Edgar Filing: PUGET SOUND ENERGY INC

10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K



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

For the fiscal year ended December 31, 2015



/ /	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

/ /

/X/

Puget Sound Energy, Inc.

Yes

/ /

/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

/ /

/X/

Puget Sound Energy, Inc.

Yes

/ /

/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/

/ /

Puget Sound Energy, Inc.

Yes

/X/

/ /

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/

/ /

Puget Sound Energy, Inc.

Yes

/X/

/ /

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

/ /

/X/

Puget Sound Energy, Inc.

Yes

/ /

/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	14
Electric Supply	16
Natural Gas Utility Operating Statistics	19
Natural Gas Supply for Natural Gas Customers	21
Energy Efficiency	23
Environment	23
Recent and Future Environmental Law and Regulation	24
Executive Officers of the Registrants	27
1A. Risk Factors	27
1B. Unresolved Staff Comments	33
2. Properties	33
3. Legal Proceedings	33
4. Mine Safety Disclosures	34

Part II
5. Market for Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	34
6. Selected Financial Data	35
7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	36
7A. Quantitative and Qualitative Disclosures about Market Risk	57
8. Financial Statements and Supplementary Data	61
Report of Management and Statement of Responsibility	62
Report of Independent Registered Public Accounting Firm – Puget Energy	63
Report of Independent Registered Public Accounting Firm – Puget Sound Energy	64
9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	129
9A. Controls and Procedures	129
9B. Other Information	130

Part III
10. Directors, Executive Officers and Corporate Governance	130
11. Executive Compensation	133
12. Security Ownership of Certain Beneficial Owners and Management and Related	154
Shareholder Matters
13. Certain Relationships and Related Transactions, and Director Independence	155
14. Principal Accountant Fees and Services	156

Part IV
15. Exhibits and Financial Statement Schedules	157
Signatures	158
Exhibit Index	160

DEFINITIONS



AFUDC	Allowance for Funds Used During Construction
AOCI	Accumulated Other Comprehensive Income
ARO	Asset Retirement and Environmental Obligations
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
ERF	Expedited Rate Filing
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	Generally Accepted Accounting Principles
GHG	Greenhouse Gases
GRC	General Rate Case
IRP	Integrated Resource Plan
IRS	Internal Revenue Service
ISDA	International Swaps and Derivatives Association
JPUD	Jefferson County Public Utility District
kW	Kilowatt (one kW equals one thousand watts)
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
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
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
REC	Renewable Energy Credit
REP	Residential Exchange Program
SEC	United States Securities and Exchange Commission
SERP	Supplemental Executive Retirement Plan
Washington Commission	Washington Utilities and Transportation Commission
WSPP	WSPP, Inc.

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. Puget Energy and PSE are collectively referred to herein as “the Company”. 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 and may be included in discussion of, among other things, our anticipated operating or financial performance, business plans and prospects, planned capital expenditures and other future expectations. In particular, these include statements relating to future actions, business plans and prospects, future performance expenses, the outcome of contingencies, such as legal proceedings, government regulation and financial results.

Forward-looking statements reflect current expectations and involve risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed. There can be no assurance that Puget Energy’s and PSE’s expectations, beliefs or projections will be achieved or accomplished.

In addition to other factors and matters discussed elsewhere in this report, including the risk factors described in Item 1A, some important factors that could cause actual results or outcomes for Puget Energy and PSE to differ materially from past results and 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), that may affect our ability to recover costs and earn a reasonable return, including but not limited to disallowance or delays in the recovery of capital investments and operating costs and discretion over allowed return on investment;
•	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 by products 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;
•	Changes in tax law, related regulations or differing interpretation or enforcement of applicable law by the Internal Revenue Service (IRS) or other taxing jurisdiction and PSE's ability to recover costs in a timely manner arising from such changes;
•	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, which would cause increases in costs of operations;
•	Accidents or natural disasters, such as hurricanes, windstorms, earthquakes, floods, fires and landslides, and other acts of God, terrorism, asset-based or cyber-based attacks, flu pandemic or similar significant events, 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 from creditworthy counterparties;
•	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, blackouts or large curtailments of transmission systems (whether PSE's or others'), or failure of the interstate natural gas pipeline delivering to PSE's system, all of which can affect PSE's ability to deliver power or natural gas to its customers and generating 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 to restart generation following a regional transmission disruption;
•	The ability of a natural gas or electric plant to operate as intended;



•	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 could impact PSE's ability to procure adequate supplies of natural gas, fuel or purchased power to serve its customers and the cost of procuring such supplies;
•	Variable hydrological conditions, which can impact streamflow and PSE's ability to generate electricity from hydroelectric facilities;
•	The ability to renew contracts for electric and natural gas supply and the price of renewal;
•	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;
•	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; 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.

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.

Puget Energy is owned through a holding company structure by Puget Holdings LLC (Puget Holdings). 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. 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 and 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.

Customers and Revenue Overview

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 tables present the number of PSE customers and revenue by customer class for electric and natural gas as of December 31, 2015 and 2014:



	Electric				Natural Gas
	December 31,		Percent		December 31,		Percent
	2015	2014	Change		2015	2014	Change
Customers: ¹
Residential	976,583	966,144	1.1	%	742,494	733,135	1.3	%
Commercial	123,681	121,814	1.5		55,208	55,021	0.3
Industrial	3,423	3,457	(1.0	)	2,397	2,392	0.2
Other	6,354	6,144	3.4		227	209	8.6
Total	1,110,041	1,097,559	1.1	%	800,326	790,757	1.2	%



	Electric				Natural Gas
	As of December 31, 2015
(Dollars in Thousands)	Revenue		Percentage		Revenue		Percentage
Revenue:
Residential	$	1,061,117	51.2	%	$	597,572	65.9	%
Commercial	867,786		41.9		268,044		29.6
Industrial	114,223		5.5		22,420		2.5
Other	30,359		1.4		18,666		2.0
Total	$	2,073,485	100	%	$	906,702	100	%

_______________


¹	At December 31, 2015, approximately 386,100 customers purchased both electricity and natural gas from PSE as compared to 381,500 at December 31, 2014.

PSE's revenues and associated expenses are not generated evenly throughout the year, primarily due to seasonal weather patterns, varying wholesale prices for electricity and the amount of hydroelectric energy supplies available to PSE, which make 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. 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 also month to month within a season, primarily as result of weather conditions. 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 for electric and natural gas operations are expected to normalize 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 natural gas operating revenues related to electric transmission and distribution, natural gas operations and general administrative costs from residential, commercial and industrial customers.

Capital Expenditures

In the five-year period ended December 31, 2015, PSE’s gross electric utility plant additions were $3.4 billion and retirements were $424.5 million. In the same five-year period, PSE’s gross natural gas utility plant additions were $748.4 million and retirements were $100.0 million and PSE’s gross common utility plant additions were $360.6 million and retirements were $228.3 million. Gross electric utility plant at December 31, 2015 was approximately $9.6 billion, which consisted of 36.0% distribution, 41.1% generation, 14.1% transmission and 8.8% general plant and other. Gross natural gas utility plant at December 31, 2015 was approximately $3.4 billion, which consisted of 93.0% distribution and 7.0% general plant and other. Gross common utility general and intangible plant at December 31, 2015 was approximately $548.7 million.

Employees

At December 31, 2015, PSE had approximately 2,800 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.

Puget Energy does not have any employees. PSE's employees provide employment services to Puget Energy and charges for their related salaries and benefits at cost.

Segment Information

Puget Energy operates one reportable business segment referred to as the regulated utility segment. For more information on this segment, see Note 17 to the consolidated financial statements included in Item 8 of this report.

Corporate Location

PSE’s and Puget Energy'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.

2013 Expedited Rate Filing, Decoupling and Centralia Decision

PSE filed a settlement agreement with the Washington Commission on March 22, 2013. The agreement was intended to settle all issues regarding decoupling, a power purchase agreement with TransAlta Centralia and the expedited rate filing (ERF) which is limited in scope and rate impact, includes the property tax tracker, and is intended to establish baseline rates on which the

decoupling mechanism is to operate. The Washington Commission placed the ERF and decoupling filings under a common procedural schedule.

On June 25, 2013, the Washington Commission issued final orders resolving the amended decoupling petition, the ERF filing and the Petition for Reconsideration (related to the TransAlta Centralia power purchase agreement). Order No. 7 in the ERF/decoupling proceeding approved PSE's ERF filing with a small change to its cost of capital from 7.80% to 7.77% to update long term debt costs. This order also approved the property tax tracker discussed below and approved the amended decoupling and rate plan filing with the further condition that PSE and the customers will share 50.0% each in earnings in excess of the 7.77% authorized rate of return. In addition, the rate plan increased allowed decoupling revenue per customer for the recovery of delivery system costs which will subsequently increase by 3.0% for the electric customers and 2.2% for the gas customers on January 1 of each year, until the conclusion of PSE's next general rate case (GRC), which will be filed before April 1, 2016. In the rate plan, rate increases are subject to a cap of 3.0% of total revenue for customers. Order No. 8 in the TransAlta Centralia proceeding granted in part and denied in part PSE's Petition for Reconsideration, clarifying certain portions of the Washington Commission's original order regarding TransAlta Centralia.

Rate mechanisms include: (1) trackers that typically track costs regarding a single specific costs during the previous 12-month period, and: (2) riders that project cost recovery during a forward looking 12-month period. Both allow rapid recovery of an expenditure without the lengthy process of a full GRC. The following table shows PSE’s rate filing and whether or not they are included in decoupling rates:



Rate Filings	Electric	Gas
Baseline rates	Yes	Yes
Annual rate plan increase	Yes	Yes
Expedited rate filing rider	Yes	Yes
Merger credit	No	No
Power cost only rates mechanism	No	N/A
Federal incentive tracker	No	N/A
Low income rates tracker	No	No
Pipeline cost recovery mechanism tracker	N/A	No
Prior year decoupling deferral tracker	No	No
Property tax tracker	No	No
Renewable energy credit tracker	No	N/A
Residential exchange credits tracker	No	N/A
Conservation costs rider	No	No
PGA rider	N/A	No

Decoupling Filings

The Washington Commission has allowed PSE to record a monthly adjustment to its electric and natural gas operating revenues related to electric transmission and distribution, natural 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 natural 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. The revenue recorded under the decoupling mechanisms will be affected by customer growth and not actual consumption. Following each calendar year, PSE will recover or refund the difference between allowed decoupling revenue and the corresponding actual revenue to affected customers during the following May to April time period. The allowed decoupling revenue per customer for the recovery of delivery system costs will subsequently increase by 3.0% for the electric customers and 2.2% for the natural gas customers on January 1 of each year. The decoupling mechanism will end on February 28, 2017 unless the continuation of the mechanism is approved in PSE’s next GRC filing which PSE is required to file by April 1, 2016 at the latest.

1, 2015. As noted earlier, the Company is also limited to a 3.0% annual decoupling related cap on increases in total revenue. This limitation was triggered for certain rate classes. The resulting amount of deferral that was not included in the 2015 rate increase is $1.9 million for electric revenue and $8.2 million for natural gas revenue that was accrued through December 31, 2014.

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 customers of $10.6 million, or 0.5% annually, and a rate decrease for natural gas customers of $1.0 million, or 0.1% annually.

In addition, PSE exceeded the earnings test threshold for its natural gas business in 2014. As a result, PSE recorded a reduction in natural gas decoupling deferral and revenue of $1.3 million. This was reflected as a reduction to the natural gas rate increases noted above. The customers share of the over earnings will be returned to customers over the subsequent 12-month period beginning May 1 of each year.

Electric Rate Filings

Federal Incentive Tracker Tariff

The Federal Incentive tracker tariff passes the benefits associated with treasury grants received by the company and production tax credits available through to its customers. The filing results in a credit back to customers of treasury grant amortization and pass-through of interest and any related true-ups. The filing is adjusted annually for new Federal benefits, actual versus forecast interest and to true-up for actual load being different than the forecasted load set in rates.

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



Effective Date	Average Percentage Increase (Decrease) in Rates		Total credit to be passed back to eligible customers (Dollars in Millions)
January 1, 2016	(0.2	)%	$	(57.3	)
January 1, 2015	(0.2	)	(55.2		)
January 1, 2014	(0.3	)	(58.5		)
February 1, 2013	(2.8	)	(58.4		)

Power Cost Adjustment Mechanism

PSE currently 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” included in revenue requirements. The “power cost baseline” is 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 currently applicable is as follows:



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

On August 7, 2015, the Washington Commission issued an order approving the settlement proposing changes to the PCA mechanism. The settlement agreement will not take effect until January 1, 2017. Key components of the settlement will result in the following changes to the PCA mechanism:



Annual Power Cost Variability	Company's Share				Customers’ Share
	Over		Under		Over		Under
+/- $17 million	100	%	100	%	—	%	—	%
+/- $17 million - $40 million	35		50		65		50
+/- $40 + million	10		10		90		90


•	Reduction to the cumulative deferral trigger for surcharge or refund from $30.0 million to $20.0 million;

•

Removal of fixed production costs from the PCA mechanism and placing them in the decoupling mechanism, assuming the decoupling mechanism continues as part of the next GRC. If decoupling was not to continue, those fixed production costs would be treated the same as other non-PCA costs unless permission to treat them in another manner is obtained from the Washington Commission. These fixed production costs include: (i) return and depreciation/amortization on fixed production assets and regulatory assets and liabilities; (ii) return on, depreciation, transmission expense and revenues on specific transmission assets; and (iii) hydro, other production and other power related expenses and O&M costs;


•	Suspension of the requirement that a GRC must be filed within three months after rates are approved in a Power Cost Only Rate Case (PCORC), and agreeing, for a five-year period, that PSE will not file a GRC or PCORC within six months of the date rates go into effect for a PCORC filing; and


•	Establishment of a five-year moratorium on changes to the PCA/PCORC.

PSE had an unfavorable PCA imbalance during the year ended December 31, 2015, due to under recovering $8.7 million of power costs that exceeded the “power cost baseline” level of which no amounts were apportioned to customers. This compares to an unfavorable imbalance of $40.1 million for the year ended December 31, 2014 of which $10.1 million was apportioned to customers.

Power Cost Only Rate Case

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 GRC.

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



Effective Date	Average Percentage Increase (Decrease) in Rates		Increase (Decrease) in Revenue (Dollars in Millions)
December 1, 2014	(0.9	)%	$	(19.4	)
November 1, 2013	(0.5	)	(10.5		)

Property Tax Tracker Mechanism

The purpose of the property tax tracker mechanism is to pass through the cost of all property taxes incurred by the Company. The mechanism was implemented in 2013 and removed property taxes from general rates for inclusion in the tracker mechanism. After the implementation, the mechanism acts as a tracker rate schedule and collects the actual amount of property taxes assessed. The tracker will be adjusted each year in May based on that year's assessed property taxes and true-ups to the rate from the prior year.

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



Effective Date	Average Percentage Increase (Decrease) in Rates		Increase (Decrease) in Revenue (Dollars in Millions)
May 1, 2015	0.4	%	$	8.4
May 1, 2014	0.5		11.0

Conservation Rider

The electric conservation rider collects revenue to cover the costs incurred in providing services and programs for conservation. Rates change annually on May 1 to collect the annual budget that started the prior January.

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



Effective Date	Average Percentage Increase (Decrease) in Rates		Increase (Decrease) in Revenue (Dollars in Millions)
May 1, 2014	0.6	%	$	12.2

Natural Gas Rate Filings

Purchased Gas Adjustment

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 or payable balance in the PGA mechanism reflects an underrecovery or over recovery, respectively, of natural gas cost through the PGA mechanism.

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



Effective Date	Average Percentage Increase (Decrease) in Rates		Increase (Decrease) in Revenue (Dollars in Millions)
November 1, 2015	(17.4	)%	$	(185.9	)
November 1, 2014	2.5		23.3
November 1, 2013	0.4		4.0

Cost Recovery Mechanism

The purpose of the Cost Recovery Mechanism (CRM) is to recover depreciation expense and return on the investment in the Company's pipeline replacement program to enhance the safety of the natural gas distribution system until included in base rates for gas service.

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



Effective Date	Average Percentage Increase (Decrease) in Rates		Increase (Decrease) in Revenue (Dollars in Millions)
November 1, 2015	0.5	%	$	5.3
November 1, 2014	0.2		2.3

Property Tax Tracker Mechanism

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



Effective Date	Average Percentage Increase (Decrease) in Rates		Increase (Decrease) in Revenue (Dollars in Millions)
June 1, 2015	(0.2	)%	$	(2.3	)
May 1, 2014	0.6		5.6

For additional information on electric and natural gas rates, see Note 3 to the consolidated financial statements included in Item 8 of this report.

ELECTRIC UTILITY OPERATING STATISTICS



	Year Ended December 31,
	2015			2014			2013
Generation and purchased power, MWh
Company-controlled resources	12,747,014			11,640,504			12,421,626
Contracted resources	5,911,012			4,050,062			4,498,204
Non-firm energy purchased	5,315,266			8,001,425			7,565,140
Total generation and purchased power	23,973,292			23,691,991			24,484,970
Less: losses and Company use	(1,514,272		)	(1,724,501		)	(1,581,108		)
Total energy sales, MWh	22,459,020			21,967,490			22,903,862
Electric energy sales, MWh
Residential	10,164,703			10,349,928			10,769,100
Commercial	8,999,068			8,900,863			9,118,720
Industrial	1,257,958			1,226,588			1,229,556
Other customers	94,847			98,499			98,579
Total energy sales to customers	20,516,576			20,575,878			21,215,955
Sales to other utilities and marketers	1,942,444			1,391,612			1,687,907
Total energy sales, MWh	22,459,020			21,967,490			22,903,862
Transportation, including unbilled	2,012,827			2,099,219			2,089,435
Electric energy sales and transportation, MWh	24,471,847			24,066,709			24,993,297
Electric operating revenue by classes
(Dollars in Thousands)
Residential	$	1,061,117		$	1,003,205		$	1,115,694
Commercial	867,786			824,778			847,704
Industrial	114,223			107,750			108,433
Other customers	20,216			19,707			19,192
Total operating revenue from customers	2,063,342			1,955,440			2,091,023
Transportation, including unbilled	10,143			9,502			8,738
Sales to other utilities and marketers	46,666			41,680			54,444
Decoupling revenue	13,630			25,735			(14,989		)
Other decoupling revenue¹	(16,634		)	5,609			—
Miscellaneous operating revenue	11,321			45,831			17,704
Total electric operating revenue	$	2,128,468		$	2,083,797		$	2,156,920
Number of customers served (average):
Residential	970,830			960,708			956,783
Commercial	123,072			121,332			119,833
Industrial	3,434			3,437			3,474
Other	6,283			6,023			5,274
Transportation	16			17			17
Total customers	1,103,635			1,091,517			1,085,381

_______________


¹	Includes amortization of prior year collection/refund, reduction related to excess rate of return, and a reduction related to amounts that will not be collected within 24 months.

ELECTRIC UTILITY OPERATING STATISTICS (Continued)



	Year Ended December 31,
	2015			2014			2013
Average kWh used per customer:
Residential	10,470			10,773			11,256
Commercial	73,120			73,360			76,095
Industrial	366,324			356,877			353,931
Other	15,096			16,354			18,691
Average revenue per customer:
Residential	$	1,093		$	1,044		$	1,166
Commercial	7,051			6,798			7,074
Industrial	33,262			31,350			31,213
Other	3,218			3,272			3,639
Average retail revenue per kWh sold:
Residential	$	0.1044		$	0.0969		$	0.1036
Commercial	0.0964			0.0927			0.0930
Industrial	0.0908			0.0878			0.0882
Other	0.2131			0.2001			0.1947
Average retail revenue per kWh sold	$	0.1006		$	0.0950		$	0.0986
Heating degree days	3,800			3,829			4,734
Percent of normal - NOAA¹30-year average	80.5		%	81.2		%	100.3		%
Load factor ²	56.2		%	52.3		%	51.2		%

_______________


¹	National Oceanic and Atmospheric Administration (NOAA).


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

ELECTRIC SUPPLY

At December 31, 2015, 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 4,887 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. When it is more economical for PSE to purchase power than to operate its own generation facilities, PSE will purchase spot market energy when sufficient transmission capacity is available.

The following table shows PSE’s electric energy supply resources and energy production for the years ended December 31, 2015 and 2014:



	Peak Power Resources At December 31,						Energy Production At December 31,
	2015			2014			2015			2014
	MW	%		MW	%		MWh	%		MWh	%
Purchased resources:
Columbia River PUD contracts	708	14.5	%	709	14.5	%	3,325,450	13.9	%	3,318,746	14.0	%
Other hydroelectric	85	1.7		85	1.7		179,057	0.7		185,943	0.8
Other producers	463	9.5		464	9.5		2,200,098	9.2		815,640	3.4
Wind	56	1.1		56	1.2		130,777	0.5		140,716	0.6
Short-term wholesale energy purchases	N/A	—		N/A	—		5,390,896	22.5		7,590,442	32.1
Total purchased	1,312	26.8	%	1,314	26.9	%	11,226,278	46.8	%	12,051,487	50.9	%
Company-controlled resources:
Hydroelectric	254	5.2	%	254	5.2	%	706,231	2.9	%	1,000,201	4.2	%
Coal	677	13.9		677	13.8		4,495,032	18.8		4,509,567	19.0
Natural gas/oil	1,871	38.3		1,871	38.3		5,830,318	24.3		4,154,983	17.5
Wind	773	15.8		773	15.8		1,715,433	7.2		1,975,753	8.3
Total company-controlled	3,575	73.2	%	3,575	73.1	%	12,747,014	53.2	%	11,640,504	49.1	%
Total resources	4,887	100.0	%	4,889	100.0	%	23,973,292	100.0	%	23,691,991	100.0	%

Company–Owned Electric Generation Resources

At December 31, 2015, 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	Hydroelectric	91	1959
Lower Baker River	Hydroelectric	109	1925; reconstructed 1960; upgraded 2001 and 2013
Snoqualmie Falls	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.

Columbia River Electric Energy Supply Contracts

During 2015, approximately 13.9% of PSE’s energy supply 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, 2015, 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).

PSE expects to participate in an Energy Imbalance Market (EIM) operated by the California Independent System Operator (ISO) effective October 1, 2016, which is expected to reduce costs for PSE customers, enhance system reliability, integrate variable energy resources, and leverage geographic diversity of electricity demand and generation resources.

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 2015, 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 financial hedges to manage the cost of natural gas. PSE utilizes natural gas storage capacity and transportation 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 2015, approximately 77% of natural gas purchased for the power portfolio originated in Canada and 23% 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. The 2015 IRP was filed on November 30, 2015 and identified the following capacity needs:



	2016	2017	2018	2019	2020
Projected MW shortfall/(surplus)	(160)	(28)	(43)	(44)	(71)

The expected capacity needs reflect the mix of energy efficiency programs deemed cost effective in the 2015 IRP. In 2015, PSE renewed all the Mid-Columbia (Mid-C) transmission available for renewal during the year to meet peak capacity needs.

PSE projects that beginning in 2021 its future energy needs will exceed current resources in its supply portfolio. The IRP identifies declining regional surpluses, 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 wholesale market, subject to the sharing bands of the PCA mechanism, at a cost that could, in the absence of regulatory relief, increase its expenses and reduce earnings and cash flows.

NATURAL GAS UTILITY OPERATING STATISTICS



	Year Ended December 31,
	2015			2014		2013
Natural gas operating revenue by classes (dollars in thousands):
Residential	$	597,572		$	644,055	$	682,636
Commercial firm	239,849			252,235		259,315
Industrial firm	21,533			23,887		25,830
Interruptible	29,082			30,770		35,545
Total retail gas sales	888,036			950,947		1,003,326
Transportation services	18,666			17,069		16,531
Decoupling revenue	51,981			29,116		(5,165		)
Other decoupling revenue ¹	(26,038		)	2,208		—
Other	14,904			13,520		13,665
Total natural gas operating revenue	$	947,549		$	1,012,860	$	1,028,357
Number of customers served (average):
Residential	737,339			727,244		716,518
Commercial firm	54,646			54,328		53,840
Industrial firm	2,378			2,383		2,394
Interruptible	429			449		429
Transportation	221			208		204
Total customers	795,013			784,612		773,385
Natural gas volumes, therms (thousands):
Residential	492,997			527,423		572,668
Commercial firm	230,507			242,095		255,543
Industrial firm	23,777			26,481		28,469
Interruptible	43,931			46,113		54,554
Total retail natural gas volumes, therms	791,212			842,112		911,234
Transportation volumes	220,392			211,429		219,696
Total volumes	1,011,604			1,053,541		1,130,930

_____________


¹	Includes amortization of prior year collection/refund, reduction related to excess rate of return, and a reduction related to amounts that will not be collected within 24 months.

NATURAL GAS UTILITY OPERATING STATISTICS (Continued)



	Year Ended December 31,
	2015			2014			2013
Working gas volumes in storage at year end, therms (thousands):
Jackson Prairie	78,337			81,889			76,772
Clay Basin	54,199			29,719			31,594
Plymouth	1,828			2,206			2,227
Average therms used per customer:
Residential	669			725			799
Commercial firm	4,218			4,456			4,746
Industrial firm	9,999			11,112			11,892
Interruptible	102,403			102,701			127,164
Transportation	997,249			1,016,486			1,076,943
Average revenue per customer:
Residential	$	810		$	886		$	953
Commercial firm	4,389			4,643			4,816
Industrial firm	9,055			10,024			10,789
Interruptible	67,791			68,530			82,855
Transportation	84,460			82,063			81,033
Average revenue per therm sold:
Residential	1.212			1.221			1.192
Commercial firm	1.041			1.042			1.015
Industrial firm	0.906			0.902			0.907
Interruptible	0.662			0.667			0.652
Average retail revenue per therm sold	1.122			1.129			1.101
Transportation	0.085			0.081			0.075
Heating degree days	3,800			3,829			4,734
Percent of normal - NOAA 30-year average	80.5		%	81.2		%	100.3		%

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 hedges to manage volatility in the cost of natural gas. All of PSE’s natural gas supply is ultimately transported through the facilities of Northwest Pipeline GP (NWP), the sole interstate pipeline delivering directly into PSE’s service territory. Accordingly, delivery of natural gas supply to PSE’s natural gas system is dependent upon the reliable operations of NWP.



Peak Firm Natural Gas Supply ¹	At December 31,
	2015				2014
	Dth per Day		%		Dth per Day		%
Purchased gas supply:
British Columbia	210,000		23.4	%	243,000		26.4	%
Alberta	110,000		12.2	%	99,000		10.7	%
United States	118,100		13.1	%	127,000		13.8	%
Total purchased natural gas supply	438,100		48.7	%	469,000		50.9	%
Purchased storage capacity:
Jackson Prairie	48,400		5.4	%	48,400		5.3	%
Clay Basin	61,600		6.8	%	52,700		5.7	%
Total purchased storage capacity	110,000		12.2	%	101,100		11.0	%
Owned storage capacity:
Jackson Prairie	348,700		38.8	%	348,700		37.8	%
Propane and LNG	2,500		0.3	%	2,500		0.3	%
Total owned storage capacity	351,200		39.1	%	351,200		38.1	%
Total peak firm natural gas supply	899,300		100.0	%	921,300		100.0	%
Other and commitments with third parties	(6,200	)	*		(5,900	)	*
Total net peak firm natural gas supply	893,100		*		915,400		*

_______________


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


*	Not meaningful and/or applicable.

For base load, peak management and supply reliability purposes, PSE supplements its firm natural gas supply portfolio by purchasing natural gas in periods of lower demand, 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; as well as 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 2015, approximately 57.0% of natural gas purchased by PSE for its natural gas customers originated in British Columbia, 24.0% originated in Alberta and 19.0% 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 periods of lower demand to minimize costs. Natural gas is marketed outside of PSE’s service territory (off-system sales) to optimize resources when on-system customer demand requirements permit and market economics are favorable; 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 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 in a short 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 397,100 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 44% 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 641,000 Dth of 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 6,100 Dth per day of firm withdrawal capacity and 178,500 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 two and four years and has rights to extend such agreements. PSE has temporarily released a portion of its Clay Basin storage services to third parties, and its net storage capacity and maximum firm withdrawal capacity at Clay Basin is 8.9 million Dth and 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.

