portfolios will perform under various weather, hydroelectric and unit performance conditions.

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. 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 and related hedging strategies are focused on reducing costs and risks where feasible, thus reducing volatility in costs 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 forward physical electric and natural gas purchase and sale agreements, fixed-for-floating swap contracts, and commodity call/put options. The forward physical electric contracts are both fixed and variable (at index), while the physical natural gas contracts are variable. To fix the price of wholesale electricity and natural gas, PSE may enter into fixed-for-floating swap (financial) contracts. PSE also utilizes natural gas call and put options as an additional hedging instrument to increase the hedging portfolio's flexibility to react to commodity price fluctuations. As of December 31, 2014, approximately 91% of these contracts, including NPNS transactions, are entered into with investment grade counterparties which, in the majority of cases, do not require collateral calls on the contracts.

The following table presents the fair value of the Company’s energy derivatives instruments, recorded on the balance sheets:

Puget Energy and Puget Sound Energy	December 31, 2014				December 31, 2013
(Dollars in Thousands)	Assets		Liabilities		Assets		Liabilities
Electric portfolio:
Current	$	3,217	$	69,771	$	14,565	$	17,731
Long-term	1,605		37,457		3,914		19,581
Total electric derivatives	$	4,822	$	107,228	$	18,479	$	37,312
Natural Gas portfolio:
Current	$	17,961	$	66,202	$	4,302	$	23,734
Long-term	1,565		22,605		3,819		11,942
Total natural gas derivatives	$	19,526	$	88,807	$	8,121	$	35,676
Total energy derivatives	$	24,348	$	196,035	$	26,600	$	72,988

At December 31, 2014, the Company had total assets of $24.3 million and total liabilities of $196.0 million related to derivative contracts used to hedge the supply and cost of electricity and natural gas to serve PSE customers. As the gains and losses in the electric portfolio are realized, they will be recorded as either purchased power costs or electric generation fuel costs under the PCA mechanism. Any fair value adjustments relating to the natural gas business have been deferred in accordance with ASC 980, due to the PGA mechanism, which passes the cost of natural gas supply to customers. 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 $25.7 million.

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The change in fair value of the Company’s outstanding energy derivative instruments from December 31, 2013 through December 31, 2014 is summarized in the table below:

Puget Energy and Puget Sound Energy Energy Derivative Contracts Gain (Loss)
(Dollars in Thousands )
Fair value of contracts outstanding at December 31, 2013	$	(46,388	)
Contracts realized or otherwise settled during 2014	(6,713		)
Change in fair value of derivatives	(118,586		)
Fair value of contracts outstanding at December 31, 2014	$	(171,687	)

The fair value of the Company’s outstanding derivative instruments at December 31, 2014, based on pricing source and the period during which the instrument will mature, is summarized below:

Puget Energy and Puget Sound Energy Source of Fair Value	Fair Value of Contracts by Settlement Year
(Dollars in Thousands)	2015			2016-2017			2018-2019			Thereafter		Total
Prices provided by external sources 1	$	(113,636	)	$	(43,703	)	$	(248	)	$	—	$	(157,587	)
Prices based on internal models and valuation methods	(1,159		)	(11,210		)	(1,745		)	14		(14,100		)
Total fair value	$	(114,795	)	$	(54,913	)	$	(1,993	)	$	14	$	(171,687	)

______________

¹  Prices provided by external pricing service, which utilizes broker quotes and pricing models.

For further details regarding both the fair value of derivative instruments and the impacts such instruments have on current period earnings, see Notes 9 and 10 to the consolidated financial statements.

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.

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: WSPP, Inc. (WSPP) agreements which standardize physical power contracts in the electric industry; International Swaps and Derivatives Association (ISDA) agreements which standardize financial gas and electric contracts; and North American Energy Standards Board (NAESB) agreements which standardize physical gas contracts. PSE believes that entering into such agreements reduces the credit risk exposure because such agreements provide for the netting and offsetting of monthly payments as well as right of set-off in the event of counterparty default. 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.

Where deemed appropriate, and when allowed under the terms of the agreements, PSE may request collateral or other security from its counterparties to mitigate the potential credit default losses.  Criteria employed in this decision include, among other things, the perceived creditworthiness of the counterparty and the expected credit exposure.  As of December 31, 2014, PSE held approximately $1.0 billion in standby letters of credit or limited parental guarantees and had 11 counterparties with unlimited parental guarantees, in support of various electric and natural gas transactions. 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 may impact PSE's decisions on derivative accounting treatment.

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 determined by weighting the fair value and contract tenors for all deals for each counterparty and arriving at an average value.  The default factor

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used is dependent upon whether the counterparty is in a net asset or a net liability position after applying the master agreement levels.

The Company applies the counterparty’s default factor to compute credit reserves for counterparties that are in a net asset position.  The Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate. The fair value of derivatives includes the impact of credit and non-performance reserves. As of December 31, 2014, the Company was in a net liability position with the majority of its counterparties, therefore the default factors of counterparties did not have a significant impact on reserves for the year.  As of December 31, 2014, PSE has posted a $1.0 million letter of credit as a condition of transacting on a physical energy exchange and clearinghouse in Canada. 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, variable-rate 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, borrowings under its commercial paper program, and its 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 following table presents the carrying value and fair value of Puget Energy and Puget Sound Energy's debt instruments:

Financial Debt Instruments	December 31, 2014				December 31, 2013
(Dollars in Thousands)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Puget Energy	$	5,328,608	$	6,743,789	$	5,394,476	$	6,324,680
Puget Sound Energy	$	3,877,192	$	4,827,641	$	3,954,856	$	4,499,419

For further details regarding Puget Energy and Puget Sound Energy debt instruments, see Notes 6 and 10 under Item 8.

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, 2014 was a net loss of $6.0 million after tax and accumulated amortization.  This compares to an after-tax loss of $6.3 million in OCI as of December 31, 2013.  All financial hedge contracts of this type are reviewed by an officer, presented to the Board of Directors, or a committee of the Board, as applicable and are approved prior to execution.  PSE had no treasury locks or forward starting swap contracts outstanding at December 31, 2014.

The Company may also enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts.  As of December 31, 2014, Puget Energy had two interest rate swap contracts outstanding and PSE did not have any outstanding interest rate swap instruments. At December 31, 2014, the fair value of the interest rate swaps was a $9.1 million pre-tax loss. The fair value considers the risk of Puget Energy’s non-performance by using its incremental borrowing rate on unsecured debt over the risk-free rate in the valuation estimate. Currently, all changes in market value are recorded in earnings.

A hypothetical 10% increase or decrease in interest rates would change the fair value of Puget Energy's interest rate swaps by $0.8 million.

The following table presents the fair value of Puget Energy’s interest rate swaps:

Puget Energy	December 31, 2014				December 31, 2013
(Dollars in Thousands)	Assets		Liabilities		Assets		Liabilities
Interest rate swaps:
Current	$	—	$	6,222	$	—	$	6,584
Long-term	—		2,851		—		6,639
Total interest rate swaps	$	—	$	9,073	$	—	$	13,223

57

The change in fair value of Puget Energy’s outstanding interest rate swaps from December 31, 2013 through December 31, 2014 is summarized in the table below:

Puget Energy Interest Rate Swap Contracts Gain (Loss)
(Dollars in Thousands )
Fair value of contracts outstanding at December 31, 2013	$	(13,223	)
Contracts realized or otherwise settled during 2014	2,396
Change in fair value of derivatives	1,754
Fair value of contracts outstanding at December 31, 2014	$	(9,073	)

The fair value of Puget Energy’s outstanding interest rate swaps at December 31, 2014, based on pricing 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)	2015			2016			2017			Total
Prices provided by external sources 1	$	(6,222	)	$	(2,798	)	$	(53	)	$	(9,073	)

______________

¹  Prices provided by external pricing service, which may utilize broker quotes and internal pricing models.  Significant pricing inputs are based on observable market data.

58

ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

	Page
REPORTS:
Report of Management and Statement of Responsibility	60
Report of Independent Registered Public Accounting Firm – Puget Energy	61
Report of Independent Registered Public Accounting Firm – Puget Sound Energy	62
CONSOLIDATED FINANCIAL STATEMENTS:
PUGET ENERGY:
Consolidated Statements of Income - Years Ended December 31, 2014, 2013 and 2012	63
Consolidated Statements of Comprehensive Income - Years Ended December 31, 2014, 2013 and 2012	64
Consolidated Balance Sheets - December 31, 2014 and 2013	65
Consolidated Statements of Common Shareholder’s Equity - Years Ended December 31, 2014, 2013 and 2012	67
Consolidated Statements of Cash Flows - Years Ended December 31, 2014, 2013 and 2012	68
PUGET SOUND ENERGY:
Consolidated Statements of Income - Years Ended December 31, 2014, 2013 and 2012	69
Consolidated Statements of Comprehensive Income - Years Ended December 31, 2014, 2013 and 2012	70
Consolidated Balance Sheets - December 31, 2014 and 2013	71
Consolidated Statements of Common Shareholder’s Equity - Years Ended December 31, 2014, 2013 and 2012	73
Consolidated Statements of Cash Flows - Years Ended December 31, 2014, 2013 and 2012	74

NOTES  to the Consolidated Financial Statements of Puget Energy and Puget Sound Energy:
Note 1.	Summary of Significant Accounting Policies	75
Note 2.	New Accounting Pronouncements	79
Note 3.	Regulation and Rates	80
Note 4.	Dividend Payment Restrictions	87
Note 5.	Utility Plant	87
Note 6.	Long-Term Debt	89
Note 7.	Liquidity Facilities and Other Financing Arrangements	91
Note 8.	Leases	92
Note 9.	Accounting for Derivative Instruments and Hedging Activities	92
Note 10.	Fair Value Measurements	97
Note 11.	Employee Investment Plans	101
Note 12.	Retirement Benefits	102
Note 13.	Income Taxes	109
Note 14.	Litigation	112
Note 15.	Commitments and Contingencies	112
Note 16.	Related Party Transactions	114
Note 17.	Segment Information	114
Note 18.	Accumulated Other Comprehensive Income (Loss)	115

SUPPLEMENTAL QUARTERLY FINANCIAL DATA	118
SCHEDULE:
I.   Condensed Financial Information of Puget Energy	119
II.  Valuation and Qualifying Accounts and Reserves	123
Years Ended December 31, 2014, 2013 and 2012

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.

59

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 designed to ensure the integrity and independence of our financial reporting processes 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/ Daniel A. Doyle	/s/ Michael J. Stranik
Kimberly J. Harris	Daniel A. Doyle	Michael J. Stranik
President and Chief Executive Officer	Senior Vice President and Chief Financial Officer	Controller and Principal Accounting Officer

60

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Puget Energy, Inc.

In our opinion, theconsolidated financial statements listed in the accompanying indexpresent fairly, in all material respects, the financial position of Puget Energy, Inc.and its subsidiariesatDecember 31, 2014and December 31, 2013, and the results of their operations and their cash flows for each of the three years in the period endedDecember 31, 2014in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the accompanying indexpresent fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidatedfinancial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (2013)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 inManagement'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

Seattle, Washington

February 27, 2015

61

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Puget Sound Energy, Inc.

In our opinion, theconsolidated financial statements listed in the accompanying indexpresent fairly, in all material respects, the financial position of Puget Sound Energy, Inc.and its subsidiaryatDecember 31, 2014and December 31, 2013, and the results of their operations and their cash flows for each of the three years in the period endedDecember 31, 2014in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying indexpresent fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidatedfinancial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (2013)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 inManagement'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

Seattle, Washington

February 27, 2015

62

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands)

	Year Ended December 31,
	2014			2013			2012
Operating revenue:
Electric	$	2,083,797		$	2,156,920		$	2,128,230
Gas	1,012,859			1,028,357			1,086,095
Other	16,515			2,020			831
Total operating revenue	3,113,171			3,187,297			3,215,156
Operating expenses:
Energy costs:
Purchased electricity	514,087			541,905			622,288
Electric generation fuel	263,493			261,332			204,956
Residential exchange	(129,036		)	(81,053		)	(73,555		)
Purchased gas	458,691			488,201			538,612
Unrealized (gain) loss on derivative instruments, net	84,146			(102,744		)	(133,606		)
Utility operations and maintenance	550,146			529,939			512,765
Non-utility expense and other	13,109			(3,555		)	814
Depreciation	370,962			364,324			337,952
Amortization	(5,356		)	24,631			55,819
Conservation amortization	104,096			105,897			114,177
Taxes other than income taxes	310,982			303,260			319,399
Total operating expenses	2,535,320			2,432,137			2,499,621
Operating income (loss)	577,851			755,160			715,535
Other income (deductions):
Other income	24,038			38,693			49,069
Other expense	(7,457		)	(7,134		)	(11,770		)
Non-hedged interest rate swap expense	(3,915		)	2,420			(4,288		)
Interest charges:
AFUDC	5,611			11,261			22,216
Interest expense	(367,308		)	(392,264		)	(392,216		)
Income (loss) before income taxes	228,820			408,136			378,546
Income tax (benefit) expense	56,985			122,408			104,725
Net income (loss)	$	171,835		$	285,728		$	273,821

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

63

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands)

	Year Ended December 31,
	2014			2013		2012
Net income (loss)	$	171,835		$	285,728	$	273,821
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $(45,890), $41,773 and $(7,469), respectively	(85,224		)	77,579		(13,870		)
Reclassification of net unrealized (gain) loss on energy derivative instruments settled during the period, net of tax of $200, $20 and $200, respectively	372			37		371
Reclassification of net unrealized (gain) loss on interest rate swaps during the period, net of tax of $50, $1,577 and $6,234, respectively	94			2,928		11,577
Other comprehensive income (loss)	(84,758		)	80,544		(1,922		)
Comprehensive income (loss)	$	87,077		$	366,272	$	271,899

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

64

PUGET ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

ASSETS

	December 31,
	2014			2013
Utility plant (at original cost, including construction work in progress of $239,690 and $310,318, respectively):
Electric plant	$	7,135,206		$	7,019,853
Gas plant	2,680,067			2,528,629
Common plant	472,926			504,036
Less:  Accumulated depreciation and amortization	(1,611,220		)	(1,373,178		)
Net utility plant	8,676,979			8,679,340
Other property and investments:
Goodwill	1,656,513			1,656,513
Other property and investments	91,139			100,332
Total other property and investments	1,747,652			1,756,845
Current assets:
Cash and cash equivalents	37,527			44,302
Restricted cash	32,863			7,171
Accounts receivable, net of allowance for doubtful accounts of $7,472 and $7,385, respectively	306,923			408,512
Unbilled revenue	168,039			219,884
Purchased gas adjustment receivable	21,073			—
Materials and supplies, at average cost	83,189			88,140
Fuel and gas inventory, at average cost	69,433			66,717
Unrealized gain on derivative instruments	21,178			18,867
Taxes	301			297
Prepaid expense and other	20,905			18,787
Power contract acquisition adjustment gain	43,843			48,509
Deferred income taxes	161,445			86,004
Total current assets	966,719			1,007,190
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes	95,432			146,867
Power cost adjustment mechanism	4,623			—
Regulatory assets related to power contracts	29,816			33,753
Other regulatory assets	866,835			749,382
Unrealized gain on derivative instruments	3,170			7,733
Power contract acquisition adjustment gain	347,547			394,556
Other	96,275			130,909
Total other long-term and regulatory assets	1,443,698			1,463,200
Total assets	$	12,835,048		$	12,906,575

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

65

PUGET ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

CAPITALIZATION AND LIABILITIES

	December 31,
	2014			2013
Capitalization:
Common shareholder’s equity:
Common stock $0.01 par value, 1,000 shares authorized, 200 shares outstanding	$	—		$	—
Additional paid-in capital	3,308,957			$	3,308,957
Earnings reinvested in the business	271,414			323,007
Accumulated other comprehensive income (loss), net of tax	(37,043		)	47,715
Total common shareholder’s equity	3,543,328			3,679,679
Long-term debt:
First mortgage bonds and senior notes	3,189,412			3,351,412
Pollution control bonds	161,860			161,860
Junior subordinated notes	250,000			250,000
Long-term debt	1,699,000			1,699,000
Debt discount and other	(218,664		)	(229,796		)
Total long-term debt	5,081,608			5,232,476
Total capitalization	8,624,936			8,912,155
Current liabilities:
Accounts payable	307,578			296,681
Short-term debt	85,000			162,000
Current maturities of long-term debt	162,000			—
Purchased gas adjustment liability	—			5,938
Accrued expenses:
Taxes	107,782			109,559
Salaries and wages	40,970			38,491
Interest	78,914			79,303
Unrealized loss on derivative instruments	142,195			48,049
Power contract acquisition adjustment loss	3,593			3,937
Other	62,464			60,335
Total current liabilities	990,496			804,293
Other Long-term and regulatory liabilities:
Deferred income taxes	1,522,357			1,487,005
Unrealized loss on derivative instruments	62,913			38,162
Power Cost Adjustment Mechanism	—			5,345
Regulatory liabilities	633,471			689,060
Regulatory liabilities related to power contracts	391,389			443,065
Power contract acquisition adjustment loss	26,223			29,816
Other deferred credits	583,263			497,674
Total other long-term and regulatory liabilities	3,219,616			3,190,127
Commitments and contingencies (Note 15)
Total capitalization and liabilities	$	12,835,048		$	12,906,575

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

66

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
Balance at December 31, 2011	200	$	—	$	3,308,957	$	22,873		$	(30,907	)	$	3,300,923
Net income (loss)	—	—		—		273,821			—			273,821
Common stock dividend	—	—		—		(88,594		)	—			(88,594		)
Other comprehensive income (loss)	—	—		—		—			(1,922		)	(1,922		)
Balance at December 31, 2012	200	$	—	$	3,308,957	$	208,100		$	(32,829	)	$	3,484,228
Net income (loss)	—	—		—		285,728			—			285,728
Common stock dividend	—	—		—		(170,821		)	—			(170,821		)
Other comprehensive income (loss)	—	—		—		—			80,544			80,544
Balance at December 31, 2013	200	$	—	$	3,308,957	$	323,007		$	47,715		$	3,679,679
Net income (loss)	—	—		—		171,835			—			171,835
Common stock dividend	—	—		—		(223,428		)	—			(223,428		)
Other comprehensive income (loss)	—	—		—		—			(84,758		)	(84,758		)
Balance at December 31, 2014	200	$	—	$	3,308,957	$	271,414		$	(37,043	)	$	3,543,328

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

67

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

	Year Ended December 31,
	2014			2013			2012
Operating activities:
Net income (loss)	$	171,835		$	285,728		$	273,821
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation	370,962			364,324			337,952
Amortization	(5,356		)	24,631			55,819
Conservation amortization	104,096			105,897			114,177
Deferred income taxes and tax credits, net	56,984			122,409			100,457
Gain on land sales	(4,071		)	—			—
Net unrealized (gain) loss on derivative instruments	80,139			(106,540		)	(146,680		)
Derivative contracts classified as financing activities due to merger	16,349			34,250			92,681
AFUDC - equity	(7,002		)	(15,930		)	(25,469		)
Funding of pension liability	(18,000		)	(20,400		)	(22,800		)
Regulatory assets	(219,604		)	(122,549		)	(170,374		)
Regulatory liabilities	(8,730		)	50,025			14,054
Other long-term assets	(6,003		)	(24,877		)	(1,644		)
Other long-term liabilities	29,765			180,015			95,166
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	153,434			(103,949		)	35,537
Materials and supplies	4,951			(5,787		)	(6,284		)
Fuel and gas inventory	(2,742		)	21,633			11,527
Taxes	(4		)	4,499			6,174
Prepayments and other	(2,136		)	(5,357		)	393
Purchased gas adjustment	(27,011		)	(26,649		)	6,647
Accounts payable	9,098			4,597			(25,963		)
Taxes payable	(1,777		)	13,936			4,896
Accrued expenses and other	6,605			(13,838		)	32,598
Net cash provided by operating activities	701,782			766,068			782,685
Investing activities:
Construction expenditures - excluding equity AFUDC	(493,130		)	(567,938		)	(859,791		)
Treasury grants received	107,876			—			205,261
Proceeds from disposition of assets	20,296			108,362			—
Restricted cash	(25,692		)	(3,471		)	483
Other	(4,512		)	(17,871		)	(38,923		)
Net cash used in investing activities	(395,162		)	(480,918		)	(692,970		)
Financing activities:
Change in short-term debt, net	(77,000		)	(26,578		)	148,437
Dividends paid	(223,428		)	(170,821		)	(88,594		)
Long-term notes and bonds issued	299,000			161,860			1,314,000
Redemption of bonds and notes	(299,000		)	(309,860		)	(1,273,000		)
Derivative contracts classified as financing activities due to merger	(16,349		)	(34,250		)	(92,681		)
Issuance cost of bonds and other	3,382			3,259			430
Net cash provided by (used in) financing activities	(313,395		)	(376,390		)	8,592
Net increase (decrease) in cash and cash equivalents	(6,775		)	(91,240		)	98,307
Cash and cash equivalents at beginning of period	44,302			135,542			37,235
Cash and cash equivalents at end of period	$	37,527		$	44,302		$	135,542
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	349,402		$	334,041		$	318,305
Cash payments (refunds) for income taxes	—			(4,500		)	(1,898		)
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows	$	51,776		$	49,977		$	79,852

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

68

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands)

	Year Ended December 31,
	2014			2013			2012
Operating revenue:
Electric	$	2,083,797		$	2,156,920		$	2,128,230
Gas	1,012,859			1,028,357			1,086,095
Other	19,467			2,058			1,934
Total operating revenue	3,116,123			3,187,335			3,216,259
Operating expenses:
Energy costs:
Purchased electricity	514,087			541,905			622,288
Electric generation fuel	263,493			261,332			204,956
Residential exchange	(129,036		)	(81,053		)	(73,555		)
Purchased gas	458,691			488,201			538,612
Unrealized (gain) loss on derivative instruments, net	85,636			(98,880		)	(119,120		)
Utility operations and maintenance	550,146			529,939			512,765
Non-utility expense and other	23,729			12,205			9,977
Depreciation	370,962			364,324			337,952
Amortization	(5,356		)	24,631			55,819
Conservation amortization	104,096			105,897			114,177
Taxes other than income taxes	310,982			303,260			319,399
Total operating expenses	2,547,430			2,451,761			2,523,270
Operating income (loss)	568,693			735,574			692,989
Other income (deductions):
Other income	24,036			38,690			49,056
Other expense	(7,457		)	(7,134		)	(11,770		)
Interest charges:
AFUDC	5,611			11,261			22,216
Interest expense	(264,745		)	(261,264		)	(246,811		)
Interest expense on parent note	(182		)	(112		)	(202		)
Income (loss) before income taxes	325,956			517,015			505,478
Income tax (benefit) expense	89,342			160,886			149,308
Net income (loss)	$	236,614		$	356,129		$	356,170

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

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PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands)

	Year Ended December 31,
	2014			2013		2012
Net income (loss)	$	236,614		$	356,129	$	356,170
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $(41,395), $47,705 and $(3,911), respectively	(76,876		)	88,593		(7,294		)
Reclassification of net unrealized (gain) loss on energy derivative instruments, net of tax of $722, $1,373 and $4,500, respectively	1,341			2,549		8,358
Amortization of treasury interest rate swaps to earnings, net of tax of $171, $171 and $171, respectively	317			317		317
Other comprehensive income (loss)	(75,218		)	91,459		1,381
Comprehensive income (loss)	$	161,396		$	447,588	$	357,551

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

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PUGET SOUND ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

ASSETS

	December 31,
	2014			2013
Utility plant (at original cost, including construction work in progress of $239,690 and $310,318, respectively):
Electric plant	$	9,330,999		$	9,276,400
Gas plant	3,282,818			3,134,880
Common plant	512,842			565,072
Less: Accumulated depreciation and amortization	(4,449,680		)	(4,297,012		)
Net utility plant	8,676,979			8,679,340
Other property and investments:
Other property and investments	86,913			91,919
Total other property and investments	86,913			91,919
Current assets:
Cash and cash equivalents	37,466			44,111
Restricted cash	32,863			7,171
Accounts receivable, net of allowance for doubtful accounts of $7,472 and $7,385, respectively	307,046			408,827
Unbilled revenue	168,039			219,884
Purchased gas adjustment receivable	21,073			—
Materials and supplies, at average cost	83,189			88,140
Fuel and gas inventory, at average cost	66,656			63,914
Unrealized gain on derivative instruments	21,178			18,867
Taxes	301			297
Prepaid expenses and other	20,907			18,770
Deferred income taxes	208,447			141,058
Total current assets	967,165			1,011,039
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes	94,913			146,350
Power cost adjustment mechanism	4,623			—
Other regulatory assets	866,793			749,382
Unrealized gain on derivative instruments	3,170			7,733
Other	89,306			123,125
Total other long-term and regulatory assets	1,058,805			1,026,590
Total assets	$	10,789,862		$	10,808,888

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

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PUGET SOUND ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

CAPITALIZATION AND LIABILITIES

	December 31,
	2014			2013
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	3,246,205			3,246,205
Earnings reinvested in the business	202,622			289,432
Accumulated other comprehensive income (loss), net of tax	(170,957		)	(95,739		)
Total common shareholder’s equity	3,278,729			3,440,757
Long-term debt:
First mortgage bonds and senior notes	3,189,412			3,351,412
Pollution control bonds	161,860			161,860
Junior subordinated notes	250,000			250,000
Debt discount and other	(13		)	(14		)
Total long-term debt	3,601,259			3,763,258
Total capitalization	6,879,988			7,204,015
Current liabilities:
Accounts payable	307,572			296,675
Short-term debt	85,000			162,000
Short-term note owed to parent	28,933			29,598
Current maturities of long-term debt	162,000			—
Purchased gas adjustment liability	—			5,938
Accrued expenses:
Taxes	107,782			109,559
Salaries and wages	40,970			38,491
Interest	55,346			55,262
Unrealized loss on derivative instruments	135,973			41,465
Other	62,464			60,334
Total current liabilities	986,040			799,322
Other Long-term and regulatory liabilities:
Deferred income taxes	1,649,857			1,584,850
Unrealized loss on derivative instruments	60,063			31,523
Regulatory liabilities	630,651			686,176
Power Cost Adjustment Mechanism	—			5,345
Other deferred credits	583,263			497,657
Total other long-term and regulatory liabilities	2,923,834			2,805,551
Commitments and contingencies (Note 15)
Total capitalization and liabilities	$	10,789,862		$	10,808,888