During 2014, PSE, working with NWP determined that the pipeline redelivery service to PSE from NWP’s Plymouth LNG facility could no longer be considered firm during peak conditions. As a result, PSE terminated the service agreement effective October 31, 2015 and removed the resource from its natural gas firm portfolio. In 2015, PSE and NWP negotiated a new contract for Plymouth LNG service for PSE’s generation fleet, which provides for LNG storage services of 241,700 Dth of PSE-owned natural gas at Plymouth, with a maximum daily deliverability of 70,500 Dth. PSE will use the Plymouth contract as an alternate supply source for natural gas required to serve PSE’s generation fleet during peak periods on a daily or intra-day basis. In addition, PSE acquired 15,000 Dth/day of firm pipeline capacity for the generation fleet. The balance of the LNG capacity will be delivered using firm NWP pipeline transportation service previously acquired to serve PSE’s generation fleet.

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 delivers 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 539,000 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 453,000 Dth per day of seasonal firm capacity on NWP to provide for delivery of natural gas stored at Jackson Prairie. PSE holds approximately 253,000 Dth per day of firm transportation capacity on NWP to supply natural gas to its electric generating facilities. In addition PSE holds over 34,000 Dth per day of seasonal firm capacity on NWP to provide for delivery of natural gas stored in Jackson Prairie for its electric generating facilities. PSE’s firm transportation capacity contracts with NWP have remaining terms ranging from one to 29 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 130,000 Dth per day under various contracts, with remaining terms of two to four years. PSE has other firm transportation capacity on Westcoast’s pipeline, which supplies the electric generating facilities, totaling 84,000 Dth per day, with remaining terms of one to three years and an option

for PSE to renew its rights under the Westcoast contract. PSE has firm transportation capacity for its natural gas customers on NOVA and Foothills pipelines, each totaling approximately 80,000 Dth per day, with remaining terms of two to eight years and an option for PSE to renew its rights on the capacity on NOVA and Foothills pipelines. PSE has other firm transportation capacity on NOVA and Foothills pipelines, which supplies the electric generating facilities, each totaling approximately 40,000 Dth per day, with remaining terms of five to eight years. PSE’s firm transportation capacity for its natural gas customers on the GTN pipeline, totaling over 77,000 Dth per day, has a remaining term of eight years and PSE has a first right-of-refusal to extend such contracts under current FERC rules. PSE has other firm transportation capacity on GTN pipeline, which supplies the electric generating facilities, totaling 40,000 Dth per day, with remaining terms of five to eight years.

Capacity Release

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

ENERGY EFFICIENCY

PSE is required under Washington state law to pursue 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 assistance with gross margin erosion associated with reduced energy sales. To address this issue, PSE received approval in 2013 from the Washington Commission for electric and natural gas decoupling mechanisms, which mitigates gross margin erosion resulting from the Company's energy efficiency efforts.

Since 1997, PSE has recovered direct electric energy efficiency (or conservation) expenditures through an electric rider mechanism. To recover natural gas expenditures, from 1997 to 2011, PSE used a tracker mechanism, which recovered actual natural gas expenditures in the year following the year in which the expenditures were incurred. In 2012, the Washington Commission directed PSE to convert natural 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 coal-fired steam electric generation facility (Colstrip), Montana. All these facilities are governed by the Clean Air Act (CAA), and all have CAA Title V operating permits, which must be renewed every five years. This renewal process could result in additional costs to the plants. PSE continues to monitor the permit renewal process 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 Treaty 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

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 to which PSE is subject include the Comprehensive Environmental Response, Compensation and Liability Act (federal) and, in Washington, the Model Toxics Control Act (state). PSE is also subject to applicable remediation laws in the state of Montana for its ownership interest in Colstrip. 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.

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 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 in Washington, 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.

PSE's Greenhouse Gas Emission Reporting

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 environmental protection agency (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 2014 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 important 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.

Federal Proposed and Final Greenhouse Gas Rules

On January 8, 2014, the 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.

On August 3, 2015, the EPA announced a final rule combining its new and modified proposals into one rulemaking and making several changes. The rule was published on October 23, 2015, and separates standards for new power plants fueled by natural gas and coal. New natural gas power plants can emit no more than 1,000 lbs. of CO₂/MWh which is achievable with the latest combined cycle technology. New coal power plants can emit no more than 1,400 lbs. of CO₂/MWh, which is less stringent than the draft rule. The standard for coal plants would not specifically require CCS but CCS was reaffirmed by the EPA as the “best system of emission reductions” (BSER). These 111(b) standards are implemented by the states, but states do not have much flexibility to alter the standards set by the EPA.

On June 2, 2014, the EPA proposed a rule under section 111(d) of the Clean Air Act for the control of CO₂ emissions from existing fossil fuel-fired power plants. The proposed rule was 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 applied its 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 announced the final rule for 111(d), the Clean Power Plan rule, on August 3, 2015 and published it on October 23, 2015. The rule included several changes from the draft rule. Specifically, the EPA excluded energy efficiency from one of four "building blocks" identified in the draft rule, leaving just three building blocks (i) increased efficiency for coal plants, (ii) greater utilization of natural gas plants and (iii) increased renewable sources. In the final rule, the EPA provided more flexibility in achieving interim goals by phasing in the reduction and giving states the option to set their own interim compliance glide path and pushing the start of compliance to 2022. The EPA also adjusted the 2012 baseline to address hydroelectricity variability and provided specific CO₂ mass targets by year for each state.

States have broad flexibility to pick a rate-based or mass-based approach and can design compliance options and decide how to allocate credits and whether to allow trading. The EPA also gave states the option of seeking additional time, if necessary, to formulate a state plan. States must submit something within one year but can request up to an additional two years for development of a state plan. Thus, states must submit a plan for implementing CO₂ reductions to the EPA one to three years following issuance of the final rule.

Based on the October 2015 final version of the rule, the final CO₂ goal for Montana became 26% more stringent than the draft version and the final CO₂ goal for Washington became 35% less stringent. By 2030 Montana must reduce CO₂ emissions from coal plants from 20.5 million tons of CO₂ to 11.3 million tons of CO₂ which is a 45% reduction in CO₂ emissions. For reference, Colstrip Units 1, 2, 3 and 4 combined emit 18 million tons of CO₂.

State Proposed Greenhouse Gas Rule

On January 6, 2016 the Washington Department of Ecology (Ecology) published a draft Clean Air Rule that establishes GHG emission reduction standards for certain stationary sources, petroleum fuel producers or importers, and natural gas distributors operating in Washington state. The “certain stationary sources” covered include power plants, petroleum refineries, metal manufacturers, waste facilities and certain organizations responsible for 100,000 metric tons CO₂ emissions.

Natural gas distribution emissions are covered from the combustion of natural gas. Natural gas distributors are not responsible for CO₂ emissions from natural gas supplied to another covered party (i.e., a party that emits greater than prescribed thresholds, see below).

As proposed, when the rule goes into effect in 2017 the Ecology will set a baseline for each source based on at least a three-consecutive-year average between 2012 and 2016. The Ecology will then set a compliance pathway for each source that requires a 1 2/3% (one and two-thirds percent) reduction in CO₂ emissions per year (5% every three years) from the baseline. Covered parties under this rule must (1) reduce their covered GHG emissions to meet the reduction pathway or (2) obtain emission reductions from (a) other covered parties, (b) GHG emission reduction projects or (c) external emission market programs.

The starting compliance threshold for covered parties is 100,000 metric tons/year (MT/yr) CO₂ emissions, and this will decrease by 5,000 tons every year from 2017 to 2035. By 2035, sources emitting 70,000 tons and over must comply with the rule. PSE will continue to monitor and participate in the rulemaking process associated with this measure.

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 PSE continues to meet the requirement.

The EPA published the final Mercury and Air Toxics Standard (MATS) in February 2012. Generating units were given 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. Colstrip meets, or is expected to meet the MATS limits for mercury and acid gases by April 2016.

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 the final decision by the Ninth Circuit was issued June 9, 2015. The Ninth Circuit Court of Appeals reviewed the EPA’s first phase requirements for Colstrip and found that the EPA had not adequately justified the need for two of the control technologies and remanded these two issues back to the EPA.

The ruling in no way affects the future planning periods for the Regional Haze program or the glide path. The current EPA assessment is that the state of Montana will require significant emission reductions to meet the natural visibility goal by 2064 which means that additional emission reductions will be necessary in future 10-year planning periods, beginning in the 2018-2028 period, and there is risk and uncertainty regarding potential costs.

Coal Combustion Residuals

On April 17, 2015, the EPA published a final rule, effective October 19, 2015, that regulates CCRs under the Resource Conservation and Recovery Act, Subtitle D. The CCR rule addresses the risks from coal ash disposal, such as leaking of contaminants into ground water, blowing of contaminants into the air as dust, and the catastrophic failure of coal ash containment structures by establishing technical design, operation and maintenance, closure and post closure care requirements for CCR landfills and surface impoundments, and corrective action requirements for any related leakage. The rule also sets forth recordkeeping and reporting requirements including posting specific information related to CCR surface impoundments and landfills to publicly-accessible websites.

PCB Handling and Disposal

In April 2010, the EPA issued an Advanced Notice of Proposed Rulemaking (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 was scheduled to be published in July 2015 but due to the number of comments received by the EPA, the rule has undergone multiple extensions and revisions. The EPA recently updated its schedule once again and the proposal is now slated for publication in June 2016. 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 26, 2016 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	51	President and Chief Executive Officer since March 2011; President July 2010 – February 2011.
D. A. Doyle	57	Senior Vice President and Chief Financial Officer since November 2011. Prior to PSE, he was President of Wisconsin Sports Development Corporation June 2010 – November 2011.
S. R. Secrist	54	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.
M. J. Stranik	52	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 26, 2016 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	51	President and Chief Executive Officer since March 2011; President July 2010 – February 2011.
D. A. Doyle	57	Senior Vice President and Chief Financial Officer since November 2011. Prior to PSE, he was President of Wisconsin Sports Development Corporation June 2010 – November 2011.
P. K. Bussey	59	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.
B. K. Gilbertson	52	Senior Vice President, Operations since March 2015; Vice President, Operations March 2013 – February 2015; Vice President, Operations Services February 2011 – February 2013; Director, Operations Performance 2007 – January 2011.
M. D. Mellies	55	Senior Vice President and Chief Administrative Officer since February 2011; Vice President Human Resources 2005 – January 2011.
S. R. Secrist	54	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.
M. J. Stranik	52	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.

RISKS RELATING TO PSE’s REGULATORY AND RATE-MAKING PROCEDURES

PSE's regulated utility business is subject to various federal and state regulations. PSE's regulatory risks include, but not limited to, the following:

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. In addition, proceedings with the Washington Commission typically involve multiple stakeholder parties, including consumer advocacy groups and various consumers of energy, who have differing concerns but who have the common objective of limiting rate increases or decreasing rates. 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 costs during a particular test year, adjusted for certain normalizing adjustments. Power costs on the other hand, are normalized for market, weather and hydrological condition during the applicable rate year, the ensuing 12-month period before rates become effective. The Washington Commission determines the rates PSE may charge to its natural gas customers based on historic costs during a particular test year. Natural gas costs are adjusted through the PGA mechanism, as discussed previously. If in a specific year PSE’s costs are higher than the amounts used by the Washington Commission to determine the rates, revenue may not be sufficient to permit PSE to earn its allowed return or to cover its costs. In addition, the Washington Commission has the authority to determine 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 is currently subject to a Washington Commission order that requires PSE to share its excess earnings above the authorized rate of return with customers.

The Washington Commission previously approved an electric and natural gas decoupling mechanism for the recovery of its delivery-system costs, along with an ERF, a rate plan and an earnings sharing mechanism that requires PSE and its customers to share in any earnings in excess of the authorized rate of return of 7.77% during the term of the rate plan. The earnings test is done for each service (electric/natural gas) separately, so PSE would be obligated to share the earnings for one service exceeding the threshold, even if the other service did not meet the earnings test. PSE has been in a stay out period, during which time it could not file for general rate increases (unless for emergency rate relief). PSE must file a GRC no later than April 1, 2016, at which time the decoupling mechanism will be subject to continuation pending the result of the 2016 GRC, which PSE plans to file in March 2016.

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.

RISKS RELATING TO PSE’s OPERATION

PSE’s cash flow and earnings could be adversely affected by potential high prices and volatile markets for purchased power, 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 PSE's 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 energy supply needs and/or purchases in wholesale markets of high volumes of energy at prices above the amount recovered in retail rates due to:


•	Below normal levels of generation 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, or the effects of large-scale natural disasters on a substantial portion of distribution infrastructure; and


•	Failure of a counterparty to deliver capacity or energy purchased by PSE.

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 or increase expenditures, including:


•	Facility shutdowns due to a breakdown or failure of equipment or processes;


•	Volatility in prices for fuel and fuel transportation;


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


•	Regulatory compliance obligations and related costs, including any required environmental remediation, and any new laws and regulations that necessitate significant investments in our generating facilities;


•	Labor disputes;


•	Operator error or safety related stoppages;


•	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 vigilant security programs and procedures to protect against the continuous threat of physical asset and cyber-based attacks, and as a result, PSE may be required to expend significant dollars and other resources to protect against existing and ensuing threats.

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

In connection with matching PSE's energy needs and available 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 for delivery of energy supply or contractually required payments related to PSE's energy supply portfolio. 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.

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 fulfill these legal requirements, PSE must spend significant sums of money to comply with these 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 GHG legislation, including an emission performance standard provision and the EPA set CO₂ emission standards with specific state goals. 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.

PSE's operating results fluctuate on a seasonal and quarterly basis and can be impacted by various impacts of climate change.

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's hydroelectric resources are also dependent on snow conditions in the Pacific Northwest.

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 and also require significant expenditures by PSE. 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 depends on an aging work force and third party vendors to perform certain important services and may be negatively affected by its inability to attract and retain professional and technical employees or the unavailability of vendors.

PSE is subject to workforce factors, including but not limited to an aging workforce, loss or retirement of key personnel and availability of qualified personnel. 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. Also, the costs associated with attracting and retaining qualified employees could reduce earnings and cash flows.

PSE continues to be concerned about the availability and aging of skilled workers for special complex utility functions. PSE also hires third party vendors 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.

Potential municipalization 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. Although PSE is compensated in connection with the town or city's acquisition of its assets, any such loss of customers and related revenue could negatively affect PSE's future financial condition.

Technological developments may have an adverse impact on PSE's financial condition.

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 FINANCE

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 necessary for future growth, 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, 2015. 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. 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, 2015, no amounts were drawn and outstanding under the PSE credit facilities. In addition, Puget Energy has issued $1.8 billion in senior secured notes, whereas PSE, as of December 31, 2015 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, the ability to hedge in wholesale markets and the ability to pay dividends.

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

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

PSE may not declare or make any dividend distribution unless on the date of distribution PSE’s corporate credit/issuer rating is investment grade, or if its credit ratings are below investment grade, PSE’s ratio of earnings before interest, tax, depreciation

and amortization (EBITDA) to interest expense for the most recently ended four fiscal quarter periods prior to such date is equal to or greater than 3 to one.

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. These judgments may include reserves for potential adverse outcomes regarding tax positions that may be subject to challenge by the taxing authorities. Disputes over interpretations of tax laws may be settled with the taxing authority in examination, upon appeal or through litigation.

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. Changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions, may also increase PSE's funding requirements related to the pension plans. Any contributions to PSE’s plans in 2016 and beyond as well as the timing of the recovery of such contributions in GRCs could impact PSE’s cash flow and liquidity.

Potential legal proceedings and claims could increase the Company’s costs, reduce the Company’s revenue and cash flow, or otherwise alter the way the Company conducts business.

The Company is, from time to time, subject to various legal proceedings and claims, either asserted or unasserted. Any such claims, whether with or without merit, could be time-consuming and expensive to defend and could divert management’s attention and resources. While management believes the Company has reasonable and prudent insurance coverage and accrues loss contingencies for all known matters that are probable and can be reasonably estimated, the Company cannot assure that the outcome of all current or future litigation will not have a material adverse effect on the Company and/or its results of operations.

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's ability to declare or make any distribution is limited by its' corporate credit/issuer rating and EBITDA to interest ratio, as previously discussed above. The common equity ratio, calculated on a regulatory basis, was 47.7% at December 31, 2015 and the EBITDA to interest expense was 4.9 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.

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 Natural 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 rulemaking proceedings relating to its operations in the normal course of business. The following is a description of pending 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, the Sierra Club and the Montana Environmental Information Center filed a Clean Air Act citizen suit against all Colstrip owners 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 during the time period from 2001 to 2012. Plaintiffs have since indicated that they do not intend to pursue claims with respect to three of the seven projects, leaving a total of four projects remaining subject to the lawsuit. The lawsuit claims that, for each of the four projects, the Colstrip plant 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. The liability trial is currently set for May 2016, 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.

Coal Combustion Residuals

The CCR rule requires significant changes to the Company's Colstrip operations and those changes were reviewed by the Company and the plant operator in the second quarter of 2015. PSE had previously recognized a legal obligation under the EPA rules to dispose of coal ash material at Colstrip in 2003. Due to the CCR rule, additional disposal costs were added to the Asset Retirement and Environment Obligations (ARO).

Clean Air Act 111(d)/EPA Clean Power Plan

In June 2014, the EPA issued a proposed Clean Power Plan rule under Section 111(d) of the Clean Air Act designed to regulate GHG 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 issued a pre-publication version of the final Clean Power Plan rule under Section 111(d) on August 3, 2015 and published a final rule on October 23, 2015. PSE is reviewing the final rule and working with key stakeholders in preparation towards implementation. PSE cannot yet provide a determination of how the final rule may impact PSE or its existing generation facilities, if at all.

For more information on litigation or legislative rulemaking proceedings, see Item 1, Business, Recent and Future Environmental Law and Regulation, and Note 14 under Item 8.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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 2015, 2014 and 2013, 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.

ITEM 6. SELECTED FINANCIAL DATA

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



Puget Sound Energy Summary of Operations	Year Ended December 31,
(Dollars in Thousands)	2015		2014		2013		2012		2011
Operating revenue	$	3,093,258	$	3,116,123	$	3,187,335	$	3,216,259	$	3,319,803
Operating income	656,138		568,693		735,574		692,989		431,043
Net income	304,189		236,614		356,129		356,170		204,120

Total assets at year end	$	10,829,535	$	10,581,415	$	10,667,830	$	10,559,956	$	9,995,939
Long-term debt	3,524,384		3,351,259		3,513,258		3,513,258		3,523,845
Junior subordinated notes	250,000		250,000		250,000		250,000		250,000
Capital lease obligations	378		9,473		17,051		24,629		32,207



Puget Energy Summary of Operations	Year Ended December 31,
(Dollars in Thousands)	2015		2014		2013		2012		2011
Operating revenue	$	3,092,700	$	3,113,171	$	3,187,297	$	3,215,156	$	3,318,765
Operating income	671,925		577,851		755,160		715,535		474,940
Net income	241,179		171,835		285,728		273,821		123,290

Total assets at year end	$	12,852,619	$	12,673,603	$	12,820,571	$	12,781,838	$	12,305,372
Long-term debt	5,115,883		4,831,608		4,982,476		5,083,200		5,027,367
Junior subordinated notes	250,000		250,000		250,000		250,000		250,000
Capital lease obligations	378		9,473		17,051		24,629		32,207

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's and PSE's 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. All of Puget Energy's common stock is indirectly owned by Puget Holdings. 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. Puget Energy and PSE are collectively referred to herein as “the Company.”

PSE generates revenue and cash flow primarily from the sale of electric and natural gas services to residential and commercial customers within a service territory covering approximately 6,000 square miles, principally in the Puget Sound region of the state of Washington. PSE continually balances its load requirements, generation resources, purchase power agreements, and market purchases to meet customer demand. 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, 2015 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) increased electric margins driven by increased electric revenues; (3) decreased utility operations and maintenance expense due to reduced bad debt expense and meter reading expense; and (4) a reduction in interest expense related to regulatory liabilities.

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 and 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 (ROE) excluding unrealized gains and losses on derivative instruments (net income plus unrealized losses and/or minus unrealized gains 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 includes adjustments that result in a departure from GAAP presentation. The Company believes that return on AMA equity, a non-GAAP measure, is a more suitable metric for comparing ROE across years and is a more accurate metric for assessing and evaluating ROE performance against the Company's authorized regulated ROE. The return on average of monthly averages (AMA) equity is not intended to represent the regulated equity. PSE's GAAP

ROE may not be comparable to other companies' ROE measures. Furthermore, this measure is not intended to replace ROE (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 GAAP ROE, its return on AMA equity, and its authorized regulated ROE for 2015 and 2014:



	2015							2014
(Dollars in Thousands)	Earnings			Average Common Equity		Return On Equity		Earnings		Average Common Equity			Return On Equity
Return on equity - GAAP	$	304,189		$	3,320,861	9.2	%	$	236,614	$	3,359,743		7.0	%
Less/Plus: Unrealized gains and losses on derivative instruments, after-tax	(8,247		)	—		*		55,663		—			*
Less: Equity adjustments ¹	—			228,267		*		—		251,467			*
Plus: Impact of average of monthly average (AMA)	—			34,585		*		—		(64,487		)	*
Return on AMA equity	$	295,942		$	3,583,713	8.3	%	$	292,277	$	3,546,723		8.2	%
Authorized regulated return on equity	*			*		9.8	%	*		*			9.8	%

_______________


¹	Equity adjustments are related to removing the impacts of accumulated other comprehensive income (AOCI), subsidiary retained earnings, retained earnings of derivative instruments, and decoupling 24-month revenue reserve.


^*	Not meaningful and/or applicable.

The Company’s 2015 return on AMA equity was 8.3%, which is lower than the authorized regulated ROE primarily due to the following:


•	Regulated equity (rate base times equity percent) was $256.0 million lower than AMA equity for the year ended December 31, 2015. The variance was primarily driven by the unanticipated impacts on rate base of bonus depreciation and lower than anticipated capital spending due to slower than anticipated growth in PSE’s service territory. The impact on ROE for this variance was $40.5 million.


•	Utility margins were $6.1 million lower than allowed in rates for the year ended December 31, 2015 due to the impacts of warmer than normal weather conditions.


•	Depreciation expense was $5.2 million higher than the amount allowed in rates for the year ended December 31, 2015.

The Company’s 2014 return on AMA equity was 8.2%, which is lower than the authorized regulated ROE 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 capital expenditures placed into service.

Factors and Trends Affecting PSE’s Performance

PSE’s ongoing regulatory requirements and operational needs necessitated the investment of substantial capital in 2015 and will continue to do so in 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. 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 that 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 amortization;


•	Bonus depreciation and its impact on rate base;


•	General economic conditions in PSE's service territory and its effects on customer growth and use-per-customer; 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 general cost increases over time due to the combined effects of regulatory lag and attrition. Accordingly, the Company will need to seek rate relief on a regular and frequent basis in the future. In addition, the Washington Commission determines whether the Company's expenses and capital investments are reasonable and prudent for the provision of cost effective, reliable and safe electric and natural gas service. If the Washington Commission determines that a capital investment does not meet the reasonable and prudent standards, the costs (including return on any resulting rate base) related to such capital investment may be disallowed, partially or entirely, and not recovered in rates.

During 2013, PSE completed an ERF, which was 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 during the rate plan period. 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 GRC 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 (i.e., power cost only rate cases (PCORC) or emergency rate relief), requires PSE to file a GRC no sooner than April 1, 2015 and no later than April 1, 2016.

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 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.

2013 Expedited Rate Filing, Decoupling and Centralia Decision

PSE filed a settlement agreement with the Washington Commission on March 22, 2013. The agreement was intended to settle all issues regarding decoupling, a power purchase agreement with TransAlta Centralia and the ERF which includes the property tax tracker. The Washington Commission placed the ERF and decoupling filings under a common procedural schedule.

On June 25, 2013, the Washington Commission issued final orders resolving the amended decoupling petition, the ERF filing and the Petition for Reconsideration (related to the TransAlta Centralia power purchase agreement). Order No. 7 in the ERF/decoupling proceeding approved PSE's ERF filing with a small change to its cost of capital from 7.80% to 7.77% to update long term debt costs. This order also approved the property tax tracker discussed below and it approved the amended decoupling and rate plan filing with the further condition that PSE and the customers will share 50.0% each in earnings in excess of the 7.77% authorized rate of return. In addition, the rate plan increase allowed decoupling revenue per customer for the recovery of delivery system costs which will subsequently increase by 3.0% for the electric customers and 2.2% for the gas customers on January 1 of each year, until the conclusion of PSE's next GRC which will be filed before April 1, 2016. In the rate plan, rate increases are subject to a cap of 3% of total revenue for customers. Order No. 8 in the TransAlta Centralia proceeding granted in part and denied in part PSE's Petition for Reconsideration, clarifying certain portions of the Washington Commission's original order regarding TransAlta Centralia.

Decoupling Filings

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, are expected to mitigate 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 natural gas operating revenues related to electric transmission and distribution, natural 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 PCA is not part of the decoupling mechanism. As a result, these electric and natural 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 recover or refund the difference between allowed decoupling revenue and the corresponding actual revenue to affected customers during the following May to April time period. The decoupling mechanism will end on February 28, 2017 unless the continuation of the mechanism is approved in PSE’s next GRC filing which PSE is required to file by April 1, 2016 at the latest.

On April 22, 2015, the Washington Commission approved PSE's request to change rates under its electric and natural gas decoupling mechanism, effective May 1, 2015. As part of this filing, PSE also requested to change the methodology of how decoupling deferrals are calculated going forward and adjust deferrals calculated in 2014. The change was done to ensure that the amortization of prior years’ accumulated decoupling deferrals were not included in the calculation of the current year decoupling deferrals. The effect of the methodology change in the first quarter of 2015, was a reduction of approximately $12.0 million previously recognized revenue from May through December 2014. The overall changes represent a rate increase for electric customers of $53.8 million, or 2.6%, annually, and a rate increase for natural gas customers of $22.0 million, or 2.1%, annually, effective May 1, 2015. In addition, PSE exceeded the earnings test threshold for its natural gas business in 2014. As a result, PSE recorded a reduction in natural gas decoupling deferral and revenue of $1.3 million. The customers' share of the over earnings will be returned to customers over the subsequent 12-month period beginning May 1 of each year.

The 3.0% annual decoupling related cap was triggered for certain rate classes. The resulting amount of deferral that was not included in the 2015 rate increase is $1.9 million for electric revenue and $8.2 million for natural gas revenue that was accrued through December 31, 2014. These amounts may be included in customer rates beginning in May 2016, subject to subsequent application of the earnings test and the 3.0% cap on decoupling related rate increases.

Due to the 3.0% cap on annual decoupling increases noted above and the growing size of decoupling deferrals, PSE performed an analysis as of December 31, 2015 to determine if electric and natural gas decoupling revenue deferrals would be collected from customers within 24 months of December 31, 2015. The analysis indicated $10.0 million of natural gas decoupling revenue will not be collected within 24 months, therefore PSE did not recognize this portion of decoupling revenue. However, once it is determined to be collectible within 24 months it will be recognized.

Other Proceedings. On August 11, 2015, PSE filed with the Washington Commission, a petition for approval of a special contract for the LNG fuel service with Totem Ocean Trailer Express, Inc. (TOTE) which upon the Washington Commission approval, has a delivery term that commences January 1, 2019. Additionally, the filing contained a request for a declaratory order approving the methodology for allocating costs between regulated and non-regulated LNG services. A prehearing conference was held on October 13, 2015, which provided for simultaneous briefs on November 20, 2015 and hearings on January 29, 2016. The January hearing date was subsequently stayed. The Commission issued an order on December 18, 2015, provisionally determining jurisdictional questions and setting further process including briefing and oral argument. The Commission provisionally determined that it can regulate the sale of LNG to marine shippers. However, the Commission ruled that it cannot exercise its jurisdiction over the sale of LNG by PSE to TOTE as set forth in PSE’s petition because PSE is not offering to provide LNG as a marine fuel to all marine shippers and therefore it is not offering a public service which the Commission regulates. PSE is reviewing its options related to the LNG service.

Electric Rates

Power Cost Adjustment Mechanism

PSE currently 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 currently applicable is as follows:



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



Annual Power Cost Variability	Company's Share		Customers’ Share
	Over	Under	Over	Under
+/- $17 million	100%	100%	—%	—%
+/- $17 million - $40 million	35	50	65	50
+/- $40 + million	10	10	90	90


•	Reduction to the cumulative deferral trigger for surcharge or refund from $30.0 million to $20.0 million;

•


•	Suspension of the requirement that a GRC must be filed within three months after rates are approved in a PCORC, and agreeing, for a five-year period, that PSE will not file a GRC or PCORC within six months of the date rates go into effect for a PCORC filing; and


•	Establishment of a five-year moratorium on changes to the PCA/PCORC.

Property Tax Tracker Mechanism

On March 26, 2015, PSE filed a request with the Washington Commission to change rates under its electric property tax tracker mechanism, effective May 1, 2015. PSE filed a substitute filing with the Washington Commission on April 15, 2015 for the electric property tax tracker mechanism. The proposed rate change incorporates the effects of an increase to property taxes paid as well as true-ups to the rate from the prior year. This represents a rate increase for electric customers of $8.4 million, or 0.4% annually.

Federal Incentive Tracker Tariff

On December 30, 2015, the Washington Commission approved the annual true-up and rate filing to PSE's Federal Incentive Tracker tariff, effective January 1, 2016. The true-up filing resulted in a total credit of $57.3 million to be passed back to eligible customers over the twelve months beginning January 1, 2016. Of the total credit, $39.6 million represents the pass-back of grant amortization and $17.7 million represents the pass through of interest, in addition to a minor true-up associated with the 2015 rate period. This filing represents an overall average rate decrease of 0.2%.

Natural Gas Rates

Purchased Gas Adjustment

The PGA mechanism assures timely recovery of gas costs incurred while balancing the Company's needs to maintain price stability to insulate customers from normal fluctuations in the market price of gas.

On October 29, 2015, the Washington Commission approved PSE's PGA natural gas tariff filing with an effective date of November 1, 2015, 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 $185.9 million, or 17.4% annually, with no impact on net operating income.

Cost Recovery Mechanism

On October 29, 2015, the Washington Commission approved PSE's CRM natural gas tariff filing with an effective date of November 1, 2015. The purpose of this filing is to recover capital costs related to enhancing the safety of the natural gas distribution system. The impact to the CRM rates is an annual revenue increase of $5.3 million, or 0.5% annually.

Property Tax Tracker Mechanism

On March 26, 2015, PSE filed a request with the Washington Commission to change rates under its natural gas property tax tracker mechanism, effective May 1, 2015. PSE made a subsequent substitute natural gas filing with the Washington Commission on May 1, 2015, which changed the rate effective date to June 1, 2015, and represented a rate decrease for natural gas customers of $2.3 million or 0.2% annually.

For additional information, see Business - Regulation and Rates included in Item 1 of this report.

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 also 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, 2015, 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, 2015 was 55.89 degrees, or 0.55 degrees warmer than the same period in the prior year, and 3.25 degrees warmer when compared to the historical average.

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”).

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 by-products 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 on measures including, but not limited to, resource planning, remediation, monitoring, pollution control equipment and emissions-related abatement and fees.

Compliance with these or other future regulations, such as those pertaining to climate change, 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 generally 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 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. Further, 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.

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, 2015 and 2014. Set forth below are the consolidated financial results of PSE for the years ended December 31, 2015, 2014 and 2013.

Non-GAAP Financial Measures – Electric and Natural Gas Margins

The following discussion includes financial information prepared in accordance with GAAP, as well as two other financial measures, electric margin and natural 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 includes adjustments that result in a departure from GAAP presentation. The presentation of electric margin and gas margin is intended to supplement an understanding of PSE’s operating performance. Electric margin and natural gas margin are used by PSE to determine whether PSE is collecting the appropriate amount of revenue from its customers to maintain electric and gas margins to ultimately provide adequate recovery of operating costs, including interest and equity returns. PSE’s electric margin and natural gas margin measures may not be comparable to other companies’ electric margin and natural 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

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. The following table displays the details of PSE’s electric margin changes from periods 2015 to 2014 and periods 2014 to 2013.



Electric Margin	Year Ended December 31,						Dollar Change			Year Ended December 31,			Dollar Change
(Dollars in Thousands)	2015			2014						2013
Electric operating revenue:
Residential sales	$	1,061,117		$	1,003,205		$	57,912		$	1,115,694		$	(112,489	)
Commercial sales	867,786			824,778			43,008			847,704			(22,926		)
Industrial sales	114,223			107,750			6,473			108,433			(683		)
Other retail sales	20,216			19,707			509			19,192			515
Total retail sales	2,063,342			1,955,440			107,902			2,091,023			(135,583		)
Transportation sales	10,143			9,502			641			8,738			764
Sales to other utilities and marketers	46,666			41,680			4,986			54,444			(12,764		)
Decoupling revenue	13,630			25,735			(12,105		)	(14,989		)	40,724
Other decoupling revenue¹	(16,634		)	5,609			(22,243		)	—			5,609
Other	11,321			45,831			(34,510		)	17,704			28,127
Total electric operating revenues²	2,128,468			2,083,797			44,671			2,156,920			(73,123		)
Minus power costs:
Purchased electricity²	(499,522		)	(514,087		)	14,565			(541,905		)	27,818
Electric generation fuel²	(249,907		)	(263,493		)	13,586			(261,332		)	(2,161		)
Residential exchange²	112,473			129,036			(16,563		)	81,053			47,983
Total electric power costs	(636,956		)	(648,544		)	11,588			(722,184		)	73,640
Electric margin³	$	1,491,512		$	1,435,253		$	56,259		$	1,434,736		$	517

Electric energy sales, MWh
Residential sales	10,164,703			10,349,928			(185,225		)	10,769,100			(419,172		)
Commercial sales	8,999,068			8,900,863			98,205			9,118,720			(217,857		)
Industrial sales	1,257,958			1,226,588			31,370			1,229,556			(2,968		)
Other retail sales	94,847			98,499			(3,652		)	98,578			(80		)
Total energy sales to customers	20,516,576			20,575,878			(59,302		)	21,215,954			(640.076		)

______________


¹	Includes amortization of prior year collection/refund, reduction related to excess rate of return, and a reduction related to amounts that will not be collected within 24 months.


²	As reported on PSE’s Consolidated Statement of Income.


³	Electric margin does not include any allocation for amortization/depreciation expense or electric generation operation and maintenance expense.

2015 compared to 2014

Electric Operating Revenue

Electric operating revenues increased $44.7 million primarily due to higher residential sales of $57.9 million, higher commercial sales of $43.0 million, partially offset by decreased deferred decoupling revenue and other decoupling revenue of $12.1 million and $22.2 million, respectively and other electric operating revenue of $34.5 million. These items are discussed in detail below.

•

Electric retail sales increased $107.9 million due to increases in rates of $113.5 million due primarily to additional $49.1 million credit provided to customers on Jefferson County Public Utility District (JPUD) gain in 2014, $17.0 million of additional Residential Exchange credits, and $12.9 million additional Renewable Energy Credit (REC) credits in 2014, which was partially offset by $5.6 million due to lower retail electricity usage.


•	Decoupling revenue resulted in a decrease of $12.1 million due to the allowed decoupled revenues per customer as compared to volumetric revenues in 2015 compared to 2014.


•	Other decoupling revenue decreased $22.2 million due to $12.8 million recovery from customers and $9.4 million related to over earnings sharing band of the decoupling mechanism.


•	Other electric operating revenue decreased $34.5 million primarily due to a reduction of non-core gas sales of $23.8 million and biogas revenues of $10.1 million.

Electric Energy Costs


•	Purchased electricity expense decreased $14.6 million primarily due to a $27.4 million decrease in long-term firm and market power purchases, partially offset by $10.1 million related to the PCA customer portion in 2014.


•	Electric generation fuel expense decreased $13.6 million primarily due to lower natural gas prices for our combustion turbine generation plants.


•	Residential exchange credits decreased $16.6 million resulting from lower Residential Exchange Program (REP) credits associated with the BPA REP settlement. The REP credit tariff was lowered effective October 1, 2015. The REP credit is a pass-through tariff item with a corresponding credit in electric operating revenue, with no impact on net income.

The Northwest Power Act, through the REP, provides access to the benefits of low-cost federal power for residential and small farm customers of regional utilities, including PSE. The program is administered by the BPA. Pursuant to agreements (including settlement agreements) between the BPA and PSE, the BPA has provided payments of REP benefits to PSE, which PSE has passed through to its residential and small farm customers in the form of electricity bill credits.

2014 compared to 2013

Electric Operating Revenue

Electric operating revenues decreased $73.1 million primarily due to lower residential sales of $112.5 million, lower commercial sales of $22.9 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.


•	Electric retail sales decreased $135.6 million primarily due to the JPUD gain of $54.3 million, which was refunded to customers in December 2014, PCORC rate decreases of $10.5 million and lower retail electricity usage of $63.1 million.


•	Sales to other utilities and marketers decreased $12.8 million primarily due to lower wholesale electricity prices which decreased revenue by $3.2 million and a decrease in sales volume of $9.6 million.


•	Decoupling revenue resulted in an additional $31.3 million 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.


•	Other electric operating revenue increased $28.1 million primarily due to an increase in 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 primarily as a result of a market price offset of $17.8 million and a $6.6 million decrease in long-term firm purchases and market purchases.


•	Residential exchange credits increased $48.0 million resulting from higher REP credits associated with the BPA REP settlement. The REP credit tariff increased effective June 1, 2014. The REP credit is a pass-through tariff item with a corresponding credit in electric operating revenue, with no impact on net income.

Natural Gas Margin

Natural 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. 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 margin or net income is not affected by changes under the PGA mechanism because over and under recoveries of gas costs included in baseline PGA rates are deferred and either refunded or collected from customers, respectively, in future periods. The following table and discussion highlights significant items that impact natural gas operating revenue and natural gas energy costs which are included in natural gas margin for the years ended December 31, 2015, 2014 and 2013:



Natural Gas Margin	Year Ended December 31,						Dollar Change			Year Ended December 31,			Dollar Change
(Dollars in Thousands)	2015			2014						2013
Natural gas operating revenue:
Residential sales	$	597,572		$	644,055		$	(46,483	)	$	682,636		$	(38,581	)
Commercial sales	268,044			281,526			(13,482		)	293,102			(11,576		)
Industrial sales	22,420			25,366			(2,946		)	27,588			(2,222		)
Total retail sales	$	888,036		$	950,947		$	(62,911	)	$	1,003,326		(52,379		)
Transportation sales	18,666			17,069			1,597			16,531			538
Decoupling revenue	51,981			29,116			22,865			(5,165		)	34,281
Other decoupling revenue¹	(26,038		)	2,208			(28,246		)	—			2,208
Other	14,904			13,520			1,384			13,665			(145		)
Total natural gas operating revenues²	$	947,549		$	1,012,860		(65,311		)	$	1,028,357		(15,497		)
Minus purchased gas costs²	(403,310		)	(458,691		)	55,381			(488,201		)	29,510
Natural gas margin³	$	544,239		$	554,169		$	(9,930	)	$	540,156		$	14,013

Natural Gas Volumes, therms (thousands):
Residential	492,997			527,423			(34,426		)	572,668			(45,245		)
Commercial firm	230,507			242,095			(11,588		)	255,543			(13,448		)
Industrial firm	23,777			26,481			(2,704		)	28,469			(1,988		)
Interruptible	43,931			46,113			(2,182		)	54,554			(8,441		)
Total retail natural gas volumes, therms	791,212			842,112			(50,900		)	911,234			(69,122		)
Transportation volumes	220,392			211,429			8,963			219,696			(8,267		)
Total natural gas volumes	1,011,604			1,053,541			(41,937		)	1,130,930			(77,389		)

___________________


¹	Includes amortization of prior year collection/refund, reduction related to excess rate of return, and a reduction related to amounts that will not be collected within 24 months.


²	As reported on PSE’s Consolidated Statement of Income.


³	Natural gas margin does not include any allocation for amortization/depreciation expense or natural gas operations and maintenance expense.

2015 compared to 2014

Natural Gas Operating Revenue

Natural gas operating revenue decreased $65.3 million due primarily to lower natural gas retail sales revenue of $62.9 million as a result of lower natural gas therm sales, PGA rate reduction and partially offset by decoupling revenue. These items are discussed in detail below.


•	Natural gas retail sales revenue decreased $62.9 million primarily due to a decrease of $57.5 million in natural gas sales due to lower therms sold and $5.4 million due to the PGA rate reduction.


•	Decoupling revenue resulted in an increase of $22.9 million due to lower volumetric revenues compared to the allowed decoupled revenues per customer.


•	Other Decoupling revenue decreased $28.2 million due to return of over earnings sharing band of the decoupling mechanism of $10.5 million, 24-month exceeding the collection period for decoupling of $10.0 million and collection from customers of $7.8 million.

Natural Gas Energy Costs

Purchased natural gas expense decreased $55.4 million due to lower natural gas costs reflected in PGA rates and by a decrease in usage of 6.0%.

2014 compared to 2013

Natural Gas Operating Revenue

Natural gas operating revenue decreased $15.5 million due primarily to lower natural gas retail sales revenue of $52.4 million as a result of lower natural gas costs, partially offset by an additional $36.5 million of decoupling revenue. These items are discussed in detail below.


•	Natural gas retail sales revenue decreased $52.4 million primarily due to a decrease of $76.1 million in natural gas sales as well as decreases in PSE's decoupling rate of $1.0 million annually, effective May 1, 2014, partially offset by a PGA rate increase of $23.3 million annually, which was effective November 1, 2014.


•	Decoupling revenue resulted in an additional $34.3 million due to lower volumetric revenues compared to the allowed decoupled revenue per customer.

Natural Gas Energy Costs

Purchased natural gas expense decreased $29.5 million 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%.

Other Operating Expenses and Other Income (Deductions)

The following table displays the details of PSE's operating expenses and other income (deductions) from periods 2015 to 2014 and periods 2014 to 2013:



Puget Sound Energy	Year Ended December 31,						Dollar Change			Year Ended December 31,			Dollar Change
(Dollars in Thousands)	2015			2014						2013
Operating expenses:
Net unrealized (gain) loss on derivative instruments	$	(12,688	)	$	85,636		$	(98,324	)	$	(98,880	)	$	(184,516	)
Utility operations and maintenance	530,720			550,146			(19,426		)	529,939			(20,207		)
Non-utility expense and other	26,618			23,729			2,889			12,205			(11,524		)
Depreciation and amortization	420,807			365,606			55,201			388,955			23,349
Conservation amortization	110,866			104,096			6,770			105,897			1,801
Taxes other than income taxes	320,531			310,982			9,549			303,260			(7,722		)
Other income (deductions):
Other income	20,711			24,036			(3,325		)	38,690			(14,654		)
Other expense	(6,764		)	(7,457		)	693			(7,134		)	(323		)
Interest expense	(239,996		)	(259,316		)	19,320			(250,115		)	(9,201		)
Income tax expense	125,900			89,342			36,558			160,886			(71,544		)

2015 compared to 2014

Other Operating Expenses

•

Net unrealized (gain) loss on derivative instruments increased $98.3 million to a gain of $12.7 million. The net gain in 2015 was comprised of a gain of $22.3 million related to electricity derivative instruments and a $9.3 million loss related to PSE's natural gas derivative instruments for power. This compares to a loss of $42.3 million related to PSE's natural gas for power derivative instruments and a loss of $43.3 million related to electricity derivative instruments, respectively, during the prior year. The gain was primarily due to decreases in natural gas and wholesale electricity forward prices.


•	Utility operations and maintenance expense decreased $19.4 million primarily driven by a decrease of $8.3 million in bad debts expense and $7.0 million in meter reading expenses.

•

Depreciation and amortization expense increased $55.2 million primarily due to $43.6 million of electric amortization expense from $46.9 million of regulatory credits related to the JPUD gain on sale returned to customers and a net increase of $3.1 million of Electron sale loss amortization, partially offset by a decrease of $5.7 million in PTC deferral. Gas depreciation also increased in the amount of $5.3 million, mainly due to new additions.


•	Conservation amortization increased $6.8 million primarily due to an increase of $6.2 million in conservation rider rate annual adjustments.


•	Taxes other than income taxes increased $9.5 million primarily due to an increase in property taxes of $5.7 million, state excise taxes of $4.3 million and municipal taxes of $2.4 million.

Other Income, Interest Expense and Income Tax Expense


•	Other income decreased $3.3 million primarily due to PSE's share of the JPUD gain of $7.5 million in 2014, which was partially offset by an increase in Allowance for Funds Used During Construction (AFUDC) equity income of $2.3 million and an increase in interest and dividend income of $1.4 million.


•	Interest expense decreased $19.3 million primarily due to a decrease of $12.0 million in regulatory liability interest expense, a reduction of $3.5 million of interest on long term debt, and an increase of $2.0 million of AFUDC debt.


•	Income tax expense increased $36.6 million primarily driven by a higher pre-tax income. For additional information, see Note 13 to the consolidated financial statements included in Item 8 of this report.

2014 compared to 2013

Other Operating Expenses

•

Net unrealized (gain) loss on derivative instruments decreased $184.5 million which 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 primarily driven by an increase of $10.4 million in bad debts expense and $10.1 million in electric transmission and distribution expenses.


•	Non-utility operations and maintenance expense increased $11.5 million due to biogas expense which increased by $10.7 million during 2014.

•

Depreciation and amortization expense decreased $23.3 million primarily due to $9.5 million of electric depreciation expense from additional capital expenditures placed into service, net of retirements, an increase of $3.6 million of gas depreciation, mainly due to new additions. The increase was offset by a $6.3 million decrease in common utility plant, mainly due to the retirement of computer equipment. The decrease in amortization was primarily due to the gain of $51.8 million on the sale of Jefferson County assets to the JPUD which was refunded to customers. Partially offsetting the decrease was a reduction of $15.5 million in regulatory credits and an increase of $5.6 million in regulatory debits.


•	Taxes other than income taxes increased $7.7 million 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.

Other Income, Interest Expense and Income Tax Expense


•	Other income decreased $14.7 million primarily due to decreases of $11.0 million in interest and dividend income, 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 expense increased $9.2 million 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 expense decreased $71.5 million primarily driven by a lower pre-tax income, and to a lesser extent, by increases in PTC and treasury grant amortization.

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, 2015, 2014 and 2013 was as follows:



Benefit/(Expense)	Year Ended December 31,						Dollar Change			Year Ended December 31,			Dollar Change
(Dollars in Thousands)	2015			2014						2013
PSE net income	$	304,189		$	236,614		$	67,575		$	356,129		$	(119,515	)
Other operating revenue	(558		)	(2,952		)	2,394			(38		)	(2,914		)
Net unrealized gain on derivative instruments	544			1,491			(947		)	3,865			(2,374		)
Non-utility expense and other	15,801			10,620			5,181			15,759			(5,139		)
Other income	—			3			(3		)	1			2
Non-hedged interest rate swap expense	(3,796		)	(3,915		)	119			2,420			(6,335		)
Interest expense ¹	(109,125		)	(102,382		)	(6,743		)	(130,887		)	28,505
Income tax benefit (expense)	34,124			32,356			1,768			38,479			(6,123		)
Puget Energy net income	$	241,179		$	171,835		$	69,344		$	285,728		$	(113,893	)

_____________


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

2015 compared to 2014

Summary Results of Operations

Puget Energy’s net income increased by $69.3 million, which is primarily attributable to PSE's net income increase of $67.6 million. 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 increased $5.2 million primarily due to higher pension expense related to the qualified pension plan.


•	Interest expense increased $6.7 million primarily due to interest expense on the long-term senior secured notes issued in 2015.

2014 compared to 2013

Summary Results of Operations

Puget Energy’s net income decreased $113.9 million, primarily due to a decrease in PSE's net income of $119.5 million. 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 primarily due to lower pension expense related to the qualified pension plan which resulted in a smaller gain in 2014.


•	Non-hedged interest rate swap expense decreased $6.3 million to an expense of $3.9 million primarily due to market value decreases of $4.7 million.

•

Interest expense decreased $28.5 million 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 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, 2015:



	Payments Due Per Period
(Dollars in Thousands)	Total		2016		2017 - 2018		2019 - 2020		Thereafter
Contractual obligations:
Energy purchase obligations ¹	$	6,906,769	$	994,062	$	1,808,475	$	1,338,797	$	2,765,435
Long-term debt including interest²	8,779,399		217,649		630,324		408,338		7,523,088
Short-term debt including interest	159,014		159,014		—		—		—
Service contract obligations	582,423		68,123		101,558		101,060		311,682
Non-cancelable operating leases³	206,484		22,254		43,317		32,828		108,085
PSE capital leases³	391		391		—		—		—
Pension and other benefits funding and payments	58,065		21,039		7,132		10,019		19,875
Total PSE contractual cash obligations	$	16,692,545	$	1,482,532	$	2,590,806	$	1,891,042	$	10,728,165
Long-term debt, including interest	2,417,100		99,163		198,326		647,043		1,472,568
Total Puget Energy contractual cash obligations	$	19,109,645	$	1,581,695	$	2,789,132	$	2,538,085	$	12,200,733

_____________


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

The following are PSE’s and Puget Energy’s aggregate availability under commercial commitments as of December 31, 2015:



	Amount of Available Commitments Expiration Per Period
(Dollars in Thousands)	Total			2016		2017 - 2018		2019 - 2020		Thereafter
Commercial commitments:
PSE working capital facility ¹	$	650,000		$	—	$	—	$	650,000	$	—
PSE energy hedging facility ¹	350,000			—		—		350,000		—
Inter-company short-term debt ²	30,000			—		—		—		30,000
Total PSE commercial commitments	$	1,030,000		$	—	$	—	$	1,000,000	$	30,000
Puget Energy revolving credit facility ³	800,000			—		800,000		—		—
Less: Inter-company short-term debt elimination ²	(30,000		)	—		—		—		(30,000		)
Total Puget Energy commercial commitments	$	1,800,000		$	—	$	800,000	$	1,000,000	$	—

_____________

As of December 31, 2015, PSE had two credit facilities which provide, in the aggregate, $1.0 billion of short-term liquidity needs, and which will mature in April 2019. These facilities consisted of a $650.0 million revolving liquidity facility to be used for general corporate purposes, including a backstop to the Company's commercial paper program, and a $350.0 million energy hedging 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 that, upon the banks' approval, would increase the total size of these facilities to $1.450 billion. As of December 31, 2015, no loans or letters of credit were outstanding under the PSE energy hedging facility, no loans or letters of credit were outstanding under the PSE liquidity facility and $159.0 million was outstanding under the commercial paper program. The credit agreements are syndicated among numerous lenders. Outside of the credit agreements, PSE has a $3.9 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.


²	As of December 31, 2015, PSE had a revolving credit facility with Puget Energy in the form of a promissory note to borrow up to $30.0 million.

As of December 31, 2015, Puget Energy had a revolving senior secured credit facility totaling $800.0 million, which matures in April 2018. The revolving senior secured credit facility is syndicated among numerous lenders. The 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. As of December 31, 2015, no amount was outstanding under the Puget Energy credit facility.

Off-Balance Sheet Arrangements

As of December 31, 2015, the Company had no off-balance sheet arrangements that have or are reasonably likely to have a material effect on the Company's financial condition.

Utility Construction Program

PSE’s construction programs for generating facilities, the electric transmission system, the natural gas and electric distribution systems and the LNG facilities are designed to meet regulatory requirements and customer growth and to support reliable energy delivery. Construction expenditures, excluding equity AFUDC, totaled $587.2 million in 2015. Presently planned utility construction expenditures, excluding equity AFUDC, are as follows:



Capital Expenditure Projections (Dollars in Thousands)	2016		2017		2018
Total energy delivery, technology and facilities expenditures	$	806,655	$	815,989	$	665,462

The program is subject to change based upon general business, economic and regulatory conditions. Utility construction expenditures and any new generation resource expenditures are typically funded from a combination of cash from operations, short-term debt, long-term debt and/or equity. PSE’s utility construction program expenditures periodically can and do exceed cash flow generated from operations. As a result, execution of PSE’s utility construction program 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, 2015 decreased by $43.9 million compared to the same period in 2014. The decrease in cash flow was primarily the result of a $66.5 million increase in accounts receivable and unbilled revenue in 2015 compared to a decrease of $153.6 million in 2014. This was partially offset by a $60.7 million increase in cash flow related to the PGA rate increase, a $74.5 million reduction in regulatory asset and liability cash outflows and a $36.6 million increase in deferred income taxes and tax credits.

Puget Energy

Cash generated from operations for the year ended December 31, 2015 decreased by $53.1 million compared to the same period in 2014. The net decrease was primarily impacted by the $43.9 million decrease from cash flow provided by the operating activities of PSE, as previously discussed. The above decrease was also negatively impacted by Puget Energy's $8.3 million cash outflow related to financing derivatives.

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. The Company believes it has sufficient liquidity through its credit facilities and access to capital markets to fund its needs over the next twelve months.

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, 2015 and 2014, PSE had $159.0 million and $85.0 million in short-term debt outstanding, respectively, exclusive of the $28.9 million demand promissory note with Puget Energy which was repaid in June 2015. 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 2015 and 2014 was 4.24%, and 4.05%, respectively. As of December 31, 2015, 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. These unsecured revolving credit facilities expire in April 2019.

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, 2015, 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 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, 2015, no amounts were drawn and outstanding under PSE's $650.0 million liquidity facility. No letters of credit were outstanding under either facility, and $159.0 million was outstanding under the commercial paper program. Outside of the credit agreements, PSE had a $3.9 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%. On June 30, 2015, PSE repaid in full the $28.9 million outstanding balance under the Note.

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.

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, 2015, PSE could issue:


•	Approximately $2.4 billion of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately $4.0 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, 2015; and

•

Approximately $434.0 million of additional first mortgage bonds under PSE’s natural gas mortgage indenture based on approximately $723.3 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, 2015.

At December 31, 2015, 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.

Shelf Registrations and Long-Term Debt Activity. PSE has in effect a shelf registration statement under which it may issue, from time to time, up to $375.0 million aggregate principal amount of senior notes secured by first mortgage bonds. The Company remains subject to the restrictions of PSE’s indentures and credit agreements on the amount of first mortgage bonds that PSE may issue.

On May 26, 2015, PSE issued $425.0 million of senior secured notes. The notes mature in May 2045 and have an interest rate of 4.30%, which is payable semi-annually in May and November. Net proceeds of the issuance were used to fund the early retirement, including accrued interest and make-whole call premiums, of the Company’s $150.0 million 5.197% senior notes maturing in October 2015 and the Company’s $250.0 million 6.75% senior notes maturing in January 2016.

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, 2015, approximately $464.1 million of unrestricted retained earnings was available for the payment of dividends under the most restrictive mortgage indenture covenant.

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, 2015 and the EBITDA to interest expense was 4.9 to one for the 12 months then ended December 31, 2015.

Puget Energy

Credit Facility. At December 31, 2015, Puget Energy maintained an $800.0 million revolving senior secured credit facility, which expires April 2018. 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, 2015, there was no amount drawn and outstanding under the facility. As of the date of this report, 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, 2015, Puget Energy was in compliance with all applicable covenants.

Long-Term Debt Activity. In June 2014, Puget Energy entered into three bilateral term loans, with two and three year maturities, which in total, equaled $299.0 million. The proceeds of the term loans were used to pay off the outstanding Puget Energy revolving credit facility balance, which subsequently allowed 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.

On May 12, 2015, Puget Energy issued $400.0 million of senior secured notes in a private placement. The notes will mature in May 2025 and have an interest rate of 3.65%, which is payable semi-annually in May and November. Net proceeds of the issuance were used to repay all amounts outstanding under Puget Energy's three term loans, and to fund a special dividend to shareholders of approximately $96.7 million. On November 6, 2015, Puget Energy exchanged $400.0 million of its 3.65% senior secured notes that were originally issued in the May 2015 private placement for registered notes of the same amount.

Dividend Payment Restrictions. 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 3.4 to one for the 12 months then ended December 31, 2015.

At December 31, 2015, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.

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 during the month less unbilled revenues recorded in the prior month. The "current" month unbilled usage is then priced at published rates for each schedule to estimate the unbilled revenues by customer.

Beginning July 1, 2013, certain revenues from PSE's electric and natural gas operations are subject to a revenue decoupling mechanism under which PSE's actual energy delivery revenues related to electric transmission and distribution, natural gas operations and general administrative costs are compared with authorized revenues allowed under the mechanism. The mechanism mitigates volatility in revenue due to weather and gross margin erosion related to energy efficiency. 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 Accounting Standards Codification (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. However, if the excess amount cannot be collected within 24 months, for GAAP purposes only, the Company will not record any decoupling revenue unless it is within the 24 months of collection, but will collect non-recorded amounts when actually billed.