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

72

 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, 2011	85,903,791	$	859	$	3,246,205	$	163,735		$	(188,579	)	$	3,222,220
Net income (loss)	—	—		—		356,170			—			356,170
Common stock dividend	—	—		—		(175,625		)	—			(175,625		)
Other comprehensive income (loss)	—	—		—		—			1,381			1,381
Balance at December 31, 2012	85,903,791	$	859	$	3,246,205	$	344,280		$	(187,198	)	$	3,404,146
Net income (loss)	—	—		—		356,129			—			356,129
Common stock dividend	—	—		—		(410,977		)	—			(410,977		)
Other comprehensive income (loss)	—	—		—		—			91,459			91,459
Balance at December 31, 2013	85,903,791	$	859	$	3,246,205	$	289,432		$	(95,739	)	$	3,440,757
Net income (loss)	—	—		—		236,614			—			236,614
Common stock dividend	—	—		—		(323,424		)	—			(323,424		)
Other comprehensive income (loss)	—	—		—		—			(75,218		)	(75,218		)
Balance at December 31, 2014	85,903,791	$	859	$	3,246,205	$	202,622		$	(170,957	)	$	3,278,729

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

73

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

	Year Ended December 31,
	2014			2013			2012
Operating activities:
Net income (loss)	$	236,614		$	356,129		$	356,170
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation	370,962			364,324			337,952
Amortization	(5,356		)	24,631			55,819
Conservation amortization	104,096			105,897			114,177
Deferred income taxes and tax credits, net	89,342			160,886			145,040
Gain on land sales	(4,071		)	—			—
Net unrealized (gain) loss on derivative instruments	85,636			(98,880		)	(119,120		)
AFUDC - equity	(7,002		)	(15,930		)	(25,469		)
Funding of pension liability	(18,000		)	(20,400		)	(22,800		)
Regulatory assets	(219,604		)	(122,549		)	(170,374		)
Regulatory liabilities	(8,730		)	50,025			14,054
Other long-term assets	(12,383		)	(21,932		)	932
Other long-term liabilities	32,972			160,596			79,789
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	153,626			(104,059		)	35,285
Materials and supplies	4,951			(5,787		)	(6,284		)
Fuel and gas inventory	(2,742		)	21,633			11,527
Taxes	(4		)	4,499			6,174
Prepayments and other	(2,136		)	(5,357		)	393
Purchased gas adjustment	(27,011		)	(26,649		)	6,647
Accounts payable	9,098			4,597			(25,972		)
Taxes payable	(1,777		)	13,936			4,896
Accrued expenses and other	4,246			(9,931		)	(954		)
Net cash provided by operating activities	782,727			835,679			797,882
Investing activities:
Construction expenditures - excluding equity AFUDC	(493,130		)	(567,938		)	(859,791		)
Treasury grants received	107,876			—			205,261
Proceeds from disposition of assets	20,296			108,362			—
Restricted cash	(25,692		)	(3,471		)	483
Other	(1,683		)	(16,751		)	(18,022		)
Net cash used in investing activities	(392,333		)	(479,798		)	(672,069		)
Financing activities:
Change in short-term debt and leases, net	(77,000		)	(26,578		)	148,437
Dividends paid	(323,424		)	(410,977		)	(175,625		)
Loan from (payment to) parent	(665		)	—			(400		)
Long-term notes and bonds issued	—			161,860			—
Redemption of bonds and notes	—			(174,860		)	—
Issuance cost of bonds and other	4,050			3,255			6,295
Net cash provided by (used in) financing activities	(397,039		)	(447,300		)	(21,293		)
Net increase (decrease) in cash and cash equivalents	(6,645		)	(91,419		)	104,520
Cash and cash equivalents at beginning of period	44,111			135,530			31,010
Cash and cash equivalents at end of period	$	37,466		$	44,111		$	135,530
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	253,803		$	244,887		$	216,128
Cash payments (refunds) for income taxes	—			(4,500		)	(1,898		)
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows	$	51,776		$	49,977		$	79,852

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

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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.  In 2009, Puget Holdings LLC (Puget Holdings), owned by a consortium of long-term infrastructure investors, completed its merger with Puget Energy (the merger).  As a result of the merger, all of Puget Energy’s common stock is indirectly owned by 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.  

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 subsidiary.  Puget Energy and PSE are collectively referred to herein as “the Company.”  The consolidated financial statements are presented after elimination of all significant intercompany items and transactions.  PSE’s consolidated financial statements continue to be accounted for on a historical basis and PSE’s financial statements do not include any ASC 805 purchase accounting adjustments.  The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period.  Actual results could differ from those estimates.

PSE collected Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes totaling $231.7 million, $243.9 million and $244.2 million for 2014, 2013 and 2012, respectively. The Company reports the collection of such taxes on a gross basis in operation revenue and as expense in taxes other than income taxes in the accompanying consolidated statements of income.

Beginning July 1, 2013, PSE's electric and gas operations contain a revenue decoupling mechanism under which PSE's actual energy delivery revenues related to electric transmission and distribution, gas operations and general administrative costs are compared with authorized revenues allowed under the mechanism. Any differences are deferred to a regulatory asset for under recovery or regulatory liability for over recovery. Revenues associated with power costs under the Power Cost Adjustment (PCA) mechanism and Purchased Gas Adjustment (PGA) rates are excluded from the decoupling mechanism.

Utility Plant

Puget Energy and PSE capitalize, 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 are included in maintenance expense. When the utility plant is retired and removed from service, the original cost of the property is charged to accumulated depreciation and costs associated with removal of the property, less salvage, are charged to the cost of removal regulatory liability.

Planned Major Maintenance

Planned major maintenance is an activity that typically occurs when PSE overhauls or substantially upgrades various systems and equipment on its natural gas fired combustion turbines on a scheduled basis. Costs related to planned major maintenance are deferred and amortized to the next scheduled major maintenance. This accounting method also follows the Washington Utilities and Transportation Commission (Washington Commission) regulatory treatment related to these generating facilities.

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 are expensed on a current basis.  Gains and losses on assets sold or retired are reflected in earnings.

Depreciation and Amortization

For financial statement purposes, the Company provides for depreciation and amortization on a straight-line basis.  Amortization is recorded for intangibles such as regulatory assets and liabilities, computer software and franchises.  The depreciation of vehicles and equipment is allocated to the asset and expense accounts based on usage.  The annual depreciation provision stated as a percent of a depreciable electric utility plant was 2.8%, 2.8% and 2.9% in 2014, 2013 and 2012, respectively;

75

depreciable gas utility plant was 3.4%, 3.4% and 3.4% in 2014, 2013 and 2012, respectively; and depreciable common utility plant was 8.5%, 11.4% and 11.6% in 2014, 2013 and 2012, respectively.  The decrease in depreciable common utility plant that occurred between 2014 and 2013 was primarily due to asset retirement. 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

In 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 2014 using an October 1, 2014 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, 2014.  There were no known events or circumstances from the date of the assessment through December 31, 2014 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.  The cash and cash equivalents balance at Puget Energy was $37.5 million and $44.3 million as of December 31, 2014 and 2013, respectively.  The 2014 and 2013 balance consisted of cash equivalents, which are reported at cost and approximate fair value, and were $1.8 million and $2.6 million, respectively.

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.  Puget Energy and PSE record these items 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.  Puget Energy and PSE record these items at the lower of cost or market value using the weighted-average cost method.

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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 is probable that future rates will permit recovery of such costs.  It similarly 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 due to the length of the amortization.  For further details regarding regulatory assets and liabilities, see Note 3.

Allowance for Funds Used During Construction

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

Effective Date	Washington Commission AFUDC Rates
July 1, 2013 - present	7.77	%
May 14, 2012 - June 30, 2013	7.80
April 8, 2010 - May 13, 2012	8.10

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.

Revenue Recognition

Operating utility revenue is recognized when the basis of services is rendered, which includes estimated unbilled revenue, in accordance with ASC 605, “Revenue Recognition” (ASC 605).  PSE's estimate of unbilled revenue is based on a calculation using meter readings from its automated meter reading (AMR) system. The estimate calculates unbilled usage at the end of each month as the difference between the customer meter readings on the last day of the month and the last customer meter readings billed. The unbilled usage is then priced at published rates for each schedule to estimate the unbilled revenues by customer.

The non-utility subsidiary recognizes 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 Renewable Energy Credits (RECs) are deferred as a regulatory liability.

Beginning July 1, 2013, PSE's electric and gas operations contain a revenue decoupling mechanism under which PSE's actual energy delivery revenues related to electric transmission and distribution, gas operations and general administrative costs are compared with authorized revenues allowed under the mechanism. Any differences are deferred to a regulatory asset for under recovery or regulatory liability for over recovery. Revenues associated with power costs under the PCA mechanism and PGA rates are excluded from the decoupling mechanism. The decoupling mechanism reduces earnings volatility, but does not materially affect the timing of cash flow due to the timing difference between the recognition of decoupling revenue and resulting impacts on rates.

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 along with information on future economic outlook.  The allowance account is adjusted monthly for this experience rate.   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, 2014 and 2013 was $7.5 million and $7.4 million, respectively.

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Self-Insurance

PSE is self-insured for storm damage and environmental contamination occurring on PSE-owned property.  In addition, PSE is required to meet a deductible 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 qualifying storm damage costs that exceed $8.0 million which will be requested for collection in future rates.  Additionally, costs may only be deferred if the outage meets the Institute of Electrical and Electronics Engineers (IEEE) outage criteria for system average interruption duration index.

Federal Income Taxes

For presentation in Puget Energy and PSE’s separate financial statements, 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.  Taxes payable or receivable are settled with Puget Holdings.

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 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 selling natural gas, previously purchased for power generation, 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 taxpayers that generate energy from qualifying renewable sources.  PSE records the benefit of the PTCs as a regulatory liability until such time as PSE utilizes the tax credit on its tax return. Once utilized, PSE will pass the benefit to customers.

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.  Some of PSE’s physical electric supply contracts qualify for the Normal Purchase Normal Sale (NPNS) exception to derivative accounting rules.  PSE may enter into financial fixed price 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.

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 in 2009.  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 affects 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. When these contracts are settled, the contract price becomes part of purchased electricity or electric generation fuel which becomes part of PSE’s PCA mechanism and the unrealized gain or loss is listed separately under energy costs, as it represents the non-rate treatment of energy costs.

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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, 2014, Puget Energy has interest rate swap contracts outstanding related to its long-term debt.  For additional information, see Note 9 Accounting for Derivative Instruments and Hedging Activities.

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).  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.  For additional information, see Note 10 Fair Value Measurements.

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.

Accumulated Other Comprehensive Income (Loss)

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

Puget Energy	December 31,
(Dollars in Thousands)	2014			2013
Net unrealized loss on energy derivative instruments	$	(333	)	$	(705	)
Net unrealized loss on interest rate swaps	—			(94		)
Net unrealized loss and prior service cost on pension plans	(36,710		)	48,514
Total Puget Energy, net of tax	$	(37,043	)	$	47,715

Puget Sound Energy	December 31,
(Dollars in Thousands)	2014			2013
Net unrealized loss on energy derivative instruments	$	(686	)	$	(2,027	)
Net unrealized loss on treasury interest rate swaps	(5,990		)	(6,307		)
Net unrealized loss and prior service cost on pension plans	(164,281		)	(87,405		)
Total PSE, net of tax	$	(170,957	)	$	(95,739	)

(2)  New Accounting Pronouncements

Income Statement

In May 2014, the FASB issued Accounting Standards Update (ASU) No. 2014-09, "Revenue from Contracts with Customers (Topic 606)", that outlines a single comprehensive model for use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The ASU is based on the principle that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the

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consideration to which the entity expects to be entitled in exchange for those goods or services. The ASU also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to fulfill a contract.

ASU 2014-09 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016.  Early adoption of the ASU is not permitted.  Entities have the option of using either a full retrospective or a modified retrospective approach for the adoption of the new standard.  The Company initiated a steering committee and project team to evaluate the impact of this standard, update any policies and procedures that may be affected and implement the new revenue recognition guidance. At this time, the Company cannot determine the impact this standard will have on its consolidated financial statements.

Extraordinary and Unusual Items

In January 2015, the FASB issued ASU 2015-01, "Income Statement - Extraordinary and Unusual Items (Subtopic 225-20): Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items." As part of FASB's initiative to reduce complexity in accounting standards, it issued ASU 2015-01, which eliminates from GAAP the concept of extraordinary items. Currently, Subtopic 225-20 requires an entity to separately classify, present and disclose extraordinary events and transactions. ASU 2015-01 will align GAAP income statement presentation guidance with International Accounting Standards 1, Presentation of Financial Statements, which prohibits the presentation and disclosure of extraordinary items.

ASU 2015-01 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. The Company is permitted to apply amendments prospectively or retrospectively to all prior periods presented in the financial statements. Early adoption is permitted, provided that the guidance is applied from the beginning of the fiscal year of adoption. At this time, the Company doesn't expect this standard to have a material effect on the Company's financial position or results of operations.

(3)  Regulation and Rates

Regulatory Assets and Liabilities

ASC 980 requires PSE to defer certain costs that would otherwise be charged to expense, if it is probable that future rates will permit recovery of such costs.  It similarly requires deferral of revenues or gains and losses that are expected to be returned to customers in the future.  

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

Period	Rate of Return	After-Tax Return
July 1, 2013 - present	7.77%	6.69%
May 14, 2012 - June 30, 2013	7.80	6.71
April 8, 2010 - May 13, 2012	8.10	6.90

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The net regulatory assets and liabilities at December 31, 2014 and 2013 included the following:

Puget Sound Energy	Remaining Amortization Period	December 31,
(Dollars in Thousands)		2014			2013
PGA deferral of unrealized losses on derivative instruments	(a)	$	69,280		$	27,555
Chelan PUD contract initiation	16.8 Years	119,316			126,404
Storm damage costs electric	1 to 4 years	118,824			116,328
Environmental remediation	(a)	66,018			57,342
Baker Dam licensing operating and maintenance costs	44 years	61,577			57,270
Snoqualmie licensing operating and maintenance costs	30 years	9,202			10,881
Colstrip common property	9.5 years	6,764			7,479
Deferred income taxes	(a)	94,913			146,350
Deferred Washington Commission AFUDC	35 years	53,709			55,495
Energy conservation costs	1 to 2 years	42,374			35,987
Unamortized loss on reacquired debt	1 to 21.5 years	35,667			37,832
White River relicensing and other costs	17.9 years	26,685			28,190
Mint Farm ownership and operating costs	10.3 years	20,320			22,320
Investment in Bonneville Exchange power contract	2.5 years	8,816			12,343
Ferndale	4.8 years	19,232			22,811
Lower Snake River	1.3 to 22.3 years	86,275			92,924
Snoqualmie	3.8 years	6,798			8,009
Property tax tracker	Less than 2 years	32,253			22,134
PGA receivable	1 year	21,073			—
PCA mechanism	(a)	4,623			—
Electron unrecovered loss	4 years	14,008			—
Decoupling under-collection	Less than 2 years	55,363			—
Various other regulatory assets	Varies	14,312			8,078
Total PSE regulatory assets		$	987,402		$	895,732
Cost of removal	(b)	$	(313,088	)	$	(269,536	)
Production tax credits	(c)	(93,616		)	(93,618		)
PGA payable	1 year	—			(5,938		)
PCA mechanism	(a)	—			(5,345		)
Decoupling over-collection	Less than 2 years	(12,582		)	(20,535		)
Summit purchase option buy-out	5.8 years	(9,188		)	(10,763		)
Deferred gain on Jefferson County sale	Less than 1 year	(4,731		)	(60,844		)
Deferred credit on Biogas sale	1 year	(1,445		)	(10,908		)
Deferred credit on gas pipeline capacity	Varies up to 3.8 years	(3,564		)	(4,508		)
Renewable energy credits	1 year	(2,383		)	(5,820		)
Treasury grants	5 to 44 years	(180,496		)	(203,889		)
Deferral of treasury grant amortization	Less than 4 years	(8,197		)	—
Various other regulatory liabilities	Up to 4 years	(6,092		)	(5,755		)
Total PSE regulatory liabilities		$	(635,382	)	$	(697,459	)
PSE net regulatory assets (liabilities)		$	352,020		$	198,273

_______________

^(a)  Amortization periods vary depending on timing of underlying transactions or awaiting regulatory approval in a future Washington Commission rate proceeding.

^(b)  The balance is dependent upon the cost of removal of underlying assets and the life of utility plant.

^(c)  Amortization will begin once PTCs are utilized by PSE on its tax return.

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Puget Energy	Remaining Amortization Period	December 31,
(Dollars in Thousands)		2014			2013
Total PSE regulatory assets	(a)	$	987,402		$	895,732
Puget Energy acquisition adjustments:
Regulatory assets related to power contracts	1 to 22 years	29,816			33,753
Various other regulatory assets	Varies	561			517
Total Puget Energy regulatory assets		$	1,017,779		$	930,002
Total PSE regulatory liabilities	(a)	$	(635,382	)	$	(697,459	)
Puget Energy acquisition adjustments:
Regulatory liabilities related to power contracts	1 to 37 years	(391,389		)	(443,065		)
Various other regulatory liabilities	Varies	(2,820		)	(2,884		)
Total Puget Energy regulatory liabilities		$	(1,029,591	)	$	(1,143,408	)
Puget Energy net regulatory asset (liabilities)		$	(11,812	)	$	(213,406	)

_______________

^(a)  Puget Energy’s regulatory assets and liabilities include purchase accounting adjustments under ASC 805 as a result of the merger. 

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 $313.1 million and $269.5 million in 2014 and 2013, respectively, for the cost of removal of utility plant.  These amounts are collected from PSE’s customers through depreciation 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 modified IEEE outage criteria for system average interruption duration index. In 2014 and 2013, PSE incurred $29.7 million and $9.4 million, respectively, in storm-related electric transmission and distribution system restoration costs, of which $18.0 million was deferred in 2014 and no amount was deferred in 2013.

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 has used an expedited six-month PCORC decision timeline rather than the statutory 11-month timeline for a general rate case.

On October 23, 2013, the Washington Commission approved an update on the Company's PCORC, effective November 1, 2013, which reflected decreases in the overall normalized power supply costs. This resulted in an estimated revenue decrease of $10.5 million or 0.5% annually.

On November 3, 2014 the Washington Commission issued an order on the settlement of the PCORC which PSE filed on May 23, 2014. The original filing proposed a decrease of $9.6 million (or an average of approximately 0.5%) in the Company's overall power supply costs. PSE filed joint testimony supporting a settlement stipulation. Customer rates decreased by approximately $19.4 million or 0.90% annually, as a result of the settlement, effective December 1, 2014.

Electric Rate Case

On April 24, 2014, the Washington Commission approved PSE’s request to change rates under its electric and natural gas decoupling mechanism, effective May 1, 2014.  The rate change incorporated the effects of an increase to the allowed delivery revenue per customer as well as true-ups to the rate from the prior year.  This represents a rate increase for electric of $10.6 million, or 0.5% annually, and a rate decrease for natural gas of $1.0 million, or 0.1% annually.  

On April 24, 2014, the Washington Commission approved PSE’s request to change rates under its electric and natural gas property tax tracker mechanism, effective May 1, 2014.  The rate change incorporated the effects of an increase in the amount of

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property taxes paid as well as true-ups to the rate from the prior year.  This represents a rate increase for electric of $11.0 million, or 0.5% annually, and a rate increase for natural gas of $5.6 million, or 0.6% annually.  

On April 24, 2014, the Washington Commission also approved PSE’s request to change rates under its electric and natural gas conservation riders, effective May 1, 2014.  The rate change incorporated the effects of changes in the annual conservation budgets as well as true-ups to the rate from the prior year.  The rate change represents a rate increase for electric of $12.2 million, or 0.5% annually, and a rate increase for natural gas of $0.3 million.

On November 3, 2014 the Washington Commission approved PSE's 2014 PCORC. The original filing proposed a decrease of $9.6 million (or an average of approximately 0.5%) in the Company's overall power supply costs with an effective date of December 1, 2014. PSE filed joint testimony supporting a settlement stipulation. Customer rates decreased by approximately $19.4 million or 0.90% as a result of the settlement, effective December 1, 2014.

On June 25, 2013, the Washington Commission approved PSE's electric and natural gas decoupling mechanism and expedited rate filing (ERF) tariff filings, effective July 1, 2013. The estimated revenue impact of the decoupling mechanism for electric is an increase of $21.4 million, or 1.0% annually. The estimated revenue impact of the ERF filings for electric is an increase of $30.7 million, or 1.5% annually. In its order, the Washington Commission approved a weighted cost of capital of 7.8% and a capital structure that included 48.0% common equity with a return on equity of 9.8%. Subsequently, certain parties to this proceeding petitioned the Washington Commission to reconsider the order. On December 13, 2013, the Washington Commission approved the settlement agreements for rates effective January 1, 2014. These settlement agreements do not materially change the revenues originally approved in June 2013.

On July 24, 2013, the Public Counsel Division of the Washington State Attorney General's Office (Public Counsel) and the Industrial Customers of Northwest Utilities (ICNU) each filed a petition in Thurston County Superior Court (the Court) seeking judicial reviews of various aspects of the Washington Commission's ERF and decoupling mechanism final order. The parties' petition argues that the order violates various procedural and substantive requirements of the Washington Administrative Procedure Act, and so requests that it be vacated and that the matter be remanded to the Washington Commission. Oral arguments regarding this matter were held on May 9, 2014. On June 25, 2014, the court issued a letter decision in which it affirmed the attrition adjustment (escalating factors referred to as the K-Factor) and the Washington Commission's decision not to consider the case as a general rate case, but reversed and remanded the cost of equity for further adjudication consistent with the court's decision. As a result, there will be evidentiary proceedings regarding Return on Equity (ROE) in February 2015 with an order anticipated in the first half of 2015.

On May 7, 2012, the Washington Commission issued its order in PSE's electric general rate case filed in June 2011, approving a general rate increase for electric customers of $63.3 million or 3.2% annually. The rate increases for electric customers became effective May 14, 2012. In its order, the Washington Commission approved a weighted cost of capital of 7.8% and a capital structure that included 48.0% common equity with a return on equity of 9.8%. PSE's requested treatment of the prepayments made to Bonneville Power Administration (BPA), filed in May 2010, was approved in the order. The final order rejected PSE's proposed conservation savings adjustment. Finally, a new rate rider for RECs was proposed by settlement of electric parties and approved by the Washington Commission in the final order.

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

Type of Rate Adjustment	Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)
PCORC	December 1, 2014	(0.9)%	$(19.4)
Conservation Rider	May 1, 2014	0.5%	12.2
Decoupling Rate Filing	May 1, 2014	0.5	10.6
Property Tax Tracker	May 1, 2014	0.5	11.0
PCORC	November 1, 2013	0.5	10.5
Decoupling Rate Filing	July 1, 2013	1.0	21.4
Expedited Rate Filing	July 1, 2013	1.5	30.7
Electric General Rate Case	May 14, 2012	3.2	63.3

In addition, PSE will be increasing the allowed delivery revenue per customer under the decoupling filing by 3.0% for electric customers on January 1 of each year until the conclusion of PSE's next general rate case.

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Accounting Orders and Petitions

On November 27, 2013, the Washington Commission issued an order authorizing PSE to provide the net proceeds from the sale of natural gas supply produced from a landfill-gas recovery project in King County (Biogas) prior to October 31, 2013 as a bill credit to customers over a one-year period in its RECs adjusting price schedule which became effective January 1, 2014.  Additionally, the Washington Commission order authorized that all net proceeds from Biogas produced after October 31, 2013 plus the internal labor needed to obtain the net proceeds is reflected as a PSE below-the-line item (i.e., not included in the revenues and expenses considered when setting electric customer rates) and excluded from utility operations.

PSE completed the sale of its electric infrastructure assets located in Jefferson County and the transition of electrical services in the county to JPUD on March 31, 2013.  The proceeds from the sale exceeded the transferred assets' net carrying value of $46.7 million resulting in a pre-tax gain of approximately $60.0 million.  In its 2010 order on the subject, the Washington Commission stated that PSE must file an accounting and ratemaking petition with the Washington Commission to determine how this gain will be allocated between customers and shareholders.  As a result, the gain was deferred and recorded as a regulatory liability pending the Washington Commission's determination of the accounting and ratemaking treatment.  On October 31, 2013, PSE filed an accounting petition for a Washington Commission order that would authorize PSE to retain the gain of $45.0 million and return $15.0 million to its remaining customers over a period of 48 months.  On March 28, 2014, intervenors filed response testimonies containing their respective proposals for allocation of the gain, which included a proposal of up to $57.0 million to customers and $3.0 million to PSE. A final order was rendered on September 11, 2014 authorizing PSE to retain $7.5 million of the gain and return $52.7 million to customers. The customer portion is booked to a regulatory liability account in other current liabilities and accruing interest at PSE's after-tax rate of return. PSE and the parties to the case filed a joint motion to amend the final order to allow for the customer portion to be paid to customers through a bill credit in the month of December 2014. The Commission granted the joint motion on October 1, 2014.

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 vary from a baseline power cost rate established in a rate proceeding. 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.

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%

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 (Treasury Grants) to taxpayers who place specified energy property in service provided certain conditions are met.   Section 1603 precludes a recipient from claiming PTCs on property for which a grant is claimed.  