Regulatory Accounting. As a regulated entity of the Washington Commission and FERC, PSE prepares its financial statements in accordance with the provisions of 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 FERC. Under the authority of these commissions, PSE has recorded certain regulatory assets and liabilities at December 31, 2015 in the amount of $971.5 million and $663.7 million, respectively, and regulatory assets and liabilities at December 31, 2014 of $987.4 million and $635.4 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 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, 2015. 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 $4.6 billion at the October 1, 2015 measurement date for the annual test of goodwill impairment. The carrying value of Puget Energy’s equity was approximately $3.5 billion with the excess of the fair value over the carrying value representing 30.9% or $1.1 billion.

The income approach and the market approach valuations resulted in Puget Energy equity values of $4.7 billion and $4.4 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 2.7% and 6.5%, respectively.

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



Equity Value Sensitivity Table
(Dollars in Billions)
Weighted-Average Cost of Capital Rate	Long-Term Growth Rate
	2.5		%	2.6		%	2.7		%	2.8		%	2.9		%	3.0		%
6.8%	$	3.5		$	3.7		$	3.9		$	4.2		$	4.4		$	4.7
6.5	4.2			4.4			4.7			5.0			5.3			5.6
6.3	5.0			5.2			5.5			5.9			6.2			6.6

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 Normal Purchase Normal Sale (NPNS) exception to derivative accounting rules. Generally, NPNS applies to contracts with creditworthy counterparties, for which physical delivery is probable and in quantities that will be used in the normal course of business. Power purchases designated as NPNS must meet additional criteria to determine if the transaction is within PSE’s forecasted load requirements and if the counterparty owns or controls energy resources within the western region to allow for physical delivery of the energy. PSE may enter into financial fixed contracts to economically hedge the variability of certain index-based contracts. Those contracts that do not meet the NPNS exception are marked-to-market to current earnings in the statements of income. Natural gas derivative contracts qualify for deferral under ASC 980 due to the 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 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.

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, 2015, Puget Energy had interest rate swap contracts outstanding originally related to its long-term debt. For additional information, see Item 7A, Note 9 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 $22.9 million, $13.8 million and $22.4 million for the years ended December 31, 2015, 2014 and 2013, respectively. Of these amounts, approximately 58.5%, 61.5% and 60.8% were included in utility operations and maintenance expense in 2015, 2014 and 2013, respectively, and the remaining amounts were capitalized. For the years ended December 31, 2015 and 2014, Puget Energy recognized incremental qualified pension income of $16.7 million and $12.8 million, respectively. In 2016, it is expected that PSE and Puget Energy will recognize pension expense of $13.8 million and incremental qualified pension income of $15.2 million, respectively.

PSE has a Supplemental Executive Retirement Plan (SERP). PSE recognized pension and other postretirement benefit expenses of $5.6 million, $4.9 million and $5.7 million for the years ended December 31, 2015, 2014 and 2013, respectively. For the years ended December 31, 2015 and 2014, Puget Energy recognized incremental income of $0.5 million and $0.6 million, respectively. In 2016, it is expected that PSE and Puget Energy will recognize pension expense of $4.8 million and incremental pension income of $0.4 million, respectively.

PSE also has other limited postretirement benefit plans. PSE recognized income of $0.2 million and $0.4 million and expense of $0.1 million for the years ended December 31, 2015, 2014 and 2013, respectively. For the years ended December 31, 2015 and 2014, Puget Energy recognized incremental expense of $0.3 million each year. In 2016, it is expected that PSE and Puget Energy will recognize an immaterial income amount and incremental expense of $0.2 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 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. During 2015, 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, 2015 and 2014, the Company’s qualified pension plan was $44.2 million and $64.0 million underfunded as measured under GAAP, or 93.1% and 90.7% funded, respectively. As of January 1, 2016, 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, 2016 are expected to be at least $18.0 million, $2.5 million and $0.5 million, respectively.

The discount rate used in accounting for pension and other benefit obligations increased from 4.25% in 2014 to 4.65% in 2015. The discount rate used in accounting for pension and other benefit expense decreased from 5.10% in 2013 to 4.25% in 2014. The rate of return on plan assets for qualified pension benefits in 2015 remained unchanged at the 2014 level, or 7.75%. The rate of return on plan assets for other benefits in 2015 also remained unchanged at the 2014 level, or 7.0%. 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	$	(33,303	)	$	(2,093	)	$	(626	)
Decrease in discount rate	50 basis points	36,767			2,241			681



Puget Energy	Change in Assumption	Impact on 2015 Pension Expense Increase /(Decrease)
(Dollars in Thousands)		Pension Benefits			SERP			Other Benefits
Increase in discount rate	50 basis points	$	(3,172	)	$	(169	)	$	(59	)
Decrease in discount rate	50 basis points	3,497			175			59
Increase in return on plan assets	50 basis points	(2,906		)	*			(39		)
Decrease in return on plan assets	50 basis points	2,906			*			39



Puget Sound Energy	Change in Assumption	Impact on 2015 Pension Expense Increase /(Decrease)
(Dollars in Thousands)		Pension Benefits			SERP			Other Benefits
Increase in discount rate	50 basis points	$	(3,180	)	$	(169	)	$	(61	)
Decrease in discount rate	50 basis points	3,490			175			68
Increase in return on plan assets	50 basis points	(2,933		)	*			(39		)
Decrease in return on plan assets	50 basis points	2,933			*			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.

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. 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.

PSE's energy risk portfolio management function monitors and manages these risks using analytical models and tools including 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. Based on the analytics from all of its models and tools, PSE enters into forward physical electric and natural gas purchase and sale agreements, fixed-for-floating swap contracts, and commodity call/put options to manage its electric and gas portfolio risks. 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.

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, 2015				December 31, 2014
(Dollars in Thousands)	Assets		Liabilities		Assets		Liabilities
Electric portfolio:
Current	$	19,051	$	81,453	$	3,217	$	69,771
Long-term	4,392		30,653		1,605		37,457
Total electric derivatives	$	23,443	$	112,106	$	4,822	$	107,228
Natural Gas portfolio:
Current	$	5,367	$	49,967	$	17,961	$	66,202
Long-term	833		17,123		1,565		22,605
Total natural gas derivatives	$	6,200	$	67,090	$	19,526	$	88,807
Total energy derivatives	$	29,643	$	179,196	$	24,348	$	196,035

At December 31, 2015, the Company had total assets of 29.6 million and total liabilities of 179.2 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 $11.9 million.

The change in fair value of the Company’s outstanding energy derivative instruments from December 31, 2014 through December 31, 2015 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, 2014	$	(171,687	)
Contracts realized or otherwise settled during 2015	147,086
Change in fair value of derivatives	(124,952		)
Fair value of contracts outstanding at December 31, 2015	$	(149,553	)

The fair value of the Company’s outstanding derivative instruments at December 31, 2015, 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)	2016			2017-2018			2019-2020			Thereafter		Total
Prices provided by external sources ¹	$	(111,790	)	$	(27,505	)	$	(530	)	$	—	$	(139,825	)
Prices based on internal models and valuation methods	4,787			(13,033		)	(1,482		)	—		(9,728		)
Total fair value	$	(107,003	)	$	(40,538	)	$	(2,012	)	$	—	$	(149,553	)

______________


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, 2015, PSE held approximately $737.3 million in standby letters of credit or limited parental guarantees and had nine 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. As of December 31, 2015, approximately 86% of the Company's energy portfolio exposure, including NPNS transactions, were entered into with investment grade counterparties which, in the majority of cases, do not require collateral calls on the contracts. 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. 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 by counterparty and arriving at 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. The fair value of derivatives includes the impact of credit and non-performance reserves. As of December 31, 2015, 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, 2015, 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, 2015				December 31, 2014
(Dollars in Thousands)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Puget Energy	$	5,524,887	$	6,679,008	$	5,328,608	$	6,743,789
Puget Sound Energy	$	3,933,388	$	4,699,621	$	3,877,192	$	4,827,641

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, 2015 was a net loss of $5.7 million after tax and accumulated amortization. This compares to an after-tax loss of $6.0 million in OCI as of December 31, 2014. 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, 2015.

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, 2015, Puget Energy had two interest rate swap contracts outstanding and PSE did not have any outstanding interest rate swap instruments. At December 31, 2015, the fair value of the interest rate swaps was a $5.1 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 $0.4 million.

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



Puget Energy	December 31,
(Dollars in Thousands)	2015		2014
Interest rate swap liability:
Current	$	4,753	$	6,222
Long-term	297		2,851
Total interest rate swaps	$	5,050	$	9,073

The change in fair value of Puget Energy’s outstanding interest rate swaps from December 31, 2014 through December 31, 2015 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, 2014	$	(9,073	)
Contracts realized or otherwise settled during 2015	2,316
Change in fair value of derivatives	1,707
Fair value of contracts outstanding at December 31, 2015	$	(5,050	)

The fair value of Puget Energy’s outstanding interest rate swaps at December 31, 2015, 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)	2016			2017-2018			2019-2020		Thereafter		Total
Prices provided by external sources ¹	$	(4,753	)	$	(297	)	$	—	$	—	$	(5,050	)

______________


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.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA



	Page
REPORTS:
Report of Management and Statement of Responsibility	62
Report of Independent Registered Public Accounting Firm – Puget Energy	63
Report of Independent Registered Public Accounting Firm – Puget Sound Energy	64

CONSOLIDATED FINANCIAL STATEMENTS:
PUGET ENERGY:
Consolidated Statements of Income - Years Ended December 31, 2015, 2014 and 2013	65
Consolidated Statements of Comprehensive Income - Years Ended December 31, 2015, 2014 and 2013	66
Consolidated Balance Sheets - December 31, 2015 and 2014	67
Consolidated Statements of Common Shareholder’s Equity - Years Ended December 31, 2015, 2014 and 2013	69
Consolidated Statements of Cash Flows - Years Ended December 31, 2015, 2014 and 2013	70

PUGET SOUND ENERGY:
Consolidated Statements of Income - Years Ended December 31, 2015, 2014 and 2013	71
Consolidated Statements of Comprehensive Income - Years Ended December 31, 2015, 2014 and 2013	72
Consolidated Balance Sheets - December 31, 2015 and 2014	73
Consolidated Statements of Common Shareholder’s Equity - Years Ended December 31, 2015, 2014 and 2013	75
Consolidated Statements of Cash Flows - Years Ended December 31, 2015, 2014 and 2013	76



NOTES to the Consolidated Financial Statements of Puget Energy and Puget Sound Energy:
Note 1.	Summary of Significant Accounting Policies	77
Note 2.	New Accounting Pronouncements	82
Note 3.	Regulation and Rates	84
Note 4.	Dividend Payment Restrictions	91
Note 5.	Utility Plant	92
Note 6.	Long-Term Debt	95
Note 7.	Liquidity Facilities and Other Financing Arrangements	97
Note 8.	Leases	98
Note 9.	Accounting for Derivative Instruments and Hedging Activities	98
Note 10.	Fair Value Measurements	102
Note 11.	Employee Investment Plans	107
Note 12.	Retirement Benefits	108
Note 13.	Income Taxes	114
Note 14.	Litigation	117
Note 15.	Commitments and Contingencies	117
Note 16.	Related Party Transactions	119
Note 17.	Segment Information	119
Note 18.	Accumulated Other Comprehensive Income (Loss)	120



SUPPLEMENTAL QUARTERLY FINANCIAL DATA	124

SCHEDULE:
I. Condensed Financial Information of Puget Energy	125
II. Valuation and Qualifying Accounts and Reserves	129
Years Ended December 31, 2015, 2014 and 2013

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.

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

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Puget Energy, Inc.

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Puget Energy, Inc. and its subsidiaries at December 31, 2015 and December 31, 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 in 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 indexpresents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, 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 in Management's Report on Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements and 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.

As discussed in Note 13 to the consolidated financial statements, in 2015 the Company changed the manner in which deferred tax assets and liabilities are classified on the balance sheet.

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 26, 2016

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Puget Sound Energy, Inc.

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Puget Sound Energy, Inc. and its subsidiary at December 31, 2015 and December 31, 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 in 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 indexpresents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, 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 in Management's Report on Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As discussed in Note 13 to the consolidated financial statements, in 2015 the Company changed the manner in which deferred tax assets and liabilities are classified on the balance sheet.

/s/ PricewaterhouseCoopers LLP

Seattle, Washington

February 26, 2016

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands)



	Year Ended December 31,
	2015			2014			2013
Operating revenue:
Electric	$	2,128,468		$	2,083,797		$	2,156,920
Natural gas	947,549			1,012,859			1,028,357
Other	16,683			16,515			2,020
Total operating revenue	3,092,700			3,113,171			3,187,297
Operating expenses:
Energy costs:
Purchased electricity	499,522			514,087			541,905
Electric generation fuel	249,907			263,493			261,332
Residential exchange	(112,473		)	(129,036		)	(81,053		)
Purchased natural gas	403,310			458,691			488,201
Unrealized (gain) loss on derivative instruments, net	(13,233		)	84,146			(102,744		)
Utility operations and maintenance	530,720			550,146			529,939
Non-utility expense and other	10,818			13,109			(3,555		)
Depreciation and amortization	420,807			365,606			388,955
Conservation amortization	110,866			104,096			105,897
Taxes other than income taxes	320,531			310,982			303,260
Total operating expenses	2,420,775			2,535,320			2,432,137
Operating income (loss)	671,925			577,851			755,160
Other income (deductions):
Other income	20,711			24,038			38,693
Other expense	(6,764		)	(7,457		)	(7,134		)
Non-hedged interest rate swap expense	(3,796		)	(3,915		)	2,420
Interest charges:
AFUDC	7,575			5,611			11,261
Interest expense	(356,696		)	(367,308		)	(392,264		)
Income (loss) before income taxes	332,955			228,820			408,136
Income tax (benefit) expense	91,776			56,985			122,408
Net income (loss)	$	241,179		$	171,835		$	285,728

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

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands)



	Year Ended December 31,
	2015		2014			2013
Net income (loss)	$	241,179	$	171,835		$	285,728
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $5,087, $(45,890) and $41,773, respectively	9,444		(85,224		)	77,579
Reclassification of net unrealized (gain) loss on energy derivative instruments, net of tax of $179, $200 and $20, respectively	333		372			37
Reclassification of net unrealized (gain) loss on interest rate swaps, net of tax of $0, $50 and $1,577, respectively	—		94			2,928
Other comprehensive income (loss)	9,777		(84,758		)	80,544
Comprehensive income (loss)	$	250,956	$	87,077		$	366,272

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

PUGET ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

ASSETS



	December 31,
	2015			2014
Utility plant (at original cost, including construction work in progress of $408,795 and $239,690, respectively):
Electric plant	$	7,432,490		$	7,135,206
Natural gas plant	2,850,290			2,680,067
Common plant	508,750			472,926
Less: Accumulated depreciation and amortization	(1,878,868		)	(1,611,220		)
Net utility plant	8,912,662			8,676,979
Other property and investments:
Goodwill	1,656,513			1,656,513
Other property and investments	86,731			91,139
Total other property and investments	1,743,244			1,747,652
Current assets:
Cash and cash equivalents	42,494			37,527
Restricted cash	7,949			32,863
Accounts receivable, net of allowance for doubtful accounts of $9,756 and $7,472, respectively	324,391			306,923
Unbilled revenue	217,274			168,039
Purchased gas adjustment receivable	—			21,073
Materials and supplies, at average cost	78,244			83,189
Fuel and gas inventory, at average cost	58,658			69,433
Unrealized gain on derivative instruments	24,418			21,178
Taxes	293			301
Prepaid expense and other	16,827			20,905
Power contract acquisition adjustment gain	37,031			43,843
Total current assets	807,579			805,274
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes	73,231			95,432
Power cost adjustment mechanism	4,749			4,623
Regulatory assets related to power contracts	26,223			29,816
Other regulatory assets	894,071			866,835
Unrealized gain on derivative instruments	5,225			3,170
Power contract acquisition adjustment gain	288,757			347,547
Other	96,878			96,275
Total other long-term and regulatory assets	1,389,134			1,443,698
Total assets	$	12,852,619		$	12,673,603

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

PUGET ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

CAPITALIZATION AND LIABILITIES



	December 31,
	2015			2014
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
Retained earnings	249,534			271,414
Accumulated other comprehensive income (loss), net of tax	(27,266		)	(37,043		)
Total common shareholder’s equity	3,531,225			3,543,328
Long-term debt:
First mortgage bonds and senior notes	3,364,412			3,189,412
Pollution control bonds	161,860			161,860
Junior subordinated notes	250,000			250,000
Long-term debt	1,800,000			1,699,000
Debt discount and other	(210,389		)	(218,664		)
Total long-term debt	5,365,883			5,081,608
Total capitalization	8,897,108			8,624,936
Current liabilities:
Accounts payable	259,353			307,578
Short-term debt	159,004			85,000
Current maturities of long-term debt	—			162,000
Purchased gas adjustment liability	12,589			—
Accrued expenses:
Taxes	114,854			107,782
Salaries and wages	38,457			40,970
Interest	73,378			78,914
Unrealized loss on derivative instruments	136,173			142,195
Power contract acquisition adjustment loss	3,611			3,593
Other	53,867			62,464
Total current liabilities	851,286			990,496
Other Long-term and regulatory liabilities:
Deferred income taxes	1,435,955			1,360,912
Unrealized loss on derivative instruments	48,073			62,913
Regulatory liabilities	652,441			633,471
Regulatory liabilities related to power contracts	325,788			391,389
Power contract acquisition adjustment loss	22,613			26,223
Other deferred credits	619,355			583,263
Total other long-term and regulatory liabilities	3,104,225			3,058,171
Commitments and contingencies (Note 15)
Total capitalization and liabilities	$	12,852,619		$	12,673,603

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

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY

(Dollars in Thousands)



	Common Stock			Additional					Accumulated Other
	Shares	Amount		Paid-in Capital		Retained Earnings			Comprehensive Income (Loss)			Total Equity
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
Net income (loss)	—	—		—		241,179			—			241,179
Common stock dividend	—	—		—		(263,059		)	—			(263,059		)
Other comprehensive income (loss)	—	—		—		—			9,777			9,777
Balance at December 31, 2015	200	$	—	$	3,308,957	$	249,534		$	(27,266	)	$	3,531,225

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

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)



	Year Ended December 31,
	2015			2014			2013
Operating activities:
Net income (loss)	$	241,179		$	171,835		$	285,728
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	420,807			365,606			388,955
Conservation amortization	110,866			104,096			105,897
Deferred income taxes and tax credits, net	91,978			56,984			122,409
Gain on land sales	—			(4,071		)	—
Net unrealized (gain) loss on derivative instruments	(17,255		)	80,139			(106,540		)
Derivative contracts classified as financing activities due to merger	8,045			16,349			34,250
AFUDC - equity	(9,325		)	(7,002		)	(15,930		)
Funding of pension liability	(18,000		)	(18,000		)	(20,400		)
Regulatory assets and liabilities	(153,877		)	(228,334		)	(72,524		)
Other long-term assets and liabilities	35,270			23,762			155,138
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	(66,703		)	153,434			(103,949		)
Materials and supplies	4,945			4,951			(5,787		)
Fuel and gas inventory	9,332			(2,742		)	21,633
Taxes	8			(4		)	4,499
Prepayments and other	4,078			(2,136		)	(5,357		)
Purchased gas adjustment	33,662			(27,011		)	(26,649		)
Accounts payable	(48,037		)	9,098			4,597
Taxes payable	7,072			(1,777		)	13,936
Accrued expenses and other	(5,323		)	6,605			(13,838		)
Net cash provided by (used in) operating activities	648,722			701,782			766,068
Investing activities:
Construction expenditures - excluding equity AFUDC	(587,225		)	(493,130		)	(567,938		)
Treasury grants received	—			107,876			—
Proceeds from disposition of assets	—			20,296			108,362
Restricted cash	24,914			(25,692		)	(3,471		)
Other	754			(4,512		)	(17,871		)
Net cash provided by (used in) investing activities	(561,557		)	(395,162		)	(480,918		)
Financing activities:
Change in short-term debt, net	74,004			(77,000		)	(26,578		)
Dividends paid	(263,059		)	(223,428		)	(170,821		)
Long-term notes and bonds issued	825,000			299,000			161,860
Redemption of bonds and notes	(711,000		)	(299,000		)	(309,860		)
Derivative contracts classified as financing activities due to merger	(8,045		)	(16,349		)	(34,250		)
Issuance cost of bonds and other	902			3,382			3,259
Net cash provided by (used in) financing activities	(82,198		)	(313,395		)	(376,390		)
Net increase (decrease) in cash and cash equivalents	4,967			(6,775		)	(91,240		)
Cash and cash equivalents at beginning of period	37,527			44,302			135,542
Cash and cash equivalents at end of period	$	42,494		$	37,527		$	44,302
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	339,866		$	349,402		$	334,041
Cash payments (refunds) for income taxes	2			—			(4,500		)
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows	$	51,588		$	51,776		$	49,977

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands)



	Year Ended December 31,
	2015			2014			2013
Operating revenue:
Electric	$	2,128,468		$	2,083,797		$	2,156,920
Natural gas	947,549			1,012,859			1,028,357
Other	17,241			19,467			2,058
Total operating revenue	3,093,258			3,116,123			3,187,335
Operating expenses:
Energy costs:
Purchased electricity	499,522			514,087			541,905
Electric generation fuel	249,907			263,493			261,332
Residential exchange	(112,473		)	(129,036		)	(81,053		)
Purchased natural gas	403,310			458,691			488,201
Unrealized (gain) loss on derivative instruments, net	(12,688		)	85,636			(98,880		)
Utility operations and maintenance	530,720			550,146			529,939
Non-utility expense and other	26,618			23,729			12,205
Depreciation and amortization	420,807			365,606			388,955
Conservation amortization	110,866			104,096			105,897
Taxes other than income taxes	320,531			310,982			303,260
Total operating expenses	2,437,120			2,547,430			2,451,761
Operating income (loss)	656,138			568,693			735,574
Other income (deductions):
Other income	20,711			24,036			38,690
Other expense	(6,764		)	(7,457		)	(7,134		)
Interest charges:
AFUDC	7,575			5,611			11,261
Interest expense	(247,507		)	(264,745		)	(261,264		)
Interest expense on parent note	(64		)	(182		)	(112		)
Income (loss) before income taxes	430,089			325,956			517,015
Income tax (benefit) expense	125,900			89,342			160,886
Net income (loss)	$	304,189		$	236,614		$	356,129

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands)



	Year Ended December 31,
	2015		2014			2013
Net income (loss)	$	304,189	$	236,614		$	356,129
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $10,987, $(41,395) and $47,705, respectively	20,404		(76,876		)	88,593
Reclassification of net unrealized (gain) loss on energy derivative instruments, net of tax of $369, $722 and $1,373, respectively	686		1,341			2,549
Amortization of treasury interest rate swaps to earnings, net of tax of $171, $171 and $171, respectively	317		317			317
Other comprehensive income (loss)	21,407		(75,218		)	91,459
Comprehensive income (loss)	$	325,596	$	161,396		$	447,588

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

ASSETS



	December 31,
	2015			2014
Utility plant (at original cost, including construction work in progress of $408,795 and $239,690, respectively):
Electric plant	$	9,601,091		$	9,330,999
Natural gas plant	3,444,744			3,282,818
Common plant	548,657			512,842
Less: Accumulated depreciation and amortization	(4,681,830		)	(4,449,680		)
Net utility plant	8,912,662			8,676,979
Other property and investments:
Other property and investments	83,069			86,913
Total other property and investments	83,069			86,913
Current assets:
Cash and cash equivalents	41,856			37,466
Restricted cash	7,949			32,863
Accounts receivable, net of allowance for doubtful accounts of $9,756 and $7,472, respectively	324,358			307,046
Unbilled revenue	217,274			168,039
Purchased gas adjustment receivable	—			21,073
Materials and supplies, at average cost	78,244			83,189
Fuel and gas inventory, at average cost	57,324			66,656
Unrealized gain on derivative instruments	24,418			21,178
Taxes	293			301
Prepaid expenses and other	16,826			20,907
Total current assets	768,542			758,718
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes	72,694			94,913
Power cost adjustment mechanism	4,749			4,623
Other regulatory assets	894,059			866,793
Unrealized gain on derivative instruments	5,225			3,170
Other	88,535			89,306
Total other long-term and regulatory assets	1,065,262			1,058,805
Total assets	$	10,829,535		$	10,581,415

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

CAPITALIZATION AND LIABILITIES



	December 31,
	2015			2014
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	3,275,105			3,246,205
Retained earnings	236,578			202,622
Accumulated other comprehensive income (loss), net of tax	(149,550		)	(170,957		)
Total common shareholder’s equity	3,362,992			3,278,729
Long-term debt:
First mortgage bonds and senior notes	3,364,412			3,189,412
Pollution control bonds	161,860			161,860
Junior subordinated notes	250,000			250,000
Debt discount and other	(1,888		)	(13		)
Total long-term debt	3,774,384			3,601,259
Total capitalization	7,137,376			6,879,988
Current liabilities:
Accounts payable	259,353			307,572
Short-term debt	159,004			85,000
Short-term note owed to parent	—			28,933
Current maturities of long-term debt	—			162,000
Purchased gas adjustment liability	12,589			—
Accrued expenses:
Taxes	114,854			107,782
Salaries and wages	38,457			40,970
Interest	47,772			55,346
Unrealized loss on derivative instruments	131,420			135,973
Other	53,868			62,464
Total current liabilities	817,317			986,040
Other Long-term and regulatory liabilities:
Deferred income taxes	1,556,616			1,441,410
Unrealized loss on derivative instruments	47,776			60,063
Regulatory liabilities	651,094			630,651
Other deferred credits	619,356			583,263
Total other long-term and regulatory liabilities	2,874,842			2,715,387
Commitments and contingencies (Note 15)
Total capitalization and liabilities	$	10,829,535		$	10,581,415

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY

(Dollars in Thousands)



	Common Stock			Additional					Accumulated Other
	Shares	Amount		Paid-in Capital		Retained Earnings			Comprehensive Income (loss)			Total Equity
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
Net income (loss)	—	—		—		304,189			—			304,189
Common stock dividend	—	—		—		(270,233		)	—			(270,233		)
Capital Contribution	—	—		28,900		—			—			28,900
Other comprehensive income (loss)	—	—		—		—			21,407			21,407
Balance at December 31, 2015	85,903,791	$	859	$	3,275,105	$	236,578		$	(149,550	)	$	3,362,992

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)



	Year Ended December 31,
	2015			2014			2013
Operating activities:
Net income (loss)	$	304,189		$	236,614		$	356,129
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	420,807			365,606			388,955
Conservation amortization	110,866			104,096			105,897
Deferred income taxes and tax credits, net	125,900			89,342			160,886
Gain on land sales	—			(4,071		)	—
Net unrealized (gain) loss on derivative instruments	(12,688		)	85,636			(98,880		)
AFUDC - equity	(9,325		)	(7,002		)	(15,930		)
Funding of pension liability	(18,000		)	(18,000		)	(20,400		)
Regulatory assets and liabilities	(153,877		)	(228,334		)	(72,524		)
Other long-term assets and liabilities	39,379			20,589			138,664
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	(66,547		)	153,626			(104,059		)
Materials and supplies	4,945			4,951			(5,787		)
Fuel and gas inventory	9,332			(2,742		)	21,633
Taxes	8			(4		)	4,499
Prepayments and other	4,081			(2,136		)	(5,357		)
Purchased gas adjustment	33,662			(27,011		)	(26,649		)
Accounts payable	(48,031		)	9,098			4,597
Taxes payable	7,072			(1,777		)	13,936
Accrued expenses and other	(12,992		)	4,246			(9,931		)
Net cash provided by (used in) operating activities	738,781			782,727			835,679
Investing activities:
Construction expenditures - excluding equity AFUDC	(587,225		)	(493,130		)	(567,938		)
Treasury grants received	—			107,876			—
Proceeds from disposition of assets	—			20,296			108,362
Restricted cash	24,914			(25,692		)	(3,471		)
Other	6,386			(1,683		)	(16,751		)
Net cash provided by (used in) investing activities	(555,925		)	(392,333		)	(479,798		)
Financing activities:
Change in short-term debt, net	74,004			(77,000		)	(26,578		)
Dividends paid	(270,233		)	(323,424		)	(410,977		)
Loan from (payment to) parent	(28,933		)	(665		)	—
Investment from parent	28,900			—			—
Long-term notes and bonds issued	425,000			—			161,860
Redemption of bonds and notes	(412,000		)	—			(174,860		)
Issuance cost of bonds and other	4,796			4,050			3,255
Net cash provided by (used in) financing activities	(178,466		)	(397,039		)	(447,300		)
Net increase (decrease) in cash and cash equivalents	4,390			(6,645		)	(91,419		)
Cash and cash equivalents at beginning of period	37,466			44,111			135,530
Cash and cash equivalents at end of period	$	41,856		$	37,466		$	44,111
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	242,774		$	253,803		$	244,887
Cash payments (refunds) for income taxes	2			—			(4,500		)
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows	$	51,588		$	51,776		$	49,977

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) Summary of Significant Accounting Policies

Basis of Presentation

Puget Energy, Inc. (Puget Energy) is an energy services holding company that owns Puget Sound Energy, Inc. (PSE). PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering 6,000 square miles, primarily in the Puget Sound region. 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 $234.2 million, $231.7 million and $243.9 million for 2015, 2014 and 2013, 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.