PSE received two treasury grants with a total amount of $107.9 million, related to Baker and Snoqualmie hydro facilities. These grants have been accounted as a reduction to utility plant and will be amortized over the life of the plant based on the Washington Commission authorization.

The Wild Horse Wind Project (Wild Horse) expansion facility was placed into service on November 9, 2009. The capacity of the Wild Horse facility was expanded from 229 megawatts (MW) to 273 MW through the addition of wind turbines.  In February 2010, the U.S. Treasury approved a Treasury Grant of $28.7 million. The 343 MW Lower Snake River facility was placed into service on February 29, 2012. In December 2012, the U.S. Treasury approved a Treasury Grant of $205.3 million.

On February 29, 2012, PSE filed proposed tariff revisions, with stated effective dates of April 1, 2012, and subsequently revised by filing on March 29, 2012 with stated effective dates of June 1, 2012, to pass-through $2.4 million in interest on the unamortized balance of the Wild Horse Expansion Treasury Grant.  On June 26, 2012, the Washington Commission approved PSE's methods and calculations and new rates became effective on July 3, 2012.

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On January 31, 2013, the Washington Commission approved a rate change to the PSE's Federal Incentive Tracker tariff, effective February 1, 2013, which incorporated the effects of the Treasury Grant related to the Lower Snake River wind generation project and keeping the ten year amortization period and inclusion of interest on the unamortized balance of the grants. The rate change passed through 11 months of amortization for both grants to eligible customers over 11 months beginning February 1, 2013. Of the total credit, $34.6 million represents the pass-back of grant amortization and $23.8 million represents the pass through of interest. This represents an overall average rate decrease of 2.8%.

On December 27, 2013, the Washington Commission approved the annual true-up and rate filing to the PSE's Federal Incentive Tracker tariff, effective January 1, 2014. The true-up filing resulted in a total credit of $58.5 million to be passed back to eligible customers over the twelve months beginning January 1, 2014.  Of the total credit, $37.8 million represents the pass-back of grant amortization and $20.6 million represents the pass through of interest, in addition to a minor true-up associated with the 2013 rate period.  This filing represents an overall average rate increase of 0.3%.

Gas Regulation and Rates

Gas General Rate Cases and Other Filings Affecting Rates

On May 7, 2012, the Washington Commission issued its order in PSE's natural gas general rate case filed in June 2011, approving a general rate increase for natural gas customers of $13.4 million, or 1.3% annually. The rate increases for natural gas customers became effective May 14, 2012. In its order, the Washington Commission approved a weighted cost of capital of 7.8% and a capital structure that included 48.0% common equity with a return on equity of 9.8%.

On June 1, 2012, PSE filed with the Washington Commission a petition seeking an Accounting Order authorizing PSE to change the existing natural gas conservation tracker mechanism into a rider mechanism to be consistent with the electric conservation program recovery. The accounting petition requested the ability to recover the costs associated with the Company's current gas conservation programs via transfers from amounts deferred for the over-recovery of commodity costs in the Company's PGA mechanism. The Commission granted PSE's accounting petition on June 28, 2012. The approved accounting petition resulted in an increase to gas conservation revenues of $6.9 million and an increase to conservation amortization expense of $6.6 million.

On June 25, 2013, the Washington Commission approved PSE's electric and natural gas decoupling mechanism and ERF tariff filings, effective July 1, 2013. The estimated revenue impact of the decoupling mechanism for natural gas is an increase of $10.8 million, or 1.1% annually. The estimated revenue impact of the ERF filings for natural gas is a decrease of $2.0 million, or a decrease of 0.2% annually. In its order, the Washington Commission approved a weighted cost of capital of 7.8% and a capital structure that included 48.0% common equity with a return on equity of 9.8%.

Subsequently, certain parties to this proceeding petitioned the Washington Commission to reconsider the order. On December 13, 2013, the Washington Commission approved a series of settlement agreements for rates effective January 1, 2014. These settlement agreements do not materially change the revenues originally approved in June 2013. As a result, certain high volume natural gas industrial customers rate schedules are excluded from the decoupling mechanism and will be subject to certain effects of abnormal weather, conservation impacts and changes in customer usage patterns.

On July 24, 2013, the Public Counsel Division of the Washington State Attorney General's Office (Public Counsel) and the Industrial Customers of Northwest Utilities (ICNU) each filed a petition in Thurston County Superior Court (the Court) seeking judicial review of various aspects of the Washington Commission's ERF and decoupling mechanism final order. The parties' petition argues that the order violates various procedural and substantive requirements of the Washington Administrative Procedure Act, and so requests that it be vacated and that the matter be remanded to the Washington Commission. Oral arguments regarding this matter were held on May 9, 2014. On June 25, 2014, the court issued a letter decision in which it affirmed the attrition adjustment K-Factor and the Washington Commission's decision not to consider the case as a general rate case, but reversed and remanded the cost of equity for further adjudication consistent with the court's decision. As a result, there will be evidentiary proceedings regarding ROE in February 2015 with an order anticipated in the first half of 2015.

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.  Changes in the PGA rates affect PSE’s revenue, but do not impact net operating income as the changes to revenue are offset by increased or decreased purchased gas and gas transportation costs.

On October 30, 2014, the Washington Commission approved the PGA natural gas tariff which proposed to reflect changes in wholesale gas and pipeline transportation costs and changes in deferral amortization rates. The impact of PGA rates is an annual revenue decrease of $23.3 million , or 2.5% annually, with no impact on net operating income.

On October 30, 2013, the Washington Commission approved PSE's PGA natural gas tariff, effective on November 1, 2013, which reflected changes in wholesale gas and pipeline transportation costs and changes in deferral amortization rates. The estimated revenue impact of the approved change is an increase of $4.0 million, or 0.4% annually, with no impact on net operating income.

On October 31, 2012, the Washington Commission approved PSE's PGA natural gas tariff filing and allowed the rates to go into effect on November 1, 2012 on a temporary basis subject to revision. The rates resulted in a decrease to the rates charged to

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customers under the PGA. On May 1, 2013, the Washington Commission approved the proposed rates and allowed them to be made permanent. The estimated revenue impact of the approved change is a decrease of $77.0 million, or 7.7% annually, with no impact on net operating income.

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, 2014	(2.5)%	$(23.3)
Decoupling Rate Filing	May 1, 2014	(0.1)	(1.0)
Purchased Gas Adjustment	November 1, 2013	0.4	4.0
Decoupling Rate Filing	July 1, 2013	1.1	10.8
Expedited Rate Filing	July 1, 2013	(0.2)	(2.0)
Purchased Gas Adjustment	November 1, 2012	(7.7)	(77.0)
Natural Gas General Rate Case	May 14, 2012	1.3	13.4
Purchased Gas Adjustment	November 1, 2011	(4.3)	(43.5)
Natural Gas General Tariff Adjustment	April 1, 2011	1.8	19.0

In addition, PSE will be increasing the allowed delivery revenue per customer under the decoupling filing by 2.2% for natural gas customers on January 1 of each year until the conclusion of PSE's next general rate case.

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 will record adjustments, if any, on a quarterly basis.  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 of $35.4 million for gas and $5.7 million for electric.  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.  The Company is also subject to cost-sharing agreements with third parties regarding environmental remediation projects in Seattle, Washington and Bellingham, Washington. The Company has taken the lead for both projects. As of December 31, 2014, the Company’s share of future remediation costs is estimated to be approximately $25.2 million. The Company's deferred electric environmental costs are $13.4 million, $12.3 million, and $10.9 million at December 31, 2014, 2013 and 2012, respectively, net of insurance proceeds. The Company's deferred natural gas environmental costs are $52.6 million, $45.1 million, and $66.4 million at December 31, 2014, 2013 and 2012, respectively, net of insurance proceeds.

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(4)  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, 2014, approximately $438.4 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 Adjusted 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 3 to one.  The common equity ratio, calculated on a regulatory basis, was 47.7% at December 31, 2014, and the EBITDA to interest expense was 4.3 to one for the twelve months then ended.

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 (as defined in the facilities), or if the payment of dividends would result in an Event of Default, 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.  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 2 to one.   Puget Energy's EBITDA to interest expense was 3.1 to one for the twelve months ended December 31, 2014.

At December 31, 2014, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.

(5)  Utility Plant

		Puget Energy						Puget Sound Energy
Utility Plant	Estimated Useful Life	At December 31,						At December 31,
(Dollars In Thousands)	(Years)	2014			2013			2014			2013
Electric, gas and common utility plant classified by prescribed accounts :
Distribution plant	10-50	$	4,748,988		$	4,448,451		$	6,417,551		$	6,127,732
Production plant	25-125	2,973,853			2,966,223			3,907,224			3,948,270
Transmission plant	45-65	1,189,296			1,043,605			1,306,009			1,162,929
General plant	5-35	481,116			504,965			553,130			599,156
Intangible plant (including capitalized software)	3-50	311,959			316,614			304,135			309,972
Plant acquisition adjustment	7-30	242,826			242,826			282,792			282,792
Underground storage	25-60	28,859			27,857			42,494			41,501
Liquefied natural gas storage	25-45	12,628			12,622			14,498			14,492
Plant held for future use	NA	54,996			28,742			55,148			28,895
Recoverable Cushion Gas	NA	8,655			8,655			8,655			8,655
Plant not classified	1-100	91,519			124,589			91,519			124,589
Grant	NA	(105,659		)	—			(105,659		)	—
Capital leases, net of accumulated amortization 1	5	9,473			17,051			9,473			17,051
Less: accumulated provision for depreciation		(1,611,220		)	(1,373,178		)	(4,449,680		)	(4,297,012		)
Subtotal		$	8,437,289		$	8,369,022		$	8,437,289		$	8,369,022
Construction work in progress	NA	239,690			310,318			239,690			310,318
Net utility plant		$	8,676,979		$	8,679,340		$	8,676,979		$	8,679,340

_______________

¹  Accumulated amortization of capital leases at Puget Energy was $28.4 million in 2014 and $20.8 million in 2013.  Accumulated amortization of capital leases at PSE was $28.4 million in 2014 and $20.8 million in 2013.

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Jointly owned generating plant service costs are included in utility plant service cost at the Company's ownership share.  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, 2014.  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	%	$	158,516	$	(12,047	)	$	293,103	$	(146,635	)
Colstrip Units 3 & 4	Coal	25	%	234,787		(28,763		)	509,619		(303,594		)
Colstrip Units 1 – 4 Common Facilities 1	Coal	various		83		(21		)	252		(189		)
Frederickson 1	Gas	49.85	%	61,771		(5,750		)	70,719		(14,698		)
Jackson Prairie	Gas Storage	33.34	%	28,185		(4,099		)	42,494		(18,409		)

_______________

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

  As of December 31, 2014, there are no new Asset Retirement Obligations (ARO) in 2014 and $0.4 million in 2013.   

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

	At December 31,
(Dollars in Thousands)	2014			2013
Asset retirement obligation at beginning of period	$	48,687		$	45,496
New asset retirement obligation recognized in the period	—			350
Liability settled in the period	(602		)	(1,188		)
Revisions in estimated cash flows	(480		)	2,769
Accretion expense	1,304			1,260
Asset retirement obligation at end of period	$	48,909		$	48,687

The Company has identified the following obligations, as defined by ASC 410, “Asset Retirement and Environmental Obligations,” which were not recognized because the liability for these assets cannot be reasonably estimated at December 31, 2014 due to:

• 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;

• 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;

• 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.

• 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;

• An obligation to pay decommissioning costs at the end of utility service franchise agreements to restore the surface of the franchise area. The decommissioning costs related to facilities at the franchise area could not be measured since the decommissioning date is indeterminable; therefore, the liability cannot be reasonably estimated; and

• A potential legal obligation may arise upon the expiration of an existing FERC hydropower license if FERC orders the project to be decommissioned, although PSE contends that FERC does not have such authority.  Given the value of ongoing generation, flood control and other benefits provided by these projects, PSE believes that the potential for decommissioning is remote and cannot be reasonably estimated.

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(6)  Long-Term Debt

(Dollars in Thousands)			At December 31,
Series	Type	Due	2014			2013
Puget Sound Energy:
7.350%	First Mortgage Bond	2015	$	10,000		$	10,000
7.360%	First Mortgage Bond	2015	2,000			2,000
5.197%	Senior Secured Note	2015	150,000			150,000
6.750%	Senior Secured Note	2016	250,000			250,000
5.500%	Promissory Note 1	2017	2,412			2,412
6.740%	Senior Secured Note	2018	200,000			200,000
7.150%	First Mortgage Bond	2025	15,000			15,000
7.200%	First Mortgage Bond	2025	2,000			2,000
7.020%	Senior Secured Note	2027	300,000			300,000
7.000%	Senior Secured Note	2029	100,000			100,000
3.900%	Pollution Control Bond	2031	138,460			138,460
4.000%	Pollution Control Bond	2031	23,400			23,400
5.483%	Senior Secured Note	2035	250,000			250,000
6.724%	Senior Secured Note	2036	250,000			250,000
6.274%	Senior Secured Note	2037	300,000			300,000
5.757%	Senior Secured Note	2039	350,000			350,000
5.795%	Senior Secured Note	2040	325,000			325,000
5.764%	Senior Secured Note	2040	250,000			250,000
4.434%	Senior Secured Note	2041	250,000			250,000
5.638%	Senior Secured Note	2041	300,000			300,000
4.700%	Senior Secured Note	2051	45,000			45,000
6.974%	Junior Subordinated Note	2067	250,000			250,000
	Unamortized discount on senior notes		(13		)	(14		)
PSE long-term debt			$	3,763,259		$	3,763,258
Puget Energy:
	Fair value adjustment of PSE long-term debt		$	(218,619	)	$	(229,746	)
	Credit Facility	2017	—			299,000
	Term-Loan	2016	100,000			—
	Term-Loan	2017	100,000			—
	Term-Loan	2016	99,000			—
6.500%	Senior Secured Note	2020	450,000			450,000
6.000%	Senior Secured Note	2021	500,000			500,000
5.625%	Senior Secured Note	2022	450,000			450,000
	Unamortized discount on senior notes		(32		)	(36		)
Total Puget Energy long-term debt			$	5,243,608		$	5,232,476

____________

¹  Puget Western, Inc., a wholly owned subsidiary of PSE, Promissory Note.

PSE's senior secured notes will cease to be secured by the pledged first mortgage bonds on the date that all of the first mortgage bonds issued and outstanding under the electric or natural gas utility mortgage indenture have been retired.  As of December 31, 2014, the latest maturity date of the first mortgage bonds, other than pledged first mortgage bonds, is December 22, 2025.

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Puget Sound Energy Long-Term Debt

PSE has in effect a shelf registration statement under which it may issue, from time to time, up to $800 million aggregate principal amount of senior notes secured by pledged 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.

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, 2014, the earnings available for interest exceeded the required amount.

Puget Sound Energy Pollution Control Bonds

PSE has two series of Pollution Control Bonds (the 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.

In May 2013, PSE refinanced $161.9 million of the Bonds to a lower weighted average interest rate from 5.01% to 3.91%. The Bonds will mature on March 1, 2031. On or after March 1, 2023, the Company may elect to call the bonds at a redemption price of 100% of the principal amount thereof, without premium, plus accrued interest, if any, to the redemption date. Due to the refinance of the Bonds, Puget Energy wrote off $18.0 million of fair value related to the Bonds that were redeemed to interest expense.

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

Puget Energy Long-Term Debt

At the time of the merger in 2009, Puget Energy entered into a $1.225 billionfive-year term-loan and a $1.0 billionfive-year capital expenditure credit facility for funding capital expenditures. In February 2012, Puget Energy entered into a $1.0 billionfive-year revolving senior secured credit facility and the 2009 term loan and capital expenditure facilities were terminated. Concurrent with the closing of the new PSE credit facilities in February 2013, the Company reduced the size of Puget Energy's credit facility to $800.0 million. The Puget Energy revolving senior secured credit facility also has an accordion feature that, upon the banks' approval, would increase the size of the facility to $1.3 billion. In April 2014, the Company completed an amendment to the senior secured credit facility, extending the maturity from February 2017 to April 2018, updating the fee structure, eliminating a financial covenant and updating or clarifying the definitions of other terms and conditions of the facility. All other terms and conditions of that facility remain unchanged from when it was committed in 2012. As a revolving facility, amounts borrowed may be repaid without a reduction in the size of the facility.

The Puget Energy revolving senior secured credit facility contains usual and customary affirmative and negative covenants.  The agreement also contains a financial covenant based on the Maximum Leverage Ratio, as defined in the agreement governing the senior secured credit facility.

In June 2014, Puget Energy entered into three bilateral term loans, with two and three year maturities, which in total, equal $299 million. The proceeds of the term loans were used to pay off the outstanding Puget Energy revolving credit facility balance, which subsequently allows the Company to carry the debt with lower interest expense. All other terms, conditions and covenants are consistent with each other and the credit facility agreement, with the exception of maturity and price.

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)	2015		2016		2017		2018		2019		Thereafter		Total
Maturities of:
PSE long-term debt	$	162,000	$	250,000	$	2,412	$	200,000	$	—	$	3,148,860	$	3,763,272
Puget Energy long-term debt	—		199,000		100,000		—		—		1,400,000		1,699,000
Puget Energy long-term debt	$	162,000	$	449,000	$	102,412	$	200,000	$	—	$	4,548,860	$	5,462,272

Financial Covenants

Puget Energy's credit facility contains a financial covenant related to maximum leverage. As of December 31, 2014, the Company is in compliance with its long-term debt financial covenants.

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(7)  Liquidity Facilities and Other Financing Arrangements

As of December 31, 2014 and 2013, PSE had $85.0 million and $162.0 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 2014 and 2013 was 4.05% and 3.93%, respectively.  As of December 31, 2014, PSE and Puget Energy had several committed credit facilities that are described below.

Puget Sound Energy Credit Facilities

PSE has two unsecured revolving credit facilities which provide, in aggregate, $1.0 billion of short-term liquidity needs. These facilities consist of a $650.0 million revolving liquidity facility (which includes a liquidity letter of credit facility and a swingline facility) to be used for general corporate purposes, including a backstop to the Company's commercial paper program and a $350.0 million revolving energy hedging facility (which includes an energy hedging letter of credit facility). The $650.0 million liquidity facility includes a swingline feature allowing same day availability on borrowings up to $75.0 million. The credit facilities also have an accordion feature which, upon the banks' approval, would increase the total size of these facilities to $1.450 billion.

In April 2014, the Company completed a one-year extension on both of the liquidity and hedging facilities, extending the maturity from February 2018 to April 2019, and updating or clarifying the definitions of other terms and conditions of the facilities from when they were committed in 2013. The credit agreements are syndicated among numerous lenders and contain usual and customary affirmative and negative covenants that, among other things, place limitations on PSE's ability to transact with affiliates, make asset dispositions and investments or permit liens to exist. The credit agreements also contain a financial covenant of total debt to total capitalization of 65% or less. PSE certifies its compliance with such covenants to participating banks each quarter. As of December 31, 2014, PSE was in compliance with all applicable covenant ratios.

The credit agreements provide PSE with the ability to borrow at different interest rate options. 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. PSE must pay a commitment fee on the unused portion of the credit facilities. The spreads and the commitment fee depend on PSE's credit ratings. As of the date of this report, the spread to the LIBOR is 1.25% and the commitment fee is 0.175%.

As of December 31, 2014, no amounts were drawn and outstanding under PSE's liquidity facility. No amounts were drawn and outstanding under the $350.0 million energy hedging facility. No letters of credit were outstanding under either facility, and $85.0 million was outstanding under the commercial paper program. Outside of the credit agreements, PSE had a $4.2 million letter of credit in support of a long-term transmission contract and a $1.0 million letter of credit in support of natural gas purchases in Canada.

Demand Promissory Note  

In 2006, PSE entered into a revolving credit facility with Puget Energy, in the form of a credit agreement and a Demand Promissory Note (Note) pursuant to which PSE may borrow up to $30.0 million from Puget Energy subject to approval by Puget Energy.  Under the terms of the Note, PSE pays interest on the outstanding borrowings based on the lower of the weighted-average interest rates of PSE’s outstanding commercial paper 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, 2014, the outstanding balance of the Note was $28.9 million.  The outstanding balance and the related interest under the Note are eliminated by Puget Energy upon consolidation of PSE’s financial statements.

Puget Energy Credit Facility

At December 31, 2014, Puget Energy maintained an $800.0 million revolving senior secured credit facility. In April, 2014, the Company completed an amendment to the senior secured credit facility, extending the maturity from February 2017 to April 2018, updating the fee structure, eliminating a financial covenant and updating or clarifying the definitions of other terms and conditions of the facility. The Puget Energy revolving senior secured credit facility also has an accordion feature which, upon the banks' approval, would increase the size of the facility to $1.3 billion.

The revolving senior secured credit facility provides Puget Energy the ability to borrow at different interest rate options and includes variable fee levels. Interest rates may be based on the bank's prime rate or LIBOR plus a spread based on Puget Energy's credit ratings. Puget Energy must pay a commitment fee on the unused portion of the facility. As of December 31, 2014, there was no amount drawn and outstanding under the facility. As a result of Puget Energy's credit rating upgrade in 2014, the spread over LIBOR was 1.75% and the commitment fee was 0.28% as of the date of this report. Puget Energy entered into interest rate swap contracts to manage the interest rate risk associated with the credit facility or similar variable rate debt.

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The revolving senior secured credit facility contains usual and customary affirmative and negative covenants. The agreement also contains a Maximum Leverage Ratio financial covenant as defined in the agreement governing the senior secured credit facility. As of December 31, 2014, Puget Energy was in compliance with all applicable covenants.

(8)  Leases

PSE leases buildings and assets under operating leases.    Certain leases contain purchase options, renewal options and escalation provisions.  Operating lease expenses net of sublease receipts were:

(Dollars in Thousands)
At December 31,
2014	$	30,737
2013	29,392
2012	29,661

Payments received for the subleases of properties were immaterial for each of the years ended 2014, 2013 and 2012.

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

(Dollars in Thousands)
At December 31,	Operating		Capital
2015	$	17,677	$	8,160
2016	21,454		2,178
2017	22,179		—
2018	20,423		—
2019	15,180		—
Thereafter	120,791		—
Total minimum lease payments	$	217,704	$	10,338

(9)  Accounting for Derivative Instruments and Hedging Activities

PSE employs various energy 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 and PSE's related hedging strategies are focused on reducing costs and risks where feasible, thus reducing volatility in costs in the portfolio. In order to manage its exposure to the variability in future cash flows for forecasted energy transactions, PSE utilizes a programmatic hedging strategy which extends out three years. 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 forward physical electric and natural gas purchase and sale agreements, fixed-for-floating swap contracts, and commodity call/put options. The forward physical electric agreements are both fixed and variable (at index), while the physical natural gas contracts are variable. To fix the price of wholesale electricity and natural gas, PSE may enter into fixed-for-floating swap (financial) contracts with various counterparties. PSE also utilizes natural gas call and put options as an additional hedging instrument to increase the hedging portfolio's flexibility to react to commodity price fluctuations.

The Company manages its interest rate risk through the issuance of mostly fixed-rate debt with varied maturities. The Company utilizes internal cash from operations, borrowings under its commercial paper program, and its credit facilities to meet short-term funding needs. The Company may enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts. As of December 31, 2014, Puget Energy had two interest rate swap contracts outstanding which extend to January 2017. PSE did not have any outstanding interest rate swap instruments.

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The following table presents the volumes, fair values and locations of the Company's derivative instruments recorded on the balance sheets:

Puget Energy and Puget Sound Energy	Year Ended December 31,
(Dollars in Thousands)	Volumes (millions)		Assets 1				Liabilities 2
	2014	2013	2014		2013		2014		2013
Interest rate swap derivatives 3	$450.0	$450.0	$	—	$	—	$	9,073	$	13,223
Electric portfolio derivatives	*	*	4,822		18,479		107,228		37,312
Natural gas derivatives (MMBtus) 4	360.4	423.5	19,526		8,121		88,807		35,676
Total derivative contracts			$	24,348	$	26,600	$	205,108	$	86,211
Current			$	21,178	$	18,867	$	142,195	$	48,049
Long-term			3,170		7,733		62,913		38,162
Total derivative contracts			$	24,348	$	26,600	$	205,108	$	86,211

___________

¹  Balance sheet location: Current and Long-term Unrealized gain on derivative instruments.

²  Balance sheet location: Current and Long-term Unrealized loss on derivative instruments.

³  Interest rate swap contracts are only held at Puget Energy.

⁴  PSE had a net derivative liability and an offsetting regulatory asset of $69.3 million at December 31, 2014 and $27.6 million at December 31, 2013 related to 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 deferred in accordance with ASC 980, due to the PGA mechanism.

^*  Electric portfolio derivatives consist of electric generation fuel of 140.2 million One Million British Thermal Units (MMBtus) and purchased electricity of 5.4 million Megawatt Hours (MWhs) at December 31, 2014 and 145.6 million MMBtus and 8.6 million MWhs at December 31, 2013.

For further details regarding the fair value of derivative instruments, see Note 10.

It is the Company's policy to record all derivative transactions on a gross basis at the contract level, without offsetting assets or liabilities. The Company generally enters into transactions using the following master agreements: WSPP, Inc. (WSPP) agreements which standardize physical power contracts; ISDA agreements which standardize financial gas and electric contracts; and NAESB agreements which standardize physical gas contracts. The Company believes that such agreements reduce credit risk exposure because such agreements provide for the netting and offsetting of monthly payments as well as right of set-off in the event of counterparty default. The set-off provision can be used as a final settlement of accounts which extinguishes the mutual debts owed between the parties in exchange for a new net amount.

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The following tables present the potential effect of netting arrangements, including rights of set-off associated with the Company's derivative assets and liabilities:

Puget Energy and Puget Sound Energy
At December 31, 2014
(Dollars in Thousands)	Gross Amounts Recognized in the Statement of Financial Position 1		Gross Amounts Offset in the Statement of Financial Position		Net of Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position
							Commodity Contracts			Cash Collateral Received/Posted			Net Amount
Assets
Energy Derivative Contracts	$	24,348	$	—	$	24,348	$	(23,066	)	$	—		$	1,282
Liabilities
Energy Derivative Contracts	$	196,035	$	—	$	196,035	$	(23,066	)	$	(20	)	$	172,949
Interest Rate Swaps 2	$	9,073	$	—	$	9,073	$	—		$	—		$	9,073
Puget Energy and Puget Sound Energy
At December 31, 2013
(Dollars in Thousands)	Gross Amounts Recognized in the Statement of Financial Position 1		Gross Amounts Offset in the Statement of Financial Position		Net of Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position
							Commodity Contracts			Cash Collateral Received/Posted			Net Amount
Assets
Energy Derivative Contracts	$	26,600	$	—	$	26,600	$	(19,491	)	$	—		$	7,109
Liabilities
Energy Derivative Contracts	$	72,988	$	—	$	72,988	$	(19,491	)	$	—		$	53,497
Interest Rate Swaps 2	$	13,223	$	—	$	13,223	$	—		$	—		$	13,223

___________

^1.  All Derivative Contract deals are executed under ISDA, NAESB and WSPP Master Netting Agreements with Right of Offset.

²  Interest Rate Swap Contracts are only held at Puget Energy.

Due to the merger in 2009, Puget Energy recorded all derivative contracts at fair value as either assets or liabilities. Certain contracts meeting the criteria defined in ASC 815 were subsequently designated as NPNS or cash flow hedges, thereby causing differences in the derivative unrealized gains/losses to be recorded through earnings between Puget Energy and PSE. These differences will occur through February 2015.

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The following tables present the effect and locations of the Company's derivatives not designated as hedging instruments, recorded on the statements of income:

Puget Energy		Year Ended December 31,
(Dollars in Thousands)	Location	2014			2013			2012
Interest rate contracts:	Other deductions	$	(3,915	)	$	2,420		$	(4,288	)
	Interest expense	500			(5,904		)	(29,727		)
Commodity contracts:
Electric derivatives	Unrealized gain (loss) on derivative instruments, net 1	(84,146		)	102,744			131,407
	Electric generation fuel	6,511			(27,008		)	(66,762		)
	Purchased electricity	(4,212		)	(38,299		)	(138,551		)
Total gain (loss) recognized in income on derivatives		$	(85,262	)	$	33,953		$	(107,921	)

___________

¹  For 2012, the amount differs from the amount stated in the statement of income as it does not include amortization related to contracts that were recorded at fair value at the time of the February 2009 merger and subsequently designated as NPNS of $2.2 million for the year ended December 31, 2012.

Puget Sound Energy		Year Ended December 31,
(Dollars in Thousands)	Location	2014			2013			2012
Commodity contracts:
Electric derivatives	Unrealized gain (loss) on derivative instruments, net	$	(85,636	)	$	98,880		$	119,120
	Electric generation fuel	6,511			(27,008		)	(66,762		)
	Purchased electricity	(4,212		)	(38,299		)	(138,551		)
Total gain (loss) recognized in income on derivatives		$	(83,337	)	$	33,573		$	(86,193	)

The unrealized gain or loss on derivative contracts is reported in the statement of cash flows under the operating activities section. However, at the time of the merger in 2009, all derivative contracts at Puget Energy were assessed to identify contracts that have a “more than an insignificant” fair value. If the fair value was greater than 10% of the notional value, the contract was deemed as having a financing element. For those contracts, the cash inflows (outflows) are presented in the financing activities section of the statement of cash flows. For the years ended December 31, 2014, 2013 and 2012, cash outflows related to financing activities of $16.3 million, $34.3 million and $92.7 million, respectively, were reported on Puget Energy's statement of cash flows.

For derivative instruments previously designated as cash flow hedges (including both commodity and interest rate swap contracts), the effective portion of the gain or loss on the derivative was recorded as a component of OCI, and then is reclassified into earnings in the same period(s) during which the hedged transaction affects earnings.

Puget Energy and PSE expect $0.5 million and $1.1 million of losses, respectively, in accumulated OCI will be reclassified into earnings within the next twelve months. The Company does not attempt cash flow hedging for any new transactions and records all mark-to-market adjustments through earnings.

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The following tables present the Company's pre-tax gain (loss) on derivatives that were previously in a cash flow hedge relationship, and subsequently reclassified out of accumulated OCI into income:

Puget Energy		Year Ended December 31,
(Dollars in Thousands)	Location	2014			2013			2012
Interest rate contracts:	Interest expense	$	(144	)	$	(4,505	)	$	(17,811	)
Commodity contracts:
Electric derivatives	Electric generation fuel	—			—			100
	Purchased electricity	(572		)	(57		)	(671		)
Total		$	(716	)	$	(4,562	)	$	(18,382	)

Puget Sound Energy		Year Ended December 31,
(Dollars in Thousands)	Location	2014			2013			2012
Interest rate contracts:	Interest expense	$	(488	)	$	(488	)	$	(488	)
Commodity contracts:
Electric derivatives	Electric generation fuel	—			—			97
	Purchased electricity	(2,063		)	(3,922		)	(12,955		)
Total		$	(2,551	)	$	(4,410	)	$	(13,346	)

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 distress. 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, 2014, approximately 99.3% 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 0.7% are either rated below investment grade or not rated by rating agencies. The Company assesses credit risk internally for counterparties that are not rated.

As the Company generally enters into transactions using the WSPP, ISDA and NAESB master agreements, it believes that such agreements reduce credit risk exposure because they provide for the netting and offsetting of monthly payments and, in the event of counterparty default, termination payments.

The Company computes credit reserves at a master agreement level by counterparty (i.e., WSPP, ISDA, or NAESB). The Company considers external credit ratings and market factors, such as credit default swaps and bond spreads, in the 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 determined by weighting the fair value and contract tenors for all deals for each counterparty to derive an average value. The default factor used is dependent upon whether the counterparty is in a net asset or a net liability position after applying the master agreement levels.

The Company applies the counterparty's default factor to compute credit reserves for counterparties that are in a net asset position. The Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate. Credit reserves are netted against unrealized gain (loss) positions. As of December 31, 2014, the Company was in a net liability position with the majority of counterparties, so the default factors of counterparties did not have a significant impact on reserves for the quarter. The majority of the Company's derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council. As of December 31, 2014, PSE has posted a $1.0 million letter of credit as a condition of transacting on a physical energy exchange and clearinghouse in Canada. PSE did not trigger any collateral requirements with any of its counterparties nor were any of PSE's counterparties required to post collateral resulting from credit rating downgrades.

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The table below presents the fair value of the overall contractual contingent liability positions for the Company's derivative activity at December 31, 2014:

Puget Energy and Puget Sound Energy Contingent Feature (Dollars in Thousands)	Fair Value 1 Liability			Posted Collateral		Contingent Collateral
Credit rating 2	$	(37,398	)	$	—	$	37,398
Requested credit for adequate assurance	(66,468		)	—		—
Forward value of contract 3	(2,490		)	—		—
Total	$	(106,356	)	$	—	$	37,398

__________

¹  Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions. Excludes NPNS, accounts payable and accounts receivable.

²  Failure by PSE to maintain an investment grade credit rating from each of the major credit rating agencies provides counterparties a contractual right to demand collateral.

³  Collateral requirements may vary, based on changes in the forward value of underlying transactions relative to contractually defined collateral thresholds.

(10)  Fair Value Measurements

ASC 820 established a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy categorizes the inputs into three levels with the highest priority given to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority given to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:

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

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

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

Financial assets and liabilities measured at fair value are classified in their entirety in the appropriate fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. The Company primarily determines fair value measurements classified as Level 2 or Level 3 using a combination of the income and market valuation approaches. The process of determining the fair values is the responsibility of the derivative accounting department which reports to the Controller and Principal Accounting Officer. Inputs used to estimate the fair value of forwards, swaps and options include market-price curves; contract terms and prices; credit-risk adjustments; and discount factors. Additionally, for options, the Black-Scholes option valuation model and implied market volatility curves are used. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs because substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments. On a daily basis, the Company obtains quoted forward prices for the electric and natural gas markets from an independent external pricing service. For interest rate swaps, the Company obtains monthly mark-to-market values from an independent external pricing service for LIBOR forward rates, which is a significant input. Some of the inputs of the interest rate swap valuations, which are less significant, include the credit standing of the counterparties, assumptions for time value and the impact of the Company's nonperformance risk of its liabilities. The Company classifies cash and cash equivalents, and restricted cash as Level 1 financial instruments due to cash being at stated value, and cash equivalents at quoted market prices.

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The Company considers its electric, natural gas and interest rate swap contracts as Level 2 derivative instruments as such contracts are commonly traded as over-the-counter forwards with indirectly observable price quotes. Management's assessment was based on the trading activity in real-time and forward electric and natural gas markets. Each quarter, the Company confirms the validity of pricing-service quoted prices (e.g., Level 2 in the fair value hierarchy) used to value commodity contracts with the actual prices of commodity contracts entered into during the most recent quarter. However, certain energy derivative instruments with maturity dates falling outside the range of observable price quotes are classified as Level 3 in the fair value hierarchy.

Assets and Liabilities with Estimated Fair Value

The following table presents the carrying value for cash, cash equivalents, restricted cash, notes receivable and short-term debt by level, within the fair value hierarchy. The carrying values below are representative of fair values due to the short-term nature of these financial instruments.

Puget Energy	Carrying / Fair Value						Carrying / Fair Value
	At December 31, 2014						At December 31, 2013
(Dollars in Thousands)	Level 1		Level 2		Total		Level 1		Level 2		Total
Assets:
Cash and Cash Equivalents	$	37,527	$	—	$	37,527	$	44,302	$	—	$	44,302
Restricted Cash	32,863		—		32,863		7,171		—		7,171
Notes Receivable and Other	—		53,503		53,503		—		53,449		53,449
Total assets	$	70,390	$	53,503	$	123,893	$	51,473	$	53,449	$	104,922
Liabilities:
Short-term debt	$	85,000	$	—	$	85,000	$	162,000	$	—	$	162,000
Total liabilities	$	85,000	$	—	$	85,000	$	162,000	$	—	$	162,000

Puget Sound Energy	Carrying / Fair Value						Carrying / Fair Value
	At December 31, 2014						At December 31, 2013
(Dollars in Thousands)	Level 1		Level 2		Total		Level 1		Level 2		Total
Assets:
Cash and Cash Equivalents	$	37,466	$	—	$	37,466	$	44,111	$	—	$	44,111
Restricted Cash	32,863		—		32,863		7,171		—		7,171
Notes Receivable and Other	—		53,503		53,503		—		53,449		53,449
Total assets	$	70,329	$	53,503	$	123,832	$	51,282	$	53,449	$	104,731
Liabilities:
Short-term debt	$	85,000	$	—	$	85,000	$	162,000	$	—	$	162,000
Short-term debt owed to parent	—		28,933		28,933		—		29,598		29,598
Total liabilities	$	85,000	$	28,933	$	113,933	$	162,000	$	29,598	$	191,598

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The fair value of the junior subordinated and long-term notes were estimated using the discounted cash flow method with U.S. Treasury yields and Company credit spreads as inputs, interpolating to the maturity date of each issue. Carrying values and estimated fair values were as follows:

Puget Energy		December 31, 2014				December 31, 2013
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Junior subordinated notes	2	$	250,000	$	276,235	$	250,000	$	269,366
Long-term debt (fixed-rate), net of discount	2	4,694,608		6,083,554		4,683,476		5,594,314
Long-term debt (variable-rate)	2	299,000		299,000		299,000		299,000
Total		$	5,243,608	$	6,658,789	$	5,232,476	$	6,162,680
Puget Sound Energy		December 31, 2014				December 31, 2013
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Junior subordinated notes	2	$	250,000	$	276,235	$	250,000	$	269,366
Long-term debt (fixed-rate), net of discount	2	3,513,259		4,437,473		3,513,258		4,038,455
Total		$	3,763,259	$	4,713,708	$	3,763,258	$	4,307,821

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following tables present the Company's financial assets and liabilities by level, within the fair value hierarchy, that were accounted for at fair value on a recurring basis and the reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy:

Puget Energy	Fair Value						Fair Value
	At December 31, 2014						At December 31, 2013
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total
Interest rate derivative instruments	$	9,073	$	—	$	9,073	$	13,223	$	—	$	13,223
Total derivative liabilities	$	9,073	$	—	$	9,073	$	13,223	$	—	$	13,223

Puget Energy and Puget Sound Energy	Fair Value						Fair Value
	At December 31, 2014						At December 31, 2013
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	1,654	$	3,168	$	4,822	$	14,661	$	3,818	$	18,479
Natural gas derivative instruments	18,064		1,462		19,526		5,448		2,673		8,121
Total assets	$	19,718	$	4,630	$	24,348	$	20,109	$	6,491	$	26,600
Liabilities:
Electric derivative instruments	$	91,998	$	15,230	$	107,228	$	18,073	$	19,239	$	37,312
Natural gas derivative instruments	85,305		3,502		88,807		32,642		3,034		35,676
Total liabilities	$	177,303	$	18,732	$	196,035	$	50,715	$	22,273	$	72,988

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Puget Energy and Puget Sound Energy	Year Ended December 31,
Level 3 Roll-Forward Net (Liability)	2014									2013									2012
(Dollars in Thousands)	Electric			Gas			Total			Electric			Gas			Total			Electric			Gas			Total
Balance at beginning of period	$	(15,421	)	$	(361	)	$	(15,782	)	$	(33,924	)	$	(1,602	)	$	(35,526	)	$	(90,311	)	$	(5,041	)	$	(95,352	)
Changes during period
Realized and unrealized energy derivatives:
Included in earnings 1	(5,537		)	—			(5,537		)	(10,491		)	—			(10,491		)	(21,362		)	—			(21,362		)
Included in regulatory assets / liabilities	—			1,630			1,630			—			(945		)	(945		)	—			(1,937		)	(1,937		)
Settlements 2	1,036			(1,534		)	(498		)	11,609			(754		)	10,855			59,133			969			60,102
Transferred into Level 3	5,155			(585		)	4,570			(7,799		)	—			(7,799		)	(55,548		)	(297		)	(55,845		)
Transferred out of Level 3	2,705			(1,190		)	1,515			25,184			2,940			28,124			74,164			4,704			78,868
Balance at end of period	$	(12,062	)	$	(2,040	)	$	(14,102	)	$	(15,421	)	$	(361	)	$	(15,782	)	$	(33,924	)	$	(1,602	)	$	(35,526	)

_______________

¹  Income Statement location: Unrealized (gain) loss on derivative instruments, net. Includes unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $(9.6) million, $(13.4) million, and $(15.2) million for the years ended December 31, 2014, 2013 and 2012, respectively.

²  The Company had no purchases, sales or issuances during the reported periods.

Realized gains and losses on energy derivatives for Level 3 recurring items are included in energy costs in the Company's consolidated statements of income under purchased electricity, electric generation fuel or purchased natural gas when settled. Unrealized gains and losses on energy derivatives for Level 3 recurring items are included in net unrealized (gain) loss on derivative instruments in the Company's consolidated statements of income.

In order to determine which assets and liabilities are classified as Level 3, the Company receives market data from its independent external pricing service defining the tenor of observable market quotes. To the extent any of the Company's commodity contracts extend beyond what is considered observable as defined by its independent pricing service, the contracts are classified as Level 3. The actual tenor of what the independent pricing service defines as observable is subject to change depending on market conditions. Therefore, as the market changes, the same contract may be designated Level 3 one month and Level 2 the next, and vice versa. The changes of fair value classification into or out of Level 3 are recognized each month, and reported in the Level 3 Roll-forward table above. The Company did not have any transfers between Level 2 and Level 1 during the years ended December 31, 2014 and 2013. The Company does periodically transact at locations, or market price points, that are illiquid or for which no prices are available from the independent pricing service. In such circumstances the Company uses a more liquid price point and performs a 15-month regression against the illiquid locations to serve as a proxy for market prices. Such transactions are classified as Level 3. The Company does not use internally developed models to make adjustments to significant unobservable pricing inputs.

The only significant unobservable input into the fair value measurement of the Company's Level 3 assets and liabilities is the forward price for electric and natural gas contracts. Below are the forward price ranges for the Company's commodity contracts, as of December 31, 2014:

(Dollars in Thousands)
	Fair Value				Range
Derivative Instrument	Assets 1	Liabilities 1	Valuation Technique	Unobservable Input	Low	High	Weighted Average
Electric	$3,168	$15,230	Discounted cash flow	Power Prices	$21.79 per MWh	$35.46 per MWh	$32.89 per MWh
Natural gas	$1,462	$3,502	Discounted cash flow	Natural Gas Prices	$3.11 per MMBtu	$3.83 per MMBtu	$3.28 per MMBtu

_______________

¹  The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.

The significant unobservable inputs listed above would have a direct impact on the fair values of the above instruments if they were adjusted. Consequently significant increases or decreases in the forward prices of electricity or natural gas in isolation would result in a significantly higher or lower fair value for Level 3 assets and liabilities. Generally, interrelationships exist between market

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prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets. At December 31, 2014, a hypothetical 10% increase or decrease in market prices of natural gas and electricity would change the fair value of the Company's derivative portfolio, classified as Level 3 within the fair value hierarchy, by $3.9 million.

Long-Lived Assets Measured at Fair Value on a Nonrecurring Basis

At the time of merger, Puget Energy recorded the fair value of its intangible assets in accordance with ASC 360, “Property, Plant, and Equipment,” (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 non-performance 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-lived assets to be tested for impairment on an annual basis, and upon the occurrence of any events or circumstances that would be more likely than not to reduce the fair value of the long-lived assets below their carrying value. One such triggering event is a significant decrease in the forward market prices of power.

At December 31, 2014, Puget Energy completed a valuation and impairment test of its purchased power contracts classified as intangible assets. The valuation indicated a fair value of $437.6 million with an impairment to the Wells hydro contract. As of December 31, 2014, the carrying value for this contract was $65.3 million and its fair value on a discounted basis was $62.1 million, thereby requiring a write-down of $3.2 million to this intangible asset with a corresponding reduction in the regulatory liability.

Below are significant unobservable inputs used in estimating the impaired long term power purchase contract's fair value on December 31, 2014:

Valuation Technique	Unobservable Input	Low	High	Average
Discounted cash flow	Power prices	$19.30 per MWh	$37.06 per MWh	$29.53 per MWh
Discounted cash flow	Power contract costs (in thousands)	$3,015 per qtr	$4,783 per qtr	$4,469 per qtr

At June 30, 2013, Puget Energy completed a valuation and impairment test of its purchased power contracts classified as intangible assets. The valuation indicated a fair value of $484.1 million with an impairment to the Priest Rapids Reasonable Portion intangible asset contract. As of June 30, 2013, the carrying value for this intangible asset contract was $47.1 million and its fair value on a discounted basis was determined to be an asset of $33.6 million, thereby requiring a write-down of $13.5 million to the intangible asset with a corresponding reduction in the regulatory liability.

Below are significant unobservable inputs used in estimating the impaired long term power purchase contract's fair value on June 30, 2013:

Valuation Technique	Unobservable Input	Low	High	Average
Discounted cash flow	Power prices	$30.85 per MWh	$65.35 per MWh	$48.47 per MWh
Discounted cash flow	Power contract costs (in thousands)	$389 per yr	$6,845 per yr	$4,110 per yr

The valuations were measured using the income approach. Significant inputs included forward electricity prices and power contract pricing which provided future net cash flow estimates which are classified as Level 3 within the fair value hierarchy. A less significant input is the discount rate reflective of PSE's cost of capital used in the valuation.

(11)  Employee Investment Plans

The Company's Investment Plan is a qualified employee 401(k) 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 $14.9 million, $14.6 million and $14.5 million for the years 2014, 2013, and 2012, respectively.  The employee Investment Plan eligibility requirements are set forth in the plan documents.

Non-represented employees and United Association of Journeymen and Apprentices of the Plumbing and Pipefitting Industry (UA) represented employees hired before January 1, 2014, and International Brotherhood of Electrical Workers Local Union 77 (IBEW) represented employees hired before December 12, 2014, have the following company contributions:

• For employees under the Cash Balance retirement plan formula, PSE will match 100% of an employee's contribution up to 6% of plan compensation each paycheck, and will make an additional year-end contribution equal to 1% of base pay. 

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• For employees grandfathered under the Final Average Earning retirement plan formula, PSE will match 55% of an employee’s contribution up to 6% of plan compensation each paycheck.

UA-represented employees hired on or after January 1, 2014 will have access to the 401k Plan. Non-represented employees hired on or after January 1, 2014, and IBEW-represented employees hired on or after December 12, 2014, will have access to the 401(k) plan and will choose how they want to accumulate funds for retirement, with two contribution sources from PSE:

• 401(k) Company Matching: New non-represented, UA-represented and IBEW-represented employees will receive company match each paycheck based on a new schedule-100% match on the first 3% of pay contributed and 50% match on the next 3% of pay contributed. An employee who contributes 6% of pay will receive 4.5% of pay in company match. Company matching will be immediately vested.

• Company Contribution: New UA-represented employees will receive an annual company contribution of 4% of eligible pay placed in the Cash Balance retirement plan. New non-represented and IBEW-represented employees will receive an annual company contribution of 4% of eligible pay, placed either in the Investment Plan 401(k) plan or in PSE’s Retirement Plan (Cash Balance retirement plan). New non-represented and IBEW-represented employees will make a one-time election within 30 days of hire and direct that PSE put the 4% contribution either into the 401(k) plan or into an account in the Cash Balance retirement plan. The Company’s 4% contribution will vest after three years of service. 

(12)  Retirement Benefits

PSE has a defined benefit pension plan covering substantially all PSE employees.  Pension benefits earned are a function of age, salary, years of service and, in the case of employees in the cash balance formula plan, the applicable annual interest crediting rates.  Beginning in 2014, all new UA employees and those new non-represented employees who elect to accumulate the Company contribution in the Cash Balance pension, (effective January 1, 2014) and all new IBEW (effective December 12, 2014), will receive annual pay credits of 4% each year. They will also receive interest credits like other participants in the Cash Balance pension, which are at least 1% per quarter. When a newly-hired employee with a vested Cash Balance benefit leaves PSE, he or she will have annuity and lump sum options for distribution, with annuities calculated according to the Pension Protection Act. Those who select the lump sum option will receive their current cash balance amount. Participation by continuing employees in the Cash Balance pension plan is not affected. PSE also maintains a non-qualified Supplemental Executive Retirement Plan (SERP) for its key senior management employees.

In addition to providing pension benefits, PSE provides group health care and life insurance benefits for certain retired employees.  These benefits are provided principally through an insurance company.  The insurance premiums, paid primarily by retirees, are based on the benefits provided during the year.

The 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 re-measurement of the retirement plans are recorded at Puget Energy.