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, which were previously recorded in utility plant, are apportioned between regulatory assets/liabilities and earnings. However, gains and losses on assets sold or retired, not previously recorded in utility plant, 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%, for each of 2015, 2014 and 2013; depreciable natural gas utility plant was 3.4%, for each of 2015, 2014 and 2013; and depreciable common utility plant was 8.5%, 8.5% and 11.4% in 2015, 2014 and 2013, 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.

Puget Energy conducted its annual impairment test in 2015 using an October 1, 2015 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, 2015. There were no known events or circumstances from the date of the assessment through December 31, 2015 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 $42.5 million and $37.5 million as of December 31, 2015 and 2014, respectively. The 2015 and 2014 balance consisted of cash equivalents, which are reported at cost and approximate fair value, and were $2.4 million and $1.8 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 Natural Gas Inventory

Fuel and natural 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. Natural 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.

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 primarily 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 are based on the effective dates as follows:



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

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.

PSE's electric and natural gas operations contain a revenue decoupling mechanism under which PSE's actual energy delivery revenues related to electric transmission and distribution, natural gas operations and general administrative costs are compared with authorized revenues allowed under the mechanism. The mechanism mitigates volatility in revenue due to weather and gross margin erosion related to energy efficiency. Any differences in revenue are deferred to a regulatory asset for under recovery or regulatory liability for over recovery under alternative revenue recognition standard. To record revenues under this program, the Company must be able to collect the revenue within 24 months based on alternative revenue recognition guidance. Decoupled rate increases are effective May 1 of each year subject to a 3.0% cap of total revenue for decoupled rate schedules. Any excess revenue above 3.0% will be included in the following year's decoupled rate. The Company will be able to recognize revenue below the 3.0% cap of total revenue for decoupled rate schedules. For revenue deferrals exceeding the annual 3.0% rate cap of total revenue for decoupled rate schedules, the Company will assess the excess amount to determine its ability to be collected within 24 months. If the excess amount cannot be collected within 24 months, for GAAP purposes only, the Company will not

record any decoupling revenue unless it is within the 24 months of collection, but will collect non-recorded amounts when actually billed. Revenues associated with energy costs under the Power Cost Adjustment (PCA) mechanism and Purchased Gas Adjustment (PGA) mechanism are excluded from the decoupling mechanism.

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, 2015 and 2014 was $9.8 million and $7.5 million, respectively.

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's 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, who is the ultimate tax payer.

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 Natural Gas Sales

As part of the Company’s electric operations, PSE purchases natural gas for 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 natural 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 other comprehensive income (AOCI) 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. 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.

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, 2015, Puget Energy has interest rate swap contracts outstanding originally 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.

(2) New Accounting Pronouncements

Revenue Recognition

In May 2014, the FASB issued Accounting Standards Update (ASU) No. 2014-09, "Revenue from Contracts with Customers (Topic 606)", which 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 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.

In August 2015, the FASB issued ASU 2015-14, "Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date," deferring the effective date for ASU 2014-09 to fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. In addition to the FASB's deferral decision, FASB provided reporting entities with an option to adopt ASU 2014-09 for the fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, the original effective date. The Company plans to adopt ASU 2014-09 according to the original effective date. Reporting entities also 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.

Debt Issuance Costs

In April 2015, the FASB issued ASU 2015-03, "Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs." ASU 2015-03 requires debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the debt liability, consistent with the presentation of a debt discount. This new guidance affects only the presentation of debt issuance costs and not the recognition and measurement of debt issuance costs. ASU 2015-03 is to be applied on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance.

In August 2015, the FASB issued ASU 2015-15, "Interest-Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangement." In accordance with the United States Securities and Exchange Commission (SEC) Staff Announcement at the June 18, 2015 Emerging Issues Task Force (EITF) meeting about debt issuance costs, ASU 2015-15 amended the accounting guidance updated by ASU 2015-03 to allow reporting entities the option to defer and present debt issuance costs related to line-of-credit arrangements as an asset and subsequently amortize the deferred debt issuance costs ratably over the term of the line-of-credit arrangement.

ASU 2015-03 and ASU 2015-15 are effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption of the amendments is permitted for financial statements that have not been previously issued. The Company plans to adopt the amendments during fiscal year 2016. The amount of unamortized debt issuance costs at Puget Energy as of December 31, 2015 and 2014 totaled $38.4 million and $35.7 million, respectively. The amount of unamortized debt issuance costs at PSE as of December 31, 2015 and 2014 totaled $30.0 million and $28.7 million, respectively.

Internal-Use Software

In April 2015, the FASB issued ASU 2015-05, "Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer's Accounting for Fees Paid in a Cloud Computing Arrangement." ASU 2015-05 requires a customer in a cloud computing arrangement to follow internal-use software guidance if both of the following criteria are met: the customer has the contractual right to take possession of the software at any time during the cloud computing arrangement and can feasibly run the software on its own hardware. If the customer does not meet both criteria, the cloud computing arrangement is considered a service contract and separate accounting for a license would not be permitted.

ASU 2015-05 is effective for annual reporting periods, including interim periods within those annual reporting periods, beginning after December 15, 2015. Early adoption is permitted. The Company plans to adopt ASU 2015-05 during fiscal year 2016 and is in the process of evaluating the potential impacts, if any, of this new guidance on its financial statements.

Fair Value Measurement

In May 2015, the FASB issued ASU 2015-07, "Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent)," which removes the requirement to categorize within the fair value hierarchy all investments for which their fair value is measured using the net asset value per share practical expedient. This ASU also removes the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient. Instead, those disclosures will be limited to investments for which the Company has elected to measure the fair value using that practical expedient.

ASU 2015-07 is effective for annual reporting periods, and interim periods within those reporting periods, beginning after December 15, 2015, and requires reporting entities to apply this ASU retrospectively to all periods presented. Early adoption is permitted. The Company plans to adopt ASU 2015-07 during fiscal year 2016. At this time, the Company cannot determine the impact this standard will have on its consolidated financial statements.

Inventory

In July 2015, the FASB issued ASU 2015-11, "Inventory (Topic 330): Simplifying the Measurement of Inventory." ASU 2015-11 requires inventory within the scope of this Topic 330 to be measured at the lower of cost and net realizable value. This amendment does not apply to inventory that is measured using last-in, first-out (LIFO) or the retail inventory method. This amendment applies to all other inventory, including inventory measured using first-in, first-out (FIFO) or average cost.

The new accounting guidance is effective for annual reporting periods, and interim periods within those annual reporting periods, beginning after December 15, 2016, with early adoption permitted. The Company plans to adopt ASU 2015-11 during fiscal year 2017. At this time, the Company cannot determine the impact this standard will have on its consolidated financial statements.

Retirement Benefits

In July 2015, the FASB issued ASU 2015-12, "Plan Accounting: Defined Benefit Pension Plans (Topic 960), Defined Contribution Pension Plans (Topic 962), and Health and Welfare Benefit Plans (Topic 965)." ASU 2015-12 is made up of three parts: Part I, Fully Benefit-Responsive Investment Contracts (Part I); Part II, Plan Investment Disclosures (Part II); and Part III, Measurement Date Practical Expedient (Part III).

Part I requires fully benefit-responsive contracts to be measured, presented and disclosed only at contract value. Part II requires both participant-directed and nonparticipant-directed investments of employee benefit plans be grouped only by general type, and removes the requirement to include the disclosure of (i) the investment strategy of an investment measured using the net asset value per share practical expedient and is part of a fund that files a U.S. Department of Labor Form 5500; and (ii) the net appreciation or depreciation for investments by general type. Part III provides entities that have a fiscal year-end that does not coincide with a month-end a practical expedient to permit plans to measure investments and investment-related accounts as of a month-end date that is closest to the plan's fiscal year-end.

All three parts are effective for fiscal years beginning after December 15, 2015, and early adoption is permitted for each part. Parts I and II must be applied retrospectively for all financial statements presented. The amendments in Part III must be applied prospectively. The Company plans to adopt ASU 2015-12 during the fiscal year 2016, and is in the process of evaluating the potential impacts, if any, of this new guidance on its financial statements.

Derivatives and Hedging

In August 2015, the FASB Issues ASU 2015-13, "Derivatives and Hedging (Topic 815): Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Markets." ASU 2015-13 allows certain reporting entities that enter into derivative contracts for the purchase or sale of electricity on a forward basis and arrange for transmission through a nodal energy market, to designate those contracts as normal purchase or normal sale contracts, if the physical delivery criterion is met. This designation removes the ASC 815, Derivatives and Hedging (ASC 815), requirement to measure those derivative contracts at fair value.

This amendment was effective upon issuance, and if elected, the guidance must be applied prospectively. The Company does not expect this guidance to have a material impact on its results of operations or financial position.

Deferred Income Taxes

This amendment is effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Earlier adoption is permitted for all entities as of the beginning of any interim or annual reporting period. The Company has early adopted ASU 2015-17 for the annual reporting period ended December 31, 2015, and has applied this amendment retrospectively. Except for changes in Consolidated Balance Sheet presentation, this guidance does

not have a material impact on the Company's results of operations or financial position. For additional information on the impact of this guidance, see Note 13, Income Taxes.

(3) Regulation and Rates

Regulatory Assets and Liabilities

Regulatory accounting allows 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 that are expected to be returned to customers in the future.

Below is a table 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

The net regulatory assets and liabilities at December 31, 2015 and 2014 included the following:



Puget Sound Energy	Remaining Amortization Period	December 31,
(Dollars in Thousands)		2015					2014
Storm damage costs electric	1 to 3 years			$	125,777			$	118,824
Chelan PUD contract initiation	15.8 Years			112,228				119,316
Deferred decoupling revenue		104,150					55,363
Decoupling revenue in excess of 2 years		(9,980	)				—
Total deferred decoupling revenue	Less than 2 years			94,170				55,363
Lower Snake River	1 to 21.3 years			79,599				86,275
Deferred income taxes	(a)			72,694				94,913
Environmental remediation	(a)			66,887				66,018
Baker Dam licensing operating and maintenance costs	43 years			63,394				61,577
PGA deferral of unrealized losses on derivative instruments	(a)			60,889				69,280
Deferred Washington Commission AFUDC	35 years			52,197				53,709
Unamortized loss on reacquired debt	1 to 20.5 years			44,984				35,667
Property tax tracker	Less than 2 years			40,353				32,253
Energy conservation costs	1 to 2 years			36,646				42,374
White River relicensing and other costs	16.9 years			23,054				26,685
Mint Farm ownership and operating costs	9.3 years			18,320				20,320
Ferndale	3.8 years			15,253				19,232
Electron unrecovered loss	3 years			10,569				14,008
Snoqualmie licensing operating and maintenance costs	29 years			7,980				9,202
Colstrip common property	8.5 years			6,049				6,764
Colstrip major maintenance	2 years			5,897				2,712
Investment in Bonneville Exchange power contract	1.5 years			5,290				8,816
Snoqualmie	2.8 years			5,024				6,798
PGA receivable	1 year			—				21,073
Various other regulatory assets	Varies			24,248				16,223
Total PSE regulatory assets				$	971,502			$	987,402
Cost of removal	(b)			$	(347,472	)		$	(313,088	)
Treasury grants	4 to 43 years			(157,102		)		(180,496		)
Production tax credits	(c)			(93,616		)		(93,616		)
Decoupling over-collection	Less than 2 years			(25,483		)		(12,582		)
PGA payable	1 year			(12,589		)		—
Summit purchase option buy-out	4.8 years			(7,612		)		(9,188		)
Deferral of treasury grant amortization	Less than 4 years			(6,058		)		(8,197		)
Various other regulatory liabilities	Up to 4 years			(13,751		)		(18,215		)
Total PSE regulatory liabilities				$	(663,683	)		$	(635,382	)
PSE net regulatory assets (liabilities)				$	307,819			$	352,020

_______________


^(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.



Puget Energy	Remaining Amortization Period	December 31,
(Dollars in Thousands)	Remaining Amortization Period	2015			2014
Total PSE regulatory assets	(a)	$	971,502		$	987,402
Puget Energy acquisition adjustments:
Regulatory assets related to power contracts	1 to 21 years	26,223			29,816
Various other regulatory assets	Varies	549			561
Total Puget Energy regulatory assets		$	998,274		$	1,017,779
Total PSE regulatory liabilities	(a)	$	(663,683	)	$	(635,382	)
Puget Energy acquisition adjustments:
Regulatory liabilities related to power contracts	1 to 36 years	(325,788		)	(391,389		)
Various other regulatory liabilities	Varies	(1,347		)	(2,820		)
Total Puget Energy regulatory liabilities		$	(990,818	)	$	(1,029,591	)
Puget Energy net regulatory asset (liabilities)		$	7,456		$	(11,812	)

_______________


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

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 (ARO),” PSE reclassified from accumulated depreciation to a regulatory liability $347.5 million and $313.1 million in 2015 and 2014, respectively, for the cost of removal of utility plant. These amounts are collected from PSE’s customers through depreciation rates.

2013 Expedited Rate Filing, Decoupling and Centralia Decision

On June 25, 2013, the Washington Commission issued final orders resolving the amended decoupling petition, the ERF filing and the Petition for Reconsideration (related to the TransAlta Centralia power purchase agreement). Order No. 7 in the ERF/decoupling proceeding approved PSE's ERF filing with a small change to its cost of capital from 7.80% to7.77% to update long term debt costs. This order also approved the property tax tracker discussed below and approved the amended decoupling and rate plan filing with the further condition that PSE and the customers will share 50.0% each in earnings in excess of the 7.77% authorized rate of return. In addition, the rate plan increase allowed decoupling revenue per customer for the recovery of delivery system costs will subsequently increase by 3.0% for the electric customers and 2.2% for the gas customers on January 1 of each year, until the conclusion of PSE's next GRC which will be filed before April 1, 2016. In the rate plan, increases are subject to a cap of 3.0% of the total revenue for customers. Order No. 8 in the TransAlta Centralia proceeding granted in part and denied in part PSE's Petition for Reconsideration, clarifying certain portions of the Washington Commission's original order regarding TransAlta Centralia.

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 argued 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 GRC, but reversed and remanded the cost of equity for further adjudication consistent with the court's decision. The remand proceeding evidentiary hearings regarding return on equity (ROE) were held in February 2015 and initial briefs and reply briefs were filed in March 2015. The Washington Commission issued a final order on remand on June 29, 2015, in which it found that 9.8% is a reasonable ROE for PSE for the term of the rate plan, taking decoupling and other relevant factors into account.

Expedited Rate Filing

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 electric and natural gas customers is an increase of $21.4 million, or 1.0%, annually and an increase of $10.8 million, or 1.1% annually, respectively. The estimated revenue impact of the ERF filings for electric and natural gas customers is an increase of $30.7 million, or 1.5%, annually and a decrease of $2.0 million, or a decrease of 0.2% annually, respectively. In its order, the Washington Commission approved a weighted cost of capital of 7.77% and a capital structure that included 48.0% common equity with a ROE 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 February 4, 2013, PSE filed revised tariffs in an ERF proceeding seeking to update the rates set by the Washington Commission in the final order of May 2012 in PSE's general rate case (GRC). This ERF filing was limited in scope and rate impact. This filing was primarily intended to establish baseline rates on which the decoupling mechanisms, described below, were 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 accruals will be deferred and recovered in a property tax tracker.

Decoupling Filings

On April 22, 2015, the Washington Commission approved PSE's request to change rates under its electric and natural gas decoupling mechanism, effective May 1, 2015. As part of this filing, PSE also requested to change the methodology of how decoupling deferrals are calculated going forward and adjust deferrals calculated in 2014. The change was done to ensure that the amortization of prior years’ accumulated decoupling deferrals were not included in the calculation of the current year decoupling deferrals. The effect of the methodology change was a reduction of approximately $12.0 million previously recognized revenue from May through December of 2014. The overall changes represent a rate increase for electric customers of $53.8 million, or 2.6%, annually, and a rate increase for natural gas customers of $22.0 million, or 2.1%, annually, effective May 1, 2015. In addition, PSE exceeded the earnings test threshold for its natural gas business in 2014. As a result, PSE recorded a reduction in natural gas decoupling deferral and revenue of $1.3 million. This was reflected as a reduction to the natural gas rate increases noted above. As noted earlier, the Company is also limited to a 3.0% annual decoupling related cap on increases in total revenue. This limitation was triggered for certain rate classes. The resulting amount of deferral that was not included in the 2015 rate increase is $1.9 million for electric revenue and $8.2 million for natural gas revenue that was accrued through December 31, 2014. These amounts may be included in customer rates beginning in May 2016, subject to subsequent application of the earnings test and the 3.0% cap on decoupling related rate increases.

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.

Electric Regulation and Rates

Storm Damage Deferral Accounting

The Washington Commission issued a GRC 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 2015 and 2014, PSE incurred $33.6 million and $29.7 million, respectively, in storm-related electric transmission and distribution system restoration costs, of which $22.4 million was deferred in 2015 and $18.0 million was deferred in 2014.

Power Cost Only Rate Case

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 power cost only rate case (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 GRC.

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



Effective Date	Average Percentage Increase (Decrease) in Rates		Increase (Decrease) in Revenue (Dollars in Millions)
December 1, 2014	(0.9	)%	$	(19.4	)
November 1, 2013	(0.5	)	(10.5		)

Electric Property Tax Tracker Mechanism

The purpose of the property tax tracker mechanism is to pass through the cost of all property taxes incurred by the Company. The mechanism was implemented in 2013 and removed property taxes from general rates and included those costs as a component rate. After the implementation, the mechanism acts as a tracker rate schedule and collects the total amount of property taxes assessed. The tracker will be adjusted each year in May based on that year's assessed property taxes and true-ups to the rate from the prior year.

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



Effective Date	Average Percentage Increase (Decrease) in Rates		Increase (Decrease) in Revenue (Dollars in Millions)
May 1, 2015	0.4	%	$	8.4
May 1, 2014	0.5		11.0

Electric Conservation Rider

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



Effective Date	Average Percentage Increase (Decrease) in Rates		Increase (Decrease) in Revenue (Dollars in Millions)
May 1, 2014	0.6	%	$	12.2

Accounting Orders and Petitions

PSE completed the sale of its electric infrastructure assets located in Jefferson County and the transition of electrical services in the county to Jefferson County Public Utility District (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 accordance with a 2010 Washington Commission order, PSE deferred the gain and recorded it 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 which authorized PSE to retain $7.5 million of the gain and return $52.7 million to customers. The customer portion was booked to a regulatory liability account in other current liabilities and accrued interest at PSE's after-tax rate of return. PSE paid this amount to customers through a bill credit in the month of December 2014.

Power Cost Adjustment Mechanism

PSE currently 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” included in revenue requirements. 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 currently applicable is as follows:



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

On August 7, 2015 the Washington Commission issued an order approving the settlement proposing changes to the PCA mechanism. The settlement agreement will not take effect until January 1, 2017. Key components of the settlement will result in the following changes to the PCA mechanism:



		Company's Share				Customers' Share
Annual Power Cost Variability		Over		Under		Over		Under
+/-	$17 million	100	%	100	%	—	%	—	%
+/-	$17 million - $40 million	35		50		65		50
+/-	$40+ million	10		10		90		90


•	Reduction to the cumulative deferral trigger for surcharge or refund from $30.0 million to $20.0 million;

•

Removal of fixed production costs from the PCA mechanism and placing them in the decoupling mechanism, assuming the decoupling mechanism continues as part of the next GRC. If decoupling was not to continue, those fixed production costs would be treated the same as other non-PCA costs unless permission to treat them in another manner is obtained from the Washington Commission. These fixed production costs include: (i) return and depreciation/amortization on fixed production assets and regulatory assets and liabilities; (ii) return on depreciation, transmission expense and revenues on specific transmission assets; and (iii) hydro, other production and other power related expenses and O&M costs;


•	Suspension of the requirement that a GRC must be filed within three months after rates are approved in a PCORC, and agreeing, for a five-year period, that PSE will not file a GRC or PCORC within six months of the date rates go into effect for a PCORC filing; and


•	Establishment of a five-year moratorium on changes to the PCA/PCORC.

Federal Incentive Tracker Tariff

The Federal Incentive tracker tariff passes the benefits associated with treasury grants received by the company and PTCs available through to its customers. The filing results in a credit back to customers for pass-back of treasury grant amortization and pass-through of interest and any related true-ups. The filing is adjusted annually for new Federal benefits, actual versus forecast interest and to true-up for actual load being different than the forecasted load set in rates.

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



Effective Date	Average Percentage Increase (Decrease) in Rates		Total credit to be passed back to eligible customers (Dollars in Millions)
January 1, 2016	(0.2	)%	$	(57.3	)
January 1, 2015	(0.2	)	(55.2		)
January 1, 2014	(0.3	)	(58.5		)
February 1, 2013	(2.8	)	(58.4		)

Gas Regulation and Rates

Gas General Rate Cases and Other Filings Affecting Rates

Cost Recovery Mechanism

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



Effective Date	Average Percentage Increase (Decrease) in Rates		Increase (Decrease) in Revenue (Dollars in Millions)
November 1, 2015	0.5	%	$	5.3
November 1, 2014	0.2		2.3

Property Tax Tracker Mechanism

The purpose of the property tax tracker mechanism is to pass through the cost of all property taxes incurred by the Company. The mechanism was implemented in 2013 and removed property taxes from general rates and included those costs as a component rate. After the implementation, the mechanism acts as a tracker rate schedule and collects the total amount of property taxes assessed. The tracker will be adjusted each year in May based on that year's assessed property taxes.

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



Effective Date	Average Percentage Increase (Decrease) in Rates		Increase (Decrease) in Revenue (Dollars in Millions)
June 1, 2015	(0.2	)%	$	(2.3	)
May 1, 2014	0.6		5.6

Purchased Gas Adjustment

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 or payable balance in the PGA mechanism reflects an under recovery or over recovery, respectively, of natural gas cost through the PGA mechanism.

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



Effective Date	Average Percentage Increase (Decrease) in Rates		Increase (Decrease) in Revenue (Dollars in Millions)
November 1, 2015	(17.4	)%	$	(185.9	)
November 1, 2014	2.5		23.3
November 1, 2013	0.4		4.0

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 $32.6 million for gas and $6.1 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, and as of December 31, 2015, the Company’s share of future remediation costs is estimated to be approximately $23.9 million. The Company's deferred electric environmental costs are $14.0 million, $13.4 million, and $12.3 million at December 31, 2015, 2014 and 2013, respectively, net of insurance proceeds. The Company's deferred natural gas environmental costs are $52.9 million, $52.6 million, and $45.1 million at December 31, 2015, 2014 and 2013, respectively, net of insurance proceeds.

(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, 2015, approximately $464.1 million of unrestricted retained earnings was available for the payment of dividends under the most restrictive mortgage indenture covenant.

Pursuant to the terms of the Washington Commission merger order, PSE may not declare or pay dividends if PSE’s common equity ratio, calculated on a regulatory basis, is 44.0% or below except to the extent a lower equity ratio is ordered by the Washington Commission. Also, pursuant to the merger order, PSE may not declare or make any distribution unless on the date of distribution PSE’s corporate credit/issuer rating is investment grade, or, if its credit ratings are below investment grade, PSE’s ratio of earnings before interest, tax, depreciation and amortization (EBITDA) to interest expense for the most recently ended four fiscal quarter periods prior to such date is equal to or greater than 3 to one. The common equity ratio, calculated on a regulatory basis, was 47.7% at December 31, 2015, and the EBITDA to interest expense was 4.9 to one for the twelve months then ended December 31, 2015.

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 3.4 to one for the twelve months ended December 31, 2015.

At December 31, 2015, 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)	2015			2014			2015			2014
Electric, natural gas and common utility plant classified by prescribed accounts :
Distribution plant	10-50	$	5,007,077		$	4,748,988		$	6,657,597		$	6,417,551
Production plant	25-125	3,028,481			2,973,853			3,950,231			3,907,224
Transmission plant	45-65	1,236,823			1,189,296			1,351,216			1,306,009
General plant	5-35	491,845			481,116			563,850			553,130
Intangible plant (including capitalized software)	3-50	305,705			311,959			294,380			304,135
Plant acquisition adjustment	7-30	242,826			242,826			282,792			282,792
Underground storage	25-60	28,914			28,859			42,545			42,494
Liquefied natural gas storage	25-45	12,628			12,628			14,498			14,498
Plant held for future use	NA	55,890			54,996			56,042			55,148
Recoverable Cushion Gas	NA	8,655			8,655			8,655			8,655
Plant not classified	1-100	65,892			91,519			65,892			91,519
Grant	NA	(102,379		)	(105,659		)	(102,379		)	(105,659		)
Capital leases, net of accumulated amortization ¹	5	378			9,473			378			9,473
Less: accumulated provision for depreciation		(1,878,868		)	(1,611,220		)	(4,681,830		)	(4,449,680		)
Subtotal		$	8,503,867		$	8,437,289		$	8,503,867		$	8,437,289
Construction work in progress	NA	408,795			239,690			408,795			239,690
Net utility plant		$	8,912,662		$	8,676,979		$	8,912,662		$	8,676,979

_______________


¹	Accumulated amortization of capital leases at Puget Energy and PSE was $32.3 million in 2015 and $28.4 million in 2014.

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, 2015. 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%	$	193,618	$	(16,749	)	$	327,843	$	(150,974	)
Colstrip Units 3 & 4	Coal	25%	254,457		(34,022		)	525,072		(304,636		)
Colstrip Units 1 – 4 Common Facilities	Coal	various	83		(24		)	252		(192		)
Frederickson 1	Gas	49.85%	61,776		(7,766		)	70,725		(16,715		)
Jackson Prairie	Gas Storage	33.34%	28,274		(4,877		)	42,579		(19,182		)

Asset Retirement Obligation

The Company has recorded liabilities for steam generation sites, combustion turbine generation sites, combined cycle generation sites, wind generation sites, distribution and transmission poles, gas mains, and leased facilities where disposal is governed by ASC 410 “ARO”.

On April 17, 2015, the U.S. EPA published a final rule, effective October 19, 2015, that regulates Coal Combustion Residuals (CCR) under the Resource Conservation and Recovery Act, Subtitle D. The CCR rule addresses the risks from coal ash disposal, such as leaking of contaminants into ground water, blowing of contaminants into the air as dust, and the catastrophic failure of coal ash surface impoundments by establishing technical requirements for CCR landfills and surface impoundments. The rule also sets out recordkeeping and reporting requirements including requirements to post specific information to a publicly-accessible website.

The CCR rule requires significant changes to the Company’s Colstrip, Montana coal-fired steam electric generation facility(Colstrip) operations and those changes were reviewed by the Company and the plant operator in the second and third quarter of 2015. PSE had previously recognized a legal obligation under the EPA rules to dispose of coal ash material at Colstrip, in 2003. Due to the CCR rule, additional disposal costs were added to the ARO.

The actual ARO costs related to the CCR rule requirements may vary substantially from the estimates used to record the increased obligation due to uncertainty about the compliance strategies that will be used and the preliminary nature of available data used to estimate costs. We will continue to gather additional data and coordinate with the plant operator to make decisions about compliance strategies and the timing of closure activities. As additional information becomes available, the Company will update the ARO obligation for these changes, which could be material.

The following table describes the changes to the Company’s ARO liability as of December 31, 2015 and 2014:



	At December 31,
(Dollars in Thousands)	2015			2014
Asset retirement obligation at beginning of period	$	48,909		$	48,687
New asset retirement obligation recognized in the period	34,534			—
Liability adjustment in the period	(3,628		)	(602		)
Revisions in estimated cash flows	3,403			(480		)
Accretion expense	1,810			1,304
Asset retirement obligation at end of period	$	85,028		$	48,909

The Company has identified the following obligations, as defined by ASC 410, “ARO,” which were not recognized because the liability for these assets cannot be reasonably estimated at December 31, 2015 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.