The following tables summarize the Company’s change in benefit obligation, change in plan assets and amounts recognized in the Statements of Financial Position for the years ended December 31, 2014 and 2013:

Puget Energy and Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2014			2013			2014			2013			2014			2013
Change in benefit obligation:
Benefit obligation at beginning of period	$	573,317		$	616,290		$	47,279		$	51,795		$	14,939		$	17,672
Service cost	17,437			19,285			1,042			1,498			112			134
Interest cost	28,039			24,754			2,310			2,045			684			664
Amendment	—			—			—			478			—			—
Actuarial loss (gain)	104,618			(48,559		)	7,162			(1,687		)	1,108			(2,240		)
Benefits paid	(33,217		)	(38,453		)	(1,938		)	(6,850		)	(1,424		)	(1,536		)
Medicare part D subsidy received	—			—			—			—			269			245
Benefit obligation at end of period	$	690,194		$	573,317		$	55,855		$	47,279		$	15,688		$	14,939

102

Puget Energy and Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2014			2013			2014			2013			2014			2013
Change in plan assets:
Fair value of plan assets at beginning of period	$	615,721		$	531,183		$	—		$	—		$	8,774		$	7,541
Actual return on plan assets	25,669			102,591			—			—			522			1,861
Employer contribution	18,000			20,400			1,938			6,850			488			908
Benefits paid	(33,217		)	(38,453		)	(1,938		)	(6,850		)	(1,424		)	(1,536		)
Fair value of plan assets at end of period	$	626,173		$	615,721		$	—		$	—		$	8,360		$	8,774
Funded status at end of period	$	(64,021	)	$	42,404		$	(55,855	)	$	(47,279	)	$	(7,328	)	$	(6,165	)

Puget Energy and Puget Sound Energy	Qualified Pension Benefits					SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2014			2013		2014			2013			2014			2013
Amounts recognized in Statement of Financial Position consist of:
Noncurrent assets	$	—		$	42,404	$	—		$	—		$	—		$	—
Current liabilities	—			—		(4,386		)	(3,981		)	(355		)	(421		)
Noncurrent liabilities	(64,021		)	—		(51,469		)	(43,298		)	(6,973		)	(5,744		)
Net assets (liabilities)	$	(64,021	)	$	42,404	$	(55,855	)	$	(47,279	)	$	(7,328	)	$	(6,165	)

Puget Energy and Puget Sound Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
(Dollars in Thousands)	2014		2013		2014		2013		2014		2013
Pension Plans with an Accumulated Benefit Obligation in excess of Plan Assets:
Project benefit obligation	$	690,194	$	573,317	$	55,855	$	47,279	$	15,688	$	14,939
Accumulated benefit obligation	681,745		566,689		50,137		40,892		15,553		14,794
Fair value of plan assets	$	626,173	$	615,721	$	—	$	—	$	8,360	$	8,774

The following tables summarize Puget Energy and Puget Sound Energy's pension benefit amounts recognized in Accumulated Other Comprehensive income for the years ended December 31, 2014 and 2013:

Puget Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
(Dollars in Thousands)	2014			2013			2014		2013		2014			2013
Amounts recognized in Accumulated Other Comprehensive Income consist of:
Net loss (gain)	$	55,471		$	(65,943	)	$	15,918	$	9,670	$	(1,457	)	$	(2,972	)
Prior service cost (credit)	(13,782		)	(15,762		)	331		373		—			—
Total	$	41,689		$	(81,705	)	$	16,249	$	10,043	$	(1,457	)	$	(2,972	)

103

Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
(Dollars in Thousands)	2014			2013			2014		2013		2014			2013
Amounts recognized in Accumulated Other Comprehensive Income consist of:
Net loss (gain)	$	247,331		$	138,324		$	19,751	$	14,050	$	(3,733	)	$	(5,556	)
Prior service cost (credit)	(10,952		)	(12,525		)	339		383		3			6
Total	$	236,379		$	125,799		$	20,090	$	14,433	$	(3,730	)	$	(5,550	)

The following tables summarize Puget Energy's and Puget Sound Energy's net periodic benefit cost for the years ended December 31, 2014, 2013 and 2012:

Puget Energy	Qualified Pension Benefits									SERP Pension Benefits							Other Benefits
(Dollars in Thousands)	2014			2013			2012			2014		2013			2012		2014			2013			2012
Components of net periodic benefit cost:
Service cost	$	17,437		$	19,285		$	16,926		$	1,042	$	1,498		$	1,073	$	112		$	134		$	139
Interest cost	28,039			24,754			25,986			2,310		2,045			2,152		684			664			751
Expected return on plan assets	(42,464		)	(39,095		)	(36,203		)	—		—			—		(535		)	(436		)	(435		)
Amortization of prior service cost (credit)	(1,980		)	(1,980		)	(1,980		)	42		(17		)	—		—			—			—
Amortization of net loss	—			2,889			768			913		1,461			702		(393		)	69			53
Net periodic benefit cost	$	1,032		$	5,853		$	5,497		$	4,307	$	4,987		$	3,927	$	(132	)	$	431		$	508

Puget Sound Energy	Qualified Pension Benefits									SERP Pension Benefits							Other Benefits
(Dollars in Thousands)	2014			2013			2012			2014		2013			2012		2014			2013			2012
Components of net periodic benefit cost:
Service cost	$	17,437		$	19,285		$	16,926		$	1,042	$	1,498		$	1,073	$	112		$	134		$	139
Interest cost	28,039			24,753			25,986			2,310		2,045			2,152		684			664			751
Expected return on plan assets	(43,252		)	(40,685		)	(41,533		)	—		—			—		(535		)	(436		)	(435		)
Amortization of prior service cost (credit)	(1,573		)	(1,573		)	(1,573		)	44		(16		)	293		3			30			35
Amortization of net loss(gain)	13,195			20,612			15,015			1,461		2,191			1,432		(702		)	(284		)	(245		)
Amortization of transition obligation	—			—			—			—		—			—		—			—			50
Net periodic benefit cost	$	13,846		$	22,392		$	14,821		$	4,857	$	5,718		$	4,950	$	(438	)	$	108		$	295

104

The following tables summarize Puget Energy's and Puget Sound Energy's benefit obligations recognized in other comprehensive income for the years ended December 31, 2014 and 2013:

Puget Energy	Qualified Pension Benefits					SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2014		2013			2014			2013			2014		2013
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)	$	121,413	$	(112,055	)	$	7,162		$	(1,687	)	$	1,121	$	(3,665	)
Amortization of net loss (gain)	—		(2,889		)	(913		)	(1,461		)	394		(70		)
Prior service credit	—		—			—			478			—		—
Amortization of prior service credit	1,980		1,980			(42		)	17			—		—
Total change in other comprehensive income for year	$	123,393	$	(112,964	)	$	6,207		$	(2,653	)	$	1,515	$	(3,735	)

Puget Sound Energy	Qualified Pension Benefit						SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2014			2013			2014			2013			2014			2013
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)	$	122,202		$	(110,465	)	$	7,162		$	(1,687	)	$	1,121		$	(3,665	)
Amortization of net (loss) gain	(13,195		)	(20,612		)	(1,461		)	(2,191		)	702			284
Prior service cost (credit)	—			—			—			477			—			—
Amortization of prior service cost (credit)	1,573			1,573			(44		)	16			(3		)	(30		)
Amortization of transition obligation	—			—			—			—			—			—
Total change in other comprehensive income for year	$	110,580		$	(129,504	)	$	5,657		$	(3,385	)	$	1,820		$	(3,411	)

The estimated prior service cost (credit) for the pension plans that will be amortized from accumulated OCI into net periodic benefit cost in 2015 by Puget Energy is $3.9 million.  The estimated net (loss) gain for the SERP that will be amortized from accumulated OCI into net periodic benefit cost in 2015 is $1.6 million. The estimated prior service cost (credit) for the SERP that will be amortized from accumulated OCI into net periodic benefit cost in 2015 is immaterial.  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 2015 are immaterial.

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 2015 by Puget Sound Energy are $20.5 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 2015 are $2.1 million. The estimated prior service cost (credit) for the SERP that will be amortized from accumulated OCI into net periodic benefit cost in 2015 is immaterial.  The estimated net (loss) gain for the other postretirement plan that will be amortized from accumulated OCI into net periodic benefit cost in 2015 is $0.3 million and prior service cost (credit) and transition (obligation) asset for the other postretirement plans are immaterial.

The aggregate expected contributions by the Company to fund the qualified pension plan, SERP and the other postretirement plans for the year ending December 31, 2015 are expected to be at least $18.0 million, $4.4 million and $0.5 million, respectively.

105

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	2014		2013		2012		2014		2013		2012		2014		2013		2012
Discount rate 1	4.25	%	5.10	%	4.15	%	4.25	%	5.10	%	4.15	%	4.25	%	5.10	%	4.15	%
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	—		—		—		—		—		—		5.70	%	6.80	%	7.50	%
Benefit Cost Assumptions
Discount rate	5.10	%	4.15	%	4.75	%	5.10	%	4.15	%	4.75	%	5.10	%	4.15	%	4.75	%
Rate of plan assets	7.75	%	7.75	%	7.75	%	—		—		—		7.00	%	6.90	%	7.50	%
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	—		—		—		—		—		—		6.70	%	8.20	%	7.50	%

_______________

¹  The Company calculates the present value of the pension liability using a discount rate of 4.25% which represents the single-rate equivalent of the AA rated corporate bond yield curve.

The assumed medical inflation rate used to determine benefit obligations is 6.70% in 2015 grading down to 4.30% in 2016.  A 1.0% change in the assumed medical inflation rate would have the following effects:

	2014					2013
(Dollars in Thousands)	1% Increase		1% Decrease			1% Increase		1% Decrease
Effect on post-retirement benefit obligation	$	47	$	(47	)	$	66	$	(66	)
Effect on service and interest cost components	2		(2		)	3		(3		)

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.

106

Plan Benefits

The expected total benefits to be paid under the next five years and the aggregate total to be paid for the five years thereafter are as follows:

(Dollars in Thousands)	2015		2016		2017		2018		2019		2020-2024
Qualified Pension total benefits	$	41,100	$	41,400	$	42,100	$	43,300	$	43,900	$	237,300
SERP Pension total benefits	$	4,386	$	2,595	1,940		5,346		5,811		18,759
Other Benefits total with Medicare Part D subsidy	$	1,080	$	1,136	$	1,113	$	1,085	$	1,062	$	5,935
Other Benefits total without Medicare Part D subsidy	$	1,429	$	1,414	$	1,398	$	1,380	$	1,362	$	6,340

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%	31%	40%
Domestic small cap equity	0%	9%	15%
Non-U.S. equity	10%	25%	30%
Fixed income	15%	25%	30%
Real estate	0%	0%	10%
Absolute return	5%	10%	15%
Cash	0%	0%	5%

Plan Fair Value Measurements

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.

ASC 820 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.

107

The following table sets forth by level, within the fair value hierarchy, the qualified pension plan as of December 31, 2014 and 2013:

	Recurring Fair Value Measures								Recurring Fair Value Measures
	As of December 31, 2014								As of December 31, 2013
(Dollars in Thousands)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets:
Equities:
Non-US equity 1	$	71,026	$	74,131	$	—	$	145,157	$	76,188	$	78,816	$	—	$	155,004
Domestic large cap equity 2	134,765		68,336		—		203,101		157,874		35,851		—		193,725
Domestic small cap equity 3	59,657		—		—		59,657		62,867		—		—		62,867
Total equities	265,448		142,467		—		407,915		296,929		114,667		—		411,596
Tactical asset allocation 4	—		—		—		—		—		—		—		—
Fixed income securities 5	72,331		67,182		—		139,513		135,007		—		—		135,007
Absolute return 6	—		—		65,251		65,251		—		—		62,278		62,278
Cash and cash equivalents 7	12,650		—		—		12,650		—		7,054		—		7,054
Subtotal	$	350,429	$	209,649	$	65,251	$	625,329	$	431,936	$	121,721	$	62,278	$	615,935
Net (payable) receivable	—		—		—		844		—		—		—		(417		)
Accrued income	—		—		—		—		—		—		—		203
Total assets							$	626,173							$	615,721

_________________

¹  Non – US Equity investments are comprised of a (1) mutual fund; and a (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, 2014.  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, 2014.

2 Domestic large cap equity investments are comprised of (1) common stock, and a (2) commingled fund.  Investments in common stock are valued using quoted market prices multiplied by the number of shares owned as of December 31, 2014.  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, 2014.

3 Domestic small cap equity investments are comprised of (1) common stock and a (2) mutual fund. The investments in common stock are valued using quoted market prices multiplied by the number of shares owned as of December 31, 2014. The investment in the mutual fund is valued using quoted market prices multiplied by the number of shares owned as of December 31, 2014.

4 The tactical asset allocation investment is comprised 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.  The investment in the mutual fund is valued using quoted market prices multiplied by the number of shares owned as of December 31, 2014.

6 As of December 31, 2014 absolute return investments consist of two partnerships.  The partnerships are valued using the financial reports as of December 31, 2014.  These investments are a Level 3 under ASC 820 because the significant valuation inputs are primarily internal to the partnerships with little third party involvement.

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, 2014.  The money market fund invests primarily in commercial paper, notes, repurchase agreements, and other evidences of indebtedness which are payable on demand or short-term in nature. 

Level 3 Roll-Forward

The following table sets forth a reconciliation of changes in the fair value of the plan’s Level 3 assets:

	As of December 31, 2014						As of December 31, 2013
(Dollars in Thousands)	Partnership		Mutual Funds		Total		Partnership		Mutual Funds		Total
Balance at beginning of year	$	62,278	$	—	$	62,278	$	55,614	$	—	$	55,614
Additional investments	—		—		—		—		—		—
Distributions	—		—		—		—		—		—
Realized losses on distributions	—		—		—		—		—		—
Unrealized gains relating to instruments still held at the reporting date	2,973		—		2,973		6,664		—		6,664
Transferred out of level 3 1	—		—		—		—		—		—
Balance at end of year	$	65,251	$	—	$	65,251	$	62,278	$	—	$	62,278

_________________

¹  The plan had no transfers between level 2 and level 1 during the years ended December 31, 2014 or 2013.

108

The following table sets forth by level, within the fair value hierarchy, the Other Benefits plan assets which consist of insurance benefits for retired employees, at fair value:

	Recurring Fair Value Measures						Recurring Fair Value Measures
	As of December 31, 2014						As of December 31, 2013
(Dollars in Thousands)	Level 1		Level 2		Total		Level 1		Level 2		Total
Assets:
Mutual fund 1	$	8,301	$	—	$	8,301	$	8,703	$	—	$	8,703
Cash equivalents 2	59		—		59		—		71		71
Total assets	$	8,360	$	—	$	8,360	$	8,703	$	71	$	8,774

_______________

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, 2014.

²  This is a money market fund.  The money market fund investments are valued at the net asset value per share of $1.00 per unit as of December 31, 2014.  The money market fund invests primarily in commercial paper, notes, repurchase agreements, and other evidences of indebtedness which are payable on demand or short-term in nature. 

(13)  Income Taxes

The details of income tax (benefit) expense are as follows:

Puget Energy	Year Ended December 31,
(Dollars in Thousands)	2014			2013			2012
Charged to operating expenses:
Current:
Federal	$	—		$	—		$	4,268
State	—			—			—
Deferred:
Federal	57,152			122,559			100,701
State	(167		)	(151		)	(244		)
Total income tax expense	$	56,985		$	122,408		$	104,725

Puget Sound Energy	Year Ended December 31,
(Dollars in Thousands)	2014		2013		2012
Charged to operating expenses:
Current:
Federal	$	—	$	—	$	4,268
State	—		—		—
Deferred:
Federal	89,342		160,886		145,040
State	—		—		—
Total income tax expense	$	89,342	$	160,886	$	149,308

109

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:

Puget Energy	Year Ended December 31,
(Dollars in Thousands)	2014			2013			2012
Income taxes at the statutory rate	$	80,087		$	142,847		$	132,491
Increase (decrease):
Production tax credit	(23,073		)	(22,414		)	(22,188		)
AFUDC excluded from taxable income	(3,790		)	(9,406		)	(16,543		)
Capitalized interest	2,947			7,294			9,757
Utility plant differences	7,090			9,527			8,674
Treasury grant amortization	(8,808		)	(7,651		)	(1,007		)
Tenaska gas contract	—			1			(4,687		)
Other - net	2,532			2,210			(1,772		)
Total income tax expense	$	56,985		$	122,408		$	104,725
Effective tax rate	24.9		%	30.0		%	27.7		%

Puget Sound Energy	Year Ended December 31,
(Dollars in Thousands)	2014			2013			2012
Income taxes at the statutory rate	$	114,084		$	180,955		$	176,917
Increase (decrease):
Production tax credit	(23,073		)	(22,414		)	(22,188		)
AFUDC excluded from taxable income	(3,790		)	(9,406		)	(16,543		)
Capitalized interest	2,947			7,294			9,757
Utility plant differences	7,090			9,527			8,674
Treasury grant amortization	(8,808		)	(7,651		)	(1,007		)
Tenaska gas contract	—			1			(4,687		)
Other - net	892			2,580			(1,615		)
Total income tax expense	$	89,342		$	160,886		$	149,308
Effective tax rate	27.4		%	31.1		%	29.5		%

The Company’s deferred tax liability at December 31, 2014 and 2013 is composed of amounts related to the following types of temporary differences:

Puget Energy	At December 31,
(Dollars in Thousands)	2014			2013
Utility plant and equipment	$	1,720,730		$	1,625,107
Regulatory asset for income taxes	95,432			146,867
Fair value of debt instruments	73,606			76,991
Other deferred tax liabilities	200,124			202,189
Subtotal deferred tax liabilities	2,089,892			2,051,154
Net operating loss carryforward	(417,684		)	(374,606		)
Production tax credit carryforward	(158,604		)	(135,531		)
Regulatory liability on production tax credit	(84,344		)	(71,880		)
Fair value of derivative instruments	(36,227		)	(7,166		)
Other deferred tax assets	(32,121		)	(60,970		)
Subtotal deferred tax assets	(728,980		)	(650,153		)
Total	$	1,360,912		$	1,401,001

110

Puget Sound Energy	At December 31,
(Dollars In Thousands)	2014			2013
Utility plant and equipment	$	1,720,730		$	1,625,107
Regulatory asset for income taxes	94,913			146,350
Other deferred tax liabilities	171,380			131,977
Subtotal deferred tax liabilities	1,987,023			1,903,434
Net operating loss carryforward	(181,514		)	(173,068		)
Production tax credit carryforward	(158,604		)	(135,531		)
Regulatory liability on production tax credit	(84,344		)	(71,880		)
Fair value of derivative instruments	(39,067		)	(9,988		)
Other deferred tax assets	(82,084		)	(69,175		)
Subtotal deferred tax assets	(545,613		)	(459,642		)
Total	$	1,441,410		$	1,443,792

The above amounts have been classified in the Consolidated Balance Sheets as follows:

Puget Energy	At December 31
(Dollars in Thousands)	2014			2013
Current deferred taxes	$	(161,445	)	$	(86,004	)
Non-current deferred taxes	1,522,357			1,487,005
Total	$	1,360,912		$	1,401,001

Puget Sound Energy	At December 31
(Dollars in Thousands)	2014			2013
Current deferred taxes	$	(208,447	)	$	(141,058	)
Non-current deferred taxes	1,649,857			1,584,850
Total	$	1,441,410		$	1,443,792

The Company calculates its deferred tax assets and liabilities under ASC 740, “Income Taxes” (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 future years.  ASC 740 requires a valuation allowance on deferred tax assets when it is more likely than not that the deferred tax assets will not be realized.  The Company’s PTC carryforwards expire from 2026 through 2034.  The Company’s net operating loss carryforwards expire from 2029 through 2034.

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 challenge by the taxing authorities and taken by management to the court of last resort.  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, 2014 and 2013, 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 2010 through 2014.  The Company classifies interest as interest expense and penalties as other expense in the financial statements.

111

(14)  Litigation

Colstrip

PSE has a 50% ownership interest in Colstrip Units 1 and 2, and a 25% interest in Colstrip Units 3 and 4. On March 6, 2013, Sierra Club and Montana Environmental Information Center (MEIC) filed a Clean Air Act citizen suit against all Colstrip owners (including PSE) alleging numerous claims for relief, most of which relate to alleged prevention of significant deterioration (PSD) violations. One claim relates to the alleged failure to update the Title V permit to reflect the major modifications alleged in the first thirty-six claim, another claim alleges that the previous Title V compliance certifications have been incomplete because they did not address the alleged major modifications, and the last claim alleges opacity violations since 2007. The lawsuit was filed in U.S. District of Montana, Billings Division, requesting injunctive relief and civil penalties, including a request that the owners remediate environmental damage and that $100,000 of the civil penalties be used for beneficial mitigation projects.  Discovery in the case is ongoing, and it has been bifurcated into separate liability and remedy trials. The liability trial is currently set for November 2015, and a date for the remedy trial has yet to be determined. PSE is litigating the allegations set forth in the notices, and as such, it is not reasonably possible to estimate the outcome of this matter.  

Other Proceedings

The Company is also involved in litigation relating to claims arising out of its operations in the normal course of business.  The Company has recorded reserves of $1.7 million and $1.4 million relating to these claims as of December 31, 2014 and 2013, respectively.

(15)  Commitments and Contingencies

For the year ended December 31, 2014, approximately 14.9% of the Company’s energy output was obtained at an average cost of approximately $0.021 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 Company's expenses under these PUD contracts were as follows for the years ended December 31:

(Dollars in Thousands)	2014		2013		2012
PUD contract costs	$	69,661	$	63,365	$	70,188

112

As of December 31, 2014, the Company purchased portions of the power output of the PUDs' projects as set forth in the following table:

		Company's Current Share of
(Dollars in Thousands)	Contract Expiration	Percent of Output		Megawatt Capacity	Estimated 2015 Costs		2015 Debt Service Costs		Interest included in 2015 Debt Service Costs		Debt Outstanding
Chelan County PUD:
Rock Island Project	2031	25.0	%	156	$	29,854	$	11,009	$	6,174	$	98,191
Rocky Reach Project	2031	25.0	%	325	27,583		8,245		3,343		53,299
Douglas County PUD:
Wells Project	2018	29.9	%	251	17,277		9,383		2,597		64,931
Grant County PUD:
Priest Rapids Development	2052	0.6	%	8	3,689		2,087		1,245		19,828
Wanapum Development	2052	0.6	%	9	3,689		2,087		1,245		19,828
Total				749	$	82,092	$	32,811	$	14,604	$	256,077

The following table summarizes the Company’s estimated payment obligations for power purchases from the Columbia River projects, contracts with other utilities and contracts with non-utilities.  These contracts have varying terms and may include escalation and termination provisions.

(Dollars in Thousands)	2015		2016		2017		2018		2019		Thereafter		Total
Columbia River projects	$	73,023	$	75,360	$	74,851	$	65,981	$	53,837	$	644,666	$	987,718
Other utilities	16,136		18,884		11,823		1,257		890		—		48,990
Non-utility contracts	117,372		153,863		199,056		204,292		209,699		1,354,191		2,238,473
Total	$	206,531	$	248,107	$	285,730	$	271,530	$	264,426	$	1,998,857	$	3,275,181

Total purchased power contracts provided the Company with approximately 12.1 million, 10.7 million and 6.1 million MWhs of firm energy at a cost of approximately $401.4 million, $348.7 million and $203.1 million for the years 2014, 2013 and 2012, respectively.

The Company has natural gas-fired generation facility obligations for natural gas supply amounting to an estimated $63.6 million in 2015.  Longer term agreements for natural gas supply amount to an estimated $286.7 million for 2016 through 2019.

PSE enters into short-term energy supply contracts to meet its core customer needs.  These contracts are sometimes classified as NPNS, however in most cases recorded at fair value in accordance with ASC 815.  Commitments under these contracts are $105.8 million, $32.4 million and $6.5 million in 2015, 2016 and 2017, 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.  The transportation and storage contracts, which have remaining terms from less than one year to 30 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 2014 for firm transportation service and firm storage and peaking service of $155.0 million and $6.6 million, respectively.  The demand charge for firm natural gas supply was immaterial in 2014. The Company incurred demand charges in 2014 for firm transportation and firm storage service for the natural gas supply for its combustion turbines in the amount of $35.7 million, which is included in the total Company demand charges.

113

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 the FERC and NEB (National Energy Board) currently authorized rates, which are subject to change. 

Demand Charge Obligations (Dollars in Thousands)	2015		2016		2017		2018		2019		Thereafter		Total
Firm transportation service	$	154,121	$	147,424	$	144,751	$	131,484	$	112,249	$	373,958	$	1,063,987
Firm storage service	6,528		5,337		5,209		1,407		1,535		1,258		21,274
Total	$	160,649	$	152,761	$	149,960	$	132,891	$	113,784	$	375,216	$	1,085,261

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)	2015		2016		2017		2018		2019		Thereafter		Total
Energy production service contracts	$	32,979	$	15,650	$	5,558	$	4,064	$	2,372	$	23,443	$	84,066
Automated meter reading system	25,402		16,081		13,362		13,996		14,602		51,986		135,429
Total	$	58,381	$	31,731	$	18,920	$	18,060	$	16,974	$	75,429	$	219,495

Other Contingencies

For information regarding PSE's environmental remediation obligations, see Note 3 Regulation and Rates.

(16)  Related Party Transactions

On October 10, 2014, U.S. Bancorp announced the appointment of Kimberly Harris to its board of directors effective October 20, 2014.  Ms. Harris is the president and chief executive officer of both Puget Energy and PSE.  U.S. Bancorp is the parent company of U.S. Bank N.A., which directly or through its subsidiaries or affiliates provides credit, banking, investment and trust services to both Puget Energy and PSE.  For the year ended December 31, 2014, Puget Energy and PSE paid a total of approximately $1.0 million in fees and interest to U.S. Bank N.A. and its subsidiaries or affiliates.

In 2006, PSE entered into a revolving credit facility with Puget Energy in the form of a Demand Promissory Note (Note).  At December 31, 2014 and 2013, the outstanding balance of the Note was $28.9 million and $29.6 million, respectively, and the interest rate was 0.391% and 0.325%, respectively. (See Note 7).

(17)  Segment Information

Puget Energy operates one reportable business segment referred to as the regulated utility segment.  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. In managing the business, management reviews the consolidated financial statements for Puget Energy and PSE during the year.

114

(18) Accumulated Other Comprehensive Income (Loss)

The following tables present the changes in the Company’s accumulated other comprehensive income (loss) (AOCI) by component for the years ended December 31, 2014, 2013 and 2012, respectively.

Puget Energy	Net unrealized gain (loss) and prior service cost on pension plans			Net unrealized gain (loss) on energy derivative instruments			Net unrealized gain (loss) on interest rate swaps
Changes in AOCI, net of tax
(Dollars in Thousands)										Total
Balance at December 31, 2011	$	(15,195	)	$	(1,113	)	$	(14,599	)	$	(30,907	)
Other comprehensive income (loss) before reclassifications	(13,574		)	—			—			(13,574		)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	(296		)	371			11,577			11,652
Net current-period other comprehensive income (loss)	(13,870		)	371			11,577			(1,922		)
Balance at December 31, 2012	$	(29,065	)	$	(742	)	$	(3,022	)	$	(32,829	)
Other comprehensive income (loss) before reclassifications	76,004			—			—			76,004
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	1,575			37			2,928			4,540
Net current-period other comprehensive income (loss)	77,579			37			2,928			80,544
Balance at December 31, 2013	$	48,514		$	(705	)	$	(94	)	$	47,715
Other comprehensive income (loss) before reclassifications	(84,301		)	—			—			(84,301		)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	(923		)	372			94			(457		)
Net current-period other comprehensive income (loss)	(85,224		)	372			94			(84,758		)
Balance at December 31, 2014	$	(36,710	)	$	(333	)	$	—		$	(37,043	)

115

Puget Sound Energy	Net unrealized gain (loss) and prior service cost on pension plans			Net unrealized gain (loss) on energy derivative instruments			Net unrealized gain (loss) on treasury interest rate swaps
Changes in AOCI, net of tax
(Dollars in Thousands)										Total
Balance at December 31, 2011	$	(168,704	)	$	(12,934	)	$	(6,941	)	$	(188,579	)
Other comprehensive income (loss) before reclassifications	(17,049		)	—			—			(17,049		)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	9,755			8,358			317			18,430
Net current-period other comprehensive income (loss)	(7,294		)	8,358			317			1,381
Balance at December 31, 2012	$	(175,998	)	$	(4,576	)	$	(6,624	)	$	(187,198	)
Other comprehensive income (loss) before reclassifications	74,969			—			—			74,969
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	13,624			2,549			317			16,490
Net current-period other comprehensive income (loss)	88,593			2,549			317			91,459
Balance at December 31, 2013	$	(87,405	)	$	(2,027	)	$	(6,307	)	$	(95,739	)
Other comprehensive income (loss) before reclassifications	(84,955		)	—			—			(84,955		)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	8,079			1,341			317			9,737
Net current-period other comprehensive income (loss)	(76,876		)	1,341			317			(75,218		)
Balance at December 31, 2014	$	(164,281	)	$	(686	)	$	(5,990	)	$	(170,957	)

116

Details about these reclassifications out of accumulated other comprehensive income (loss) for the years ended December 31, 2014, 2013 and 2012, respectively, are as follows:

Puget Energy
(Dollars in Thousands)
Details about accumulated other comprehensive income (loss) components	Affected line item in the statement where net income (loss) is presented	Amount reclassified from accumulated other comprehensive income (loss)
		2014			2013			2012
Net unrealized gain (loss) and prior service cost on pension plans:
Amortization of prior service cost	(a)	1,938			1,997			1,980
Amortization of net gain (loss)	(a)	(519		)	(4,420		)	(1,524		)
	Total before tax	1,419			(2,423		)	456
	Tax (expense) or benefit	(496		)	848			(160		)
	Net of Tax	$	923		$	(1,575	)	$	296
Net unrealized gain (loss) on energy derivative instruments:
Commodity contracts: Electric derivatives	Electric generation fuel	—			—			100
	Purchased electricity	(572		)	(57		)	(671		)
	Total before tax	(572		)	(57		)	(571		)
	Tax (expense) or benefit	200			20			200
	Net of Tax	$	(372	)	$	(37	)	$	(371	)
Net unrealized gain (loss) on interest rate swaps:
Interest rate contracts	Interest expense	$	(144	)	$	(4,505	)	$	(17,811	)
	Tax (expense) or benefit	50			1,577			6,234
	Net of Tax	$	(94	)	$	(2,928	)	$	(11,577	)
Total reclassification for the period	Net of Tax	$	457		$	(4,540	)	$	(11,652	)

__________

^(a)  These accumulated other comprehensive income components are included in the computation of net periodic pension cost (see Note 12 for additional details).