(6) Long-Term Debt



(Dollars in Thousands)			At December 31,
Series	Type	Due	2015			2014
Puget Sound Energy:
7.350%	First Mortgage Bond	2015	$	—		$	10,000
7.360%	First Mortgage Bond	2015	—			2,000
5.197%	Senior Secured Note	2015	—			150,000
6.750%	Senior Secured Note	2016	—			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
4.300%	Senior Secured Note	2045	425,000			—
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		(1,888		)	(13		)
Total PSE long-term debt			$	3,774,384		$	3,763,259
Puget Energy:
	Fair value adjustment of PSE long-term debt		$	(207,977	)	$	(218,619	)
	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
3.650%	Senior Secured Note	2025	400,000			—
	Unamortized discount on senior notes		(524		)	(32		)
Total Puget Energy long-term debt			$	5,365,883		$	5,243,608

____________


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, 2015, the latest maturity date of the first mortgage bonds, other than pledged first mortgage bonds, is December 22, 2025.

Puget Sound Energy Long-Term Debt

PSE has in effect a shelf registration statement under which it may issue, from time to time, senior notes secured by first mortgage bonds. As of December 31, 2015, PSE may issue up to $375.0 million of senior notes under the shelf registration statement which are secured by first mortgage bonds. PSE 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, 2015, the earnings available for interest exceeded the required amount.

On May 26, 2015, PSE issued $425.0 million of senior notes secured by first mortgage bonds. The notes mature in May 2045 and have an interest rate of 4.30%, which is payable semi-annually in May and November. Net proceeds of the issuance were used to fund the early retirement, including accrued interest and make-whole call premiums, of the Company's $150.0 million 5.197% senior notes maturing in October 2015 and the Company's $250.0 million 6.75% senior notes maturing in January 2016.

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

In June 2014, Puget Energy entered into three bilateral term loans, with two and three year maturities, which in total, equaled $299.0 million. The proceeds of the term loans were used to pay off the outstanding Puget Energy revolving credit facility balance, which subsequently allowed the Company to carry the debt with lower interest expense.

On May 12, 2015, Puget Energy issued $400.0 million of senior secured notes in a private placement. The notes mature in May 2025 and have an interest rate of 3.65%, which is payable semi-annually in May and November. Net proceeds of the issuance were used to repay all amounts outstanding under Puget Energy's three term loans, and to fund a special dividend to shareholders of approximately $96.7 million. On November 6, 2015, Puget Energy exchanged $400.0 million of its 3.65% senior secured notes that were originally issued in the May 2015 private placement for registered notes of the same amount.

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)	2016		2017		2018		2019		2020		Thereafter		Total
Maturities of:
PSE long-term debt	$	—	$	2,412	$	200,000	$	—	$	—	$	3,573,860	$	3,776,272
Puget Energy long-term debt	—		—		—		—		450,000		1,350,000		1,800,000
Puget Energy long-term debt	$	—	$	2,412	$	200,000	$	—	$	450,000	$	4,923,860	$	5,576,272

(7) Liquidity Facilities and Other Financing Arrangements

As of December 31, 2015 and 2014, PSE had $159.0 million and $85.0 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 2015 and 2014 was 4.24% and 4.05%, respectively. As of December 31, 2015, 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, 2015, 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, 2015, no amounts were drawn under either PSE's $650.0 million facility or PSE's $350.0 million energy hedging facility. No letters of credit were outstanding under either facility, and $159.0 million was outstanding under the commercial paper program. Outside of the credit agreements, PSE had a $3.9 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

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%. On June 30, 2015, PSE repaid in full the $28.9 million outstanding balance under the Note.

Puget Energy

Credit Facility

At December 31, 2015, 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, 2015, 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 Note 9 for more details).

(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,
Years	Operating Lease Expense
2015	$	27,843
2014	30,737
2013	29,392

Payments received for the subleases of properties were immaterial for each of the years ended 2015, 2014 and 2013.

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



(Dollars in Thousands)
At December 31,	Future Minimum Lease Payments
Years	Operating		Capital
2016	$	22,254	$	391
2017	22,849		—
2018	20,468		—
2019	17,403		—
2020	15,425		—
Thereafter	108,085		—
Total minimum lease payments	$	206,484	$	391

(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, 2015, Puget Energy had two interest rate swap contracts outstanding which extend to January 2017. Currently, these swap instruments do not hedge any variable interest rate debt. Management continues

to monitor the economics of terminating the swaps, and unless the economics of terminating the swaps become more favorable, management intends to let them expire naturally in 2017. PSE did not have any outstanding interest rate swap instruments.

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)		Assets¹				Liabilities ²
	2015	2014	2015		2014		2015		2014
Interest rate swap derivatives ³	$450.0	$450.0	$	—	$	—	$	5,050	$	9,073
Electric portfolio derivatives	*	*	23,443		4,822		112,106		107,228
Natural gas derivatives (MMBtus) ⁴	369.5	360.4	6,200		19,526		67,090		88,807
Total derivative contracts			$	29,643	$	24,348	$	184,246	$	205,108
Current			$	24,418	$	21,178	$	136,173	$	142,195
Long-term			5,225		3,170		48,073		62,913
Total derivative contracts			$	29,643	$	24,348	$	184,246	$	205,108

___________


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	All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations,” due to the PGA mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers.


^*	Net purchase and sale volumes for electric portfolio derivatives consist of electric generation fuel of 202.1 million One Million British Thermal Units (MMBtus) and purchased electricity of 0.1 million Megawatt Hours (MWhs) at December 31, 2015 and 140.2 million MMBtus and 5.4 million MWhs at December 31, 2014.

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; 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. 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.

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, 2015
(Dollars in Thousands)	Gross Amounts Recognized in the Statement of Financial Position¹		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	$	29,643	$	—	$	29,643	$	(23,998	)	$	—		$	5,645
Liabilities
Energy derivative contracts	179,196		—		179,196		(23,998		)	—			155,198
Interest rate swaps ²	5,050		—		5,050		—			—			5,050

Puget Energy and Puget Sound Energy
At December 31, 2014
(Dollars in Thousands)	Gross Amounts Recognized in the Statement of Financial Position¹		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

___________


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


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

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	2015			2014			2013
Interest rate contracts:	Other deductions	$	(3,796	)	$	(3,915	)	$	2,420
	Interest expense	560			500			(5,904		)
Commodity contracts:
Electric derivatives	Unrealized gain (loss) on derivative instruments, net ¹	13,233			(84,146		)	102,744
	Electric generation fuel	(44,648		)	6,511			(27,008		)
	Purchased electricity	(39,137		)	(4,212		)	(38,299		)
Total gain (loss) recognized in income on derivatives		$	(73,788	)	$	(85,262	)	$	33,953

100



Puget Sound Energy		Year Ended December 31,
(Dollars in Thousands)	Location	2015			2014			2013
Commodity contracts:
Electric derivatives	Unrealized gain (loss) on derivative instruments, net ¹	$	12,688		$	(85,636	)	$	98,880
	Electric generation fuel	(44,648		)	6,511			(27,008		)
	Purchased electricity	(39,137		)	(4,212		)	(38,299		)
Total gain (loss) recognized in income on derivatives		$	(71,097	)	$	(83,337	)	$	33,573

_______________


¹	Differences between Puget Energy and PSE are due to certain derivative contracts recorded at fair value in 2009 and subsequently designated as NPNS or cash flow hedges. These differences occurred through February 2015.

The unrealized gain or loss on derivative contracts is reported in the statement of cash flows under the operating activities section. However, due to purchase accounting requirements, 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, 2015, 2014 and 2013, cash outflows related to financing activities of $8.0 million, $16.3 million and $34.3 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 reclassified into earnings in the same period(s) during which the hedged transaction affects earnings. The Company does not attempt cash flow hedging for any new transactions and records all mark-to-market adjustments through earnings.

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	2015			2014			2013
Interest rate contracts:	Interest expense	$	—		$	(144	)	$	(4,505	)
Commodity contracts:
Electric derivatives	Purchased electricity	(512		)	(572		)	(57		)
Total		$	(512	)	$	(716	)	$	(4,562	)



Puget Sound Energy		Year Ended December 31,
(Dollars in Thousands)	Location	2015			2014			2013
Interest rate contracts:	Interest expense ¹	$	(488	)	$	(488	)	$	(488	)
Commodity contracts:
Electric derivatives	Purchased electricity	(1,055		)	(2,063		)	(3,922		)
Total		$	(1,543	)	$	(2,551	)	$	(4,410	)

_______________


¹	Within the next twelve months, $0.5 million of losses in AOCI will be reclassified into earnings.

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.

101

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, 2015, approximately 99.2% 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 0.8% are either rated below investment grade or not rated by rating agencies. The Company assesses credit risk internally for counterparties that are not rated.

The Company computes credit reserves at a master agreement level by counterparty. 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, 2015, 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, 2015, 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.

The table below presents the fair value of the overall contractual contingent liability positions for the Company's derivative activity at December 31, 2015:



Puget Energy and Puget Sound Energy Contingent Feature (Dollars in Thousands)	Fair Value ¹ Liability		Posted Collateral		Contingent Collateral
Credit rating ²	$	24,187	$	—	$	24,187
Requested credit for adequate assurance	67,003		—		—
Total	$	91,190	$	—	$	24,187

__________


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.

(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.

102

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.

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
Puget Energy	At December 31, 2015						At December 31, 2014
(Dollars in Thousands)	Level 1		Level 2		Total		Level 1		Level 2		Total
Assets:
Cash and Cash Equivalents	$	42,494	$	—	$	42,494	$	37,527	$	—	$	37,527
Restricted Cash	7,949		—		7,949		32,863		—		32,863
Notes Receivable and Other	—		52,820		52,820		—		53,503		53,503
Total assets	$	50,443	$	52,820	$	103,263	$	70,390	$	53,503	$	123,893
Liabilities:
Short-term debt	$	159,004	$	—	$	159,004	$	85,000	$	—	$	85,000
Total liabilities	$	159,004	$	—	$	159,004	$	85,000	$	—	$	85,000

103



Puget Sound Energy	Carrying / Fair Value						Carrying / Fair Value
Puget Sound Energy	At December 31, 2015						At December 31, 2014
(Dollars in Thousands)	Level 1		Level 2		Total		Level 1		Level 2		Total
Assets:
Cash and Cash Equivalents	$	41,856	$	—	$	41,856	$	37,466	$	—	$	37,466
Restricted Cash	7,949		—		7,949		32,863		—		32,863
Notes Receivable and Other	—		52,820		52,820		—		53,503		53,503
Total assets	$	49,805	$	52,820	$	102,625	$	70,329	$	53,503	$	123,832
Liabilities:
Short-term debt	$	159,004	$	—	$	159,004	$	85,000	$	—	$	85,000
Short-term debt owed to parent	—		—		—		—		28,933		28,933
Total liabilities	$	159,004	$	—	$	159,004	$	85,000	$	28,933	$	113,933

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, 2015				December 31, 2014
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Junior subordinated notes	2	$	250,000	$	211,173	$	250,000	$	276,235
Long-term debt (fixed-rate), net of discount	2	5,115,883		6,308,831		4,694,608		6,083,554
Long-term debt (variable-rate)	2	—		—		299,000		299,000
Total		$	5,365,883	$	6,520,004	$	5,243,608	$	6,658,789

Puget Sound Energy		December 31, 2015				December 31, 2014
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Junior subordinated notes	2	$	250,000	$	211,173	$	250,000	$	276,235
Long-term debt (fixed-rate), net of discount	2	3,524,384		4,329,444		3,513,259		4,437,473
Total		$	3,774,384	$	4,540,617	$	3,763,259	$	4,713,708

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
Puget Energy	At December 31, 2015						At December 31, 2014
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total
Interest rate derivative instruments	$	5,050	$	—	$	5,050	$	9,073	$	—	$	9,073
Total derivative liabilities	$	5,050	$	—	$	5,050	$	9,073	$	—	$	9,073

104



Puget Energy and Puget Sound Energy	Fair Value						Fair Value
Puget Energy and Puget Sound Energy	At December 31, 2015						At December 31, 2014
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	10,709	$	12,734	$	23,443	$	1,654	$	3,168	$	4,822
Natural gas derivative instruments	4,538		1,662		6,200		18,064		1,462		19,526
Total assets	$	15,247	$	14,396	$	29,643	$	19,718	$	4,630	$	24,348
Liabilities:
Electric derivative instruments	$	92,027	$	20,079	$	112,106	$	91,998	$	15,230	$	107,228
Natural gas derivative instruments	63,045		4,045		67,090		85,305		3,502		88,807
Total liabilities	$	155,072	$	24,124	$	179,196	$	177,303	$	18,732	$	196,035



Puget Energy and Puget Sound Energy	Year Ended December 31,
Level 3 Roll-Forward Net (Liability)	2015									2014									2013
(Dollars in Thousands)	Electric			Gas			Total			Electric			Gas			Total			Electric			Gas			Total
Balance at beginning of period	$	(12,062	)	$	(2,040	)	$	(14,102	)	$	(15,421	)	$	(361	)	$	(15,782	)	$	(33,924	)	$	(1,602	)	$	(35,526	)
Changes during period
Realized and unrealized energy derivatives:
Included in earnings ¹	(6,432		)	—			(6,432		)	(5,537		)	—			(5,537		)	(10,491		)	—			(10,491		)
Included in regulatory assets / liabilities	—			3,695			3,695			—			1,630			1,630			—			(945		)	(945		)
Settlements²	902			(3,885		)	(2,983		)	1,036			(1,534		)	(498		)	11,609			(754		)	10,855
Transferred into Level 3	(787		)	—			(787		)	5,155			(585		)	4,570			(7,799		)	—			(7,799		)
Transferred out of Level 3	11,034			(153		)	10,881			2,705			(1,190		)	1,515			25,184			2,940			28,124
Balance at end of period	$	(7,345	)	$	(2,383	)	$	(9,728	)	$	(12,062	)	$	(2,040	)	$	(14,102	)	$	(15,421	)	$	(361	)	$	(15,782	)

_______________


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 $(7.4) million, $(9.6) million, and $(13.4) million for the years ended December 31, 2015, 2014 and 2013, 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.

105

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, 2015 and 2014. 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, 2015:



	Fair Value				Range
(Dollars in Thousands)			Valuation Technique	Unobservable Input	Low	High	Weighted Average
Electric	$12,734	$20,079	Discounted cash flow	Power Prices	$10.69 per MWh	$29.18 per MWh	$23.39 per MWh
Natural gas	$1,662	$4,045	Discounted cash flow	Natural Gas Prices	$1.12 per MMBtu	$2.95 per MMBtu	$2.25 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 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, 2015, 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 $1.3 million.

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

Puget Energy records 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.

During 2015 and 2014, Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets. In 2015 and 2014, due to continued significant decreases in forward power prices, the following impairments were recorded to one of the Company's intangible asset contracts, with corresponding reductions to the regulatory liability as follows:



Intangible Asset Contract
(Dollars in Thousands)
Valuation Date	Contract Name	Carrying Value		Fair Value		Write Down
December 31, 2015	Wells Hydro	$	32,988	$	27,628	$	5,360
September 30, 2015	Wells Hydro	42,422		35,714		6,708
March 31, 2015	Wells Hydro	59,273		49,317		9,956
December 31, 2014	Wells Hydro	65,299		62,132		3,167

106

The valuations were measured using a discounted cash flow, income-based valuation methodology. 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.

Below are significant unobservable inputs used in estimating the impaired long term power purchase contracts' fair value in 2015 and 2014:



Valuation Date	Unobservable Input	Low	High	Average
December 31, 2015
	Power prices	$15.16 per MWh	$27.25 per MWh	$23.23 per MWh
	Power contract costs (in thousands)	$4,100 per qtr	$4,659 per qtr	$4,417 per qtr
September 30, 2015
	Power prices	$18.38 per MWh	$27.92 per MWh	$24.88 per MWh
	Power contract costs (in thousands)	$4,100 per qtr	$4,659 per qtr	$4,388 per qtr
March 31, 2015
	Power prices	$19.54 per MWh	$32.17 per MWh	$27.23 per MWh
	Power contract costs (in thousands)	$4,129 per qtr	$4,783 per qtr	$4,493 per qtr
December 31, 2014
	Power prices	$19.30 per MWh	$37.06 per MWh	$29.53 per MWh
	Power contract costs (in thousands)	$3,015 per qtr	$4,783 per qtr	$4,469 per qtr

(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 $16.1 million, $14.9 million and $14.6 million for the years 2015, 2014, and 2013, 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.


•	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 401(k) 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, choosing from one of the 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 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.

107

(12) Retirement Benefits

PSE has a defined benefit pension plan (Qualified Pension Benefits) covering the largest portion of 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. Starting with January 1, 2014, all newly hired non-represented employees, United Association of Journeymen and Apprentices of the Plumbing and Pipe Fitting Industry employees, and International Brotherhood of Electrical Workers Local Union 77 hired on or after December 12, 2014 who elect to accumulate the Company contribution in the cash balance formula portion of the pension plan, will receive annual pay credits of 4% each year. They will also receive interest credits like other participants in the cash balance pension formula of the pension plan, which are at least 1% per quarter. When an employee with a vested cash balance formula benefit leaves PSE, he or she will have annuity and lump sum options for distribution. Those who select the lump sum option will receive their current cash balance amount. 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 legacy group health care and life insurance benefits (Other 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 prior year.

Puget Energy records purchase accounting adjustments associated with the re-measurement of the retirement plans.

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, 2015 and 2014:



Puget Energy and Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2015			2014			2015			2014			2015			2014
Change in benefit obligation:
Benefit obligation at beginning of period	$	690,194		$	573,317		$	55,855		$	47,279		$	15,688		$	14,939
Service cost	21,287			17,437			1,108			1,042			112			112
Interest cost	28,088			28,039			2,281			2,310			621			684
Actuarial loss (gain)	(55,665		)	104,618			(4,430		)	7,162			(1,416		)	1,108
Benefits paid	(39,963		)	(33,217		)	(3,535		)	(1,938		)	(1,354		)	(1,424		)
Medicare part D subsidy received	—			—			—			—			295			269
Administrative expense	(853		)	—			—			—			—			—
Benefit obligation at end of period	$	643,088		$	690,194		$	51,279		$	55,855		$	13,946		$	15,688



Puget Energy and Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2015			2014			2015			2014			2015			2014
Change in plan assets:
Fair value of plan assets at beginning of period	$	626,173		$	615,721		$	—		$	—		$	8,360		$	8,774
Actual return on plan assets	(4,489		)	25,669			—			—			(378		)	522
Employer contribution	18,000			18,000			3,535			1,938			575			488
Benefits paid	(39,963		)	(33,217		)	(3,535		)	(1,938		)	(1,354		)	(1,424		)
Administrative expense	(856		)	—			—			—			—			—
Fair value of plan assets at end of period	$	598,865		$	626,173		$	—		$	—		$	7,203		$	8,360
Funded status at end of period	$	(44,223	)	$	(64,021	)	$	(51,279	)	$	(55,855	)	$	(6,743	)	$	(7,328	)

108



Puget Energy and Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2015			2014			2015			2014			2015			2014
Amounts recognized in Statement of Financial Position consist of:
Noncurrent assets	$	—		$	—		$	—		$	—		$	—		$	—
Current liabilities	—			—			(2,545		)	(4,386		)	(353		)	(355		)
Noncurrent liabilities	(44,223		)	(64,021		)	(48,734		)	(51,469		)	(6,390		)	(6,973		)
Net assets (liabilities)	$	(44,223	)	$	(64,021	)	$	(51,279	)	$	(55,855	)	$	(6,743	)	$	(7,328	)



Puget Energy and Puget Sound Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
(Dollars in Thousands)	2015		2014		2015		2014		2015		2014
Pension Plans with an Accumulated Benefit Obligation in excess of Plan Assets:
Projected benefit obligation	$	643,088	$	690,194	$	51,279	$	55,855	$	13,946	$	15,688
Accumulated benefit obligation	635,599		681,745		46,978		50,137		13,828		15,553
Fair value of plan assets	598,865		626,173		—		—		7,203		8,360

The following tables summarize Puget Energy's and PSE's pension benefit amounts recognized in AOCI for the years ended December 31, 2015 and 2014:



Puget Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
(Dollars in Thousands)	2015			2014			2015		2014		2015			2014
Amounts recognized in Accumulated Other Comprehensive Income consist of:
Net loss (gain)	$	45,447		$	55,471		$	9,848	$	15,918	$	(1,834	)	$	(1,457	)
Prior service cost (credit)	(11,802		)	(13,782		)	288		331		—			—
Total	$	33,645		$	41,689		$	10,136	$	16,249	$	(1,834	)	$	(1,457	)



Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
(Dollars in Thousands)	2015			2014			2015		2014		2015		2014
Amounts recognized in Accumulated Other Comprehensive Income consist of:
Net loss (gain)	$	221,064		$	247,331		$	13,202	$	19,751	$	3,834	$	(3,733	)
Prior service cost (credit)	(9,379		)	(10,952		)	295		339		—		3
Total	$	211,685		$	236,379		$	13,497	$	20,090	$	3,834	$	(3,730	)

109

The following tables summarize Puget Energy's and PSE's net periodic benefit cost for the years ended December 31, 2015, 2014 and 2013:



Puget Energy	Qualified Pension Benefits									SERP Pension Benefits							Other Benefits
(Dollars in Thousands)	2015			2014			2013			2015		2014		2013			2015			2014			2013
Components of net periodic benefit cost:
Service cost	$	21,287		$	17,437		$	19,285		$	1,108	$	1,042	$	1,498		$	112		$	112		$	134
Interest cost	28,088			28,039			24,754			2,281		2,310		2,045			621			684			664
Expected return on plan assets	(45,038		)	(42,464		)	(39,095		)	—		—		—			(531		)	(535		)	(436		)
Amortization of prior service cost (credit)	(1,980		)	(1,980		)	(1,980		)	42		42		(17		)	—			—			—
Amortization of net loss (gain)	3,887			—			2,889			1,641		913		1,461			(130		)	(393		)	69
Net periodic benefit cost	$	6,244		$	1,032		$	5,853		$	5,072	$	4,307	$	4,987		$	72		$	(132	)	$	431



Puget Sound Energy	Qualified Pension Benefits									SERP Pension Benefits							Other Benefits
(Dollars in Thousands)	2015			2014			2013			2015		2014		2013			2015			2014			2013
Components of net periodic benefit cost:
Service cost	$	21,287		$	17,437		$	19,285		$	1,108	$	1,042	$	1,498		$	112		$	112		$	134
Interest cost	28,088			28,039			24,753			2,281		2,310		2,045			621			684			664
Expected return on plan assets	(45,462		)	(43,252		)	(40,685		)	—		—		—			(531		)	(535		)	(436		)
Amortization of prior service cost (credit)	(1,573		)	(1,573		)	(1,573		)	44		44		(16		)	3			3			30
Amortization of net loss(gain)	20,555			13,195			20,612			2,120		1,461		2,191			(406		)	(702		)	(284		)
Net periodic benefit cost	$	22,895		$	13,846		$	22,392		$	5,553	$	4,857	$	5,718		$	(201	)	$	(438	)	$	108

The following tables summarize Puget Energy's and PSE's benefit obligations recognized in OCI for the years ended December 31, 2015 and 2014:



Puget Energy	Qualified Pension Benefits					SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2015			2014		2015			2014			2015			2014
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)	$	(6,136	)	$	121,413	$	(4,430	)	$	7,162		$	(508	)	$	1,121
Amortization of net loss (gain)	(3,887		)	—		(1,641		)	(913		)	131			394
Amortization of prior service credit	1,980			1,980		(42		)	(42		)	—			—
Total change in other comprehensive income for year	$	(8,043	)	$	123,393	$	(6,113	)	$	6,207		$	(377	)	$	1,515

110



Puget Sound Energy	Qualified Pension Benefit						SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2015			2014			2015			2014			2015			2014
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)	$	(5,711	)	$	122,202		$	(4,430	)	$	7,162		$	(508	)	$	1,121
Amortization of net (loss) gain	(20,556		)	(13,195		)	(2,120		)	(1,461		)	407			702
Amortization of prior service cost (credit)	1,573			1,573			(44		)	(44		)	(3		)	(3		)
Total change in other comprehensive income for year	$	(24,694	)	$	110,580		$	(6,594	)	$	5,657		$	(104	)	$	1,820

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 2016 by PSE are $15.0 million and $1.6 million, respectively. The estimated net (loss) gain for the SERP that will be amortized from accumulated OCI into net periodic benefit cost in 2016 is $1.3 million. The estimated prior service cost (credit) for the SERP that will be amortized from accumulated OCI into net periodic benefit cost in 2016 is immaterial. The estimated net (loss) gain and prior service cost (credit) for the other postretirement plans that will be amortized from accumulated OCI into net periodic benefit cost in 2016 is immaterial. For Puget Energy, the overall amounts expected to be amortized from accumulated OCI into net period benefit cost in 2016 were 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, 2016 are expected to be at least $18.0 million, $2.5 million and $0.5 million, respectively.

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	2015		2014		2013		2015		2014		2013		2015		2014		2013
Discount rate	4.65	%	4.25	%	5.10	%	4.65	%	4.25	%	5.10	%	4.65	%	4.25	%	5.10	%
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	—		—		—		—		—		—		7.20		5.70		6.80
Benefit Cost Assumptions
Discount rate	4.25	%	5.10	%	4.15	%	4.25	%	5.10	%	4.15	%	4.25	%	5.10	%	4.15	%
Return on plan assets	7.75		7.75		7.75		—		—		—		7.00		7.00		6.90
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	—		—		—		—		—		—		7.20		6.70		8.20

The assumed medical inflation rate used to determine benefit obligations is 7.20% in 2016 grading down to 4.30% in 2017. A 1.0% change in the assumed medical inflation rate would have the following effects:



	2015					2014
(Dollars in Thousands)	1% Increase		1% Decrease			1% Increase		1% Decrease
Effect on post-retirement benefit obligation	$	52	$	(42	)	$	47	$	(47	)
Effect on service and interest cost components	2		(2		)	2		(2		)

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

111

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, and 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.

Plan Benefits

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



(Dollars in Thousands)	2016		2017		2018		2019		2020		2021-2025
Qualified Pension total benefits	$	41,300	$	42,400	$	43,100	$	43,300	$	45,000	$	235,600
SERP Pension total benefits	2,545		1,922		5,210		5,564		4,455		19,875
Other Benefits total with Medicare Part D subsidy	1,031		1,091		1,064		1,038		1,003		5,568
Other Benefits total without Medicare Part D subsidy	1,369		1,358		1,339		1,319		1,292		5,934

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

112

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.

The following table sets forth by level, within the fair value hierarchy, the qualified pension plan as of December 31, 2015 and 2014:



	Recurring Fair Value Measures									Recurring Fair Value Measures
	As of December 31, 2015									As of December 31, 2014
(Dollars in Thousands)	Level 1		Level 2		Level 3		Total			Level 1		Level 2		Level 3		Total
Assets:
Equities:
Non-US equity ¹	$	69,127	$	76,071	$	—	$	145,198		$	71,026	$	74,131	$	—	$	145,157
Domestic large cap equity ²	119,512		65,287		—		184,799			134,765		68,336		—		203,101
Domestic small cap equity ³	53,985		—		—		53,985			59,657		—		—		59,657
Total equities	242,624		141,358		—		383,982			265,448		142,467		—		407,915
Fixed income securities ⁴	81,696		58,425		—		140,121			72,331		67,182		—		139,513
Absolute return ⁵	—		—		64,925		64,925			—		—		65,251		65,251
Cash and cash equivalents ⁶	340		17,041		—		17,381			12,650		—		—		12,650
Subtotal	$	324,660	$	216,824	$	64,925	$	606,409		$	350,429	$	209,649	$	65,251	$	625,329
Net (payable) receivable	—		—		—		(7,544		)	—		—		—		844
Accrued income	—		—		—		—			—		—		—		—
Total assets							$	598,865								$	626,173

_________________


¹	Non – US Equity investments are comprised of a mutual fund (at level 1); and a commingled fund (at level 2). The investment in the mutual fund is valued at the daily closing price as reported by the funds. 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, 2015.

Domestic large cap equity investments are comprised of common stock (at level 1), and a commingled fund (at level 2). Investments in common stock traded on a national securities exchange are valued at the last reported sales price on the last business day of the year. Securities traded in the over-the-counter market and listed securities for which no sale was reported on that date are valued at the last reported sale or bid price, as available or at values based upon bid quotations for identical or similar instruments. 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, 2015.


³	Domestic small cap equity investments are comprised of common stock and a mutual fund, please see 1 and 2 above for a description.

⁴

Fixed income securities consist of mutual funds and US treasury bonds (at level 1), and government securities and corporate bonds (at level 2). Please see 1 above for a description of mutual funds. Government securities and corporate bonds are valued using pricing models maximizing the use of observable inputs for similar securities. When quoted prices are not available for identical or similar bonds, the bond is valued under a discounted cash flow approach maximizing observable inputs.

⁵

As of December 31, 2015 absolute return investments consist of two partnerships. The partnerships are valued based on the net asset value provided by the Plan's investment custodians, and reported in the funds' financial statements which are audited annually by independent accountants. These investments are at Level 3 under ASC 820 because the significant valuation inputs are primarily internal to the partnerships with little third party involvement.


⁶	The investment consists of a money market fund (at level 1) and a collective trust fund (at level 2). The money market fund is valued at the net asset value per share of $1.00 per unit as of December 31, 2015. The collective trust fund invests primarily in commercial paper, notes, repurchase agreements, and other evidences of indebtedness which are payable on demand or short-term in nature.

113

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, 2015						As of December 31, 2014
(Dollars in Thousands)	Partnership			Total			Partnership		Total
Balance at beginning of year	$	65,251		$	65,251		$	62,278	$	62,278
Additional investments	—			—			—		—
Distributions	—			—			—		—
Realized losses on distributions	—			—			—		—
Unrealized gain (loss) instruments still held at the reporting date	(326		)	(326		)	2,973		2,973
Transferred in/out of level 3¹	—			—			—		—
Balance at end of year	$	64,925		$	64,925		$	65,251	$	65,251

_________________


¹	The plan had no transfers between level 2 and level 1 during the years ended December 31, 2015 or 2014.

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, 2015						As of December 31, 2014
(Dollars in Thousands)	Level 1		Level 2		Total		Level 1		Level 2		Total
Assets:
Mutual fund ¹	$	7,135	$	—	$	7,135	$	8,301	$	—	$	8,301
Cash equivalents ²	—		68		68		59		—		59
Total assets	$	7,135	$	68	$	7,203	$	8,360	$	—	$	8,360

_______________


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, 2015.


²	The investment consists of a money market fund (at level 1) and a collective trust fund (at level 2). The money market fund is valued at the net asset value per share of $1.00 per unit as of December 31, 2015. The collective trust 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)	2015			2014			2013
Charged to operating expenses:
Deferred:
Federal	$	91,968		$	57,152		$	122,559
State	(192		)	(167		)	(151		)
Total income tax expense	$	91,776		$	56,985		$	122,408

114



Puget Sound Energy	Year Ended December 31,
(Dollars in Thousands)	2015		2014		2013
Charged to operating expenses:
Deferred:
Federal	$	125,900	$	89,342	$	160,886
State	—		—		—
Total income tax expense	$	125,900	$	89,342	$	160,886

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)	2015			2014			2013
Income taxes at the statutory rate	$	116,534		$	80,087		$	142,847
Increase (decrease):
Production tax credit	(19,470		)	(23,073		)	(22,414		)
AFUDC excluded from taxable income	(5,386		)	(3,790		)	(9,406		)
Capitalized interest	3,397			2,947			7,294
Utility plant differences	5,671			7,090			9,527
Treasury grant amortization	(8,807		)	(8,808		)	(7,651		)
Other - net	(163		)	2,532			2,211
Total income tax expense	$	91,776		$	56,985		$	122,408
Effective tax rate	27.6		%	24.9		%	30.0		%



Puget Sound Energy	Year Ended December 31,
(Dollars in Thousands)	2015			2014			2013
Income taxes at the statutory rate	$	150,531		$	114,084		$	180,955
Increase (decrease):
Production tax credit	(19,470		)	(23,073		)	(22,414		)
AFUDC excluded from taxable income	(5,386		)	(3,790		)	(9,406		)
Capitalized interest	3,397			2,947			7,294
Utility plant differences	5,671			7,090			9,527
Treasury grant amortization	(8,807		)	(8,808		)	(7,651		)
Other - net	(36		)	892			2,581
Total income tax expense	$	125,900		$	89,342		$	160,886
Effective tax rate	29.3		%	27.4		%	31.1		%

115

The Company’s net deferred tax liability at December 31, 2015 and 2014 is composed of amounts related to the following types of temporary differences:



Puget Energy	At December 31,
(Dollars in Thousands)	2015			2014
Utility plant and equipment	$	1,788,078		$	1,720,730
Regulatory asset for income taxes	73,231			95,432
Fair value of debt instruments	70,260			73,606
Other deferred tax liabilities	161,627			131,776
Subtotal deferred tax liabilities	2,093,196			2,021,544
Net operating loss carryforward	(384,338		)	(417,684		)
Production tax credit carryforward	(178,075		)	(158,604		)
Regulatory liability on production tax credit	(94,828		)	(84,344		)
Subtotal deferred tax assets	(657,241		)	(660,632		)
Total net deferred tax liabilities	$	1,435,955		$	1,360,912



Puget Sound Energy	At December 31,
(Dollars In Thousands)	2015			2014
Utility plant and equipment	$	1,788,078		$	1,720,730
Regulatory asset for income taxes	72,694			94,913
Other deferred tax liabilities	80,351			50,229
Subtotal deferred tax liabilities	1,941,123			1,865,872
Net operating loss carryforward	(111,604		)	(181,514		)
Production tax credit carryforward	(178,075		)	(158,604		)
Regulatory liability on production tax credit	(94,828		)	(84,344		)
Subtotal deferred tax assets	(384,507		)	(424,462		)
Total net deferred tax liabilities	$	1,556,616		$	1,441,410

The Company adopted ASU 2015-17 for year ended December 31, 2015 and the impact to Puget Energy and PSE was a reclass in 2014 from current to noncurrent of $161.4 million and $208.4 million, respectively. Except for changes in Consolidated Balance Sheet presentation, this guidance does not have a material impact on the Company's results of operations or financial position.

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 2027 through 2035. The Company’s net operating loss carryforwards expire from 2029 through 2033. No valuation allowance has been provided for PTC or net operating loss carryforwards.

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, 2015 and 2014, the Company had no material unrecognized tax benefits. As a result, no interest or penalties were accrued for unrecognized tax benefits during the year.

116

For ASC 740 purposes, the Company has open tax years from 2012 through 2015. The Company classifies interest as interest expense and penalties as other expense in the financial statements.

(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,

the Sierra Club and the Montana Environmental Information Center filed a Clean Air Act citizen suit against all Colstrip owners 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 during the time period from 2001 to 2012. Plaintiffs have since indicated that they do not intend to pursue claims with respect to three of the seven projects, leaving a total of four projects remaining subject to the lawsuit. The lawsuit claims that, for each of the four projects, the Colstrip plant 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. The liability trial is currently set for May 2016, 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.

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 $0.3 million and $1.7 million relating to these claims as of December 31, 2015 and 2014, respectively.

(15) Commitments and Contingencies

For the year ended December 31, 2015, approximately 13.9% of the Company’s energy output was obtained at an average cost of approximately $0.022 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 share of power 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)	2015		2014		2013
PUD contract costs	$	72,833	$	69,661	$	63,365

117

As of December 31, 2015, 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 2016 Costs		2016 Debt Service Costs		Interest included in 2016 Debt Service Costs		Debt Outstanding
Chelan County PUD:
Rock Island Project	2031	25.0	%	156	$	28,422	$	10,496	$	5,868	$	92,603
Rocky Reach Project	2031	25.0	%	325	31,243		7,870		3,117		49,081
Douglas County PUD:
Wells Project	2018	29.9	%	251	17,146		9,384		2,487		59,942
Grant County PUD:
Priest Rapids Development	2052	0.6	%	8	3,073		1,874		1,093		18,271
Wanapum Development	2052	0.6	%	9	3,073		1,874		1,093		18,271
Total				749	$	82,957	$	31,498	$	13,658	$	238,168

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)	2016		2017		2018		2019		2020		Thereafter		Total
Columbia River projects	$	77,331	$	77,474	$	67,371	$	55,866	$	53,531	$	566,081	$	897,654
Other utilities	16,421		10,357		1,257		890		—		—		28,925
Non-utility contracts	158,874		199,125		204,658		209,590		213,352		1,164,975		2,150,574
Total	$	252,626	$	286,956	$	273,286	$	266,346	$	266,883	$	1,731,056	$	3,077,153

Total purchased power contracts provided the Company with approximately 11.2 million, 12.1 million and 10.7 million MWhs of firm energy at a cost of approximately $373.8 million, $401.4 million and $348.7 million for the years 2015, 2014 and 2013, respectively.

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 $133.0 million, $37.3 million and $7.3 million in 2016, 2017 and 2018, respectively.

Natural Gas Supply Obligations

The Company has entered into various firm supply, transportation and storage service contracts in order to ensure adequate availability of natural gas supply for its customers and generation requirements. 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 transportation and storage contracts, which have remaining terms from less than one year to 29 years, provide that the Company must pay a fixed demand charge each month, regardless of actual usage. The Company incurred demand charges for 2015 for firm transportation, storage and peaking services for its natural gas customers of $120.3 million. The Company incurred demand charges in 2015 for firm transportation and storage services for the natural gas supply for its combustion turbines in the amount of $35.1 million.

118

The following table summarizes the Company’s obligations for future natural gas supply and 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.



Natural Gas Supply and Demand Charge Obligations (Dollars in Thousands)	2016		2017		2018		2019		2020		Thereafter		Total
Natural gas supply	$	247,017	$	204,798	$	451,815	$	233,865	$	151,664	$	—	$	1,289,159
Firm transportation service	153,590		147,998		143,076		138,360		132,391		612,778		1,328,193
Firm storage service	6,616		6,616		3,861		2,943		1,950		4,093		26,079
Total	$	407,223	$	359,412	$	598,752	$	375,168	$	286,005	$	616,871	$	2,643,431

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)	2016		2017		2018		2019		2020		Thereafter		Total
Energy production service contracts	$	50,557	$	42,576	$	23,038	$	22,160	$	39,948	$	173,898	$	352,177
Automated meter reading system	17,566		17,596		18,348		19,092		19,860		137,784		230,246
Total	$	68,123	$	60,172	$	41,386	$	41,252	$	59,808	$	311,682	$	582,423

Other Commitments and Contingencies

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

(16) Related Party Transactions

Scott Armstrong serves on the Board of Directors of the Company, and is the president and Chief Executive Officer of Group Health Cooperative (Group Health). Group Health provides coverage to over 600,000 residents in Washington and Northern Idaho. Certain employees of PSE elect Group Health as their medical provider and as a result, PSE paid Group Health a total of $20.3 million and $17.7 million for medical coverage for the year ended December 31, 2015 and 2014, respectively.

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 2015 and 2014, Riddell Williams was paid $1.81 million and $1.98 million, respectively, 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.

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, 2015 and 2014, Puget Energy and PSE paid a total of approximately $1.0 million in fees and interest each year to U.S. Bank N.A. and its subsidiaries or affiliates.

(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.

119

(18) Accumulated Other Comprehensive Income (Loss)

The following tables present the changes in the Company’s (loss) AOCI by component for the years ended December 31, 2015, 2014 and 2013, 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, 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	)
Other comprehensive income (loss) before reclassifications	7,196			—			—			7,196
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	2,248			333			—			2,581
Net current-period other comprehensive income (loss)	9,444			333			—			9,777
Balance at December 31, 2015	$	(27,266	)	$	—		$	—		$	(27,266	)

120



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, 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	)
Other comprehensive income (loss) before reclassifications	6,922			—			—			6,922
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	13,482			686			317			14,485
Net current-period other comprehensive income (loss)	20,404			686			317			21,407
Balance at December 31, 2015	$	(143,877	)	$	—		$	(5,673	)	$	(149,550	)

121

Details about the reclassifications out of AOCI (loss) for the years ended December 31, 2015, 2014 and 2013, 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)
		2015			2014			2013
Net unrealized gain (loss) and prior service cost on pension plans:
Amortization of prior service cost	(a)	1,938			1,938			1,997
Amortization of net gain (loss)	(a)	(5,397		)	(519		)	(4,420		)
	Total before tax	(3,459		)	1,419			(2,423		)
	Tax (expense) or benefit	1,211			(496		)	848
	Net of Tax	$	(2,248	)	$	923		$	(1,575	)
Net unrealized gain (loss) on energy derivative instruments:
Commodity contracts: Electric derivatives	Purchased electricity	(512		)	(572		)	(57		)
	Tax (expense) or benefit	179			200			20
	Net of Tax	$	(333	)	$	(372	)	$	(37	)
Net unrealized gain (loss) on interest rate swaps:
Interest rate contracts	Interest expense	$	—		$	(144	)	$	(4,505	)
	Tax (expense) or benefit	—			50			1,577
	Net of Tax	$	—		$	(94	)	$	(2,928	)
Total reclassification for the period	Net of Tax	$	(2,581	)	$	457		$	(4,540	)

__________


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

122



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)
		2015			2014			2013
Net unrealized gain (loss) and prior service cost on pension plans:
Amortization of prior service cost	(a)	$	1,526		$	1,526		$	1,559
Amortization of net gain (loss)	(a)	(22,268		)	(13,954		)	(22,519		)
	Total before tax	(20,742		)	(12,428		)	(20,960		)
	Tax (expense) or benefit	7,260			4,349			7,336
	Net of tax	$	(13,482	)	$	(8,079	)	$	(13,624	)
Net unrealized gain (loss) on energy derivative instruments:
Commodity contracts: Electric derivatives	Purchased electricity	(1,055		)	(2,063		)	(3,922		)
	Tax (expense) or benefit	369			722			1,373
	Net of Tax	$	(686	)	$	(1,341	)	$	(2,549	)
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	$	(14,485	)	$	(9,737	)	$	(16,490	)

__________


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

123

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	2015 Quarter
(Unaudited; Dollars in Thousands)	First		Second		Third			Fourth
Operating revenue	$	926,835	$	658,341	$	605,733		$	901,791
Operating income	245,235		126,772		69,888			230,030
Net income (loss)	115,676		25,616		(7,928		)	107,815



	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



Puget Sound Energy	2015 Quarter
(Unaudited; Dollars in Thousands)	First		Second		Third		Fourth
Operating revenue	$	926,843	$	658,341	$	605,913	$	902,161
Operating income	240,903		122,753		66,036		226,446
Net income (loss)	129,100		42,699		9,876		122,514



	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

124

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,
	2015			2014			2013
Non-utility expense and other	$	(1,617	)	$	(5,390	)	$	(1,255	)
Other income (deductions):
Equity in earnings of subsidiary (Note 1)	309,603			240,102			351,718
Non-hedged interest rate swap expense	(3,796		)	(3,915		)	2,420
Interest income	63			185			114
Interest expense	(100,114		)	(93,382		)	(103,372		)
Income taxes	37,040			34,235			36,103
Net income (loss)	241,179			171,835			285,728
Comprehensive income (loss)	$	250,956		$	87,077		$	366,272

See accompanying notes to the condensed financial statements.

125

Puget Energy

Condensed Balance Sheets

(Dollars in Thousands)



	December 31,
	2015		2014
Assets:
Investment in subsidiaries	$	3,415,571	$	3,337,718
Other property and investments:
Goodwill	1,656,513		1,656,513
Current assets:
Cash	639		62
Receivables from affiliates ¹	203		28,950
Total current assets	842		29,012
Long-term assets:
Deferred income taxes	272,487		236,038
Other	16,114		15,802
Total long-term assets	288,601		251,840
Total assets	$	5,361,527	$	5,275,083
Capitalization and liabilities:
Common equity	$	3,531,225	$	3,543,328
Long-term debt	1,799,475		1,698,968
Total capitalization	5,330,700		5,242,296
Current liabilities:
Account Payable	171		130
Interest	25,606		23,585
Unrealized loss on derivative instruments	4,753		6,222
Total current liabilities	30,530		29,937
Long-term liabilities:
Unrealized loss on derivative instruments	297		2,850
Total long-term liabilities	297		2,850
Commitments and contingencies (Note 3)
Total capitalization and liabilities	$	5,361,527	$	5,275,083

_______________


¹	Eliminated in consolidation.

See accompanying notes to the condensed financial statements.

126

Puget Energy

Condensed Statements of Cash Flows

(Dollars in Thousands)



	Year Ended December 31,
	2015			2014			2013
Operating activities:
Net cash provided by (used in) operating activities	171,576			225,459			307,115
Investing activities:
Investment in subsidiaries	(28,900		)	—			—
(Increase) decrease in loan to subsidiary	28,933			665			—
Other	(5,632		)	(2,829		)	(1,120		)
Net cash provided by (used in) investing activities	(5,599		)	(2,164		)	(1,120		)
Financing activities:
Dividends paid	(263,059		)	(223,428		)	(170,821		)
Issuance of bond	400,000			—			—
Redemption of term-loan and other long-term debt	(299,000		)	—			(135,000		)
Issue costs and others	(3,341		)	4			5
Net cash provided by (used in) by financing activities	(165,400		)	(223,424		)	(305,816		)
Increase (decrease) in cash	577			(129		)	179
Cash at beginning of year	62			191			12
Cash at end of year	$	639		$	62		$	191

See accompanying notes to the condensed financial statements.

127

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 $304.2 million, $236.6 million and $356.1 million for the years ended December 31, 2015, 2014 and 2013, respectively, and business combination accounting adjustments under ASC 805 recorded at Puget Energy for PSE of $5.4 million, $3.5 million and $(4.4) million for the years ended December 31, 2015, 2014 and 2013, respectively. Investment in subsidiaries includes Puget Energy business combination accounting adjustments under ASC 805 that are recorded at Puget Energy.

In November 2015, the FASB issued ASU 2015-17, "Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes." ASU 2015-17 requires reporting entities to classify deferred tax liabilities and assets as noncurrent in a classified balance sheet instead of separating such deferred taxes into current and noncurrent amounts. Puget Energy has early adopted ASU 2015-17 for the year ended December 31, 2015, and has applied this amendment retrospectively. The impact of the reclass to long-term deferred income tax asset was a decrease of $31.8 million in 2014.

(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.

128

SCHEDULE II: VALUATION AND QUALIFYING ACCOUNTS AND RESERVES



Puget Energy and 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, 2015
Accounts deducted from assets on balance sheet:
Allowance for doubtful accounts receivable	$	7,472	$	20,732	$	18,448	$	9,756
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

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

Puget Energy

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of Puget Energy’s management, including the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, Puget Energy has evaluated the effectiveness of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of December 31, 2015, the end of the period covered by this report. Based upon that evaluation, the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer of Puget Energy concluded that these disclosure controls and procedures are effective.

Changes in Internal Control Over Financial Reporting

There have been no changes in Puget Energy’s internal control over financial reporting during the year ended December 31, 2015 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, 2015.

Puget Energy’s effectiveness of internal control over financial reporting as of December 31, 2015 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.

129

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, 2015, 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, 2015 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, PSE’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, 2015.

PSE’s effectiveness of internal control over financial reporting as of December 31, 2015 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 26, 2016, eleven directors constitute Puget Energy’s Board of Directors and twelve 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.

Scott Armstrong, age 56, has been a director on the board of PSE since June 25, 2015. Mr. Armstrong is currently President and CEO of Group Health Cooperative of Seattle, Washington, which positions he has held since January 2005. An independent director not affiliated with any of the Company’s investors, Mr. Armstrong’s executive leadership experience in a heavily regulated industry that has undergone extensive change, along with his involvement in civic affairs in the Pacific Northwest, are among the reasons for his appointment to the PSE board.

Andrew Chapman, age 60, 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.

130

Melanie Dressel, age 63, 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 39, 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 51, 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.

Steven W. Hooper, age 62, 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., as well as on the boards of various Ignition Partners portfolio companies. 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 62, 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.

Christopher Leslie, age 51, 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 63, 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.

131

Paul McMillan, age 61, has been a director on the boards of both Puget Energy and PSE since April 23, 2015. Mr. McMillan is currently principal of Tidal Shift Capital Inc. of Toronto, Ontario, Canada, which position he has held since July 2009. He served as Senior Vice President of EPCOR Energy Division of Edmonton, Alberta, Canada, from May 2005 to July 2009 and President of EPCOR Merchant and Capital LP from September 2000 to May 2005. In addition, Mr. McMillan is on the boards of Waterstone Energy Services and BluEarth Renewables. Mr. McMillan serves on the boards of Puget Energy and PSE as a representative of Aimco’s ownership interests, pursuant to the terms of the Puget Energy and PSE bylaws, and brings to this service his experience in energy and gas operations and trading as well as renewable and gas project development.

Mary McWilliams, age 67, 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 until 2015 on the board of the 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.

Christopher Trumpy, age 61, 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.

Audit Committee

The Puget Energy and PSE Boards of Directors have both established an Audit Committee. Directors Andrew Chapman, Steven Hooper, David MacMillan and Paul McMillan are the members of the Audit Committee. The Board has determined that Andrew Chapman meets the definition of “Audit Committee Financial Expert” under SEC rules. Puget Energy and PSE currently do not have any outstanding stock listed on a national securities exchange and, therefore, there are no independence standards applicable to either company in connection with the independence of its Audit Committee members.

Changes to the Procedures by which Shareholders may recommend Nominees to the Board of Directors

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.

132

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 2015, nor were they 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 below. For 2015 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);

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

•Philip K. Bussey, Senior Vice President, Chief Customer Officer; and

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

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 short and long-term 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 the 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 2015, 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 of similar size and scope of operations 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 target annual and long-term incentive award opportunities) to the 50th percentile of the market data with variations by individual executive, as

133

appropriate. 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.

The total compensation package is designed to provide participants with appropriate incentives that are competitive with the comparator group described below and 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 2015 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 for 2015 base salaries, annual incentive programs and long-term incentive programs, 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 2014 Energy Services Survey, comprised of utility and other companies similar in size and scope of operations to PSE. The 26 companies in the custom market survey cut used to inform compensation decisions for 2015 are:



Custom Survey Peer Group
1.	AGL Resources	10.	MDU Resources Group	19.	SCANA
2.	Alliant Energy	11.	NiSource	20.	Southwest Gas
3.	Ameren	12.	Northeast Utilities	21.	Teco Energy
4.	Atmos Energy	13.	OGE Energy	22.	UIL Holdings
5.	Avista	14.	Oncor Electric Delivery	23.	UNS Energy
6.	Black Hills	15.	Pepco Holdings	24.	Vectren
7.	CMS Energy	16.	Pinnacle West Capital	25.	Westar Energy
8.	Integrys Energy Group	17.	PNM Resources	26.	Wisconsin Energy
9.	LLG&E and KU Energy	18.	Portland General Electric

134

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 14 companies, all but one of which overlapped with companies included in the market survey data. The 2014 median revenue of the executive compensation peers was $3.4 billion, which was comparable to PSE’s annual revenues of $3.2 billion at the time the peer group was developed. The peer companies included in the Company’s executive compensation benchmarking peer group to inform 2015 compensation decisions are shown below:



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

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 2015 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 reviewed annually by the Committee based on its median philosophy, internal equity considerations and individual executive considerations such as expertise level of performance achievement, experience in role and contribution relative to others in the organization.

Base Salary Adjustments for 2015

The Committee reviewed the base salaries of the Named Executive Officers in early 2015 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. The adjustments were effective March 1, 2015. Base salaries for 2015 generally remained at the 50th percentile of market among the comparator group. The annual salary for Ms. Harris is unchanged from 2014, given that her current base salary was slightly higher than 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 4%, similar to salary increases for other non-represented employees.



Name	2014 Base Salary	2015 Base Salary	% Change
Kimberly J. Harris	$900,000	$900,000	—%
Daniel A. Doyle	$482,040	$496,501	3.0%
Marla D. Mellies	$289,626	$299,763	3.5%
Philip K. Bussey	$291,750	$297,583	2%
Steve R. Secrist	$352,352	$362,923	3%

135

2015 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 2015, the Company’s service quality commitment was measured by performance against nine Service Quality Indicators (SQIs) covering three broad categories, set forth below. These are the same SQIs for which the Company is accountable to the Washington Commission. Annual incentive funding is decreased if a SQI is not achieved. 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 2015 were the same as those in 2014 and were as follows:


•	Customer Satisfaction (3 SQIs) - Customer satisfaction with the telephone access center and natural 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 2015, the Company retained a safety performance measure in the annual incentive plan funding to promote its continued commitment to employee safety. The employee safety measure functions similarly to the nine 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 2015 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%.


•	The Company DART (Days Away from Work, days of Restricted Work, or Job Transfer) not to exceed a rate of 0.61 in 2015.


•	Field employees to attend the Industrial Athlete program, a new training designed to improve mobility and strengthen stability. The target completion rate is no less than 95% of field employees.


•	Office employees to complete an on-line training to increase awareness on ergonomic resources and tools available to help reduce sprain and strain injuries. The target completion rate is no less than 95% of office employees.

In 2015, 100% funding for the annual incentive plan required (i) achievement of 10 out of 10 customer service and safety measures (all nine SQIs and achievement of the safety measure) and (ii) target EBITDA performance. In total, eight of the 10 customer service and safety measures were met or deemed met. The two SQIs not met were SQI 3, System Average Interruption Duration Index (SAIDI) and SQI 5, Telephone Center Answering Performance.

Funding levels for 2015 at maximum, target, and threshold are shown in the table below.



Annual Incentive Performance Payout Scale and Actual Performance
Performance	2015 EBITDA (In Millions)		SQI & Safety*	Funding Level
Maximum	$	1,668.2	10/10	200	%
Target	1,235.7		10/10	100	%
Threshold Payout Funding	1,112.1		6/10	30	%
2015 Actual Performance	$	1,222.2	8/10	75.60	%

_______________


^*	Combined SQI & Safety results of 6/10 or better and minimum EBITDA of $1,112.1 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 2015. Individual awards may be adjusted upward or

136

downward based on an evaluation of an executive officer’s performance against individual and team goals that align with the corporate goals described below.

2015 Corporate Goals

In 2015, the Company continued using the Integrated Strategic Plan (ISP) to summarize for employees the direction and overall goals of the Company. The plan has five objectives which capture our 2015 corporate goals and which have been communicated to our employees. Each employee, including the Named Executive Officers, has specific individual and team goals linked to driving strategies that meet one or more of the following 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.

2015 Annual Incentive Plan Results

Achievement of the corporate goals for 2015 was at 98.9% of target for EBITDA, and below target for SQI and safety achievement. PSE EBITDA was $1,222.2 million, and SQI and safety achievement was 8 out of 10, leading to a funding level for 2015 of 75.6% under the annual incentive plan.

For 2015, individual target incentive levels for the annual incentive plan varied by executive officer as a percentage of 2015 base salary as shown in the table below, based on the executive’s level of responsibility within the Company. Target annual incentive opportunities as a percentage of base salary for participating executives remained unchanged from 2014 levels. The maximum incentive payable for exceptional performance in this plan is twice the target incentive. An executive’s individual award amount can be increased or decreased based on an 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 below CEO in 2015. The Committee similarly recommended an award amount for the CEO which included a small adjustment for individual performance in 2015 and to recognize that the Company nearly met 2015 annual incentive goals at target. The adjustments for individual performance did not materially change the amounts resulting from 2015 achievement of the corporate goals. The Board approved the incentive amounts shown below, which will be paid in March 2016.



Name	Target Incentive (% of Base Salary)	2015 Actual Incentive Paid		2015 Actual Incentive (% of Base Salary)
Kimberly J. Harris	100%	$	714,420	79	%
Daniel A. Doyle	45%	152,019		31	%
Marla D. Mellies	45%	112,177		37	%
Philip K. Bussey	45%	101,238		34	%
Steve R. Secrist	45%	123,466		34	%

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 ROE, each measured over a three-year performance cycle. Total return reflects the change in the value of the Company during the performance cycle plus any distributions made to investors. Achievement of each performance measure during the performance cycle is evaluated independently of the other.

The Committee recommends for Board approval 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 initial per-unit value is measured at the Puget Holdings level

137

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 recommends for Board approval 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 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 cycle.