117

Puget Sound Energy
(Dollars in Thousands)
Details about accumulated other comprehensive income (loss) components	Affected line item in the statement where net income (loss) is presented	Amount reclassified from accumulated other comprehensive income (loss)
		2014			2013			2012
Net unrealized gain (loss) and prior service cost on pension plans:
Amortization of prior service cost	(a)	$	1,526		$	1,559		$	1,245
Amortization of net gain (loss)	(a)	(13,954		)	(22,519		)	(16,203		)
Amortization of transition obligation	(a)	—			—			(50		)
	Total before tax	(12,428		)	(20,960		)	(15,008		)
	Tax (expense) or benefit	4,349			7,336			5,253
	Net of tax	$	(8,079	)	$	(13,624	)	$	(9,755	)
Net unrealized gain (loss) on energy derivative instruments:
Commodity contracts: Electric derivatives	Electric generation fuel	—			—			97
	Purchased electricity	(2,063		)	(3,922		)	(12,955		)
	Total before tax	(2,063		)	(3,922		)	(12,858		)
	Tax (expense) or benefit	722			1,373			4,500
	Net of Tax	$	(1,341	)	$	(2,549	)	$	(8,358	)
Net unrealized gain (loss) on treasury interest rate swaps:
Interest rate contracts	Interest expense	(488		)	(488		)	(488		)
	Tax (expense) or benefit	171			171			171
	Net of Tax	$	(317	)	$	(317	)	$	(317	)
Total reclassification for the period	Net of Tax	$	(9,737	)	$	(16,490	)	$	(18,430	)

__________

^(a) These accumulated other comprehensive income components are included in the computation of net periodic pension cost (see Note 12 for additional details).

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	2014 Quarter
(Unaudited; Dollars in Thousands)	First		Second		Third			Fourth
Operating revenue	$	1,025,375	$	662,916	$	593,715		$	831,165
Operating income	236,301		145,266		65,069			131,215
Net income (loss)	107,592		41,113		(12,958		)	36,088

	2013 Quarter
(Unaudited; Dollars in Thousands)	First		Second		Third		Fourth
Operating revenue	$	999,818	$	642,486	$	598,348	$	946,645
Operating income	317,735		95,081		100,043		242,301
Net income (loss)	167,475		905		8,540		108,808

118

Puget Sound Energy	2014 Quarter
(Unaudited; Dollars in Thousands)	First		Second		Third		Fourth
Operating revenue	$	1,025,375	$	662,916	$	593,951	$	833,881
Operating income	232,977		142,185		62,317		131,214
Net income (loss)	121,083		57,834		3,057		54,640

	2013 Quarter
(Unaudited; Dollars in Thousands)	First		Second		Third		Fourth
Operating revenue	$	999,707	$	642,486	$	598,348	$	946,794
Operating income	310,587		91,094		96,085		237,808
Net income (loss)	179,938		26,663		26,605		122,923

SCHEDULE I:  CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY

Puget Energy

Condensed Statements of Income and Comprehensive Income (Loss)

(Dollars in Thousands)

	Year Ended December 31,
	2014			2013			2012
Non-utility expense and other	$	(5,390	)	$	(1,255	)	$	(2,040	)
Other income (deductions):
Equity in earnings of subsidiary (Note 1)	240,102			351,718			365,590
Unhedged interest rate swap expense	(3,915		)	2,420			(4,288		)
Interest income	185			114			214
Interest expense	(93,382		)	(103,372		)	(135,312		)
Income taxes	34,235			36,103			49,657
Net income (loss)	171,835			285,728			273,821
Comprehensive income (loss)	$	87,077		$	366,272		$	271,899

See accompanying notes to the consolidated financial statements.

119

Puget Energy

Condensed Balance Sheets

(Dollars in Thousands)

	December 31,
	2014		2013
Assets:
Investment in subsidiaries	$	3,337,718	$	3,508,460
Other property and investments:
Goodwill	1,656,513		1,656,513
Current assets:
Cash	62		191
Receivables from affiliates 1	28,950		29,605
Total current assets	29,012		29,796
Long-term assets:
Deferred income taxes	267,810		241,787
Other	15,802		17,992
Total long-term assets	283,612		259,779
Total assets	$	5,306,855	$	5,454,548
Capitalization and liabilities:
Common equity	$	3,543,328	$	3,679,679
Long-term debt	1,698,968		1,698,964
Total capitalization	5,242,296		5,378,643
Current liabilities:
Account Payable	130		322
Interest	23,585		24,047
Deferred income taxes	31,772		38,296
Unrealized loss on derivative instruments	6,222		6,584
Total current liabilities	61,709		69,249
Long-term liabilities:
Unrealized loss on derivative instruments	2,850		6,656
Total long-term liabilities	2,850		6,656
Commitments and contingencies (Note 3)
Total capitalization and liabilities	$	5,306,855	$	5,454,548

_______________

¹  Eliminated in consolidation.

See accompanying notes to the consolidated financial statements.

120

Puget Energy

Condensed Statements of Cash Flows

(Dollars in Thousands)

	Year Ended December 31,
	2014			2013			2012
Operating activities:
Net income (loss)	$	171,835		$	285,728		$	273,821
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Unrealized gain on derivative instruments	(4,024		)	(3,869		)	(12,984		)
Deferred income taxes and tax credits - net	(32,597		)	(35,872		)	(49,496		)
Equity in earnings of subsidiary	(240,102		)	(351,718		)	(365,590		)
Other	4,758			3,055			11,409
Dividends received from subsidiary	323,424			410,977			175,625
Accounts receivable	(10		)	3			283
Accounts payable	(192		)	110			212
Accrued interest	2,367			(1,299		)	33,842
Net cash provided by (used in) operating activities	225,459			307,115			67,122
Investing activities:
(Increase) decrease in loan to subsidiary	665			—			400
Other	(2,829		)	(1,120		)	(20,901		)
Net cash provided by (used in) investing activities	(2,164		)	(1,120		)	(20,501		)
Financing activities:
Dividends paid	(223,428		)	(170,821		)	(88,594		)
Issuance of bond	—			—			884,000
Redemption of term-loan and other long-term debt	—			(135,000		)	(843,000		)
Issue costs and others	4			5			(5,239		)
Net cash provided by (used in) by financing activities	(223,424		)	(305,816		)	(52,833		)
Increase (decrease) in cash	(129		)	179			(6,212		)
Cash at beginning of year	191			12			6,224
Cash at end of year	$	62		$	191		$	12

See accompanying notes to the consolidated financial statements.

121

NOTES TO CONDENSED FINANCIAL STATEMENTS

(1) Basis of Presentation

Puget Energy is an energy services holding company that conducts substantially all of its business operations through its subsidiary. These condensed financial statements and related footnotes have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X. These financial statements, in which Puget Energy’s subsidiary has been included using the equity method, should be read in conjunction with the consolidated financial statements and notes thereto of Puget Energy included in Part II, Item 8 of this Form 10-K. Puget Energy owns 100% of the common stock of its subsidiary.

Equity earnings of subsidiary included earnings from PSE of $236.6 million, $356.1 million and $356.2 million for the years ended December 31, 2014, 2013 and 2012, respectively, and business combination accounting adjustments under ASC 805 recorded at Puget Energy for PSE of $3.5 million, $(4.4) million and $9.4 million for the years ended December 31, 2014, 2013 and 2012, respectively. Investment in subsidiaries includes Puget Energy business combination accounting adjustments under ASC 805 that are recorded at Puget Energy.

(2) Debt

For information concerning Puget Energy’s long-term debt obligations, see Note 6, Long-Term Debt, to the consolidated financial statements of Puget Energy.

(3) Commitments and Contingencies

For information concerning Puget Energy’s material contingencies and guarantees, see Note 15, Commitments and Contingencies, to the consolidated financial statements of Puget Energy.

122

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, 2014
Accounts deducted from assets on balance sheet:
Allowance for doubtful accounts receivable	$	7,385	$	27,228	$	27,141	$	7,472
Year Ended December 31, 2013
Accounts deducted from assets on balance sheet:
Allowance for doubtful accounts receivable	$	9,932	$	26,330	$	28,877	$	7,385
Year Ended December 31, 2012
Accounts deducted from assets on balance sheet:
Allowance for doubtful accounts receivable	$	8,495	$	21,567	$	20,130	$	9,932

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, 2014
Accounts deducted from assets on balance sheet:
Allowance for doubtful accounts receivable	$	7,385	$	27,228	$	27,141	$	7,472
Year Ended December 31, 2013
Accounts deducted from assets on balance sheet:
Allowance for doubtful accounts receivable	$	9,932	$	26,330	$	28,877	$	7,385
Year Ended December 31, 2012
Accounts deducted from assets on balance sheet:
Allowance for doubtful accounts receivable	$	8,495	$	21,567	$	20,130	$	9,932

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

PugetEnergy

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, 2014, 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.

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Changes in Internal Control Over Financial Reporting

There have been no changes in Puget Energy’s internal control over financial reporting during the year ended December 31, 2014 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 (2013) 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, 2014.

Puget Energy’s effectiveness of internal control over financial reporting as of December 31, 2014 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, 2014, 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 year ended December 31, 2014 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 (2013) 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, 2014.

PSE’s effectiveness of internal control over financial reporting as of December 31, 2014 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

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Board of Directors

As of February 27, 2015, twelve directors constitute Puget Energy’s Board of Directors and thirteen 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.

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Andrew Chapman, age 59, has been a director on the boards of both Puget Energy and PSE since February 2009.  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 served as a director on the boards of Duquesne Light Holdings, Inc. and Duquesne Light Company from 2009 to 2013. Mr. Chapman represents the Company’s Macquarie affiliated investors on the boards, in accordance with the terms of the Puget Energy and PSE bylaws, and brings to his service many years of experience in the operational and financial management challenges specific to regulated utilities.

Melanie Dressel, age 62, is a director on the boards of both Puget Energy and PSE, which positions she has held since December 2011.  Ms. Dressel is currently President and Chief Executive Officer of Columbia Bank and its parent company, Columbia Banking System, Inc., of Tacoma, Washington, which positions she has held since 2000 and 2003, respectively.  An independent director not affiliated with any of the Company’s investors, Ms. Dressel’s leadership skills, financial experience and many ties to civic and community groups in the Company’s service territory are among the reasons for her appointment to the Puget Energy and PSE boards.

Daniel Fetter, age 38, is a director on the boards of both Puget Energy and PSE, which positions he has held since August 2, 2012. Mr. Fetter is currently the Senior Principal, Private Infrastructure with Canada Pension Plan Investment Board (CPPIB), which position he has held since 2009. Prior to that, Mr. Fetter served as both a Principal (from 2007 to 2009) and Associate (from 2006 to 2007) at CPP Investment Board. Mr. Fetter serves on the boards of Puget Energy and PSE as a representative of CPPIB's ownership interests, pursuant to the terms of the Puget Energy and PSE bylaws, and brings to this service his skills in financial management of infrastructure providers.

Kimberly Harris, age 50, 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 through 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. Ms. Harris is currently on the board of directors of U.S. Bancorp, a bank holding company.

Benjamin Hawkins, age 40, has been a director on the boards of both Puget Energy and PSE since May 21, 2010.  Mr. Hawkins is currently a Director of Infrastructure & Timber Investments for Alberta Investment Management Corporation (AimCo), which position he has held since 2012.  Mr. Hawkins also served as Principal of Infrastructure Investments of AimCo from November 2008 until June 2011, and Portfolio Manager of Infrastructure Investments from May of 2007 until November 2008.  Prior to joining AimCo, Mr. Hawkins held various positions with EPCOR Utilities, a Canadian power and water utility company.  Mr. Hawkins serves on the boards as a representative of AimCo’s ownership interest in the Company, pursuant to the terms of the Puget Energy and PSE bylaws, and brings to this service his skills in financial oversight of utilities.

Steven W. Hooper, age 61, is a director on the boards of both Puget Energy and Puget Sound Energy, which positions he has held since January 2015.  Mr. Hooper is currently co-founder and partner of Ignition Partners, a venture capital firm that focuses on technology based in Bellevue, Washington, which position he has held since 2000.   Previously, Mr. Hooper was the co-CEO of Teledesic (1998-2000) and CEO of Nextlink (1997-1998) and AT&T Wireless (1994-1997).  Mr. Hooper also currently serves on the boards of directors of Recreational Equipment, Inc. (REI) and Blucora, Inc.   An independent director not affiliated with any of the Company’s investors, Mr. Hooper’s leadership skills, experience with the challenges facing regulated businesses, and involvement with regional educational and civic organizations are some of the reasons that led to his appointment to the Puget Energy and PSE boards.

Alan James, age 61, has been a director on the boards of both Puget Energy and PSE since February 2009, as a representative of the Company’s Macquarie affiliated investors consistent with the Puget Energy and PSE bylaws.  Mr. James is currently the Chairman and Senior Managing Director of Macquarie Capital (USA) Inc. based in New York where he specializes in providing M&A advice and capital raising solutions to the utility, power and renewable sectors in North America, 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 and held various positions with Deutsche Bank AG in Australia and Europe from 1993 to 2002 specializing in the energy sector.  Mr. James provides the boards the benefit of his broad experience with the financial needs and operational and regulatory challenges of infrastructure providers.

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Christopher Leslie, age 50, has been a director on the boards of both Puget Energy and PSE since February 2009, as a representative of the Company’s Macquarie affiliated investors consistent with the Puget Energy and PSE bylaws.  Mr. Leslie is currently an Executive Director of Macquarie Group Limited, which position he has held since 2005, President of Macquarie Infrastructure and Real Assets Inc., and since 2006 Chief Executive Officer of Macquarie Infrastructure Partners Inc.  Mr. Leslie served as a director on the boards of Duquesne Light Holdings, Inc. and Duquesne Light Company in 2009 and 2010.  In addition to his management and banking skills, Mr. Leslie provides the Puget Energy and PSE boards the benefit of his experience with electric utilities, gas distribution systems and other aspects of the infrastructure sector.

David MacMillan, age 62, has been a director on the boards of both Puget Energy and PSE since November 6, 2012. Mr. MacMillan currently is a non-executive director of Viridian Group Ltd., an energy company based in Northern Ireland, and serves on the boards of Potentia Solar Inc. and Eagle Creek Renewable Energy, LLC. He has also served as managing director and senior advisor to Good Energies Capital (now named Bregal Energy), a New York-based private equity fund focused on the renewable energy sector, which positions he held from 2007 to 2010, non-executive director of Ontario Power Generation (from 2004 to 2012) and Intergen (from 2006 to 2008). Mr. MacMillan serves on the boards of Puget Energy and PSE as a representative of CPPIB's ownership interests, pursuant to the terms of the Puget Energy and PSE bylaws, and brings to this service his skills in project finance and experience with managing the capital requirements of energy companies.

Mary McWilliams, age 66, has been a director on the boards of both Puget Energy and PSE since March 1, 2011.  Ms. McWilliams was most recently the Executive Director at Washington Health Alliance, which position she held from 2008 to 2014.  She also served as President and Chief Executive Officer at Regence BlueShield from 2000 to 2008.  In addition, Ms. McWilliams serves as a Board member of the Virginia Mason health system and Seattle Branch of the Federal Reserve Bank of San Francisco.  Ms. McWilliams’s significant experience managing consumer-focused organizations with challenging regulatory and compliance regimes, as well as her extensive knowledge of the western Washington economy generally, are some of the reasons that led to her appointment to the Puget Energy and PSE boards on behalf of the CPPIB.

Drew Murphy, age 54, has been a director on the boards of both Puget Energy and PSE since May 8, 2013. Mr. Murphy is currently a Senior Managing Director at Macquarie Infrastructure and Real Assets Inc. (“MIRA”), which position he has held since January 2013. Prior to joining MIRA, Mr. Murphy was an Executive Vice President of NRG Energy, Inc., a power and energy company, from December 2006 through November 2012 and served in several roles during that time, including head of the Strategy and M&A team (from August 2011 to November 2012), President of NRG’s Northeast Region (from February 2009 to July 2011) and General Counsel (from December 2006 to February 2009). Mr. Murphy is a director on the boards of Duquesne Light Holdings, Inc. and Duquesne Light Company. Mr. Murphy serves on the boards of Puget Energy and PSE as a representative of the Company's Macquarie affiliated investors consistent with the Puget Energy and PSE bylaws, and provides the Puget Energy and PSE boards the benefit of his experience managing and overseeing the legal, regulatory and operational affairs of regulated utilities.

Herbert Simon, age 71, is a director on the board of PSE, on which he has served since March 2006.  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 at the University of Washington and as a Board member of Acre, the real estate committee for the University of Washington.  Mr. Simon previously served on the Advisory Boards of the University of Washington at Tacoma and its Institute of Technology.  An independent director not affiliated with any of the Company’s investors, Mr. Simon’s long-standing involvement with the commercial, educational, political and philanthropic leadership of western Washington are among the qualifications supporting his appointment to the PSE board.

Christopher Trumpy, age 60, has been a director on the boards of both Puget Energy and PSE since January 12, 2010.  Mr. Trumpy is currently a consultant at Circle Square Solutions, which position he has held since 2013.  He served as the Chairman of the Pacific Carbon Trust from 2008 to 2013. 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.  Mr. Trumpy represents the ownership stake in the Company of bcIMC, in accordance with the terms of the Puget Energy and PSE bylaws, and provides the boards the benefit of his significant leadership roles in government and policy-making, among other attributes.

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.

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Audit Committee

The Puget Energy and PSE Boards of Directors have both established an Audit Committee.  Directors Andrew Chapman, Steven Hooper, Benjamin Hawkins, David MacMillan and Drew Murphy are the members of the Audit Committee.  The Board has determined that Andrew Chapman meets the definition of “Audit Committee Financial Expert” under United States Securities and Exchange Commission (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.

Additional Information

The Company’s reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available or may be accessed free of charge at the Company’s website, www.pugetenergy.com.  Information may also be obtained via the SEC Internet website at www.sec.gov.

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 Committee (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 2014, were formerly Company officers or had any relationship otherwise requiring disclosure.  Each member meets the independence requirements of the SEC and the New York Stock Exchange (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 2014, the Company’s Named Executive Officers and titles were:

•Kimberly J. Harris, President and Chief Executive Officer (CEO);

•Daniel A. Doyle, Senior Vice President and Chief Financial Officer (CFO);

•Paul M. Wiegand, Senior Vice President, Energy Operations;

•Marla D. Mellies, Senior Vice President, Chief Administrative Officer; and

•Steve R. Secrist, Senior Vice President, General Counsel, Chief Ethics and Compliance Officer.

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This section also includes a discussion and analysis of the overall objectives of our compensation program and each element of compensation the Company provides.

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 incentive compensation payments with the 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 obtains information and advice on various aspects of its executive compensation program from its independent executive compensation consultant, Frederic W. Cook & Co., Inc. (Cook & Co.).  The Committee recommends to the full Board for approval both the salary level for our CEO, based on information provided by Cook & Co., and the salary levels for the other executives, based on recommendations from our CEO.  The Committee also recommends to the Board for its approval the annual and long-term incentive compensation plans for the executives, the setting of performance goals and the determination of target and actual awards under those plans.

In 2014, the Committee used the following strategies to achieve the objectives of our executive compensation program:

• Design and deliver a competitive total compensation 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 compensation to external market data from similar companies in our industry and targets base salary and target total direct compensation (the sum of base salary and annual and long-term incentive target award opportunities) to the 50th percentile of the market data.   The Committee also recognizes the importance of providing retirement income.  Executives choose to work for the Company as opposed to 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 based on achievement relative to 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 our annual and long-term incentive programs and considers adjustments as appropriate to meet the objectives of our executive compensation program.  As described under “Risk Assessment,” the Company’s policies and practices surrounding incentive pay are structured in a manner to mitigate the risk that employees would seek to take untoward risks in an attempt to increase incentive results.

• Oversee the Company’s talent management 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 and discussions with her executive team.  Each executive conducts talent reviews of senior employees that report to him or her and who have high potential for assuming greater responsibility in the Company. Utilizing evaluations and assessments, 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.

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 limited number of perquisites.  The Company also provides certain post-termination and change in control benefits to executives who were employed by the Company prior to March 2009.  Since the Company is not publicly listed and does not grant equity awards to its executives, it relies on a mix of non-equity compensation elements to achieve its compensation objectives.

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The total compensation package is designed to provide participants with appropriate incentives that are competitive with the comparator group and to drive the achievement of 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, although long-term incentive awards 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 2014 through base salary to provide liquidity for the executives and through incentive programs to focus performance on important Company goals and to increase the alignment with investors.

Review of Pay Element Competitiveness

To help inform the Committee’s recommendations on base salary, annual incentive programs and long-term incentive programs, for 2014 compensation the Committee reviewed both market data obtained from industry-specific surveys and proxy statements of companies selected for inclusion in the Company’s custom executive compensation benchmarking peer group. The market survey data were sourced from a select cut from the Towers Watson 2013 Energy Services Survey, comprised of utility and other companies similar in size and scope of operations to PSE.  The list of the 22 companies comprising the custom market survey cut used to inform compensation decisions for 2014 is:

Custom Survey Peer Group
1.	AGL Resources	9.	Northeast Utilities	17.	Southwest Gas
2.	Alliant Energy	10.	NV Energy	18	Teco Energy
3.	Atmos Energy	11.	OGE Energy	19	UIL Holdings
4.	Avista	12.	Pepco	20	Vectren
5.	CMS Energy	13.	Pinnacle West Capital	21	Westar Energy
6.	Integrys Energy	14.	PNM Resources	22	Wisconsin Energy
7.	LG&E and KU Energy	15	Portland General Electric
8	MDU Resources	16	SCANA

As noted, the market survey data were supplemented with proxy statement data for select positions in the Company’s executive compensation peer group, which was comprised of 15 companies, many of which overlapped with companies included in the market survey data. The resulting median revenue of the executive compensation peers was $3.4 billion, which is comparable to PSE’s annual revenues of $3.1 billion at the time the peer group was developed. The peer companies that comprised the Company’s executive compensation benchmarking peer group to inform 2014 compensation decisions are shown below:

Proxy Peer Group
1.	Alliant Energy	6	NiSource	11	Portland General Electric
2.	Avista	7	Northeast Utilities	12	SCANA
3.	Great Plains Energy	8	NV Energy	13	Vectren
4.	Integrys Energy Group	9	Pepco Holdings	14	Westar Energy
5.	MDU Resources Group	10	Pinnacle West	15	Wisconsin Energy

As a matter of philosophy, all three components of target total direct compensation are generally targeted at the 50th percentile of industry practice, with deviations by individual executive as described below.  If Company performance results are below expectations, actual compensation is expected to be below this targeted level and if Company performance significantly exceeds target, actual compensation is expected to be above this targeted level.

Individual pay adjustments are reviewed annually to see how they position the executive in relation to the 50th percentile of market pay, while also considering the executive’s recent performance and experience level.  Despite the median philosophy, the Company may choose to target an executive’s compensation above or below the 50th percentile 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. In addition to the foregoing survey data, the Committee generally also received advice from Cook & Co. in connection with 2014 compensation decisions.

Base Salary

We recognize that it is necessary to provide executives with a fixed amount of total compensation that is delivered each month and provides a balance to other pay elements that are at risk.  As mentioned above, base salaries are generally targeted at the 50th

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percentile of the comparator group and are reviewed annually by the Committee on an individual basis using as a guideline, the 50th percentile salary levels of our comparator group, as well as internal pay equity among our 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 for 2014

The Committee reviewed the base salaries of the Named Executive Officers in early 2014 and recommended base salary adjustments to the Board.  The Board approved the Committee’s recommendation to increase executive salaries as shown in the table below, and base salaries for 2014 generally remained at the 50th percentile of market among the comparator group.  Effective March 1, 2014, the Board increased the base salary of Ms. Harris, President and CEO, from $875,000 to $900,000. In establishing the salary amount for Ms. Harris, the Committee recommended and the Board approved a base salary that continued to be slightly below the 50th percentile of market among the comparator group. The salary increase percentages approved by the Board for the other Named Executive Officers were in a range of 2% to 5%, similar to salary increases for other non-represented employees.

Name	2013 Base Salary	2014 Base Salary	% Change
Kimberly J. Harris	$875,000	$900,000	2.9%
Daniel A. Doyle	$468,000	$482,040	3.0%
Paul M. Wiegand	$297,567	$306,494	3.0%
Marla D. Mellies	$281,190	$289,626	3.0%
Steve R. Secrist	$338,800	$352,352	4.0%

2014 Annual Incentive Compensation

All PSE employees, including the Named Executive Officers, are eligible to participate in an annual incentive program referred to as the “Goals and Incentive Plan.”  The plan is designed to provide financial incentives for achieving desired annual operating results, measured by EBITDA, while also meeting the Company’s service quality commitment to customers and an employee safety measure.  EBITDA was selected as a performance goal because it provides a financial measure of cash flows generated from the Company’s annual operating performance.

For 2014, 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.  The Company’s service quality report cards are available at http://www.PSE.com/PerformanceReportCards.

The SQIs for 2014 were the same as in 2013 and were as follows:

•Customer Satisfaction (3 SQIs)

- Customer satisfaction with the telephone access center and gas field services and number of Washington Commission complaints

•Customer Service (2 SQIs)

- Calls answered “live” and on-time appointments

•Safety and Reliability (4 SQIs)

- Gas emergency response, electric emergency response, non-storm outage frequency and non-storm outage duration

 In 2014, to continue emphasizing the Company's commitment to employee safety, the Company retained a safety performance measure in the annual incentive plan funding. The employee safety measure functions similarly to the 9 SQIs in determining the funding of the annual incentive plan. That is, if the safety measure is not achieved, annual incentive funding will be decreased by 10%, in the same way as a missed SQI. The safety performance measure contains four targets which must all be satisfied for the safety measure to be treated as met. The four targets for 2014 were:

• All employees attend a monthly safety “meeting in a box” presentation, or complete the same content online. The target completion rate is no less than 95%.

• All employees complete two classes on safety, disaster preparedness, or wellness, choosing from in person or on-line courses. The target completion rate is no less than 95% for all new hires.

•The Company Total Incident Case Rate (TICR) not to exceed a rate of 1.40 in 2014.

•The Company Lost Workday Case Rate (LWCR) not to exceed a rate of 0.29 in 2014.

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In 2014, 100% funding for the annual incentive plan required (i) achievement of 10 out of 10 customer service and safety measures (all 9 SQIs and achievement of the safety measure) and (ii) target EBITDA performance. In total, all 10 customer service and safety measures were met or deemed met.

Funding levels at maximum, target, and threshold are shown in the table below.

Annual Incentive Performance Payout Scale and Actual Performance
Performance	2014 EBITDA (In Millions)		SQI & Safety*	Funding Level
Maximum	$	1,562.6	10/10	200	%
Target	1,157.5		10/10	100	%
Threshold Payout Funding	1,041.8		6/10	30	%
2014 Actual Performance	$	1,146.4	10/10	95.20	%

_______________

^*  Combined SQI & Safety results of 6/10 or better and minimum EBITDA of $1,041.80 million are required for any annual incentive payout funding. SQI/Safety results below 10/10 reduce funding (e.g., 9/10 = 90%, 8/10 = 80%, 7/10 = 70%).

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 exclude any items for 2014. Individual awards may be adjusted upward or downward based on a subjective evaluation of an executive officer’s performance against individual and team goals.  

2014 Corporate Goals

In 2014, the Company introduced the Integrated Strategic Plan (ISP) to summarize for employees the direction and overall goals of the Company. The plan has five objectives whichcapture our 2014 goals and which have been communicated to our employees as shown below. Each employee, including the Named Executive Officers, has specific goals linked to driving strategies that meet one or more of the objectives:

• Safety-- Our Safety Objective is our foundation: If Nobody Gets Hurt Today, we will feel safe and secure and be able to perform at our best.

• People-- When we’re Safe, we can achieve our People Objective of being a Great Place to Work, with engaged employees who live our values, embrace an ownership culture and are motivated to drive results for our company and our customers.

• Process and Tools-- Engaged employees take us to our Process and Tools Objective where results start with achieving Operational Excellence, with continuous improvement of our internal processes and tools so that we can increase efficiency, eliminate waste, improve reliability and enhance customer service.

• Customer-- We now have the fundamentals to achieve our Customer Objective of delivering greater value and being our Customer’s Energy Partner of Choice in a competitive marketplace.

• Financial-- Being our customer’s energy partner of choice takes us to our Financial Objective of increasing our Financial Strength, allowing us to sustain further improvement.

2014 Annual Incentive Plan Results

Achievement of the corporate goals for 2014 was at 99% of target for EBITDA, and at target for SQI and safety achievement.  PSE EBITDA was $1,146.4 million, and SQI and safety achievement was 10 out of 10, leading to a funding level for 2014 of 95.2% under the annual incentive plan.

For 2014, individual target incentive levels for this plan varied by executive officer as a percentage of 2014 base salary as shown in the table below, based on the individual executive’s level of responsibility within the Company.  Target annual incentive opportunities as a percentage of base salary for participating executives remained unchanged from 2013 levels except for Mr. Secrist, who was promoted to Senior Vice President. In connection with Mr. Secrist’s promotion, the Board approved an increase in his 2014 target award opportunity from 40% to 45% of base salary. The maximum incentive payable for exceptional performance in this plan is twice the target incentive.  As described above, an executive’s individual award 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 determined to be met or exceeded by each executive, small adjustments were made by the CEO for individual performance of the Named Executive Officers other than the CEO in 2014. The Committee similarly recommended an award amount for the CEO which included a small adjustment for individual performance in 2014 and to recognize that the Company nearly met 2014 annual incentive goals at target. The adjustments for individual performance did not materially change the amounts resulting from 2014 achievement of the corporate goals. The Board approved the incentive amounts shown below, which were paid in March 2015.

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Name	Target Incentive (% of Base Salary)	2014 Actual Incentive Paid		2014 Actual Incentive (% of Base Salary)
Kimberly J. Harris	100%	$	899,640	100	%
Daniel A. Doyle	45%	216,831		45	%
Paul M. Wiegand	45%	131,302		43	%
Marla D. Mellies	45%	142,687		49	%
Steve R. Secrist	45%	166,042		47	%

Long-Term Incentive Compensation

Long-term incentive compensation opportunities are designed to be competitive with market practices, reward long-term performance and promote retention. Long-term incentive plan (LTI Plan) awards are denominated in units and are settled in cash if threshold performance measures are met. Performance measures are based on two financial goals, total return (Total Return) and Return on Equity (ROE), measured over a three-year performance cycle. Total return reflects the annual change in the value of the Company plus any distributions made to investors. Achievement of one performance measure during the performance cycle is evaluated independently of the other. The Committee annually approves a targeted LTI grant value for each executive, which is expressed as a percentage of base salary. The target LTI grant value is then converted into a target number of units, allocated equally among the two financial goals, based on the unit value on the grant date. The per-unit value is measured at the Puget Holdings level and is calculated annually by an independent auditing firm.  The number of units ultimately earned may range from 0% to 200% of target depending on performance, with the payout being made in cash based on the number of units earned and the per-unit value at the end of the performance period. Executives generally must be employed on the payment date to receive a cash payment under the LTI Plan, except in the event of retirement, disability or death.

The Committee determines the number of LTI Plan units granted to each executive by evaluating long-term incentive grant values provided to similarly situated executives at comparable companies (using the previously discussed survey and peer group data) as well as other relevant executive-specific factors.  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.  

Half of the target units are earned based on Total Return and the other half are earned based on ROE, each over a 3-year performance period. These metrics and weightings have remained unchanged since the 2012 - 2014 grant.

2014-2016 LTI Plan Target Awards and Performance Goals

Consistent with prior years, target LTI Plan awards for the 2014-2016 performance cycle were calculated based on a percentage of an executive's annual base salary, taking into account the executive's level of responsibility within the Company. Target LTI Plan award amounts for the 2014-2016 performance cycle were 170% of base salary for Ms. Harris and 95% for Mr. Doyle, Mr. Wiegand, Ms. Mellies and Mr. Secrist, which percentages were unchanged from amounts established for the 2013-2015 performance cycle, except for Mr. Secrist. Mr. Secrist’s target award was increased from 50% to 95% as a result of his promotion during 2014. The total number of LTI Plan units granted to a Named Executive Officer for the 2014-2016 performance cycle is equal to the applicable percentage of salary (converted to dollars) divided by the per unit value at the beginning of the performance cycle, which was $41.25, as adjusted as described below under “Total Return Model Corrections.” Details of the number of units granted and expected values at target, threshold and maximum performance levels can be found in the “2014 Grants of Plan-Based Awards” table below. Effective February 27, 2015, the Board approved an increase in LTI target for Ms. Harris from 170% to 200% of base salary effective with the 2015-2017 LTI grant. Targets for the other Named Executive Officers were not changed.

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The table below shows the percentage of LTI Plan target awards under the Total Return component that could be earned based on three-year performance.  Payout percentages will be linearly interpolated if performance falls between the values shown below.

Annualized 3 Year Return	Plan Funding
15% or more	200%
14%	180%
13%	160%
12%	140%
11%	120%
10%	100%
9%	80%
8%	60%
7%	40%
6%	20%
<6%	0%

The table below shows the percentage of LTI Plan target awards under the ROE component that could be earned based on average performance during the three-year performance period.  Payout percentages will be interpolated if performance falls between the values shown below.

ROE Compared to Target	Plan Funding
Target + 250 bps	200%
Target + 200 bps	180%
Target + 150 bps	160%
Target + 100 bps	140%
Target + 50 bps	120%
Target ROE	100%
Target - 50 bps	80%
Target - 100 bps	60%
Target - 150 bps	40%
Target - 200 bps	20%
<Target - 200 bps	0%

Total Return Model Corrections

The Company uses an internally managed financial model to track and forecast Total Return, a key measure in the LTI Plan, and periodically reviews the assumptions within the model. This financial model is provided as an input to the independent valuation firm which determines Total Return for the calculation of LTI Plan awards, subject to Board approval. During 2012 and again in 2014, certain model inputs were adjusted with Board approval, and these changes impacted the 2012 and 2014 calculations of Total Return achieved. LTI grant payments in 2012 and 2013 were not impacted, as the performance threshold was not met. The adjustments to Total Return, if they had been implemented in the model prior to the 2012-2014 LTI cycle, would have resulted in changes to the initial unit prices for the 2012-14, 2013-15, and 2014-16 LTI performance cycles. In 2014, the Board approved the model changes and approved adjusted initial performance unit prices for each of the 2012-14, 2013-15 and 2014-16 LTI performance cycles. To preserve the same initial grant value to each executive, the Board approved corresponding adjustments to the number of units granted to each executive in each of the foregoing performance cycles. The Board took this action because it believes that LTI Plan participants should not be penalized or benefit from these changes which did not reflect differences in actual performance. The table below summarizes the initial performance unit grants and the adjusted grants (rounded to whole units), each of which provided identical grant value to the executive. As a result, this adjustment had a neutral economic effect under the LTI Plan for outstanding performance cycles.

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Performance Cycle	Name	Initial Unit Price	Initial Units Granted	Intended Grant Value (Assuming 100% performance)	Adjusted Unit Price	Adjusted Units Granted (provides identical grant value)
2012-2014	K. Harris	$36.03	38,690	$1,394,001	$35.76	38,982
	D. Doyle	$36.03	11,865	$427,496	$35.76	11,955
	P. Wiegand	$36.03	7,617	$274,441	$35.76	7,675
	M. Mellies	$36.03	7,198	$259,344	$35.76	7,252
	S. Secrist	$36.03	4,274	$153,992	$35.76	4,306
2013-2015	K. Harris	$36.32	40,955	$1,487,486	$37.81	39,341
	D. Doyle	$36.32	12,241	$444,593	$37.81	11,759
	P. Wiegand	$36.32	7,783	$282,679	$37.81	7,476
	M. Mellies	$36.32	7,355	$267,134	$37.81	7,065
	S. Secrist	$36.32	4,664	$169,397	$37.81	4,480
2014-2016	K. Harris	$39.77	38,471	$1,529,992	$41.25	37,091
	D. Doyle	$39.77	11,515	$457,952	$41.25	11,102
	P. Wiegand	$39.77	7,321	$291,156	$41.25	7,058
	M. Mellies	$39.77	6,918	$275,129	$41.25	6,670
	S. Secrist	$39.77	8,417	$334,744	$41.25	8,115

LTI Plan Performance 2012-2014 Performance Cycle

The 2012-2014 performance cycle has now ended. Amounts payable as a result of award vesting are shown in the table below. Units granted have been adjusted as described above.

• Performance on the Total Return component for the combined three-year average was a compounded annual rate of 7.59%, below the three-year average target but above the threshold needed for payment. The Total Return Component funded at 51.8% of target units.

• Performance on the ROE Component of the grant was an average of target plus 15.7 basis points for funding at 106.27% of target units.

Name	Target Incentive (% of Base Salary) 1	Total Return Component Units Granted/Paid	ROE Component Units Granted/Paid	2012-2014 Actual LTIP Paid 2
Kimberly J. Harris	170%	19,491/10,096.3	19,491/20,713.1	$	1,371,944
Daniel A. Doyle	95%	5,977.5/3,096.3	5,977.5/6,352.3	$	420,748
Paul M. Wiegand	95%	3,837.5/1,987.8	3,837.5/4,078.1	$	270,116
Marla D. Mellies	95%	3,626/1,878.3	3,626/3,853.4	$	255,229
Steve R. Secrist	50%	2,153/1,115.3	2,153/2,288	$	151,547

______________

¹  Target LTI Plan incentive is a percentage of 2012 base salary when the grants were made in 2012.

²  2012-2014 actual LTI Plan amount payable is equal to the unit price $44.53 multiplied by earned Total Return and ROE component units.

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LTI Plan Performance for Outstanding Cycles

The table below summarizes the status of the two other outstanding performance cycles from the initial grant date to December 31, 2014, with the projected payout assuming this same performance for the full three-year cycle (the payout scales for Total Return and ROE above also apply to both of these grants):

Performance Cycle	Cycle Progress	Total Return Performance	Payout (% of Target)	ROE Performance	Payout (% of Target)	Total Projected Payout (based on performance as of 12/31/2014)
2013 - 2015	67% Complete	7.9%	58%	-3.5 bps	99%	83.5%
2014 - 2016	33% Complete	7.9%	58%	+79 bps	132%	98%

Retirement Plans - SERP and Retirement Plan

The Company maintains the Supplemental Executive Retirement Plan (SERP) to attract and retain executives by providing 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 participate in the SERP.   Additional information regarding the SERP and the Retirement Plan is shown in the “2014 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 eligible executives an opportunity to defer up to 100% of base salary, annual incentive bonuses and earned 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.  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.  Additional information regarding the Deferred Compensation Plan is shown in the “2014 Nonqualified Deferred Compensation” table.

Post-Termination Benefits

Effective March 30, 2009, the Company entered into Executive Employment Agreements with the Named Executive Officers, except Mr. Doyle (who was not then employed by the Company) and Mr. Secrist (who was not then an officer), which amended and restated then existing Amended and Restated Change of Control Agreements between the Company and each of the executives.  The Executive Employment Agreements provided for an employment period of two years following the completion of a merger and otherwise generally provide severance benefits similar to those under the previous Change of Control Agreements.  Since 2009, the Company has ceased entering into these agreements with new executive officers.

The Committee periodically reviews existing change in control and severance arrangements for the peer group companies.  Based on this information, the Committee believes that the current arrangements generally provide benefits that are similar to those of the comparator group for longer tenured executives, but is not extending them to newly hired executives.

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, 2014.

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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 limited perquisites.  The Company may provide payments upon hiring a new executive to help offset the executive’s relocation expenses, a practice needed to attract qualified candidates from other areas of the country.  The current 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 personal use of club facilities.  These perquisites generally do not make up a significant portion of executive compensation and did not exceed $10,000 in total for each Named Executive Officer in 2014. Executives are taxed on the value of the perquisites received.

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.

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 on interests important to the Company and its investors and customers 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, the Committee and/or the Board.  As a result, the Committee and the Board believe that the programs’ design do not have risks that are reasonably likely to have a material adverse effect on the Company and also provide appropriate incentive opportunities for executives to achieve Company goals that support the interests of our investors and customers.

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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.  Each member of the Committee served during all of 2014.

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, 2014 for filing with the SEC.

Compensation and Leadership

Development Committee of

Puget Energy, Inc.

Puget Sound Energy, Inc.

Chris Trumpy, Chair

Melanie Dressel

Daniel Fetter

Christopher Leslie

Mary McWilliams

Herbert B. Simon (PSE Only)

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SUMMARY COMPENSATION TABLE

The following information is provided for the year ended December 31, 2014 (and for prior years where applicable) with respect to the Named Executive Officers during 2014.  The positions listed below are at Puget Energy and PSE, except that Mr. Wiegand and Ms. Mellies are executives of PSE only. Positions listed are those held by the Named Executive Officers as of December 31, 2014.  Salary and incentive compensation includes amounts deferred at the executive’s election.

Name and Principal Position	Year	Salary		Bonus		Stock Awards		Option Awards		Non-Equity Incentive Plan Compensation 1		Change in Pension Value and Nonqualified Deferred Compensation Earnings 2		All Other Compensation 3		Total
Kimberly J. Harris	2014	$	897,763	$	—	$	—	$	—	$	2,271,584	$	2,333,346	$	27,128	$	5,529,821
President and Chief	2013	863,771		84,350		—		—		1,222,707		1,465,614		24,664		3,661,106
Executive Officer 4	2012	799,365		44,378		—		—		1,222,140		1,725,380		24,974		3,816,237
Daniel A. Doyle	2014	$	479,115	$	—	$	—	$	—	$	637,579	$	336,575	$	47,822	$	1,501,091
Senior Vice President	2013	464,325		19,030		—		—		358,806		269,754		53,147		1,165,062
and Chief Financial Officer 5	2012	450,000		22,534		—		—		306,517		147,857		38,287		965,195
Paul M. Wiegand	2014	$	304,634	$	—	$	—	$	—	$	401,418	$	370,458	$	41,138	$	1,117,648
Senior Vice President,	2013	295,797		11,923		—		—		272,076		387,469		42,955		1,010,220
Energy Operations 6	2012	285,000		7,233		—		—		286,790		407,780		40,000		1,026,803
Marla D. Mellies	2014	$	287,868	$	12,367	$	—	$	—	$	385,549	$	388,950	$	30,126	$	1,104,860
Senior Vice President,	2013	279,518		11,511		—		—		262,368		205,448		29,567		788,412
Chief Administrative Officer 7	2012	271,349		6,836		—		—		220,679		260,092		28,680		787,636
Steve R. Secrist	2014	$	349,529	$	7,485	$	—	$	—	$	310,104	$	621,610	$	21,225	$	1,309,953
Senior Vice President	2013	332,512		24,419		—		—		204,892		304,051		20,116		885,990
General Counsel, Chief Ethics & Compliance Officer 8	2012	302,223		—		—		—		164,833		459,921		19,801		946,778

___________________

¹  For 2014, reflects annual cash incentive compensation paid under the 2014 Goals and Incentive Plan and cash incentive compensation paid under the LTI Plan for the 2012-2014 performance cycle. Cash incentive amounts were paid in early 2015 or deferred at the executive's election.  The 2014 Goals and Incentive Plan and the LTI Plan are described in further detail under “Compensation Discussion and Analysis,” including the individual amounts paid to each Named Executive Officer in early 2015.

²  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. In 2014, low interest rates and improved mortality assumptions have increased the actuarial value of the underlying retirement benefits.  Information regarding these pension plans is set forth in further detail under “2014 Pension Benefits.”  The change in pension value amounts for 2014 are: Ms. Harris, $2,331,156; Mr. Doyle, $336,575; Mr. Wiegand, $367,992; Ms. Mellies, $388,644; and Mr. Secrist, $621,610. Also included in this column are the portions of Deferred Compensation Plan earnings that are considered above market.  These amounts for 2014 are: Ms. Harris, $2,190; Mr. Doyle, $0; Mr. Wiegand, $2,466; Ms. Mellies, $306; and Mr. Secrist $0. See the “2014 Nonqualified Deferred Compensation” table for all Deferred Compensation Plan earnings.

³  All Other Compensation for 2014 is shown in detail in the table below.

⁴  Ms. Harris was promoted to President and CEO from President on March 1, 2011.

⁵  Mr. Doyle joined PSE and Puget Energy as Senior Vice President and Chief Financial Officer on November 28, 2011.

⁶  Mr. Wiegand retired from PSE on January 9 2015, and worked at PSE since June 1977.

⁷  Ms. Mellies has worked at PSE since October 2005.

⁸  Mr. Secrist has worked at PSE since May 1989.

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Detail of All Other Compensation

Name	Perquisites and Other Personal Benefits 1		Registrant Contributions to Defined Contribution and deferred compensation Plans 2		Other 3
Kimberly J. Harris	$	3,290	$	18,150	$	5,688
Daniel A. Doyle	—		42,217		5,605
Paul M. Wiegand	3,301		28,814		9,023
Marla D. Mellies	965		26,839		2,322
Steve R. Secrist	675		15,982		4,568

_______________

¹  After an initial reimbursement up to $7,500, annual reimbursement for financial planning, tax planning, and/or legal planning, up to a maximum of $5,000 for Ms. Harris and $2,500 for the other Named Executive Officers.  This column also includes club use which 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 2014 to PSE’s Investment Plan (a tax qualified 401(k) plan) and the Deferred Compensation Plan.  Company 401(k) contributions are as follows:  Ms. Harris, $18,150; Mr. Doyle, 18,150; Mr. Wiegand, 15,893; Ms. Mellies, $18,150; and Mr. Secrist, 15,982. Company contributions to the Deferred Compensation Plan are as follows: Ms. Harris, $0; Mr. Doyle, $24,067; Mr. Wiegand, $12,921; Ms. Mellies, $8,689; and Mr. Secrist $0.

³  Reflects the value of imputed income for life insurance and Company paid premiums on supplemental disability insurance.

2014 Grants of Plan-Based Awards

The following table presents information regarding 2014 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
Kimberly J. Harris
Annual Incentive 1	1/1/2014		$	270,000	$	900,000	$	1,800,000
LTI Plan 2014-2016 2	2/28/2014	37,091	351,397		2,000,302		4,487,234
Daniel A. Doyle
Annual Incentive 1	1/1/2014		$	65,070	$	216,900	$	433,800
LTI Plan 2014-2016 2	2/28/2014	11,102	105,179		598,723		1,343,103
Paul M. Wiegand
Annual Incentive 1	1/1/2014		$	41,378	$	137,925	$	275,850
LTI Plan 2014-2016 2	2/28/2014	7,058	66,871		380,656		853,917
Marla D. Mellies
Annual Incentive 1	1/1/2014		$	39,096	$	130,320	$	260,640
LTI Plan 2014-2016 2	2/28/2014	6,670	63,190		359,702		806,911
Steve R. Secrist
Annual Incentive 1	1/1/2014		$	47,567	$	158,558	$	317,115
LTI Plan 2014-2016 2	2/28/2014	8,115	76,882		437,642		981,754

_______________

¹  As described in the “Compensation Discussion and Analysis,” the 2014 Goals and Incentive Plan had dual funding triggers in 2014 of $1,041.8 million EBITDA and SQI performance of 6/10.  Payment would be $0 if either trigger is not met.  The threshold estimate assumes $1,041.8 million EBITDA and SQI/Safety measure performance at 6/10. The target estimate assumes $1.157.5 million EBITDA and SQI/Safety measure performance at 10/10.  The maximum estimate assumes $1,562.6 million EBITDA or higher and SQI/Safety measure performance at 10/10.

²  As described in the “Compensation Discussion and Analysis,” LTI Plan grants for the 2014-2016 performance cycle were equally allocated between a Total Return component and an ROE component.  Payments are calculated based on Total Return at Puget Holdings during the three-year performance cycle, the average three-year performance of ROE and the unit value at the end of the performance cycle.

2014 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

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using interest rate and mortality rate assumptions consistent with those used in the Company’s financial statements. Each of the Named Executive Officers participates in both plans.

Name	Plan Name	Number of Years Credited Service	Present Value of Accumulated Benefit 1,2		Payments During Last Fiscal Year
Kimberly J. Harris	Retirement Plan	15.7	$	364,217	$	—
	SERP	15.7	7,262,319		—
Daniel A. Doyle	Retirement Plan	3.1	83,845		—
	SERP	3.1	652,371		—
Paul M. Wiegand	Retirement Plan	37.5	799,971		—
	SERP	37.5	2,286,913		—
Marla D. Mellies	Retirement Plan	9.2	225,687		—
	SERP	9.2	1,154,023		—
Steve R. Secrist	Retirement Plan	25.6	425,744		—
	SERP	25.6	1,906,012		—

_______________

¹  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, 2014 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 2014 and are assumed to be 4.0% through 2019, and 5.0% annually thereafter.  The discount assumption is 4.25%, and the post-retirement mortality assumption is based on the 2015 417(e) unisex mortality table adjusted to reflect RP-2014 with MP-2014 improvements. Annuity benefits are converted to lump sum amounts at retirement based on assumed future 417(e) segment rates of % 1.15%, 4.06%, and 5.15% (the 24 month average of the underlying rates as of September 2014).  These assumptions are consistent with the ones used for the Retirement Plan and the SERP for financial reporting purposes for 2014.  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, 2013 for the benefits earned as of that date using the assumptions used for financial reporting purposes for 2013.  These assumptions included assumed cash balance interest credits of 4.0% annual through 2017 and 5.0% annually thereafter, a discount assumption of 5.10% and post-retirement mortality assumption based on the 2014 417(e) unisex mortality table. Annuity benefits were converted to lump sum amounts at retirement based on assumed future 417(e) segment rates of 1.37%, 4.05% and 5.06% (the 24 month average of the underlying rates as of September 2013). Other assumptions used to determine the value as of December 31, 2013 were the same as those used for December 31, 2014.