2015-2017 Long-Term Incentive Plan Target Awards and Performance Goals

Consistent with prior years, target LTI Plan awards for the 2015-2017 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 2015-2017 performance cycle were 200% of base salary for Ms. Harris and 95% for Mr. Doyle, Mr. Secrist, Ms. Mellies and Mr. Bussey, which percentages were unchanged from amounts established for the 2014-2016 performance cycle, except for Ms. Harris. The Board approved an increase in Ms. Harris’ target award from 170% to 200% to provide a target level of award that was market competitive. The total number of target LTI Plan units granted to a Named Executive Officer for the 2015-2017 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 $44.53. Details of the number of units granted and expected values at target, threshold and maximum performance levels can be found in the “2015 Grants of Plan-Based Awards” table below. Effective with the 2015-2017 LTI Plan grants, the Board approved a change in the calculation of performance results. Under this change, actual performance is measured as a percentage of target performance and plan funding is based on the modified payout scales shown below. Target Total Return will be set annually by the Board prior to the grant date, and was set at 9.8% for the 2015-2017 performance cycle. Target ROE remains based on the ROE target in the Board’s approved budget for each year. Prior outstanding LTIP grants continue to have the performance targets and payout scales in effect at the time of grant. 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 during the 2015-2017 performance cycle. Payout percentages will be linearly interpolated if performance falls between the values shown below.



Annualized Three-Year Total Return Compared to Target	Plan Funding for Total Return (% of Target Units)
117.5% of Target or More	200%
115% of Target	185.5
110% of Target	157.0
105% of Target	128.5
100% of Total Return Target	100
95% of Target	89.6
90% of Target	79.2
88% of Target	75.0
85% of Target	62.3
80% of Target	41.2
75% of Target	20
<75% of Target	—

138

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
117.5% of Target or More	200%
115% of Target	185.5
110% of Target	157.0
105% of Target	128.5
Target ROE	100
95% of Target	84
90% of Target	68
85% of Target	52
80% of Target	36
75% of Target	20
<75% of Target	—

Performance Scales for 2013-2015 and 2014-2016 LTI Plan grants

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 during the 2013-2015 performance cycle. Payout percentages will be linearly interpolated if performance falls between the values shown below.



Annualized Three-Year Total Return	Plan Funding for Total Return (% of Target Units)
15% or more	200%
14%	180
13%	160
12%	140
11%	120
10%	100
9%	80
8%	60
7%	40
6%	20
<6%	—

139

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 2013-2015 performance period. Payout percentages will be interpolated if performance falls between the values shown below.



ROE Compared to Target	Plan Funding for ROE (% of Target Units)
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	—

Long-Term Incentive Plan Performance 2013-2015 Performance Cycle

The 2013-2015 performance cycle has now ended. Amounts payable as a result of award vesting are shown in the table below.


•	Performance on the Total Return component for the three-year performance cycle was a compounded annual rate of 8.32%, below the target but above the threshold needed for payment. The Total Return Component funded at 66.3% of target units.


•	Performance on the ROE component of the grant was an average of target minus 10.7 basis points for funding at 95.73% of target units.



Name	Target Incentive (% of Base Salary) ¹	Total Return Component Units Granted/Paid	ROE Component Units Granted/Paid	2013-2015 Actual LTIP Paid ²
Kimberly J. Harris	170%	19,670/13,041.5	19,670/18,830.6	$	1,531,455
Daniel A. Doyle	95%	5,879.5/3,898.1	5,879.5/5,628.4	457,751
Steve R. Secrist	50%	2,240.0/1,485.1	2,240.0/2,149.4	174,396
Marla D. Mellies	95%	3,532.5/2,342.0	3,532.5/3,381.7	275,024
Philip K. Bussey	95%	3,558.5/2,359.3	3,558.5/3,406.6	277,049
Steve R. Secrist	50%	2,240.0/1,485.1	2,240.0/2,144.4	174,396

______________


¹	Target LTI Plan incentive is a percentage of 2013 base salary when the grants were made in 2013.


²	2013-2015 actual LTI Plan amount payable is equal to the unit price $48.05 multiplied by earned Total Return and ROE component units.

Long-Term Incentive 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, 2015, with the projected payout assuming this same performance for the full three-year cycle under the applicable payout scales for Total Return and ROE:



Performance Cycle	Cycle Progress	Total Return Performance	Payout (% of Target)	ROE Performance	Payout (% of Target)	Total Projected Payout (based on performance as of 12/31/2015)
2014 - 2016	67% Complete	7.9%	58%	+17.3 bps	107%	82.7%
2015 - 2017	33% Complete	7.9%	44%	97%	91%	67.2%

140

Retirement Plans - SERP and Retirement Plan

The Company maintains the 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 “2015 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 “2015 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). The Executive Employment Agreements provide for an employment period of two years following a change in control and provide severance benefits in the event of a qualifying termination of employment within two years of a change in control. Since 2009, the Company has ceased entering into these agreements with new executive officers. Mr. Bussey was an officer of PSE at March 30, 2009, but left PSE in May 2009 and upon his rehire in March 2012 does not have an employment agreement with the Company.

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, 2015.

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 and business club memberships 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 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 2015. Executives are taxed on the value of the perquisites received, with no corresponding gross-up by the Company.

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 opportunities for both annual and long-term incentives, because each plan operates with a target 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.

141

Impact of Accounting Treatment of Compensation

The accounting treatment of compensation generally has not been a significant 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 the 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.

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 2015.

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, 2015 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

142

SUMMARY COMPENSATION TABLE

The following information is provided for the year ended December 31, 2015 (and for prior years where applicable) with respect to the Named Executive Officers during 2015. The positions listed below are at Puget Energy and PSE, except that Ms. Mellies and Mr. Bussey are executives of PSE only. Positions listed are those held by the Named Executive Officers as of December 31, 2015. 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	2015	$	900,000	$	—	$	—	$	—	$	2,245,875	$	157,077	$	25,032	$	3,327,984
President and Chief	2014	897,763		—		—		—		2,271,584		2,333,346		27,128		5,529,821
Executive Officer ⁴	2013	863,771		84,350		—		—		1,222,707		1,465,614		24,664		3,661,106
Daniel A. Doyle	2015	$	493,488	$	—	$	—	$	—	$	609,770	$	360,012	$	51,487	$	1,514,757
Senior Vice President	2014	479,115		—		—		—		637,579		336,575		47,822		1,501,091
and Chief Financial Officer ⁵	2013	464,325		19,030		—		—		358,806		269,754		53,147		1,165,062
Marla D. Mellies	2015	$	297,651	$	—	$	—	$	—	$	387,201	$	143,686	$	30,941	$	859,479
Senior Vice President,	2014	287,868		12,367		—		—		385,549		388,950		30,126		1,104,860
Chief Administrative Officer ⁶	2013	279,518		11,511		—		—		262,368		205,448		29,567		788,412
Philip K. Bussey	2015	$	296,367	$	—	$	—	$	—	$	378,286	$	408,937	$	23,792	$	1,107,383
Senior Vice President,
Chief Customer Officer ⁷
Steve R. Secrist	2015	$	360,721	$	—	$	—	$	—	$	297,862	$	95,395	$	23,861	$	777,843
Senior Vice President	2014	349,529		7,485		—		—		310,104		621,610		21,225		1,309,953
General Counsel, Chief Ethics & Compliance Officer ⁸	2013	332,512		24,419		—		—		204,892		304,051		20,116		885,990

___________________

For 2015, reflects annual cash incentive compensation paid under the 2015 Goals and Incentive Plan and cash incentive compensation paid under the LTI Plan for the 2013-2015 performance cycle. Cash incentive amounts were paid in early 2016 or deferred at the executive's election. The 2015 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 2016.

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 2015, updated interest rates and updated mortality assumptions have decreased the actuarial value of the underlying retirement benefits relative to assumptions for 2014. Information regarding these pension plans is set forth in further detail under “2015 Pension Benefits.” The change in pension value amounts for 2015 are: Ms. Harris, $153,818; Mr. Doyle, $360,012; Ms. Mellies, $143,230; Mr. Bussey, $408,937; and Mr. Secrist, $95,399. Also included in this column are the portions of Deferred Compensation Plan earnings that are considered above market. These amounts for 2015 are: Ms. Harris, $3,259; Mr. Doyle, $0; Ms. Mellies, $456; Mr. Bussey, $0; and Mr. Secrist $0. See the “2015 Nonqualified Deferred Compensation” table for all Deferred Compensation Plan earnings.


³	All Other Compensation for 2015 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	Ms. Mellies has worked at PSE since October 2005.


⁷	Mr. Bussey rejoined PSE as Senior Vice President and Chief Customer Officer on March 19, 2012.


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

143

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	$	4,744	$	14,600	$	5,688
Daniel A. Doyle	2,500		43,289		5,698
Marla D. Mellies	400		27,493		3,048
Philip K. Bussey	450		18,500		4,842
Steve R. Secrist	625		18,500		4,736

_______________

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.

Includes Company contributions during 2015 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, $14,600; Mr. Doyle, $18,500; Ms. Mellies, $18,500; Mr. Bussey, $18,500; and Mr. Secrist, $18,500. Company contributions to the Deferred Compensation Plan are as follows: Ms. Harris, $0; Mr. Doyle, $24,789; Ms. Mellies, $8,993; Mr. Bussey $0; and Mr. Secrist $0.


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

2015 Grants of Plan-Based Awards

The following table presents information regarding 2015 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	1/1/2015		$	270,000	$	900,000	$	1,800,000
LTI Plan 2015-2017 ²	2/27/2015	40,422	382,958		2,179,958		4,890,254
Daniel A. Doyle
Annual Incentive ¹	1/1/2015		$	67,028	$	223,425	$	446,851
LTI Plan 2015-2017 ²	2/27/2015	10,592	100,349		571,227		1,281,420
Marla D. Mellies
Annual Incentive ¹	1/1/2015		$	40,468	$	134,893	$	269,787
LTI Plan 2015-2017 ²	2/27/2015	6,395	60,586		344,882		773,667
Philip K. Bussey
Annual Incentive ¹	1/1/2015		$	40,174	$	133,913	$	267,825
LTI Plan 2015-2017 ²	2/27/2015	6,349	60,150		342,402		768,102
Steve R. Secrist
Annual Incentive ¹	1/1/2015		$	48,995	$	163,315	$	326,631
LTI Plan 2015-2017 ²	2/27/2015	7,743	73,357		417,580		936,748

_______________

As described in the “Compensation Discussion and Analysis,” the 2015 Goals and Incentive Plan had dual funding triggers in 2015 of $1,112.1 million EBITDA and SQI performance of 6/10. Payment would be $0 if either trigger is not met. The threshold estimate assumes $1,112.1 million EBITDA and SQI/Safety measure performance at 6/10. The target estimate assumes $1,235.7 million EBITDA and SQI/Safety measure performance at 10/10. The maximum estimate assumes $1,668.2 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 2015-2017 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.

144

2015 Pension Benefits

The Company and its affiliates maintain two pension plans: the Retirement Plan and the SERP. The following table provides information for each of the Named Executive Officers regarding the actuarial present value of the executive’s accumulated benefit and years of credited service under the Retirement Plan and the SERP. The present value of accumulated benefits was determined using interest rate and mortality rate assumptions consistent with those used in the Company’s financial statements. 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	16.7	$	336,021	$	—
	SERP	16.7	7,416,137		—
Daniel A. Doyle	Retirement Plan	4.1	104,002		—
	SERP	4.1	992,226		—
Marla D. Mellies	Retirement Plan	10.2	231,645		—
	SERP	10.2	1,291,295		—
Philip K. Bussey	Retirement Plan	9.3	260,215		—
	SERP	9.3	1,382,428		—
Steve R. Secrist	Retirement Plan	26.6	401,005		—
	SERP	26.6	2,001,411		—

_______________

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, 2015 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 assumed to be 4.0% annually. The discount assumption is 4.65%, and the post-retirement mortality assumption is based on the 2016 417(e) unisex mortality table. Annuity benefits are converted to lump sum amounts at retirement based on assumed future 417(e) segment rates of 1.34%, 4.03%, and 5.06% (the 24-month average of the underlying rates as of September 2015). These assumptions are consistent with the ones used for the Retirement Plan and the SERP for financial reporting purposes for 2015. 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, 2014 for the benefits earned as of that date using the assumptions used for financial reporting purposes for 2014. These assumptions included assumed cash balance interest credits of 4.0% through 2019 and 5.0% annually thereafter, a discount assumption of 4.25% and post-retirement mortality assumption based on the 2015 417(e) unisex mortality table adjusted to reflect RP 2014 with MP-2014 improvements. Annuity benefits were 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). Other assumptions used to determine the value as of December 31, 2014 were the same as those used for December 31, 2015.

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, 2015. Each SERP-eligible Named Executive Officer (except Mr. Doyle) was vested in his or her SERP benefits as of December 31, 2015.



Estimated Lump Sum
Name	Lump Sum
Kimberly J. Harris	$	11,861,777
Daniel A. Doyle	1,222,030
Marla D. Mellies	1,715,520
Philip K. Bussey	1,531,284
Steve R. Secrist	2,889,981

145

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 2015, the limit was $265,000. For 2016, 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 2015 and 2016, 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, 2015, 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 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, 2012, who have not yet attained age 55, including Ms. Harris 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.

146

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 “2015 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.

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.

147

2015 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 2015 and year-end account balances under the Deferred Compensation Plan.



Name	Executive Contributions in 2015 ¹		Registrant Contributions in 2015 ²		Aggregate Earnings in 2015 ³		Aggregate Withdrawals/ Distributions		Aggregate Balance at December 31, 2015 ⁴
Kimberly J. Harris	$	—	$	—	$	11,872	$	—	$	300,074
Daniel A. Doyle	234,993		24,789		2,061		—		483,228
Marla D. Mellies	8,420		8,993		1,907		—		108,458
Philip K. Bussey	—		—		—		—		—
Steve R. Secrist	—		—		—		—		—

_______________

The amount in this column reflects elective deferrals by the executive of salary, annual incentive compensation or LTI Plan awards paid in 2015. Deferred salary amounts are: Ms. Harris, $0; Mr. Doyle, $24,619; Ms. Mellies, $8,420; Mr. Bussey, $0; and Mr. Secrist, $0. Deferred incentive compensation amounts are: Ms. Harris, $0; Mr. Doyle, $0; Ms. Mellies, $0; Mr. Bussey, $0; and Mr. Secrist $0. Mr. Doyle deferred $210,374 of LTIP earnings. The amounts are also included in the applicable column of the Summary Compensation Table for 2015.


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 2015.


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 2015.


⁴	Of the amounts in this column, the amounts in the table below have also been reported in the Summary Compensation Table for 2015, 2014 and 2013.



Nonqualified Deferred Compensation also Reported
Name	Reported for 2015		Reported for 2014		Reported for 2013
Kimberly J. Harris	$	3,259	$	2,190	$	3,007
Daniel A. Doyle	259,782		132,127		52,664
Marla D. Mellies	17,869		16,314		16,740
Philip K. Bussey	—		—		—
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 2015 calendar year returns of these tracking funds were:



Vanguard Total Bond Market Index	0.41	%
Vanguard 500 Index	1.25	%
Vanguard Money Market Index	0.05	%
Interest Crediting Fund (pre-2012 deferrals)	4.10	%

148

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).

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, Ms. Harris and Ms. Mellies are each parties to an Executive Employment Agreement with the Company, dated March 2009. The agreements which provide 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 in which awards are not assumed or substituted, outstanding LTI Plan awards will be paid on a pro-rata basis 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 in control.

Employment Agreements with Certain Named Executive Officers

In March 2009, PSE entered into Executive Employment Agreements (Employment Agreements) with each of Ms. Harris and Ms. Mellies (the Covered Executives). The Employment Agreements provide for an employment period of two years following a change in control. 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 outstanding immediately after such acquisition (other than through a registered public offering) or (ii) all or substantially all of the Company’s assets.

149

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 2015, 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 natural gas in Washington or soliciting others to leave the Company or causing them to be hired from the Company by another

150

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.

151

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, 2015. 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.



	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)	$	—	$	5,400,000	$	—	$	—	$	—
Long Term Incentive Plan	3,725,369		3,725,369		—		2,968,444		2,968,444
SERP (additional years of credited service) ¹	—		—		—		—		—
Benefits (continuation) ²	—		28,756		—		28,756		28,756
Supplemental Life Insurance	—		—		—		—		3,000,000
Total Estimated Incremental Value	$	3,725,369	$	9,154,125	$	—	$	2,997,200	$	5,997,200
Daniel A. Doyle
Long Term Incentive Plan	$	1,090,361	$	1,090,361	$	—	$	871,003	$	871,003
SERP (additional years of credited service) ¹	—		—		—		—		—
Benefits (continuation) ²	—		—		—		—		—
Supplemental Life Insurance	—		—		—		—		943,352
Total Estimated Incremental Value	$	1,090,361	$	1,090,361	$	—	$	871,003	$	1,814,355
Marla D. Mellies
Cash Severance (salary and/or annual incentive)	$	—	$	1,303,969	$	—	$	—	$	—
Long Term Incentive Plan	655,607		655,607		523,666		523,666		523,666
SERP (additional years of credited service)¹	—		409,418		—		—		—
Benefits (continuation) ²	—		40,549		—		40,549		40,549
Supplemental Life Insurance	—		—		—		—		569,550
Total Estimated Incremental Value	$	655,607	$	2,409,543	$	523,666	$	564,215	$	1,133,765
Philip K. Bussey
Cash Severance (salary and/or annual incentive)	$	—	$	—	$	—	$	—	$	—
Long Term Incentive Plan	658,953		658,953		526,477		526,477		526,477
SERP (additional years of credited service) ¹	—		—		—		—		—
Benefits (continuation) ²	—		—		—		—		—
Supplemental Life Insurance	—		—		—		—		565,408
Total Estimated Incremental Value	$	658,953	$	658,953	$	526,477	$	526,477	$	1,091,885
Steve R. Secrist
Long Term Incentive Plan	$	599,301	$	599,301	$	—	$	476,493	$	476,493
SERP (additional years of credited service) ¹	—		—		—		—		—
Benefits (continuation) ²	—		—		—		—		—
Supplemental Life Insurance	—		—		—		—		689,554
Total Estimated Incremental Value	$	599,301	$	599,301	$	—	$	476,493	$	1,166,047

_______________


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, 2015. 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.

152

Director Compensation for Fiscal Year 2015

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 2015 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 Chapman, Daniel Fetter, Alan James and Christopher Leslie. 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 2015 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
Scott Armstrong	$	—	$	60,600	$	60,600
Melanie Dressel	186,817		—		186,817
Steve Hooper	—		128,033		128,033
David MacMillan	160,800		—		160,800
Paul McMillan	101,500		—		101,500
Herbert Simon ²	144,000		3,953		147,953
Christopher Trumpy	151,600		—		151,600
Mary O. McWilliams	132,400		—		132,400

_______________


¹	Represents earnings accrued on deferred compensation considered to be above market.


²	Herbert Simon resigned from his position as a member of the Board of Directors of PSE, effective as of January 21, 2016.

Nonemployee Director Compensation Program

The 2015 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 2015 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 2015, 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.

153

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. Scott Armstrong and Steve Hooper are the only independent board members to defer any director fees during 2015.

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, 2015 by each person or group that we know owns more than 5.0% of Puget Energy’s and PSE’s common stock. No director, executive officer or executive officer named in the Summary Compensation Table in Item 11 of Part III of this report owns any of the outstanding shares of common stock of Puget Energy or PSE. Puget Equico LLC(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 PSE common stock outstanding as of December 31, 2015.

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, 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 98004.


•	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 2500, P.O. Box 101, Toronto, Ontario, Canada M5C 2W5.


•	The address of the principal office of bcIMC is Suite 300-2950 Jutland Road, Victoria, British Columbia, Canada V8T 5K2.


•	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, and (b) the senior secured notes issued on December 6, 2010, June 3, 2011, June 15, 2012 and May 12, 2015.

^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, and (b) the senior secured notes issued on December 6, 2010, June 3, 2011, June 15, 2012 and May 12, 2015.

154

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.

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), Melanie Dressel (member of the Boards of both Puget Energy and PSE), and Scott Armstrong (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

155

who: (a) shall not be a member of Puget Holdings (referred to as a Holdings Member) or an affiliate of any Holdings Member (including by way of being a member, stockholder, director, manager, partner, officer or employee of any such member), (b) shall not be an officer or employee of PSE, (c) shall be a resident of the state of Washington, and (d) if and to the extent required with respect to any specific director, shall meet such other qualifications as may be required by any applicable regulatory authority for an independent director or manager. The Company’s definition of "Independent Director" is available in the Corporate Governance Guidelines at www.pugetenergy.com.

In making these independence determinations, the Boards have established a categorical standard that a director’s independence is not impaired solely as a result of the director, or a company for which the director or an immediate family member of the director serves as an executive officer, making payments to PSE for power or natural gas provided by PSE at rates fixed in conformity with law or governmental authority, unless such payments would automatically disqualify the director under the NYSE’s corporate governance listing standards. The Boards have 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 Armstrong, 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. Because these relationships either fall within the Boards' 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:



	2015				2014
(Dollars in Thousands)	Puget Energy		PSE		Puget Energy		PSE
Audit fees ¹	$	2,413	$	2,128	$	2,041	$	1,878
Audit related fees ²	45		45		111		111
Tax fees ³	—		—		31		31
Other fees⁴	52		52		52		52
Total	$	2,510	$	2,225	$	2,235	$	2,072

_______________


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 2015 fees are estimated and include an aggregate amount of $1.3 million billed to Puget Energy and $1.1 million to PSE through December 2015.


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.

156

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 the Audit Committee. In addition, any proposed services exceeding pre-approved cost levels will require specific pre-approval by the Audit Committee.

The annual audit services engagement terms and fees, as well as any changes in terms, conditions and fees relating to the engagement, are subject to specific pre-approval by the Audit Committee. In addition, on an annual basis, the Audit Committee grants general pre-approval for specific categories of audit, audit-related, tax and other services, within specified fee levels, that may be provided by the independent registered public accounting firm. With respect to each proposed pre-approved service, the independent registered public accounting firm is required to provide detailed back-up documentation to the Audit Committee regarding the specific services to be provided. Under the policies, the Audit Committee may delegate pre-approval authority to one or more of their members. The member or members to whom such authority is delegated shall report any pre-approval decision to the Audit Committee at its next scheduled meeting. The Audit Committee does not delegate responsibilities to pre-approve services performed by the independent registered public accounting firm to management.

For 2015 and 2014, 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, 2015, 2014 and 2013, consist of the following:


I.	Condensed Financial Information of Puget Energy


II.	Valuation of Qualifying Accounts and Reserves


3)	Exhibits

157

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 26, 2016	Date:	February 26, 2016

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 26, 2016
(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/ Steven W. Hooper	Director
(Steven W. Hooper)

	Director
(Alan W. James)

	Director
(Christopher J. Leslie)

/s/ David MacMillan	Director
(David MacMillan)

158



/s/ Paul McMillan	Director
(Paul McMillan)

/s/ Mary O. McWilliams	Director
(Mary O. McWilliams)

/s/ Christopher Trumpy	Director
(Christopher Trumpy)

/s/ Scott Armstrong	Director of PSE only
(Scott Armstrong)

159

EXHIBIT INDEX

Certain of the following exhibits are filed herewith. Certain other of the following exhibits have heretofore been filed with the 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).

160



	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).
	4.21	Fourth Supplemental Indenture dated as of May 12, 2015, between Puget Energy, Inc. and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.1 to Puget Energy’s Current Report on Form 8-K, dated May 13, 2015, Commission File No. 1-16305).

161



	10.1	First Amendment dated as of October 4, 1961 to Power Sales Contract between Public Utility District No. 1 of Chelan County, Washington and Puget Sound Energy, Inc., relating to the Rocky Reach Project (incorporated herein by reference to Exhibit 10.1 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
	10.2	First Amendment dated February 9, 1965 to Power Sales Contract between Public Utility District No. 1 of Douglas County, Washington and Puget Sound Energy, Inc., relating to the Wells Development (incorporated herein by reference to Exhibit 10.2 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
	10.3	Contract dated November 14, 1957 between Public Utility District No. 1 of Chelan County, Washington and Puget Sound Energy, Inc., relating to the Rocky Reach Project (incorporated herein by reference to Exhibit 10.3 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
	10.4	Power Sales Contract dated as of November 14, 1957 between Public Utility District No. 1 of Chelan County, Washington and Puget Sound Energy, Inc., relating to the Rocky Reach Project (incorporated herein by reference to Exhibit 10.4 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
	10.5	Power Sales Contract dated May 21, 1956 between Public Utility District No. 2 of Grant County, Washington and Puget Sound Energy, Inc., relating to the Priest Rapids Project (incorporated herein by reference to Exhibit 10.5 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
	10.6	First Amendment to Power Sales Contract dated as of August 5, 1958 between Puget Sound Energy, Inc. and Public Utility District No. 2 of Grant County, Washington, relating to the Priest Rapids Development (incorporated herein by reference to Exhibit 10.6 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
	10.7	Power Sales Contract dated June 22, 1959 between Public Utility District No. 2 of Grant County, Washington and Puget Sound Energy, Inc., relating to the Wanapum Development (incorporated herein by reference to Exhibit 10.7 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
	10.8	Agreement to Amend Power Sales Contracts dated July 30, 1963 between Public Utility District No. 2 of Grant County, Washington and Puget Sound Energy, Inc., relating to the Wanapum Development (incorporated herein by reference to Exhibit 10.8 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
	10.9	Power Sales Contract executed as of September 18, 1963 between Public Utility District No. 1 of Douglas County, Washington and Puget Sound Energy, Inc., relating to the Wells Development (incorporated herein by reference to Exhibit 10.9 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
	10.10	Construction and Ownership Agreement dated as of July 30, 1971 between The Montana Power Company and Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit 10.10 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
	10.11	Operation and Maintenance Agreement dated as of July 30, 1971 between The Montana Power Company and Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit 10.11 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
	10.12	Contract dated June 19, 1974 between Puget Sound Energy, Inc. and P.U.D. No. 1 of Chelan County (incorporated herein by reference to Exhibit 10.12 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
	10.13	Transmission Agreement dated April 17, 1981 between the Bonneville Power Administration and Puget Sound Energy, Inc. (Colstrip Project) (incorporated herein by reference to Exhibit (10)-55 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).
	10.14	Transmission Agreement dated April 17, 1981 between the Bonneville Power Administration and Montana Intertie Users (Colstrip Project) (incorporated herein by reference to Exhibit (10)-56 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).
	10.15	Ownership and Operation Agreement dated as of May 6, 1981 between Puget Sound Energy, Inc. and other Owners of the Colstrip Project (Colstrip 3 and 4) (incorporated herein by reference to Exhibit (10)-57 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).
	10.16	Colstrip Project Transmission Agreement dated as of May 6, 1981 between Puget Sound Energy, Inc. and Owners of the Colstrip Project (incorporated herein by reference to Exhibit (10)-58 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).
	10.17	Common Facilities Agreement dated as of May 6, 1981 between Puget Sound Energy, Inc. and Owners of Colstrip 1 and 2, and 3 and 4 (incorporated herein by reference to Exhibit (10)-59 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).

162



	10.18	Amendment dated as of June 1, 1968, to Power Sales Contract between Public Utility District No. 1 of Chelan County, Washington and Puget Sound Energy, Inc. (Rocky Reach Project) (incorporated herein by reference to Exhibit (10)-66 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).
	10.19	Transmission Agreement dated as of December 30, 1987 between the Bonneville Power Administration and Puget Sound Energy, Inc. (Rock Island Project) (incorporated herein by reference to Exhibit (10)-74 to Report on Form 10-K for the fiscal year ended December 31, 1988, Commission File No. 1-4393).
	10.20	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 Energy's and Puget Sound Energy’s Current Report on Form 8-K, dated April 3, 2009, Commission File Nos. 1-16305 and 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).

163



**	10.35	Puget Sound Energy, Inc. Amended and Restated Supplemental Executive Retirement Plan effective January 1, 2013 (incorporated herein by reference to Exhibit 10.35 to Puget Energy’s and Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2012, Commission File Nos. 1-16305 and 1-4393).
**	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.
**	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	Amendment to 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	Amendment to 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 January 21, 2016.
	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. (2011 through 2015).
*	12.2	Statement setting forth computation of ratios of earnings to fixed charges of Puget Sound Energy, Inc. (2011 through 2015).
*	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.
	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, 2015, filed on February 26, 2016, 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).

____

164

_______________


*	Filed herewith.


**	Management contract, compensatory plan or arrangement.


***	Management contract, compensatory plan or arrangement filed herewith.

165