²  As described in footnote 1 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, 2014.  Each SERP-eligible Named Executive Officer (except Mr. Doyle) was vested in his or her SERP benefits as of December 31, 2014.

Estimated Lump Sum
Name	Lump Sum
Kimberly J. Harris	$	11,639,580
Daniel A. Doyle	823,036
Paul M. Wiegand	2,286,913
Marla D. Mellies	1,560,508
Steve R. Secrist	2,781,739

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Retirement Plan

Under the Retirement Plan, the Company's eligible employees hired prior to January 1, 2014 (prior to December 12, 2014, in the case of IBEW-represented 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. Non-represented and UA-represented employees hired on or after January 1, 2014 and IBEW-represented employees hired on or after December 12, 2014 will receive pay credits equal to 4% (rather than the age-based pay credit described above), which non-represented and IBEW-represented employees may choose to have contributed to the Company’s 401(k) plan, rather than credited under the Retirement Plan. Eligible compensation generally includes base salary and bonuses (other than bonuses paid under the LTI Plan and signing, retention and similar bonuses), up to the limit imposed by the Internal Revenue Code.  For 2014, the limit was $260,000. For 2015, the limit is $265,000. 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 2014 and 2015, 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, 2014, 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.  All the Named Executive Officers 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 and attainment of age 55 while employed by the Company or any of its affiliates. However, SERP participants as of December 31, 2014, who had not yet attained age 55 at that date, including Ms. Harris, Ms. Mellies, and Mr. Secrist, have been exempted from the age 55 vesting requirement. All the participating Named Executive Officers, except Mr. Doyle, are vested in their SERP benefits.  However, Ms. Harris must continue Company service through December 31, 2016 in order to vest additional SERP benefit value after December 31, 2012.

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The monthly benefit payable under the SERP to a Named Executive Officer (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 consecutive calendar years of earnings.  The three consecutive calendar years must be among the last ten calendar years completed by the executive prior to his or her termination. Prior to December 31, 2012, a participant's highest average earnings was not required to be calculated based on a three consecutive year basis. Executives participating in the SERP as of December 31, 2012 will have their highest average earnings on that date preserved as a minimum value for highest average earnings in the future. “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, including 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 “2014 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. An executive may also elect to have his or her SERP benefit transferred to the Deferred Compensation Plan and paid in accordance with his or her elections under that plan.

An executive may elect to have his or her SERP benefit paid, or commence to be paid, upon termination of employment after attaining age 55 but prior to attaining age 62. The SERP benefit of any executive who receives such early retirement benefits will be reduced by 1/3% for each month that the early commencement date precedes the beginning of the month coincident with or next following the date on which the executive attains age 62. Mr. Wiegand is the only Named Executive Officers eligible for early retirement benefit payments under the SERP as of December 31, 2014.

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, with any applicable reductions for early commencement if the executive dies before age 62.  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.

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2014 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 2014 and year-end account balances under the Deferred Compensation Plan.

Name	Executive Contributions in 2014 1		Registrant Contributions in 2014 2		Aggregate Earnings in 2014 3		Aggregate Withdrawals/ Distributions		Aggregate Balance at December 31, 2014 4
Kimberly J. Harris	$	—	$	—	$	12,436	$	—	$	288,202
Daniel A. Doyle	108,060		24,067		11,746		—		221,386
Paul M. Wiegand	18,316		12,921		29,357		—		605,737
Marla D. Mellies	7,318		8,689		2,064		—		89,138
Steve R. Secrist	—		—		—		—		—

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¹  The amount in this column reflects elective deferrals by the executive of salary, annual incentive compensation or LTI Plan awards paid in 2014.  Deferred salary amounts are: Ms. Harris, $0; Mr. Doyle, $23,806; Mr. Wiegand, $18,316; Ms. Mellies, $7,318; and Mr. Secrist, $0. Deferred incentive compensation amounts are: Ms. Harris, $0; Mr. Doyle, $0; Mr. Wiegand, $0; Ms. Mellies, $0; and Mr. Secrist $0. The amounts are also included in the applicable column of the Summary Compensation Table for 2014.

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. These amounts are also included in the total amounts shown in the All Other Compensation column of the Summary Compensation Table for 2014.

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 2014.

⁴  Of the amounts in this column, the amounts in the table below have also been reported in the Summary Compensation Table for 2014, 2013 and 2012.

Nonqualified Deferred Compensation also Reported
Name	Reported for 2014		Reported for 2013		Reported for 2012
Kimberly J. Harris	$	2,190	$	3,007	$	3,116
Daniel A. Doyle	132,127		52,664		21,250
Paul M. Wiegand	33,703		35,094		33,894
Marla D. Mellies	16,314		16,740		16,579
Steve R. Secrist	—		—		—

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 payments.  In addition, each year, executives are eligible to receive Company contributions under the Deferred Compensation Plan 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.

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 a money market index. For deferrals prior to 2012, an interest crediting fund was available.  The tracking funds differ from the investment funds offered in the 401(k) plan.  The 2014 calendar year returns of these tracking funds were:

Vanguard Total Bond Market Index	5.91	%
Vanguard 500 Index	13.51	%
Vanguard Money Market Index	0.01	%
Interest Crediting Fund (pre-2012 deferrals)	4.48	%

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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. Wiegand is the only Named Executive Officer 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 below 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; (iv) retirement; (v) disability; or (vi) death.

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. Doyle and Mr. Secrist, entered into an Executive Employment Agreement with the Company in March 2009, which provides for benefits or payments upon certain qualifying terminations of employment from the Company following a change in control.  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 annual 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 Agreements with Named Executive Officers

In March 2009, PSE entered into Executive Employment Agreements (Employment Agreements) with each of the Named Executive Officers except Mr. Doyle and Mr. Secrist (collectively, individual parties to such Employment Agreements, the Covered Executives), the terms of which are the same for all the Covered Executives and which amended and restated then existing Amended and Restated Change of Control Agreements between the Company and each of the Covered Executives.  The Employment Agreements provide for an employment period of two years following completion of a merger, and generally provides benefits similar to those provided under the previous Change of Control Agreements.  In the event of a termination of employment within two years of a change in control (a Covered Termination), a Covered Executive is eligible to receive the payments described below.  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

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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 a Covered Executive’s employment is terminated without cause by the Company or is terminated by the Covered Executive for good reason within two years of a change in control, the Covered Executive is eligible to receive the following compensation and benefits:

• Lump sum payment of 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 2014, no amount is shown in the table below;

• Supplemental retirement benefit equal to the difference between (x) the actuarial equivalent of the amount the Covered Executive would have received under the Retirement Plan and the SERP had his or her employment continued until the end of two years following the change in control, and (y) the actuarial equivalent of the amount the Covered Executive actually receives or is entitled to receive under the Retirement Plan and SERP; and

• Continued group medical, dental, disability and life insurance benefits to the Covered Executive and his or her family for the remainder of the two-year protection period.  Benefits will be paid by the Company while the Covered Executive is eligible for COBRA and thereafter by reimbursement of payments made by the Covered Executive for such coverage (including related tax amounts), except that if the Covered 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 Covered Executive to substantially perform the Covered 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 Covered Executive or (ii) the Covered 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 Covered Executive’s part is considered “willful” unless the Covered Executive has acted or failed to act with an absence of good faith and without a reasonable belief that the Covered Executive’s action or failure to act was in the best interests of the Company.

Good Reason generally means (i) the assignment of the Covered Executive to a non-officer position with the Company, which the parties agree would constitute a material reduction in the Covered Executive’s authority, duties or responsibilities; (ii) a material diminution in the Covered Executive’s total compensation opportunities under the Employment Agreement; (iii) the Company’s requiring the Covered Executive to be based at any location that represents a material change from the Covered Executive’s location in the Seattle/Bellevue metropolitan area, unless the Covered 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 Covered Executive.

Payments upon Retirement, Disability or Death

In the event of a Covered Termination 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 to the Covered Executive.  The bonus is payable at the time the Covered Executive otherwise would have received the payment had employment continued, based on the Company’s actual achievement of performance goals.

In the event of a Covered Termination due to disability or death, the Covered 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, other than by reason of retirement, the Covered 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 Covered Executive’s timely execution (and non-revocation) of a general waiver and release of claims.

The Employment Agreements also contain noncompetition and anti-solicitation provisions that restrict the Covered Executive for twelve months after termination from, respectively, engaging in activities related to selling or distributing electric power or

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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 Covered Executives must keep confidential all secret or confidential information, knowledge or data relating to the Company and its affiliates obtained during their employment.  The Covered 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 a change in control while the Company's stock is not traded on an established securities market or otherwise immediately before such change in control, then the Covered Executive will agree to execute a waiver of any “excess parachute payments” (within the meaning of Section 280G of the Internal Revenue Code), 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 Covered Executive.

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Estimated Potential Incremental Payments Upon Termination or Change in Control

The amounts shown in the table below assume that the termination of employment of a Named Executive Officer or a change in control was effective as of December 31, 2014.  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 a change in control.  Actual amounts payable can only be determined at the time of a termination of employment or a 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		Retirement		Disability		Death
Kimberly J. Harris
Cash Severance (salary and/or annual incentive)	n/a	$	—	$	5,400,000	$	—	$	—	$	—
Long Term Incentive Plan	—	5,139,381		5,139,381		—		2,553,920		2,553,920
SERP (additional years of credited service) 1	—	—		—		—		—		—
Benefits (continuation) 2	n/a	—		29,787		—		29,787		29,787
Supplemental Life Insurance	n/a	—		—		—		—		2,400,000
Total Estimated Incremental Value	n/a	$	5,139,381	$	10,569,168	$	—	$	2,583,707	$	4,983,707
Daniel A. Doyle
Long Term Incentive Plan	—	$	1,550,314	$	1,550,314	$	—	$	774,088	$	774,088
SERP (additional years of credited service) 1	—	—		—		—		—		—
Benefits (continuation) 2	n/a	—		—		—		—		—
Supplemental Life Insurance	n/a	—		—		—		—		915,800
Total Estimated Incremental Value	n/a	$	1,550,314	$	1,550,314	$	—	$	774,088	$	1,689,888
Paul M. Wiegand
Cash Severance (salary and/or annual incentive)	n/a	$	—	$	1,333,275	$	—	$	—	$	—
Long Term Incentive Plan	—	988,973		988,973		494,764		494,764		494,764
SERP (additional years of credited service)1	n/a	—		—		—		—		—
Benefits (continuation) 2	n/a	—		41,522		—		41,522		41,522
Supplemental Life Insurance	n/a	—		—		—		—		582,350
Total Estimated Incremental Value	n/a	$	988,973	$	2,363,770	$	494,764	$	536,286	$	1,118,636
Marla D. Mellies
Cash Severance (salary and/or annual incentive)	n/a	$	—	$	1,259,760	$	—	$	—	$	—
Long Term Incentive Plan	—	934,564		934,564		—		467,550		467,550
SERP (additional years of credited service) 1	n/a	—		409,418		—		—		—
Benefits (continuation) 2	n/a	—		40,348		—		40,348		40,348
Supplemental Life Insurance	n/a	—		—		—		—		550,240
Total Estimated Incremental Value	n/a	$	934,564	$	2,644,090	$	—	$	507,898	$	1,058,138
Steve R. Secrist
Long Term Incentive Plan	—	$	752,623	$	752,623	$	—	$	306,175	$	306,175
SERP (additional years of credited service) 1	n/a	—		—		—		—		—
Benefits (continuation) 2	n/a	—		—		—		—		—
Supplemental Life Insurance	n/a	—		—		—		—		669,465
Total Estimated Incremental Value	n/a	$	752,623	$	752,623	$	—	$	306,175	$	975,640

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¹  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, 2014. These values are based on interest rate and mortality rate assumptions consistent with those used in the Company’s financial statements.

²  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 Ms. Harris and $2,500 for all the other Named Executive Officers eligible for benefits continuation.

Director Compensation for Fiscal Year 2014

The following table sets forth information regarding compensation paid by the Company to the directors named in the table who received compensation from the Company in 2014 for service as directors.  We refer to these directors as nonemployee directors.  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 are employed by the Company’s investor-owners are: Andrew

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Chapman, Daniel Fetter, Benjamin Hawkins, Alan James, Christopher Leslie, and Drew Murphy. Kimberly Harris is employed by the Company and also serves as a director.

As described in further detail below, the Company’s nonemployee director compensation program in 2014 consisted of quarterly retainer cash fees of $27,500.  Additional quarterly retainer amounts associated with serving as Chair of the Board, chairing Board committees, serving on the Audit Committee and meeting fees were also paid in cash.

Name	Fees Earned		Nonqualified Deferred Compensation Earnings 1		Total
William Ayer	$	183,400	$	4,549	$	187,949
Melanie Dressel	144,400		—		144,400
David MacMillan	158,400		—		158,400
Herbert Simon	142,400		2,656		145,056
Christopher Trumpy	151,600		—		151,600
Mary O. McWilliams	140,400		—		140,400

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¹  Represents earnings accrued on deferred compensation considered to be above market.

Nonemployee Director Compensation Program

The 2014 nonemployee 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 2014 compensation program for nonemployee directors was as follows:

• A base cash quarterly retainer fee of $27,500;

• $1,600 for attendance at each in-person Board and committee meeting; and

• $800 for each telephonic meeting lasting 60 minutes or less, and $1,600 for each telephonic meeting lasting more than 60 minutes.

In 2014, nonemployee directors were paid the following additional cash quarterly retainer fees:

• Independent Board Chairman, $13,750;

• Chair of the Compensation and Leadership Development Committee, $2,000;

• Chair of the Governance and Public Affairs Committees, $1,500;

• Chair of the Audit Committee, $2,500; and

• Each member of the Audit Committee other than the chair, $1,000.

Nonemployee directors were reimbursed for actual travel and out-of-pocket expenses incurred in connection with their services.

Nonemployee 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 $500 a year in contributions by a director to non-profit organizations that have Internal Revenue Service (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 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 directors are permitted to make changes in measurement fund allocations quarterly.  Melanie Dressel was the only independent board member to defer any director fees during 2014.

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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, 2014 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 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, 2014.

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 (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), FSS Infrastructure Trust (formerly Macquarie-FSS Infrastructure Trust) (FIT), Padua MG Holdings LLC (PMGH) Canada Pension Plan Investment Board (USRE II) Inc. (CPPIB), 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, FIT, PMGH, CPPIB, 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 FIT is Level 21, 83 Clarence Street, 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 CPPIB 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 1100, 10830 Jasper Avenue, Edmonton, Alberta, Canada T5J 2B3.

^2.  Pursuant to that certain Pledge Agreement dated as of May 10, 2010, as amended on February 10, 2012, made by Puget Equico to JPMorgan Chase Bank, N.A., as administrative agent, 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 February 10, 2012, as amended and extended April 15, 2014, among Puget Energy., JPMorgan Chase Bank, N.A., as administrative agent, the other agents party thereto, and the lenders party thereto, (b) the Term Loans Agreements dated as of June 26, 2014 among Puget Energy, as borrower and JPMorgan Chase Bank, N.A., U.S. Bank, N.A. and CoBank, ACB, as individual lenders, and (c) the senior secured notes issued on December 6, 2010, June 3, 2011 and June 15, 2012.

^3.  Pursuant to that certain Borrower's Security Agreement dated as of May 10, 2010, as amended on February 10, 2012, 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 February 10, 2012, as amended and extended April 15, 2014, among Puget Energy as Borrower, JPMorgan Chase Bank, N.A., as administrative agent, the other agents party thereto, and the lenders party thereto, (b) the Term Loan Agreements dated as of June 26, 2014 among Puget Energy, as borrower, and JPMorgan Chase Bank, N.A., U.S. Bank, N.A. and CoBank, ACB, as individual lenders, and (c) the senior secured notes issued on December 6, 2010, June 3, 2011 and June 15, 2012.

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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, the President and Chief Executive Officer, and a director of Puget Energy and PSE, is married to Kyle Branum, a principal at the law firm Riddell Williams P.S., one of PSE’s primary law firms for nearly 50 years.  In 2014, Riddell Williams was paid $1.98 million for legal services provided to PSE and Mr. Branum is among the lawyers at Riddell Williams who provided such legal services.  This work was performed under the supervision of PSE's General Counsel and the compensation arrangements were comparable to other regional law firms providing legal services to PSE.

On October 10, 2014, U.S. Bancorp announced the appointment of Kimberly Harris to its board of directors effective October 20, 2014.  Ms. Harris is the president and chief executive officer of both Puget Energy and PSE.  U.S. Bancorp is the parent company of U.S. Bank N.A., which directly or through its subsidiaries or affiliates provides credit, banking, investment and trust services to both Puget Energy and PSE.  For the year ended December 31, 2014, Puget Energy and PSE paid a total of approximately $1.0 million in fees and interest to U.S. Bank N.A. and its subsidiaries or affiliates.

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, Steven Hooper (member of the Boards of both Puget Energy and PSE), Mary McWilliams (member of the Boards of both Puget Energy and PSE), Melanie Dressel (member of the Boards of both Puget Energy and PSE), and Herbert Simon (member of the Board of PSE) are independent under the 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.

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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 their respective subsidiaries), including some that are not required to be disclosed in this report as related-person transactions.  Messrs, Hooper and Simon, Ms. McWilliams and Ms. Dressel 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 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 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 the Company or the other entity, the Boards have 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.  Ms. Dressel, 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:

	2014				2013
(Dollars in Thousands)	Puget Energy		PSE		Puget Energy		PSE
Audit fees 1	$	2,041	$	1,878	$	2,118	$	1,926
Audit related fees 2	111		111		294		274
Tax fees 3	31		31		28		28
Other fees4	52		52		48		48
Total	$	2,235	$	2,072	$	2,488	$	2,276

_______________

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 2014 fees are estimated and include an aggregate amount of $1.1 million billed to Puget Energy and $1.0 million to PSE through December 2014.

²  Consists of work performed in connection with registration statements and other regulatory audits.

³  Consists of tax consulting and tax return reviews.

⁴  Consists of software and research tools.

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

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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 2014 and 2013, 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, as required for the years ended December 31, 2014, 2013 and 2012, consist of the following:

I. Condensed Financial Information of Puget Energy

II. Valuation of Qualifying Accounts and Reserves

3) Exhibits

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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:	February 27, 2015	Date:	February 27, 2015

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	February 27, 2015
(Kimberly J. Harris)	Chief Executive Officer
/s/ Daniel A. Doyle	Senior Vice President and
(Daniel A. Doyle)	Chief Financial Officer
/s/ Michael J. Stranik	Controller and Principal Accounting Officer
(Michael J. Stranik)
/s/ Melanie Dressel	Chair and Director
(Melanie Dressel)
/s/ Andrew Chapman	Director
(Andrew Chapman)
/s/ Daniel Fetter	Director
(Daniel Fetter)
/s/ Benjamin Hawkins	Director
(Benjamin Hawkins)
/s/ Steven W. Hooper	Director
(Steven W. Hooper)
/s/ Alan W. James	Director
(Alan W. James)
/s/ Christopher J. Leslie	Director
(Christopher J. Leslie)
/s/ David MacMillan	Director
(David MacMillan)

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/s/ Drew Murphy	Director
(Drew Murphy)
/s/ Mary O. McWilliams	Director
(Mary O. McWilliams)
/s/ Christopher Trumpy	Director
(Christopher Trumpy)
/s/ Herbert B. Simon	Director of PSE only
(Herbert B. Simon)

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EXHIBIT INDEX

Certain of the following exhibits are filed herewith.  Certain other of the following exhibits have heretofore been filed with the United States Securities and Exchange Commission (SEC) 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 Quarterly 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 Quarterly 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-3, 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	Eighty-eighth, Eighty-ninth and Ninetieth Supplemental Indentures defining the rights of the holders of Puget Sound Energy's Electric Utility First Mortgage Bonds (incorporated herein by reference to Exhibits 4.1 through 4.3 to Puget Sound Energy's Report on Form 10-Q for the quarter ended March 31, 2012, Commission File No. 1-4393).

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4.6	Ninety-first and Ninety-second supplemental Indentures defining the rights of the holders of Puget Sound Energy’s Electric Utility First Mortgage Bonds (incorporated herein by reference to Exhibit 4.6 to Puget Sound Energy’s Registration Statement on Form S-3, filed January 24, 2014, Registration No. 333-193555 and to Exhibit 4.4 to Puget Sound Energy’s Current Report on Form 8-K filed May 29, 2013).
4.7	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).
4.8	First, Sixth, Seventh, Sixteenth and Seventeenth Supplemental Indenture to the Gas Utility First Mortgage, dated as of April 1, 1957, 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-3, filed March 13, 2009, Registration No. 333-157960).
4.9	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 Annual Report on Form 10-K for the fiscal year ended September 30, 1986, Commission File No. 0-951).
4.10	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).
4.11	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 Quarterly 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 Annual 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 Annual 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 Annual 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).
4.12	Unsecured Debt Indenture, dated as of May 18, 2001, between Puget Sound Energy, Inc. and The Bank of New York Mellon 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).
4.13	Second Supplemental Indenture to the Unsecured Debt Indenture, dated June 1, 2007, between Puget Sound Energy, Inc. and The Bank of New York Mellon 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).
4.14	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).
4.15	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	Second Supplemental Indenture to the Indenture dated December 6, 2010 between Puget Energy, Inc. and Wells Fargo Bank, National Association defining the rights of Puget Energy’s Senior Secured Notes due September 1, 2021 (incorporated herein by reference to Exhibit 4.1 to Puget Energy’s Current Report on Form 8-K, filed June 6, 2011, Commission File No. 1-16305).
4.17	Third Supplemental Indenture between Wells Fargo Bank, National Association and Puget Energy, Inc. dated as of June 15, 2012 (incorporated by reference to Exhibits 4.1 to Puget Energy's Current Report on Form 8-K, filed June 18, 2012, Commission File No. 1-16305).
4.18	Trust Indenture, dated as of May 1, 2013 (the “Indenture”), by and between the City and Wells Fargo Bank, National Association, as trustee. (incorporated herein by reference to Exhibit 4.1 to Puget Sound Energy's Current Report on Form 8-K, dated May 30, 2013, Commission File No. 1-04393).
4.19	Loan Agreement, dated as of May 1, 2013, between Puget Sound Energy, Inc. and the City of Forsyth, Rosebud County, Montana. (incorporated herein by reference to Exhibit 4.2 to Puget Sound Energy's Current Report on Form 8-K, dated May 30, 2013, Commission File No. 1-04393).
4.20	Pledge Agreement, dated as of May 1, 2013, between Puget Sound Energy, Inc. and Wells Fargo Bank, National Association, as trustee. (incorporated herein by reference to Exhibit 4.3 to Puget Sound Energy's Current Report on Form 8-K, dated May 30, 2013, Commission File No. 1-04393).
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).

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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).

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	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	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).
	10.21	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).
	10.22	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).
	10.23	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).
	10.24	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).
	10.25	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).
	10.26	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).
	10.27	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).
	10.28	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).
	10.29	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).
	10.30	Credit Agreement dated as of February 10, 2012 among Puget Energy, Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative 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 8-K dated February 16, 2012, Commission File Nos. 1-16305 and 1-4393).
	10.31	Amendment No. 1 dated April 6, 2012 to Credit Agreement dated as of February 10, 2012 among Puget Energy, Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, the other agents party thereto, and the lenders party thereto (incorporated herein by reference to Exhibit 10.2 to Puget Energy's Report on Form 10-Q for the quarter ended March 31, 2012, Commission File No. 1-16305).
	10.32	Credit Agreement dated as of February 4, 2013 among Puget Sound Energy, Inc., as Borrower, Wells Fargo Bank, National Association, as Administration 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 8-K dated February 11, 2013, Commission File Nos. 1-16305 and 1-4393).
**	10.33	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).
**	10.34	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).
**	10.35	Puget Sound Energy, Inc. Amended and Restated Supplemental Executive Retirement Plan effective January 1, 2013.

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**	10.36	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).
**	10.37	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).
**	10.38	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).
**	10.39	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).
**	10.40	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).
**	10.41	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).
**	10.42	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).
**	10.43	Puget Energy, Inc. Amended and Restated 2005 Long-Term Incentive Plan, effective March 4, 2011 (incorporated herein by reference to Exhibit 10.52 to Puget Energy’s and Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2010, Commission File No. 1-16305 and 1-4393).
	10.44	Amendment No. 1 dated April 15, 2014 to Credit Agreement dated as of February 4, 2013 among Puget Sound Energy, Inc., as Borrower, Wells Fargo Bank, National Association, as Administrative 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 March 31, 2014, Commission File No. 1-16305 and 1-4393).
	10.45	Amendment No. 2 dated April 15, 2014 to Credit Agreement dated as of February 10, 2012 among Puget Energy, Inc., as Borrower, JPMorgan Chase Bank, National Association, as Administrative 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 March 31, 2014, Commission File No. 1-16305 and 1-4393).
*	12.1	Statement setting forth computation of ratios of earnings to fixed charges of Puget Energy, Inc. (2010 through 2014).
*	12.2	Statement setting forth computation of ratios of earnings to fixed charges of Puget Sound Energy, Inc. (2010 through 2014).
*	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 – Daniel A. Doyle.
*	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 – Daniel A. Doyle.
*	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 – Daniel A. Doyle.

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101 Financial statements from the annual report on Form 10-K of Puget Energy, Inc. and Puget Sound Energy, Inc. for the fiscal year ended December 31, 2014, filed on February 27, 2015, formatted in XBRL: (i) the Consolidated Statement of Income (Unaudited), (ii) the Consolidated Statements of Comprehensive Income (Unaudited), (iii) the Consolidated Balance Sheets (Unaudited), (iii) the Consolidated Statements of Cash Flows (Unaudited), and (iv) the Notes to Consolidated Financial Statements (submitted electronically herewith).

____________________

* Filed herewith.

** Management contract, compensating plan or arrangement.

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